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Home My WebLink About219-188CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Ryan Lemay To:McLellan, Bryan J (OGC) Cc:Donna Ambruz; Trevor Willms - (C) Subject:RE: [EXTERNAL] RE: BCU-19RD / PTD: 219-188 / Sundry # 325-473 / Request For Approval Date:Thursday, August 21, 2025 5:46:38 PM Attachments:BCU-19RD Schematic 08-07-25 - Proposed.pdf BCU-19RD Upper Beluga Perfs August 2025 Procedure.pdf Bryan, Thanks for the approval. Attached is the updated procedure and proposed schematic for the Bel 5 proposed perfs. I apologize for not catching this sooner. Have a good evening. Ryan LeMay Operations Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, August 21, 2025 5:18 PM To: Ryan Lemay <ryan.lemay@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; Trevor Willms - (C) <Trevor.Willms@hilcorp.com> Subject: [EXTERNAL] RE: BCU-19RD / PTD: 219-188 / Sundry # 325-473 / Request For Approval Approved. Please send corrected TVD for the Bel 5 top & bottom perfs as discussed. Thanks Bryan McLellan 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. Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Lemay <ryan.lemay@hilcorp.com> Sent: Thursday, August 21, 2025 5:10 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Trevor Willms - (C) <Trevor.Willms@hilcorp.com> Subject: BCU-19RD / PTD: 219-188 / Sundry # 325-473 / Request For Approval Good evening Bryan, This is a follow up to our conversation on Wednesday. In the conditions of approval for this Sundry, a requirement was set that Hilcorp dump bail 25’ of cement on top of existing plug at 6288’ MD before proceeding and setting additional plugs in the well. Hilcorp is requesting approval to remove this requirement of dump bailing 25’ of cement on the current plug at 6288’ MD. If we were to dump bail 25’ of cement on top of the CIBP at 6288’, we would be dump bailing cement across the open Bel 7 perf set. My intention is to be able to push fluid away with N2 through those perforations prior to setting a plug above the Bel 7 (zone watered out) and dump bailing cement across those perforations could compromise my ability to do so. Additionally, the perforations sundried in this procedure are the last 4 zones in the Beluga before we would transition to the Sterling at a future date. The top of the Beluga Gas pool is at 6088’ MD / 5818’ TVD (only 200’ above the plug at 6288’ MD requesting cement to be dump bailed on). Hilcorp’s plan would be to set a CIBP plug, dump bail a minimum of 35’ of cement, tag, and pressure test for plug integrity at the top of the Beluga gas pool for proper zonal isolation when we transition from the Beluga to the Sterling Gas pool. In our discussion, you had mentioned that if BLM was aligned and would not require us to dump bail cement on this plug, that you’d be open to approving and removing this as a requirement as well. BLM has just approved the Sundry and will not require that we dump bail cement on the plug at 6288’ MD. With BLM aligned, please let me know if you also approve of removing the requirement to dump bail cement on the current plug at 6288’ MD as a condition of approval for this sundry. Additional note: I did follow up to your inquiry on the TVDs in the Sundry and the TVDs in the Sundry are correct. Thank you, Ryan LeMay Operations Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. _____________________________________________________________________________________ Updated by RPL 08-07-25 SCHEMATIC Proposed Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 2 6,288’6,001’N/A CIBP (5/11/25) 3 6,445’6,144’N/A CIBP (5/10/25) 4 6,521’6,214’N/A CIBP (3/16/25) 5 7,615’7,212’N/A CIBP w/ 35’ of cement - TOC @ 7,580’ (6/24/24) 6 8,581’8,094’2.0”Known tight spot- difficult to get long (20’+) tool strings down hole. (2/16/24) 7 9,399’8,867’N/A CIBP (35’ cmt on top) TOC 9,364’ MD (2/16/24) 8 9,929’9,369’N/A CIBP (2/13/24) 9 10,940’10,331’2.441”Float Shoe 10 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 11 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441”Surf 10,943’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments UBEL ±6,115 ±6,125 ±5,843'±5,852'±10'Proposed Bel 5 ±6,148 ±6,168 ±5,873'±5,891'±20'Proposed Bel 6 ±6,229 ±6,236 ±5,947'±5953'±7'Proposed Bel 6 ±6,238 ±6,247 ±5,955'±5,963'±9'Proposed Bel 7 6,257’6,273’5,972'5,987'16'5/11/25 Open Bel 7B 6,302’6,322’6,013'6,032'16'5/10/25 Isolated Bel 9 6,495’6,509’6,189’6,202’14’3/20/25 Isolated Bel 9 6,537’6,551'6,228’6,240’14’9/27/24 Isolated Bel 9 6,557’6,567'6,246'6,255'10'9/26/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'7/17/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'8/18/24 Isolated Bel 10 6,581’6,593’6,267'6,279'12’9/26/24 Isolated Bel 10 6,642'6,652'6,323'6,332'10'6/28/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/26/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/27/24 Isolated Bel 11 6,720’6,729’6,394'6,402'9’9/26/24 Isolated Bel 11 6,795’6,809’6,462'6,475'14’9/26/24 Isolated BEL B17 7,665'7,675'7,258'7,267'10'2/23/24 Isolated BEL 20 7,885'7,895'7,459'7,469'10'2/23/24 Isolated BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2/22/24 Isolated B26 8,294’8,307’7,830’7,843’13’2/22/24 Isolated B27 8,378’8,389’7,908’7,919’11’2/22/24 Isolated BEL 28 8,513’8,527’8,030’8,043’14’2/20/24 Isolated BEL 28 Lwr 8,560’8,575’8,074’8,088’15 2/20/24 Isolated BEL 28 Lwr 8,575’8,585’8,088’8,096’10’2/19/24 Isolated BEL B31 Lwr 8,821'8,835'8,317'8,330'14'2/19/24 Isolated B31C 8,952 8962’8,263’8,276’10’2/18/24 Isolated B32 9,013 9,033’8,330’8,338’20’2/18/24 Isolated T1XX 9,082’9,096’8,566’8,579’14’2/14/24 Isolated T1X 9,223’9,231’8,699’8,704’8’2/14/24 Isolated T4 9,449’9,462’8,916’8,927’13’2/14/24 Isolated TY T7A 9,744'9,761'9,236'9,252'17'2/13/24 Isolated T8 9,979’9,996’9,416’9,432’17’2/7/24 Isolated TY T18 10,886'10,906'10,222'10,228'20'1/25/24 Isolated T19 10,901’10,921’10,290’10,310’20’1/25/24 Isolated T19 10,923’10,937’10,315’10,328’14’5/9/20 Isolated T19A 10,957’10,970’10,347’10,359’13’4/13/20 Isolated T66 12,683’12,708’12,003’12,027’25’4/8/20 Isolated Well Prognosis Well: BCU-19RD Well Name: BCU-19RD API Number: 50-133-20579-01-00 Current Status: Gas Producer Permit to Drill Number: 219-188 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: 2635 psi @ 5987’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 2036 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.71 psi/ft using 13.6 ppg EMW FIT at the 9-5/8” int. casing shoe Shallowest Allowable Perf TVD: MPSP / (0.71-0.1) = 2036 psi / 0.61 = 3338‘ TVD Top of Applicable Gas Pool / PA: 6088’ MD / 5818’ TVD (Beluga Gas) Well Status: Gas Producer x 207 mcfd / 0 bwpd / 66 psi FTP (As of last well test on 7/31/2025) Recent Well Summary: Most recent well work on BCU-19RD was completed from March – May 2025. The currently open perforation zone is the Beluga 7 interval from (6,257’ – 6,273’ MD). This zone initially came on ~730 mcfd / 0 bwpd / 87 psi FTP in May 2025 and has since steadily declined in gas production rate to 207 mcfd / 0 bwpd / 66 psi FTP (As of last well test on 7/31/2025). The objective of this Sundry is to add additional perforations in UBel – Bel 6 sands. Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,500 psi high 3. RIH and perforate the following sands from bottom up: Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Well Sand Top MD Btm MD Top TVD Btm TVD Interval BCU-19RD UBEL ±6,115 ±6,125 ±5,843' ±5,852' ±10' BCU-19RD Bel 5 ±6,148 ±6,168 ±5,873' ±5,891' ±20' BCU-19RD Bel 6 ±6,229 ±6,236 ±5,947' ±5953' ±7' BCU-19RD Bel 6 ±6,238 ±6,247 ±5,955' ±5,963' ±9' a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation b. Use Gamma/CCL to correlate c. Record tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) d. Pending well production, all perf intervals may not be completed e. If any current or proposed zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations Well Prognosis Well: BCU-19RD i. Note: A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. 35ft will not be placed on each plug as these zones are close together. If possible, the CIBP will be set 50’ above of the top of the last perforated sand unless zones are too close together in which case the plug will be set within 50’. f. If necessary, use nitrogen or pad gas to pressure up well during perforating or to depress water prior to setting a plug above perforations. 4. RDMO Contingency Procedure: Coiled Tubing Cleanout 1. If throughout the job any current or proposed zones produce sand and / or water that cannot be depressed and pushed away with nitrogen or pad gas, a coil tubing unit may be rigged up to clean out fill or fluid blown down as necessary. a. MIRU Fox CTU, PT BOPE to 250 psi low / 2500 psi high i. Provide AOGCC 24hrs notice of BOP test. b. Cleanout wellbore fill and / or blowdown well with nitrogen if necessary. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Diagram 4. Standard Well Procedure – N2 Operations CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Ryan Lemay Cc:Donna Ambruz; Trevor Willms - (C) Subject:RE: BCU-19RD / PTD: 219-188 / Sundry # 325-473 / Request For Approval Date:Thursday, August 21, 2025 5:17:00 PM Approved. Please send corrected TVD for the Bel 5 top & bottom perfs as discussed. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Ryan Lemay <ryan.lemay@hilcorp.com> Sent: Thursday, August 21, 2025 5:10 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Trevor Willms - (C) <Trevor.Willms@hilcorp.com> Subject: BCU-19RD / PTD: 219-188 / Sundry # 325-473 / Request For Approval Good evening Bryan, This is a follow up to our conversation on Wednesday. In the conditions of approval for this Sundry, a requirement was set that Hilcorp dump bail 25’ of cement on top of existing plug at 6288’ MD before proceeding and setting additional plugs in the well. Hilcorp is requesting approval to remove this requirement of dump bailing 25’ of cement on the current plug at 6288’ MD. If we were to dump bail 25’ of cement on top of the CIBP at 6288’, we would be dump bailing cement across the open Bel 7 perf set. My intention is to be able to push fluid away with N2 through those perforations prior to setting a plug above the Bel 7 (zone watered out) and dump bailing cement across those perforations could compromise my ability to do so. Additionally, the perforations sundried in this procedure are the last 4 zones in the Beluga before we would transition to the Sterling at a future date. The top of the Beluga Gas pool is at 6088’ MD / 5818’ TVD (only 200’ above the plug at 6288’ MD requesting cement to be dump bailed on). Hilcorp’s plan would be to set a CIBP plug, dump bail a minimum of 35’ of cement, tag, and pressure test for plug integrity at the top of the Beluga gas pool for proper zonal isolation when we transition from the Beluga to the Sterling Gas pool. In our discussion, you had mentioned that if BLM was aligned and would not require us to dump bail cement on this plug, that you’d be open to approving and removing this as a requirement as well. BLM has just approved the Sundry and will not require that we dump bail cement on the plug at 6288’ MD. With BLM aligned, please let me know if you also approve of removing the requirement to dump bail cement on the current plug at 6288’ MD as a condition of approval for this sundry. Additional note: I did follow up to your inquiry on the TVDs in the Sundry and the TVDs in the Sundry are correct. Thank you, Ryan LeMay Operations Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: CTCO, N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,850'6,785' (fill) Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 7,460psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.lemay@hilcorp.com 661-487-0871 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 Ryan LeMay, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 219-188 50-133-20579-01-00 Hilcorp Alaska, LLC Proposed Pools: 6.5# / L-80 TVD Burst 10,943' 10,640psi 2,509' Size 106' 9-5/8"4,488' 2,510' MD See Attached Schematic 5,750psi 3,060psi 3,450psi 106' 4,372' 106' 2,510' August 21, 2025 2-7/8" 12,841' Perforation Depth MD (ft): 4,488' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 19RDCO 237D Same 12,157'5-1/2" ~2,036psi 12,841' See Schematic Length Swell Pkr; N/A 4,295' MD/4,208' TVD; N/A 12,166'7,580'7,180' Beaver Creek Beluga Gas 20" 13-3/8" See Attached Schematic 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 3:01 pm, Aug 11, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.08.11 14:47:14 - 08'00' Noel Nocas (4361) 325-473 DSR-8/14/25 Dump bail 25' of cement on top of existing plug at 6288' MD before setting additional plugs in the well. BJM 8/18/25 10-404 A.Dewhurst 14AUG25JLC 8/18/2025 Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.08.19 06:57:29 -08'00'08/19/25 RBDMS JSB 082025 Well Prognosis Well: BCU-19RD Well Name: BCU-19RD API Number: 50-133-20579-01-00 Current Status: Gas Producer Permit to Drill Number: 219-188 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: 2635 psi @ 5987’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 2036 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.71 psi/ft using 13.6 ppg EMW FIT at the 9-5/8” int. casing shoe Shallowest Allowable Perf TVD: MPSP / (0.71-0.1) = 2036 psi / 0.61 = 3338‘ TVD Top of Applicable Gas Pool / PA: 6088’ MD / 5818’ TVD (Beluga Gas) Well Status: Gas Producer x 207 mcfd / 0 bwpd / 66 psi FTP (As of last well test on 7/31/2025) Recent Well Summary: Most recent well work on BCU-19RD was completed from March – May 2025. The currently open perforation zone is the Beluga 7 interval from (6,257’ – 6,273’ MD). This zone initially came on ~730 mcfd / 0 bwpd / 87 psi FTP in May 2025 and has since steadily declined in gas production rate to 207 mcfd / 0 bwpd / 66 psi FTP (As of last well test on 7/31/2025). The objective of this Sundry is to add additional perforations in UBel – Bel 6 sands. Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 2,500 psi high 3. RIH and perforate the following sands from bottom up: Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Well Sand Top MD Btm MD Top TVD Btm TVD Interval BCU-19RD UBEL ±6,115 ±6,125 ±5,843' ±5,852' ±10' BCU-19RD Bel 5 ±6,148 ±6,168 ±5,694' ±5,712' ±20' BCU-19RD Bel 6 ±6,229 ±6,236 ±5,947' ±5953' ±7' BCU-19RD Bel 6 ±6,238 ±6,247 ±5,955' ±5,963' ±9' a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation b. Use Gamma/CCL to correlate c. Record tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) d. Pending well production, all perf intervals may not be completed e. If any current or proposed zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations Well Prognosis Well: BCU-19RD i. Note: A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. 35ft will not be placed on each plug as these zones are close together. If possible, the CIBP will be set 50’ above of the top of the last perforated sand unless zones are too close together in which case the plug will be set within 50’. f. If necessary, use nitrogen or pad gas to pressure up well during perforating or to depress water prior to setting a plug above perforations. 4. RDMO Contingency Procedure: Coiled Tubing Cleanout 1. If throughout the job any current or proposed zones produce sand and / or water that cannot be depressed and pushed away with nitrogen or pad gas, a coil tubing unit may be rigged up to clean out fill or fluid blown down as necessary. a. MIRU Fox CTU, PT BOPE to 250 psi low / 2500 psi high i. Provide AOGCC 24hrs notice of BOP test. b. Cleanout wellbore fill and / or blowdown well with nitrogen if necessary. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Diagram 4. Standard Well Procedure – N2 Operations _____________________________________________________________________________________ Updated by RPL 06-02-25 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 2 6,288’6,001’N/A CIBP (5/11/25) 3 6,445’6,144’N/A CIBP (5/10/25) 4 6,521’6,214’N/A CIBP (3/16/25) 5 7,615’7,212’N/A CIBP w/ 35’ of cement - TOC @ 7,580’ (6/24/24) 6 8,581’8,094’2.0”Known tight spot- difficult to get long (20’+) tool strings down hole. (2/16/24) 7 9,399’8,867’N/A CIBP (35’ cmt on top) TOC 9,364’ MD (2/16/24) 8 9,929’9,369’N/A CIBP (2/13/24) 9 10,940’10,331’2.441”Float Shoe 10 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 11 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441”Surf 10,943’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Bel 7 6,257’6,273’5,972'5,987'16'5/11/25 Open Bel 7B 6,302’6,322’6,013'6,032'16'5/10/25 Isolated Bel 9 6,495’6,509’6,189’6,202’14’3/20/25 Isolated Bel 9 6,537’6,551'6,228’6,240’14’9/27/24 Isolated Bel 9 6,557’6,567'6,246'6,255'10'9/26/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'7/17/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'8/18/24 Isolated Bel 10 6,581’6,593’6,267'6,279'12’9/26/24 Isolated Bel 10 6,642'6,652'6,323'6,332'10'6/28/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/26/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/27/24 Isolated Bel 11 6,720’6,729’6,394'6,402'9’9/26/24 Isolated Bel 11 6,795’6,809’6,462'6,475'14’9/26/24 Isolated BEL B17 7,665'7,675'7,258'7,267'10'2/23/24 Isolated BEL 20 7,885'7,895'7,459'7,469'10'2/23/24 Isolated BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2/22/24 Isolated B26 8,294’8,307’7,830’7,843’13’2/22/24 Isolated B27 8,378’8,389’7,908’7,919’11’2/22/24 Isolated BEL 28 8,513’8,527’8,030’8,043’14’2/20/24 Isolated BEL 28 Lwr 8,560’8,575’8,074’8,088’15 2/20/24 Isolated BEL 28 Lwr 8,575’8,585’8,088’8,096’10’2/19/24 Isolated BEL B31 Lwr 8,821'8,835'8,317'8,330'14'2/19/24 Isolated B31C 8,952 8962’8,263’8,276’10’2/18/24 Isolated B32 9,013 9,033’8,330’8,338’20’2/18/24 Isolated T1XX 9,082’9,096’8,566’8,579’14’2/14/24 Isolated T1X 9,223’9,231’8,699’8,704’8’2/14/24 Isolated T4 9,449’9,462’8,916’8,927’13’2/14/24 Isolated TY T7A 9,744'9,761'9,236'9,252'17'2/13/24 Isolated T8 9,979’9,996’9,416’9,432’17’2/7/24 Isolated TY T18 10,886'10,906'10,222'10,228'20'1/25/24 Isolated T19 10,901’10,921’10,290’10,310’20’1/25/24 Isolated T19 10,923’10,937’10,315’10,328’14’5/9/20 Isolated T19A 10,957’10,970’10,347’10,359’13’4/13/20 Isolated T66 12,683’12,708’12,003’12,027’25’4/8/20 Isolated _____________________________________________________________________________________ Updated by RPL 06-02-25 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 2 6,288’6,001’N/A CIBP (5/11/25) 3 6,445’6,144’N/A CIBP (5/10/25) 4 6,521’6,214’N/A CIBP (3/16/25) 5 7,615’7,212’N/A CIBP w/ 35’ of cement - TOC @ 7,580’ (6/24/24) 6 8,581’8,094’2.0”Known tight spot- difficult to get long (20’+) tool strings down hole. (2/16/24) 7 9,399’8,867’N/A CIBP (35’ cmt on top) TOC 9,364’ MD (2/16/24) 8 9,929’9,369’N/A CIBP (2/13/24) 9 10,940’10,331’2.441”Float Shoe 10 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 11 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441”Surf 10,943’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Bel 7 6,257’6,273’5,972'5,987'16'5/11/25 Open Bel 7B 6,302’6,322’6,013'6,032'16'5/10/25 Isolated Bel 9 6,495’6,509’6,189’6,202’14’3/20/25 Isolated Bel 9 6,537’6,551'6,228’6,240’14’9/27/24 Isolated Bel 9 6,557’6,567'6,246'6,255'10'9/26/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'7/17/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'8/18/24 Isolated Bel 10 6,581’6,593’6,267'6,279'12’9/26/24 Isolated Bel 10 6,642'6,652'6,323'6,332'10'6/28/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/26/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/27/24 Isolated Bel 11 6,720’6,729’6,394'6,402'9’9/26/24 Isolated Bel 11 6,795’6,809’6,462'6,475'14’9/26/24 Isolated BEL B17 7,665'7,675'7,258'7,267'10'2/23/24 Isolated BEL 20 7,885'7,895'7,459'7,469'10'2/23/24 Isolated BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2/22/24 Isolated B26 8,294’8,307’7,830’7,843’13’2/22/24 Isolated B27 8,378’8,389’7,908’7,919’11’2/22/24 Isolated BEL 28 8,513’8,527’8,030’8,043’14’2/20/24 Isolated BEL 28 Lwr 8,560’8,575’8,074’8,088’15 2/20/24 Isolated BEL 28 Lwr 8,575’8,585’8,088’8,096’10’2/19/24 Isolated BEL B31 Lwr 8,821'8,835'8,317'8,330'14'2/19/24 Isolated B31C 8,952 8962’8,263’8,276’10’2/18/24 Isolated B32 9,013 9,033’8,330’8,338’20’2/18/24 Isolated T1XX 9,082’9,096’8,566’8,579’14’2/14/24 Isolated T1X 9,223’9,231’8,699’8,704’8’2/14/24 Isolated T4 9,449’9,462’8,916’8,927’13’2/14/24 Isolated TY T7A 9,744'9,761'9,236'9,252'17'2/13/24 Isolated T8 9,979’9,996’9,416’9,432’17’2/7/24 Isolated TY T18 10,886'10,906'10,222'10,228'20'1/25/24 Isolated T19 10,901’10,921’10,290’10,328’20’1/25/24 Isolated Superseded by updated schematic. -A.Dewhurst 14AUG25 _____________________________________________________________________________________ Updated by RPL 08-07-25 SCHEMATIC Proposed Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 2 6,288’6,001’N/A CIBP (5/11/25) 3 6,445’6,144’N/A CIBP (5/10/25) 4 6,521’6,214’N/A CIBP (3/16/25) 5 7,615’7,212’N/A CIBP w/ 35’ of cement - TOC @ 7,580’ (6/24/24) 6 8,581’8,094’2.0”Known tight spot- difficult to get long (20’+) tool strings down hole. (2/16/24) 7 9,399’8,867’N/A CIBP (35’ cmt on top) TOC 9,364’ MD (2/16/24) 8 9,929’9,369’N/A CIBP (2/13/24) 9 10,940’10,331’2.441”Float Shoe 10 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 11 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441”Surf 10,943’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments UBEL ±6,115 ±6,125 ±5,843'±5,852'±10'Proposed Bel 5 ±6,148 ±6,168 ±5,694'±5,712'±20'Proposed Bel 6 ±6,229 ±6,236 ±5,947'±5953'±7'Proposed Bel 6 ±6,238 ±6,247 ±5,955'±5,963'±9'Proposed Bel 7 6,257’6,273’5,972'5,987'16'5/11/25 Open Bel 7B 6,302’6,322’6,013'6,032'16'5/10/25 Isolated Bel 9 6,495’6,509’6,189’6,202’14’3/20/25 Isolated Bel 9 6,537’6,551'6,228’6,240’14’9/27/24 Isolated Bel 9 6,557’6,567'6,246'6,255'10'9/26/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'7/17/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'8/18/24 Isolated Bel 10 6,581’6,593’6,267'6,279'12’9/26/24 Isolated Bel 10 6,642'6,652'6,323'6,332'10'6/28/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/26/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/27/24 Isolated Bel 11 6,720’6,729’6,394'6,402'9’9/26/24 Isolated Bel 11 6,795’6,809’6,462'6,475'14’9/26/24 Isolated BEL B17 7,665'7,675'7,258'7,267'10'2/23/24 Isolated BEL 20 7,885'7,895'7,459'7,469'10'2/23/24 Isolated BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2/22/24 Isolated B26 8,294’8,307’7,830’7,843’13’2/22/24 Isolated B27 8,378’8,389’7,908’7,919’11’2/22/24 Isolated BEL 28 8,513’8,527’8,030’8,043’14’2/20/24 Isolated BEL 28 Lwr 8,560’8,575’8,074’8,088’15 2/20/24 Isolated BEL 28 Lwr 8,575’8,585’8,088’8,096’10’2/19/24 Isolated BEL B31 Lwr 8,821'8,835'8,317'8,330'14'2/19/24 Isolated B31C 8,952 8962’8,263’8,276’10’2/18/24 Isolated B32 9,013 9,033’8,330’8,338’20’2/18/24 Isolated T1XX 9,082’9,096’8,566’8,579’14’2/14/24 Isolated T1X 9,223’9,231’8,699’8,704’8’2/14/24 Isolated T4 9,449’9,462’8,916’8,927’13’2/14/24 Isolated TY T7A 9,744'9,761'9,236'9,252'17'2/13/24 Isolated T8 9,979’9,996’9,416’9,432’17’2/7/24 Isolated TY T18 10,886'10,906'10,222'10,228'20'1/25/24 Isolated T19 10,901’10,921’10,290’10,310’20’1/25/24 Isolated T19 10,923’10,937’10,315’10,328’14’5/9/20 Isolated T19A 10,957’10,970’10,347’10,359’13’4/13/20 Isolated T66 12,683’12,708’12,003’12,027’25’4/8/20 Isolated _____________________________________________________________________________________ Updated by RPL 08-07-25 SCHEMATIC Proposed Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 2 6,288’6,001’N/A CIBP (5/11/25) 3 6,445’6,144’N/A CIBP (5/10/25) 4 6,521’6,214’N/A CIBP (3/16/25) 5 7,615’7,212’N/A CIBP w/ 35’ of cement - TOC @ 7,580’ (6/24/24) 6 8,581’8,094’2.0”Known tight spot- difficult to get long (20’+) tool strings down hole. (2/16/24) 7 9,399’8,867’N/A CIBP (35’ cmt on top) TOC 9,364’ MD (2/16/24) 8 9,929’9,369’N/A CIBP (2/13/24) 9 10,940’10,331’2.441”Float Shoe 10 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 11 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441”Surf 10,943’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments UBEL ±6,115 ±6,125 ±5,843'±5,852'±10'Proposed Bel 5 ±6,148 ±6,168 ±5,694'±5,712'±20'Proposed Bel 6 ±6,229 ±6,236 ±5,947'±5953'±7'Proposed Bel 6 ±6,238 ±6,247 ±5,955'±5,963'±9'Proposed Bel 7 6,257’6,273’5,972'5,987'16'5/11/25 Open Bel 7B 6,302’6,322’6,013'6,032'16'5/10/25 Isolated Bel 9 6,495’6,509’6,189’6,202’14’3/20/25 Isolated Bel 9 6,537’6,551'6,228’6,240’14’9/27/24 Isolated Bel 9 6,557’6,567'6,246'6,255'10'9/26/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'7/17/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'8/18/24 Isolated Bel 10 6,581’6,593’6,267'6,279'12’9/26/24 Isolated Bel 10 6,642'6,652'6,323'6,332'10'6/28/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/26/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/27/24 Isolated Bel 11 6,720’6,729’6,394'6,402'9’9/26/24 Isolated Bel 11 6,795’6,809’6,462'6,475'14’9/26/24 Isolated BEL B17 7,665'7,675'7,258'7,267'10'2/23/24 Isolated BEL 20 7,885'7,895'7,459'7,469'10'2/23/24 Isolated BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2/22/24 Isolated B26 8,294’8,307’7,830’7,843’13’2/22/24 Isolated B27 8,378’8,389’7,908’7,919’11’2/22/24 Isolated BEL 28 8,513’8,527’8,030’8,043’14’2/20/24 Isolated BEL 28 Lwr 8,560’8,575’8,074’8,088’15 2/20/24 Isolated BEL 28 Lwr 8,575’8,585’8,088’8,096’10’2/19/24 Isolated BEL B31 Lwr 8,821'8,835'8,317'8,330'14'2/19/24 Isolated B31C 8,952 8962’8,263’8,276’10’2/18/24 Isolated B32 9,013 9,033’8,330’8,338’20’2/18/24 Isolated T1XX 9,082’9,096’8,566’8,579’14’2/14/24 Isolated T1X 9,223’9,231’8,699’8,704’8’2/14/24 Isolated T4 9,449’9,462’8,916’8,927’13’2/14/24 Isolated TY T7A 9,744'9,761'9,236'9,252'17'2/13/24 Isolated T8 9,979’9,996’9,416’9,432’17’2/7/24 Isolated TY T18 10,886'10,906'10,222'10,228'20'1/25/24 Isolated T19 10,901’10,921’10,290’10,328’20’1/25/24 Isolated Superseded by updated schematic. -A.Dewhurst 14AUG25 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1 Dewhurst, Andrew D (OGC) From:Ryan Lemay <ryan.lemay@hilcorp.com> Sent:Thursday, 14 August, 2025 12:07 To:Dewhurst, Andrew D (OGC) Cc:McLellan, Bryan J (OGC); Cody Dinger; Donna Ambruz Subject:RE: [EXTERNAL] BCU 19RD Perf Sundry (325-473): Question Attachments:BCU-19RD Schematic 08-07-25 - Proposed.pdf; BCU-19RD Schematic 05-11-25.pdf Good afternoon Andrew, Thanks for catching this. Looks like these lower perf zones got removed from the perforation detail inadvertently when the 2-7/8” cement tieback job was completed in 2024. Attached is the updated / corrected PDF versions of the actual and proposed schematics. Ryan LeMay OperaƟons Engineer Swanson River / Beaver Creek Cell: (661) 487-0871 E-mail: Ryan.lemay@hilcorp.com To help protect your privacy, Microsoft Office prevented automatic download of this picture from the Internet. From: Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Sent: Tuesday, August 12, 2025 5:47 PM To: Ryan Lemay <ryan.lemay@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Cody Dinger <cdinger@hilcorp.com> Subject: [EXTERNAL] BCU 19RD Perf Sundry (325-473): Question Ryan, I am completing my review of the perf sundry for BCU 19RD and have a question: 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 It appears that the Perforation Detail on the schematic page list is missing a few of the deepest perforations. The actual schematic looks correct. Would you check on this and send me a revised PDF of that page if conƱrmed? From the original completion report: Thanks, Andy Andrew Dewhurst Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 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 dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2 Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,850 feet See Schematic feet true vertical 12,166 feet 6,785' (fill)feet Effective Depth measured 6,288 feet 4,208 feet true vertical 6,001 feet 4,134 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 10,943' MD 