The URL can be used to link to this page

Home My WebLink About224-1131. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,129'N/A Casing Collapse Structural Conductor 1,540psi Surface Intermediate 4,750psi Production 7,020psi Liner 10,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan LeMay, Operations Engineer Contact Email:ryan.lemay@hilcorp.com Contact Phone: 661-487-0871 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: CTCO, N2 LTP & N/A 2,870' (MD ) 2,660' (TVD) & N/A 6,728'6,346'6,057' Beaver Creek Unit Beluga Gas 13-3/8" Beaver Creek Unit (BCU) 09ACO 237D Same 2,834'7" ~1954psi N/A September 24, 2025 7,129'4,259' 3-1/2" 6,730' 3,075' (TOW) Perforation Depth MD (ft): See Attached Schematic 3-1/2" See Attached Schematic 6,870psi 3,090psi116' 1,789' 116' 3,075' Size 116' 9-5/8"1,853' MD 1,853' Length L-80 TVD Burst 2,882' 8,160psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AKA 028083 224-113 50-133-20445-01-00 Hilcorp Alaska, LLC Proposed Pools: 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 AOGCC USE ONLY 10,160psi Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:41 am, Sep 12, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.09.12 10:21:34 - 08'00' Noel Nocas (4361) 325-556 A.Dewhurst 15SEP25 CT BOP test to 2500 psi (contingent) Provide AOGCC 24 hrs notice for opportunity to witness TOC tag and pressure test. Downhole commingling of production between Beluga and Sterling sands is not permitted without an order from the AOGCC. 10-404 BJM 9/17/25 X DSR-9/12/25JLC 9/17/2025 Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2025.09.17 13:08:42 -08'00' 09/17/25 RBDMS JSB 091925 Well Prognosis Well: BCU-09A Well Name: BCU-09A API Number: 50-133-20445-01-00 Current Status: Gas Producer Permit to Drill Number: 224-113 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: 2546 psi @ 5919’ TVD Based on 0.43 psi/ft Max. Potential Surface Pressure: 1954 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.73 psi/ft using 14.1 ppg EMW FIT at 7” shoe Shallowest Allowable Perf TVD: MPSP / (0.73 - 0.1) = 1954 psi / 0.63 = 3102’ TVD Top of Applicable Gas Pool / PA: Beluga Gas Pool / PA – 6216’ MD / 5830’ TVD Sterling Gas Pool / PA – 5220’ MD / 4850’ TVD Well Status: Gas Producer x 308 mcfd / 0 bwpd / 57 psi FTP (As of 9/7/2025) Recent Well Summary: BCU-09A was a sidetrack well (parent wellbore BCU 09) drilled and initially completed in late 2024. The well was perforated from the Bel 11 through Bel 6 sands. The Bel 11 through lower Bel 6 sands proved to be unsuccessful and the only current open perforation is the Bel 6 interval from 6319’ – 6329’ MD. Initial production came on 520 mcfd / 0 bwpd / 88 psi FTP. Since, the well has gradually declined to 308 mcfd / 0 bwpd / 57 psi FTP (as of 9/7/2025). The objective of this sundry is to add additional perforations in the Bel 5 intervals. If there is no sustained gas production in the remaining Bel 5 intervals proposed, the Beluga Gas Pool / PA will be isolated, and additional Sterling perforations will be added. Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,500 psi high 3. RIH and perforate the following sands: Below are proposed targeted sands in order of testing (bottom/up), but additional sands 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-09A Bel 5 ±6,267’ ±6,278’ ±5,880' ±5,891' ±11' BCU-09A Bel 5 ±6,290’ ±6,295’ ±5,903' ±5,908' ±5' BCU-09A Bel 5 ±6,301’ ±6,307’ ±5,913' ±5919' ±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 Well Prognosis Well: BCU-09A c. Record tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) d. Pending well production, all perf intervals may not be completed e. If any current or proposed zones produce sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Note: A CIBP will be used if zone(s) require isolation. 35ft will not be placed on each plug as these zones are close together. f. If necessary, use nitrogen or pad gas throughout operations to pressure up well during perforating or to depress water prior to setting a plug above perforations 4. RDMO and turn well over to production ops. Contingency Procedure: Isolate Beluga Gas Pool / PA & Add Additional Sterling Perforations 1. M/U 3-1/2” CIBP and set at + 6,262’ MD 2. Dump bail a minimum of 25’ cement on top of CIBP bringing TOC to + 6,237’ MD. a. A minimum of 25’ of cement dump bailed on top of plug meets AOGCC regulations. b. This is a requested variance from BLM 3172.12(a)(2)(iii) which requires 35’ of cement to be dump bailed on a bridge plug. Hilcorp is requesting to only dump bail a minimum of 25’ of cement on top of plug due to proximity of the first zone that is planned to be perforated in the Sterling Gas Pool / PA. (Sterling A2 6,207’ – 6,216’ MD). 3. Tag TOC w/ E-line and pressure test CIBP + cement to verify plug placement and integrity for Beluga Gas Pool / PA isolation. 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. 5. RIH and perforate the following sands: Below are proposed targeted sands in order of testing (bottom/up), but additional sands 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-09A Sterling B3L ±5,479’ ±5,488’ ±5,104' ±5,113' ±9' BCU-09A Sterling B4 ±5,547’ ±5,558’ ±5,171' ±5,182' ±11' BCU-09A Sterling B5 ±5,602’ ±5,606’ ±5,225' ±5,229' ±4' BCU-09A Sterling B6 ±5,628’ ±5,640’ ±5,250' ±5,262' ±12' BCU-09A Sterling B6 ±6,119’ ±6,128’ ±5,734' ±5,743' ±9' BCU-09A Sterling A1 ±6,157’ ±6,163’ ±5,771' ±5,777' ±6' BCU-09A Sterling A2 ±6,207’ ±6,216’ ±5,821' ±5,830' ±9' Well Prognosis Well: BCU-09A g. Correlate using log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation h. Use Gamma/CCL to correlate i. 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) j. Pending well production, all perf intervals may not be completed k. If any current or proposed zones produce 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’. l. If necessary, use nitrogen or pad gas throughout operations to pressure up well during perforating or to depress water prior to setting a plug above perforations 6. RDMO and turn well over to production ops. Coil Tubing Cleanout Procedure: 1. If throughout operations during either the primary or contingency procedure 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. Proposed Schematic – Contingency 4. Coil Tubing BOP Diagram 5. Standard Well Procedure – N2 Operations _____________________________________________________________________________________ Updated by CJD 1-7-25 SCHEMATIC Beaver Creek Unit Well: BCU-09A PTD: 224-113 API: 50-133-20445-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8”Conductor 61 / J-55 / Butt 12.515”Surf 116’ 9-5/8"Intermediate 47 / N-80 / BTC 8.861”Surf 1,853’ 7"Intermediate 29 / N-80 /BTC 6.276”Surf 3,075’ (TOW) 3-1/2”Prod Casing 9.2 / L-80 / Hyd 563 2.991”2,870’7,129’ 3-1/2”Tieback Tbg 9.2 / L-80 / EUE 8RD 2.991”Surf 2,882’ OPEN HOLE / CEMENT DETAIL 13-3/8”Driven 9-5/8"TOC @ Surface 700 sx 7”TOC @ 2,800’ MD 350 sx Stg 1 / 215 sx Stg 2 3-1/2”TOC @ ±2,852’ (CBL 10/26/24) L – 349 sx / T – 78 sx JEWELRY DETAIL No.Depth Item 1 1,504’Chemical Inj Sub 2 2,870’Liner Top Packer 3 2,882’Seal Stem 4 6,346’CIBP (12/28/24) 5 6,371’CIBP (12/23/24) 6 6,386’CIBP (12/17/24) 7 6,426’CIBP (11/26/24) 8 6,450’CIBP (11/25/24) 9 6,486’CIBP (11/24/24) PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status BEL 6 6,319’6,329’5,932’5,941’10’12/29/2024 Open BEL 6 6,349’6,363’5,961’5,975’14’12/23/2024 Isolated BEL 7 6,374’6,380’5,985’5,991’6’12/23/2024 Isolated BEL 7B 6,402’6,408’6,013’6,019’6’11/26/2024 Isolated BEL 7B 6,414’6,420’6,025’6,031’6’11/26/2024 Isolated BEL 8 6,431’6,441’6,042’6,052’10’11/25/2024 Isolated BEL 8 6,456’6,465’6,067’6,076’9’11/24/2024 Isolated BEL 9 6,596'6,606'6,205'6,215'10'11/14/2024 Isolated BEL 10 6,667'6,677'6,274'6,284’10'11/14/2024 Isolated BEL 11 6,756'6,776'6,372'6,382'10'11/13/2024 Isolated BEL 11 6,801'6,807'6,407'6,413'6'11/13/2024 Isolated _____________________________________________________________________________________ Updated by RPL 9-9-2025 SCHEMATIC Proposed Beaver Creek Unit Well: BCU-09A PTD: 224-113 API: 50-133-20445-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8”Conductor 61 / J-55 / Butt 12.515”Surf 116’ 9-5/8"Intermediate 47 / N-80 / BTC 8.861”Surf 1,853’ 7"Intermediate 29 / N-80 /BTC 6.276”Surf 3,075’ (TOW) 3-1/2”Prod Casing 9.2 / L-80 / Hyd 563 2.991”2,870’7,129’ 3-1/2”Tieback Tbg 9.2 / L-80 / EUE 8RD 2.991”Surf 2,882’ OPEN HOLE / CEMENT DETAIL 13-3/8”Driven 9-5/8"TOC @ Surface 700 sx 7”TOC @ 2,800’ MD 350 sx Stg 1 / 215 sx Stg 2 3-1/2”TOC @ ±2,852’ (CBL 10/26/24) L – 349 sx / T – 78 sx JEWELRY DETAIL No.Depth Item 1 1,504’Chemical Inj Sub 2 2,870’Liner Top Packer 3 2,882’Seal Stem 4 6,346’CIBP (12/28/24) 5 6,371’CIBP (12/23/24) 6 6,386’CIBP (12/17/24) 7 6,426’CIBP (11/26/24) 8 6,450’CIBP (11/25/24) 9 6,486’CIBP (11/24/24) PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Bel 5 ±6,267’±6,278’±5,880'±5,891'±11'Proposed Bel 5 ±6,290’±6,295’±5,903'±5,908'±5'Proposed Bel 5 ±6,301’±6,307’±5,913'±5,919'±6'Proposed BEL 6 6,319’6,329’5,932’5,941’10’12/29/2024 Open BEL 6 6,349’6,363’5,961’5,975’14’12/23/2024 Isolated BEL 7 6,374’6,380’5,985’5,991’6’12/23/2024 Isolated BEL 7B 6,402’6,408’6,013’6,019’6’11/26/2024 Isolated BEL 7B 6,414’6,420’6,025’6,031’6’11/26/2024 Isolated BEL 8 6,431’6,441’6,042’6,052’10’11/25/2024 Isolated BEL 8 6,456’6,465’6,067’6,076’9’11/24/2024 Isolated BEL 9 6,596'6,606'6,205'6,215'10'11/14/2024 Isolated BEL 10 6,667'6,677'6,274'6,284’10'11/14/2024 Isolated BEL 11 6,756'6,776'6,372'6,382'10'11/13/2024 Isolated BEL 11 6,801'6,807'6,407'6,413'6'11/13/2024 Isolated _____________________________________________________________________________________ Updated by RPL 9-9-2025 SCHEMATIC Proposed – Contingency Beaver Creek Unit Well: BCU-09A PTD: 224-113 API: 50-133-20445-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8”Conductor 61 / J-55 / Butt 12.515”Surf 116’ 9-5/8"Intermediate 47 / N-80 / BTC 8.861”Surf 1,853’ 7"Intermediate 29 / N-80 /BTC 6.276”Surf 3,075’ (TOW) 3-1/2”Prod Casing 9.2 / L-80 / Hyd 563 2.991”2,870’7,129’ 3-1/2”Tieback Tbg 9.2 / L-80 / EUE 8RD 2.991”Surf 2,882’ OPEN HOLE / CEMENT DETAIL 13-3/8”Driven 9-5/8"TOC @ Surface 700 sx 7”TOC @ 2,800’ MD 350 sx Stg 1 / 215 sx Stg 2 3-1/2”TOC @ ±2,852’ (CBL 10/26/24) L – 349 sx / T – 78 sx JEWELRY DETAIL No.Depth Item 1 1,504’Chemical Inj Sub 2 2,870’Liner Top Packer 3 2,882’Seal Stem 4 +6,262’ CIBP + 25’ cement (Proposed) 5 6,346’CIBP (12/28/24) 6 6,371’CIBP (12/23/24) 7 6,386’CIBP (12/17/24) 8 6,426’CIBP (11/26/24) 9 6,450’CIBP (11/25/24) 10 6,486’CIBP (11/24/24) PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status Sterling B3L ±5,479’±5,488’±5,104'±5,113'±9'Proposed Sterling B4 ±5,547’±5,558’±5,171'±5,182'±11'Proposed Sterling B5 ±5,602’±5,606’±5,225'±5,229'±4'Proposed Sterling B6 ±5,628’±5,640’±5,250'±5,262'±12'Proposed Sterling B6 ±6,119’±6,128’±5,734'±5,743'±9'Proposed Sterling A1 ±6,157’±6,163’±5,771'±5,777'±6'Proposed Sterling A2 ±6,207’±6,216’±5,821'±5,830'±9'Proposed Bel 5 ±6,267’±6,278’±5,880'±5,891'±11'Proposed Isolate Bel 5 ±6,290’±6,295’±5,903'±5,908'±5'Proposed Isolate Bel 5 ±6,301’±6,307’±5,913'±5,919'±6'Proposed Isolate BEL 6 6,319’6,329’5,932’5,941’10’12/29/2024 Isolate BEL 6 6,349’6,363’5,961’5,975’14’12/23/2024 Isolated BEL 7 6,374’6,380’5,985’5,991’6’12/23/2024 Isolated BEL 7B 6,402’6,408’6,013’6,019’6’11/26/2024 Isolated BEL 7B 6,414’6,420’6,025’6,031’6’11/26/2024 Isolated BEL 8 6,431’6,441’6,042’6,052’10’11/25/2024 Isolated BEL 8 6,456’6,465’6,067’6,076’9’11/24/2024 Isolated BEL 9 6,596'6,606'6,205'6,215'10'11/14/2024 Isolated BEL 10 6,667'6,677'6,274'6,284’10'11/14/2024 Isolated BEL 11 6,756'6,776'6,372'6,382'10'11/13/2024 Isolated BEL 11 6,801'6,807'6,407'6,413'6'11/13/2024 Isolated STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 4 4 5 - 0 1 - 0 0 We l l N a m e / N o . BE A V E R C K U N I T 0 9 A Co m p l e t i o n S t a t u s 2- G A S Co m p l e t i o n D a t e 11 / 1 3 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 1 1 3 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 71 2 9 TV D 67 3 0 Cu r r e n t S t a t u s 2- G A S 6/ 1 1 / 2 0 2 5 UI C No We l l L o g I n f o r m a t i o n : Di g i t a l Me d / F r m t Re c e i v e d St a r t S t o p OH / CH Co m m e n t s Lo g Me d i a Ru n No El e c t r Da t a s e t Nu m b e r Na m e In t e r v a l Li s t o f L o g s O b t a i n e d : CB L 1 0 - 2 6 - 2 4 , G e o t a p ( F T W D ) , L W D ( P C G , A D R , A L D , C T N , P W D , D D S R ) , P e r f / T i e I n L o g s No No Ye s Mu d L o g S a m p l e s D i r e c t i o n a l S u r v e y RE Q U I R E D I N F O R M A T I O N (f r o m M a s t e r W e l l D a t a / L o g s ) DA T A I N F O R M A T I O N Lo g / Da t a Ty p e Lo g Sc a l e DF 1/ 9 / 2 0 2 5 30 7 0 7 1 2 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : B C U 0 9 A L W D Fi n a l . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 18 1 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 6 7 6 8 f t M D 6 3 7 3 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 0 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 0 6 4 5 1 f t M D 6 0 6 1 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 0 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 1 6 4 3 6 f t M D 6 0 4 7 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 1 1 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 2 6 3 9 5 f t M D 6 0 0 6 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 1 1 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 3 6 3 9 5 f t M D 6 0 0 6 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 1 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 4 6 3 7 7 f t M D 5 9 8 8 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 2 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 5 6 3 7 6 f t M D 5 9 8 7 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 2 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 6 6 3 7 5 f t M D 5 9 8 6 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a We d n e s d a y , J u n e 1 1 , 2 0 2 5 AO G C C P a g e 1 o f 6 BC U 0 9 A L W D Fi n al. l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 4 4 5 - 0 1 - 0 0 We l l N a m e / N o . BE A V E R C K U N I T 0 9 A Co m p l e t i o n S t a t u s 2- G A S Co m p l e t i o n D a t e 11 / 1 3 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 1 1 3 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 71 2 9 TV D 67 3 0 Cu r r e n t S t a t u s 2- G A S 6/ 1 1 / 2 0 2 5 UI C No DF 1/ 9 / 2 0 2 5 2 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 7 6 3 5 7 f t M D 5 9 6 9 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 3 3 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 8 6 3 5 6 f t M D 5 9 6 8 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 20 2 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 5 6 7 9 4 f t M D 6 3 9 9 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 21 2 1 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 6 6 5 9 9 f t M D 6 2 0 7 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 22 2 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 7 6 4 9 4 f t M D 6 1 0 4 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 23 2 3 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 8 6 4 6 1 f t M D 6 0 7 1 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 23 2 3 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 9 6 4 5 1 f t M D 6 0 6 1 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 3 3 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 1 9 6 3 5 5 f t M D 5 9 5 7 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 18 1 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 2 6 7 6 7 f t M D 6 3 7 2 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 4 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 2 0 6 3 2 6 f t M D 5 9 3 8 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 4 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 2 1 6 3 2 6 f t M D 5 9 3 8 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 5 5 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 2 2 6 3 2 6 f t M D 5 9 3 8 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 5 5 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 2 3 6 3 0 5 f t M D 5 9 1 7 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a We d n e s d a y , J u n e 1 1 , 2 0 2 5 AO G C C P a g e 2 o f 6 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 4 4 5 - 0 1 - 0 0 We l l N a m e / N o . BE A V E R C K U N I T 0 9 A Co m p l e t i o n S t a t u s 2- G A S Co m p l e t i o n D a t e 11 / 1 3 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 1 1 3 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 71 2 9 TV D 67 3 0 Cu r r e n t S t a t u s 2- G A S 6/ 1 1 / 2 0 2 5 UI C No DF 1/ 9 / 2 0 2 5 5 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 2 4 6 3 0 4 f t M D 5 9 1 6 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 6 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 2 5 6 3 0 4 f t M D 5 9 1 6 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 7 7 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 2 6 6 2 7 1 f t M D 5 8 8 4 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 19 1 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 3 6 7 9 6 f t M D 6 4 0 1 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 19 2 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : H i l c o r p B C U 0 9 A Me m o r y G e o T a p T e s t 4 6 7 9 5 f t M D 6 4 0 0 f t TV D . l a s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A L W D F i n a l M D . c g m 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A L W D F i n a l T V D . c g m 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B R U 2 2 1 - 2 6 L W D F i n a l Ge o T a p . c g m 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U - 0 9 A - D e f i n i t i v e S u r v e y Re p o r t . p d f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U - 0 9 A - F i n a l S u r v e y s . x l s x 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U - 0 9 A _ D S R _ A c t u a l - Po r t r a i t _ P l a n . p d f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U - 0 9 A _ D S R _ A c t u a l - Po r t r a i t _ V s e c . p d f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U - 9 A _ D S R - G I S . t x t 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U - 9 A _ D S R . t x t 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A F i n a l G e o T a p . e m f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A L W D F i n a l M D . e m f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A L W D F i n a l T V D . e m f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A A l a s k a G e o T a p R T Su m m a r y S h e e t . x l s x 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A F i n a l G e o t a p R e p o r t . p d f 39 9 4 4 ED Di g i t a l D a t a We d n e s d a y , J u n e 1 1 , 2 0 2 5 AO G C C P a g e 3 o f 6 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 4 4 5 - 0 1 - 0 0 We l l N a m e / N o . BE A V E R C K U N I T 0 9 A Co m p l e t i o n S t a t u s 2- G A S Co m p l e t i o n D a t e 11 / 1 3 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 1 1 3 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 71 2 9 TV D 67 3 0 Cu r r e n t S t a t u s 2- G A S 6/ 1 1 / 2 0 2 5 UI C No DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : Hi l c o r p _ B C U _ 0 9 A _ M e m o r y _ G e o T a p _ A l l _ T e s t s . d li s 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : Hi l c o r p _ B C U _ 0 9 A _ M e m o r y _ G e o T a p _ A l l _ T e s t s . v er 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A F i n a l G e o T a p . p d f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A L W D F i n a l M D . p d f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A L W D F i n a l T V D . p d f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A F i n a l G e o T a p . t i f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A L W D F i n a l M D . t i f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 9 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A L W D F i n a l T V D . t i f 39 9 4 4 ED Di g i t a l D a t a DF 1/ 1 6 / 2 0 2 5 70 3 7 2 7 5 0 E l e c t r o n i c D a t a S e t , F i l e n a m e : B C U 0 9 A S C B L MA I N P A S S 1 0 - 2 6 - 2 0 2 4 . l a s 39 9 5 8 ED Di g i t a l D a t a DF 1/ 1 6 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A S C B L M A I N P A S S 1 0 - 26 - 2 0 2 4 . p d f 39 9 5 8 ED Di g i t a l D a t a DF 1/ 1 6 / 2 0 2 5 E l e c t r o n i c F i l e : B C U - 0 9 A S C B L 1 0 - 2 6 - 2 4 . p d f 39 9 5 8 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 39 9 0 4 9 2 7 E l e c t r o n i c D a t a S e t , F i l e n a m e : B C U 0 9 A G P T 1 1 - 15 - 2 4 . l a s 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 59 0 0 6 9 5 2 E l e c t r o n i c D a t a S e t , F i l e n a m e : B C U 0 9 A T E M P LO G F L O W I N G . l a s 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 60 7 3 6 8 9 9 E l e c t r o n i c D a t a S e t , F i l e n a m e : B C U 0 9 A T E M P LO G S H U T - I N . l a s 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 69 2 6 6 4 6 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : B C U 0 9 A , B E L 10 S A N D , 6 6 6 7 - 6 6 7 7 , C O R R E L A T I O N 1 1 - 1 4 - 20 2 4 . l a s 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 70 2 0 6 4 5 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : B C U 0 9 A , B E L 11 S A N D 6 7 5 6 - 6 7 7 6 , C O R R E L A T I O N P A S S 1 1 - 13 - 2 0 2 4 . l a s 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 70 4 4 5 9 3 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : B C U 0 9 A , B E L 11 S A N D 6 8 0 1 - 6 8 0 7 , C O R R E L A T I O N P A S S 1 1 - 13 - 2 0 2 4 . l a s 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 64 0 0 7 0 5 7 E l e c t r o n i c D a t a S e t , F i l e n a m e : B C U 0 9 A , G P T LO G 1 1 - 1 4 - 2 0 2 4 . l a s 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 55 0 0 7 0 5 8 E l e c t r o n i c D a t a S e t , F i l e n a m e : B C U 0 9 A G P T LO G 1 0 - 3 0 - 2 0 2 4 . l a s 40 0 5 3 ED Di g i t a l D a t a We d n e s d a y , J u n e 1 1 , 2 0 2 5 AO G C C P a g e 4 o f 6 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 4 4 5 - 0 1 - 0 0 We l l N a m e / N o . BE A V E R C K U N I T 0 9 A Co m p l e t i o n S t a t u s 2- G A S Co m p l e t i o n D a t e 11 / 1 3 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 1 1 3 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 71 2 9 TV D 67 3 0 Cu r r e n t S t a t u s 2- G A S 6/ 1 1 / 2 0 2 5 UI C No We l l C o r e s / S a m p l e s I n f o r m a t i o n : Re c e i v e d St a r t S t o p C o m m e n t s To t a l Bo x e s Sa m p l e Se t Nu m b e r Na m e In t e r v a l IN F O R M A T I O N R E C E I V E D Co m p l e t i o n R e p o r t Pr o d u c t i o n T e s t I n f o r m a t i o n Ge o l o g i c M a r k e r s / T o p s Y Y / N A Y Mu d L o g s , I m a g e F i l e s , D i g i t a l D a t a Co m p o s i t e L o g s , I m a g e , D a t a F i l e s Cu t t i n g s S a m p l e s Y / N A Y Y / N A Di r e c t i o n a l / I n c l i n a t i o n D a t a Me c h a n i c a l I n t e g r i t y T e s t I n f o r m a t i o n Da i l y O p e r a t i o n s S u m m a r y Y Y / N A Y Co r e C h i p s Co r e P h o t o g r a p h s La b o r a t o r y A n a l y s e s Y / N A Y / N A Y / N A CO M P L I A N C E H I S T O R Y Co m p l e t i o n D a t e : 11 / 1 3 / 2 0 2 4 Re l e a s e D a t e : 9/ 1 9 / 2 0 2 4 DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A G P T 1 1 - 1 5 - 2 4 . p d f 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A G P T - P E R F - T E M P FI N A L . p d f 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A T E M P L O G FL O W I N G . p d f 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A T E M P L O G S H U T - IN . p d f 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A , B E L 1 0 S A N D , 6 6 6 7 - 66 7 7 , C O R R E L A T I O N 1 1 - 1 4 - 2 0 2 4 . p d f 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A , B E L 1 1 S A N D 6 7 5 6 - 67 7 6 , C O R R E L A T I O N P A S S 1 1 - 1 3 - 2 0 2 4 . p d f 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A , B E L 1 1 S A N D 6 8 0 1 - 68 0 7 , C O R R E L A T I O N P A S S 1 1 - 1 3 - 2 0 2 4 . p d f 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A , G P T L O G 1 1 - 1 4 - 20 2 4 . p d f 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A G P T F I N A L 1 0 - 3 0 - 20 2 4 . p d f 40 0 5 3 ED Di g i t a l D a t a DF 2/ 7 / 2 0 2 5 E l e c t r o n i c F i l e : B C U 0 9 A G P T L O G 1 0 - 3 0 - 20 2 4 . p d f 40 0 5 3 ED Di g i t a l D a t a We d n e s d a y , J u n e 1 1 , 2 0 2 5 AO G C C P a g e 5 o f 6 DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 50 - 1 3 3 - 2 0 4 4 5 - 0 1 - 0 0 We l l N a m e / N o . BE A V E R C K U N I T 0 9 A Co m p l e t i o n S t a t u s 2- G A S Co m p l e t i o n D a t e 11 / 1 3 / 2 0 2 4 Pe r m i t t o D r i l l 22 4 1 1 3 0 Op e r a t o r Hi l c o r p A l a s k a , L L C MD 71 2 9 TV D 67 3 0 Cu r r e n t S t a t u s 2- G A S 6/ 1 1 / 2 0 2 5 UI C No Co m m e n t s : Co m p l i a n c e R e v i e w e d B y : Da t e : Da t e C o m m e n t s De s c r i p t i o n We d n e s d a y , J u n e 1 1 , 2 0 2 5 AO G C C P a g e 6 o f 6 6/ 1 1 / 2 0 2 5 M. G u h l 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name:6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address:7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section):8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:9. Ref Elevations: KB: 17. Field / Pool(s): Beaver Creek Unit GL: 160.4' BF: N/A 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 N/A (ft MSL) 22.Logs Obtained: 23. BOTTOM 3-1/2"L-80 6,730' 3-1/2"L-80 2,670' 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 Rate 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 L - 349 sx / T - 78 sx CBL 10-26-24, Geotap(FTWD), LWD(PCG, ADR, ALD, CTN, PWD, DDSR), Perf/Tie In Logs. PACKER SET (MD/TVD) N/A 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 317379 2434004 50-133-20445-01-00October 12, 2024 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 11/13/2024 224-113 / 324-549 / 324-501 N/A BCU 09AOctober 17, 20241188' FNL, 1567' FWL, Sec 34, T7N, R10W, SM, AK 178.4' Beluga Gas Pool A028083 N/A 3,075' MD / 2,834' TVD N/A 7,129' MD / 6,730' TVD 6,346' MD / 6,057' TVD 2291' FSL, 1396' FWL, Sec 34, T7N, R10W, SM, AK 2158' FSL, 1383' FWL, Sec 34, T7N, R10W, SM, AK AMOUNT PULLED 317184 317169 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, 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 only if necessary. GRADE CEMENTING RECORD 2432205 SETTING DEPTH TVD 2432072 TOP HOLE SIZEBOTTOMCASINGWT. PER FT. 6" SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 9.3#Surface 2,882'Surface Tieback Choke Size: 2,660' Per 20 AAC 25.283 (i)(2) attach electronic information 9.2#7,129' Water-Bbl: PRODUCTION TEST 11/13/2024 Date of Test:Oil-Bbl: Flowing *** Please see attached schematic for perforation details *** Gas-Oil Ratio: 2,870' Tieback Assy. Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl:Water-Bbl: 0 0882123 1/2/2025 24 Flow Tubing 0 520 N/A5200 G s d 1 0 p d B P L s (att Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 2:44 pm, Jan 09, 2025 Complete 11/13/2024 JSB RBDMS JSB 012725 GDSR-4/7/25 324-610 / SFD 3/27/2025BJM 5/12/25 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval 6,319' (BEL 6) 5,932' 3287' 3012' 4638' 4276' 5215' 4844' 6145' 5760' 6216' 5829' 6250' 5864' 6319' 5932' 6363' 5975' 6430' 6041' 6014' 6192' 6665' 6272' 6751' 6357' 7043' 6645' 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 Digital Signature with Date:Contact Email:cdinger@hilcorp.com Contact Phone: 907-777-8389 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: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered)FORMATION TESTS Beluga 9 Beluga 10 Beluga 11 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. 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). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 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). Authorized Name and Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. INSTRUCTIONS Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt Reports. Authorized Title: Drilling Manager Beluga 8 Sterling A Sterling D Beluga Beluga 7 Sterling C Sterling B Beluga 5 Beluga 6 Formation Name at TD: 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. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Beluga 13 N Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.01.09 12:19:23 - 09'00' Sean McLaughlin (4311) _____________________________________________________________________________________ Updated by CJD 1-7-25 SCHEMATIC Beaver Creek Unit Well: BCU-09A PTD: 224-113 API: 50-133-20445-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8”Conductor 61 / J-55 / Butt 12.515”Surf 116’ 9-5/8"Intermediate 47 / N-80 / BTC 8.861”Surf 1,853’ 7"Intermediate 29 / N-80 /BTC 6.276”Surf 3,075’ (TOW) 3-1/2”Prod Casing 9.2 / L-80 / Hyd 563 2.991”2,870’7,129’ 3-1/2”Tieback Tbg 9.2 / L-80 / EUE 8RD 2.991”Surf 2,882’ OPEN HOLE / CEMENT DETAIL 13-3/8”Driven 9-5/8"TOC @ Surface 700 sx 7”TOC @ 2,800’ MD 350 sx Stg 1 / 215 sx Stg 2 3-1/2”TOC @ ±2,852’ (CBL 10/26/24) L – 349 sx / T – 78 sx JEWELRY DETAIL No.Depth Item 1 1,504’Chemical Inj Sub 2 2,870’Liner Top Packer 3 2,882’Seal Stem 4 6,346’CIBP (12/28/24) 5 6,371’CIBP (12/23/24) 6 6,386’CIBP (12/17/24) 7 6,426’CIBP (11/26/24) 8 6,450’CIBP (11/25/24) 9 6,486’CIBP (11/24/24) PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status BEL 6 6,319’6,329’5,932’5,941’10’12/29/2024 Open BEL 6 6,349’6,363’5,961’5,975’14’12/23/2024 Isolated BEL 7 6,374’6,380’5,985’5,991’6’12/23/2024 Isolated BEL 7B 6,402’6,408’6,013’6,019’6’11/26/2024 Isolated BEL 7B 6,414’6,420’6,025’6,031’6’11/26/2024 Isolated BEL 8 6,431’6,441’6,042’6,052’10’11/25/2024 Isolated BEL 8 6,456’6,465’6,067’6,076’9’11/24/2024 Isolated BEL 9 6,596'6,606'6,205'6,215'10'11/14/2024 Isolated BEL 10 6,667'6,677'6,274'6,284’10'11/14/2024 Isolated BEL 11 6,756'6,776'6,372'6,382'10'11/13/2024 Isolated BEL 11 6,801'6,807'6,407'6,413'6'11/13/2024 Isolated Page 1/5 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Well Operations Summary Jobs Actual Start Date:10/3/2024 End Date:10/23/2024 Report Number 5 Report Start Date 10/7/2024 Report End Date 10/8/2024 Operation Crews meet at CCI Yard, begin rigging down modules for move, CCI offload rig move equipment from barge, crew travel to Beaver Creek, Lay felt liner and set mats, off load equipment as it arrives on trucks, split apart rig stage for transport and P/U rig mats ship to beaver creek. Continue laying rig mats as arrive, pull sub and draw works down and stage on trucks, transport to beaver creek, continue hauling modules and staging in beaver creek, transport cranes to beaver creek and spot in, set sub on pony subs and center over well, set draw works and derrick on sub and pin, set doghouse/water tank, raise doghouse and pin in drilling position, rest crews for the night break tours. Rest crews, break tours. Report Number 6 Report Start Date 10/8/2024 Report End Date 10/9/2024 Operation Crews arrive on location, rig movers transporting equipment from yard, begin riggin up modules, spot crane set derrick board wind walls, prep to raise mast, spot in pit modules and pump skids. Continue rigging up modules, prep and raise mast, set in gen shed and top drive HPU, spot boiler complexes, continue rigging up rig modules. R/U tool pushers trailer and sleeper shack Hook up Pason . Hook up electric, water, fuel and started on steam lines. Installed vent line and raised poor boy degasser. Install hand rails. Installed and hooked up lights. Spotted and hooked up gen 3. Spotted 3rd party shacks. Cont. installing steam lines. Spool drill line and prep to scope derrick. Scope derrick. Report Number 7 Report Start Date 10/9/2024 Report End Date 10/10/2024 Operation Continue R/U modules, P/U T and secure torque tube R/U and P/U top dive in cradle , secure to blocks remove cradle, P/U torque bushing, and M/U to top drive and torque tube, hook up top drive and service loop, rig smart still installing system Install IBOP and saver sub on topdrive, spot in fuel tank continue rigging up rig systems, install gas alarm system and function test, set in fuel tank and fuel rig, trouble shoot top drive function, dress shakers, fill rig tank with water get it going around rig, fill boiler and begin staging up boiler.. Repair 37 pin on top drive. Dress rig floor. R/U moneky board and install pull back ropes. Weight indicator stuck at 52k- trouble shoot. Will have zack with Quadco take a look. Meanwhile installed one of teh old weight indicators. R/U iron roughneck and dress with dies. Hooked up rig smart. R/U pits and mud pumps. Hooked up centrifuge mud lines and vacuum degassser. Run water through pits and function test pit volume alarms. Clean and rinse pits. Remove shipping beams. Install DSA on BOP and stab onto wellhead. Connect kill and choke line. Stage up boilers to full pressure. Change oil and filter on rig loader. Fill pits with water. Report Number 8 Report Start Date 10/10/2024 Report End Date 10/11/2024 Operation Tighten bolts on stack, install choke and kill lines, install flow box and riser , install bell nipple, secure stack. Quadco calibrate weight indicator and all gauges on choke accumulator and drillers console, install swivel packing on top drive. Install Test plug and tighten lock down as per vault rep, charge accumulator and function test BOP Stack, install test jt and R/U for testing. R/U and test BOP's w/ 4.5'' test jt t/ 250 low for 5 min and 5000 high f/ 10 min state and BLM inspectors witnessing. attempt first test tighten leaks on annular cap and choke manifold flanges, bleeed and retest good, test number 2 HCR kill leaking grease and retest then door seal leaking had to change and retest, re flood stack and purge air continue testing. Replaced test hose fitting. Reflooded, purged air. and re-test, pulled test joint reflooded stack, function rams, reinstalled test joint purged air and re-tested-pass. Test #3-UPR, TIW valve, inside kill, CM-valve- #4,5,6-Pass Test #4-UPR, TIW valve, inside kill, CM-valve-#1,2,3-Pass Test #5-UPR, TIW, Inside kill, choke HCR-fail. Grease choke and function re-test-pass Test #6- Accumulator draw down test-Pass Test #6- Blind rams, inside choke-Fail/Pass. Inside choke failed on high, greased and functioned, re-test DSA failed on low tig htened flange, re-test. Test fitting failed on high, changed fitting. Test #8- Manual choke, pressured up to 2000psi hold, bled off to 1500psi caught pressure and hold-Pass Test #9- Electric choke-Fail/Pass. Choke would not hold pressure. Disassembled and found choke was not put together properly. Re-assmeble. and test. R/D test equipment and blow down surface lines and choke manifold. Report Number 9 Report Start Date 10/11/2024 Report End Date 10/12/2024 Operation R/D test equipment, pull test plug set wear ring, blow down lines, load pipe on racks and prep to P/U Comission Rig Smart system, trouble shoot system not working correctly work on rig smart system, test mud lines w/ new test pump, replace leaking 4'' valve on Rack strap and tally 4.75" spiral drill collars. Mob clean out components to rig floor. M/U BHA #1., bit, scraper, mill and drill collars. P/U and RIH w/ 16 joints of 4.5" HWDP t/684'. RIH w/ 4.5" DP singles from cat walk f/684' t/1662'. Pason crashed multiple times. Trouble shooting with Pason tech support. Report Number 10 Report Start Date 10/12/2024 Report End Date 10/13/2024 Operation Continue wiating on Pason to fix their rig sytem. Field: Beaver Creek Sundry #: State: ALASKA Rig/Service: HEC 169Permit to Drill (PTD) #:224-113 Wellbore API/UWI:50-133-20445-01-00 Page 2/5 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Continue RIH w/ clean out assembly P/U DP single f/ 1662' t/ 3128' tag cement, dress off Displace well t/ 8.9pp g 6% KCL polymer mud system. Work on rig smart system POOH f/ 3168' t/ BHA Rack back and L/D BHA bit mills and crossover Level derrick and service rig recalibrate draw works encoder M/U WIS mill assembly on bottom of 4" HWDP singleas per WIS rep. M/U Sperry directional tools on top of HWDP and perform offset. P/U and M/U whipstock on bottom of mill asembly. RIH w/ 6 4.75" spiral drill collars and and 8 stands of 4.5" HWDP. t/ 765'. TIH out of derrick f/765' t/1541'. P/U-43K, S/O-40K. Disp: Calc-22.9bbl, Act-23bbl. Cont. to RIH f/1541' t/3085' Orient Whipstock to 34L TF. RIH t/3128' and trip anchor w/ 8K. P/U 3' and set down 5k to ensure anchor tripped. P/U t/ 3094' (TOW 3075'). S/O and observe shear w/ 28k. P/U-73K, S/O 60K. Begin milling at 3075'. 