10,333' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 4,208' MD 4,134' TVD N/A, N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone: Ryan Lemay, Operations Engineer 325-100 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf ryan.lemay@hilcorp.com 27 Size 106' 0 20729 0 4830 87 9-5/8" 5-1/2" Intermediate 20" 13-3/8" 106' Production Liner 4,488' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-188 50-133-20579-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028083 Beaver Creek / Beluga Gas Beaver Creek Unit 19RD 12,841' Casing Structural 4,372' 12,157' 4,488' 12,841' 106'Conductor Surface 2,510' TVDMD 661-487-0871 measured Packer Plugs Junk measured Length 3,090psi 7,460psi 3,060psi 3,450psi 5,750psi 10,640psi 2,510'2,509' Burst Collapse 1,500psi 1,950psi measured true vertical p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 10:34 am, Jun 05, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.06.04 19:33:37 - 08'00' Noel Nocas (4361) BJM 9/19/25 DSR-6/18/25 RBDMS JSB 061325 Page 1/2 Well Name: BCU-019RD Report Printed: 6/2/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20579-01-00 Field Name:Beaver Creek State/Province:ALASKA Permit to Drill (PTD) #:219-188 Sundry #:325-100 Rig Name/No: Jobs Actual Start Date:2/19/2025 End Date: Report Number 1 Report Start Date 3/4/2025 Report End Date 3/5/2025 Last 24hr Summary MIRU slickline. PT lubricator 250 psi low / 2500 psi high - good test. Bail from 6475' to 6502'kb Report Number 2 Report Start Date 3/11/2025 Report End Date 3/11/2025 Last 24hr Summary PTW/PJSM. 438 psi SITP. MIRU Pollard Slickline. PT lubricator 250 psi low / 2500 psi high - good test. Bail fill from 6,502' to 6,523' RKB in 8 runs with 1.75" and 2.25" bailers. Saw fluid level ~1,200'. SDFN. Report Number 3 Report Start Date 3/12/2025 Report End Date 3/13/2025 Last 24hr Summary Continue bailing 6523' - 6533' RKB Report Number 4 Report Start Date 3/13/2025 Report End Date 3/14/2025 Last 24hr Summary Continue attempting to bail to 6537' RKB. Unable to bail past 6533' RKB. RDMO slickline. Report Number 5 Report Start Date 3/14/2025 Report End Date 3/15/2025 Last 24hr Summary PTW/PJSM. 500 psi SITP. MIRU Fox N2. PT lines to 3500 psi - good test Pump N2 @ 900 scfm and pressure up well to 3500 psi. Monitor pressure drop. PT lines to 4000 psi - good test. Pump N2 @ 800 scfm and pressure up well from 3350 psi to 4000 psi. Monitor pressure drop. Pump N2 @ 800 scfm and pressure up well from 3750 psi to 4000 psi. Pumped 29,057 scf (312 gals) N2. Secure well, SDFN. Report Number 6 Report Start Date 3/16/2025 Report End Date 3/16/2025 Last 24hr Summary PTW/PJSM. 3460 psi SITP. MIRU YJ E-line. PT lubricator to 250 psi low / 3200 psi high - good test. RIH w/ GPT and find fluid level ~ 1,380'. RIH w/ CIBP and set @ 6,521'. RDMO YJ E-line. Report Number 7 Report Start Date 3/17/2025 Report End Date 3/17/2025 Last 24hr Summary PTW/PJSM. 2760 psi SITP. MIRU Pollard Slickline. PT lubricator 250 psi low / 2500 psi high - good test. Bleed well to 0 psi. RIH w/ 2 7/8" swab cups and swab fluid from 1,380' to 3,300' in 19 runs. Recovered 11 of 30 calculated bbls. SDFN. Report Number 8 Report Start Date 3/18/2025 Report End Date 3/18/2025 Last 24hr Summary PTW/PJSM. 0 psi SITP. RIH w/ 2 7/8" swab cups and swab fluid from 3,300' to 5,900' in 16 runs. Recovered 15 bbls today, 26 of 30 calculated bbls total recovery. SDFN. Report Number 9 Report Start Date 3/19/2025 Report End Date 3/19/2025 Last 24hr Summary PTW/PJSM. 0 psi SITP. RIH w/ 2 7/8" swab cups and swab fluid from 5,900' to 6,460' in 8 runs. Tagging CIBP @ 6,521'. Recovered 3.6 bbls today, 29.4 of 30 calculated bbls total recovery. RDMO Pollard, RU Fox N2. PT lines to 2000 psi (max pumping pressure is 1700 psi with no open perfs). Pressure up well from 0 to 1700 psi with 33,100 scf (355 gals) N2. RD Fox, secure well, SDFN. Report Number 10 Report Start Date 3/20/2025 Report End Date 3/20/2025 Last 24hr Summary PTW/PJSM. 1700 psi SITP. MIRU YJ E-line. PT lubricator to 250 psi low / 2500 psi high - good test. RIH w/ 14' x 2" 6 SPF 60 DEG guns and perf BEL 9 (6,495' - 6,509'). RIH w/ GPT and find fluid level ~6,330'. Flow well starting @ 2127 psi and dropping 5-10 psi/min. Check for fluid influx w/ GPT. Last fluid level ~5,560' and getting LEL's @ 1740 psi FTP. POOH, secure well, and hand well to production. Report Number 11 Report Start Date 3/21/2025 Report End Date 3/21/2025 Last 24hr Summary PTW/PJSM. 330 psi FTP. RU YJ E-line. RIH w/ 1 11/16" GPT (w/ 2" weight bar) and find slugging fluid near surface and suspended fluid from ~4,200'-6,300'. Tag @ 6,506'. RDMO YJ and flow well. Report Number 12 Report Start Date 3/28/2025 Report End Date 3/28/2025 Last 24hr Summary MIRU slickline unit. PT lubricator 250 psi low / 2500 psi high - good test. Tagged fill at 6492'KB- Bailed fill to 6513'KB. Noted Fluid influx to 5860'KB Report Number 13 Report Start Date 3/29/2025 Report End Date 3/29/2025 Last 24hr Summary Tagged fill at 6510'KB- Bailed fill to 6521'KB- Allowed for flow attempt- Bailed from 6431'KB- back to 6513'KB Report Number 14 Report Start Date 3/30/2025 Report End Date 3/31/2025 Last 24hr Summary PTW/PJSM, RU PWL. Bail from 6480' SLM (6487' KB)-6495' SLM (6512' KB) in 7 runs. RDMO slickline. turn well over to operations to attempt to flow well. Page 2/2 Well Name: BCU-019RD Report Printed: 6/2/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 15 Report Start Date 5/1/2025 Report End Date 5/1/2025 Last 24hr Summary MIRU slickline. PT lubricator 250 psi low / 2500 psi. RIH w/ 2.0" x 4.0' DD bailer to 6501' and tag. RDMO slickline. Report Number 16 Report Start Date 5/10/2025 Report End Date 5/11/2025 Last 24hr Summary Complete PTW / PJSM. Spot Ak Eline and begin rigging up. MIRU Fox N2 pump and PT to 4000 psi. WHP 300 psi. Online down tubing w/N2 @ 1000 scfm. WHP broke over 2300 psi. Pumped 47k scf N2 (504 gallons). Pick up E-line PCE and stab on well. PT 250 psi low / 2500 psi high - goot test. Ran 1.69" GPT w/1.69" Junk Basket w/2.30" gauge ring, hard tag 6498' elm, corrected from Geo. No fluid in wellbore. Set 2.10" CIBP @ 6445'. Bleed WHP to 1558 psi. Perforated BEL 7B sands 6302' - 6322'. WHP 1503 psi. Gun dry. Discuss plan forward w/OE. Production to flow test well in the morning. Secure well. SDFN. Report Number 17 Report Start Date 5/11/2025 Report End Date 5/12/2025 Last 24hr Summary Complete PTW / PJSM. PT 250 psi / 2500 psi. RIH w/GPT, see FL @ 4530'. PT Fox N2 pump and surface lines to 4000 psi. WHP 60 psi. Online down tubing w/N2 @ 1000 scfm. WHP broke over 2850 psi. Confirm fluid gone w/GPT. Pumped 86k scf N2 (923 gallons). Set 2.10" CIBP @ 6288'. Bleed WHP to 1480 psi. Perforated BEL 7 sands 6257' - 6273'. WHP 5 min 1400 psi. Gun dry. Secure well. RDMO E-line and turn well over to flow to production. _____________________________________________________________________________________ Updated by RPL 06-02-25 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 2 6,288’6,001’N/A CIBP (5/11/25) 3 6,445’6,144’N/A CIBP (5/10/25) 4 6,521’6,214’N/A CIBP (3/16/25) 5 7,615’7,212’N/A CIBP w/ 35’ of cement - TOC @ 7,580’ (6/24/24) 6 8,581’8,094’2.0”Known tight spot- difficult to get long (20’+) tool strings down hole. (2/16/24) 7 9,399’8,867’N/A CIBP (35’ cmt on top) TOC 9,364’ MD (2/16/24) 8 9,929’9,369’N/A CIBP (2/13/24) 9 10,940’10,331’2.441”Float Shoe 10 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 11 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441”Surf 10,943’ PERFORATION DETAIL Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Bel 7 6,257’6,273’5,972'5,987'16'5/11/25 Open Bel 7B 6,302’6,322’6,013'6,032'16'5/10/25 Isolated Bel 9 6,495’6,509’6,189’6,202’14’3/20/25 Isolated Bel 9 6,537’6,551'6,228’6,240’14’9/27/24 Isolated Bel 9 6,557’6,567'6,246'6,255'10'9/26/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'7/17/24 Isolated Bel 9 6,567'6,580'6,255'6,267'13'8/18/24 Isolated Bel 10 6,581’6,593’6,267'6,279'12’9/26/24 Isolated Bel 10 6,642'6,652'6,323'6,332'10'6/28/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/26/24 Isolated Bel 11 6,701'6,715'6,376'6,389'14'6/27/24 Isolated Bel 11 6,720’6,729’6,394'6,402'9’9/26/24 Isolated Bel 11 6,795’6,809’6,462'6,475'14’9/26/24 Isolated BEL B17 7,665'7,675'7,258'7,267'10'2/23/24 Isolated BEL 20 7,885'7,895'7,459'7,469'10'2/23/24 Isolated BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2/22/24 Isolated B26 8,294’8,307’7,830’7,843’13’2/22/24 Isolated B27 8,378’8,389’7,908’7,919’11’2/22/24 Isolated BEL 28 8,513’8,527’8,030’8,043’14’2/20/24 Isolated BEL 28 Lwr 8,560’8,575’8,074’8,088’15 2/20/24 Isolated BEL 28 Lwr 8,575’8,585’8,088’8,096’10’2/19/24 Isolated BEL B31 Lwr 8,821'8,835'8,317'8,330'14'2/19/24 Isolated B31C 8,952 8962’8,263’8,276’10’2/18/24 Isolated B32 9,013 9,033’8,330’8,338’20’2/18/24 Isolated T1XX 9,082’9,096’8,566’8,579’14’2/14/24 Isolated T1X 9,223’9,231’8,699’8,704’8’2/14/24 Isolated T4 9,449’9,462’8,916’8,927’13’2/14/24 Isolated TY T7A 9,744'9,761'9,236'9,252'17'2/13/24 Isolated T8 9,979’9,996’9,416’9,432’17’2/7/24 Isolated TY T18 10,886'10,906'10,222'10,228'20'1/25/24 Isolated T19 10,901’10,921’10,290’10,328’20’1/25/24 Isolated Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/29/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250529 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 5/10/2025 AK E-LINE GPT/CIBP/Perf HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL IRU 241-01 50283201840000 221076 5/7/2025 AK E-LINE Plug/Perf KBU 22-06Y 50133206500000 215044 5/6/2025 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 5/7/2025 AK E-LINE Perf KBU 24-06RD 50133204990100 206013 4/8/2025 YELLOWJACKET GPT-PLUG MPI 1-61 50029225200000 194142 5/10/2025 AK E-LINE Perf MPU E-42 50029236350000 219082 5/3/2025 AK E-LINE Patch MPU S-55 50029238130000 225006 5/13/2025 AK E-LINE CBL OP16-03 50029234420000 211017 4/25/2025 READ LeakDetect PAXTON 13 50133207330000 225021 4/29/2025 YELLOWJACKET SCBL PBU 01-12B 50029202690200 223090 4/8/2025 HALLIBURTON RBT PBU D-08B 50029203720200 225007 3/22/2025 BAKER MRPM PBU H-17B (REVISION)50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG PBU J-25B 50029217410200 224134 3/10/2025 BAKER MRPM PBU K-19C (REVISION)50029225310300 224004 3/27/2025 BAKER MRPM PBU K-19C 50029225310300 224004 3/27/2025 HALLIBURTON RBT SRU 241-33B 50133206960000 221053 3/12/2025 YELLOWJACKET PERF Revision Explanation: Both wells had wrong side stack well name and API#/PTD on previous upload H-17b was marked as H-17A and K-19C was marked as K-19B. Well name now reflets correct sidetrack and has correct SPI# and PTD. T40489 T40490 T40491 T40492 T40492 T40493 T40494 T40495 T40496 T40497 T40498 T40499 T40500 T40501 T40502 T40503 T40503 T40504 BCU 19RD 50133205790100 219188 5/10/2025 AK E-LINE GPT/CIBP/Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.29 14:33:01 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250402 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 3/20/2025 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 3/16/2025 YELLOWJACKET PLUG BRU 212-26 50283201820000 220058 3/21/2025 AK E-LINE Perf BRU 212-26 50283201820000 220058 3/15/2025 AK E-LINE Perf CLU 7 50133205310000 203191 1/22/2025 YELLOWJACKET PLUG IRU 11-06 50283201300000 208184 3/20/2025 AK E-LINE Perf KALOTSA 10 50133207320000 224147 3/1/2025 YELLOWJACKET GPT-PLUG-PERF KBU 22-06Y 50133206500000 215044 1/25/2025 YELLOWJACKET GPT-PLUG-PERF KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP MPE-20A 50029225610100 204054 3/13/2025 READ CaliperSurvey MPI 1-39A 50029218270100 206187 3/4/2025 YELLOWJACKET PERF MPU C-01 50029206630000 181143 1/30/2025 YELLOWJACKET PERF MPU K-17 50029226470000 196028 2/7/2025 AK E-LINE Caliper MPU S-53 50029238110000 224159 3/7/2025 YELLOWJACKET SCBL MRU A-15RD2 50733201050200 202019 3/10/2025 AK E-LINE TubingCut PBU 18-27E 50029223210500 212131 3/15/2025 YELLOWJACKET RCT PBU B-30A 50029215420100 201105 3/7/2025 READ CaliperSurvey PBU S-10A 50029207650100 191123 11/18/2024 YELLOWJACKET CBL-TEMP PBU W-220A 50029234320100 224161 2/22/2025 YELLOWJACKET SCBL Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40256 T40256 T40257 T40257 T40258 T40259 T40260 T40261 T40262 T40263 T40264 T40265 T40266 T40267 T40268 T40269 T40270 T40271 T40272 BCU 19RD 50133205790100 219188 3/20/2025 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 3/16/2025 YELLOWJACKET PLUG Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.02 12:55:27 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,850'6,785' (fill) Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 7,460psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ryan.lemay@hilcorp.com 661-487-0871 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 Ryan Lemay, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 219-188 50-133-20579-01-00 Hilcorp Alaska, LLC Proposed Pools: 6.5# / L-80 TVD Burst 10,943' 10,640psi 2,509' Size 106' 9-5/8"4,488' 2,510' MD See Attached Schematic 5,750psi 3,060psi 3,450psi 106' 4,372' 106' 2,510' March 6, 2025 2-7/8" 12,841' Perforation Depth MD (ft): 4,488' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 19RDCO 237D Same 12,157'5-1/2" ~2,202psi 12,841' See Schematic Length Swell Pkr; N/A 4,295' MD/4,208' TVD; N/A 12,166'7,580'7,180' Beaver Creek Tyonek Gas 20" 13-3/8" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-100 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2025.02.21 17:14:41 -09'00' By Gavin Gluyas at 8:28 am, Feb 24, 2025 SFD 2/25/2025 DSR-2/24/25 Perforate Beluga Gas SFD X 10-404 BJM 2/27/25 CT BOP test to 2500 psi - contingency *&: 2/27/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.27 13:19:18 -09'00' RBDMS JSB 022825 Well Prognosis Well: BCU-19RD Well Name: BCU-19RD API Number: 50-133-20579-01-00 Current Status: Shut In Producing Gas Well Permit to Drill Number: 219-188 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Ryan LeMay (661) 487-0871 Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Max. Expected BHP: 2849 psi @ 6,475’ TVD Based on .44 psi/ft gradient to bottom perf Max. Potential Surface Pressure 2202 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: .71 psi/ft using 13.6 ppg EMW FIT at the intermediate casing shoe Shallowest Allowable Perf TVD: MPSP/(0.71-0.1) = 2202 psi / 0.61 = 3610‘ TVD (no plans to perforate above applicable gas pool) Top of Applicable Gas Pool: 6088’ MD/ 5818’ TVD Well Status: Shut in Gas Producer Brief Well Summary BCU-19RD is an offline gas well drilled in May 2020. Multiple workovers have been completed in attempt to help the well flow due to water loading. In January 2024, A 2-7/8” liner was installed from surface to 10,943’ and cemented in place in attempt to capture rate from the Tyonek formation and allow future production from the Beluga formation. The well was perforated from the bottom up and never established sustained flow following the workover. The Tyonek and Beluga formations were isolated from each other including a 35’ cement cap on top of the CIBP at 9,399’. From June – September, 2024 additional perforations were added in the Beluga 9-11 sands. During this time, there were very brief periods of production spikes as high as ~3MMCFD with rapid production decline and more normalized production rates of 300-600MCFD. In addition, water production from the well increased significantly during this time period. In middle to late December of 2024, production continued to decline with the well ceasing to produce gas in early January 2025. The purpose of this Sundry is to plug and isolate currently open Bel 9-11 perforations and add additional perforations in the UBel – Bel 9 sands. Notes Regarding Current Wellbore Condition: x Production tubing is 2-7/8” 6.5# 8 Rd tubing x Max Inclination: 32deg @ 4393’ x Max DLS: ~6.8 degrees / 100’ at 4782’ MD x 2-7/8” Cement with CBL – TOC @ 5790’ x Recent slickline diagnostic work: o Initial tag at 6,565’ MD with tight spot noted in tubing at 6,533’ MD o Fluid level identified at ~6,505’ MD o Bailed fill down to 6,595’ before starting to lose hole and make no further progress. Last tag was at 6,585’ MD prior to RDMO slickline. BLM Variance Request: - Hilcorp is requesting setting CIBP less than 50’ from the top of current perforation and not dump bailing 35’ cement due to tight proximity of proposed perforations (28’ between current top perforation and proposed bottom perforation). Current open and proposed perforations for this Sundry are within the same Beluga PA. Beluga Gas Pool SFD Well Prognosis Well: BCU-19RD Slickline Procedure: 1. MIRU slickline unit and pressure control equipment 2. PT lubricator 250 psi low / 2500 psi high 3. RIH with full drift gauge ring and verify tag at or below planned plug setting depth of + 6,525’ MD. a. Bail if deemed necessary depending upon initial tag depth b. Record fluid level c. A coil tubing cleanout and / or N2 blowdown may be required dependent upon fill or fluid level observed. Procedural details provided in Contingency Procedure. 4. RDMO slickline unit. E-line Procedure: 5. MIRU E-line and pressure control equipment 6. PT lubricator to 250 psi low / 2,500 psi high 7. Make up 2-7/8” CIBP, RIH and set 2-7/8” CIBP at + 6,525’ MD. a. Do not set tubing plug across a collar b. Tubing tally shows collars at 6,533.22’ and 6,500.58’ MD. 8. Perforate following intervals bottoms up as directed by reservoir team. Well Sand Top MD Btm MD Top TVD Btm TVD Interval BCU-19RD UBEL +6,115 +6,125 ±5,843' ±5,852' ±10' BCU-19RD Bel 6 +6,229 +6,236 ±5,947' ±5953' ±7' BCU-19RD Bel 6 +6,238 +6,247 ±5,955' ±5,963' ±9' BCU-19RD Bel 7 +6,257 +6,273 ±5,972' ±5,987' ±16' BCU-19RD Bel 7B +6,302 +6,322 ±6,013' ±6,032' ±16' BCU-19RD Bel 9 +6,495 +6,509 ±6,189' ±6,202' ±14' a. Correlate using Open Hole Correlation log provided by Geologist. Send correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. b. Use Gamma / CCL to correlate c. Record tubing pressure before and after each perforating run at 5 min, 10 min, and 15 min intervals post shot and record. 9. Turn well over to operations and flow the well. a. Pending well production, all perforation intervals may not be completed on this Sundry. 10. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations a. 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’. b. As necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations. Well Prognosis Well: BCU-19RD Contingency Procedure: Coiled Tubing Cleanout 1. If throughout the job any current or proposed zones produce sand and / or water that cannot be depressed and pushed away with nitrogen, a coil tubing unit may be rigged up to clean out fill or fluid blown down as necessary. a. MIRU Fox CTU, PT BOPE to 250 psi low / 2500 psi high i. Provide AOGCC 24hrs notice of BOP test. b. Cleanout wellbore fill and / or blowdown well with nitrogen as necessary. Attachments: 1. Current Schematic 2. Proposed Schematic 3. CT BOP Schematic 4. Standard Well Procedure – N2 Operations _____________________________________________________________________________________ Updated by DMA 10-17-24 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 1a 7,615’7,212’N/A CIBP w/ 35’ of cement - TOC @ 7,580’ (6/24/24) 2 8,581’8,094’2.0”Known tight spot- difficult to get long (20’+) tool strings down hole. (2/16/24) 3 9,399’8,867’N/A CIBP (35’ cmt on top) TOC 9,364’ MD (2/16/24) 4 9,929’9,369’N/A CIBP (2/13/24) 5 10,940’10,331’2.441”Float Shoe 6 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441”Surf 10,943’ Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Bel 9 6,537’6,551'6,228’6,240’14’9/27/24 Open Bel 9 6,557’6,567'6,246'6,255'10'9/26/24 Open Bel 9 6,567'6,580'6,255'6,267'13'7/17/24 Open Bel 9 6,567'6,580'6,255'6,267'13'8/18/24 Open Bel 10 6,581’6,593’6,267'6,279'12’9/26/24 Open Bel 10 6,642'6,652'6,323'6,332'10'6/28/24 Open Bel 11 6,701'6,715'6,376'6,389'14'6/26/24 Open Bel 11 6,701'6,715'6,376'6,389'14'6/27/24 Open Bel 11 6,720’6,729’6,394'6,402'9’9/26/24 Open Bel 11 6,795’6,809’6,462'6,475'14’9/26/24 Open BEL B17 7,665'7,675'7,258'7,267'10'2/23/24 Isolated BEL 20 7,885'7,895'7,459'7,469'10'2/23/24 Isolated BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2/22/24 Isolated B26 8,294’8,307’7,830’7,843’13’2/22/24 Isolated B27 8,378’8,389’7,908’7,919’11’2/22/24 Isolated BEL 28 8,513’8,527’8,030’8,043’14’2/20/24 Isolated BEL 28 Lwr 8,560’8,575’8,074’8,088’15 2/20/24 Isolated BEL 28 Lwr 8,575’8,585’8,088’8,096’10’2/19/24 Isolated BEL B31 Lwr 8,821'8,835'8,317'8,330'14'2/19/24 Isolated B31C 8,952 8962’8,263’8,276’10’2/18/24 Isolated B32 9,013 9,033’8,330’8,338’20’2/18/24 Isolated T1XX 9,082’9,096’8,566’8,579’14’2/14/24 Isolated T1X 9,223’9,231’8,699’8,704’8’2/14/24 Isolated T4 9,449’9,462’8,916’8,927’13’2/14/24 Isolated TY T7A 9,744'9,761'9,236'9,252'17'2/13/24 Isolated T8 9,979’9,996’9,416’9,432’17’2/7/24 Isolated TY T18 10,886'10,906'10,222'10,228'20'1/25/24 Isolated T19 10,901’10,921’10,290’10,328’20’1/25/24 Isolated _____________________________________________________________________________________ Updated by RPL 02-19-25 SCHEMATIC Proposed Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 2 + 6,525’N/A CIBP (Proposed) 3 7,615’7,212’N/A CIBP w/ 35’ of cement - TOC @ 7,580’ (6/24/24) 4 8,581’8,094’2.0”Known tight spot- difficult to get long (20’+) tool strings down hole. (2/16/24) 5 9,399’8,867’N/A CIBP (35’ cmt on top) TOC 9,364’ MD (2/16/24) 6 9,929’9,369’N/A CIBP (2/13/24) 7 10,940’10,331’2.441”Float Shoe 8 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 9 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441”Surf 10,943’ Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments UBEL +6,115 +6,125 ±5,843'±5,852'±10'Proposed Bel 6 +6,229 +6,236 ±5,947'±5953'±7'Proposed Bel 6 +6,238 +6,247 ±5,955'±5,963'±9'Proposed Bel 7 +6,257 +6,273 ±5,972'±5,987'±16'Proposed Bel 7B +6,302 +6,322 ±6,013'±6,032'±16'Proposed Bel 9 +6,495 +6,509 ±6,189'±6,202'±14'Proposed Bel 9 6,537’6,551'6,228’6,240’14’9/27/24 Isolate Bel 9 6,557’6,567'6,246'6,255'10'9/26/24 Isolate Bel 9 6,567'6,580'6,255'6,267'13'7/17/24 Isolate Bel 9 6,567'6,580'6,255'6,267'13'8/18/24 Isolate Bel 10 6,581’6,593’6,267'6,279'12’9/26/24 Isolate Bel 10 6,642'6,652'6,323'6,332'10'6/28/24 Isolate Bel 11 6,701'6,715'6,376'6,389'14'6/26/24 Isolate Bel 11 6,701'6,715'6,376'6,389'14'6/27/24 Isolate Bel 11 6,720’6,729’6,394'6,402'9’9/26/24 Isolate Bel 11 6,795’6,809’6,462'6,475'14’9/26/24 Isolate BEL B17 7,665'7,675'7,258'7,267'10'2/23/24 Isolated BEL 20 7,885'7,895'7,459'7,469'10'2/23/24 Isolated BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2/22/24 Isolated B26 8,294’8,307’7,830’7,843’13’2/22/24 Isolated B27 8,378’8,389’7,908’7,919’11’2/22/24 Isolated BEL 28 8,513’8,527’8,030’8,043’14’2/20/24 Isolated BEL 28 Lwr 8,560’8,575’8,074’8,088’15 2/20/24 Isolated BEL 28 Lwr 8,575’8,585’8,088’8,096’10’2/19/24 Isolated BEL B31 Lwr 8,821'8,835'8,317'8,330'14'2/19/24 Isolated B31C 8,952 8962’8,263’8,276’10’2/18/24 Isolated B32 9,013 9,033’8,330’8,338’20’2/18/24 Isolated T1XX 9,082’9,096’8,566’8,579’14’2/14/24 Isolated T1X 9,223’9,231’8,699’8,704’8’2/14/24 Isolated T4 9,449’9,462’8,916’8,927’13’2/14/24 Isolated TY T7A 9,744'9,761'9,236'9,252'17'2/13/24 Isolated T8 9,979’9,996’9,416’9,432’17’2/7/24 Isolated TY T18 10,886'10,906'10,222'10,228'20'1/25/24 Isolated T19 10,901’10,921’10,290’10,328’20’1/25/24 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. 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: 12/05/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20241217 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 8/17/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 9/26/2024 YELLOWJACKET PERF-GPT BCU 24 50133206390000 214112 8/19/2024 YELLOWJACKET PERF BCU 25 50133206440000 214132 9/27/2024 YELLOWJACKET PLUG-PERF BLOSSOM 1 50133206480000 215015 9/30/2024 YELLOWJACKET GPT-PLUG-PERF HV B-17 50231200490000 215189 9/23/2024 YELLOWJACKET GPT KU 24-7 50133203520100 205099 10/3/2024 YELLOWJACKET PERF KU 13-06A 50133207160000 223112 12/5/2024 AK E-LINE Plug Setting KU 22-6X 50133205800000 208135 12/8/2024 AK E-LINE Perf KU 23-07A 50133207300000 224126 12/7/2024 AK E-LINE CBL MPU L-17 50029225390000 194169 10/5/2024 YELLOWJACKET PERF MPU R-103 50029237990000 224114 10/14/2024 YELLOWJACKET CBL MPU C-23 50029226430000 196016 11/29/2024 AK E-LINE Plug/cement MPU D-01 50029206640000 181144 11/26/2024 AK E-LINE Perf PBU 13-24B 50029207390200 224087 9/26/2024 YELLOWJACKET CBL PBU 06-07A 50029202990100 224043 9/29/2024 BAKER MRPM PBU 06-18B 50029207670200 223071 10/1/2024 BAKER MRPM PBU 07-32B 50029225250200 204128 10/28/2024 BAKER SPN PBU 14-32B 50029209990200 224073 10/12/2024 BAKER MRPM PBU H-13A 50029205590100 209044 10/23/2024 BAKER SPN PBU L2-20 50029213760000 185134 10/7/2024 BAKER SPN PBU L3-22A 50029216630100 219051 10/9/2024 BAKER PEARL 10 50133207110000 223028 9/25/2024 YELLOWJACKET GPT-PERF PEARL 11 50133207120000 223032 8/29/2024 YELLOWJACKET GPT-PLUG-PERF SRU 241-33 50133206630000 217047 8/23/2024 YELLOWJACKET PERF Please include current contact information if different from above. T39863 T39864 T39865 T39868 T39869 T39870 T39871 T39872 T39873 T39875 T39874 T39867 T39866 T39876 T39877 T39880 T39878 T39879 T39881 T39882 T39883 T39884 T39885 T39886 T39887 BCU 19RD 50133205790100 219188 9/26/2024 YELLOWJACKET PERF-GPT Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.12.18 08:35:44 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2 Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,850 feet See Schematic feet true vertical 12,166 feet 6,785' (fill)feet Effective Depth measured 7,580 feet 4,208 feet true vertical 7,180 feet 4,234 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 10,943' MD 10,333' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 4,208' MD 4,134' TVD N/A, N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: Scott Warner, Operations Engineer 324-246 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf scott.warner@hilcorp.com 240 Size 106' 477 10001021 0 5520 97 9-5/8" 5-1/2" Intermediate 20" 13-3/8" 106' Production Liner 4,488' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-188 50-133-20579-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028083 Beaver Creek / Tyonek Gas Beaver Creek Unit 19RD 12,841' Casing Structural 4,372' 12,157' 4,488' 12,841' 106'Conductor Surface 2,510' TVDMD 907-564-4506 measured Packer Plugs Junk measured Length 3,090psi 7,460psi 3,060psi 3,450psi 5,750psi 10,640psi 2,510' 2,509' Burst Collapse 1,500psi 1,950psi measured true vertical p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.11.01 11:22:33 - 08'00' Noel Nocas (4361) By Grace Christianson at 3:18 pm, Nov 01, 2024 Page 1/2 Well Name: BCU-019RD Report Printed: 10/31/2024WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:6/22/2024 End Date: Report Number 1 Report Start Date 4/19/2024 Report End Date 4/20/2024 Last 24hr Summary Arrive PWL shop, gather tools and equipment Arrive Beaver Creek, permit, PJSM, discuss job scope w/ Mike Arrive on location, spot equipment. Prep well for work RU PT lubricator to 250 psi low, 2500 psi high. Passed RIH w/ 2.25 x 4' DD Bailer w/ spring ball bottom to FL @ 5940' kb, continue to 8581' kb sit down. Pull up tp 8575' for fluid sample. POOH w/ fluid sample. Stand by for Ops to bleed well off. Well @ 65 psi. RIH w/ 2.25 x 4' DD Bailer to 5460' kb (fluid level). POOH RD MOB to BC 16RD Report Number 2 Report Start Date 6/22/2024 Report End Date 6/23/2024 Last 24hr Summary AK E-line and Baker Hughes PTW and PJSM. MIRU, M/U SPN (Spectra Pulse Neutron) tool string, PCE and PT 250 psi/2000 psi. SI well, RIH and experienced tool comm issues and troubleshoot for 4 hours. Remedied problem, located fluid level at 5900' and ran log survey from 8530' to 5700' at 15 fpm. Ran back in hole and repeated log survey (8530'-5700'). Job complete. Secured well and RDMO. Report Number 3 Report Start Date 6/24/2024 Report End Date 6/25/2024 Last 24hr Summary Fox N2 and AK E-line PTW and PJSM. Rig up hard line and PT 250 psi / 4500 psi. SITP-600 psi. Pump N2 at 800 scfm to 3800 psi