234GPM=965PSI, 60RPM=5.5-8.9k TQ. P/U-73K, S/O-58K, ROT-66K. While milling hydraulic oil began leaking out of hard line on the derrick for the Top Drive. Report Number 11 Report Start Date 10/13/2024 Report End Date 10/14/2024 Operation Continue replacing Hydraulic hose in derrick, remove washed out 90 on the service loop reconnect service loop and purge hydraulic system, function test top drive Resume Milling Window f/ 3077' t/ 3085' 230 gpm 1-2k WOB 8.5k torque Drill 20' of new hole t/3105'. P/U-75K, S/O-60K, ROT-70K. Drift window without pumps- no overpulls observed. Pumped 25bbl hi vis walnut sweep around. Sweep back ontime with10% increase in cuttings. 237GPM=1000PSI, 40RPM=5-8K TQ. Obtained SPR's. R/U test equipment and perform FIT. Obtained 14.1ppg EMW (770psi) Pumped 0.38bbl, bled back 0.30bbl. Flow check well-static. POOH on elevators f/3058' t/805'. Hole fill: Calc-13.8bbl, Act-13.05bbl. Cont to POOH f/805' t/ bha at 765'. Rack back HWDP. L/D 6 spiral drill collars, MWD tools, and mills. Starter mill-1/16" under, middle and upper mills were in guage. Service and inspect, crown, blocks, top drive, saver sub, iron roughneck, drawworks, gear box, drive chain, drive line, brake linkage, and floor motor. P/U directinal/rathole bha #3. M/U 6" mill tooth bit to SperryDrill. M/U DM and TM collar and perform RFO. P/U flex collars x 2. RIH w/ 3 stnds of HWDP. P/U jars and HWDP single. Cont t/ RIH with 5 stnds of HWDP t/670' Cont. to RIH picking up 13 jnts of 4.5" DP from catwalk f/670' t/1048' Report Number 12 Report Start Date 10/14/2024 Report End Date 10/15/2024 Operation Continue RIH P/U DP f/ 1048' t/ 3051' orient before going through window, wash last stand to bottom no issues passing through window. Drill 6'' Hole f/ 3105' t/ 3300' to accomodate smart tools, 250 gpm 1300 psi 60 rpm 5-7k tq 70k PUW 58k SOW 65k ROT 9 ppg MW CBU, obtain SPR's and Flow check well static slight loss POOH f/ 3300' t/ BHA no issues passing through window. L/D rathole BHA as per DD/MWD. L/D jars due to upper deal being damaged.Bit Graded: 1-1-WT-A-E-I-NO-BHA PJSM-P/U BHA #4. M/U new 6"HDBS PDC bit to 4.75" SperryDrill. Make up DM collar and perform offset. Cont. to M/U MWD tools to TM collar. Plug in and download MWD tools. Perform shallow pulse test and then load sources. RIH with 3 stnds of HWDP, P/U new jars and HWDP single. Cont to RIH out of derrick w/ 5 stnds of RIH P/U 20 jnts of 4.5" DP singles f/692' t/1345'. Cont. t/ RIH P/U 38 jnts of 4.5" DP singles f/1345 t/2511'. Service and inspect: crown, blocks, top drive, saver sub, iron roughneck, drawworks, gear box, drive chain, drive line, brake linkage, floor motor, clean MP suction screens. Cont to RIH out of the derrick f/2511/ t/3300'. Oriented TF at 3072'. No issues passing through the winow. Wash last stand to bottom. P/U-63K, S/O-51K. Resume drilling ahead in 6" production hole section f/3300' t/3512'. 225GPM=1275PSI, 50RPM=5.7k Tq. MW 8.9, Max Gas-82 units. P/U-76K, S/O-60K, ROT-74K. Report Number 13 Report Start Date 10/15/2024 Report End Date 10/16/2024 Operation Cont drilling 6" hole from 3510' to 3900'. Rot wob 3K, 225 gpm-1300 psi, 60 rpm-6000 ft/lbs on bott torque, 120 ft/hr ROP. MW 8.9/vis 53, ECD 10.6 ppg, BGG 28 units, max gas 85 units. Cont drilling 6" hole from 3900' to 4328'. Sliding wob 3K, 236 gpm-1320 psi, 55 psi diff, 87 ft/hr ROP. Rot wob 1-3K, 232 gpm-1382 psi, 60 rpm-6640 ft/lbs on bott torque, 120 ft/hr ROP. MW 8.9+/vis 55, ECD 10.6 ppg, BGG 6 units, max gas 129 units. CBU twice at 233 gpm-1302 psi, obtained on bottom survey and SPR's, performed 10 minute flow check. Pulled 17 stand wiper trip from 4328' up to 3300'. P/U-110K, S/O-75K. Service and inspect: crown, blocks, top drive, saver sub, iron roughneck, drawworks, gear box, drive chain, drive line, brake linkage, floor motor, clean MP suction screens. CBU, pump 25bbl hi vis sweep around. Back on time with 30% increase in cuttings. 228GPM=1450psi, 60RPM=6.3k Tq RIH on elevators f/3300' t/4327'. Wash last stand down. P/U-95K, S/O-65K. Drill 6" hole f/4327' t/4832'. 225 gpm-1300 psi, 60 rpm=6k Tq 1-3k WOB MW 8.9/vis 54, ECD 10.4 ppg, max gas 6 units. P/U-105k, S/O-74k, ROT-84k. Report Number 14 Report Start Date 10/16/2024 Report End Date 10/17/2024 Field: Beaver Creek Sundry #: State: ALASKA Rig/Service: HEC 169 Page 3/5 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Cont drilling from 4832' to 5286', rot wob 2-3K, 227 gpm-1382 psi, 60 rpm-7750 ft/lbs on bott torque, 120 ft/hr ROP. MW 8.9/vis 53, ECD 10.5 ppg, BGG 15 units, max gas 69 units. Received 400 sx lead cement in silo. Cont drilling from 5286' to 5393', rot wob 2-3K, 235 gpm-1548 psi, 60 rpm-7980 ft/lbs on bott torque, 120 ft/hr ROP. MW 8.9/vis 51, ECD 10.5+ppg, BGG 3 units, max gas 32 units. CBU twice at 239 gpm-1585 psi, 60 rpm-8000 ft/lbs off bott torque. RU GeoSpan unit in cellar, obtained on bottom survey and SPR's, 10 minute flow check = slight seepage. Pulled up hole on elevators from 5393' to 4322' with no issue. Up wt 140K. Serviced rig and topdrive, cleaned suction screens on mud pumps, fluid packed GeoSpan unit checking for leaks (no leaks). Re-booted Pason to correct time display. TIH from 4322' to 5331' with no issue, dwn wt 75K. MU topdrive on last stand, filled pipe, washed/reamed to bottom. Pumped a 20 bbl hi-vis nutplug sweep around at 232 gpm-1640 psi, 60 rpm-8000 ft/lbs off bott torque. Max gas 12 units at bottoms up, sweepback on time with 20% increase in cuttings. Cont drilling from 5393' to 5770'. 239GPM=1567PSI, 60RPM=8.6K Tq, 1-3K WOB, MW-8.95ppg, ECD-10.67, Max gas=442. P/U-130K, S/O-76K, ROT-101K. Cont drilling from 5770' to 6205'. 230GPM=1790PSI, 60RPM=9K Tq, 1-3K WOB, MW-8.95ppg, ECD-10.55, Max gas=180. P/U-146K, S/O-82K, ROT-107K. CBU x1 priror to wiper trip. 230GPM=1500, 60RPM=9k Tq. Report Number 15 Report Start Date 10/17/2024 Report End Date 10/18/2024 Operation Obtained on bottom survey and SPR's, 10 minute flow check = slight seepage. Pulled wiper trip up hole from 6205' to 5390' with no issue, up wt 156K. Serviced rig and topdrive, cleaned mud pump suction screens. TIH from 5390' to 6143' with no issue, MU topdrive on last stand, filled pipe, washed/reamed to bottom at 6205'. Pumped a 20 bbl hi-vis nutplug sweep around at 238 gpm-1706 psi, 80 rpm-7800 to 9000 ft/lbs off bott torque. Max gas at bottoms up 34 units. Sweep back 150 strokes late but brought back 100% increase in cuttings. Cont drilling from 6205' to 6330. Rot wob 4-5K, reduced rate of 200 gpm-1446 psi, 60 rpm-9340 ft/lbs on bott torque, reduced ROP of 60 ft/hr. Sliding wob 1K, 200 gpm-1428 psi, 82 psi diff, 75 ft/hr ROP. MW 8.9+/vis 54, ECD 10.4 ppg, BGG 4 units, max gas 284 units. No sign of losses drilling into the Beluga 6. Cont drilling from 6330' to 6572', rot wob 2-7K, reduced gpm of 180-1264 psi, 60 rpm-10,200 ft/lbs on bott torque, 60 ft/hr ROP. MW 9.0/vis 54, ECD 10.4+ ppg, BGG 20 units, max gas 188 units. No sign of losses drilling into the Beluga 7. Cont drilling from 6572' to 6833', rot wob 2-6K, 233 gpm-1860 psi, 60 rpm-10,200 ft/lbs on bott torque. MW-9.0PPG, ECD-10.8PPG, Max gas-94 units. P/U-150K, S/O-90K, 115K. Cont drilling from 6833' to TD at 7129', rot wob 2-6K, 233 gpm-1860 psi, 60 rpm-11.1k Tq. MW-9.0PPG, ECD-10.67PPG, Max Gas-148. P/U-157K, S/O-95K, 120K. Obtain final survey. Pump sweep and circulate hole clean. 230GPM=1710PSI, 60RPM=10.6k Tq. Report Number 16 Report Start Date 10/18/2024 Report End Date 10/19/2024 Operation Finish pumping sweep out of the hole. Back 9bbl late w/ 20% in crease. 230GPM=1700PSI, 60RPM=10.7K Tq Obtained on bottom survey and SPR's, 10 minute flow check = slight seepage. Pulled wiper trip up hole from 7129'' to 3103' with no issue. Mad passed at 6830', 6385', 6165' to fill gaps in logs from bad detection. P/U-185K. S/O-110K. Serviced rig and topdrive, cleaned suction screens on mud pumps, fluid packed GeoSpan unit checking for leaks (no leaks). Re-booted Pason to correct time display. RIH on elevators f/3133' t/ 7074' set down 15k not able to work past. Wash/ream to bottom. Filled pipe every 1500'. Pumped 20 bbl hi vis nut plulg sweep while roataing and reciprocating pipe. Max gas-42 units. Sweep back 14 bbl early with a 25% increase. 230GPM=1820PSI,80RPM=10.3k Tq Pull up the hole to 6920' MAD Pass #1 f/6920' t/6900'. MAD Pass #2 f/6690' t/6670'. Geotap stations:station 1- 6769', station 2-6599', station 3-6494', station 4-6461', station 5-6559'. P/U-145k, S/O-90k. MW-9.0ppg Cont. Geotap tests: station #5-6461', station #6-6436', station #7-6395', station #8-6377', station #9-6357', station #10 6326'. Unable to get a good test at staion #8. 243GPM=1795PSI, MW-9.0ppg Report Number 17 Report Start Date 10/19/2024 Report End Date 10/20/2024 Operation Obtained last two GeoTap stations at 6305' and 6271', blew down topdrive. RIH on elevators from 6271' to 7084', dwn wt 97K. MU topdrive on last stand, filled pipe, washed/reamed to bottom at 7129'. Pumped a 20 bbl hi-vis nutplug sweep around at 237 gpm-1810 psi, 80 rpm-11,700 ft/lbs on bott torque. Max gas at bottoms up 2 units. Sweep back 300 strokes late (17 bbls) and had 75% increase in cuttings. Notified AOGCC of upcoming MIT's. Pulled up hole from 7129' to 6956', up wt 105K. At 6956' blew down topdrive and GeoSpan unit. Cont to POOH to 4948' with no issue. Cont POOH from 4948' to HWDP at 692', dropping 2.39" hollow drift with wire at 2890'. 10 minute flow check fluid dropped 2' in wellbore. Cont cleaning pre-mix tanks. Racked back 8 stands HWDP, L/D jars and single joint, held PJSM and removed sources, plugged in and downloaded MWD data. Called out wellhead rep to pull wear ring and set test plug. Cont flushing and L/D Sperry smart tools, bit graded 1-1 in gauge. Clean and cleared rig floor/catwalk. P/U test joint, M/U XO subs and pull wear ring and set test plug. Test annular and UPR's w/ 3.5" test joint 250/2500psi 5/10min. Field: Beaver Creek Sundry #: State: ALASKA Rig/Service: HEC 169 Page 4/5 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation R/U Parker TRS casing equipment. M/U TWI and swedge. PJSM w/ casing crew. M/U and Baker Loc shoe track. Test floats-good. Cont to RIH w/ 3.5" H563 9.2lb/ft liner as per tally f/ surface t/ 2935'. Filling on the fly and topping off every 10. Report Number 18 Report Start Date 10/20/2024 Report End Date 10/21/2024 Operation Cont PU single in hole with 3 1/2" liner from 2935' to 3057', MU circ swedge and topdrive. CBU just above window at 3 bpm-169 psi, then obtained rotating parameters at 10-2650, 20-2980 and 30-3365 ft/lbs, blew down topdrive. Cont PU single in open hole from 3057' to 4229'. PU Yellow Jacket Ranger liner hanger and Scout packer assembly. Mixed and poured xanstar, RD tubing tongs and airslips, PU and singled in 2 jnts of 4 3/4" DC's. MU XO and topdrive, pumped liner volume at 132 gpm-285 psi, obtained rotating parameters at 10-3100 and 20-3375 ft/lbs. Shut down and blew down topdrive. Cont PU single in another 11 jnts of 4 3/4" DC's to 4671', crossed over to HWDP and ran 8 stands to 5165'. Cont TIH at 25 to 30 ft/min getting decent displacement, to 5284', MU topdrive and filled pipe, blew down topdrive. Up wt 83K, dwn wt 70K. Cont TIH on DP from 5284' to 6229', MU topdrive and filled pipe at 133 gpm-452 psi, blew down topdrive and called out cementers. Cont TIH from 6229' to 7109', MU topdrive on extra stand, with pump at idle washed down and tagged bottom at 7131' three times, racked back stand, PU 15' pup followed by YJ cement head with 10' pup on bottom, MU topdrive and torqued through. Cont to circ and work pipe at 136 gpm-490 psi, max gas at bottoms up 31 units. Up wt122K, dwn wt 85K. Tried to rotate on down stroke but torque went to 5800 ft/lbs so canceled that. Laid down liner and spotted Fox Energy cement pump unit and bulk trailer. Strung out mud line and hardware to RU on cement line and cement head. Held PJSM with rig team and cementers. Fox Energy pumped 5 bbls water to flush and fill lines. Shut in at YJ cement head and PT lines at 500 psi low 4580 psi high. Good tests. Lined up YJ cement head to hole, pumped 30 bbls 11 ppg FMP300 Spacer at 4 bpm-500 to 470 psi, followed with 130 bbls (349 sx) 12.5 ppg Class G Lead cement at 4-5 bpm-330psi to 130psi, followed with 17 bbls (78 sx) 15.3 ppg Class G Tail cement at 2 bpm- 25psi. Had 1 ppb of fibre LCM in Spacer. YJ released plug, Fox then displaced with 9.0 ppg 6% KCL mud at 4 bpm- 20 to 330 psi. With 28 bbls to go, reduced rate to 2 bpm-630 to 900 psi and bumped plug on landing collar at 68.25 bbls into displacement (calculated at 69.5 bbls). FCP 1500 psi. Fox increased to and held 2300 psi (800 over fcp) for 3 minutes, bled back 0.5bbl to truck and floats held. Brought pressure up to 2300 psi for 3 minutes to set hanger. Slacked off on blocks from 122K to 15K, giving us a good indication hanger was set. CIP at 22:53 on 10-20-2024. Pressured up to 3700 psi on setting tool for 2 min, seen packer set at 3700psi and running tool release. P/U to 80K with good indication of release. P/U 5’ set slips and R/D and L/D cement head. P/U 9’ to expose dog sub. Not able to get down to liner top had to P/U e-kelly. Set down 50k on liner top and rotated at 5rpm. L/D e-kelly. M/U TD to stump to circulate. Pressured up to 1000 psi on drill string and PU 13’ and pressure dumped. CBU x2 at 300 gpm-580 psi. Had 30 bbls spacer and 15 bbls cement/contaminated mud circulated to surface. No losses throughout the job. Reciprocated throughout job. RD and released Fox Energy. L/D 15' pup w/single of DP. POOH f/2770' t/413'. L/D 13 jnts of 4-3/4" spiral drill collars and YJ running tool. M/U johnny whacker and flush stack with black water. P/U cement head and break off pup jnts and XO's. Report Number 19 Report Start Date 10/21/2024 Report End Date 10/22/2024 Operation PU YJ tieback and lower PBR polish mill assembly. TIH to 2829’, MU topdrive, washed down and tagged with pump at idle TOL at 2870’. Dressed liner top as per YJ at 8 rpm-3K wob. Held PJSM then displaced upper wellbore to IFW at 273 gpm-782 psi. With clean water to surface shut down. Monitored wellbore (negative pressure) for 30 min while cleaning under shakers and troughs, no flow. CCI RU to vac wiper balls through DP on pipe rack. POOH from 2870' to surface and LD polish mill. CCI vac'd wiper balls on piperack, cleaned and dried threads, re-doped and installed thread protectors. PU YJ cement head, broke out pup joints and XO's. MU diffuser sub, RIH with DP from derrick to 2503' and MU topdrive. Pumped string volume to flush pipe. POOH from 2503' LD DP. Held kick while trip drill at 1687' and discussed drill with crew. Cont POOH LD DP to surface. R/U test equipment and test liner lap to 2500psi/30min-good test. Pumped 1.3bbl, bled back 1.3bbl. RIH w/ remaing 4.5" DP out of derrick f/ surface t/1725'. Pump pipe volume 409 storkes, to flush DP. Blow down top drive. POOH L/D 4.5" DP to catwalk f/1725' t/628'. Cont. to POOH L/D 4.5" DP f/628' t/ surface. Clean and clear rig floor. R/U Parker TRS casing equipment. M/U FOSV and XO. PJSM w/ casing crew and YJ. M/U YJ tieback seal assembly. RIH w/ 3.5" tubing as per tally f/ surface t/ 1882'. Report Number 20 Report Start Date 10/22/2024 Report End Date 10/23/2024 Operation Cont PU single in hole from 1882' with 3 1/2" 8 rnd tubing torqued to 3000 ft/lbs, to 2847', banding control line each joint. PU two extra joints and tagged liner top with no-go at 2870'. L/D the two joints, MU two 8' pups below jnt 94, PU landing