when pressure broke over and steadily declined. RU E-line and GPT, PT with N2 to 2500 psi. RIH, no fluid detected to 7700'( top of open perfs at 7665'-7675'). M/U 2.10" CIBP and set at 7615'. Dump bail 8.5 gallons (35') cement on plug (2 runs), Est. TOC - 7580'. Top off well with N2 to 2090 psi. Secure well. RDMO Fox and rig back E-line. Report Number 4 Report Start Date 6/26/2024 Report End Date 6/27/2024 Last 24hr Summary AK E-line PTW and PJSM. M/U 2" x 14' perf gun, PT 250 psi / 3000 psi. SITP - 2060 psi. RIH, correlate and perforate the BEL_11 sand (6701'-6715'). (15 min. build -1949 psi - 1975 psi). M/U GPT, RIH, log through perfs and tag PBTD at 7580'. No fluid detected. Begin draw down in 500 psi increments, SI and run GPT passes and monitor 15 min. build between flow backs. Detected LEL on third flowback at 1460 psi, SI well and ran log, no fluid detected. POOH. Secure well, rig back E- line. Turn well over to production. Report Number 5 Report Start Date 6/27/2024 Report End Date 6/28/2024 Last 24hr Summary AK E-line PTW and PJSM. FTP-70 psi/630 mcfd. Rig back on well, M/U GPT w/ fluid sample catcher. RIH, temperature cooling across perfs at 6701'-6715'. Locate fluid level at 7405'. POOH and collect fluid sample. Reduce choke to build well pressure to perforate. FTP - 234 psi / 630 mcfd. RIH with 2" x 14' perf gun and reperf the BEL_11 sand at 6701' - 6715'. Pressure increased 234 psi - 288 psi. Opened choke to 72 psi / 750 mcfd. Secure well and drop 2 soap sticks. Turn well over to production to monitor flow. Report Number 6 Report Start Date 6/28/2024 Report End Date 6/29/2024 Last 24hr Summary AK E-line PTW and PJSM. FTP -71 psi / 654 mcfd. RIH with GPT and locate fluid level at 7220' (open B11 perfs 6701'-6715') tagged PBTD at 7576'. Pinched well flow to 235 mcfd to build pressure, RIH with10' perf gun and perforated the BEL_10 sand 6642'-6652'. Well SI after firing gun and pressure increased from 740 psi to 1700 psi in 30 minutes. Secured well, released E-line and turned well over to production to flow test. Report Number 7 Report Start Date 7/6/2024 Report End Date 7/6/2024 Last 24hr Summary Tag fill @ 7600'kb collect water sample @ 6710'slm flowing survey Report Number 8 Report Start Date 7/17/2024 Report End Date 7/18/2024 Last 24hr Summary PTW/PJSM. MIRU AK E-line. P-test 250/3,000 psi. Perforate BEL 9 from 6,567 6,581. Init SITP: 1709 psi, 15 min SITP: 2064 psi. Flow well to production and monitor. RDMO. Report Number 9 Report Start Date 8/18/2024 Report End Date 8/19/2024 Last 24hr Summary PTW PJSM. MIRU YJOS E-line. T/I/O: 70/300/530 psi. MU 2' and 13' x 2" guns. PT 250/3000 psi. RIH w/ guns. FTP 69 psi. Shoot 2' BEL_9 6575 - 6577'. Monitor 10 mins. FTP 70 psi. Rate increased 80 MCF. FTP 69 psi. Perforate 13' BEL_9 6567 - 6580'. FTP 78 psi. POH. Job complete. ***Perf guns 2" Geo Razor XDP 6 SPF, 60* Phasing, 6.8 gms*** Field: Beaver Creek Sundry #: 324-246 State: Alaska Rig/Service:Permit to Drill (PTD) #:219-188Permit to Drill (PTD) #:208-123 Wellbore API/UWI:50-133-20579-00-00 Page 2/2 Well Name: BCU-019RD Report Printed: 10/31/2024WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 10 Report Start Date 8/23/2024 Report End Date 8/23/2024 Last 24hr Summary Clear a Hydrate Forming at 222' By Droping Methanol and Working downto 2700' RKB before it melted enough to Disapate. Tag fluid see a light foam at 5410' RKB Fall thru to A thicker Fluid at 7190' Make A static Survey Run , then Bring Wellonline and Bleed Pressure from about 1700 to 1200 while Running Survey Report Number 11 Report Start Date 8/24/2024 Report End Date 8/24/2024 Last 24hr Summary Drift and tag at 7337' RKB (12' Higher then Prior Day) Run A flowing Survey Report Number 12 Report Start Date 8/27/2024 Report End Date 8/28/2024 Last 24hr Summary PJSM, Crew travel to location, Pump 16 BBLS Methanol, Spot in & rig up N2 pump, Pressure test 250/5000 psi-good, Pressure up to 2000 psi, Open to well and pump to push N2 away break over @ 2979 psi, Cont. injecting FCP 2367 [psi, Monitor well drop off, Rig down & release Fox N2 Field: Beaver Creek Sundry #: 324-246 State: Alaska Rig/Service: Page 1/1 Well Name: BCU-019RD Report Printed: 10/31/2024WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:9/24/2024 End Date: Report Number 1 Report Start Date 9/26/2024 Report End Date 9/26/2024 Last 24hr Summary PTW/PJSM. MIRU YJ E-line. Well flowing 250 MCFD @ 250 psi. PT lubricator to 250/3000 psi - good test. Pinch back well to 460 psi. Perforate BEL-11 from 6,795'-6,809' and 6,720'-6,729' on switch guns. Open well up to stable flow. Run GPT and find fluid level @ ~6,730' (in between both bottom perf intervals), POOH. Pinch well back to 590 psi. Perforate BEL-10 from 6,581'-6,593' and BEL-9 from 6,557'-6,567' on switch guns. POOH. Turn well back to production, SDFN. Report Number 2 Report Start Date 9/27/2024 Report End Date 9/27/2024 Last 24hr Summary PTW/PJSM. RU YJ E-line. Well flowing 350 MCFD @ 73 psi. RIH w/ 2" 6SPF 60 deg guns on switch, tag fill @ 6,785'. Shut in and pinch well back to 476 psi. Perforate BEL-9 from 6,537'-6,551'. Well built to 1130 psi in 20 min. Decision not to shoot next interval, POOH and bring well on production. RD YJ E-line and secure well. Report Number 3 Report Start Date 9/28/2024 Report End Date 9/28/2024 Last 24hr Summary PTW/PJSM. Flow well and decide to RD YJ E-line and monitor production. RD YJ E-line. Report Number 4 Report Start Date 10/4/2024 Report End Date 10/4/2024 Last 24hr Summary Spot up Equipment and Rig up Slickilne - P/T 250 Low 3000 High. Bail From 6710' RKB to Deepest at 6735' RKB - During Bailing Pressure Started at 100PSI Bailing Was Very Easy but lost a lot of Hole Between Runs That Was Recoverable until breaking about 850 to 900 PSI as of 13:30 wellhead was around 1100 PSI and Sand Appeared hard enough to Break Pins on Flapper Btms - Swapped to Smaller Bailer to Make hole. Rig Down Slickline Clean and Secure area and Install Soap Launcher Field: Beaver Creek Sundry #: 324-246 State: Alaska Rig/Service:Permit to Drill (PTD) #:219-188Permit to Drill (PTD) #:208-123 Wellbore API/UWI:50-133-20579-00-00 _____________________________________________________________________________________ Updated by DMA 10-17-24 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730Surf 106 13-3/8Surface 68 /L-80 J-55 /BTC 12.415Surf 2,510 9-5/8"Intermediate 40 / L-80 / BTC 8.835Surf 4,488 5-1/2"Production 17 / P-110 / CDC-DWC 4.892Surf 12,841 JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,2954,2087.09-5/8 Swell Packer 1a 7,6157,212N/A CIBP w/ 35 of cement - TOC @ 7,580 (6/24/24) 2 8,581 8,094 2.0 Known tight spot- difficult to get long (20+) tool strings down hole. (2/16/24) 3 9,3998,867N/A CIBP (35 cmt on top) TOC 9,364 MD (2/16/24) 4 9,9299,369N/A CIBP (2/13/24) 5 10,94010,3312.441Float Shoe 6 10,95010,340N/A Halliburton EZ Drill Bridge Plug (4 cmt on top) TOC 10,946 MD 7 12,66011,981N/A CIBP (43 cmt on top) TOC 12,617 MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441Surf 10,943 Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Bel 9 6,5376,551'6,2286,240149/27/24 Open Bel 9 6,5576,567'6,246'6,255'10'9/26/24 Open Bel 9 6,567'6,580'6,255'6,267'13'7/17/24 Open Bel 9 6,567'6,580'6,255'6,267'13'8/18/24 Open Bel 10 6,5816,5936,267'6,279'129/26/24 Open Bel 10 6,642'6,652'6,323'6,332'10'6/28/24 Open Bel 11 6,701' 6,715' 6,376' 6,389' 14' 6/26/24 Open Bel 11 6,701' 6,715' 6,376' 6,389' 14' 6/27/24 Open Bel 11 6,720 6,7296,394' 6,402'99/26/24 Open Bel 11 6,795 6,8096,462' 6,475'149/26/24 Open BEL B17 7,665' 7,675' 7,258' 7,267' 10' 2/23/24 Isolated BEL 20 7,885' 7,895' 7,459' 7,469' 10' 2/23/24 Isolated BEL B21 Lwr 7,964' 7,973' 7,531' 7,540' 9' 2/22/24 Isolated B26 8,294 8,307 7,830 7,843 132/22/24 Isolated B27 8,378 8,389 7,908 7,919 112/22/24 Isolated BEL 28 8,513 8,527 8,030 8,043 142/20/24 Isolated BEL 28 Lwr 8,560 8,575 8,074 8,08815 2/20/24 Isolated BEL 28 Lwr 8,575 8,585 8,088 8,096 102/19/24 Isolated BEL B31 Lwr 8,821' 8,835' 8,317' 8,330' 14' 2/19/24 Isolated B31C 8,952 8962 8,263 8,276 102/18/24 Isolated B32 9,013 9,033 8,330 8,338 202/18/24 Isolated T1XX 9,082 9,096 8,566 8,579 142/14/24 Isolated T1X 9,223 9,231 8,699 8,704 82/14/24 Isolated T4 9,449 9,462 8,916 8,927 132/14/24 Isolated TY T7A 9,744' 9,761' 9,236' 9,252' 17' 2/13/24 Isolated T8 9,979 9,996 9,416 9,432 172/7/24 Isolated TY T18 10,886' 10,906' 10,222' 10,228' 20' 1/25/24 Isolated T19 10,901 10,921 10,290 10,328 201/25/24 Isolated 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: 9/27/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240927 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 14B 50133205390200 222057 8/14/2024 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 8/18/2024 YELLOWJACKET PERF BRU 214-13 50283201870000 222117 9/13/2024 AK E-LINE Perf BRU 221-26 50283202010000 224098 9/9/2024 AK E-LINE CBL BRU 222-26 50283201950000 224035 8/20/2024 AK E-LINE Perf BRU 233-23T 50283202000000 224088 9/14/2024 AK E-LINE CBL END 1-61 50029225200000 194142 9/11/2024 READ CaliperSurvey KBU 32-06 50133206580000 216137 8/6/2024 YELLOWJACKET PERF MPU B-24 50029226420000 196009 9/9/2024 READ CaliperSurvey MPU L-03 50029219990000 190007 9/18/2024 READ CaliperSurvey MPU R-103 50029237990000 224114 9/16/2024 AK E-LINE TubingCut MPU R-103 50029237990000 224114 9/19/2024 AK E-LINE TubingCut MRU M-02 50733203890000 187061 9/17/2024 AK E-LINE Plug NCIU A-19 50883201940000 224026 9/20/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/13/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/15/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 8/18/2024 AK E-LINE CBL NCIU A-20 50883201960000 224065 9/11/2024 AK E-LINE PPROF NCIU A-20 50883201960000 224065 8/26/2024 READ MemoryRadialCementBondLog PBU 09-27A 50029212910100 215206 9/13/2024 AK E-LINE CBL/TubingPunch PBU 09-34A 50029213290100 193201 12/31/2023 YELLOWJACKET PL PBU 13-24B 50029207390200 224087 8/21/2024 YELLOWJACKET CBL-PERF PBU 13-24B 50029207390200 224087 8/23/2024 YELLOWJACKET CBL PBU 13-26 50029207460000 182074 8/13/2024 YELLOWJACKET CCL PBU NK-26A 50029224400100 218009 7/20/2024 YELLOWJACKET PPROF Please include current contact information if different from above. T39593 T39594 T39595 T39596 T39597 T39598 T39599 T39600 T39601 T39602 T39603 T39603 T39604 T39605 T39605 T39605 T39605 T39606 T39606 T39607 T39608 T39609 T39609 T39610 T39611 BCU 19RD 50133205790100 219188 8/18/2024 YELLOWJACKET PERF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.27 14:47:28 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 9/12/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240912 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 7/22/2024 BAKER RPM Blossom 1 50133206480000 215015 8/31/2024 READ Coilflag Blossom 1 50133206480000 215015 9/2/2024 READ MemoryRadialCementBondLog KBY 43-07Y 50133206250000 214019 9/9/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 8/29/2024 AK E-LINE Perf NCIU A-19 50883201940000 224026 9/4/2024 AK E-LINE Plug/Perf NCIU A-20 50883201960000 224065 8/29/2024 AK E-LINE Perf NCIU A-20 50883201960000 224065 9/3/2024 AK E-LINE Plug/Perf PBU N-21A (REVISED) 50029213420100 196196 3/28/2024 BAKER SPN PBU N-02 50029200830000 170055 7/25/2024 BAKER SPN PBU S-104 50029229880000 200196 7/7/2024 BAKER SPN PBU Z-68 50029234930000 213093 7/6/2024 BAKER SPN Pearl 11 50133207120000 223032 6/24/2024 BAKER SPN Revision explanation: OmniView .las file was the same as the carbo/oxygen .las file, omniview file has been replaced with the correct file and data. Please include current contact information if different from above. T39545 T39546 T39546 T39547 T39548 T39548 T39549 T39549 T39550 T39551 T39552 T39553 T39554 BCU 19RD 50133205790100 219188 7/22/2024 BAKER RPM Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.09.12 12:52:42 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Scott Warner Cc:Donna Ambruz Subject:RE: BCU-19RD AOGCC 10-403 324-246 PTD 219-188 Approved 05-10-24 Date:Monday, September 9, 2024 3:47:00 PM Scott, Hilcorp has approval to add the additional perfs listed below as part of the approved sundry 324-246. 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: Monday, September 9, 2024 3:21 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: FW: BCU-19RD AOGCC 10-403 324-246 PTD 219-188 Approved 05-10-24 Bryan, This Sundry is still open and we are hoping to add the following perforation table to the Sundry. We have only perforated the BEL 9, BEL 10, and BEL 11 from the original sundry and these additional perforations are to add footage in those same 3 sands. The current schematic is attached. Well Sand Top MD Btm MD Top TVD Btm TVD Interval BCU-19RD Bel 9 ±6,496'±6,509'±6,190'±6,202'±13' BCU-19RD Bel 9 ±6,537'±6,551'±6,228'±6,240'±14' BCU-19RD Bel 9 ±6,557'±6,567'±6,246'±6,255'±10' BCU-19RD Bel 10 ±6,581'±6,593'±6,267'±6,279'±12' BCU-19RD BEL 11 ±6,720'±6,729'±6,394'±6,402'±9' BCU-19RD BEL 11 ±6,795'±6,809'±6,462'±6,475'±14' md tvd Top Beluga Gas pool* 6088 5818 * per Conservation Order CO 237C If you have any questions, please let me know. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: Donna Ambruz <dambruz@hilcorp.com> Sent: Friday, May 10, 2024 10:35 AM To: Scott Warner <Scott.Warner@hilcorp.com> Cc: Noel Nocas <Noel.Nocas@hilcorp.com>; Jacob Flora <Jake.Flora@hilcorp.com> Subject: BCU-19RD AOGCC 10-403 324-246 PTD 219-188 Approved 05-10-24 FYI – Please distribute as necessary. Thank you. Donna Ambruz Operations/Regulatory Tech KEN Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 907.777.8305 - Direct dambruz@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 7/30/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240730 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 14B 50133205390200 222057 5/22/2024 YELLOW JACKET PERF BCU 14B 50133205390200 222057 6/11/2024 YELLOW JACKET GPT-PLUG-PERF BCU 19RD 50133205790100 219188 7/17/2024 AK E-LINE Perf BRU 222-26 50283201950000 224035 7/1/2024 AK E-LINE CBL BRU 222-26 50283201950000 224035 7/11/2024 AK E-LINE PressureTemp CLU 16 50133207200000 224021 5/16/2024 YELLOW JACKET SCBL CLU 16 50133207200000 224021 5/31/2024 YELLOW JACKET SCBL END 2-14 50029216390000 186149 5/9/2024 YELLOW JACKET PLUG KU 33-08 50133207180000 224008 5/9/2024 YELLOW JACKET GPT-PLUG-PERF MPU H-08B 5.00292E+13 201047 7/14/2024 READ CaliperSurvey MPU I-40 50029236890000 220071 7/6/2024 AK E-LINE TubingCut MPU R-101 50029237930000 224078 7/16/2024 YELLOW JACKET SCBL MPU S-17 50029231150000 202173 7/12/2024 AK E-LINE TubingCut MPU S-17 5.00292E+13 202173 7/18/2024 READ CaliperSurvey PBU NK-43 50029229980000 201001 6/11/2024 YELLOW JACKET PL PBU PTM P1-13 50029223720000 193074 7/4/2024 YELLOW JACKET PL Pearl 11 50133207120000 223032 7/10/2024 AK E-LINE Plug/Perf Please include current contact information if different from above. T39310 T39310T T39311T T39312T T39312 T39313 T39313 T39314 T39315 T39316 T39317 T39318 T39319 T39319 T39320 T39321 T39322 BCU 19RD 50133205790100 219188 7/17/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.30 13:09:33 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 7/11/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240711 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 6/28/2024 AK E-LINE Perf BRU 214-13 50283201870000 222117 7/2/2024 AK E-LINE Perf IRU 44-36 50283200890000 193022 6/28/2024 AK E-LINE TubingCut Pearl 11 50133207120000 223032 6/25/2024 AK E-LINE GPT/Plug Pearl 11 50133207120000 223032 7/8/2024 AK E-LINE Perf SRU 13-09 50133203430000 181098 6/9/2024 AK E-LINE CBL/CIBP/PUNCH Revision Explanation: There are additional images added to the final report and a few new .las files. In the Emeraude folder there are 2 new .las files and in the Field Data folder the RIH and POOH are new .las files Please include current contact information if different from above. T39171 T39172 T39173 T39174 T39174 T39175 BCU 19RD 50133205790100 219188 6/28/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.11 13:30:29 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 7/1/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240701 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 6/24/2024 AK E-LINE SetPlug/Cement MPU C-08 50029212770000 185014 6/23/2024 AK E-LINE Leak Point Survey MRU M-34 50733206260000 214027 6/25/2024 AK E-LINE Tubing Punch Revision Explanation: There are additional images added to the final report and a few new .las files. In the Emeraude folder there are 2 new .las files and in the Field Data folder the RIH and POOH are new .las files Please include current contact information if different from above. T39100 T39101 T39102 BCU 19RD 50133205790100 219188 6/24/2024 AK E-LINE SetPlug/Cement Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.07.01 12:56:17 -08'00' 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Friday, February 2, 2024 3:26 PM To:Eli Wilson - (C) Cc:Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: BCU BC-19RD Coil Tubing 10-424 Form, 1/3/24 Attachments:Fox 8 01-03-24 Revised.xlsx Thank you. I’ve added 14:44 to the Ɵme ﬁeld and your remarks. Please update your copy. Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Eli Wilson ‐ (C) <Eli.Wilson@hilcorp.com> Sent: Friday, February 2, 2024 3:21 PM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: RE: [EXTERNAL] RE: BCU BC‐19RD Coil Tubing 10‐424 Form, 1/3/24 24 hr test noƟce sent on 1/2/24 @ 2:44 pm as well as a follow up email the next morning 1/3/24 with no reply from the AOGCC. See attached. Wasn’t sure what to put there. Eli Wilson Wellsite Supervisor Hilcorp Wells Group, GPB Hmy #32 / Cell: 907-342-9840 From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Friday, February 2, 2024 3:14 PM To: Eli Wilson ‐ (C) <Eli.Wilson@hilcorp.com> Subject: [EXTERNAL] RE: BCU BC‐19RD Coil Tubing 10‐424 Form, 1/3/24 You don't often get email from eli.wilson@hilcorp.com. Learn why this is important Beaver Creek Unit 19RDPTD 2191880 2 Eli, The Waived By/Witness ﬁeld was leŌ blank as well as the Time the 24 hour noƟce was given; please advise. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Eli Wilson ‐ (C) <Eli.Wilson@hilcorp.com> Sent: Sunday, January 7, 2024 11:03 AM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov> Subject: BCU BC‐19RD Coil Tubing 10‐424 Form, 1/3/24 All, See aƩached Fox #8 Coiled Tubing BOPE test form for BCU BC‐19RD. Thanks, Eli Wilson Wellsite Supervisor, GPB / CIO / KEN Hilcorp Wells Group Cell: 907-342-9840 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Some people who received this message don't often get email from eli.wilson@hilcorp.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 3 While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:8 DATE:1/3/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2191880 Sundry #323-567 Operation:Drilling:Workover:x Explor.: Test:Initial:x Weekly:Bi-Weekly:Other: Rams:250/3500 Annular:Valves:250/3500 MASP:2695 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0 NA Permit On Location P Hazard Sec.NA Lower Kelly 0 NA Standing Order Posted P Misc.NA Ball Type 0 NA Test Fluid Water Inside BOP 0 NA FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 2 1.75" Hydrolic P Trip Tank NA NA Annular Preventer 0 NA Pit Level Indicators NA NA #1 Rams 1 1.75" Pipe Rams P Flow Indicator NA NA #2 Rams 1 Blind/Shears P Meth Gas Detector NA NA #3 Rams 0 NA H2S Gas Detector NA NA #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA ACCUMULATOR SYSTEM: Choke Ln. Valves 2 2-1/16"FP Time/Pressure Test Result HCR Valves 0 NA System Pressure (psi)2950 P Kill Line Valves 2 2-1/16"P Pressure After Closure (psi)2300 P Check Valve 0 NA 200 psi Attained (sec)4 P BOP Misc 0 NA Full Pressure Attained (sec)18 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):4/1400 P No. Valves 5 P ACC Misc 0 NA Manual Chokes 2 P Hydraulic Chokes 0 NA Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 0 NA #1 Rams 27 P Coiled Tubing Only:#2 Rams 28 P Inside Reel valves 1 P #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:2.5 HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 1/2/24 @ 14:44 Waived By Test Start Date/Time:1/3/2024 13:00 (date)(time)Witness Test Finish Date/Time:1/3/2024 15:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Fox Test fluid: FW. Coil BOPE Test. Tested Combi Pipe/Slips and BS rams to 250 psi low / 3500 psi high as per BLM sundry. AOGCC sundry 3000 psi. Flow cross valve # 3 failed, greased and cycled then passed. 24 hr test notice sent on 1/2/24 @ 2:44 pm as well as a follow up email the next morning 1/3/24 with no reply from the AOGCC. Terrence Rais Hilcorp Eli Wilson BCU 19RD Test Pressure (psi): trais@foxak.com eli.wilson@hilcorp.com Form 10-424 (Revised 08/2022)2024-0103_BOP_Fox8_BCU_19RD         J. Regg; 4/5/2024 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 12,850' N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 7,460psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Swell Pkr; N/A 4,208' MD/4,134' TVD; N/A 12,166' 9,364' 8,833' Beaver Creek Tyonek Gas 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 19RDCO 237D Same 12,157'5-1/2" ~2173psi 12,841' See Schematic Length April 26, 2024 2-7/8" 12,841' Perforation Depth MD (ft): 4,488' See Attached Schematic 5,750psi 3,060psi 3,450psi 106' 4,372' 106' 2,510' Size 106' 9-5/8"4,488' 2,510' MD Hilcorp Alaska, LLC Proposed Pools: 6.5# / L-80 TVD Burst 10,943' 10,640psi 2,509' 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 FEDA028983 219-188 50-133-20579-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Warner, Operations Engineer AOGCC USE ONLY 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: m n P s 66 t 2 c N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 9:39 am, Apr 25, 2024 10-404 BJM 5/9/24 DSR-4/29/24 X SFD 4/25/2024 CT BOP test to 3000 psi FEDA028083 SFD Perforate JLC 5/9/2024 Well Prognosis Well: BCU-19RD Date:4/12/24 Well Name:BCU-19RD API Number:50-133-20579-01-00 Current Status:Shut In Producing Gas Well Permit to Drill Number:219-188 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) Max. Expected BHP:~ 2812 psi @ 6,389 TVD Based on .44 psi/ft gradient to bottom perf Max. Potential Surface Pressure ~ 2173 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient:.71 psi/ft using 13.6 ppg EMW FIT at the intermediate casing shoe Shallowest Allowable Perf TVD:MPSP/(0.71-0.1) = 2173 psi / 0.61 = 3563 TVD Top of Applicable Gas Pool:6088 MD/ 5818 TVD Well Status:Shut in Gas Producer Brief Well Summary BCU-19RD is an offline gas well drilled in May 2020. Multiple workovers have been completed in attempt to help the well flow due to water loading with the most recent workover being completed in January 2024. A 2- 7/8 scab liner was installed from surface to 10,943 in attempt to capture rate from the Tyonek formation and allow future production from the Beluga formation if needed. The well was perforated from the bottom up and never established sustained flow following the workover. The Tyonek and Beluga formations were isolated from each other including a 35 cement cap on top of the CIBP at 9,399. The purpose of this sundry is to isolate existing perforations and perforate additional footage in the Beluga 6 - 11 sands to get the well flowing. Notes Regarding Wellbore Condition Production tubing is 2-7/8 6.5# 8 Rd tubing Max Inclination: 32deg @ 4393 Max DLS: ~6.8 degrees / 100 at 4782 MD Known tight spot with long toolstrings w/ min Id of ~2.0 @ 8581 MD 2-7/8 Cement with CBL TOC @ 5790 CIBP w/35 cement cap @ 9399 Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low / 3,000 psi high 3. RIH with GPT and confirm log interval is fluid packed. Fluid shot on 4/15 showed fluid at 5050 4. Run PNL log per procedure, confirm good data. 5. Rig up N2, depress fluid below 7615. RIH w/GPT to confirm fluid level a. Slickline or coil tubing may be utilized to swab or reverse fluid out of the well if depressing fluid with N2 is unsuccessful b. If CT is utilized, i. MIRU 1.75 coiled tubing ii. PT BOPE to 250 psi low/3,000 psi high iii. RIH and reverse fluid from well with N2 iv. POOH, leaving 2000 psi on the well for perforating v. RDMO CT 6. RIH and set plug at 7615 , equivalent to 3,573' MD SFD Shallowest allowable perf should be based on the top of the deepest perf interval that hasn't been P&A'd per 20 AAC 25.112(c). For this well, it should be based on the top of the T1X @ 8699' TVD, yeilding 4848' TVD shallowest allowable perf. -bjm Top of Applicable Gas Pool:6088 MD/5818 TVD Well Prognosis Well: BCU-19RD Date:4/12/24 7. PU and RIH with 2 perf guns and perforate Beluga 6-11 sands from bottom up: Sand Top MD Btm MD Top TVD Btm TVD Interval Bel 6 ±6,239'±6,248'±5,956'±5,964'±9' Bel 7 ±6,256'±6,272'±5,971'±5,986'±16' Bel 7 ±6,307'±6,323'±6,018'±6,033'±16' Bel 8 ±6,359'±6,371'±6,065'±6,076'±12' Bel 8 ±6,404'±6,409'±6,107'±6,111'±5' Bel 8 ±6,418'±6,425'±6,119'±6,126'±7' Bel 8 ±6,459'±6,465'±6,157'±6,162'±6' Bel 9 ±6,496'±6,509'±6,190'±6,202'±13' Bel 9 ±6,567'±6,580'±6,255'±6,267'±13' Bel 10 ±6,642'±6,652'±6,323'±6,332'±10' Bel 11 ±6,699'±6,715'±6,375'±6,389'±16' a. Proposed perfs are also shown on the proposed schematic in red font b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation c. Use Gamma/CCL to correlate d. Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) e. Pending well production, all perf intervals may not be completed f. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations. Note: All proposed perforations are within the same existing pool/PA. A CIBP will be used instead of a WRP if it is determined that no cement is required for operational purposes. 35 ft of cement will not be placed on each plug as these zones are close together in the same pool. g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 8. RDMO Attachments: 1. Current Schematic 2. Proposed Schematic 3. CT BOP Schematic 4. Standard Well Procedure N2 Operations _____________________________________________________________________________________ Updated by DMA 03-15-24 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730Surf 106 13-3/8Surface 68 /L-80 J-55 /BTC 12.415Surf 2,510 9-5/8"Intermediate 40 / L-80 / BTC 8.835Surf 4,488 5-1/2"Production 17 / P-110 / CDC-DWC 4.892Surf 12,841 JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,2954,2087.09-5/8 Swell Packer 2 8,5818,0942.0Known tight spot- difficult to get long (20+) tool strings down hole. (2/16/24) 3 9,3998,867N/A CIBP (35 cmt on top) TOC 9,364 MD (2/16/24) 4 9,9299,369N/A CIBP (2/13/24) 5 10,94010,3312.441Float Shoe 6 10,95010,340N/A Halliburton EZ Drill Bridge Plug (4 cmt on top) TOC 10,946 MD 7 12,66011,981N/A CIBP (43 cmt on top) TOC 12,617 MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441Surf 10,943 Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments BEL B17 7,665'7,675'7,258'7,267'10'2/23/24 Open BEL 20 7,885'7,895'7,459'7,469'10'2/23/24 Open BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2/22/24 Open B26 8,2948,3077,8307,843132/22/24 Open B27 8,3788,3897,9087,919112/22/24 Open BEL 28 8,5138,5278,0308,043142/20/24 Open BEL 28 Lwr 8,5608,5758,0748,08815 2/20/24 Open BEL 28 Lwr 8,575 8,585 8,088 8,096 102/19/24 Open BEL B31 Lwr 8,821' 8,835' 8,317' 8,330' 14' 2/19/24 Open B31C 8,952 8962 8,263 8,276 102/18/24 Open B32 9,013 9,033 8,330 8,338 202/18/24 Open T1XX 9,082 9,096 8,566 8,579 142/14/24 Open T1X 9,223 9,231 8,699 8,704 82/14/24 Open T4 9,449 9,462 8,916 8,927 132/14/24 Isolated TY T7A 9,744' 9,761' 9,236' 9,252' 17' 2/13/24 Isolated T8 9,979 9,996 9,416 9,432 172/7/24 Isolated TY T18 10,886' 10,906' 10,222' 10,228' 20' 1/25/24 Isolated T19 10,901 10,921 10,290 10,328 201/25/24 Isolated _____________________________________________________________________________________ Updated by SRW 04-12-24 PROPOSED Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730Surf 106 13-3/8Surface 68 /L-80 J-55 /BTC 12.415Surf 2,510 9-5/8"Intermediate 40 / L-80 / BTC 8.835Surf 4,488 5-1/2"Production 17 / P-110 / CDC-DWC 4.892Surf 12,841 JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,2954,2087.09-5/8 Swell Packer 2 7,6157,212N/A CIBP 3 8,5818,0942.0Known tight spot- difficult to get long (20+) tool strings down hole. (2/16/24) 4 9,3998,867N/A CIBP (35 cmt on top) TOC 9,364 MD (2/16/24) 5 9,9299,369N/A CIBP (2/13/24) 6 10,94010,3312.441Float Shoe 7 10,95010,340N/A Halliburton EZ Drill Bridge Plug (4 cmt on top) TOC 10,946 MD 8 12,66011,981N/A CIBP (43 cmt on top) TOC 12,617 MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441Surf 10,943 Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments Bel 6 ±6,239'±6,248'±5,956'±5,964'±9'TBD Future Bel 7 ±6,256'±6,272'±5,971'±5,986'±16'TBD Future Bel 7 ±6,307'±6,323'±6,018'±6,033'±16'TBD Future Bel 8 ±6,359'±6,371'±6,065'±6,076'±12'TBD Future Bel 8 ±6,404'±6,409'±6,107'±6,111'±5'TBD Future Bel 8 ±6,418'±6,425'±6,119'±6,126'±7'TBD Future Bel 8 ±6,459' ±6,465' ±6,157' ±6,162' ±6' TBD Future Bel 9 ±6,496' ±6,509' ±6,190' ±6,202' ±13' TBD Future Bel 9 ±6,567' ±6,580' ±6,255' ±6,267' ±13' TBD Future Bel 10 ±6,642' ±6,652' ±6,323' ±6,332' ±10' TBD Future Bel 11 ±6,699' ±6,715' ±6,375' ±6,389' ±16' TBD Future BEL B17 7,665' 7,675' 7,258' 7,267' 10' 2/23/24 Isolated BEL 20 7,885' 7,895' 7,459' 7,469' 10' 2/23/24 Isolated BEL B21 Lwr 7,964' 7,973' 7,531' 7,540' 9' 2/22/24 Isolated B26 8,294 8,307 7,830 7,843 132/22/24 Isolated B27 8,378 8,389 7,908 7,919 112/22/24 Isolated BEL 28 8,513 8,527 8,030 8,043 142/20/24 Isolated BEL 28 Lwr 8,560 8,575 8,074 8,08815 2/20/24 Isolated BEL 28 Lwr 8,575 8,585 8,088 8,096 102/19/24 Isolated BEL B31 Lwr 8,821' 8,835' 8,317' 8,330' 14' 2/19/24 Isolated B31C 8,952 8962 8,263 8,276 102/18/24 Isolated B32 9,013 9,033 8,330 8,338 202/18/24 Isolated T1XX 9,082 9,096 8,566 8,579 142/14/24 Isolated T1X 9,223 9,231 8,699 8,704 82/14/24 Isolated T4 9,449 9,462 8,916 8,927 132/14/24 Isolated TY T7A 9,744' 9,761' 9,236' 9,252' 17' 2/13/24 Isolated T8 9,979 9,996 9,416 9,432 172/7/24 Isolated TY T18 10,886' 10,906' 10,222' 10,228' 20' 1/25/24 Isolated T19 10,901 10,921 10,290 10,328 201/25/24 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. 