joint/hanger wellhead reps and Polard rep terminated 3/8" control line at hanger and tested to 3000 psi for 5 min, good test. Ran 56 bands. Drained BOP stack, with IA valve open S/O and landed hanger, up wt 36K, dwn wt 34K, saw seals enter SBR, no-go 2.35' off seat. BLM Rep Quinn Sawyer on loc at 09:30, (AOGCC waived witness at 09:18 on 10-21-24). Wellhead rep RILD's while RU for MIT's. Pumped 21.85 gals down tubing to achieve 2530 psi and held 30 min on chart. Bled back 21.85 gals, good test. RU in IA and pumped 33.35 gals to achieve 2520 psi on 7" x 3 1/2" IA and held 30 min on chart. Lost 60 psi over 30 min with no psi increase on tubing or OA, could find no leaks, bled of then pumped 32.2 gals to achieve 2520 psi on IA, held 30 min on chart, bled back 32.2 gals, good test. RD test equipment. RD test equipment, B/O and L/D landing jnt, wellhead rep installed 2 way check in hanger. Flushed topdrive, choke manifold, gas buster, kill/choke lines, mud pumps and pop off's, pit lines and charge pumps with BaraKlean followed with BaraCorr followed with fresh water and cleaned tank bottoms. Field: Beaver Creek Sundry #: State: ALASKA Rig/Service: HEC 169 Page 5/5 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Removed flowline, flow riser, drip pan, 4 way chains, opened upper ram doors, cleaned, inspected and greased cavities, buttoned up doors, removed stack from wellhead and installed spacer spool for cradle fit, removed DSA from wellhead. With wellhead Rep installed master valve/cap on wellhead. Tested void & lower section of tree T/5000 psi for 10 min (ok). /d service loop & Kelly hose for TDS. Remved saver sub from TDS. R/D bails & elevators from TDS. Unpinned TDS from TQ bushing, set in craddle, and L/D same. L/D TQ bushing. Disassembled both MP's, inspected fluid ends and reassembled same (ok). R/D high/low pressure lines in pump house. Vacuumed out all remaining fluids from pit system. R/D transfer lines, equalizer lines, and dump line in the pits. R/D MGS and TT pump. R/D tongs and sent off rig floor, along with subs & XO's. Un-bolted T bar from TQ tube. Crew change, held PTSM. Cont. R/D and preparing rig for move. Blew down and winterized test pump. R/D gen #3. Performed mast inspection. Held PJSM, scoped to half-mast. R/D catwalk and laid over beaver slide, R/D koomey lines, R/D MGS and laid over. Unspooled drill line and cut off 17 wraps. Rig released at 06:00 on 10-23-24 Field: Beaver Creek Sundry #: State: ALASKA Rig/Service: HEC 169 Page 1/3 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:10/28/2024 End Date: Report Number 1 Report Start Date 10/26/2024 Report End Date 10/26/2024 Last 24hr Summary RIH W/ 1 11/16" CBL TOOLS , CALIBRATED @ 2840' PULLED A FREE PIPE LOG, RAN DOWN TO 7027' PULLED A REPEAT LOG, WENT BACK ON BOTTOM AND PULLED MAIN LOG SECTION TO TOP OF CMT @ 2852 ( BASICALLY TO THE LINER ) Report Number 2 Report Start Date 10/27/2024 Report End Date 10/27/2024 Last 24hr Summary Site visit and line up third party equipment. Report Number 3 Report Start Date 10/28/2024 Report End Date 10/28/2024 Last 24hr Summary PTW and PJSM. Spot in coil equipment. Rig up hardline. NU BOPS's. BOPE test 250/3000psi. Secure location. SDFN. Report Number 4 Report Start Date 10/29/2024 Report End Date 10/29/2024 Last 24hr Summary PTW and PJSM. Pick up IH and made up 2.13" OD reverse out BHA. Pressure test lubricator 250/2500psi. RIH. Tag @ 7071', picked up to 7065'. Pumped 20 bbls FW, 10 bbls gel, 9 bbls of water. Came online with N2, pumped 210k scf. Recovered 96 bbls of fluid. POOH and trapped 2400psi on WH. RDMO. Report Number 5 Report Start Date 10/30/2024 Report End Date 10/30/2024 Last 24hr Summary PTW and PJSM. Spot in E-line and rig up. Make up perf gun. PT lubricator 250/3000 psi. Open swab and 0 psi on tubing and 720 psi on IA. Confirmed no ice plug was present. Pulled tools into lubricator and closed swab. Called out Fox N2. Bled IA to 0 psi. Pressure up tubing to 2000 psi, IA tracked to 980 psi. Bled IA off again, appeared to flow at 90 psi for 45 minutes, SI and monitored tubing and IA. M/U GPT, RIH and located fluid level at 6,990'. Secured Well. SDFN. Report Number 6 Report Start Date 10/31/2024 Report End Date 10/31/2024 Last 24hr Summary PTW and PJSM. RDMO E-Line. Good PT on hanger and CIM line. Bleed WH down to 1000 psi, IA to 0psi. Fill IA with 3 bbls of diesel. Good 2500 psi MIT on IA. R/U slickline and Fox N2. Make up D&D hole finder. PT lubricator 250/2500psi. Set hole finder @ 2801' (Liner top seal assembly @ 2882') and pump N2, WH 2000 psi. Monitored 15 mins and no change in WH or IA pressure. Pulled hole finder, WH equalized to 1300 psi and IA came up to 200 psi. R/D E-Line and N2. Secure Well. SDFN Report Number 7 Report Start Date 11/11/2024 Report End Date 11/12/2024 Last 24hr Summary Pressure up IA to 300psi with MeOH Report Number 8 Report Start Date 11/12/2024 Report End Date 11/13/2024 Last 24hr Summary RU Fox N2, PT 250/3000psi - Good Pressure up tubing from 1,000psi to 2,000psi (36kSCF) Secure well. Final pressures T/IA 2000/475psi Report Number 9 Report Start Date 11/13/2024 Report End Date 11/14/2024 Last 24hr Summary PTW/PJSM. MIRU YJ E-line. T/I/O: 2047psi/1060 psi/0 psi. PT 250/2500 psi. RIH with 6' perf gun and identified fluid level at 69 60' using line tension on weight indicator. Perforate the BEL_11 sand (6801'-6807'). Pressure increased 1 psi/min. Draw down well to 1800 psi, SI and check fluid level, no change. Draw down to 1600 psi, SI and check fluid level, no change. Well pressure build at 2 psi/min. RIH with 20' gun, locate fluid level at 6960'. Perforate the BE L_11 sand (6756'-6776'). Draw down well from 1835 to 1600 psi and check fluid level - no change. Secure well, rig back e-line and begin flowing well test. Report Number 10 Report Start Date 11/14/2024 Report End Date 11/15/2024 Last 24hr Summary PTW/PJSM. FTP-109 psi (328 mcfd) / IA -860 psi. Rig YJ E-line back on well. RIH with GPT and locate fluid level at 6803' (BEL_11 perfs 6801'-6807'). SI well to build pressure. RIH with 10' perf gun. RU N2, top off well to 1800 psi and perforate the BEL_10 (6667'-6677') and the BEL_9 (6596'-6606'). Secure well and flow off N2 until 100 percent LEL and divert gas to sales line. Flow test well. (IA -885 psi) Report Number 11 Report Start Date 11/15/2024 Report End Date 11/16/2024 Last 24hr Summary PTW/PJSM with YJ E-line. FTP-76 psi / 250-350 mcfd. IA - 785 psi. Discuss diagonostics procedure to locate fluid influx. Rig E-line back on well and RIH with temperature / CCL and junk basket with 2.75" OD gauge ring. Run flowing temperature survey from 5900' - 6926' across BEL_9,10 & 11 sands. Tagged PBTD at 6926' (last tag 7040' 14-Nov-24). Shut in well and log 2 temperature warm back passes after 1-1/2 and 3 hrs. P/U GPT and locate fluid level at 4615'. SITP-1560 psi. Secure well and turn over to production to flow well. IA - 740 psi Report Number 12 Report Start Date 11/20/2024 Report End Date 11/20/2024 Last 24hr Summary Obtain PTW and hold PJSM with Pollard Wireline. T/I/O: 348/48/0. MIRU slickline and PT 250 / 2500. M/U 2.70" blind box, RIH and locate fluid level at 1130', then tag PBTD at 6715'(RKB). RIH and collect fluid sample. RD PWL and move to BCU-16rd. Operations crew, bled gas cap off IA, RU triplex,crystal gauges and recorded MIT of IA to 3069 psi. Pumped total of 1.5 bbls diesel. MIRU Fox N2, PT 250 low/4500 high. Online with N2, pumped to 3000 psi and 80K scfs. RD N2 and secure well. Field: Beaver Creek Sundry #: 324-610 State: ALASKA Rig/Service:Permit to Drill (PTD) #:224-113Permit to Drill (PTD) #:224-113 Wellbore API/UWI:50-133-20445-01-00 Page 2/3 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 13 Report Start Date 11/22/2024 Report End Date 11/22/2024 Last 24hr Summary PTW / PJSM. YJ E-line move from BC-11A to 9A and RU. T/I/O: 2157/3141/0. PT 250 low/2500 high. RIH w/ GPT and JBGR to 6630'. Fluid level below top perfs at 6596'-6606'. RIH and set CIBP at 6590'. Bleed well down to 1800 psi. RIH and perforate the BEL_8B interval 6492'-6498'. Gun wet. Secure well, rig back and release E-line for rig support. Monitor pressure. Report Number 14 Report Start Date 11/24/2024 Report End Date 11/25/2024 Last 24hr Summary PTW/PJSM with YJ E-line and Fox N2. MIRU and PT lines and lubricator 250 low/3500 high. RIH w/GPT and locate fluid level at 6160' (open perfs at 6492'-98'). On line with N2 and pump to 3250 psi and SD. GPT confirmed fluid into perfs, RDMO N2. RIH and set CIBP at 6486'. Draw down well to 1800 psi. RIH and perforate the BEL_8 sand 6456'-6465'. 15 min. increase 1879 psi. Secure well, rig back e-line and flow N2 back to tank in 200 psi increments and monitor 15 min. pressure builds. Steadily gained 50-60 psi during shut ins. Bled to 20 psi and detected LEL. SI at 0 psi at 20:40 hours. SDFN. Report Number 15 Report Start Date 11/25/2024 Report End Date 11/26/2024 Last 24hr Summary PTW/PJSM YJ E-line. T/I/O: 126/2908/0. RIH w/ GPT locate fluid level at 470'. MIRU Fox N2, PT 250/4000 psi. Pump N2 to 3,000 psi/92.5k scfs. Confirm fluid is pushed away with GPT to perfs at 6456'-6465'.RIH and set CIBP at 6450'. Draw down well to 1826 psi and perforate the BEL_8 sand 6431'-6441'. Well pressure increased to 1930 psi. Gun wet. Secure well and SDFN. Report Number 16 Report Start Date 11/26/2024 Report End Date 11/27/2024 Last 24hr Summary PTW/PJSM. T/I/O: 1970/3016/0. Rig YJ E-Line back on well, RIH w/ GPT and locate fluid level at 5985'. Open perfs at 6431'-41'. Park tools above FL. PTW/PJSM w/ Fox N2. Pump N2 to 2950 psi, see break over and SD pump. GPT confirmed fluid is away to open perfs. RIH and set CIBP at 6426'. Draw down well to 1800 psi and perforate the BEL_7B sand at 6414'-6420'. Gun dry, RIH w/ second 6' gun and perforate the upper BEL_7B interval 6402'-6408'. Well pressure decreasing at ~1 psi/min Gun dry. Secure well, rig back e-line and hand over to production to start flow back in 200 psi increments /15 min. shut ins. Report Number 17 Report Start Date 11/27/2024 Report End Date 11/28/2024 Last 24hr Summary PTW/PJSM with YJ E-Line and Fox N2. RIH w/ GPT and locate fluid level at 1220'. PT N2 lines 250/4500 psi. Pump N2 up to 3000 psi. SD pump wait 10 min. and lost 300 psi. Pump back up to 4000 psi. Wait 30 min. and lost 700 psi. Repeat pump cycle to 4000 psi. RIH with GPT and locate FL at 2300'. POOH. Pump pressure up to 4500 psi x 2, SD pump. RIH with GPT, locate fluid level at 3100', continue in hole and tag PBTD at 6288' (114' above perfs at 6402'-6408'). Secure well and SDFN. Report Number 18 Report Start Date 11/30/2024 Report End Date 11/30/2024 Last 24hr Summary PTW/PJSM. SITP: 3,110 psi. RU Pollard Slickline. PT lubricator w/ well pressure - good test. RIH w/ 2.25" bailer and tag @ 6,290' RKB. Bleed well pressure to 1375 psi. RIH w/ 2.5" bailer, tag @ 6,290'. RIH w/ 2.5" bailer, tag @ 6,289'. RIH w/ 2.25" pump bailer (no flapper) and agitate @ 6,289'. RIH w/ 2.5" bailer, tag @ 6,289'. Bleed well pressure to 500 psi. RIH w/ 2.5" bailer, tag @ 6,289'. RIH w/ 2.25" bailer, tag @ 6,291'. Tagging fluid level on all runs ~3,100'. SDFN. Report Number 19 Report Start Date 12/1/2024 Report End Date 12/1/2024 Last 24hr Summary PTW/PJSM. SITP: 500 psi. RU Pollard Slickline. Bail fill from 6,292'-6,309' RKB in 7 runs w/ 2.25" and 2.5" bailers. SDFN. Report Number 20 Report Start Date 12/2/2024 Report End Date 12/2/2024 Last 24hr Summary PTW/PJSM. SITP: 445 psi. RU Pollard Slickline. Bail fill from 6,309'-6,317' RKB in 5 runs w/ 2.25" and 2.5" bailers. Passed through bridge w/ 2.5" bailer and tag @ 6,424' RKB. Pressure increase to 650 psi and fluid level up from ~3,250' to 2,080'. RIH w/ 2.83" GR and tag @ liner top (2,875' RKB). RIH w/ 2.79" GR and tag @ 6,367' RKB. RIH w/ 2.5" bailer and tag @ 6,348' and WT 6,360' RKB. POOH and SDFN. Report Number 21 Report Start Date 12/2/2024 Report End Date 12/3/2024 Last 24hr Summary Bail from 6317'KB to 6330'KB - Discover crane issue - Diagnose Crane - Lay down lub and secure well - replace crane Report Number 22 Report Start Date 12/3/2024 Report End Date 12/4/2024 Last 24hr Summary Bail from 6309'KB to 6317'KB w/ different bailers - Sudden downhole change while opening up to well @ 14:20 -Fluid Level came up tag up @ 6424'KB w/ 2.5" Bailer - Run 2 different G-Rings (2.83" and 2.79") to 2887'KB - W/T w/ 2.79" G-Ring and make it through to 6367'KB and W/T again could not pass - Run 2.5" DD Bailer to 6348'KB - Lay down lub and secure well Report Number 23 Report Start Date 12/4/2024 Report End Date 12/5/2024 Last 24hr Summary Bail from 6323'KB to 6339'KB w/ 2.5" DD Bailer - Pressure up lub before opeening valves - Lose Hole- tag @ 6333'KB w/ Same - Continue bailing and playing with pressures - End @ 6340'KB bailing - Rehead - Secure well Report Number 24 Report Start Date 12/5/2024 Report End Date 12/6/2024 Last 24hr Summary Bail from 6340'KB to 6370'KB - Pressure match to well before runs - Find wells pressure balance point @ 627 psi Report Number 25 Report Start Date 12/6/2024 Report End Date 12/7/2024 Last 24hr Summary PTW/PJSM, Made several bailer & star bit runs. Bail sand from 6350'-6354' SLM (6372' RKB) Final T/I/O 624/1525/0 Field: Beaver Creek Sundry #: 324-610 State: ALASKA Rig/Service: Page 3/3 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 26 Report Start Date 12/8/2024 Report End Date 12/9/2024 Last 24hr Summary PTW/PJSM Report Number 27 Report Start Date 12/8/2024 Report End Date 12/9/2024 Last 24hr Summary BAIL FILL - Report Number 28 Report Start Date 12/9/2024 Report End Date 12/10/2024 Last 24hr Summary Bail down to 6390 Report Number 29 Report Start Date 12/10/2024 Report End Date 12/11/2024 Last 24hr Summary Bail down to 6393' kb Report Number 30 Report Start Date 12/11/2024 Report End Date 12/12/2024 Last 24hr Summary PJSM. Permit. Ran 1.75" DD and 2" pump bailers. Bail from 6390' to 6394' max depth. FL 1520' w/ 2.80" gauge ring. Inject N2 19,300 SCF's at 3500 PSI from 550 PSI SI. Original FL 1520'. Post N2 FL 1565'. Pressure did not break over. Tag fill 2.80 gauge ring 6393' MD. Final 1.75" bailer post N2 tag at 6393'. SDFN. Report Number 31 Report Start Date 12/12/2024 Report End Date 12/13/2024 Last 24hr Summary PJSM. Permit. 3280 PSI. Tag FL 1550'. Ran 1.75" DD, 2" and 2.25" pump bailers 6392' to 6396' MD. All came back empty. Also ran spear and 1.68" chisel to churn sand w/ not good results. Bled N2 off tubing mid day from 2750 to 1000 PSI and fluid off of IA from 1820 to 400 PSI. Did not make a difference in sand consistency. Secure equipment & well. SDFN. Plan forward: Continue trying to churn up sand and rerun bailers. Report Number 32 Report Start Date 12/13/2024 Report End Date 12/14/2024 Last 24hr Summary PTW/PJSM. Make 4 slickline bailer runs, tagging fill at 6,394'-6,395' MD. Recover small amount of hard-packed sand/clay and fluid. RD slickline. RU E-line. PT 250/2,500 psi. Run GPT log w/ 2.25" GR - found fluid level at 1,510' and tagged fill at 6,388' MD. SDFN. Report Number 33 Report Start Date 12/17/2024 Report End Date 12/18/2024 Last 24hr Summary PTW/PJSM. Set 2.75" CIBP @ 6386' MD Report Number 34 Report Start Date 12/21/2024 Report End Date 12/22/2024 Last 24hr Summary PTW/ PJSM. MIRU Fox CT. SDFN. Report Number 35 Report Start Date 12/22/2024 Report End Date 12/23/2024 Last 24hr Summary PTW/PJSM. SITP/IA/OA: 730/300/0 psi. RU Fox CT. Perform BOPE test to 250/3000 psi - all passed. RIH w/ nozzle on 2" coil and tag @ 6,380' CTM. Reverse out 41 bbls fluid (42 calculated) and POOH leaving 1750 psi on well. Pumped 101,252 scf (1087 gals) N2. RDMO Fox CT. Report Number 36 Report Start Date 12/23/2024 Report End Date 12/24/2024 Last 24hr Summary PTW/PJSM. SITP/IA/OA: 1740/1700/0 psi. RU YJ E-line. PT lubricator to 3000 psi - good test. RIH w/ 6' x 2 3/8" 5 SPF 60 deg guns and perf BEL 7 (6,374'-6,380'). RIH w/ GPT and find fluid level @ ~6,350' and tag CIBP @ 6,386'. RU Fox N2 and pump N2 @ 1100 scfm from 1740 psi to 3500 psi. Pumped 39,139 scf (420 gal) N2. RIH w/ GPT and did not see fluid level. RIH w/ CIBP and set @ 6,371', confirm set with tag. Bleed well pressure to 1800 psi. RIH w/ 14' x 2 3/8" 5 SPF 60 deg guns and perf BEL 6 (6,349'-6,363'). RIH w/ GPT and find fluid level @ 6,349' (top perf). PU above perfs and bleed 100 psi off well to 1726 psi and RIH w/ GPT to find fluid level @ 6,339' (up 10'). POOH, RDMO YJ. Report Number 37 Report Start Date 12/28/2024 Report End Date 12/29/2024 Last 24hr Summary PTW/PJSM. T/I/O=1003/2155/0, Ran GPT found fluid level @ 6326', tag @ 6368', Fox N2 pressured up tbg from 1000 - 3500psi. total 92113scf pumped. Retag W/ GPT @ 6369', no sign of fluid. Set 2.75" CIBP @ 6346' Report Number 38 Report Start Date 12/29/2024 Report End Date 12/30/2024 Last 24hr Summary PTW/PJSM, Perforate BEL6 from 6319'-6329', Pressure starting falling after perforating. Ran GPT found no sign of fluid & tagged CIBP @ 6346'. Bleed tbg down from 886-531 and saw a 15psi build in 15 mins. Bled from 560-415psi & had 78 psi build in 15 mins, No fluid observed. Bled well till it stabilized @ 328psi. Turn well over to ops to flow test. Field: Beaver Creek Sundry #: 324-610 State: ALASKA Rig/Service: See email about post-POP MITIA on 1/18/25. MITIA to 2600 psi passed. -bjm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eslie Johnson Digitally signed by Leslie Johnson Date: 2024.10.28 13:48:53 -05'00' Page 1/1 Well Name: BCU-009A Report Printed: 1/6/2025 WellViewAdmin@hilcorp.com Casing Liner Wellbore Wellbore Name: BCU-09A Total Depth of Wellbore (ftKB): 7,129.00 Original KB/RT Elevation (ft): 178.40 RKB to GL (ft): 18.00 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description: Liner Run Date: 10/20/2024 Set Depth (ftKB): 7,129.00 Casing Weight on Slips (1000lbf): 52,000.0 Pick Up Weight (1000lbf): 122,000.0 Block Weight (1000lbf): 15,000.0 Make-Up Contractor: Number Hrs to Run (hr): 17.00 Ft/Min (ft/min): 6.99 Run Job: 241-00151 BCU-09A Drilling, Drilling - Drilling, 10/3/2024 06:00 Set Depth (ftKB): 7,129.00 Set Depth (TVD) (ftKB): 6,729.2 Centralizer Detail: 105 Attribute Subtype: Value: Pipe Reciprocated?: Yes Pipe Rotated?: No Float Failed?: No Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft)Btm (ftKB) Top (ftKB) 1 Liner Hanger 5 1/2 4.29 23.57 2,893.57 2,870.00 1 XO 5 1/2 3.92 H563 1.69 2,895.26 2,893.57 1 Liner Pup Joint 3 1/2 2.87 9.20 L-80 H563 5.76 2,901.02 2,895.26 18 Blank Liner 3 1/2 2.87 9.20 L-80 H563 551.67 3,452.69 2,901.02 1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 15.40 3,468.09 3,452.69 16 Blank Liner 3 1/2 2.87 9.20 L-80 H563 493.66 3,961.75 3,468.09 1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 15.39 3,977.14 3,961.75 16 Blank Liner 3 1/2 2.87 9.20 L-80 H563 496.76 4,473.90 3,977.14 1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 14.78 4,488.68 4,473.90 16 Blank Liner 3 1/2 2.87 9.20 L-80 H563 500.05 4,988.73 4,488.68 1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 9.80 4,998.53 4,988.73 16 Blank Liner 3 1/2 2.87 9.20 L-80 H563 501.02 5,499.55 4,998.53 1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 15.39 5,514.94 5,499.55 16 Blank Liner 3 1/2 2.87 9.20 L-80 H563 498.45 6,013.39 5,514.94 1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 9.77 6,023.16 6,013.39 16 Blank Liner 3 1/2 2.87 9.20 L-80 H563 497.74 6,520.90 6,023.16 1 Marker Joint 3 1/2 2.87 9.20 L-80 H563 15.17 6,536.07 6,520.90 17 Blank Liner 3 1/2 2.87 9.20 L-80 H563 526.74 7,062.81 6,536.07 2 Landing/Float Collar 4 1/2 2.41 IBT 1.71 7,064.52 7,062.81 2 Blank Liner 3 1/2 2.87 9.20 L-80 IBT 62.58 7,127.10 7,064.52 1 Shoe 4 1/2 IBT 1.90 7,129.00 7,127.10 Page 1/1 Well Name: BCU-009A Report Printed: 1/6/2025 WellViewAdmin@hilcorp.com Cement Liner Cement Type Casing Description Liner Cement Cemented String Liner, 7,129.00ftKB Wellbore BCU-09 Job 241-00151 BCU-09A Drilling, Drilling - Drilling, 10/3/2024 06:00 Cementing Start Date 10/20/2024 Cementing End Date 10/20/2024 Top Depth (ftKB) 2,852.0 Cement Stages Stage Number: 1 Description Liner Cement Top Depth (ftKB) 2,852.0 Bottom Depth (ftKB) 7,129.0 Top Measurement Method CBL Pump Start Date 10/20/2024 Cement in Place At 10/20/2024 Final Circulating Pressure (psi) 1,400.0 Plug Bump Pressure (psi) 2,300.0 Full Return? Yes Returns During Job (%) 100 Volume to Surface (bbl) 15.0 Volume Lost (bbl) 0.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? Yes Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer)11.00 30.0 30.0 4 Fox Energy Lead Slurry G 349 2.09 12.50 130.0 30.0 5 Fox Energy Tail Slurry G 78 1.23 15.30 17.0 17.0 4 Fox Energy Displacement 9.10 68.3 69.5 4 Fox Energy Post Job Calculations Subtype Value From:Scott Warner To:McLellan, Bryan J (OGC) Cc:Ryan Lemay; Noel Nocas Subject:FW: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 Date:Thursday, May 8, 2025 4:15:26 PM Attachments:BC-9 IA MIT on 11-20-24-AOGCC .xls BC-9 IA MIT on 1-18-25-AOGCC.xls BCU-09A Production Plot.pdf Bryan, Attached are the MIT-IAs that were done. One on 11/21 and the other on 1/18/25. The well was brought online with initial production on 11/14/24 but quickly died off. An MIT-IA was done during this time period to ensure we still had mechanical integrity after initial perforations were shot. 11/21/24: Starting Pressure: 3071 Ending Pressure: 3060.5 Total Pressure loss: 10.5 psi – Pass Additional perforations were added and the well was again brought online on 12/29/24. An MIT-IA was done ~19 days later to ensure mechanical integrity after the well as stable. 1/18/25: Starting Pressure: 2700.4 Ending Pressure: 2684.0 Total Pressure loss: 16.4 psi – Pass The Production Plot with wellhead pressures is attached for reference. Please let me know if you need anything else. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, May 7, 2025 3:09 PM To: Scott Warner <Scott.Warner@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 Scott, I’m looking over the 10-407 for this well and don’t see where there was a follow up MITIA done after 30 days on production. If the MITIA was done, please send report to me so I can include with the 10-407. Also please send wellhead pressure plot for the entire life of the well. Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Monday, November 11, 2024 6:42 PM To: Scott Warner <Scott.Warner@hilcorp.com> Cc: Noel Nocas <Noel.Nocas@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 Scott, Hilcorp has approval to perforate the well per the sundry on the condition that the MITIA is repeated after 30 days of production to verify it still passes. Thanks and regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Thursday, November 7, 2024 4:06 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 Bryan, Please see responses below. What is Hilcorp’s plan for long term monitoring on this well to ensure the IA remains liquid packed and IA pressure doesn’t exceed safe limits? Long term monitoring will be done by pad operators who occupy the field 24/7 with multiple rounds per day. Due to what we suspect is a one way leak to gas at the liner seal assembly, we plan to keep some pressure (200-400 psi) on the IA to keep the IA overbalanced to reduce the chance of any gas migrating into the IA. If any communication is seen, either through an increase or decrease in IA pressure not associated with thermal changes to the well, we plan to monitor IA fluid level to determine if IA fluid is being lost to the leak. Repressurization of the IA will be managed by bleed as necessary to maintain some diagnostic differential pressure between the tubing and IA. All pressure tests passed on liquid therefore we don’t expect any fluid loss aside from anything that is bled off to surface by operators to manage pressure as needed especially during initial startup and thermodynamic changes. How will you know if the leak doesn’t get worse with time? CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. We have baseline data that I shared in the original email and we will continue to monitor pressure to ensure no communication is seen under normal operating conditions and when the well is first shut in after perforating. During shutdown activities, pressures will be monitored. If any abnormal pressure increases are seen, we plan on using diagnostic tools to further investigate and ensure communication hasn’t changed over time. What is Hilcorp’s maximum operating limit for the IA at Beaver Creek and what is protocol when the IA exceeds these limits? Beaver Creek does not have SCP regulations designating maximum operating limits, Hilcorp operates these wells to API standards, maintaining appropriate safety margins to equipment burst/ collapse limits which is limited to the 5000 psi rating on the wellhead. We do not expect the IA to ever exceed these limits even during a shut-in event based off of bottom hole pressures we saw during drilling and testing that was done once the one way leak was first identified. During diagnostic testing the IA did not increase past 800 psi with a tubing pressure of 2000 psi therefore we don’t expect the IA to be over 1000 psi even when the well is shut in based off of reservoir pressures of ~2600 psi that were seen while performing the RFT’s after drilling. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, November 6, 2024 4:50 PM To: Scott Warner <Scott.Warner@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 Scott, What is Hilcorp’s plan for long term monitoring on this well to ensure the IA remains liquid packed and IA pressure doesn’t exceed safe limits? How will you know if the leak doesn’t get worse with time? What is Hilcorp’s maximum operating limit for the IA at Beaver Creek and what is protocol when the IA exceeds these limits? Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Wednesday, November 6, 2024 1:07 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 Bryan, Just checking in on this one. Feel free to give me a call if needed. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, November 4, 2024 5:42 PM To: Scott Warner <Scott.Warner@hilcorp.com> Subject: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Scott, We are reviewing this issue internally. I’ll respond tomorrow. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Monday, November 4, 2024 9:50 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: BCU 09A PTD 224-113 - Sundry 324-610 Bryan, As mentioned on the phone Friday afternoon, I am wanting to make you aware of our plan forward for BCU-09A along with diagnostic work that has been completed. · 10/23 – Rig 169 lands completion o PT tree to 5,000psi – Pass o MIT-T to 2500psi – pass witnessed by BLM Rep Quinn Sawyer o MIT-IA to 2500psi - pass witnessed BLM Rep Quinn Sawyer § Details (Pumped 21.85 gals down tubing to achieve 2530 psi and held 30 min on chart. Bled back 21.85 gals, good test. RU in IA and pumped 33.35 gals to achieve 2520 psi on 7" x 3 1/2" IA and held 30 min on chart. Lost 60 psi over 30 min with no psi increase on tubing or OA, could find no leaks, bled of then pumped 32.2 gals to achieve 2520 psi on IA, held 30 min on chart, bled back 32.2 gals, good test. RD test equipment.) · 10/29 o Reverse circulate well dry with coil and N2 o Tubing pressure got as high as 2,200psi IA got up to 720 on IA o This was the first sign of any TxIA communication and triggered further diagnostics · 10/30 o Tubing bled off to 0psi, still 720psi on the IA o Bleed IA down to 30psi o Pressure up tubing with N2 - Tubing- 2,000 psi, IA - 800 psi · 10/31 o Pressure test tree, hanger and chem injection line for leaks – No leaks o Bleed tubing down to 1000 psi and bleed IA to 0psi. IA did not climb over 1hr o Fill IA with 3 bbls of diesel. Good 2500 psi MIT on IA. o Set SL plug (D&D hole finder) @ 2801' (Liner top seal assembly @ 2882') and pump N2 down tubing, Tubing 2000 psi. Monitored T/IA 15 mins and no change in Tubing or IA (2000psi/0psi) release plug, tubing equalized to 1300 psi and IA came up to 200 psi. o Bleed tubing to 1150psi, IA to 40psi · 11/1 o Tubing at 1150psi 160psi on IA (could have trapped N2 from the day before we didn’t bleed very long) o Bled IA to 0psi, came back to 60psi o Bleed IA to 0psi, stayed bled off o Final T/IA 1150psi/0psi MIT charts attached. The liner top/seal bore is at 2,871ft MD (~2,660ft TVD) and hydrostatic with fresh water is ~1,152psi at the liner top. We are assuming that there is a one-way N2 only leak somewhere between 2,801’ and the liner top/seal bore at 2,871’. We have not seen any communication from the IA to the tubing and only see tubing to IA communication when tubing pressure has increased (with gas only) over the hydrostatic pressure of the IA at the liner top. We plan to proceed with perforating and do not expect to see TxIA communication during normal operating conditions since this well will have a FTP <800 psi and flow to HP sales pressure (620-700 psi) or lower when dropped into low pressure. The IA will remain liquid packed and as mentioned above, the hydrostatic pressure at the leak point is ~1152 psi therefore TxIA communication will not be seen while the well is flowing. If/when the well is shut in there is potential to see TxIA communication but even if we see a SITP of 2000 psi which is highly unlikely, the IA will remain at or below 800 psi due to the tubing/IA equalizing which was proven on 10/30. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. From:McLellan, Bryan J (OGC) To:Scott Warner Cc:Noel Nocas Subject:RE: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 Date:Monday, November 11, 2024 6:41:00 PM Scott, Hilcorp has approval to perforate the well per the sundry on the condition that the MITIA is repeated after 30 days of production to verify it still passes. Thanks and regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Thursday, November 7, 2024 4:06 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 Bryan, Please see responses below. What is Hilcorp’s plan for long term monitoring on this well to ensure the IA remains liquid packed and IA pressure doesn’t exceed safe limits? Long term monitoring will be done by pad operators who occupy the field 24/7 with multiple rounds per day. Due to what we suspect is a one way leak to gas at the liner seal assembly, we plan to keep some pressure (200-400 psi) on the IA to keep the IA overbalanced to reduce the chance of any gas migrating into the IA. If any communication is seen, either through an increase or decrease in IA pressure not associated with thermal changes to the well, we plan to monitor IA fluid level to determine if IA fluid is being lost to the leak. Repressurization of the IA will be managed by bleed as necessary to maintain some diagnostic differential pressure between the tubing and IA. All pressure tests passed on liquid therefore we don’t expect any fluid loss aside from anything that is bled off to surface by operators to manage pressure as needed especially during initial startup and thermodynamic changes. How will you know if the leak doesn’t get worse with time? We have baseline data that I shared in the original email and we will continue to monitor pressure to ensure no communication is seen under normal operating conditions and when the well is first shut in after perforating. During shutdown activities, pressures will be monitored. If any abnormal pressure increases are seen, we plan on using diagnostic tools to further investigate and ensure communication hasn’t changed over time. What is Hilcorp’s maximum operating limit for the IA at Beaver Creek and what is protocol when the IA exceeds these limits? Beaver Creek does not have SCP regulations designating maximum operating limits, Hilcorp operates these wells to API standards, maintaining appropriate safety margins to equipment burst/ collapse limits which is limited to the 5000 psi rating on the wellhead. We do not expect the IA to ever exceed these limits even during a shut-in event based off of bottom hole pressures we saw during drilling and testing that was done once the one way leak was first identified. During diagnostic testing the IA did not increase past 800 psi with a tubing pressure of 2000 psi therefore we don’t expect the IA to be over 1000 psi even when the well is shut in based off of reservoir pressures of ~2600 psi that were seen while performing the RFT’s after drilling. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, November 6, 2024 4:50 PM To: Scott Warner <Scott.Warner@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Scott, What is Hilcorp’s plan for long term monitoring on this well to ensure the IA remains liquid packed and IA pressure doesn’t exceed safe limits? How will you know if the leak doesn’t get worse with time? What is Hilcorp’s maximum operating limit for the IA at Beaver Creek and what is protocol when the IA exceeds these limits? Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Wednesday, November 6, 2024 1:07 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 Bryan, Just checking in on this one. Feel free to give me a call if needed. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, November 4, 2024 5:42 PM To: Scott Warner <Scott.Warner@hilcorp.com> Subject: [EXTERNAL] RE: BCU 09A PTD 224-113 - Sundry 324-610 Scott, We are reviewing this issue internally. I’ll respond tomorrow. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Monday, November 4, 2024 9:50 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: BCU 09A PTD 224-113 - Sundry 324-610 Bryan, As mentioned on the phone Friday afternoon, I am wanting to make you aware of our plan forward for BCU-09A along with diagnostic work that has been completed. · 10/23 – Rig 169 lands completion o PT tree to 5,000psi – Pass o MIT-T to 2500psi – pass witnessed by BLM Rep Quinn Sawyer o MIT-IA to 2500psi - pass witnessed BLM Rep Quinn Sawyer § Details (Pumped 21.85 gals down tubing to achieve 2530 psi and held 30 min on chart. Bled back 21.85 gals, good test. RU in IA and pumped 33.35 gals to achieve 2520 psi on 7" x 3 1/2" IA and held 30 min on chart. Lost 60 psi over 30 min with no psi increase on tubing or OA, could find no leaks, bled of then pumped 32.2 gals to achieve 2520 psi on IA, held 30 min on chart, bled back 32.2 gals, good test. RD test equipment.) · 10/29 o Reverse circulate well dry with coil and N2 o Tubing pressure got as high as 2,200psi IA got up to 720 on IA o This was the first sign of any TxIA communication and triggered further diagnostics · 10/30 o Tubing bled off to 0psi, still 720psi on the IA o Bleed IA down to 30psi o Pressure up tubing with N2 - Tubing- 2,000 psi, IA - 800 psi · 10/31 o Pressure test tree, hanger and chem injection line for leaks – No leaks o Bleed tubing down to 1000 psi and bleed IA to 0psi. IA did not climb over 1hr o Fill IA with 3 bbls of diesel. Good 2500 psi MIT on IA. o Set SL plug (D&D hole finder) @ 2801' (Liner top seal assembly @ 2882') and pump N2 down tubing, Tubing 2000 psi. Monitored T/IA 15 mins and no change in Tubing or IA (2000psi/0psi) release plug, tubing equalized to 1300 psi and IA came up to 200 psi. o Bleed tubing to 1150psi, IA to 40psi · 11/1 o Tubing at 1150psi 160psi on IA (could have trapped N2 from the day before we didn’t bleed very long) o Bled IA to 0psi, came back to 60psi o Bleed IA to 0psi, stayed bled off o Final T/IA 1150psi/0psi MIT charts attached. The liner top/seal bore is at 2,871ft MD (~2,660ft TVD) and hydrostatic with fresh water is ~1,152psi at the liner top. We are assuming that there is a one-way N2 only leak somewhere between 2,801’ and the liner top/seal bore at 2,871’. We have not seen any communication from the IA to the tubing and only see tubing to IA communication when tubing pressure has increased (with gas only) over the hydrostatic pressure of the IA at the liner top. We plan to proceed with perforating and do not expect to see TxIA communication during normal operating conditions since this well will have a FTP <800 psi and flow to HP sales pressure (620-700 psi) or lower when dropped into low pressure. The IA will remain liquid packed and as mentioned above, the hydrostatic pressure at the leak point is ~1152 psi therefore TxIA communication will not be seen while the well is flowing. If/when the well is shut in there is potential to see TxIA communication but even if we see a SITP of 2000 psi which is highly unlikely, the IA will remain at or below 800 psi due to the tubing/IA equalizing which was proven on 10/30. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/8/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240208 Well API #PTD #Log Date Log Company Log Type BCU 09A 50133204450100 224113 11/13/2024 YELLOWJACKET GPT-PERF BCU 09A 50133204450100 224113 10/30/2024 YELLOWJACKET GPT BCU 11A 50133205210100 224123 11/9/2024 YELLOWJACKET SCBL BCU 25 50133206440000 214132 11/2/2024 YELLOWJACKET SCBL END 2-74 REVISED 50029237850000 224024 12/5/2024 HALLIBURTON MFC24 HVA 10 50231200280000 204186 11/13/2024 YELLOWJACKET GPT-PERF KU 23-07A 50133207300000 224126 11/23/2024 YELLOWJACKET SCBL NCIU A-21 50883201990000 224086 11/29/2024 AK E-LINE CaliperSurvey PAXTON 6 50133207070000 222054 11/7/2024 YELLOWJACKET PERF PBU 01-37 50029236330000 219073 11/23/2024 BAKER MRPM PBU 06-15A 50029204590200 224108 12/26/2024 BAKER MRPM PBU 06-19B 50029207910200 224095 12/10/2024 BAKER MRPM PBU 07-29E 50029217820500 213001 11/26/2024 BAKER SPN PBU 14-31A 50029209890100 224090 11/10/2024 BAKER MRPM PBU 14-41A 50029222900100 224076 11/9/2024 BAKER MRPM SRU 241-33B 50133206960000 221053 11/5/2024 YELLOWJACKET GPT-PERF Revision Explanation: Annotations added to processed log. Please include current contact information if different from above. T40053 T40053 T40054 T40055 T40056 T40057 T40058 T40059 T40060 T40061 T40062 T40063 T40064 T40065 T40066 T40067 BCU 09A 50133204450100 224113 11/13/2024 YELLOWJACKET GPT-PERF BCU 09A 50133204450100 224113 10/30/2024 YELLOWJACKET GPT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.07 13:25:23 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240116 Well API #PTD #Log Date Log Company Log Type AOGCC ESet # BCU 09A 50133204450100 224113 10/26/2024 YELLOWJACKET SCBL BCU 12A 50133205300100 214070 8/21/2024 YELLOWJACKET GPT-PLUG-PERF BRU 233-23T 50283202000000 224088 12/28/2024 AK E-LINE PPROF BRU 233-27 50283100260000 163002 12/31/2024 AK E-LINE PPROF BRU 243-34 50283201240000 208079 12/27/2024 AK E-LINE PPROF GP 03-87 50733204370000 166052 12/25/2024 AK E-LINE CBL GP AN-17A 50733203110100 213049 12/16/2024 AK E-LINE CBL GP AN-17A 50733203110100 213049 12/21/2024 AK E-LINE Perf GP BR-03-87 50733204370000 166052 1/3/2025 AK E-LINE CBL IRU 44-36 50283200890000 193022 1/3/2024 AK E-LINE Depth Determination/Plug IRU 44-36 50283200890000 193022 12/26/2024 AK E-LINE DepthDetermination KU 31-07X 50133204950000 200148 12/3/2024 AK E-LINE Perf MPU B-21 50029215350000 186023 1/4/2025 AK E-LINE PlugSettingRecord MPU H-08B 50029228080200 201047 12/28/2024 AK E-LINE Welltech MRU G-01RD 50733200370100 191139 12/12/2024 AK E-LINE IPROF MRU G-01RD 50733200370100 191139 12/18/2024 AK E-LINE Perf MRU M-25 50733203910000 187086 12/3/2024 AK E-LINE Perf MRU M-25 50733203910000 187086 12/19/2024 AK E-LINE Perf PBU 01-37 50029236330000 219073 11/23/2024 HALLIBURTON PPROF PBU 06-05 50029202980000 178020 12/21/2024 HALLIBURTON RBT PBU 06-19B 50029207910200 224095 12/11/2024 HALLIBURTON RBT PBU 11-38A 50029227230100 198216 11/27/2024 HALLIBURTON TEMP PBU 14-31A 50029209890100 224090 11/11/2024 HALLIBURTON RBT PBU L-103 50029231010000 202139 11/25/2024 HALLIBURTON IPROF PBU M-207 50029238070000 224141 12/25/2024 HALLIBURTON RBT PBU P2-55 50029222830000 192082 12/5/2024 HALLIBURTON PPROF PBU S-15 50029211130000 184071 11/18/2024 HALLIBURTON RBT TBU M-25 50733203910000 187086 12/13/2024 AK E-LINE Perf T39958 T39959 T39960 T39961 T39962 T39963 T39964 T39964 T39965 T39966 T39966 T39967 T39968 T39969 T39970 T39970 T39971 T39971 T39972 T39973 T39974 T39975 T39976 T39977 T39978 T39979 T39980 T39981 BCU 09A 50133204450100 224113 10/26/2024 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.01.16 13:56:40 -09'00' 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: 01/09/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: BCU 09A PTD: 224-113 API: 50-133-20445-01-00 FINAL LWD FORMATION EVALUATION + GEOTAP LOGS (10/12/2024 to 10/19/2024) ROP, PCG, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) Final GeoTap Formation Pressure Logs, Data and Reports Final Definitive Directional Survey Folder Contents: Please include current contact information if different from above. 224-113 T39944 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.01.09 13:12:48 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Scott Warner Subject:RE: BCU 09A PTD 224-113 - Sundry 324-610 Date:Monday, October 28, 2024 12:43:00 PM Scott, Hilcorp has approval to proceed with perforating per sundry 324-610. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Sunday, October 27, 2024 12:14 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: BCU 09A PTD 224-113 - Sundry 324-610 Bryan, Attached is the CBL for BCU-09A. We plan to blow the well dry tomorrow and will then perforate quickly after once we have your approval. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently 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:Rance Pederson - (C) To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC); Wallace, Chris D (OGC) Subject:Rig 169 MIT Test Report Date:Tuesday, October 22, 2024 4:13:29 PM Attachments:MIT Hilcorp 169 10-22-24.xlsx BCU-09A 7 x 3.5 Casing_Liner Lap_MIT"s Chart.pdf Please see the attached MIT report and chart for BCU-09A in Beaver Creek. Rance Pederson Drilling Foreman Beaver Creek Unit 907-283-1369 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&UHHN8QLW$ 37' Submit to: OOPERATOR: FIELDD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2241130 Type Inj N Tubing 0 2530 2505 2505 Type Test P Packer TVD 2679 BBL Pump 0.5 IA 0 150 145 145 Interval O Test psi 2500 BBL Return 0.5 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2241130 Type Inj N Tubing 0 285 285 285 Type Test P Packer TVD 2679 BBL Pump 0.8 IA 0 2520 2505 2505 Interval O Test psi 2500 BBL Return 0.8 OA 0 0 0 0 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska, LLC Beaver Creek / Beaver Creek Unit / Pad 3 Witness Waived by Jim Regg Rance Pederson 10/22/24 Notes:Post completion 3 1/2" tieback string and liner. Yellow Jacket SCOUT liner top packer element at 2678.63' Notes: Notes: Notes: BCU-09A BCU-09A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMechanicall Integrityy Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:Post completion 7" x 3 1/2" annulus. Yellow Jacket SCOUT liner top packer element at 2678.63'. Tested IA twice due to 60 psi loss over 30 minutes first test, no pressure gain in tubing or IA. Bled back and re-tested ok. Notes: Notes: Form 10-426 (Revised 01/2017)2024-1022_MITP_BCU-09A_2tests 9999 99 9 9 9 999 9 9 -5HJJ tieback string and liner 7" x 3 1/2" annulus 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,129 N/A Casing Collapse Structural Conductor 1,540psi Surface Intermediate 4,750psi Production 7,020psi Liner 10,540psi 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: Initial Completion / CT / N2 Operations LTP & N/A 2,875 (MD ) 2,664 (TVD) & N/A 6,728 7,074 6,676 Beaver Creek Unit Beluga Gas & Sterling Gas 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 09ACO 237D Same 2,834'7" 2,163 3,075' N/A Length October 29, 2024 6,876'4,001' 3-1/2" 6,480' 3,075' Perforation Depth MD (ft): 1,853' 3-1/2" See Attached Schematic 6,870psi 3,090psi116' 1,789' 116' Size 116' 9-5/8"1,853' MD Hilcorp Alaska, LLC Proposed Pools: L-80 TVD Burst ѷ2,875 8,160psi Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AKA 028083 224-113 50-133-20445-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Warner, Operations Engineer AOGCC USE ONLY 10,160psi Tubing Grade: scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: 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 12:15 pm, Oct 22, 2024 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2024.10.22 10:13:40 -08'00' 324-610 Submit CBL and obtain AOGCC approval before perforating BJM 10/24/24 CT BOP test to 3000 psi XCT 10-407 SFD 10/23/2024 DSR-10/23/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.25 11:10:05 -08'00'10/25/24 RBDMS JSB 102924 Well Prognosis Maximum Expected BHP: Max. Potential Surface Pressure: Applicable Frac Gradient: Shallowest Potential Perf TVD: Top of Applicable Gas Pool: 2799 psi @ 6362’ TVD (Based on 0.44 psi/ft gradient)) 2163 psi (Based on 0.1 psi/ft gas gradient to surface) 0.73 psi/ft using 14.1 ppg EMW FIT at the 7” Int. Casing shoe MPSP/(0.73-0.1) = 2163 psi / 0.63 = 3433‘ TVD 6216’ MD/ 5830’ TVD (Beluga) Well Status:New Drill Initial Completion Brief Well Summary: BCU-09A is a new drill well targeting the Upper Beluga sands. The objective of this sundry is to clean out the liner with coil tubing/nitrogen and perforate the Upper Beluga 5-11 Sands. Wellbore Conditions: - - - - - Max Inclination – 34° at 3137’ MD Max DLS °/100’ – 5.9° at 3529’ MD Liner will be full of ~9.1 ppg 6% KCl mud Tubing and IA will be displaced to 8.4 ppg CIW T & IA will be pressure tested to 2500 psi Pre-Sundry work: 1. 2. 3. 4. Review all approved COAs MIRU E-line and pressure control equipment Log well with CBL tool in 3-1/2” liner (send results to AOGCC to review) RDMO E-line Procedure: 1. 2. MIRU Coil Tubing and pressure control equipment PT BOPE to 250psi low / 3000 psi high a.Provide AOGCC 24hr notice and BLM 48 hrs for BOP test 3. 4. RIH & clean out wellbore to PBTD (~7129’), displace liner to 8.4 ppg water Reverse out wellbore with nitrogen, trap ~2000 psi on wellbore o ~62 bbls total wellbore volume 5. 6. 7. 8. RDMO Coil Tubing MIRU E-line and pressure control equipment PT lubricator to 250 psi low /2,500 psi high Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 9. RIH and perforate per RE/Geo and test Beluga sands within the interval below, from the bottom up: Well Name:BCU-09A API Number:50-133-20445-01-00 Current Status:New Drill Well Permit to Drill Number:224-113 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) Well Prognosis a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. Pending well production, all perf intervals may not be completed 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’. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 10. RDMO 11. Turn well over to production & flow test well 12. Test SVS as necessary once well has reached stable flow rates a. Notify state 48hrs prior to testing within 5 days of stable production Coil Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: 1. 2. 3. 4. MIRU Coiled Tubing Unit, PT BOPE to 250psi low / 3000 psi high a. Provide AOGCC 24hr notice and BLM 48 hrs for BOP test PU wash nozzle, RIH and cleanout well to below perfs or proposed plug depth PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole RDMO coil tubing 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 ±6,264'±6,282'±5,877'±5,895'±18' BEL 5 ±6,289'±6,311'±5,902'±5,924'±22' BEL 6 ±6,322'±6,329'±5,935'±5,942'±7' BEL 6 ±6,336'±6,364'±5,948'±5,976'±28' BEL 7 ±6,374'±6,381'±5,986'±5,993'±7' BEL 7B ±6,393'±6,424'±6,005'±6,035'±31' BEL 8 ±6,431'±6,446'±6,042'±6,057'±15' BEL 8 ±6,449'±6,478'±6,060'±6,088'±29' BEL 8B ±6,491'±6,498'±6,101'±6,108'±7' BDL 8C ±6,511'±6,526'±6,121'±6,136'±15' BEL 8D ±6,556'±6,567'±6,165'±6,176'±11' BEL 9 ±6,596'±6,605'±6,205'±6,213'±9' BEL 10 ±6,667'±6,709'±6,274'±6,316'±42' BEL 11 ±6,756'±6,765'±6,362'±6,371'±9' Well Prognosis Attachments: 1. 2. 3. 4. Current Well Schematic Proposed Well Schematic Coil Tubing BOP Diagram Standard Nitrogen Operations _____________________________________________________________________________________ Updated by JLL 10/21/24 SCHEMATIC Beaver Creek Unit Well: BCU-09A PTD: 224-113 API: 50-133-20445-01-00 TD =7,129’ (MD) / 6,728’(TVD) 13-3/8” RKB: GL = 18.5’ 3-1/2” 9-5/8” 7” TOW @ 3,075’ 1/2 PBTD = 7,074 (MD) / 6,676 (TVD) CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8” Conductor 61 / J-55 / Butt 12.515” Surf 116’ 9-5/8" Intermediate 47 / N-80 / BTC 8.861” Surf 1,853’ 7" Intermediate 29 / N-80 /BTC 6.276” Surf 3,075’ (TOW) 3-1/2” Prod Casing 9.2 / L-80 / Hyd 563 2.991” 2,875’ 6,876’ 3-1/2” Tieback Tbg 9.2 / L-80 / EUE 8RD 2.991” Surf ±2,875’ OPEN HOLE / CEMENT DETAIL 13-3/8” Driven 9-5/8" TOC @ Surface 700 sx 7” TOC @ 2,800’ MD 350 sx Stg 1 / 215 sx Stg 2 3-1/2” TOC @ Liner Top ~128 bbls JEWELRY DETAIL No. Depth Item 1 2,875’ Liner Top Packer 2 ±2,875’ Seal Stem _____________________________________________________________________________________ Updated by SRW 10-21-24 PROPOSED SCHEMATIC Beaver Creek Unit Well: BCU-09A PTD: 224-113 API: 50-133-20445-01-00 OPEN HOLE / CEMENT DETAIL 13-3/8” Driven 9-5/8" TOC @ Surface 700 sx 7” TOC @ 2,800’ MD 350 sx Stg 1 / 215 sx Stg 2 3-1/2” TOC @ Liner Top ~128 bbls TD =7,129’(MD) /6,728’(TVD) 13-3/8” RKB: GL = 18.5’ 3-1/2” 9-5/8” 7” TOW @ 3,075’ 1/2 PBTD =7,074’(MD) / 6,676 (TVD) CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8” Conductor 61 / J-55 / Butt 12.515” Surf 116’ 9-5/8" Intermediate 47 / N-80 / BTC 8.861” Surf 1,853’ 7" Intermediate 29 / N-80 /BTC 6.276” Surf 3,075’ (TOW) 3-1/2” Prod Casing 9.2 / L-80 / Hyd 563 2.991” 2,875’ 6,876’ 3-1/2” Tieback Tbg 9.2 / L-80 / EUE 8RD 2.991” Surf ±2,875’ JEWELRY DETAIL No. Depth Item 1 2,875’ Liner Top Packer 2 ±2,875’ Seal Stem PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD FT Date Status BEL 5 ±6,264' ±6,282' ±5,877' ±5,895' ±18' TBD Proposed BEL 5 ±6,289' ±6,311' ±5,902' ±5,924' ±22' TBD Proposed BEL 6 ±6,322' ±6,329' ±5,935' ±5,942' ±7' TBD Proposed BEL 6 ±6,336' ±6,364' ±5,948' ±5,976' ±28' TBD Proposed BEL 7 ±6,374' ±6,381' ±5,986' ±5,993' ±7' TBD Proposed BEL 7B ±6,393' ±6,424' ±6,005' ±6,035' ±31' TBD Proposed BEL 8 ±6,431' ±6,446' ±6,042' ±6,057' ±15' TBD Proposed BEL 8 ±6,449' ±6,478' ±6,060' ±6,088' ±29' TBD Proposed BEL 8B ±6,491' ±6,498' ±6,101' ±6,108' ±7' TBD Proposed BDL 8C ±6,511' ±6,526' ±6,121' ±6,136' ±15' TBD Proposed BEL 8D ±6,556' ±6,567' ±6,165' ±6,176' ±11' TBD Proposed BEL 9 ±6,596' ±6,605' ±6,205' ±6,213' ±9' TBD Proposed BEL 10 ±6,667' ±6,709' ±6,274' ±6,316' ±42' TBD Proposed BEL 11 ±6,756' ±6,765' ±6,362' ±6,371' ±9' TBD Proposed STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________BEAVER CK UNIT 09A JBR 12/06/2024 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:11 4.5" test joint used for testing. During test #1: CMV #6 was leaking at the flange(captured in the CH Misc), the annular was leaking on it's cap, and the HCR choke was leaking by its NPT body plug. Test #2: HCR kill failed to hold dp, the door seal on the blind rams started leaking, cycled UPR in attempt to center up the stack, CMV #8 failed to hold dp. Test #5: HCR choke failed to hold dp. Test #7: the manual choke valve failed to hold dp and the DSA began leaking at the flange. Test #8: the superchoke failed. It was disassembled and found that it had been assembled incorrectly. All the valve that failed to hold dp were serviced and retested for a pass. The accumulator's 16 charge bottles precharge pressures ranged from 1000 psi to 1025 psi. Several test fitting and sensator failures. Long test. Test Results TEST DATA Rig Rep:K. Porterfield/B. DeshotOperator:Hilcorp Alaska, LLC Operator Rep:J. Riley/J. Gruenberg Rig Owner/Rig No.:Hilcorp 169 PTD#:2241130 DATE:10/11/2024 Type Operation:DRILL Annular: 250/5000Type Test:INIT Valves: 250/5000 Rams: 250/5000 Test Pressures:Inspection No:bopGDC241008153716 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 17 MASP: 2203 Sundry No: 324-549 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 15 FPNo. Valves 1 PManual Chokes 1 FPHydraulic Chokes 1 FPCH Misc Stripper 0 NA Annular Preventer 1 11" 5000 FP #1 Rams 1 2 7/8"x5" VB FP #2 Rams 1 Blinds FP #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8" 5000 FP HCR Valves 2 2 1/16", 3 1/8 FP Kill Line Valves 1 2 1/16" 5000 P Check Valve 0 NA BOP Misc 1 DSA flange FP System Pressure P3050 Pressure After Closure P1850 200 PSI Attained P24 Full Pressure Attained P82 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P4 @ 2450 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P11 #1 Rams P5 #2 Rams P4 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2 9 9 9 9 9999 9 9 9 9 9 9 9 9 9 9 9 $SSURYHG6XQGU\LVIRUFKDQJHWR%23VWDFN FP FP FP FP FP FP FP FP FP CMV #6 was leaking annular was leaking HCR choke was leaking HCR kill failed to hold dp door seal on the blind rams CMV #8 failed to hold dp manual choke valve failed DSA began leaking superchoke failed Several test fitting and sensator failures. P.I. Supv Comm: Rig Coil Tubing Unit? No Rig Contractor Rig Representative Operator Operator Representative Well Permit to Drill # 224-113 Sundry Approval # 324-549 Operation Inspection Location Working Pressure, W/H Flange P Pit Fluid Measurement P Working Pressure P P Flow Rate Sensor P Operating Pressure P P Mud Gas Separator P Fluid Level/Condition P P Degasser P Pressure Gauges P P Separator Bypass P Sufficient Valves P P Gas Detectors P Regulator Bypass P P Alarms Separate/Distinct P Actuators (4-way valves) P P Choke/Kill Line Connections P Blind Ram Handle Cover P P Reserve Pits P Control Panel, Driller P P Trip Tank P Control Panel, Remote P PFirewallP P 2 or More Pumps P P Kelly or TD Valves P Independent Power Supply P P Floor Safety Valves P N2 Backup P P Driller's Console P Condition of Equipment P P Flow Monitor P Flow Rate Indicator P Pit Level Indicators P Valves P PPE P Gauges P Remote Hydraulic Choke P Well Control Trained P Gas Detection Monitor P FOV Upstream of Chokes P Housekeeping P Hydraulic Control Panel P Targeted Turns P Well Control Plan P Kill Sheet Current NA Bypass Line P FAILURES:0 CORRECT BY: COMMENTS Guy Cook 10/10/2024INSPECT DATE AOGCC INSPECTOR Hilcorp 169 Parker Drilling Hilcorp Alaska LLC MISCELLANEOUS Flange/Hub Connections Drilling Spool Outlets Flow Nipple Control Lines RIG FLOOR ALASKA OIL AND GAS CONSERVATION COMMISSION RIG INSPECTION REPORT HCR Valve(s) Manual Valves Annular Preventer Working Pressure, BOP Stack Stack Anchored Choke Line Kill Line Targeted Turns Pipe Rams Blind Rams K. Porterfield/B. Deshotel J. Riley/J Gruenberg Locking Devices, Rams BOP STACK Referenced Sundry is for a change to the BOP stack arrangement in PTD. CHOKE MANIFOLD Beaver Creek MUD SYSTEM BCU-09A Drilling CLOSING UNIT 2024-1010_Rig_Hilcorp169_BCU-09A_gc rev. 4-19-2023 9 9 9 9 9 -5HJJ 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? 