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Monday, February 12, 2024 11:23 AM To:Cole Bartlewski Cc:Regg, James B (OGC) Subject:RE: Fox CTU 8 1/21/2024 BOPE test report Attachments:Fox 8 01-21-24 Revised.xlsx Cole, Attached is a revised report changing the report date to 1/21/24 and sundry to 323‐567. Please update your copy Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas ConservaƟon Commission Phone: 907‐793‐1242 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Cole Bartlewski <cbartlewski@hilcorp.com> Sent: Tuesday, January 23, 2024 2:42 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Juanita Lovett <jlovett@hilcorp.com> Subject: Fox CTU 8 1/21/2024 BOPE test report Good afternoon, Attached is the BOPE test report from Fox CTU 8 performed 1/21/2024 on BCU‐019RD. Respectfully, Cole Bartlewski Hilcorp Alaska, LLC Sr. Wellsite Supervisor Email: cbartlewski@hilcorp.com Office 907-283-1301 Cell 907-690-2854 Hilcorp Alaska, LLC A Company built on Energy CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Beaver Creek Unit 19RDPTD 2191880 2 From: Jotform <noreply@jotform.com> Sent: Saturday, January 20, 2024 5:10 PM To: Cole Bartlewski <cbartlewski@hilcorp.com> Subject: [EXTERNAL] AOGCC Inspection Form Confirmation Email This email confirms your request for an inspection with the following information: Type of Test Requested: BOPE Requested Time for Inspection: 01‐21‐2024 6:00 PM Location: Fox Energy CTU‐8, Beaver Creek BCU‐19 Name: Cole Bartlewski E‐mail: cbartlewski@hilcorp.com Phone Number: (907) 690‐2854 Company: Hilcorp Alaska Other Information: If you are not contacted within 12 hours, please notify Jim Regg at 907‐793‐1236. Thank you! Alaska Oil and Gas Conservation Commission The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* Submit to:jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner:Rig No.:8 DATE:1/21/24 Rig Rep.:Rig Email: Operator: Operator Rep.:Op. Rep Email: Well Name:PTD #2191880 Sundry #323-567 Operation:Drilling:Workover:x Explor.: Test:Initial:x Weekly:Bi-Weekly:Other: Rams:250/3500 Annular:Valves:250/3500 MASP:2695 MISC. INSPECTIONS:TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0 NA Permit On Location P Hazard Sec.NA Lower Kelly 0 NA Standing Order Posted NA Misc.NA Ball Type 0 NA Test Fluid Water Inside BOP 0 NA FSV Misc 0 NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75 TOP LOAD P Trip Tank NA NA Annular Preventer 0 N/A NA Pit Level Indicators NA NA #1 Rams 1 1.75" B/S P Flow Indicator NA NA #2 Rams 1 1.75" P/S P Meth Gas Detector NA NA #3 Rams 1 N/A NA H2S Gas Detector NA NA #4 Rams 1 N/A NA MS Misc 0 NA #5 Rams 0 N/A NA #6 Rams 0 N/A NA ACCUMULATOR SYSTEM: Choke Ln. Valves 2 2" FMC P Time/Pressure Test Result HCR Valves 0 N/A NA System Pressure (psi)3000 P Kill Line Valves 0 N/A NA Pressure After Closure (psi)2350 P Check Valve 1 2" flapper P 200 psi Attained (sec)3 P BOP Misc 0 N/A NA Full Pressure Attained (sec)15 P Blind Switch Covers:All stations Yes CHOKE MANIFOLD:Bottle Precharge:NA Quantity Test Result Nitgn. Bottles # & psi (Avg.):NA No. Valves 5 P ACC Misc 0 NA Manual Chokes 2 P Hydraulic Chokes 0 NA Control System Response Time:Time (sec)Test Result CH Misc 0 NA Annular Preventer 0 NA #1 Rams 29 P Coiled Tubing Only:#2 Rams 27 P Inside Reel valves 1 P #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:4.0 HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 1/20/2024@1710 Waived By Test Start Date/Time:1/21/2024 17:00 (date)(time)Witness Test Finish Date/Time:1/21/2024 21:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Landry Lynn Hilcorp Alaska Cole Bartlewski BCU-19RD Test Pressure (psi): Llynn@foxenergy.com cbartlewski@hilcorp.com Form 10-424 (Revised 08/2022)2024-0121_BOP_Fox8_BCU_19RD        jbr J. Regg; 4/5/2024 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/4/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240404 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 2/23/2024 YELLOW JACKET GPT-PERF BRU 241-23 50283201910000 223061 11/25/2023 AK E-LINE Perf HV B-13 50231200320000 207151 3/11/2024 YELLOW JACKET GPT KALOTSA 6 50133206850000 219114 3/2/2024 YELLOW JACKET PERF KU 13-06A 50133207160000 223112 3/13/2024 YELLOW JACKET GPT-PERF KU 21-06RD 50133100900100 201097 3/19/2024 YELLOW JACKET GPT-PERF END MPI 2-62 50029216480000 186158 2/14/2024 YELLOW JACKET PERF MPU G-18 50029231940000 204020 3/21/2024 READ Caliper Survey MPU G-18 50029231940000 204020 3/9/2024 AK E-LINE HoistCutter MPU I-24 50029237780000 224001 3/11/2024 AK E-LINE CBL NCIU A-18 50883201890000 223033 12/20/2023 AK E-LINE Perf NCIU A-18 50883201890000 223033 12/18/2024 AK E-LINE GPT/Plug/Perf PAXTON 3 50133205880000 209168 3/6/2024 YELLOW JACKET GPT PAXTON 3 50133205880000 209168 3/8/2024 YELLOW JACKET PERF PAXTON 3 50133205880000 209168 3/12/2024 AK E-LINE PPROF PAXTON 7 50133206430000 214130 2/26/2024 YELLOW JACKET PERF PBU 09-52 50029236180000 218168 3/24/2024 HALLIBURTON PPROF SD-06 50133205820000 208160 2/20/2024 YELLOW JACKET PERF SRU 222-33 50133207150000 223100 12/19/2023 AK E-LINE Perf Please include current contact information if different from above T38683 T38684 T38685 T38686 T38689 T38687 T38690 T38691 T38691T38692 T38963 T38963 T38694 T38694 T38694 T38695 T38696 T38697 T38698 BCU 19RD 50133205790100 219188 2/23/2024 YELLOW JACKET GPT-PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.04.09 13:48:29 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/20/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240320 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 2/2/2024 AK E-LINE Perf CLU 14 50133206840000 219078 12/11/2023 AK E-LINE Perf IRU 41-01 50283200880000 192109 11/15/2023 AK E-LINE PERF KBU 22-06Y 50133206500000 215044 12/29/2023 AK E-LINE PERF MPU C-14 50029213440000 185088 3/4/2024 AK E-LINE Whipstock MPU L-62 50029236850000 220059 3/3/2024 AK E-LINE TubingPunch NCIU A-17 50883201880000 223031 12/13/2024 AK E-LINE GPT /Plug /Perf Paxton 6 50133207070000 222054 2/27/2024 AK E-LINE Plug/Perf PBU BORE V-109 50029231200000 202202 2/13/2024 AK E-LINE TubingPunch Please include current contact information if different from above. T38657 T38658 T38659 T38660 T38661 T38662 T38663 T38664 T38665 BCU 19RD 50133205790100 219188 2/2/2024 AK E-LINE Perf Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 13:14:02 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/15/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240315 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 12/6/2023 AK E-LINE Cement-JetCut BCU 13 50133205250000 203138 2/11/2024 AK E-LINE CIBP-Perf BCU 19RD 50133205790100 219188 2/20/2024 AK E-LINE Perf-CIBP BRU 232-26 50283200770000 184138 11/26/2023 AK E-LINE GPT-PLUG-PERF BRU 244-27 50283201850000 222038 2/27/2024 AK E-LINE GPT-Perf GP ST 18742 37 (AN- 37) 50733203940000 187109 11/22/2023 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 11/3/2023 AK E-LINE GPT-PERF KBU 42-6 50133205460000 204209 2/16/2024 AK E-LINE Patch PBU L-122 50029231470000 203051 12/7/2023 AK E-LINE Patch NCIU A-12B 50883200320200 223053 12/6/2023 AK E-LINE Perf-GPT NCIU A-17 50883201880000 223031 12/10/2023 AK E-LINE Perf-GPT NCIU B-02 50883200900100 197210 3/9/2024 AK E-LINE GPT-Perf SRU 241-33B 50133206960000 221053 3/6/2024 AK E-LINE GPT-Cmnt-CIBP- Perf Please include current contact information if different from above. T38630 T38630 T38631 T38632 T38633 T38634 T38635 T38636 T38637 T38638 T38639 T38640 T38641 BCU 19RD 50133205790100 219188 2/20/2024 AK E-LINE Perf-CIBP Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.18 08:49:06 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/7/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240307 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 1/9/2024 AK E-LINE GPT-Perf BCU 19RD 50133205790100 219188 1/25/2024 AK E-LINE Perf BCU 13 50133205250000 203138 12/8/2023 AK E-LINE CMT CUT END 2-34 50029216620000 186172 10/29/2023 AK E-LINE PERF KBU 42-6 50133205460000 204209 2/19/2024 AK E-LINE Perf MPU C-13 50029213280000 18567 2/15/2024 AK E-LINE Whipstock Please include current contact information if different from above. T38604 T38604 T38605 T38606 T38607 T38608 BCU 19RD 50133205790100 219188 Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.07 13:13:02 -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: 3/6/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240306 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU-19RD 50133205790100 219188 12/9/2023 AK E-LINE CBL BRU 232-09 50283200750000 184136 10/30/2023 AK E-Line PT/CALIPER MPU B-19A 50029214510100 223123 2/26/2024 HALLIBURTON Jewelry Log MPU I-12 50029230380000 201163 1/30/2024 HALLIBURTON Coilflag MPU J-08A 50029224970100 199117 1/21/2024 HALLIBURTON Coilflag PBU N-11D 50029213750300 223083 2/13/2024 HALLIBURTON RBT Please include current contact information if different from above. T38597 T38598 T38599 T38600 T38601 T38602 BCU-19RD 50133205790100 219188 Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.06 12:00:22 -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:Brooks, Phoebe L (OGC) To:Daniel Scarpella Cc:Regg, James B (OGC) Subject:RE: Corrected Hilcorp Fox CTU #8 11-26-2023 Date:Thursday, January 11, 2024 10:36:16 AM Attachments:Fox 8 11-26-23 Revised.xlsx Thank you. I’ve attached a revised report adding the operation type Workover, changing the MASP to 2695 per sundry #323-567, the floor safety valve test results to “NA” (based on the quantity 0), Rig to reflect Fox 8, and adding back the Full Pressure Attained time of 17 seconds. Please update your copy or let me know if you disagree. Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Daniel Scarpella <Daniel.Scarpella@hilcorp.com> Sent: Thursday, January 11, 2024 10:23 AM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Subject: Corrected Hilcorp Fox CTU #8 11-26-2023 Phoebe, Sorry I took so long to get back to you. I was gone for three weeks over the holiday season. The final pressure after the draw down on the CTU koomy system has been added to the 10-424 I appreciate your support. Thank you, Daniel Scarpella Hilcorp North Slope LLC., Alaska | Sr. Well Site Supervisor | PBU Wells Team 907.230.2692 cell | 907.659.5580 office | H 2154 | alt. Anthony Knowles Well Interventions:daniel.scarpella@hilcorp.com RWO Operations:pbwellsrwowss@hilcorp.com P.O. Box 340067| DP PBOC 34 | PBOC 20| Prudhoe Bay, AK 99734 %HDYHU&UHHN8QLW5' 37' revised report The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu bmitt to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:8 DATE: 11/26/23 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2191880 Sundry #323-567 Operation: Drilling: Workover: x Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:n/a Valves:250/3000 MASP:2695 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NA Permit On Location P Hazard Sec.P Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 0NA Test Fluid Water Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA P Annular Preventer 0NAPit Level Indicators NA P #1 Rams 1 4-1/16' Blind/Shear P Flow Indicator NA P #2 Rams 1 1-3/4" Pipe/Slip P Meth Gas Detector NA P #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 2 2"P Time/Pressure Test Result HCR Valves 0NASystem Pressure (psi)3000 P Kill Line Valves 2 2"P Pressure After Closure (psi)2350 P Check Valve 0NA200 psi Attained (sec)3 P BOP Misc 1PFull Pressure Attained (sec)17 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4/1000 psi P No. Valves 5P ACC Misc 0NA Manual Chokes 2P Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 0 NA #1 Rams 38 P Coiled Tubing Only:#2 Rams 34 P Inside Reel valves 1P #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:1.5 HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 11/25/2023 9:57AM Waived By Test Start Date/Time:11/26/2023 16:05 (date) (time)Witness Test Finish Date/Time:11/26/2023 17:35 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Fox Test w/ freash water. Bottle precharge - 1000 psi. ***Daniel Scarpella sent the 24hr notice and received the system reply at 09:57 11/25/2023, No response from AOGCC field rep... Called Jim Regg, as per automated email instructions, and left a message at 07:36 AM 11/26/2023. No reply*** Jeremy Hart Hilcorp Alaska LLC. Daniel Scarpella Beaver Ck 19RD Test Pressure (psi): jeremyhart76@gmail.com daniel.scarpella@hilcorp.com Form 10-424 (Revised 08/2022)2023-1126_BOP_Fox8_BCU-19RD 9 9 9 999 9 9 9 MEU 9 Workover:x Sundry #323-567 MASP:2695 Fox 8 FLOOR SAFETY VALVES Full Pressure Attained 17(sec) 1 Junke, Kayla M (OGC) From:McLellan, Bryan J (OGC) Sent:Tuesday, December 26, 2023 5:04 PM To:Chad Helgeson Cc:Donna Ambruz; Eli Wilson - (C) Subject:RE: BCU-19RD (PTD# 219-188) Sundry #323-567 MIT-T Chad, Please send us the CBL log. OpƟon A is acceptable. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, December 26, 2023 9:31 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Eli Wilson ‐ (C) <Eli.Wilson@hilcorp.com> Subject: BCU‐19RD (PTD# 219‐188) Sundry #323‐567 MIT‐T Bryan, As we brieﬂy discussed on Friday we have a small leak in our 2‐7/8” tubing we ran inside the 5‐1/2” tubing on BCU‐ 19RD. We are on step 32 to complete the MIT‐T to 3500 psi on the well. As I menƟoned there is a small leak that doesn’t seem to ﬂaƩen out. We have monitored the 2‐7/8” x 5‐1/2” pressure during our aƩempts at an MIT‐T and it does not increase, indicaƟng the leak is below the cement top in the IA and have conﬁrmed there is no leak at surface in any piping we can see. We had Ɵme and leŌ the well pressured up and the tubing pressure dropped below the IA pressure. The leak is less than 10% in 30 min, however it doesn’t even ﬂaƩen out. Would you approve the following steps to meet the tubing test? OpƟon A ‐ IA pressure test above the MASP? This would indicate the tubing above the cement in IA is competent. And meet the requirement to have a monitorable annulus. OpƟon B – Set a retrievable plug ~6000Ō which is below IA cement, and test to 3500 psi. Prefer not to do this opƟon as increases risk to well CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Below are the results of the test (Not bad) Tubing 1pm‐ 3700psi 2:15pm‐ 3576psi I/A 1pm 2500psi 2:15 2465psi Let me know if you have any quesƟons, need more info, or if you are okay with the proposed plan forward. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907‐777‐8405 ‐ O 907‐229‐4824 ‐ C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________BEAVER CK UNIT 19RD JBR 01/17/2024 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:2 2 7/8" test joint used for testing. The HCR choke valve failed to hold dp. The valve was serviced and passed the retest. The second TIW failed. The valve was replaced and tested good. While testing the replacement TIW a test fitting failed on the high. The fitting was replaced and we went right to the high to finish the test. This BOP test should have been to 5000 psi. The company rep was notified after confirmation was given from our office. Jim Regg allowed the 3000 psi test to be completed and not to retest to 5000 psi as long as the company rep and tool pusher were notified so it does not happen in the future. Test Results TEST DATA Rig Rep:K. Reed/B. WhittenOperator:Hilcorp Alaska, LLC Operator Rep:Harold Soule/Ed Hooter Rig Owner/Rig No.:Hilcorp 401 PTD#:2191880 DATE:12/1/2023 Type Operation:WRKOV Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopGDC231129194359 Inspector Guy Cook Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 7 MASP: 2695 Sundry No: 323-567 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 0 NA Lower Kelly 0 NA Ball Type 2 FP Inside BOP 1 P FSV Misc 0 NA 8 PNo. Valves 2 PManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 7 1/16" 5000 P #1 Rams 1 2 7/8" Solid P #2 Rams 1 Blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 1/16" 5000 P HCR Valves 1 2 1/16" 5000 FP Kill Line Valves 3 2 1/16" 5000 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3025 Pressure After Closure P2650 200 PSI Attained P26 Full Pressure Attained P74 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6@ 2100 ACC Misc NA0 NA NATrip Tank P PPit Level Indicators NA NAFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P7 #1 Rams P3 #2 Rams P3 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill NA0 9 99 9999 9 9 9 9 9 MEU TIW failed. HCR choke valve failed FP FP 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:Daniel Scarpella To:Regg, James B (OGC); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (OGC) Subject:Hilcorp Fox CTU #8 BC-13RD BOPE Test Date:Monday, November 27, 2023 12:07:26 PM Attachments:Hilcorp Fox CTU #8 11-26-2023.xlsx Attached is the corrected BOPE test form for FOX CTU services on Beaver Creek well BC-19RD Thank you, Daniel Scarpella Hilcorp North Slope LLC., Alaska | Sr. Well Site Supervisor | PBU Wells Team 907.230.2692 cell | 907.659.5580 office | H 2154 | alt. Anthony Knowles Well Interventions: daniel.scarpella@hilcorp.com RWO Operations: pbwellsrwowss@hilcorp.com P.O. Box 340067| DP PBOC 34 | PBOC 20| Prudhoe Bay, AK 99734 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. %HDYHU&UHHN8QLW5' 37' STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSub m it to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:CTU DATE: 11/26/23 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #22191880 Sundry #323-567 Operation: Drilling: Workover: Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:n/a Valves:250/3000 MASP:2758 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NA Permit On Location P Hazard Sec.P Lower Kelly 0P Standing Order Posted P Misc.NA Ball Type 0P Test Fluid Water Inside BOP 0P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA P Annular Preventer 0NAPit Level Indicators NA P #1 Rams 1 4-1/16' Blind/Shear P Flow Indicator NA P #2 Rams 1 1-3/4" Pipe/Slip P Meth Gas Detector NA P #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 2 2"P Time/Pressure Test Result HCR Valves 0NASystem Pressure (psi)3000 P Kill Line Valves 2 2"P Pressure After Closure (psi)P Check Valve 0NA200 psi Attained (sec)3 P BOP Misc 1PFull Pressure Attained (sec)17 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge: 1000 P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 4/1000 P No. Valves 5P ACC Misc 0NA Manual Chokes 2P Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 0 NA #1 Rams 38 P Coiled Tubing Only:#2 Rams 34 P Inside Reel valves 1P #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:1.5 hrs HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 11/25/2023 9:57AM Waived By Test Start Date/Time:11/26/2023 16:05 (date) (time)Witness Test Finish Date/Time:11/26/2023 17:35 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Fox Test w/ freash water. ***Daniel Scarpella sent the 24hr notice and received the system reply at 09:57 11/25/2023, No response from AOGCC field rep... Called Jim Regg, as per automated email instructions, and left a message at 07:36 AM 11/26/2023. No reply*** Jeremy Hart Hilcorp Alaska LLC. Daniel Scarpella BC-19RD Test Pressure (psi): jeremyhart76@gmail.com daniel.scarpella@hilcorp.com Form 10-424 (Revised 08/2022)2023-1126_BOP_Fox8_BCU-19RD 9 9 9 999 9 9 9 9 MEU 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Re-Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Install Scab Liner 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): 12,850'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 7,460psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Hydraulic retrieveable; N/A 6,097' MD/5,827' TVD; N/A 12,166'10,946'10,336' Beaver Creek Beluga Gas, Tyonek Gas 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 19RDCO 237D Tyonek Gas 12,157'5-1/2" 2,695 psi 12,841' 10950; 12660 Length November 1, 2023 2-7/8" 12,841' Perforation Depth MD (ft): 7,447' See Attached Schematic 5,750psi 3,060psi 3,450psi 106' 7,057' 106' 2,510' Size 106' 9-5/8"7,447' 2,510' MD Hilcorp Alaska, LLC Proposed Pools: 6.5# / L-80 TVD Burst 9,041' 10,640psi 2,509' 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 FEDA028983 219-188 50-133-20579-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t 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 2:49 pm, Oct 17, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.10.17 10:18:11 - 08'00' Noel Nocas (4361) SFD 10/19/2023 X DSR-10/19/23 10-404 BJM 10/20/23 Re-Perforate FEDA028083 SFD BOP tests to 3000 psi *&: Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.10.23 15:08:22 -08'00'10/23/23 RBDMS JSB 102623 Well Prognosis Well: BCU-19RD Date: 10/17/2023 Well Name: BCU-19RD API Number: 50-133-20579-01-00 Current Status: Online Gas Producer Permit to Drill Number: 219-188 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (M) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Max. Expected BHP: 3,485 psi @ 7903’ TVD (Based on Geotap Reading) Max. Anticipated Surface Pressure: 2,695 psi (BHP - 0.1 psi/ft gas gradient to surface) Brief Well Summary BCU-19RD is an online gas well drilled in May 2020. After initial failed attempts to produce from the T-66 and T- 19A, IP was established at nearly 3MMCFD in once the T-19L, T-19U, T-8, T-7B, T-4, T-1X, and T-1XX were perforated. Within five months, however, BC-19RD’s production died due to water loading in the 5-1/2” monobore. Coil installed a 2-7/8” velocity string in October 2020, but could not remove the CIBPs set as part of that work so when the well returned to production in early November, everything below the T-1X was isolated. During the next two months, gas rates never exceeded 500 MCFD. In the latter half of December 2020, the rig was brought over to mill the problematic plugs, re-open the T-4, T-7B, T-8, and T-9, and re-set the 2-7/8” velocity string completion. This work still did not redeem the well; after kickoff with N2, it barely exceeded 60MCFD. In mid-January 2021, the T-1XXX, T-1X, T-4, and T-19 were re-perf’d and new perfs were added while flowing to the T-8, T-19, B-32, and B-31. Once some water was unloaded, flow stabilized around 400MCFD until more Beluga perfs (B-26, B-28, B-30) were added at the end of March 2021. In October of 2021 additional Beluga perfs were added increasing the rate from 500mcf to 1000mcf. In April 2023 additional Beluga zones were shot, but did not add much rate. The well has dropped rate below 500mcf and all flow coming from the Beluga sands. The purpose of this work is to pull the 2-7/8” string and install a cemented scab liner (v-string) all the way to the Tyonek formation and reperforate from the bottom up to get the well unloaded. This well is currently commingled in the Beluga and Tyonek Pools/PAs. After the work the well will be completed as a Tyonek only producer unless the rate does not exceed 1 mmscfd where Beluga sands will be added to get the rate above 1 mmscfd. Notes Regarding Wellbore Condition x Production tubing is 2-7/8” 6.5# 8 Rd tubing x Production casing is 5-1/2” 17# P-110 tubing x Min Id is 2.313 x WL tag on 5/11/23 @ 8230 (PLT Run) x Current Pressures (T/I/O): 10/710/0 x Max Inclination: 32deg @ 4393’ x Max DLS: ~6.8 degrees / 100’ at 4782’ MD x 5-1/2” Cement with CBL – TOC @ 4,024’’ BOP Usage during the project: The rig will be operated with 1 shift per day. The nightly shutdown of the unit will be manned to maintain heat and equipment for efficient operations the following day when temperatures are below freezing. The BOP equipment will be used to shut the well in overnight, with blind rams or pipe in the pipe rams, when circulating fluids & gas after releasing the packer, pressure testing plugs, pumping cement, etc. The BOP components will not be retested after use unless they are; x Purposely used to prevent the uncontrolled flow of fluids from the well, x Specifically mentioned in the procedure to test at certain steps to test s well is currently commingled in the Beluga and Tyonek Pools/ Well Prognosis Well: BCU-19RD Date: 10/17/2023 x They appear to be damaged from the work completed or use of them (eg, stripping pipe through them or closing on tool strings) Pre rig Procedure 1. Review all approved COAs 2. Provide 24hrs notice to AOGCC of BOP test 3. MIRU 1.75” coiled tubing, PT BOPE to 250 Low/3000 Hi 4. RIH with a slick cleanout assembly and clean well out to TD (10930’) using 6% KCl and N2 as necessary 5. Make several washing attempts from 7650-9050 to try and clean behind the 2-7/8” tubing. 6. POOH CT and RDMO well 7. MIRU Eline 8. PT Lubricator to 250/3000 9. RIH with tubing punch and punch tubing just below packer at 6097. (this is to bleed packer gas before tubing is pulled) 10. RDMO Eline 11. MIRU SL 12. PT Lubricator to 250/3000 13. RIH and open sliding sleeve at 6084’ 14. POOH and RD SL RWO Procedure 15. MIRU Hilcorp Service Unit #401 16. Circulate well with a minimum of 130 bbls of 6%KCl brine (~8.4ppg) and ensure well is dead and packer gas is circulated out of the well 17. Set BPV / TWC 18. NU 7” BOP’s and test a. Provide 24 hr notice to AOGCC & BLM b. PT to 250psi low / 2500psi high c. Test with 2-7/8” 19. Pull BPV / TWC 20. Monitor well to ensure its static, fill well as necessary 21. PU on tubing and release packer with 45K overpull (Should release at approximately 85-90K at surface) DO NOT pull more than 80% of tubing strength, approx~116K. Contingency: If packer or tubing doesn’t pull free, plan to RU Eline and cut tubing above packer or in tubing at 7650’. Continue to fish tubing with 2-7/8” PH-6 work string as necessary. 