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): 8,881'N/A Casing Collapse Structural Conductor Surface 4,760 psi Intermediate 7,020 psi Production Liner 10,160psi 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 DLH Hydraulic Pkr; N/A 5,410' MD / 5,029' TVD 8,496'5,282'4,901' Beaver Creek N/A 13-3/8" 9-5/8" N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 09A20 AAC 25.055 Beluga and Sterling Gas 2,203 5,513 & 5,615 Length September 28, 2024 8,881'3,067' 3-1/2" 8,496' Perforation Depth MD (ft): 5,950' 3-1/2" N/A 8,160 psi 6,870 psi 116' 5,569' 116' 1,853' Size 116' 7"5,950' 1,853' MD Hilcorp Alaska, LLC Proposed Pools: L-80 TVD Burst 5,430' 1,790' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 224-113 50-133-20445-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Sean Mclaughlin AOGCC USE ONLY 10,530psi Tubing Grade: sean.mclaughlin@hilcorp.com 907-223-6784 Drilling Manager Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 5,282'; 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t _ c N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:44 pm, Sep 23, 2024 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.09.23 14:03:16 - 08'00' Sean McLaughlin (4311) SFD BJM 9/24/24 SFD 9/24/2024 (BCU 09) SFD Filed as part of 10-407 for new well All conditions of approval on PTD still apply. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.24 15:05:53 -08'00'09/24/24 RBDMS JSB 100124 Well Prognosis Well: BCU-09A Date: 9-23-24 Well Name:BCU-09A API Number:50-133-20445-01-00 Current Status:Prepping Rig 169 Estimated Start Date:9-27-24 Rig:Rig 169 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd:N/A Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:224-113 First Call Engineer:Sean McLaughlin (907)-223-6784 (M) Second Call Engineer AFE Number: Summary: The wellhead height on Beaver Creek 09 will not allow for an 11” four preventor BOP arrangement as planned. Adding gravel at BCU is difficult due to the BLM’s requirement for certified weed free gravel. Given the MASP of 2203 psi a three preventor arrangement is acceptable per 20 AAC 25.035(e)(1)(A). No change to planned test pressures. A pipe ram will be tested for all drill pipe and tubulars run. Revised summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 6” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/2500 (Annular 2500 psi) Subsequent Tests: 250/2500 (Annular 2500 psi) Attachments 1.Proposed BOPE Schematic Beaver Creek 2024 Rig 169 09//23/2024 ϭϭΖ͛5M Cameron Townsend LWS type 2 7/8-5 variables Blinds DSA 11 5M x 7 1/16 5M CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Sean McLaughlin To:Davies, Stephen F (OGC); Cody Dinger Cc:McLellan, Bryan J (OGC); Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL] BCU 09A (PTD 224-113, Sundry 324-549) - Questions Date:Tuesday, September 24, 2024 8:54:08 AM Attachments:BCU-09 Schematic 09-09-24.pdf Hi Steve, I believe “plug for redrill” fits the best since that is the current state of BC-9. The change to approved program box is also checked because we are amending the PTD. Perhaps it would be clearer if the plug for redrill box was not checked. The Sundry form is not ideal for this type of change. Since the rig has not moved to BC-09 the present condition is correct regarding the TD and liner depths. Also, a similar change will be coming for the BC-11 PTD. We can take care of it before or after the PTD is issued. Whatever you prefer. Thanks, sean From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, September 23, 2024 4:49 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL] BCU 09A (PTD 224-113, Sundry 324-549) - Questions Sean, I’m reviewing Hilcorp’s application 324-549, and I a couple of questions. The Type of Request section of the 403 form has a checkmark next to the box labeled “Plug for Redrill.” I’d like to check with you to ensure that this is a cut-and-paste error. Correct? The Present Well Condition Summary lists the Total Depth and Liner Depth as 8,881’ MD (8496’ TVD). Are these values correct? Hilcorp’s Permit to Drill 224-113 (approved by AOGCC on September 19, 2024) lists a proposed depth of 6,876’ MD (6479’ TVD) for BCU 09A. Have I missed something? Are these values correct? If so, did Hilcorp receive AOGCC approval to extend the well an additional 2,000’ MD/TVD? Please provide the Sundry Number for that approval. Thanks and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Beaver Creek Field, Beluga Gas and Sterling Gas Pools, BCU-09A Hilcorp Alaska, LLC Permit to Drill Number: 224-113 Surface Location: 1188' FNL, 1567' FWL, Sec 34, T7N, R10W, SM, AK Bottomhole Location: 2203' FSL, 1367' 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 all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 19th day of September 2024. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.19 08:34:22 -08'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 6,876' TVD: 6,479' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 178.4' 15. Distance to Nearest Well Open Surface: x-317379 y-2434004 Zone-.4 160.4' to Same Pool: 850' to BCU-19RD 16. Deviated wells:Kickoff depth: 3,075 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 33 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 6" 3-1/2" 9.2# L-80 Hyd 563 4,001' 2,875' 2,664' 6,876' 6,479' Tieback 3-1/2" 9.2# L-80 EUE 8RD 2,875' Surface Surface 2,875' 2,664' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD 116' 1,790' 5,569' 8,496' Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 10/5/2024 3338' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 8,881' 2560 Cement Volume MD 116' 1,853'9-5/8"700 sx Drilling Manager Monty Myers 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): 1,853' 5,950' 500 sx Plugged Conductor/Structural 13-3/8"116' Authorized Title: Authorized Signature: 3-1/2" Authorized Name: Production Liner 5,950' 3,067' Intermediate 8,881'8,496' LengthCasing 5,513' Size Plugs (measured): (including stage data) L - 1430 ft3 / T - 205 ft3 Tieback Assy. 5,282'4,901' Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 2850 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 2203 2320' FSL, 1375' FWL, Sec 34, T7N, R10W, SM, AK 2203' FSL, 1367' FWL, Sec 34, T7N, R10W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 1188' FNL, 1567' FWL, Sec 34, T7N, R10W, SM, AK AKA 028083 BCU 09A Beaver Creek Unit Beluga Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Plugged 565 sx7" s N ype of W L l R L 1b S Class: os N s No s N o D s s s D 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Drilling Manager 08/15/24 Monty M Myers By Grace Christianson at 9:38 am, Aug 15, 2024 BOP test to 2500 psi Submit FIT/LOT data within 48 hrs of performing test. and Sterling Gas Pool A.Dewhurst 30AUG24 224-113 DSR-8/21/24 See attached emails. -A.Dewhurst 30AUG24 50-133-20445-01-00 BJM 9/18/24*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.19 08:34:35 -08'00' 09/19/24 09/19/24 RBDMS JSB 092724 BC 9A Drilling Program Beaver Creek Unit August 5, 2024 BC 9A Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Current Schematic (Post plugging)..............................................................................................6 7.0 Planned Wellbore Schematic........................................................................................................7 8.0 Drilling / Completion Summary...................................................................................................8 9.0 Mandatory Regulatory Compliance / Notifications....................................................................9 10.0 R/U and Preparatory Work........................................................................................................12 11.0 BOP N/U and Test........................................................................................................................13 12.0 Set Whipstock / Mill Window.....................................................................................................13 13.0 Drill 6” Hole Section....................................................................................................................15 14.0 Run 3-1/2” Production Liner......................................................................................................16 15.0 Cement 3-1/2” Production Liner................................................................................................19 16.0 3-1/2” Liner Tieback Polish Run................................................................................................22 17.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................23 18.0 BOP Schematic.............................................................................................................................24 19.0 Wellhead Schematic.....................................................................................................................25 20.0 Anticipated Drilling Hazards......................................................................................................26 21.0 Hilcorp Rig 167 Layout...............................................................................................................27 22.0 Choke Manifold Schematic.........................................................................................................28 23.0 Casing Design Information.........................................................................................................29 24.0 6” Hole Section MASP.................................................................................................................30 25.0 Spider Plot....................................................................................................................................31 26.0 Surface Plat (As-Built NAD27 & NAD83).................................................................................32 Page 2 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 1.0 Well Summary Well BC 9A Rig 169 Pad & Old Well Designation Beaver Creek – Pad 3 Sidetrack Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Upper Beluga / Lower Sterling Planned Well TD, MD / TVD 6876 MD / 6479’ TVD PBTD, MD / TVD 6776’ MD AFE Number AFE Days AFE Amount Maximum Anticipated Pressure (Surface)2203 psi Maximum Anticipated Pressure (Downhole/Reservoir)2850 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 178.4 Ground Elevation 160.4 BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 2.0 Management of Change Information Page 4 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) 6”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 *Ensure at least 100’ of overlap between casing and liner 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellview. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to Sean.McLaughlin@hilcorp.com,and cdinger@hilcorp.com Page 6 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 6.0 Current Schematic (Post plugging) The BCU-09 Plug for redrill sundry 324-501 was revised to include tubing pulled from below D1X perfs and plugs set above and below these perfs inside the 7" casing. -bjm Page 7 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 7.0 Planned Wellbore Schematic Page 8 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 8.0 Drilling / Completion Summary BC 9A is an S-shaped sidetrack development well to be drilled from Beaver Creek Pad 3. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Sterling and Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~3075’ MD. Maximum hole angle will be ~33 deg. and TD of the well will be 6876’ TMD/ 6479’ TVD, ending with 10 deg inclination. Vertical separation will be 1898 ft. Drilling operations are expected to commence approximately October, 2024. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. Planned Pre Rig operations: - Abandon the BC 09 reservoir - Decomplete 3-1/2” tubing from the packer at 3209. - Spot an abandonment / sidetrack plug - Test 7” casing to 2500 psi General sequence of operations: 1. Rig 169 will MIRU over BC-09 2. NU BOPE and test to 2500 psi. (MASP 2203psi) 3. Set 7” 29# whipstock at 3075’ and 30L. Swap well to 9.0 ppg mud. 4. Mill window with 20’ of new formation. 5. Perform FIT to 14.0 ppg EMW 6. MU 6” bit with 4-3/4” tools (Triple Combo) 7. Drill 6” production hole to 6876’ MD, performing short trips as needed 8. Run GeoTap RFT, Cleanout as necessary 9. RIH w/ 3-1/2” liner. Set liner and cement. Circ wellbore clean. 10. Perform Clean out run to polish bore, LDDP 11. Perform liner lap test to 2500 psi. 12. Run 3-1/2” tie back completion. 13. Land hanger and test.MIT-T to 2500 psi, MIT-IA to 2500 psi 14. ND BOPE, NU tree and test void Reservoir Evaluation Plan: Production Hole: Triple Combo + GeoTAP Sundry 324-501 BCU-09 PTD #192-122 -bjm Triple Combo + GeoTAP see Sundry 324-462 Page 9 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations and all BLM regulations pertaining to 43 CFR 3171 or 3172. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of BC 9A. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. And BLM 48 hrs notice prior to testing. x The initial test of BOP equipment will be 250/2500 psi & subsequent tests of the BOP equipment will be to 250/2500 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC and BLM approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the BLM APD and the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. BLM Regulation Variance Requests: x 43 CFR 3172.6(b)(1)(iii) o Hilcorp requests approval to install a 2-1/16” 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. Page 10 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 6” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/2500 (Annular 2500 psi) Subsequent Tests: 250/2500 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48 hours notice prior to testing BOPs. x Any other notifications required in APD. Required BLM Notifications: x 48 hours before spud. Follow up with actual spud date and time within 24 hours. x 72 hours before casing running and cmt operations x 72 hours before BOPE tests x 72 hours before logging, coring, & testing x Any other notifications required in APD Additional requirements may be stipulated on APD and Sundry. Page 11 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) BLM Allie Schoessler / BLM Petroleum Engineer / (O): 907-271-3127 Email:aschoessler@blm.gov Use the below email address for BOP notifications to the BLM: BLM_AK_AKSO_EnergySection_Notifications@blm.gov Page 12 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 10.0 R/U and Preparatory Work 1. Level pad and ensure enough room for layout of rig footprint and R/U. 2. Layout Herculite on pad to extend beyond footprint of rig. 3. R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 4. After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 5. 6” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3075’- 6876’8.8 – 9.5 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for 8.8 – 9.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 6. Install 5-1/2” liners in mud pumps. Page 13 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. 