22. POOH with 2-7/8” tubing, Rack back good tubing, laydown all tubing with perf holes a. Depending on results of pulling tubing, a cleanout run may be made with a cleanout assembly 23. MU 2-7/8” liner/scab assembly w/ cement shoe, use centralizers every 3 joints (floating between tubing upsets) 24. RIH with 2-7/8” liner and land at ±10,900’ 25. Cement 2-7/8” liner in place with ~15.3 ppg class G cement with LCM d. Planned TOC ~5500’ in 2-7/8” x 5-1/2” Annulus e. Cement volume of ~82bbls f. Displace cement with 63 bbls of 6% KCl down tubing i. Slow down to 1 bpm@ 60 bbls to prepare to bump plug ii. Bump plug to 500 psi over circ pressure (hold pressure on tubing during rig down of equipment.) Well Prognosis Well: BCU-19RD Date: 10/17/2023 26. Set BPV / TWC 27. ND BOPs, NU Tree, test to 5000psi Completion procedure 28. MIRU E-line and pressure control equipment 29. PT lubricator to 250 low / 3000 high 30. Log CBL of 2-7/8” production liner from PBTD to above TOC 31. RDMO EL 32. MIT-T to 3500psi for 30 minutes (charted) 33. MIRU CT and pressure control equipment 34. PT lubricator to 250 low / 3000 high 35. RIH and reverse fluid from well with N2 36. POOH and Pressure up well with N2 for perforating, approximately 2000 psi Perf procedure 37. MIRU Eline, pressure test lubricator, 250psi low / 3000psi High 38. PU and RIH W/ 2”perf guns and perforate proposed intervals shown below from the bottom up; testing and working Tyonek sands, trying to achieve the initial rate of 3mmscfd originally found on completion Sands MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) BEL B17 ±7,665' ±7,675' ±7,258' ±7,267' ±10' BEL 19 ±7,757’ ±7,781’ ±7,342’ ±7,364’ ±24’ BEL 20 ±7,794’ ±7,804’ ±7,376’ ±7,385’ ±10’ BEL 20 ±7,811’ ±7,829’ ±7,392’ ±7,408’ ±29’ BEL Lwr-Bel ±7,885' ±7,895' ±7,459' ±7,469' ±10' BEL B21 Lwr ±7,964' ±7,973' ±7,531' ±7,540' ±9' BEL 22 ±8,035’ ±8,049’ ±7,596’ ±7,609’ ±14’ BEL 22 ±8,055’ ±8,080’ ±7,614’ ±7,637’ ±25’ BEL B25 Upr ±8,200' ±8,207' ±7,745' ±7,752' ±7' B26 ±8,294’ ±8,307’ ±7,830’ ±7,843’ ±13’ B27 ±8,378’ ±8,389’ ±7,908’ ±7,919’ ±11’ BEL 28 ±8,472’ ±8,482’ ±7,994’ ±8,003’ ±10’ BEL 28 ±8,492’ ±8,500’ ±8,012’ ±8,019’ ±8’ BEL 28 ±8,513’ ±8,526’ ±8,030’ ±8,043’ ±13’ BEL 28 Lwr ±8,561’ ±8,584’ ±8,075’ ±8,096’ ±23’ BEL B31-Lwr ±8,821' ±8,835' ±8,317' ±8,330' ±14' B31C ±8,952 ±8966’ ±8,263 ±8,276’ ±14’ B32 ±9,020 ±9,032’ ±8,330’ ±8,338’ ±12’ T1XX ±9,083’ ±9,097’ ±8,566’ ±8,579’ ±14’ T1X ±9,224’ ±9,229’ ±8,699’ ±8,704’ ±5’ T4 ±9,451’ ±9,462’ ±8,916’ ±8,927’ ±11’ TY T4 ±9,478' ±9,484' ±8,942' ±8,947' ±6' Well Prognosis Well: BCU-19RD Date: 10/17/2023 TY T7 ±9,744' ±9,757' ±9,195' ±9,207' ±13' TY T7A ±9,771' ±9,779' ±9,220' ±9,228' ±8' TY T7A ±9,788' ±9,805' ±9,236' ±9,252' ±17' T8 ±9,979’ ±9,996’ ±9,416’ ±9,432’ ±17’ TY T18 ±10,826' ±10,833' ±10,222' ±10,228' ±7' T19 ±10,898’ ±10,937’ ±10,290’ ±10,328’ ±39’ g. Proposed perfs. also shown on the proposed schematic in red font. h. Correlate using Open Hole Correlation Log provided by Geologist and CCL once it is tied in. Send the correlation pass to the Operations Engineer, Reservoir Engineer (Meredyth Richards), and Geologist (Sarah Frey) for confirmation i. Verify PTs are open to SCADA or Krystal gauge is on well before perforating. Record tubing pressures before and after each perforating run at 0, 5, 10, and 15 min intervals post shot. j. These sands are located in the Tyonek Gas Pool and Beluga Gas Pool per CO 237D. k. If/when the zones are commingled a Production log will be completed annually per CO 237D, and per BLM approved subsurface commingling for BCU-19RD (11/5/2020). 39. Test zones individually. May include PT surveys, flowing well, swabbing fluid off well, etc. 40. RD e-line 41. Turn well over to production 42. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) 43. Complete a flowing survey once the well is online and stable (within 30 days of completing the perfs) to allocate production between Tyonek Gas and Beluga Gas Pools, per CO 237D. Contingencies: I) Coil Tubing & Nitrogen Procedure (Contingency if fill is encountered after perforating, cement stringers after cementing, or fluid won’t push back into formation): 1. MIRU Coiled Tubing, notify AOGCC 24 hours in advance of BOP test, PT BOPE to 3500 psi 2. Clean out to TD 3. Blow down well with nitrogen, trap pressure for perforating, RDMO CTU II) E-line Procedure (Contingency if water is encountered after perforating): 1. MIRU E-Line, PT lubricator to 3000 psi 2. Use N2 to push water into formation, monitoring with GPT 3. RIH and set plug above the perforations OR set patch over the wet perforations Attachments: 1. Current Schematic 2. Proposed Schematic 3. BOP Schematic – Rig 401 Perform MIT _____________________________________________________________________________________ Updated by CAH 05-19-23 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 2 6,084’5,815’2.313”2-7/8” Sliding Sleeve [CLOSED] (Shift Up to Open) 12/23/20 3 6,097’5,827’2.390”2-7/8” x 5-1/2” Retrievable Packer (45K# Shear) 4 6,114’5,842’2.313”2-7/8” X Profile Nipple 5 9,041’8,525’2.441”2-7/8” WLEG 6 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Gun Size Date Comments BEL B17 7,665'7,675'7,258'7,267'10'2-1/8”10/27/21 Open BEL 19 7,757’7,781’7,342’7,364’24’2”4/20/23 Open BEL 20 7,794’7,804’7,376’7,385’10’2”4/20/23 Open BEL 20 7,811’7,829’7,392’7,408’29’2”4/20/23 Open BEL Lwr-Bel 7,885'7,895'7,459'7,469'10'2-1/8”10/27/21 Open BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2-1/8”10/27/21 Open BEL 22 8,035’8,049’7,596’7,609’14’2”4/20/23 Open BEL 22 8,055’8,080’7,614’7,637’25’2”4/20/23 Open BEL B25 Upr 8,200'8,207'7,745'7,752'7'2-1/8”10/27/21 Open B26 8,294’8,307’7,830’7,843’13’2”3/30/21 Open B27 8,378’8,389’7,908’7,919’11’2”3/30/21 Open BEL 28 8,472’8,482’7,994’8,003’10’2”4/19/23 Open BEL 28 8,492’8,500’8,012’8,019’8’2”4/19/23 Open BEL 28 8,513’8,526’8,030’8,043’13’2”3/30/21 Open BEL 28 Lwr 8,561’8,584’8,075’8,096’23 2”4/19/23 Open BEL B31-Lwr 8,821'8,835'8,317'8,330'14'2”10/08/21 Open B31C 8,952 8966’8,263 8,276’14 2”1/14/21 Open B32 9,020 9,032’8,330’8,338’12 2”1/14/21 Open T1XX 9,083’9,093’8,566’8,575’10’2-7/8”5/19/20 Open 9,083’9,097’8,565’8,579’14’2”1/13/21 Open T1X 9,224’9,229’8,699’8,704’5’2-7/8”5/19/20 Open 9,224’9,231’8,669’8,706’7’2”1/13/21 Open T4 9,451’9,462’8,916’8,927’11’2”1/13/21 Open 9,452’9,462’8,916’8,925’10’2-7/8”5/18/20 Open TY T4 9,478'9,484'8,942'8,947'6'2”10/08/21 Open TY T7 9,744'9,757'9,195'9,207'13'2”10/08/21 Open TY T7A 9,771'9,779'8,220'9,228'8'2”10/08/21 Open TY T7A 9,788'9,805'9,236'9,252'17'2”10/08/21 Open T7B 9,850’9,860’9,295’9,304’10’2-7/8”5/18/20 Open T8 9,979’9,994’9,416’9,430’15’2-7/8”5/18/20 Open 9,979’9,996’9,416’9,432’17’2”1/14/21 Open TY T18 10,826'10,833'10,222'10,228'7'2”10/08/21 Open T19 10,898’10,937’10,290’10,328’39’2”1/13/21 Open 10,898’10,937’10,290’10,328’39’2”1/14/21 Open 10,899’10,923’10,293’10,315’24’2-7/8”5/9/20 Open 10,923’10,937’10,315’10,328’14’2-7/8”5/9/20 Open T19A 10,957’10,970’10,347’10,359’23’3-1/8” 4/13/20 Isolated T66 12,683’12,708’12,003’12,027’25’3-1/8” 4/8/20 Isolated TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Velocity 6.5 / L-80 / 8RD EUE 2.44”Surf 9,041’ _____________________________________________________________________________________ Updated by CAH 10-17-23 PROPOSED Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 2 10,940’2.441”Float Shoe 3 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 4 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441”Surf 10,940’ Sand Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Date Comments BEL B17 ±7,665'±7,675'±7,258'±7,267'±10'TBD Future BEL 19 ±7,757’±7,781’±7,342’±7,364’±24’TBD Future BEL 20 ±7,794’±7,804’±7,376’±7,385’±10’TBD Future BEL 20 ±7,811’±7,829’±7,392’±7,408’±29’TBD Future BEL Lwr-Bel ±7,885'±7,895'±7,459'±7,469'±10'TBD Future BEL B21 Lwr ±7,964'±7,973'±7,531'±7,540'±9'TBD Future BEL 22 ±8,035’±8,049’±7,596’±7,609’±14’TBD Future BEL 22 ±8,055’±8,080’±7,614’±7,637’±25’TBD Future BEL B25 Upr ±8,200'±8,207'±7,745'±7,752'±7'TBD Future B26 ±8,294’±8,307’±7,830’±7,843’±13’TBD Future B27 ±8,378’±8,389’±7,908’±7,919’±11’TBD Future BEL 28 ±8,472’±8,482’±7,994’±8,003’±10’TBD Future BEL 28 ±8,492’±8,500’±8,012’±8,019’±8’TBD Future BEL 28 ±8,513’±8,526’±8,030’±8,043’±13’TBD Future BEL 28 Lwr ±8,561’±8,584’±8,075’±8,096’±23’TBD Future BEL B31-Lwr ±8,821'±8,835'±8,317'±8,330'±14'TBD Future B31C ±8,952 ±8966’±8,263 ±8,276’±14’TBD Future B32 ±9,020 ±9,032’±8,330’±8,338’±12’TBD Future T1XX ±9,083’±9,097’±8,566’±8,579’±14’TBD Future T1X ±9,224’±9,229’±8,699’±8,704’±5’TBD Future T4 ±9,451’±9,462’±8,916’±8,927’±11’TBD Future TY T4 ±9,478'±9,484'±8,942'±8,947'±6'TBD Future TY T7 ±9,744'±9,757'±9,195'±9,207'±13'TBD Future TY T7A ±9,771'±9,779'±9,220'±9,228'±8'TBD Future TY T7A ±9,788'±9,805'±9,236'±9,252'±17'TBD Future T8 ±9,979’±9,996’±9,416’±9,432’±17’TBD Future TY T18 ±10,826'±10,833'±10,222'±10,228'±7'TBD Future T19 ±10,898’±10,937’±10,290’±10,328’±39’TBD Future _____________________________________________________________________________________ Updated by CAH 10-17-23 PROPOSED Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size Date Comments BEL B17 7,665' 7,675' 7,258' 7,267' 10' 2-1/8” 10/27/21 Isolated BEL 19 7,757’ 7,781’ 7,342’ 7,364’ 24’ 2” 4/20/23 Isolated BEL 20 7,794’ 7,804’ 7,376’ 7,385’ 10’ 2” 4/20/23 Isolated BEL 20 7,811’ 7,829’ 7,392’ 7,408’ 29’ 2” 4/20/23 Isolated BEL Lwr-Bel 7,885' 7,895' 7,459' 7,469' 10' 2-1/8” 10/27/21 Isolated BEL B21 Lwr 7,964' 7,973' 7,531' 7,540' 9' 2-1/8” 10/27/21 Isolated BEL 22 8,035’ 8,049’ 7,596’ 7,609’ 14’ 2” 4/20/23 Isolated BEL 22 8,055’ 8,080’ 7,614’ 7,637’ 25’ 2” 4/20/23 Isolated BEL B25 Upr 8,200' 8,207' 7,745' 7,752' 7' 2-1/8” 10/27/21 Isolated B26 8,294’ 8,307’ 7,830’ 7,843’ 13’ 2” 3/30/21 Isolated B27 8,378’ 8,389’ 7,908’ 7,919’ 11’ 2” 3/30/21 Isolated BEL 28 8,472’ 8,482’ 7,994’ 8,003’ 10’ 2” 4/19/23 Isolated BEL 28 8,492’ 8,500’ 8,012’ 8,019’ 8’ 2” 4/19/23 Isolated BEL 28 8,513’ 8,526’ 8,030’ 8,043’ 13’ 2” 3/30/21 Isolated BEL 28 Lwr 8,561’ 8,584’ 8,075’ 8,096’ 23 2” 4/19/23 Isolated BEL B31-Lwr 8,821' 8,835' 8,317' 8,330' 14' 2” 10/08/21 Isolated B31C 8,952 8966’ 8,263 8,276’ 14 2” 1/14/21 Isolated B32 9,020 9,032’ 8,330’ 8,338’ 12 2” 1/14/21 Isolated T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 2-7/8” 5/19/20 Isolated 9,083’ 9,097’ 8,565’ 8,579’ 14’ 2” 1/13/21 Isolated T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 2-7/8” 5/19/20 Isolated 9,224’ 9,231’ 8,669’ 8,706’ 7’ 2” 1/13/21 Isolated T4 9,451’ 9,462’ 8,916’ 8,927’ 11’ 2” 1/13/21 Isolated 9,452’ 9,462’ 8,916’ 8,925’ 10’ 2-7/8” 5/18/20 Isolated TY T4 9,478' 9,484' 8,942' 8,947' 6' 2” 10/08/21 Isolated TY T7 9,744' 9,757' 9,195' 9,207' 13' 2” 10/08/21 Isolated TY T7A 9,771' 9,779' 8,220' 9,228' 8' 2” 10/08/21 Isolated TY T7A 9,788' 9,805' 9,236' 9,252' 17' 2” 10/08/21 Isolated T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 2-7/8” 5/18/20 Isolated T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 2-7/8” 5/18/20 Isolated 9,979’ 9,996’ 9,416’ 9,432’ 17’ 2” 1/14/21 Isolated TY T18 10,826' 10,833' 10,222' 10,228' 7' 2” 10/08/21 Isolated T19 10,898’ 10,937’ 10,290’ 10,328’ 39’ 2” 1/13/21 Isolated 10,898’ 10,937’ 10,290’ 10,328’ 39’ 2” 1/14/21 Isolated 10,899’ 10,923’ 10,293’ 10,315’ 24’ 2-7/8” 5/9/20 Isolated 10,923’ 10,937’ 10,315’ 10,328’ 14’ 2-7/8” 5/9/20 Isolated T19A 10,957’ 10,970’ 10,347’ 10,359’ 23’ 3-1/8” 4/13/20 Isolated T66 12,683’ 12,708’ 12,003’ 12,027’ 25’ 3-1/8” 4/8/20 Isolated 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2 Development Exploratory 3. Address:Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: 9399, 9929 Total Depth measured 12,850 feet 10950; 12660 feet true vertical 12,166 feet N/A feet Effective Depth measured 9,364 feet 4,295 feet true vertical 8,833 feet 4,208 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 10,943' MD 10,333' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 4,208' TVD 4,208' TVD N/A, N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Contact Name: Contact Email: Authorized Title:Contact Phone:907-564-4506 measured Packer Plugs Junk measured Length 3,090psi 7,460psi 3,060psi 3,450psi 5,750psi 10,640psi 2,510'2,509' Burst Collapse 1,500psi 1,950psi measured true vertical Production Liner 7,447' 12,841' Casing Structural 7,057' 12,157' 7,447' 12,841' 106'Conductor Surface 2,510' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-188 50-133-20579-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028083 Beaver Creek / Tyonek Gas Beaver Creek Unit 19RD MD 55 Size 106' 11 60752 0 8013 86 9-5/8" 5-1/2" Intermediate 20" 13-3/8" 106' Scott Warner, Operations Engineer 323-567 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 549 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf scott.warner@hilcorp.com p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 1:24 pm, Mar 15, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.03.15 12:52:20 - 08'00' Noel Nocas (4361) DSR-3/15/24 RBDMS JSB 032824 Page 1/10 Well Name: BCU-019RD Report Printed: 3/6/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:11/22/2023 End Date: Report Number 1 Report Start Date 11/26/2023 Report End Date 11/27/2023 Operation Roads & Pads scraping/preping pad for CT operations. Roads wet sheets of ice. Stop and chain up equipment. Arrive on location, complete PTW, conduct PJSM Spot source tank, return tank, choke and run hardline. ND tree cap. PU BOP stack, function test and MU 4-1/16" x 3-1/8" x-over flange. NU BOP stack, rig up 2" iron stack to CT pump. Stack to Choke. Fill BOP stack. Start BOPE testing. End BOPE testing. Secure location, leave well flowing. Continue job tomorrow morning. Report Number 2 Report Start Date 11/27/2023 Report End Date 11/28/2023 Operation Arrive on location, check equipment, PJSM, Permit, Pad Op S/I well at SSV on flow line and close wing 21 turns PU CT injector, 10' lubricator and MU 1.75" CTC, CT injector on well, line up to fill/flush coil w/30 bbls of fresh water. Pop off well and MU BHA , 2" DFCV, 1.75" Mandral By-Pass Bar, 2" JDN. OAL= 8.67'. CT injecotor on well, pressure test 250 psi / 3000 psi. Open Swab 21 turns, RIH w.BHA #1 1.75" CTC, 2" DFCV, 1.75" Mandral By-Pass Bar, 2" JDN. OAL= 8.67'. Wt Ck 2 5000' 18k-lbs/11k-lbs. Tag in 2-7/8" Tbg @ 8278' pickup weight 30k-lbs Park CT 8203'. Bring fluid pump on line and establish circulation WHP 1150 psi. Steady rate @ 1 bpm, Circ P 500. WHP 1150. Crack choke open to return tank. Start bleeding down WHP slowly as fluid is added to wellbore. WHP at zero, CT vol from gooseneck to BHA 17 bbls, Ann Vol 23.3 bbls. Looking for fluid to surface a 40+ bbls. Caught fluid 45 bbls pumped, Circ pressure came up from 600-800 psi. Continue pumping attempting to establish circulation to surface. Should see fluid at surface ~68 bbls pumped. Circ P now at 1583 psi and climbing. Good indication we are lifting fluid to surface. 68 bbls pumped Circ P leveled out, returns to surface. Get visual estmated return rate. ~1 bpm. Start in hole to top of fill @ 8278' slow ROP to 17 fpm. 10% loading Work coil from 8443 to 9041, taking small bites and circ btms up as needed. work through tubing tail at 9041. stop at 9062 and circ btm up 24bbls PUH to 7650 washiing through perfs. celan out to TT @ 9041. make several passes. run out of TT and wrok coil pumping down to 9240 while pumping. circ btms up. RIH from 8801' with pumps off to 9667' and tag hard. Call OE, update on progress. Decission to poke at tag depth to determine next BHA run. On line with pump and attemp to wash down 10'. POOH and prep for reel blow down. 6% KCl freeze temp 27 deg temp expected to drop over night to 26 deg F. 40' from surface blow down CT string. OOH, install night cap, SDFN. Report Number 3 Report Start Date 11/28/2023 Report End Date 11/29/2023 Operation Arrive on location check equipment, PJSM, Permit to work Fill CT with 6% KCL, MU BHA #2, Presure test PCE 250 psi/3000psi RIH w/ 1.75" CTC, 2" DFCV's, 1.75" Mandral By-Pass Bar, 2" JDN Wt Ck @ 5000' 17.5k-lbs/12k-lbs Wt Ck @ 9000' 29k-lbs/17k-lbs Tag fill in 5-1/2" LNR @ 9696' Start clean out at 8 fpm/15% Loading At 10120' solids at 5% in returns increase ROP At 10420' Circ pressure increasing slow ROP Made multiple recips in area between 10615' - 10551' attempting to clean up 7k-10k-lbs over pull each time Call OE discuss situation. TD called at 10615' POOH Mechanically hung up at Tubing Tail. Can move down but not thru. Attempt several times/tricks Call CT Manager to pull max. BHA in Tubing. POOH tight spot on way out at 7330' Start N2 down coil @ 1830' pushing 6% KCL into wellbore. At survace, close swab 21 turns. Start RDMO Job Complete Report Number 4 Report Start Date 11/29/2023 Report End Date 11/30/2023 Operation Coil Crew arrive on location. Compelte RDMO coil equipment. Coil left field. vac truck removed remaining fluids from tanks. RIg 401 Crew Arrive, complete Permits, Safety meeting, start RU of equipment Lay out felt and liner, set base beam & carrier, set Koomey house, gererator, bang board, Dragon heater, pits, pump and choke house,mix pit, hook up circulating hose from pit to pump, Running Electrical , set office trailer PJSM, inspect lines and cables on derrick, Raise and scope up derrick and secure same, stage pallets of KCL by mix pit, organize and staging equipment baskets. Winterize Carrier, hang rig floor & pin back to derrick, rigging up heaters, electric equpment, check motor rotation, service fluid pump, secure liner on berm Report Number 5 Report Start Date 11/30/2023 Report End Date 12/1/2023 Operation R/U e/line w/ 1 9/16 Hole punchloaded 10 shots, P/T Lubricator 250/3000 good, RIH correlate to punch below packer, CCL t/top shot 5.2', pak CCL @ 6101.8', placing shots 6107-6108.5, fire punch, good indication it fired, POOH all shots fired. API: 50-133-20579-01-00 Field: Beaver Creek Sundry #: 323-567 State: Alaska Rig/Service:Permit to Drill (PTD) #:208-123 Page 2/10 Well Name: BCU-019RD Report Printed: 3/6/2024www.peloton.com Well Operations Summary Operation L/D Spent hole punch, P/U loaded 1 9/16" hole punch. RIH Correlate CCL t/6087.6, ccl to top shot 5.4', placing shots 6093-6094.5' fire punch, good indication shots fired, got blown uphole pulled heavy, worked free, R/U circulate hole volume plus til clean, (148 bbls) did get some gas back, bled off to gasbuster. monitor well on slight vac, R/D E-line, set BPV. N/D tree, N/U BOPE, Make up 2-7/ test joint Rig up floor, wind walls, stairs and ladder charge koomey and function test Bope PIck up and land test joint, fluid pack Bope stack and surface equipment Continue to function and purge air from BOPE, install skirting around floor and get heat on stack, perform shell test on Bope to 250 psi and 3000 psi high with water, held on chart for 5 minutes Test Gas & H2S alarms, Test 7-1/16 5m BOPE to Hilcorp and AOGCC specs to 250 low and 3000 psi Hi, test made with water and held on chart, , Guy Cook with AOGCC on location to witness Bope Test, BLM Allie Schoessier waived BOPE test witness Report Number 6 Report Start Date 12/1/2023 Report End Date 12/2/2023 Operation Contuinue test BOPE 250/3000, had Failure on choke HCR, serviced & re-tested good, had failure on lower kelly valve, replaced & tested good. R/D test Eq.Blow down lines, Pull banking sub, monitor well on vac. pull BPV, r/u handling Eq. & landing joint. Back out L/D pins, Pull hanger free @ 45k, continue pulling staging up t/ 114k pulling packer & tail pipe free, pull hanger to floor @ 64k L/D same. R/U circulating eq. pump hole volume plus till clean @ 3.1BPM, 450 psi to gasbuster. shut down POOH stand back 2 7/8", 6.5#, EUE, L-80 tbg, completion. string, lay down 2-7/8 x nipple with RHCP, 2-7/8 x 5-1/2" DHL Retrievable packer assembly,(4) 2-7/8 pup joints, 2-7/8 X profile, sliding sleeve, Rack back total of 118 stands of 2-7/8 tbg. ~ 7,602 ft. Spot and rig up pipe skate & prep to lay down 2-7/8" tbg perforated joints Continue pooh laying down 2-7/8, 6.5#, L-80 perforated joints Report Number 7 Report Start Date 12/2/2023 Report End Date 12/3/2023 Operation Continue POOH from 220' l/D 2 7/8" completion, full recovery. Fill Hole Clear Floor, C/O handling Eq. lay out & strap BHA P/U cleanout BHA,-4 3/4" rollercone bit, bit sub, 6ea. 3 1/8" drill collars, xo, xo= 186.57" Rig down tongs and prep floor to rig up power swivel C/O handling Eq, RIH p/u 2 7/8" PH6 7.9#, P110, wk string. t/ 10,548 DPM, tagging with 4k dn on bit, P/up wt. 98k, S/O wt 54k dn Pick up power swivel, rig up same, break circulation With 14.0 bbls Wash and ream from 10,548 ft. dpm to 10,553 ft. dpm, made connection, attempted to continue to wash, pipe plugged, trouble shooting source of obstruction in circulation system Report Number 8 Report Start Date 12/3/2023 Report End Date 12/4/2023 Operation Continue attempt to clear pipe no joy, POOH t/ 10492', check surface lines good, R/U reverse line, continue rocking pressures until pipe cleared. CBU long way, 2 BPM 1000psi, RIH t/ 10553', Reverse a BU then clean. Wash & ream down f/ 10553' t/10,938 ft. pumping at 2.5 bpm,/ 1,180 psi, reverse each joint clean @ 2.5BPM, 1,180 psi, at 60 rpm, torque a 3k with 0/2 k WOB Attempt to reverse circulate, pipe plug, work plug free, regain circulation down tbg Circulate hole clean with 8.6 ppg 6% KCL in & out of the hole,Shut down pump, attempt to Reverse circulate, hole packed off, Regain circulation down tbg, pick up off bottom had over pull to 120k worked free, pick up to 10,916 dpm, shut down pump Break out and lay down single, break TIW valve and Saver sub off power swivel, lay out power swivel, Pick up single of 2-7/8 ph6, make up TIW and head pin, rig up tongs, rigging up circulate hose Report Number 9 Report Start Date 12/4/2023 Report End Date 12/5/2023 Operation CBU long way, @ 2.5 bpm, 980 psi, R/D circulating Eq. POOH f/10,944' L/D 2 7/8" PH6 wk string, & BHA = 2-7/8 ph 6 X 2-3/8 ph 6 bxp x/over, 2-3/8 ph 6 x 2-3/8 reg BXP x/over, (6) 3-1/8 drill collars, 2-3/8 reg x 2-7/8 reg bit sub, 4-3/4 bit =186' Clear rig floor, change out handling equipment, rig down 'Foster tongs Rig up McCoys tongs Spot pipe skate, rig up same, load with 25 joints 2-7/8 EUE make up 3.75 od Flt collar with mule shoe on 2-7/8 tbg trip in hole pick up singles off pipe rack to 787 ft dpm, installng centralizers every third joint ( floating between tbg connections), continue in hole running tbg out of derrick f/ 787 ft to 1,567' ( depth at rpt time) installing centralizers every third joint( floating between tbg connections Report Number 10 Report Start Date 12/5/2023 Report End Date 12/6/2023 Operation Continue RIH with 2-7/8 liner out of derrick installing Centralizers every 3 rd joint floating between tbg connections,From 1,567 ft to 8140.00 ft. SLM, Filling pipe every 40 joints, last centralizer installed at 5096 ft. API: 50-133-20579-01-00 Field: Beaver Creek Sundry #: 323-567 State: Alaska Rig/Service: Page 3/10 Well Name: BCU-019RD Report Printed: 3/6/2024www.peloton.com Well Operations Summary Operation Continue RIH picking up singles from 8140 to 10,904 ft. make up circ hose and wash down from 10,904 to 10,943 ft. with 4k down, ( had no wash off) pick up 5 ft make pipe for space out up wt 73k down wt 40k, Lay out jt # 341 & 340, pick up and space out, make up pups, x/over , & 7-5/8 hanger with 3-1/2 EUE lift and suspend threads, 3"Type H BPV profile, Land hanger with 40k down wt, Placing Mule shoe at 10,939 ft. Note: BLM inspector Allie Schoessier at 7:51 hrs waived witness of cmt job on the BCU 19 Rd Lay out jt # 341 & 340, pick up and space out, make up pups, x/over , & 7-5/8 hanger with 3-1/2 EUE lift and suspend threads, 3"Type H BPV profile, Land hanger with 40k down wt, Placing Mule shoe at 10,939 ft. Note: BLM inspector Allie Schoessier at 7:51 hrs waived witness of cmt job on the BCU 19 RD Rig down pipe skate, lay down landing joints, Break off x/o and make up cmt head pup, land in hanger with 40k down, up wt 73k down wt 40k , make up cmt head and load plug, spot cement equipment & rig up hoses,Transfer 65 bbls brine to cementers, Rig up cmt equipment Report Number 11 Report Start Date 12/6/2023 Report End Date 12/7/2023 Operation Held PJSM, discussed upcoming cement job and potential hazards Broke circulation down tbg retruns from IA at 3bpm. Pumped away 5bbls. SI and PT lines to 3000psi-good test. Began mixing and pumped 22bbls of 15.3ppg cement at 3bpm/200psi. After 22bbls of cement away had to SD due to losing the mix pump and cement unit. Troubleshot found bad electric solenoid Decision made to circulate out cement then repair cement unit. Began cicrulating out cement at 3 bpm/150psi. Once cement turned the corner pressure built to 750psi. Continued circulating 3bpm at 215 bbls pump away observed returns of 15.3ppg cement at pits. (cal vol 209 bbls). Swapped returns to cutting box and circulated until retruns were 8.5 ppg. SI well. washed up cement unit. Blow down circulaing lines, wait on cement unit. Prep for rig move and housekeeping. Cmt pump arrived spot same and rig up Cmt equipoment Batch up 392 sks cl "G" cmt 86 bbls slurry weitht at 15.3 ppg with 1.24 yld + FCD 2100 + .2% ffl 2320 +.3% FMR Pump 86 bbls of 15.3 ppg cmt at 2.26 bpm at 500 psi Attempt to flush line, cmt line pluged, rig up pump on tbg. Displace cmt at 2.5 bpm final perssure at 2000 psi bumped plug at 59 bbsl displaced , hold 5 minutes, bleed off pressue. floats held ok, pressure up to 2500 psi on tbg, had full returns during cmt job Waiting on cmt. Report Number 12 Report Start Date 12/7/2023 Report End Date 12/8/2023 Operation Washed up and R/d cement eq. Began rolling up hoses and perp equipment for move. Bleed off tbg no flow back (float holding), Set TWC, Cleared and removed work floor. N/d BOP's N/u Tree. Test void 250-5000psi-good test. Continue Rigging down, cleaning pits, stacking up grating, move office Trailer, koomey house, bang board and generator Herd prejob meeting with crews, scope down derrick, & lay over same, move carrier off base beam Removing 'Berm from around liner lower pit roofs and remoe gas buster, winch dragon fire heater, pump and pits off liner, remove mix pit and heaters. Remove foot from carrier, lower landings and fold up walkways, remove choke house and base Beam from, clear liner of snow and fold up, coil up choke and kill hoses in basket, loading and organize trailers going to Swanson first and then trailers going to KGF Weaver Brothers on location hooking onto trailers and loading up carrier moving to next location Report Number 13 Report Start Date 12/9/2023 Report End Date 12/10/2023 Operation Arrive at Beaver Creek. Compelte Safety Meeting & PTW. Spot Equipment, RU, MU Bond Tool and complete surface air calibration. Stab On / MU for PT. Pressure test to 250L/2500H - Good Test. Pipe zero and pipe signal calibrations. RIH to 10,770. Make a repeat pass, complete main pass from 10,770 to 6560'. Complete free pipe pass. Log Complete. POOH, RDMO Report Number 14 Report Start Date 12/28/2023 Report End Date 12/29/2023 Operation Completed MIT-Tubing to 3100 psi. Lost 12psi first 15 min, lost 11 psi the second 15 min. MIT passed first attempt and witnessed by BLM Quinn Sawyer. Report Number 15 Report Start Date 1/2/2024 Report End Date 1/3/2024 Operation Performed MIT-IA to 2963 psi for 30 minutes charted. 15 min pressure = 2946 psi, Lost 17 psi. 30 min pressure = 2936 psi, Lost 10 psi second 15 minutes. MIT-IA passed first attempt. Test showed stabilization. Report Number 16 Report Start Date 1/3/2024 Report End Date 1/4/2024 Operation Complete PJSM & PTW. RDMO Fox CTU and support equipment from BC-13 and move over to BC-19RD. Put MEOH cap on BC-13 w/triplex. Move cement bulk pods to edge of pad. N/U BOPE stack & flow cross on BC-19RD. Empty 400 bbl UR to vac truck. Move 400 bbl UR over to BC-19 and load w/FW from vac truck. Begin BOPE testing 250 psi low / 3500 psi high. BOPE testing completed. 2 FP's. R/D test equipment and triplex. R/D Cruz 75 ton crane. API: 50-133-20579-01-00 Field: Beaver Creek Sundry #: 323-567 State: Alaska Rig/Service: Page 4/10 Well Name: BCU-019RD Report Printed: 3/6/2024www.peloton.com Well Operations Summary Operation Prep to pick up injector in the morning. SDFN. Report Number 17 Report Start Date 1/4/2024 Report End Date 1/5/2024 Operation PJSM & PTW. Review plan forward w/Fox coil crew & YellowJacket. Pick up injector head & risers. M/U CTC & MHA. Stab on well. Fill reel w/35 bbls FW. Unstab from well. M/U CTC & pull test 25k. M/U MHA and PT to 3000 psi. M/U BHA = 2” x .20’ CTC, 1.69” x .93’ DFCV, 1.69” x 4.13’ Bidi Jars, 1.69” x 1.33’ Disco (1/2” seat), 1.69” x 1.30’ Circ Sub (7/16” seat), 1.69” x 11.10’ motor, 2.28” x .64’ Bi-Cone Rock Bit. BHA OAL = 19.63’. Stab on well. Shell test PCE/IRV to 250 psi low / 3500 psi high. RIH w/milling BHA = 2.28" Bi-cone Rock Bit. Depth: 5,700’ ctm, Circ 0 psi, WHP 0, PUW 15k. RIH. PUW 35k @ 10,500’. Start stacking 10,838’, 2k down. PUH and establish milling free spin 1:1 returns. RIH milling. Mill down to 10,925’ ctm. Hard tag. Re-Confirm tag. Pumped bottoms up 30 bbls. Wiper trip to 10,790’, clean PUW 35k. Load & launch 7/16” ball. 23 bbls away, drop rate .5 bpm for ball to seat. Depth 10,920' ctm. Ball seated 30 bbls away. Sheared circ sub. Online down coil w/N2. Calculated volume CTBS + CV to 10,925’ = 59.73 bbls. Starting return strap 121 bbls. Depth: 10,924’ ctm. Circ 3000 psi, WHP 3011 psi. 39 bbls of returns. Continue N2. 58 bbls of returns. Pooh pumping N2. Offline w/N2 pump. Trap 2700 psi on tubing. Unstab from well. B/D BHA, recovered 7/16" ball. Secure well and RDMO Fox CTU. Report Number 18 Report Start Date 1/5/2024 Report End Date 1/6/2024 Operation PJSM & PTW. Review plan forward and perf intervals. R/D P-sub off BC-13 from cement job. Move Eline unit and equipment over to BC-19RD. Spot unit, crane, and PCE trailer on BC-19. MIRU AK Eline with 9/32 cable. Layout lubricator. Tie cable head 4/2 = #3850 100%. Check collars. Check fire good. M/U BHA = CH, GG/CCL, 2" x 20' gun (6 spf, 6.5g). Stab on well and PT PCE to 250 psi low / 3000 psi high. Attempt to RIH, SIBD, Unstab and add more weight bar for WHP. Stab on well and PT. CCL to Top Shot = 12.5', CCL to Bottom Shot = 32.5'. RIH w/Gun Run #1 (2" x 20'). Tagged @ 6,959'. Pulled up #1000 over pull. Make several passes to mak sure no obstruction. Continue RIH. PUW = #2200. Tagged high 10,903' elm @ 100 fpm. Pulled up and instantly stuck from down pass tag. Gun depth 10,883' - 10,903'. Work wire to 80% #3100. No movement. Contact OE. Work wire #2000 - #4000. Pull binds and lock in brake, no movement. Discuss plan forward w/OE. Work wire up incrementally, pulled free #4500, see collars, appear to have toolstring. Pooh w/Gun Run # 1. On surface w/Gun Run # 1. All tools accounted for. Disarm tools ballistically then electrically. Secure well & R/D Eline. SDFN. Report Number 19 Report Start Date 1/6/2024 Report End Date 1/7/2024 Operation Slickline PJSM & PTW. Spot SL unit & equipment. Tie rope socket. Begin rigging up w/.125 wire. RS, 1.75” x 10’ weight bar, OJ, LSS. M/U stuffing box to lubricator. Pick up lubricator, take control of wire. Stab on well w/2.25” x 7’ DD bailer w/mule shoe ball bottom. PT lubricator to 3500 psi. RIH w/2.25” DD bailer, saw bobble 6,975’, made passes. RIH. Work bailer through 8,559’ and 10,730’. Tagged TD 10,951’. Pooh w/tools. OOH w/empty bailer. RIH w/2.30” gauge ring. Tagged 10,960’ slm. Pooh w/tools. RIH w/ 2.21” x 20' dummy guns to 6900' slow down to 150 fpm to 10,960’ slm. PUW #1150 off bottom. Pooh w/tools. Secure well. RDMO Pollard Slickline. Rig down complete, travel to shop. Report Number 20 Report Start Date 1/8/2024 Report End Date 1/9/2024 Operation PJSM, Crew travel to location, Start & warm equipment, Rehead, Build Firing head, Pick up & make up CCL/GR/Gun 1, Thaw out equipment. Pressure test Lube 250 low /3000 high-good. Run in hole wih 2" x 20' gun to tag @ 10,888', 49' high. discuss with town. Unable to pass pull out of hole & pick up 7' x 2" gun, Run in Hole & tag @ 10,888', Call town decsion made to pull up & shoot T18, 10826' - 10833', OG psi: 2539 psi, 7'x2", 6 spf, 60 deg., 6.5 grams, 5-2538,10-2537, 15-2535, Pull out of hole to surface. PIck up 1-11/16" weight bars on CCL/GR & run in hole to tag @ 10,888'. Pull out of hole & layd down tools for the night. Report Number 21 Report Start Date 1/12/2024 Report End Date 1/13/2024 API: 50-133-20579-01-00 Field: Beaver Creek Sundry #: 323-567 State: Alaska Rig/Service: Page 5/10 Well Name: BCU-019RD Report Printed: 3/6/2024www.peloton.com Well Operations Summary Operation PJSM, Spot in & rig up, Pressure test lube 250/3000-good, Open valves run in hole 2.25" GR on Slick line Tag @ 10912' work to 10914', Pull out of hole, No indicators on Gauge ring, Secure well & rig down for the night. Report Number 22 Report Start Date 1/13/2024 Report End Date 1/14/2024 Operation PJSM, Start & warm equipment, PIck up tool & equipment, Stab onto wellhead, Pressure test lube 250/3000-good, Run in hole with 2.25" star bit to tag @ 10921' (10888 eline tag correlation) beat down to 10894' slm (10894' elm equvilant), Tight spot picking up to jar down so jar free & pull out of hole to inspect tool string at surface (no marks), Pick up 2.1" brush & 1.99" Gauge ring, Make up Lube & run in hole @ 10921' (10888 eline tag correlation) beat down to 10894' slm (10894' elm) Spang down 2 times and work string up tight hole & over pull spang free, Pull out of hole to surface, Recovered small chunks cement, magnetic metal, plastic, Make up 2.12" LIB & run in hole, Tag @ 10921 slm-10888 elm, Pull out of hole & evalute, Pick up 2.25" magnet & run in hole tag @ 10921 slm 10888 elm, Pull out of hole, Secure well & rig down equipment. Report Number 23 Report Start Date 1/14/2024 Report End Date 1/15/2024 Operation PJSM, Start & warm equipment, Rig up equipment, Make up magent, Stab onto the wellhead & pressure test 250/3000-good, Run in hole with magnet to tag @ 10921' slm (10888 elm), Pull out of hole & inspect (fines no large pieces), Run in hole same bha, Tag bottom @ 10921' pull out of hole (all fines recovered), Call engineer & descion made to release slick line. secure well & release slick line, Hand over to production. Report Number 24 Report Start Date 1/16/2024 Report End Date 1/17/2024 Operation Report Number 25 Report Start Date 1/21/2024 Report End Date 1/22/2024 Operation PTW, JSA Spot equipment. MIRU FOX CTU 8 with 1.75" coil. RU hardl line and install BOPE on tree. Spot upright tank and diffuser tank. Start BOPE test. Test all rams and valves 250 low 3500 psi high. BOPE test complete. Report Number 26 Report Start Date 1/22/2024 Report End Date 1/23/2024 Operation PTW, JSA with crew. Discuss cold weather operations. -12 F. Fire equipment. Change stripper pack offs. Pick injector head and lubricator. Instal external slip coil connector. Pull test 15K. Re tighten coil connector. Pull test 15K connector failed and fell off. Install back up connector and pull to 25K. Stab on well. CIrculate 27 bbl reel volume. Pop off well. Install remaining tools. CC 2.19" OD , X over 1.98" OD, DFCV 1.68" OD, 1.69" BiDi Jars, TJ hyd. disco 1.68" ( 1/2" ball), Circ sub 1.68" (7/16" ball), 1.69" mudd motor, Bi cone rock bit 2.25" OD. BHA length 27.54'. Stab on well. PT stack 250/3500 psi. Correct depth at coil zero to +4' to get on depth with RKB. RIH. Weight check @ 10,457' 38K up 9 K down. Well bore was empty. Fill well while runing in hole 48 bbls pumped. 1:1 returns to surface. Shut down pump. RIH for dry tag. Tagged clean at 10,930' RKB. Previous coil milling operation on 1/4/24 coil mill depth 10,925' . PIck up heavy 45K to 10,773'. Online down CT to establish milling parameters. 1 bbl/min at 3000 psi. Start milling from 10,930 until stall at 10,944' CTMD. Mill to 10,950' hard stall. PU and re-engage. Stacking weight 3k down not seeing any motor work. Possibly spinning plug? Pick up clean. Back mlling at 10,950 with 300 lbs motor work. Look to be pushing somthing ahead. Run to 10,954.3' Discuss plan forward with ops engineer. Perform wiper trips/back ream through 10,815'-10,940' 4 sets completed. Load and launch 7/16" ball to open circ sub. 38 bbls of 27 bbl reel volume pumped. Did not see ball seat. Launch second ball. Did not see ball seat after 40 bbls pumped. Decision made to POOH to surface and check BHA. POOH to surface. Tagged up. Pop off well. Circ sub was shifted. Rig down BHA. Stab on well. Cool down N2 and come online to blow down at 1000 scf/min. Secure well and Rig back injector head. SDFN. Plan forward. RIH with nozzle and blow well dry. 415 bbls pumped. Report Number 27 Report Start Date 1/23/2024 Report End Date 1/24/2024 Operation PTW, JSA with crew. -20*F. Fire up equipment. PIck injector head and lubricator. Make up nozzle BHA. 2.125" O.D. tools. Coil connector, DFCV, Mandrel bypass tool, Jet swirl nozzle; OAL 8.5'. Stab on well. PT stack 250/3500 psi. RIH. Dry tag 10,954' CTMD. Cool down N2. PT lines 250/3500 psi. Online with 1000 scf/min down coil taking returns up Coil x tubing annuli to open top tank. LIft wellbore fluids from 10,940' CTMD. 3900 psi Circ pressure to start moving fluid to surface. 53 bbls recovered. POOH to surface from 10,940' CTMD. Close choke and build WHP while POOH . Tagged up at surface. 2600 psi of N2 SITP. RIg down Fox CTU 8 and support equipment. Report Number 28 Report Start Date 1/25/2024 Report End Date 1/26/2024 Operation Travel to Beaver Creek office. PJSM & Permit. Travel to location. MIRU AK E-Line. AK E-Line thawing out some frozen surface equipment. (-20 ambient). Triplex to adjoining well for metahanol use. Triplex returned. Attempt PT. Built PSI but found tree flange small leak. Bled off & production tightened flange. PT 250 / 3000 PSI. Good test. RIH w/ 2" x 20' Gun ONE to shoot T-19 zone. Tagged fill higher than what CTU depth left at 10,926'. (E-Line miking wire for maintenance evey 1000' while RIH) Made tie in pass. Sent log to town. Town approved. Position Gun ONE as able from bottom. CCL to TS = 7.5' / CCL to BS = 27.5'. Fired Gun ONE perforating T-19 zone 10,901' to 10,921'. POOH. PSI 2440 to 2435 in 15 minutes. API: 50-133-20579-01-00 Field: Beaver Creek Sundry #: 323-567 State: Alaska Rig/Service: Page 6/10 Well Name: BCU-019RD Report Printed: 3/6/2024www.peloton.com Well Operations Summary Operation OOH. L/D Gun ONE. All shots fired. P/U Gun TWO. Attempt RIH w/ Gun TWO. Sitting down in tree. SI. Bled off. Stab back on. Cycled valves on tree several times. Got through tree. RIH w/ 2" x 20' Gun TWO to shoot T-19 zone 10,886' to 10,906'. CCL to TS = 7.5' / CCL to be at 10,878.5' to place TS at 10,886'. Made tie in pass. Sent log to town. Town approved. Position Gun TWO. Fired Gun TWO. POOH. Start PSI 2342 / 5 Min 2342 / 10 Min 2340 / 15 Min 2336. OOH. L/D Gun TWO. All shots fired. Lay down lubricator. Nite cap & secure well. Turn well over to production to test over night. Report Number 29 Report Start Date 2/5/2024 Report End Date 2/6/2024 Operation Complete PTW & PJSM. Discuss plan forward w/OE. MIRU Ak Eline, spot crane & unit. Lay out riser. Cable head 4/2. 12’ 1-11/16 WB, GPT. CCL to bottom of tool = 7’. PT lubricator to 250 psi low / 3000 psi high w/meoh. RIH w/GPT. Tagged TD 10,926' elm. Logging OOH. FL 10,360' corrected up pass. OOH w/GPT. Check collars and check fire. Remove shooting panel key. M/U 2” x 17’ gun 6 spf. RIH w/Gun Run # 3, 2” x 17’ 6 spf. CCL to top shot = 11.4’. Tagged 8,586’ 4-5 times, little sticky coming off 300# over pull. Discuss plan forward w/OE. Pooh w/gun. OOH w/gun, no sign of fill or definitive marks on bottom or side of gun. M/U 2” x 8’ gun. Get junk basket headed to location. RIH w/2” x 8’ gun. Bobble through 8,586’ and tag TD @ 10,926’ elm. Log correlation pass up. Pull up through tight spot and bobble through #200 - 400 overpull. Discuss plan forward w/OE and gun swell. Decision to let Slickline troubleshoot in the morning. Pooh w/2” gun. OOH w/gun. Secure well & rig down eline. Report Number 30 Report Start Date 2/6/2024 Report End Date 2/7/2024 Operation Complete PTW & PJSM. Discuss plan forward w/OE. MIRU Pollard Slickline w/.125 wire. spot crane & unit. Lay out riser. M/U risers, tie rope socket. Pick up lubricator and tools. Stab on well. PT lubricator 250 psi low / 3000 psi high. RIH w/2.25” x 10’ bailer. Tag 8584’ slm. Work bailer. Run down to 10,000’. Pooh. RIH w/2.28” gauge ring, make passes 8,500’ - 8,600’. Run down to 10,000’. Pooh. RIH w2.35” gauge ring, make passes 8,500’ - 8,600’. Run down to 10,000’. Pooh. RIH w/2.10” x 20’ dummy gun. Sat down 8,584’ and tap through tight spot. Make 20 passes 8500’ - 8600’. If under 150 fpm dummy gun sits down, if over 150 fpm gun slides through. 400# overpull coming up through. Drift to 10,000’ no issues. Pooh. OOH w/Dmy Gun. RDMO Slickline. Move over to BC-13. Report Number 31 Report Start Date 2/7/2024 Report End Date 2/8/2024 Operation Complete PTW & PJSM. MIRU Ak Eline. Spot crane & unit. Lay out riser. Pull tree cap and install P-sub & BOPs. Pick up grease head and lubricator. M/U BHA = 1.38” CH (1-3/8” FN), 1.69” Titan GR / CCL, 1.56” Impact Selector Jars, 1.69” Shock Sub, 2” FH, and 2” x 20’ gun carrier (17’ loaded, 6 spf). BHA OAL = 37’. CCL to top shot = 17.80’. Stab on well, PT Pressure Control Equipment 250 psi / 3000 psi. RIH w/2” x 20’ Gun Run 3 (6spf). PUW 950# at 4000’. Continue RIH. Increase speed to 200 fpm going through restriction 8,584' and traveled through no issues. Make correlation pass 10,200’ up to 9700’. Send logs to Geo / Res. Want +4’ shift. Shift and re-log. Send +4’ logs. Approved by GEO / RES. Log CCL on depth 9,961.2’ + 17.80’ = Top Shot 9,979’, Bottom Shot = 9,996’. Perforate T8 Sands 9,979' - 9,996'. Good indication of shots fired. Pick up instant over pull 1000#, jars fired, moving up hole dragging. Tools shorted. Hanging up every 30' appears collars. Work wire 1000# - 3200# . Continue working BHA up hole. Hang up 9,640’. Work wire 500# - 3500#. No movement. Discuss with OE , Ak Eline Coordinator. Gradually work wire, 3700# weak point. Pulled out of cable head 4000#. Pooh. Increase stripper pressure while pulling to surface. Wire to surface. Shut swab & secure well. Discuss plan forward w/OE. BHA in hole 1-3/8” FN, 37’ OAL. Cable head body 1.45” for overshot. Install tree cap and PT. RDMO Ak Eline. Slickline to come fish Eline toolstring. Report Number 32 Report Start Date 2/9/2024 Report End Date 2/10/2024 Operation Complete PTW & PJSM. MIRU Pollard SL w/.125 wire. Stab on well w/2.25" Lead Impression Block. PT PCE to 250 psi / 3000 psi. RIH w/2.17” LIB. Tagged 9,359’ KB. Hit one lick down and appears tools fell down hole. RIH, tagged 10,702’ KB. Tools fell downhole to 10,888’ KB. Jar down, Pooh. FL @ 9,820’. On surface w/impression of 1-3/8" FN w/frayed wire rolled over. RIH w/2” JDC split skirt. Tagged 10,888’ slm. Jar down, unable to latch FN. Continue jarring down. No latch. Pooh to inspect tools. OOH w/JDC, tool not sheared, marks on edge of skirt. API: 50-133-20579-01-00 Field: Beaver Creek Sundry #: 323-567 State: Alaska Rig/Service: Page 7/10 Well Name: BCU-019RD Report Printed: 3/6/2024www.peloton.com Well Operations Summary Operation RIH w/2.24” blind box, tagged 10,888' KB, jar down. Pooh. OOH w/blind box, wire marks on face of box. RIH w/2" split skirt JUS to 10,888' KB. Jar down, unable to latch. Pooh. OOH w/JUS not sheared. RIH w/2.25" LIB to 10,888' KB. Jar down, Pooh. OOH w/impression of wire strands on edge of block. RIH w/2-7/8" GR w/Bait Sub & 2-prong wire grab to 10,888' KB. No latch, friction bites. Pooh. RIH w/2-7/8" GR w/Bait Sub & center spear to 10,888' KB. No latch, friction bites. Pooh. RIH w/2-7/8" GR w/Bait Sub & Bowen Overshot to 10,888' KB. No latch, friction bites. Pooh. Secure well & SDFN. Pollard to round up more fishing tools: grabs, decentralizer, LIBs, etc. Report Number 33 Report Start Date 2/10/2024 Report End Date 2/11/2024 Operation Complete PTW & PJSM. MIRU Pollard SL w/.125 wire. PT PCE to 250 psi / 3000 psi. RIH w/2-7/8”, bait sub, and modified spangs 2 prong offset w/staggered wire slots. PUW 800#. Latch wire, hit jar lick. Gained 400#. Pooh w/fish. OOH w/37' Eline toolstring, confirmed shots fired. Lay down lubricator & fish. Approximately 4’ of frayed eline cable sticking out of cable head. RIH w/2-7/8” wire finder & 2.25” magnet. Tagged 10,912’ KB. Pooh. OOH w/single armor pieces of wire on magnet. Less than 2”. RDMO Pollard Slickline. Move over to BC-13. Report Number 34 Report Start Date 2/13/2024 Report End Date 2/14/2024 Operation Complete PTW/PJSM Complete RD on well 13 and move unit and equipment to well 19 Pull tree cap and install wireline valves Pick up grease head and lube, PT PCE to 250/3,000psi Open well and RIH with 2-7/8” CIBP, T/I/O=1350/250/400psi. CCL to top of plug = 12.5’ Geo confirms -6.5’ correction RBIH and log from 9970’ to 9916.5’ (plug set depth, collars on depth) Set 2-7/8” CIBP at 9929’ top of plug, Tubing pressure was 1350psi PU clean off plug, RBIH and tag in same spot, POOH tag up at surface, pop off well and lay down plug tools Pickup 17’ of 2” geo rzr perfs 6spf 60 degree phasing and RIH. CCL to TS = 18.5’ bobbled through tight spot at 8,600’ Pulled Tie in pass from 9900-9600’, Geo confirmed tie in RIH to below shooting interval WHP is 1271psi at shot depth, perforate interval 9744’-9761’ Had to work wire after firing guns to get free, WHP is 1276psi At surface lay down guns, rehead cable, secure well with night cap Depart location Report Number 35 Report Start Date 2/14/2024 Report End Date 2/15/2024 Operation Complete PTW/PJSM Pickup 13’ of 2” geo razors perfs 6spf 60 degree phasing and RIH. CCL to TS = 9.33’ Log from 9650’-9290’, confirm 2.5’ correction with geo RIH past shot depth WHP is 1344psi, PUH and perforate 9449’-9462’, PU was clean this time. Start POOH WHP rose to 1347psi after shooting and didn’t increase after 15min. lay down 13’ gun and pick up 8’ gun. CCL to TS = 10.3’ log from 9435’-9100’, Geo confirmed tie-in with -3’ depth shift RIH below perf depth, WHP = 1342psi PUH and perforate 9223’-9231’, PU clean. Start POOH OOH with guns, make up GPT and RIH Fluid level found at 9760’ Lay down GPT tools and pick up 14’x2” perf gun CCL to TS=8.4’ Log 8,900-9,250’, Geo confirmed tie in. RIH below shot depth, WHP = 1335psi PUH and perforate 9082’-9096’, PU clean. Start POOH Secure location for the night and turn well over to ops to flow test Report Number 36 Report Start Date 2/15/2024 Report End Date 2/16/2024 Operation Complete PTW/PJSM API: 50-133-20579-01-00 Field: Beaver Creek Sundry #: 323-567 State: Alaska Rig/Service: Page 8/10 Well Name: BCU-019RD Report Printed: 3/6/2024www.peloton.com Well Operations Summary Operation Make up GPT tools and RIH fluid level found at 9,450’, start POOH Discuss plan forward with OE, decided to set CIBP at 9,399’ and dump bail 35’ of cement on top Lay down GPT tools and make up 2-7/8” CIBP, RIH (CCL to Top of plug =12.5’) Town is evaluating plug set standby until final decision is made. OE wants to proceed with plug set Log from 9550-9107’ confirm tie in with GEO RIH past set depth, PUH and set CIBP at 9,399’, confirm set by tagging (tag record in log). Pull OOH with plug tools Secure well and unit for the night. Send crew to shop to prepare dump bailing tools. Report Number 37 Report Start Date 2/16/2024 Report End Date 2/17/2024 Operation PTW / PJSM WHP 1400psi Make up 2” dump bailer loaded with 2.8 gallons of cement and RIH pop off well, bailer bottom was blown off correctly, MU new bailer bottom and fill bailer with cement 2.8 gallons of cement. Tag plug at 9399’, PU 10’ and dump bail cement (estimated TOC 9387’) Make multiple cycle with bailer to dump cement, then POOH pop off well, bailer bottom was blown off correctly, MU new bailer bottom and fill bailer with cement 2.8 gallons of cement. RIH with second bailer dump second bailer run on top of plug, cycle wire as last time (estimated TOC 9376’) pop off well, bailer bottom looked good, redress bailer and fill with 2.8 gallons of cement. RIH with third bailer dump third bailer run on top of plug, cycle wire as last time (estimated TOC 9,364’) pop off well, bailer bottom looked good, lay down cement tools and pick up 20’ x2” gun RIH with perf gun run #5 2”x20’ 6spf 60 degree phasing Could not make it through tight spot at 8581’ with 20’ gun, POOH to pickup 10’ gun. Lay down 20’ gun and MU 2”x10’ 6spf 60 degree phasing gun. RIH and tagged up at the same spot. Discussed plan forward and decided to RDMO EL and bring SL out tomorrow. Secure well and equipment and depart location. Report Number 38 Report Start Date 2/17/2024 Report End Date 2/18/2024 Operation ON LOCATION - TGSM - JSA - PERMIT RIG UP W/L - PT LUB 250/3000 PSI - GOOD RIH W/ 2.33" GAUGE RING TO 8596'KB SET DOWN - NO SPANGS - TOOLS APPEAR TO BE SETTING DOWN AT STEM NOT GAUGE RING - PICK UP 100' GO BACK DOWN HOLE - MAKE IT THROUGH WITH SMALL BOBBLE AT 150 FPM - CONT IN HOLE TO 9312'KB SET DOWN - POOH - WORK THROUGH TIGHT SPOT 100-200LBS OVER PULL - POOH RIH W/ 2" X 20' DUMMY GUNS (SPENT PERF) TO 8584'KB MAKE SEVERAL ATTEMPTS TO FALL THROUGH AT VARIOUS SPEEDS - WILL NOT BOBBLE THROUGH - SET DOWN WT - (SPANG DOWN) FALL THROUGH PULL BACK UP AND HANG UP AT 8574'KB - MAKE SEVERAL PASSES THROUGH TIGHT SPOTS SPANGING DOWN - CONDITION DOES NOT IMPROVE (400 LBS OVER PULL) RIH W/ 2" X 15' DUMMY GUNS TO 8574'KB SET DOWN - MAKE SEVERAL ATTEMPTS TO PASS AT DIFFERENT SPEEDS UP TO 700 FPM - WILL NOT PASS - SPANG DOWN 5 TIMES TOOLS FALL TO 8584'KB SPANG DOWN 5 TIMES TOOLS FALL - PULL 500LBS OVER TO COME THROUGH RIH W/ 2" X 10' DUMMY GUN TO 8574'KB - SET DOWN - ATTEMPT TO PASS AT DIFFERENT SPEEDS TOOLS BOBBLE THROUGH AT 450 FPM - MAKE SEVERAL PASSES - SAME RESULTS POOH RIH W/ 2"X5' DUMMY GUN W/ 2.21" LIB TO 8574'KB SET DOWN ONE SPANG LICK DOWN - FALL THROUGH - DO NOT TAG - POOH - OOH W/ NO IMPRESSION RDMO SL Unit Report Number 39 Report Start Date 2/18/2024 Report End Date 2/19/2024 Operation Complete PTW/PJSM, rehead cable after damage found from previous attempts to run guns. PT PCE to 250/3000psi MU 1.69”x10’ strip gun 4spf 0 degree phasing and RIH (CCL to TS =3’) Log from 8870-9200’, confirm tie in with GEO, RUH past perf depth. WHP =1439.2psi Pull up to stop depth and perforate interval 9023-9033’ WHP after shooting 1440psi, 5min 1440psi, 10 min 1438psi, 15min 1437psi POOH and lay down spent strip gun, MU 1.69”x10’ strip gun 4spf 0 dgree phasing and RIH (CCL to TS=3’) Log from 9200-8900’, send tie in to GEO for record. RIH past perf depth. WHP=1419psi Pull up to stop depth and perforate interval 9013-9023’ API: 50-133-20579-01-00 Field: Beaver Creek Sundry #: 323-567 State: Alaska Rig/Service: Page 9/10 Well Name: BCU-019RD Report Printed: 3/6/2024www.peloton.com Well Operations Summary Operation WHP after shooting 1418psi, 5min 1416psi, 10min 1415psi, 15min 1414psi. POOH and lay down spent strip gun, MU 1.69”x10’ strip gun 4spf 0 dgree phasing and RIH (CCL to TS=3’) log from 9106’-8750’, send tie into GEO for record. RIH past perf depth. WHP =1407psi Pull up to stop depth and perforate interval 8952’-8962’ WHP after shooting 1409psi, 5min 1408psi, 10min 1407psi, 15 min 1405psi Lay down spent guns and secure location for the night. Report Number 40 Report Start Date 2/19/2024 Report End Date 2/20/2024 Operation Complete PTW/PJSM Make up 1.69"x10' strip gun 4spf 0 degree phasing and RIH Log from 9000'-8650', correlate per GEO approved previous tie-in, WHP = 1457psi RBIH past shot depth, pull up to shot depth and perforate interval 8825-8835' WHP after shooting 1459psi, 5min 1459psi, 10min 1456psi, 15min 1454psi Lay down spent guns, found jars shorted change jars, and MU 1.69"x10' strip gun 4spf 0 degree phasing and RIH (CCL to TS=3') Log from 8946-8200', correlate per GEO approved tie-in, RIH past perf depth. WHP=1453psi RBIH past shot depth, pull up to stop depth and perforate interval 8821-8831' Lay down spent guns and make up 1.69"x10' strip gun 4spf 0 degree phasing and RIH Log from 8710-8340 , correlate per GEO approved tie-in, RIH past perf depth. WHP 1457psi RBIH past shot depth, PUH to stop depth and attempt to fire guns but had no surface indications that guns fired. Start POOH with live guns. Pop off well with live guns, could not find issue with guns or tool string, remove knuckle and jars and MU new 1.69"x10' strip gun. (CCL to TS 3') Having issues keeping a grease seal. Pull to surface while we troubleshoot issue. Grease issues resolved RBIH with guns. Log from 8720-8400', correlate per geo approved tie-in log, RIH past perf depth. WHP 1367psi PUH to stop depth and perforate 8575-8585' WHP after shooting 1370psi, 5min 1370, 10min 1372 15min1374 Lay down spent guns, secure well and location for the night Report Number 41 Report Start Date 2/20/2024 Report End Date 2/21/2024 Operation Complete PTW/PJSM Make up 1.69"x10' strip gun 4spf 0 degree phasing and RIH Log from 8720-8450', correlate per geo approved tie-in, RIH past perf depth. WHP =1463psi Pull up to stop depth and perforate 8560-8570' WHP after shooting 1462psi, 5min 1462psi, 10min 1460psi, 1458psi Lay down spent gun, PU 1.69"x10' strip gun and RIH. Log from 8740-8408', correlate per geo approved tie-in, RIH past perf depth. WHP=1437psi PUH to stop depth and perforate 8565-8575 WHP after shooting 1438psi, 5min POOH and lay down spent strip gun, Make up 2"x14' 6spf 60 degree phasing and RIH. (CCL to TS = 2.7') Log from 8546'- 8353', correlate per geo approved tie-in log, RIH past perf depth. WHP =1430psi PUH to stop depth and perforated interval 8513-8527' WHP after shooting 1430psi, 5min 1427psi, 10min 1425psi, POOH and lay down spent perf gun. RDMO EL unit and turn well over to ops for flow test. Report Number 42 Report Start Date 2/22/2024 Report End Date 2/23/2024 Operation PJSM, Crew travel to location, Spot in & rig up, Pick up lube & gun run #1, Pressure test 250/3000-good. Run in hole with Run #1, (B 27 & B26), Run in hole & correlate, Send in pass (shift up 2') CCL-TS=24', (B27 8378-8389 (11'), OG psi: 609, 5 min-609, 10 min-610, Pull up hole to Shoot 2nd gun, (B26 8294-8307 (13')) , OG psi: 609, 5 min-609, 10 min-610, Pull out of hole & lay down run #1. (2', 6.8 gr, 60 degree, 6 spf) Run in hole with Run #2, ( BEL B 21 LWR, BEL LWR, BEL 17), Run in hole & correlate, CCL-TS=31', (BEL B 21 7964-7973 (9'), OG psi: 624, 5 min-624, 10 min- 625, Pull up hole to shoot,, (BEL LWR 7885-7895 (did not fire)Pull up hole to Shoot 3rd gun, (BEL LWR 7885-7895 (did not fire), Pull out of hole & lay down run #2. Guns 2 & 3 Misfired due to flooding. (2', 6.8 gr, 60 degree, 6 spf) Secure well & lay down tool string, Rig down & release Yellowacket. Report Number 43 Report Start Date 2/23/2024 Report End Date 2/24/2024 API: 50-133-20579-01-00 Field: Beaver Creek Sundry #: 323-567 State: Alaska Rig/Service: Page 10/10 Well Name: BCU-019RD Report Printed: 3/6/2024www.peloton.com Well Operations Summary Operation PJSM, Crew travel to location, Spot in & rig up, Pick up lube & CCL/GR/GPT, Pressure test 250/3000-good. Run in the hole to find fluid @ 5150', Log for tag to 8500' (no tag), Pull out of hole, Pick up sample catcher run in hole and catch sample. Pull out of hole & lay down lube. Spot in & rig up N2 unit, Pressure test 5000 psi-good, Load hole with N2 see break over @ 4100 psi, Maintains 4100 psi with 1400 scfs a min. Run in hole with GPT (No fluid to 8530'), Pull out of hole & lay down GPT. Pick up Run #3 BEL LWR & BEL B17, Run in hole & correlate to RA @ 7417.5', On depth, Pull into BEL LWR (7885-7895 (10'), OG PSI: 1800 psi, Pull up hole to BEL B 17 (7665-7675 (10'), Pull out of hole, Secure well. (2', 6.8 gr, 60 degree, 6 spf) Rig down & release Yellowjacket Eline API: 50-133-20579-01-00 Field: Beaver Creek Sundry #: 323-567 State: Alaska Rig/Service: _____________________________________________________________________________________ Updated by DMA 03-15-24 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 4,488’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’4,208’7.0”9-5/8” Swell Packer 2 8,581’8,094’2.0”Known tight spot- difficult to get long (20’+) tool strings down hole. (2/16/24) 3 9,399’8,867’N/A CIBP (35’ cmt on top) TOC 9,364’ MD (2/16/24) 4 9,929’9,369’N/A CIBP (2/13/24) 5 10,940’10,331’2.441”Float Shoe 6 10,950’10,340’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’11,981’N/A CIBP (43’ cmt on top) TOC 12,617’ MD TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Tubing 6.5 / L-80 / 8RD EUE 2.441”Surf 10,943’ Sand Top MD Btm MD Top TVD Btm TVD Amt Date Comments BEL B17 7,665'7,675'7,258'7,267'10'2/23/24 Open BEL 20 7,885'7,895'7,459'7,469'10'2/23/24 Open BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2/22/24 Open B26 8,294’8,307’7,830’7,843’13’2/22/24 Open B27 8,378’8,389’7,908’7,919’11’2/22/24 Open BEL 28 8,513’8,527’8,030’8,043’14’2/20/24 Open BEL 28 Lwr 8,560’8,575’8,074’8,088’15 2/20/24 Open BEL 28 Lwr 8,575’8,585’8,088’8,096’10’2/19/24 Open BEL B31 Lwr 8,821'8,835'8,317'8,330'14'2/19/24 Open B31C 8,952 8962’8,263’8,276’10’2/18/24 Open B32 9,013 9,033’8,330’8,338’20’2/18/24 Open T1XX 9,082’9,096’8,566’8,579’14’2/14/24 Open T1X 9,223’9,231’8,699’8,704’8’2/14/24 Open T4 9,449’9,462’8,916’8,927’13’2/14/24 Isolated TY T7A 9,744'9,761'9,236'9,252'17'2/13/24 Isolated T8 9,979’9,996’9,416’9,432’17’2/7/24 Isolated TY T18 10,886'10,906'10,222'10,228'20'1/25/24 Isolated T19 10,901’10,921’10,290’10,328’20’1/25/24 Isolated 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,850 feet 10950; 12660 feet true vertical 12,166 feet 8,842 feet Effective Depth measured 10,946 feet 4,295 feet true vertical 10,336 feet 4,208 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 9,041 (MD) 8,525 (TVD) 4,295 (MD) Packers and SSSV (type, measured and true vertical depth)Swell Pkr 4,208 (TVD) SSSV: NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: measured Packer Plugs Junk measured Length 3,090psi 7,460psi 3,060psi 3,450psi 5,750psi 10,640psi 2,510' 2,509' Burst Collapse 1,500psi 1,950psi measured true vertical Production Liner 7,447' 12,841' Casing Structural 7,057' 12,157' 7,447' 12,841' 106'Conductor Surface 2,510' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-188 50-133-20579-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028083 Beaver Creek Unit / Beluga and Tyonek Gas Pools Beaver Creek Unit 19RD Gas-Mcf MD 55 Size 106' 11 60752 0 8013 86 9-5/8" 5-1/2" Intermediate 20" 13-3/8" 106' Chad Helgeson, Operations Engineer 323-184 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 549 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 chelgeson@hilcorp.com 907-777-8405 N/A Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 p k ft t Fra O s O 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:32 pm, May 19, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361), ou=Users Date: 2023.05.19 14:46:05 -08'00' Noel Nocas (4361) Rig Start Date End Date 4/4/23 5/11/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 04/19/2023 - Wednesday AK E-line arrive at BC office, sign in, obtain PTW and hold PJSM. Discuss well site conditions and scope of work. Move equipment to location. Initial: FTP - 76 psi / 536.5 mcfd RU and MU Gun #1 (1.68" GR/CCL, shock sub and 2" x 23' (6spf/60D) perforating gun). (10.5' CCL -T.S.). PU tools and lubricator, stab on and PT 250/3000 psi. Pass. Open swab, with well flowing, RIH and tag PBTD. Run correlation pass, send to RE/GEO. Make +10' adjustment to log - PBTD @ 8857'. Position gun to shoot BEL 28L at 8561'-8584'. Fire gun. Gun stuck ,600 lb. overpull to free. POOH. Initial FTP- 76 psi / 536.5 mcfd Final - 79.1 psi / 638.4 mcfd. OOH. Gun wet. All shots fired. MU Gun #2 (8') & #3 (10') (CCL to TS 20.3' and 7.4'). RIH, correlate on depth and fire lower Gun #2 (BEL 28 - 8492'-8500'). Gun stuck momentarily. Drop down then pull up into position for gun #3 (BEL 28 - 8472'-82'). Gun stuck, then free. POOH. Initial: FTP - 78.5 psi / 637.6 mcfd Final - 84 psi / 728.2 mcfd. OOH. Gun wet and all shots fired. MU Gun #4 (21') (CCL to T.S. - 8.4'). 