11.0 BOP N/U and Test 1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug 2. N/U to 11” 5M tubing spool 3. N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 4. Run BOPE test plug. 5. Test BOPE. x Test BOP to 250/3000 psi for 5/10 min. x Test VBR’s with 4-1/2” and 3-1/2 test joint x Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint x Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 6. Mix 9.0 ppg 6% KCL PHPA mud system. 7. Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. 12.0 Set Whipstock / Mill Window Operation Steps: 1. Pull test plug. Set wear bushing in wellhead. Ensure ID of wear bushing > 6”. 2. Make up the WIS Mechanical set Whipstock. Page 14 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 3. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly ¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. ¾Avoid sudden starts and stops while running the whipstock. ¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. 4. Orient whipstock as directed by the directional driller. The directional plan specifies 30 deg LOHS. 5. Set the top of the whipstock at ~3,075’ MD (confirm depth after RWO) x 7” Collars at 3069’ and 3112’. x Ref log: Beaver Creek #9 SLB VDL 30-AUG-1994 (TOC above 2800’) x Parent well plugged to 3110’ (verify after RWO) 6. Mill window plus 20’-50’ of new hole (DO NOT EXCEED 50’ OF NEW HOLE BEFORE RUNNING THE PLANNED FIT/LOT). ¾Use ditch magnets to collect the metal shavings. Clean regularly. ¾Ensure any personnel working around metal shavings wear proper PPE, including goggles, face shield and Kevlar gloves. ¾Work the upper mill through the window to confirm the window milling is complete and circulate well clean (circulate a minimum of 1-1/2 bottoms up). Pump a high-vis super sweep to remove metal shavings and make every effort to remove all of the super sweep pill from the mud system as it is circulated to surface. 7. Pull starter mill into casing above top of whipstock, flow check the well for 10 minutes and conduct a FIT to 14.0 ppg. ¾**Assuming the kick zone is at TD, a FIT of 13.0 ppg EMW gives a Kick Tolerance volume of 16 bbls with 9.5 ppg mud weight. ¾Monitor OA during FIT and report and change in pressure. 8. POOH and LD milling assembly ¾Once out of the hole, inspect mill gauge and record. ¾Flow check well for 10 minutes to confirm no flow: ¾Before pulling off bottom. Page 15 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx ¾Before pulling the BHA through the BOPE. 9. Flush the stack/lines to remove metal debris that may have settled out in these areas. Ensure BOP equipment is operable. 13.0 Drill 6” Hole Section 1. P/U 4-3/4” Sperry Sun motor drilling assy w/ triple combo tools (DEN, POR, RES) and 6” bit 2. Ensure BHA components have been inspected previously. 3. Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 4. Ensure TF offset is measured accurately and entered correctly into the MWD software. 5. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at ~200 gpm. 6. Production section will be drilled with a motor. Must keep up with 3 deg/100 DLS in the build section of the wellbore. 7. TIH to window. Shallow test MWD on trip in. 8. Circulate well with 9.0 ppg mud to warm up mud until good 9.0 ppg in and out. 9. Drill 6” hole to 6876’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Minimize backreaming when working tight hole 10. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU. 11. TOH with drilling assembly, handle BHA as appropriate. 12. LD source tools and pick up 4-3/4” GeoTap RFT. Log per Asset team. Page 16 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 13. Clean out wellbore as necessary 14. Confirm 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint. 14.0 Run 3-1/2” Production Liner 1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” Liner x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with Baker landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 4. Continue running 3-1/2” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to the 7” window. Leave the centralizers free floating. 5. Continue running 3-1/2” production liner Page 17 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx Page 18 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 6. Run in hole w/ 3-1/2” liner to the 7” window shoe. 7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 11. Set casing slowly in and out of slips. 12. PU 3-1/2” X 7” YJOC liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 15. Stage pump rates up slowly to circulating rate. Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 19 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 15.0 Cement 3-1/2” Production Liner 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. 2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 3. Pump 5 bbls spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining spacer. 6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Page 20 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx Estimated Total Cement Volume: Cement Slurry Design: Lead Slurry (6376’ MD to 2875’ MD)Tail Slurry (6876’ to 6376’ MD) System Extended Conventional Density 12 lb/gal 15.4 lb/gal Yield 2.46 ft3/sk 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk Additives Code Description 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.FDP-C1446-21 Slurry Conditioner SA-1015 Suspension Agent BridgeMaker II Lost Circulation Verified cement calcs. -bjm Page 21 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 8. Displace cement at max rate of 4 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 10. Bump the plug and pressure up to up as required by Baker procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 11. Slack off total liner weight plus 30k to confirm hanger is set. 12. Do not overdisplace by more than 2x shoe track volume. Shoe track volume is 0.7 bbls. 13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool (HRD-E) from the liner. 15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17. Pressure up drill pipe to 500 psi and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. Page 22 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 21. If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 22. NOTE: Some hole conditions may require movement of the drillpipe to “work” the torque down to the setting tool. 23. After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set-down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 16.0 3-1/2” Liner Tieback Polish Run 1. No cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. Page 23 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 2. Test liner lap to 2500 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 3. PU liner tieback polish mill assy per YJOC rep and RIH on drillpipe. 4. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per YJOC procedure. 5. POOH, and LDDP and polish mill. 17.0 3-1/2” Tieback Run, ND/NU, RDMO 1. Run 3-1/2” tubing completion assembly to above the liner top x Tubing will be 3-1/2” L-80 9.2# EUE 8rd x No GLM, CIM, or SSSV required 2. Swap the well over to CI Water 3. Space out and land seal bore in tie back sleeve. RILDs. 4. Test IA to 2500 psi and tubing to 2500 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void 7. Rig Down Page 24 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 18.0 BOP Schematic Page 25 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 19.0 Wellhead Schematic Page 26 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 20.0 Anticipated Drilling Hazards 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 27 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 21.0 Hilcorp Rig 167 Layout Page 28 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 22.0 Choke Manifold Schematic Page 29 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 23.0 Casing Design Information Page 30 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 24.0 6” Hole Section MASP Page 31 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 25.0 Spider Plot Page 32 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx 26.0 Surface Plat (As-Built NAD27 & NAD83) Page 33 Version PTD August 05, 2024 BC 9A Drilling Procedure PTD# xxxxx !! !! !! ! !! !! ! ! !! ! !! ! ! D $) BCU 9A_BHL BCU 9A_TPH BCU 9A_SHL BCU Pad 3 BCU 25 BHL BCU 19 BHL BCU 12 BHL BCU 13 BHL BCU 09 BHL BCU 04 BHL BCU 14B BHL BCU 12A BHL BCU 18RD BHL BEAVER CREEK UNIT34S007N010W Beaver Creek Unit BCU-09A wp05 0400800 Feet Alaska State Plane Zone 4, NAD27 ¯ Legend $)BCU 9A_BHL !BCU 9A_SHL D BCU 9A_TPH !Other Surface Well Locations Other Bottom Hole Locations Well Paths Oil and Gas Unit Boundary BCU_09A_Buffer Map Date: 9/18/2024 6WDQGDUG3URSRVDO5HSRUW $XJXVW 3ODQ%&8$ZS +LOFRUS$ODVND//& %HDYHU&UHHN8QLW %HDYHU&UHHN8QLW3DG 3ODQ%HDYHU&.8QLW %&8$ 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175 6500 6825True Vertical Depth (650 usft/in)325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 Vertical Section at 186.15° (650 usft/in) 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5500 6000 6500 7000 BCU 9 7" KOP 3 1/2" x 6" 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 6 8 7 6 BCU-09A wp05 KOP : Start Dir 12.75º/100' : 3075' MD, 2834.3'TVD : 30° LT TF End Dir : 3088' MD, 2845.27' TVD Start Dir 3º/100' : 3188' MD, 2929'TVD End Dir : 3248.15' MD, 2979.69' TVD Start Dir 3º/100' : 3480.15' MD, 3176.43'TVD End Dir : 4213.48' MD, 3856.86' TVD Total Depth : 6876' MD, 6478.93' TVD STERLING_B STERLING_B1 STERLING_B2 STERLING_B3U STERLING_B3L STERLING_B4 STERLING_B5 STERLING_B6 STERLING_A STERLING A2 BELUGA BELUGA_5 BELUGA_6 BELUGA_6 LOW BELUGA_7BELUGA_7 LOW BELUGA_7B BELUGA_8 BELUGA_8B BELUGA_8C BELUGA_8D BELUGA_9 BELUGA_10 BELUGA_11 BELUGA_11 LOW Middle_BELUGA 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 9 Ground Level: 160.40 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2434004.02 317379.72 60° 39' 30.3469 N 151° 1' 4.5236 W SURVEY PROGRAM Date: 2024-07-22T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 445.30 3075.00 BCU 9 (BCU 9) 3_MWD 3075.00 3400.00 BCU-09A wp05 (BCU 9A) 3_MWD_Interp Azi+Sag 3400.00 6876.00 BCU-09A wp05 (BCU 9A) 3_MWD+IFR1+MS+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 4838.34 4659.94 5210.10 STERLING_B 4916.76 4738.36 5289.73 STERLING_B1 4969.12 4790.72 5342.90 STERLING_B2 5048.37 4869.97 5423.37 STERLING_B3U 5087.75 4909.35 5463.36 STERLING_B3L 5147.23 4968.83 5523.76 STERLING_B4 5171.49 4993.09 5548.39 STERLING_B5 5247.64 5069.24 5625.72 STERLING_B6 5751.76 5573.36 6137.61 STERLING_A 5775.40 5597.00 6161.62 STERLING A2 5820.23 5641.83 6207.14 BELUGA 5860.84 5682.44 6248.38 BELUGA_5 5926.22 5747.82 6314.77 BELUGA_6 5926.22 5747.82 6314.77 BELUGA_6 LOW 5964.30 5785.90 6353.43 BELUGA_7 5964.30 5785.90 6353.43 BELUGA_7 LOW 5984.58 5806.18 6374.03 BELUGA_7B 6032.44 5854.04 6422.62 BELUGA_8 6079.45 5901.05 6470.36 BELUGA_8B 6109.70 5931.30 6501.08 BELUGA_8C 6145.79 5967.39 6537.72 BELUGA_8D 6182.05 6003.65 6574.54 BELUGA_9 6268.27 6089.87 6662.09 BELUGA_10 6345.81 6167.41 6740.83 BELUGA_11 6345.81 6167.41 6740.83 BELUGA_11 LOW 6398.51 6220.11 6794.34 Middle_BELUGA REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Beaver CK Unit 9, True North Vertical (TVD) Reference:BCU 9A RKB @ 178.40usft (HEC 169) Measured Depth Reference:BCU 9A RKB @ 178.40usft (HEC 169) Calculation Method:Minimum Curvature Project:Beaver Creek Unit Site:Beaver Creek Unit Pad 3 Well:Plan: Beaver CK Unit 9 Wellbore:BCU 9A Design:BCU-09A wp05 SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 3075.00 31.70 188.10 2834.30 -950.92 -126.98 0.00 0.00 959.05 KOP : Start Dir 12.75º/100' : 3075' MD, 2834.3'TVD : 30° LT TF 2 3088.00 33.15 186.58 2845.27 -957.83 -127.87 12.75 -30.00 966.02 End Dir : 3088' MD, 2845.27' TVD 3 3188.00 33.15 186.58 2929.00 -1012.15 -134.14 0.00 0.00 1020.70 Start Dir 3º/100' : 3188' MD, 2929'TVD 4 3248.15 32.00 184.00 2979.69 -1044.39 -137.13 3.00 -130.64 1053.08 End Dir : 3248.15' MD, 2979.69' TVD 5 3480.15 32.00 184.00 3176.43 -1167.03 -145.71 0.00 0.00 1175.93 Start Dir 3º/100' : 3480.15' MD, 3176.43'TVD 6 4213.48 10.00 184.00 3856.86 -1427.59 -163.93 3.00 180.00 1436.94 End Dir : 4213.48' MD, 3856.86' TVD 7 6876.00 10.00 184.00 6478.93 -1888.81 -196.18 0.00 0.00 1898.95 Total Depth : 6876' MD, 6478.93' TVD CASING DETAILS TVD TVDSS MD Size Name 2835.15 2656.75 3076.00 7 7" KOP 6478.93 6300.53 6876.00 3-1/2 3 1/2" x 6" -1900 -1850 -1800 -1750 -1700 -1650 -1600 -1550 -1500 -1450 -1400 -1350 -1300 -1250 -1200 -1150 -1100 -1050 -1000 -950 South(-)/North(+) (100 usft/in)-500 -450 -400 -350 -300 -250 -200 -150 -100 -50 0 50 100 150 200 West(-)/East(+) (100 usft/in) 3000 3250 3500 3750 4000 4250 4500 67 5 0 75008493BCU 97" KOP 3 1/2" x 6" 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6479 BCU-09A wp05 KOP : Start Dir 12.75º/100' : 3075' MD, 2834.3'TVD : 30° LT TF End Dir : 3088' MD, 2845.27' TVD Start Dir 3º/100' : 3188' MD, 2929'TVD End Dir : 3248.15' MD, 2979.69' TVD Start Dir 3º/100' : 3480.15' MD, 3176.43'TVD End Dir : 4213.48' MD, 3856.86' TVD Total Depth : 6876' MD, 6478.93' TVD CASING DETAILS TVD TVDSS MD Size Name 2835.15 2656.75 3076.00 7 7" KOP 6478.93 6300.53 6876.00 3-1/2 3 1/2" x 6" Project: Beaver Creek Unit Site: Beaver Creek Unit Pad 3 Well: Plan: Beaver CK Unit 9 Wellbore: BCU 9A Plan: BCU-09A wp05 WELL DETAILS: Plan: Beaver CK Unit 9 Ground Level: 160.40 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2434004.02 317379.72 60° 39' 30.3469 N 151° 1' 4.5236 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: Beaver CK Unit 9, True North Vertical (TVD) Reference: BCU 9A RKB @ 178.40usft (HEC 169) Measured Depth Reference:BCU 9A RKB @ 178.40usft (HEC 169) Calculation Method:Minimum Curvature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eparation Factor3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000Measured DepthBCU 9No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: Beaver CK Unit 9 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 160.40+N/-S +E/-W Northing EastingLatitudeLongitude0.000.002434004.02317379.7260° 39' 30.3469 N151° 1' 4.5236 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: Beaver CK Unit 9, True NorthVertical (TVD) Reference:BCU 9A RKB @ 178.40usft (HEC 169)Measured Depth Reference:BCU 9A RKB @ 178.40usft (HEC 169)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2024-07-22T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool445.30 3075.00 BCU 9 (BCU 9) 3_MWD3075.00 3400.00 BCU-09A wp05 (BCU 9A) 3_MWD_Interp Azi+Sag3400.00 6876.00 BCU-09A wp05 (BCU 9A) 3_MWD+IFR1+MS+Sag0.0035.0070.00105.00140.00175.00Centre to Centre Separation (60.00 usft/in)3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000Measured DepthBCU 9GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference3075.00 To 6876.00Project: Beaver Creek UnitSite: Beaver Creek Unit Pad 3Well: Plan: Beaver CK Unit 9Wellbore: BCU 9APlan: BCU-09A wp05CASING DETAILSTVD TVDSS MD Size Name2835.15 2656.75 3076.00 7 7" KOP6478.93 6300.53 6876.00 3-1/2 3 1/2" x 6" 1 Dewhurst, Andrew D (OGC) From:Dewhurst, Andrew D (OGC) Sent:Friday, 30 August, 2024 11:18 To:Sean McLaughlin; Sean Wagner; Joseph Lastufka Cc:Davies, Stephen F (OGC); Guhl, Meredith D (OGC); McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] BCU 09A PTD (224-113): Question Thank you. From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Friday, 30 August, 2024 11:12 To: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov>; Sean Wagner <Sean.Wagner@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] BCU 09A PTD (224-113): Question Andy, The liner will cover both the Beluga and Sterling. The primary target is the upper Beluga with a secondary target in the lower Sterling. Regards, sean From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Friday, August 30, 2024 10:34 AM To: Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Cc: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] BCU 09A PTD (224-113): Question Joe, Would you conĮrm that the BCU 09A redrill is planned to be completed in both the Sterling and Beluga gas pools like the parent wellbore? Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas ConservaƟon Commission CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 333 W. 7th Ave, Anchorage, AK 99501 andrew.dewhurst@alaska.gov Direct: (907) 793-1254 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 d issemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. BEAVER CREEK BELUGA GAS and STERLING GAS 224-113 BCU 09A WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:BEAVER CK UNIT 09AInitial Class/TypeDEV / PENDGeoArea820Unit50212On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241130BEAVER CREEK, BELUGA GAS - 80500 BEAVER CREEK, STERLING GNA1 Permit fee attachedYes AKA0280832 Lease number appropriateYes3 Unique well name and numberYes BEAVER CREEK, BELUGA GAS - 80500 - governed by CO 237D4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA Sidetrack18 Conductor string providedYes19 Surface casing protects all known USDWsNA20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2203 psi, BOP rated to 5000 psi (BOP test to 2500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes H2S not recorded in nearby wells.35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating normal pore pressures with potential for underpressured Beluga sands (Beluga-6,7,11)36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate8/30/2024ApprBJMDate9/10/2024ApprADDDate8/30/2024AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 9/19/2024