04/04/2023 - Tuesday Mobe equipment and travel to Beaver Creek. PJSM and permits. Rig up AK E-Line and set up PLT tools. Pressure test surface equipment 250 / 1500 PSI. Test good. Run in hole w/ PLT tools at 120 FPM to 7500'. Make 5 minute stop. Continue down hole at 40 FPM logging. Target depth 10,050'. Well averaging 525 MCF flow at 80 PSI tubing. Bottom spinner stopped working at 2000' but inline spinner still working good. Sat down high in tubing at 8842' just below BEL B31 lower perfs. Work tools at 40-60-80-100' FPM but could not pass obstruction. Called engineering. Satisfied with this depth. Continue logging passes with 8842' as max depth. Begin pulling up hole at 40' FPM to 7500'. Completed 40'-80'- 120' FPM passes. Bottom spinner started working again. Completed one more 120' FPM pass with both spinners working as well as 5 minute station stops between perfs at 8843', 8700', 8425', 8350', 8050', 7700', 7500'. Continue to pull out of hole. Out of hole. Rig down AK E-Line. Logs forwarded via e-mail by AK E-Line. Secure well and turn over to production. Return to shop with equipment. Rig Start Date End Date 4/4/23 5/11/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 05/11/2023 - Thursday AKE-line arrives at BC office. Sign in, obtain PTW, hold PJSM. Discuss RU and scope of work. RU E-line equipment. MU tool string for drift run. 1.68" x 12' wt. bars, CCL, spang jars and 2.25" gauge ring. PU lubricator, tool string and stab on well. PT 250L/1000H Pass. 788 mcfd / 115psi Open swab and RIH. Tagged obstruction at 8230' (previous tag at 8857' 20-Apr-23). Worked tools with spang jars for 15 minutes. Made no hole. Hard tag not sticky. POOH. OOH inspected gauge ring, no apparent marks or debris found. Orders from OE to proceed with PL survey. MU PL tool string: wt bars, centralizer, telemetry, GR/CCL, centralizer, 2-1/8" in-line spinner, press/temp/cap, 1-11/16" caged spinner. RIH at 120 fpm to 7400'. Start 40fpm down pass to 8230'. PU logging at 40 fpm to 7400'. Repeat up and down passes at 80 fpm and 120 fpm. Run back to bottom (8220') and start 10 minute station stops above each perf interval. 8190', 8054', 8000', 7910', 7850', 7810', 7793' & 7700'. PU to 7600' for 30 minute stop. Then 7400' for 10 minute stop. Run back to 8230' and rerun 80 fpm up pass. POOH. Data obtained complete. OOH. Secure well, reapply soap launcher. RDMO. AK E-line sign in, obtain PTW and hold PJSM. Travel to location. PU lubricator and MU Gun #6 tool string (1-11/16" GR/CCL, shock sub and 2" OD x 25' (6spf/60deg phase). CCL to T.S. - 8.5'. Move to wellhead. FTP = 78 psi / 631 mcfd Open swab, RIH. Tag PBTD at 8857'. Run correlation pass 8300' - 7900'. Send to RE/GEO. Adjust log pass (add 2'). Position gun and perf BEL 22 interval 8055'-8080'. Gun stuck but released with 600 lb. overpull. POOH. OOH. Rate fell off but returned after unloading a column of water. LD gun, all shots fired, gun wet. RIH with gun #7 (14'). Confirm correlation, position and fire gun in BEL_22 interval (8035'-8049'). 80 psi/639 mcfd. POOH. No overpull after firing gun. More guns delivered to location to shoot BEL 19 & 20. OOH. LD spent gun. All shots fired, gun wet. RIH with gun #8 (18'). Confirm correlation, position and fire gun in BEL_20 (lwr) interval (7811'-7829'). 80 psi / 653 mcfd No overpull after firing gun. POOH. OOH. LD spent gun. All shots fired. Gun wet. RIH with gun #9 (10'). Confirm correlation, position and fire gun in BEL_20(upper) interval (7794'-7804') 80.1 psi / 706 mcfd Slight overpull after shot. POOH. OOH. LD spent gun, all shots fired. Gun wet. RIH w/ gun #10 (24'). Confirm correlation, position and fire gun in BEL_19 interval (7757'-7781') 80.4 psi / 698 mcfd Slight overpull after shot. POOH. OOH. LD spent gun, all shots fired, gun wet. Secure well. RDMO. Drop soap. Final: 81.6 psi / 658.1 mcfd 04/20/2023 - Thursday _____________________________________________________________________________________ Updated by CAH 05-19-23 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730Surf 106 13-3/8Surface 68 /L-80 J-55 /BTC 12.415Surf 2,510 9-5/8"Intermediate 40 / L-80 / BTC 8.835Surf 4,488 5-1/2"Production 17 / P-110 / CDC-DWC 4.892Surf 12,841 JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,2954,2087.09-5/8 Swell Packer 2 6,0845,8152.3132-7/8 Sliding Sleeve [CLOSED] (Shift Up to Open) 12/23/20 3 6,0975,8272.3902-7/8 x 5-1/2 Retrievable Packer (45K# Shear) 4 6,1145,8422.3132-7/8 X Profile Nipple 5 9,0418,5252.4412-7/8 WLEG 6 10,95010,340N/A Halliburton EZ Drill Bridge Plug (4 cmt on top) TOC 10,946 MD 7 12,66011,981N/A CIBP (43 cmt on top) TOC 12,617 MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size Date Comments BEL B17 7,665'7,675'7,258'7,267'10'2-1/810/27/21 Open BEL 19 7,7577,7817,3427,3642424/20/23 Open BEL 20 7,7947,8047,3767,3851024/20/23 Open BEL 20 7,8117,8297,3927,4082924/20/23 Open BEL Lwr-Bel 7,885'7,895'7,459'7,469'10'2-1/810/27/21 Open BEL B21 Lwr 7,964'7,973'7,531'7,540'9'2-1/810/27/21 Open BEL 22 8,035 8,049 7,596 7,609 14 24/20/23 Open BEL 22 8,055 8,080 7,614 7,637 25 24/20/23 Open BEL B25 Upr 8,200' 8,207' 7,745' 7,752' 7'2-1/810/27/21 Open B26 8,294 8,307 7,830 7,843 13 23/30/21 Open B27 8,378 8,389 7,908 7,919 11 23/30/21 Open BEL 28 8,472 8,482 7,994 8,003 10 24/19/23 Open BEL 28 8,492 8,500 8,012 8,019 8 24/19/23 Open BEL 28 8,513 8,526 8,030 8,043 13 23/30/21 Open BEL 28 Lwr 8,561 8,584 8,075 8,09623 24/19/23 Open BEL B31-Lwr 8,821' 8,835' 8,317' 8,330' 14'210/08/21 Open B31C 8,952 89668,263 8,27614 21/14/21 Open B32 9,020 9,032 8,330 8,33812 21/14/21 Open T1XX 9,083 9,093 8,566 8,575 10 2-7/85/19/20 Open 9,083 9,097 8,565 8,579 14 21/13/21 Open T1X 9,224 9,229 8,699 8,704 5 2-7/85/19/20 Open 9,224 9,231 8,669 8,706 7 21/13/21 Open T4 9,451 9,462 8,916 8,927 11 21/13/21 Open 9,452 9,462 8,916 8,925 10 2-7/85/18/20 Open TY T4 9,478' 9,484' 8,942' 8,947' 6'210/08/21 Open TY T7 9,744' 9,757' 9,195' 9,207' 13'210/08/21 Open TY T7A 9,771' 9,779' 8,220' 9,228' 8'210/08/21 Open TY T7A 9,788' 9,805' 9,236' 9,252' 17'210/08/21 Open T7B 9,850 9,860 9,295 9,304 10 2-7/85/18/20 Open T8 9,979 9,994 9,416 9,430 15 2-7/85/18/20 Open 9,979 9,996 9,416 9,432 17 21/14/21 Open TY T18 10,826' 10,833' 10,222' 10,228' 7'210/08/21 Open T19 10,898 10,937 10,290 10,328 39 21/13/21 Open 10,898 10,937 10,290 10,328 39 21/14/21 Open 10,899 10,923 10,293 10,315 24 2-7/85/9/20 Open 10,923 10,937 10,315 10,328 14 2-7/85/9/20 Open T19A 10,957 10,970 10,347 10,359 23 3-1/8 4/13/20 Isolated T66 12,683 12,708 12,003 12,027 25 3-1/8 4/8/20 Isolated TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Velocity 6.5 / L-80 / 8RD EUE 2.44Surf 9,041 ! 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J * J ,1 0 ’ * ) / ) , , +$ / $ ( , - ’ " ) ( @ ! , + * ’ = ! / 5 J ’" " + ! & ) / , ! $ / , ! / ! / - @ ) , J ’" " % " ’ / 5 ) + * ! " " ! / 5 & 0 , ( , ( * ’ + + " ) -$ & & $ / - ) / ( ) * " ! / ) J *% , ) 4 - ) . ( = @ ) / & & $ + ! % ! ) + J +* ’ = ! / 5 ! , ’ ( @ ! * + ’/ 5 " ) . * $ M ) - ( ! $ / J 2 )- / + ) , - * ! . ( ! $ / +’ ( ) .’ * ( / $ J ?7 : < < 7 7 E 6 A9 ; J ? B A? < J > B AC > J F B 7 7 C 7 Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 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: 06/21/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230421 Well API #PTD #Log Date Log Company Log Type BCU 19RD 50133205790100 219188 5/11/2023 AK E-LINE PPROF MPU I-27 50029236920000 221013 3/23/2023 HALLIBURTON Tubing Punch-Cut MPU J-05 50029221960000 191095 3/25/2023 HALLIBURTON Tubing Punch-Cut MPU L-36 50029227940000 197148 3/14/2023 HALLIBURTON MFC24 Please include current contact information if different from above. T37778 T37779 T37780 T37781 BCU 19RD 50133205790100 219188 5/11/2023 AK E-LINE PPROF Kayla Junke Digitally signed by Kayla Junke Date: 2023.06.21 13:55:21 -08'00' Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 04/14/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230414 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPF-81 50029229590000 200066 3/29/2023 READ CaliperSurvey MPI-04A 50029220680100 201092 4/2/2023 READ CaliperSurvey MPI-27 50029236920000 221013 4/2/2023 READ CaliperSurvey MPI-27 50029236920000 221013 3/20/2023 READ CaliperSurvey MPL-12 50029223340000 193011 4/2/2023 READ CaliperSurvey MPU I-27 50029236920000 221013 3/23/2023 READ LeakPointSurvey PBU 09-23A 50029210660100 198044 3/28/2023 READ MultipleArrayProductionProfile PBU L-112A 50029231290100 222138 3/27/2023 READ MemoryRadialCementBondLog END 1-11 50029221070000 190157 3/19/2023 AK E-LINE Perf END 1-29 50029216690000 186181 2/9/2023 AK E-LINE Perf NCI A-08 50883200280000 169063 3/20/2023 AK E-LINE Perf BCU 19RD 50133205790100 219188 4/4/2023 AK E-LINE PPROF SRU 224-10 50133101380100 222124 3/31/2023 AK E-LINE CIBP_GPT_Perf SRU 224-10 50133101380100 222124 4/3/2023 AK E-LINE GPT_Perf SRU 231-33 50133101630100 223008 3/29/2023 AK E-LINE GPT Please include current contact information if different from above. T37595 T37596 T37599 T37599 T37597 T37599 T37598 T37601 T37603 T37600 T37602 T37594 T37604 T37604 T37605 BCU 19RD 50133205790100 219188 4/4/2023 AK E-LINE PPROF Kayla Junke Digitally signed by Kayla Junke Date: 2023.04.17 14:10:44 -08'00' RBDMS JSB 040423 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 1/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU 19RD (PTD 219-188) Gamma Ray Correlation & Perf 10/27/2021 Please include current contact information if different from above. 37' (6HW Received By: 01/12/2022 By Abby Bell at 12:35 pm, Jan 11, 2022 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 11/09/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU 19RD (PTD 219-188) Perf 10/08/2021 Please include current contact information if different from above. 37' (6HW Received By: 12/07/2021 By Abby Bell at 3:33 pm, Dec 07, 2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ______________________ Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,850 feet 10,950 feet true vertical 12,166 feet N/A feet Effective Depth measured 10,946 feet 4,295 feet true vertical 10,336 feet 4,208 feet Perforation depth Measured depth 7,665 - 10,937 feet True Vertical depth 7,258 - 10,328 feet Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 9,041 (MD) 8,525 (TVD) 4,295 (MD) Packers and SSSV (type, measured and true vertical depth)Swell Pkr 4,208 (TVD) SSSV: NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Contact Phone: 321-478 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 544 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 6 319 Chad Helgeson chelgeson@hilcorp.com (907) 777-8405 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 13 0921 0 330 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 106' 2,510' N/A 0 Structural TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-188 50-133-20579-01-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028083 Beaver Creek Unit / Beluga and Tyonek Gas Pools Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Beaver Creek Unit 19RD measuredPlugs Junk measured N/A Length 106' 2,510' Size Conductor Surface Intermediate 20" 13-3/8" 9-5/8" Production Liner 7,447' 12,841' Casing 106' 2,509' 7,057' 12,157' 7,447' 12,841'5-1/2" 3,090psi 7,460psi 3,060psi 3,450psi 5,750psi 10,640psi Burst Collapse 1,500psi 1,950psi L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 3:29 pm, Nov 24, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.11.24 11:08:32 -09'00' Dan Marlowe (1267) SFD 11/29/2021 DSR-11/24/21 RBDMS HEW 11/29/2021 BJM 12/1/21 _____________________________________________________________________________________ Updated by JLL 11/20/21 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 TD = 12,850’ (MD) / 12,166’ (TVD) 20” RKB: 178.5’ (17’ above GL) 7 13-3/8” 9-5/8” PBTD =10,946’ (MD) /10,336’ (TVD) 5-1/2” 1 T1XX T1X T4 T7 T8 T18 –T19 T19A T66 6 3 4 B31 B32 2 5 B26 B27 B28 B21 –B25 Bel Lwr & Upr B17 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730” Surf 106’ 13-3/8” Surface 68 /L-80 – J-55 /BTC 12.415” Surf 2,510’ 9-5/8" Intermediate 40 / L-80 / BTC 8.835” Surf 7,447’ 5-1/2" Production 17 / P-110 / CDC-DWC 4.892” Surf 12,841’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID Item 1 4,295’ 4,208’ 7.0” 9-5/8” Swell Packer 2 6,084’ 5,815’ 2.313” 2-7/8” Sliding Sleeve [CLOSED] (Shift Up to Open) 12/23/20 3 6,097’ 5,827’ 2.390” 2-7/8” x 5-1/2” Retrievable Packer (45K# Shear) 4 6,114’ 5,842’ 2.313” 2-7/8” X Profile Nipple 5 9,041’ 8,525’ 2.441” 2-7/8” WLEG 6 10,950’ 10,340’ N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’ 11,981’ N/A CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size Date Comments BEL B17 7,665' 7,675' 7,258' 7,267' 10' 2-1/8” 10/27/2021 Open BEL Lwr-Bel 7,885' 7,895' 7,459' 7,469' 10' 2-1/8” 10/27/2021 Open BEL B21 Lwr 7,964' 7,973' 7,531' 7,540' 9' 2-1/8” 10/27/2021 Open BEL B25 Upr 8,200' 8,207' 7,745' 7,752' 7' 2-1/8” 10/27/2021 Open B26 8,294’ 8,307’ 7,830’ 7,843’ 13’ 2” 3/30/21 Open B27 8,378’ 8,389’ 7,908’ 7,919’ 11’ 2” 3/30/21 Open B28 8,513’ 8,526’ 8,030’ 8,043’ 13’ 2” 3/30/21 Open BEL B31-Lwr 8,821' 8,835' 8,317' 8,330' 14' 2” 10/08/21 Open B31C 8,952 8966’ 8,263 8,276’ 14 2” 1/14/21 Open B32 9,020 9,032’ 8,330’ 8,338’ 12 2” 1/14/21 Open T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 2-7/8” 5/19/20 Open 9,083’ 9,097’ 8,565’ 8,579’ 14’ 2” 1/13/21 Open T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 2-7/8” 5/19/20 Open 9,224’ 9,231’ 8,669’ 8,706’ 7’ 2” 1/13/21 Open T4 9,451’ 9,462’ 8,916’ 8,927’ 11’ 2” 1/13/21 Open 9,452’ 9,462’ 8,916’ 8,925’ 10’ 2-7/8” 5/18/20 Open TY T4 9,478' 9,484' 8,942' 8,947' 6' 2” 10/08/21 Open TY T7 9,744' 9,757' 9,195' 9,207' 13' 2” 10/08/21 Open TY T7A 9,771' 9,779' 8,220' 9,228' 8' 2” 10/08/21 Open TY T7A 9,788' 9,805' 9,236' 9,252' 17' 2” 10/08/21 Open T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 2-7/8” 5/18/20 Open T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 2-7/8” 5/18/20 Open 9,979’ 9,996’ 9,416’ 9,432’ 17’ 2” 1/14/21 Open TY T18 10,826' 10,833' 10,222' 10,228' 7' 2” 10/08/21 Open T19 10,898’ 10,937’ 10,290’ 10,328’ 39’ 2” 1/13/21 Open 10,898’ 10,937’ 10,290’ 10,328’ 39’ 2” 1/14/21 Open 10,899’ 10,923’ 10,293’ 10,315’ 24’ 2-7/8” 5/9/20 Open 10,923’ 10,937’ 10,315’ 10,328’ 14’ 2-7/8” 5/9/20 Open T19A 10,957’ 10,970’ 10,347’ 10,359’ 23’ 3-1/8” 4/13/20 Isolated T66 12,683’ 12,708’ 12,003’ 12,027’ 25’ 3-1/8” 4/8/20 Isolated TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8" Velocity 6.5 / L-80 / 8RD EUE 2.44” Surf 9,041’ TY T18 10,826' 10,833' 10,222' 10,228' 7' 2” 10/08/21 Open TY T4 9,478' 9,484' 8,942' 8,947' 6' 2” 10/08/21 Open TY T7 9,744' 9,757' 9,195' 9,207' 13' 2” 10/08/21 Open TY T7A 9,771' 9,779' 8,220' 9,228' 8' 2” 10/08/21 Open TY T7A 9,788' 9,805' 9,236' 9,252' 17' 2” 10/08/21 Open BEL B31-Lwr 8,821' 8,835' 8,317' 8,330' 14' 2” 10/08/21 Open BEL B17 7,665' 7,675' 7,258' 7,267' 10' 2-1/8” 10/27/2021 Open BEL Lwr-Bel 7,885' 7,895' 7,459' 7,469' 10' 2-1/8” 10/27/2021 Open BEL B21 Lwr 7,964' 7,973' 7,531' 7,540' 9' 2-1/8” 10/27/2021 Open BEL B25 Upr 8,200' 8,207' 7,745' 7,752' 7' 2-1/8” 10/27/2021 Openp, , , , /// p Rig Start Date End Date E-Line 10/8/21 10/27/21 10/27/2021 - Wednesday Sign in and mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 psi low and 3,500 psi high. FTP - 339 psi/Rate - 529 MCF. We will be perforating with ell flowing. RIH w/Gun #1, 2-1/8" x 7', 3 spf, 80 deg phase Strip Gun and tie into OHL. Run correlation log and send to town. Get ok to perf Beluga B25-Upper from 8,200' to 8,207' w/339 psi - 529 mcf. Spotted and fired gun. After 5 min - 336 psi/571 mcf, 10 min - 336 psi /559 mcf and 15 min - 335 psi/553 mcf. POOH. All shots fired. RIH w/Gun #2, 2-1/8" x 9', 3 spf, 80 deg phase Strip Gun and tie into OHL. Run correlation log and send to town. Get ok to perf from 7,964' to 7,973' (B21_LWR). Spot and fire gun w/332 psi/547 mcf. After 5 min- 331 psi/566 mcf, 10 min - 331 psi/567 mcf and 15 min - 331 psi/625 mcf. POOH. All shots fired. RIH w/Gun #3, 2-1/8" x 10', 3 spf, 80 deg phase Strip Gun and tie into OHL. Had trouble running thru tree. Decided it was the strip. Changed out 10' gun. RIH now. Run correlation log and send to town. Get ok to perf from 7,885' to 7,895 (Beluga Lwr_Beluga) w/346 psi/554 mcf. After 5 min - 326 psi/585 mcf, 10 min -326 psi/601 mcf and 15 min - 327 psi/554 mcf. POOH. All shots fired. RIH w/Gun #4, 2-1/8" x 10', 3 spf, 80 deg phase Strip Gun and tie into OHL. Run correlation log and send to town. Get ok to perf from 7,665' to 7,675' w/327 psi/555 mcf, 5 min - 327 psi/620 mcf. 10 min - 328 psi/587 mcf and 15 min - 329 psi/585 mcf. POOH. All shots fired. Rig down lubricator, put soap launcher on tree and turn well over to field. 10/08/2021- Friday Crew arrives at facility and obtains permit to work. MIRU e-line unit and pressure test lubricator to 250 psi low / 3500 psi high. RIH with GR-CCL & 2" HSC switched gun assembly, 7' and 17' guns. Correlated first gun and perforated Tyonek from 10826-10833'. Correlated and pulled into position for second gun and failed to fire. POOH, redress BHA and RIH with 17' gun. Correlate gun and perforated Tyonek from 9788-9805'. RIH with GR/CCL & 2" HSC switched gun assembly, 8' and 13' guns. Correlated first gun and perforated Tyonek from 9771-9779'. Correlated and pulled into position for second gun and failed to fire. POOH, redress BHA and RIH with 13' gun. Correlate and perforate Tyonek from 9744-9757'. Troubleshoot BHA and determine that GR/CCL is unable to shoot on positive polarity. Change correlation tool to CCL. RIH W/ CCL & 6' & 14' Switched gun assembly and logged correlation strip across tubing tail. Spotted bottom gun and perforated Tyonek from 9478-9484'. Pulled into position for 14' top gun and shot Beluga from 8821-8835'. POOH. POOH and RDMO e-line. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 perforated Tyonek from 10826-10833'. shot Beluga from 8821-8835' perforated Tyonek from 9788-9805' o perf Beluga B25-Upper from 8,200' to 8,207' o perf from 7,885' to 7,895 (Beluga Lwr_Beluga) perforated Tyonek from 9771-9779' Spotted and fired gun. perforate Tyonek from 9744- from 7,665' to 7,675' o perf from 7,964' to 7,973' (B21_LWR). Spot and fire gu '. T-9757' perforated Tyonek from 9478-9484' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,850'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 7,460psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Dan Marlowe (907) 283-1329 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: October 1, 2021 2-7/8" 12,841' Perforation Depth MD (ft): 7,447' See Attached Schematic 12,841' 12,157'5-1/2" 20" 13-3/8" 106' 9-5/8"7,447' 2,510' 3,060psi 3,450psi 106' 2,509' 7,057' 106' 2,510' 6.5# / L-80 TVD Burst 9,041' 10,640psi MD 5,750psi Length Size CO 237B Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 219-188 50-133-20579-01-00 Beaver Creek Unit (BCU) 19RD Beaver Creek Unit / Beluga and Tyonek Gas Pools COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic todd.sidoti@hilcorp.com 12,166'10,950'10,340'2,695 10,950' Swell Pkr; N/A 4,295' MD/4,208' TVD; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 1:48 pm, Sep 16, 2021 321-478 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.09.16 13:35:57 -08'00' Dan Marlowe (1267) X DSR-9/16/21 DLB 09/17/2021 10-407 BJM 9/23/21 dts 9/24/2021 JLC 9/24/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.24 16:09:05 -08'00' RBDMS HEW 9/27/2021 Well Prognosis Well: BCU-19RD Date: 9/14/2021 Well Name: BCU-19RD API Number: 50-133-20579-01-00 Current Status: Gas Producer Leg: N/A Estimated Start Date: 10/1/2021 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-188 First Call Engineer: Todd Sidoti (907) 777-8443 (O)(907) 632-4113 (M) Second Call Engineer: Jake Flora (907) 777-8442 (O)(720) 988-5375 (M) AFE Number: Max. Expected BHP: 3485 psi @ 7903’ TVD (Based on Geotap Reading) Max. Anticipated Surface Pressure: 2695 psi (BHP - 0.1 psi/ft gas gradient to surface) Brief Well Summary BCU-19RD is an online gas well drilled in May 2020. After initial failed attempts to produce from the T-66 and T- 19A, nearly 3MMCFD in IP was established once the T-19L, T-19U, T-8, T-7B, T-4, T-1X, and T-1XX were perforated. Within five months, however, BC-19RD’s production died due to water loading in the 5-1/2” monobore. Coil installed a 2-7/8” velocity string in October 2020, but could not remove the CIBPs set as part of that work so when the well returned to production in early November, everything below the T-1X was isolated. During the next two months, gas rates never exceeded 500 MCFD. In the latter half of December 2020, the rig was brought over to mill the problematic plugs, re-open the T-4, T-7B, T-8, and T-9, and re-set the 2-7/8” velocity string completion. This work still did not redeem the well; after kickoff with N2, it barely exceeded 60MCFD. In mid- January 2021, the T-1XXX, T-1X, T-4, and T-19 were re-perf’d and new perfs were added while flowing to the T- 8, T-19, B-32, and B-31. Once some water was unloaded, flow stabilized around 400MCFD until more Beluga perfs (B-26, B-28, B-30) were added at the end of March 2021. Since then, BC-19RD has steadily produced 550MCFD at a rock-steady ~330# FTP. Review of the logs suggests there is rate add potential in multiple Tyonek and Beluga sands. The purpose of this work is to add perforations with the well flowing. E-line Procedure 1. MIRU E-line. Pressure test lubricator to 250 psi low / 3500 psi high. 2. Perforate per the table below with 2” HSC guns. Well Prognosis Well: BCU-19RD Date: 9/14/2021 3. a. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer (Meredyth Richards), and Geologist (Jeff Nelson) for confirmation. c. In the case that a zone needs to be shut off below the tubing tail, a through tubing bridge plug would be set and capped with 35’ of cement. Nitrogen may be employed to depress fluid level. 4. RD E-line. 5. Turn well over to production. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Hilcorp Standard Nitrogen Procedure Sand TOP MD BOT MD Total TOP TVD BOT TVD Pool Beluga B15 7448 7463 15 7058 7072 Beluga Beluga B16 7585 7598 13 7184 7196 Beluga Beluga B17 7665 7677 12 7257 7268 Beluga Beluga B18 7690 7702 12 7280 7291 Beluga Beluga B19 7759 7780 21 7344 7364 Beluga Beluga B20_Upper 7793 7804 11 7374 7385 Beluga Beluga B20 7811 7829 18 7392 7410 Beluga Beluga Lwr_Beluga 7884 7895 11 7459 7469 Beluga Beluga B21_Lwr 7964 7973 9 7532 7539 Beluga Beluga B22 8057 8081 24 7616 7640 Beluga Beluga B25_Upper 8198 8207 9 7743 7752 Beluga Beluga B25_Mid 8214 8226 12 7758 7768 Beluga Beluga B28_Upper 8458 8480 22 7981 8000 Beluga Beluga B28_Lwr 8561 8583 22 8076 8096 Beluga Beluga B31_Upper 8774 8783 9 8273 5282 Beluga Beluga B31_Lwr 8819 8835 16 8315 8330 Beluga Tyonek T1XX 9146 9160 14 9625 9639 Tyonek Tyonek T4 9474 9485 11 8937 8948 Tyonek Tyonek T7 9744 9757 13 9195 9207 Tyonek Tyonek T7A 9769 9806 37 9219 9254 Tyonek Tyonek T18 10823 10835 12 10219 10230 Tyonek _____________________________________________________________________________________ Updated by DMA 04-14-21 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 7,447’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth ID Item 1 4,295’7.0”9-5/8” Swell Packer 2 6,084’2.313”2-7/8” Sliding Sleeve [CLOSED] (Shift Up to Open) 12/23/20 3 6,097’2.390”2-7/8” x 5-1/2” Retrievable Packer (45K# Shear) 4 6,114’2.313”2-7/8” X Profile Nipple 5 9,041’2.441”2-7/8” WLEG 6 10,950’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’N/A CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Gun Size Date Comments B26 8,294’8,307’7,830’7,843’13’2”3/30/21 Open B27 8,378’8,389’7,908’7,919’11’2”3/30/21 Open B28 8,513’8,526’8,030’8,043’13’2”3/30/21 Open B31C 8,952 8966’8,263 8,276’14 2”1/14/21 Open B32 9,020 9,032’8,330’8,338’12 2”1/14/21 Open T1XX 9,083’9,093’8,566’8,575’10’2-7/8”5/19/20 Open 9,083’9,097’8,565’8,579’14’2”1/13/21 Open T1X 9,224’9,229’8,699’8,704’5’2-7/8”5/19/20 Open 9,224’9,231’8,669’8,706’7’2”1/13/21 Open T4 9,451’9,462’8,916’8,927’11’2”1/13/21 Open 9,452’9,462’8,916’8,925’10’2-7/8”5/18/20 Open T7B 9,850’9,860’9,295’9,304’10’2-7/8”5/18/20 Open T8 9,979’9,994’9,416’9,430’15’2-7/8”5/18/20 Open 9,979’9,996’9,416’9,432’17’2”1/14/21 Open T19 10,898’10,937’10,290’10,328’39’2”1/13/21 Open 10,898’10,937’10,290’10,328’39’2”1/14/21 Open 10,899’10,923’10,293’10,315’24’2-7/8”5/9/20 Open 10,923’10,937’10,315’10,328’14’2-7/8”5/9/20 Open T19A 10,957’10,970’10,347’10,359’23’3-1/8” 4/13/20 Isolated T66 12,683’12,708’12,003’12,027’25’3-1/8” 4/8/20 Isolated TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Velocity 6.5 / L-80 / 8RD EUE 2.44”Surf 9,041’ _____________________________________________________________________________________ Updated by TCS 09-14-21 PROPOSED SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / Weld 18.730”Surf 106’ 13-3/8”Surface 68 /L-80 – J-55 /BTC 12.415”Surf 2,510’ 9-5/8"Intermediate 40 / L-80 / BTC 8.835”Surf 7,447’ 5-1/2"Production 17 / P-110 / CDC-DWC 4.892”Surf 12,841’ JEWELRY DETAIL No Depth ID Item 1 4,295’7.0”9-5/8” Swell Packer 2 6,084’2.313”2-7/8” Sliding Sleeve [CLOSED] (Shift Up to Open) 12/23/20 3 6,097’2.390”2-7/8” x 5-1/2” Retrievable Packer (45K# Shear) 4 6,114’2.313”2-7/8” X Profile Nipple 5 9,041’2.441”2-7/8” WLEG 6 10,950’N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’N/A CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD)Btm(MD)Top(TVD)Btm(TVD)Amt Gun Size Date Comments Multiple TBD TBD TBD TBD TBD 2”TBD Open B26 8,294’8,307’7,830’7,843’13’2”3/30/21 Open B27 8,378’8,389’7,908’7,919’11’2”3/30/21 Open B28 8,513’8,526’8,030’8,043’13’2”3/30/21 Open B31C 8,952 8966’8,263 8,276’14 2”1/14/21 Open B32 9,020 9,032’8,330’8,338’12 2”1/14/21 Open T1XX 9,083’9,093’8,566’8,575’10’2-7/8”5/19/20 Open 9,083’9,097’8,565’8,579’14’2”1/13/21 Open T1X 9,224’9,229’8,699’8,704’5’2-7/8”5/19/20 Open 9,224’9,231’8,669’8,706’7’2”1/13/21 Open T4 9,451’9,462’8,916’8,927’11’2”1/13/21 Open 9,452’9,462’8,916’8,925’10’2-7/8”5/18/20 Open T7B 9,850’9,860’9,295’9,304’10’2-7/8”5/18/20 Open T8 9,979’9,994’9,416’9,430’15’2-7/8”5/18/20 Open 9,979’9,996’9,416’9,432’17’2”1/14/21 Open T19 10,898’10,937’10,290’10,328’39’2”1/13/21 Open 10,898’10,937’10,290’10,328’39’2”1/14/21 Open 10,899’10,923’10,293’10,315’24’2-7/8”5/9/20 Open 10,923’10,937’10,315’10,328’14’2-7/8”5/9/20 Open T19A 10,957’10,970’10,347’10,359’23’3-1/8” 4/13/20 Isolated T66 12,683’12,708’12,003’12,027’25’3-1/8” 4/8/20 Isolated TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8"Velocity 6.5 / L-80 / 8RD EUE 2.44”Surf 9,041’ 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. David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564- 4422 Received By: Date: Hilcorp North Slope, LLC Date: 06/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Log Vendor BCU 05RD2 501332026202 218068 2/5/2021 PERF GAMMA RAY Yellowjacket BCU 05RD2 501332026202 218068 3/5/2021 PERF GAMMA RAY Yellowjacket BCU 11 501332052100 203025 6/12/2021 PERF Yellowjacket BCU 11 501332052100 203025 6/12/2021 RCBL Yellowjacket BCU 14A 501332053901 213196 6/14/2021 GPT Yellowjacket BCU 19RD 501332057901 219188 1/13/2021 PERF GAMMA RAY Yellowjacket BCU-19RD 501332057901 219188 4/24/2020 CALIPER Yellowjacket BCU-19RD 501332057901 219188 5/18/2020 PERF GAMMA RAY/GPT Yellowjacket Please include current contact information if different from above. Received By: 06/28/2021 37' (6HW By Abby Bell at 11:08 am, Jun 28, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564- 4422 Received By: Date: Hilcorp North Slope, LLC Date: 06/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Log Vendor BCU 05RD2 501332026202 218068 2/5/2021 PERF GAMMA RAY Yellowjacket BCU 05RD2 501332026202 218068 3/5/2021 PERF GAMMA RAY Yellowjacket BCU 11 501332052100 203025 6/12/2021 PERF Yellowjacket BCU 11 501332052100 203025 6/12/2021 RCBL Yellowjacket BCU 14A 501332053901 213196 6/14/2021 GPT Yellowjacket BCU 19RD 501332057901 219188 1/13/2021 PERF GAMMA RAY Yellowjacket BCU-19RD 501332057901 219188 4/24/2020 CALIPER Yellowjacket BCU-19RD 501332057901 219188 5/18/2020 PERF GAMMA RAY/GPT Yellowjacket Please include current contact information if different from above. Received By: 06/28/2021 37' (6HW By Abby Bell at 11:08 am, Jun 28, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564- 4422 Received By: Date: Hilcorp North Slope, LLC Date: 06/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Log Vendor BCU 05RD2 501332026202 218068 2/5/2021 PERF GAMMA RAY Yellowjacket BCU 05RD2 501332026202 218068 3/5/2021 PERF GAMMA RAY Yellowjacket BCU 11 501332052100 203025 6/12/2021 PERF Yellowjacket BCU 11 501332052100 203025 6/12/2021 RCBL Yellowjacket BCU 14A 501332053901 213196 6/14/2021 GPT Yellowjacket BCU 19RD 501332057901 219188 1/13/2021 PERF GAMMA RAY Yellowjacket BCU-19RD 501332057901 219188 4/24/2020 CALIPER Yellowjacket BCU-19RD 501332057901 219188 5/18/2020 PERF GAMMA RAY/GPT Yellowjacket Please include current contact information if different from above. Received By: 06/28/2021 37' (6HW By Abby Bell at 11:08 am, Jun 28, 2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,850 feet 10,950; 12,660 feet true vertical 12,166 feet N/A feet Effective Depth measured 10,946 feet N/A feet true vertical 10,336 feet N/A feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) V String 2-7/8" 6.5# / L-80 9,043' MD 8,527' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 4,295' MD 4,208' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 WINJ WAG 408 Water-Bbl MD 106' 2,510' 0 Oil-Bbl measured true vertical Packer 5-1/2"12,841' 7,057' 12,157' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Beaver Creek / Beluga and Tyonek Gas PoolN/A measured TVD Tubing Pressure 3210 Beaver Creek Unit (BCU) 19RD N/A FEDA 028083 7,447' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-188 50-133-20579-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-122 336 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Authorized Signature with date: Authorized Name: 330 Casing Pressure Liner 628 0 Representative Daily Average Production or Injection Data 106' 2,510' 7,447' 12,841' Conductor Surface Intermediate Production 7,460psi Casing Structural 20" 13-3/8" 9-5/8" Length 5,750psi 3,450psi Collapse 1,500psi 1,950psi 3,090psi todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 3,060psi 10,640psi 106' 2,509' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:03 am, Apr 28, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.04.27 14:53:41 -08'00' Taylor Wellman (2143) DSR-4/29/21 SFD 4/28/2021BJM 7/16/21 RBDMS HEW 4/30/2021 Rig Start Date End Date E-Line 3/30/21 3/30/21 03/30/2021 - Tuesday Sign in, Mobe to location, PTW and JSA. Rig up equipment and lubricator, PT to 250 psi low and 3,500 psi high. TP - 320 psi, rate 421K, Will shoot well flowing. RIH w/ 2" x 13' Razar HC, 6spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 8,513' to 8,526' w/321 psi on tubing. Spot and fire gun 1. Lost 250 lbs line tension when fired. Got it right back. After 5 min - 321 psi/425 mcf, 10 min - 321 psi/503 mcf and 15 min - 320 psi/429 mcf. POOH. RIH w/ 2" x 13' and a 2" x 11' Razar HC, 6 spf, 60 deg phase switch guns and tie into OHL. Run correlation log and send to town. Get ok to shoot gun 2 from 8,378' to 8,389' and gun 3 at 8,294'to 8,307', spot and fire 2d gun. Pull up and fired 3 gun. Didn't see much change. Gun 2- 5 min - 320 psi/460 mcf, 10 min - 320 psi 455 mcf and 15 min - 321 psi/545 mcf. 3d gun - 5 min - 321 psi/458 mcf, 10 min - 320 psi/456 mcf and 15 min - 321 psi/555 mcf. POOH. All shots fired and gun was wet. Rig down Equipment and secure well. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 Get ok to perf from 8,513' to 8,526' w/321 psi on tubing. Spot and fire gun 1. Pull up and fired 3 gun. ok to shoot gun 2 from 8,378' to 8,389' and gun 3 at 8,294'to 8,307', spot and fire 2d gun. _____________________________________________________________________________________ Updated by DMA 04-14-21 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730” Surf 106’ 13-3/8” Surface 68 /L-80 – J-55 /BTC 12.415” Surf 2,510’ 9-5/8" Intermediate 40 / L-80 / BTC 8.835” Surf 7,447’ 5-1/2" Production 17 / P-110 / CDC-DWC 4.892” Surf 12,841’ JEWELRY DETAIL No Depth ID Item 1 4,295’ 7.0” 9-5/8” Swell Packer 2 6,084’ 2.313” 2-7/8” Sliding Sleeve [CLOSED] (Shift Up to Open) 12/23/20 3 6,097’ 2.390” 2-7/8” x 5-1/2” Retrievable Packer (45K# Shear) 4 6,114’ 2.313” 2-7/8” X Profile Nipple 5 9,041’ 2.441” 2-7/8” WLEG 6 10,950’ N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’ N/A CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size Date Comments B26 8,294’ 8,307’ 7,830’ 7,843’ 13’ 2” 3/30/21 Open B27 8,378’ 8,389’ 7,908’ 7,919’ 11’ 2” 3/30/21 Open B28 8,513’ 8,526’ 8,030’ 8,043’ 13’ 2” 3/30/21 Open B31C 8,952 8966’ 8,263 8,276’ 14 2” 1/14/21 Open B32 9,020 9,032’ 8,330’ 8,338’ 12 2” 1/14/21 Open T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 2-7/8” 5/19/20 Open 9,083’ 9,097’ 8,565’ 8,579’ 14’ 2” 1/13/21 Open T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 2-7/8” 5/19/20 Open 9,224’ 9,231’ 8,669’ 8,706’ 7’ 2” 1/13/21 Open T4 9,451’ 9,462’ 8,916’ 8,927’ 11’ 2” 1/13/21 Open 9,452’ 9,462’ 8,916’ 8,925’ 10’ 2-7/8” 5/18/20 Open T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 2-7/8” 5/18/20 Open T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 2-7/8” 5/18/20 Open 9,979’ 9,996’ 9,416’ 9,432’ 17’ 2” 1/14/21 Open T19 10,898’ 10,937’ 10,290’ 10,328’ 39’ 2” 1/13/21 Open 10,898’ 10,937’ 10,290’ 10,328’ 39’ 2” 1/14/21 Open 10,899’ 10,923’ 10,293’ 10,315’ 24’ 2-7/8” 5/9/20 Open 10,923’ 10,937’ 10,315’ 10,328’ 14’ 2-7/8” 5/9/20 Open T19A 10,957’ 10,970’ 10,347’ 10,359’ 23’ 3-1/8” 4/13/20 Isolated T66 12,683’ 12,708’ 12,003’ 12,027’ 25’ 3-1/8” 4/8/20 Isolated TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8" Velocity 6.5 / L-80 / 8RD EUE 2.44” Surf 9,041’ B26 8,294’8,307’7,830’7,843’13’2” 3/30/21 Open B27 8,378’8,389’7,908’7,919’11’2”3/30/21 Open B28 8,513’8,526’8,030’8,043’13’2”3/30/21 Open Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 04/12/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU 19RD (PTD 219-188) PERFORATING RECORD 03/30/2021 Please include current contact information if different from above. PTD: 2191880 E-Set: 34952 Received by the AOGCC 04/12/2021 04/12/2021 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,850'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 7,460psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng todd.sidoti@hilcorp.com 12,166'10,950'10,340'2,695 10,950' Swell Pkr; N/A 4,295' MD/4,208' TVD; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 219-188 50-133-20579-01-00 Beaver Creek Unit (BCU) 19RD Beaver Creek Unit / Beluga and Tyonek Gas Pools Length Size CO 237B Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 6.5# / L-80 TVD Burst 9,041' 10,640psi MD 5,750psi 3,060psi 3,450psi 106' 2,509' 7,057' 106' 2,510' 12,157'5-1/2" 20" 13-3/8" 106' 9-5/8"7,447' 2,510' 12,841' Perforation Depth MD (ft): 7,447' See Attached Schematic 12,841' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: March 24, 2021 2-7/8" Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 3:31 pm, Mar 10, 2021 321-122 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.03.10 15:13:52 -09'00' Taylor Wellman (2143) DSR-3/10/21DLB 03/10/2021 X 10-404 BJM 3/16/21Comm. 3/17/21 dts 3/16/2021 JLC 3/17/2021 RBDMS HEW 3/18/2021 Well Prognosis Well: BCU-19RD Date: 3/3/2021 Well Name: BCU-19RD API Number: 50-133-20579-01-00 Current Status: Sidetrack Leg: N/A Estimated Start Date: 3/24/2021 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-188 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number: Max. Expected BHP: 3485 psi @ 7903’ TVD (Based on Geotap Reading) Max. Anticipated Surface Pressure: 2695 psi (BHP - 0.1 psi/ft gas gradient to surface) Brief Well Summary BCU-19RD is a producing gas well that was recently drilled. The well’s production rate quickly dropped off due to a water influx causing the 5-1/2 Inch monobore to load up. A 2-7/8” velocity string was ran in the well in order to reduce the liquid unloading rate for the well. The through tubing plug milling operation with CTU was not successful in removing the CIBPs set prior to running the velocity string. 401 was mobilized to work the well over. The plugs were removed and a velocity string was re-installed. A re-perf of the current zones was unsuccessful in regaining the rate. Two Beluga sands were perforated with sub-par results. The purpose of this work is to add Beluga zones with the well flowing. E-line Procedure 1. MIRU E-line. Pressure test lubricator to 250 psi low / 3500 psi high. 2. Perforate per the table below starting with the B27 with 2-3/8” HSC guns loaded at 5 SPF. Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Beluga B20 ±7793’ ±7804’ ±7374’ ±7385’ 11’ Beluga B20 ±7811’ ±7829’ ±7392’ ±7410’ 18’ Beluga B22 ±8057’ ±8081’ ±7616’ ±7640’ 24’ Beluga B26 ±8294’ ±8306’ ±7830’ ±7842’ 12’ Beluga B27 ±8373’ ±8389’ ±7903’ ±7919’ 16’ Beluga B28 ±8513’ ±8526’ ±8030’ ±8043’ 13’ a. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer (Trudi Hallett), and Geologist (Jeff Nelson) for confirmation. 3. RD E-line. 4. Turn well over to production. Attachments: 1. Current Schematic 2. Proposed Schematic _____________________________________________________________________________________ Updated by DMA 01-31-21 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730” Surf 106’ 13-3/8” Surface 68 /L-80 – J-55 /BTC 12.415” Surf 2,510’ 9-5/8" Intermediate 40 / L-80 / BTC 8.835” Surf 7,447’ 5-1/2" Production 17 / P-110 / CDC-DWC 4.892” Surf 12,841’ JEWELRY DETAIL No Depth ID Item 1 4,295’ 7.0” 9-5/8” Swell Packer 2 6,084’ 2.313” 2-7/8” Sliding Sleeve [CLOSED] (Shift Up to Open) 12/23/20 3 6,097’ 2.390” 2-7/8” x 5-1/2” Retrievable Packer (45K# Shear) 4 6,114’ 2.313” 2-7/8” X Profile Nipple 5 9,041’ 2.441” 2-7/8” WLEG 6 10,950’ N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’ N/A CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size Date Comments B31C 8,952 8966’ 8,263 8,276’ 14 2” 1/14/21 Open B32 9,020 9,032’ 8,330’ 8,338’ 12 2” 1/14/21 Open T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 2-7/8” 5/19/20 Open 9,083’ 9,097’ 8,565’ 8,579’ 14’ 2” 1/13/21 Open T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 2-7/8” 5/19/20 Open 9,224’ 9,231’ 8,669’ 8,706’ 7’ 2” 1/13/21 Open T4 9,451’ 9,462’ 8,916’ 8,927’ 11’ 2” 1/13/21 Open 9,452’ 9,462’ 8,916’ 8,925’ 10’ 2-7/8” 5/18/20 Open T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 2-7/8” 5/18/20 Open T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 2-7/8” 5/18/20 Open 9,979’ 9,996’ 9,416’ 9,432’ 17’ 2” 1/14/21 Open T19 10,898’ 10,937’ 10,290’ 10,328’ 39’ 2” 1/13/21 Open 10,898’ 10,937’ 10,290’ 10,328’ 39’ 2” 1/14/21 Open 10,899’ 10,923’ 10,293’ 10,315’ 24’ 2-7/8” 5/9/20 Open 10,923’ 10,937’ 10,315’ 10,328’ 14’ 2-7/8” 5/9/20 Open T19A 10,957’ 10,970’ 10,347’ 10,359’ 23’ 3-1/8” 4/13/20 Isolated T66 12,683’ 12,708’ 12,003’ 12,027’ 25’ 3-1/8” 4/8/20 Isolated TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8" Velocity 6.5 / L-80 / 8RD EUE 2.44” Surf 9,041’ _____________________________________________________________________________________ Updated by TRH 18Feb2021 PROPOSED Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 TD = 12,850’ (MD) / 12,166’ (TVD) 20” RKB: 178.5’ (17’ above GL) 7 13-3/8” 9-5/8” PBTD = 10,946’ (MD) / 10,336’ (TVD) 5-1/2” 1 T1XX T1X T4 T7B T8 T19 T19A T66 6 3 4 B31C B32 2 5 Proposed Beluga Perfs CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730” Surf 106’ 13-3/8” Surface 68 /L-80 –J-55 /BTC 12.415” Surf 2,510’ 9-5/8" Intermediate 40 /L-80 / BTC 8.835” Surf 7,447’ 5-1/2" Production 17 / P-110 / CDC-DWC 4.892” Surf 12,841’ JEWELRY DETAIL No Depth ID Item 14,295’7.0” 9-5/8” Swell Packer 2 6,084’ 2.313” 2-7/8” Sliding Sleeve [CLOSED] (Shift Up to Open) 12/23/20 3 6,097’ 2.390” 2-7/8” x 5-1/2” Retrievable Packer (45K# Shear) 4 6,114’ 2.313” 2-7/8” X Profile Nipple 5 9,041’ 2.441” 2-7/8” WLEG 6 10,950’ N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’ N/A CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt GunSize Date Comments B20 ±7,793’ ±7,804’ ±7,374’ ±7,385’ ±11’ TBD TBD Proposed B20 ±7,811’ ±7,829’ ±7,392’ ±7,410’ ±18’ TBD TBD Proposed B22 ±8,057’ ±8,081’ ±7,616’ ±7,640’ ±24’ TBD TBD Proposed B26 ±8,294’ ±8,306’ ±7,830’ ±7,842’ ±12’ TBD TBD Proposed B27 ±8,373’ ±8,389’ ±7,903’ ±7,919’ ±16’ TBD TBD Proposed B28 ±8,513’ ±8,526’ ±8,030’ ±8,043’ ±13’ TBD TBD Proposed B31C 8,952 8966’ 8,263 8,276’ 14 2” 1/14/21 Open B32 9,020 9,032’ 8,330’ 8,338’ 12 2” 1/14/21 Open T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 2-7/8” 5/19/20 Open 9,083’ 9,097’ 8,565’ 8,579’ 14’ 2” 1/13/21 Open T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 2-7/8” 5/19/20 Open 9,224’ 9,231’ 8,669’ 8,706’ 7’ 2” 1/13/21 Open T4 9,451’ 9,462’ 8,916’ 8,927’ 11’ 2” 1/13/21 Open 9,452’ 9,462’ 8,916’ 8,925’ 10’ 2-7/8” 5/18/20 Open T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 2-7/8” 5/18/20 Open T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 2-7/8” 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Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Install Velocity String & N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 12,850 feet 10,950; 12,660 feet true vertical 12,166 feet N/A feet Effective Depth measured 10,946 feet N/A feet true vertical 10,336 feet N/A feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) V String 2-7/8" 6.5# / L-80 9,043' MD 8,527' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 4,295' MD 4,208' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 3,060psi 10,640psi 106' 2,509' 5,750psi 3,450psi Collapse 1,500psi 1,950psi 3,090psi 7,460psi Casing Structural 20" 13-3/8" 9-5/8" Length 106' 2,510' 7,447' 12,841' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 0 Casing Pressure Liner 346 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-500 & 321-003 95 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-188 50-133-20579-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 00 Beaver Creek Unit (BCU) 19RD N/A FEDA 028083 7,447' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Beaver Creek / Tyonek Gas PoolN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 5-1/2"12,841' 7,057' 12,157' WINJ WAG 0 Water-Bbl MD 106' 2,510' 6 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 8:56 am, Feb 16, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.02.15 11:23:06 -09'00' Taylor Wellman (2143) RBDMS HEW 2/16/2021 DSR-2/16/21BJM 2/16/21 Rig Start Date End Date 12/8/20 1/14/21 PJSM, stack counter weights on pipe rack, p/u joint & make up to swivel & insert stripping head, m/U t/string, start pumping, stop & repair leak on Kelly hose & wash pipe. Start milling on CIBP @ 9,056', up wt 56, dn wt 44, rot 20 rpm, rot wt 49, tq, 500 off, 2k on, 300 diff pressure. Lost swab on pump, p/u & shut down to repair, source parts from yard & c/o 2 swabs. Cont milling on CIBP @ 9,056', up wt 56, dn wt 44, rot 20 rpm, rot wt 49, tq, 500 off, 2k on, pump 3.4 BPM. 1,025 psi, 300 diff pressure. WOB 1-3 k, Plug fell away, chased down t/9,090' no tag. R/D swivel & hang, r/u handling eq. up wt 55k, dn wt 44k. RIh chase plug down t/ 9,281', set down t/30k, no movement. Shut in blow down, night watch & work on project list. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 Daily Operations: 12/09/2020 - Wednesday PTSM, check well pressures good, set BPV. N/D tree, prep wellhead, install blanking sub, N/U BOPE, install floor & wind wall for cellar, tq. flanges, install choke & kill line, accumulator lines, install stairs, build 2-7/8" test jt. Test BOPE as per Hilcorp & AOGCC requirements, AOGCC witness waived by Jim Regg, Inspector Quinn Sawyer with BLM witnessed test. tested 250/3,000 with 2-7/8" TJ. Pull test jt & blanking sub, pull BPV, secure well for night Blow down surface lines. Night watch rig, work on punch list. 12/10/2020 - Thursday 12/08/2020 - Tuesday PJSM, lay felt & liner, spot accumulator, base beam, install landings on carrier, & spot to well center, continue spotting aux eq. stand mast & scope up, secure guy lines. Install berming. R/U electrical lines, r/u PVT system. R/u circulating lines to wellhead, Fill mix tank, mix 100 bbls 6% kcl, transfer to rig pits, re-fill mix tank & mix 100 bbls 6% kcl, cont. r/u aux eq. SITP=2,000psi, SICP 2,300psi, pump down tubing take returns to gas-buster, stage pump up t/1.5 BPM, following pump schedule @ 30 bbls pumped tubing pressure =0, cont pumping holding back pressure on casing following pump schedule, shut down @ 200 bbls pumped SICP=700 psi, SITP=0, mix 90 bbls 6% kcl, resume pumping stage up t/ 3bpm @ 450psi good returns 8.6ppg @236bbls pumped. shut down & secure well, blow down lines. Night watch rig, cont. winterization on carrier. PTSM, check well, good, r/u 2-7/8" handling eq. m/u landing joint, lay out liner, r/u pipe rack, skate & hyd unit for tongs, warm up same. BOLD pins, pull hanger off seat @ 40k, string travel @ 42k, l/d hanger & landing jt, POOH l/d 2-7/8" 6.5# L- 80 EUE completion tubing. f/9,008' t/8,411' Cont. POOH l/d 2-7/8" completion t/2,404', l/d 208 jts Night watch rig, blow down lines, fuel rig. 12/11/2020 - Friday PTSM, check well static, blow through surface lines good, Cont. POOH f/2,404', l/d 2 7/8" completion 281 full jts & one mule shoe jt. C/o handling tools, load & tally first layer of wk string. P/U BHA #1= Mill, xo, 3 1/2" mud mtr, D pin xo, 3- boot baskets, bit sub, bumper sub, oil jar, xo = 49.69', surface test MTR good, @ 3bpm, 400 psi TIH p/u 2-7/8" PH6 wk string t/3874', up wt 25k, dn wt 25k Night watch rig, blow down lines, work on punch list. 12/12/2020 - Saturday PTSM, Blow through lines, rack & tally pipe, cont. TIH f/3,874', p/u 2-7/8" PH6 wk string t/9,056' where we tagged, up wt 52k, dn wt 43k R/U power swivel, tq. lines, went to function swivel & had leak on hose swivel connection, made run to yard for parts, ( blew down surface lines,) r/u tongs, repaired swivel connection, m/u Kelly valve & saver sub. secure well for night Night watch rig, work on project list. 12/13/2020 - Sunday Rig Start Date End Date 12/8/20 1/14/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 Daily Operations: PJSM with crew, emphasis on checking circulation lineups, well monitoring during milling ops. Mill on fish at 9,276.5'. Free spin initial rates of 1.3 bpm / 800 psi, increase to 2.3 bpm / 1600 psi. Motorwork at 2.3-2.5 bpm is 1570-1850 psi, varying stack down weight ~7.5 to 15k. Light cement in returns from bottoms up with higher differential pressures, slower progress. Mill ~3', suspect plug is spinning. PU, new parameters: 2.5 bpm, 1300 psi, 4-5k down weight, but can't get it to react. RD Power Swivel, RU Power Tongs. POH with BHA. Initial PU to 75k without any movement. Change from short bales (80k limit) to long bales. Pick up, heavy at 60k breakover, steady pull at 57k (~9k over). Well initially swabbing, when set in slips goes on drink. Continue to POH, well stabilizes on fluids, still dragging weight. Pull 30 stands, hole fill stabilizing to calculated fill. Close in to secure well. Night crew building fluids, monitor well. PJSM, Blow through lines good, Cont. TIHf/ 5,690' t/ 9,281' tag, up wt 54k, dn we 42k. Wk spear 3x no depth change or weight fluctuation. POOH standing back 2-7/8" wk string. Pull BHA, had no recovery, no substantial markings on spear, did have pieces of dies stuck in nose of spear, discussed options with engineers, decide to run magnet on e-line then dump bail cmt on plug in the AM. Blow down & l/d BHA while waiting on W/L. R/U w/l. RIH With run #1, w/ 4" magnet, tagged up 9,295 WLM, POOH recovered one piece of rubber & some swarf. RIH With run #2, w/ 4" magnet, tagged & worked 9,295' WLM, POOH recovered swarf, r/d w/l & secured well for night. Night watch rig. Safety meeting with crew regarding rigging up E-line, checking and monitoring well for pressure. RU Alaska E-Line for bailer run. RIH with 10' bailer, tag at 9,296' wireline measurement (previous Slickline unit tagged at 9,299'). Lay in 5' of cement on top of CIBP, POH. RD E-line unit. RU, test BOP and Power Swivel IBOP to 250 psi low / 3,000 psi high. Test rams with 2-7/8" test joint. Make up milling BHA: Tri-cone roller bit, 3-1/2" motor, 3 each junk baskets, 3-1/8" bumper sub, 3- 1/8" jar. RIH on 2-7/8" PH6 workstring to 117', function test motor. Hang off string, secure well and turn over to nightwatch crew. 12/17/2020 - Thursday PJSM with crew on RIH and milling operation. Discuss monitoring well conditions and consistent straps of fluids on locations. RIH with Milling BHA #2 on 2-7/8" workstring. Tag fish at 9,276' drill pipe measured depth. RD power tongs, RU Power Swivel, function test. Begin milling ahead at 2.4-2.5 bpm, 1,100-1,400 psi. Make ~1/2’ gain, swab on pump blew out. Crew working on pump, have to call in Field Maintenance to bring out parts. Blow down all circulation lines, double check to ensure clear. Complete blowdown of lines, secure well for evening. Evening crew making up 60 bbls of 8.6 ppg, 6% KCL. 12/16/2020 - Wednesday 12/14/2020 - Monday PJSM, check rig eq. Prep to POOH. POOH f/ 9,270' standing back wk string, t/ BHA. C/O BHA, l/d motor/mill & boot baskets, recover hand full of metal from milling, M/U BHA#2=Spear, xo, bumper sub, oil jar, xo = 24.53'. TIh with BHA #2 on 2-7/8" wk string from derrick t/5,690', up wt 36k, dn wt 33k. Night watch rig. 12/15/2020 - Tuesday 12/18/2020 - Friday Was anything retrieved with BHA? Is 2nd bridge plug still in the hole at 9278? Rig Start Date End Date 12/8/20 1/14/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 Safety meeting with rig and Slickline crews, emphasis on clearing footpaths of snow, conducting Slickline work and RD. MU fishing tools on Slickline. RIH, tag fish neck from previous run. Fish on, POH. All BHA out of hole, indications that spear was on plug by wear on nose, paraffin packed into bullnose. RD Slickline rigging. Clear rig floor. MU BHA #4: 5 Blade Inserted Junk Mill with cutrite, 2-7/8" Bi-Directional Jars, 3 each Boot Baskets. RIH with BHA on 2-7/8" workstring. Mobilize tongs off floor, RU Power Swivel. Circulate above plugs at max rate. Pump Hi-vis pill down, engage fish while circulating around. Begin milling, 300-500 lbs down. Slow gains, pushed plugs away. RIH with 2 joints minimal resistance. RD Power Swivel, mobilize tongs to rig floor, RU. Blow down lines in preparation to RIH with workstring. Monitor well, notice flow. Close in, record pressure, strap pits, line-up to circulate a bottoms up. Break circulation through choke manifold and MGS. Initial circ pressure of 1,100 psi at 1.3 bpm. Stage up to 2.3 bpm, 3,300 psi. Catch fluid at 37 bbls away, begin bottoms up strokes. CBU, shut down and close in choke to monitor. Initial pressure 0 psi. Monitor for 30 minutes, 0 psi. Fill across top to gauge losses. 12/22/2020 - Tuesday Safety meeting with crew on planned ops, focus on monitoring well, ensuring to keep well full during trip in, weather. Conduct walk arounds and service rig. Rearrange rigging on securing Power Swivel, RU tongs. RIH with 2-7/8" workstring to push plugs to PBTD. Slight 1-2k bobbles on trip in, otherwise unremarkable. Plugs on bottom at 10,943'. Pick up off bottom sticky at 65k PUW. Stage joint in Annular for circulation, close Annular. RU to circulate bottoms up from PBTD. PJSM on monitoring well during circulation. Doublecheck line ups, break circulation. Circulate through choke manifold to MGS. POH with 2-7/8" workstring laying down sideways. LD BHA. Close in and secure well. 12/19/2020 - Saturday POH with Fishing BHA #2 with unknown fish and/or debris around or on BHA, pulling heavy on trip out. Well taking fluid, hole displacement off by ~1/2 to 1 bbl per 10 stands. BHA out, bit packed off with grease and cement, nothing in junk baskets. LD BHA, notify ODE. Secure well. Arrange for Slickline unit to come out, nothing available until Sunday. Conduct rig repair and maintenance, clean mix tank, repair hydraulic hoses and secure, improve rigging on Power Swivel, clear snow from rig footprint (~8"), prep layout area for Slickline. 12/20/2020 - Sunday Safety meeting with crew, emphasis on housekeeping (a lot of snow yesterday), blowing down lines, opening to well, and hand placement during BHA MU / breakdown. Inspect equipment, clear walkways. Stage tools, prep area for staging in Slickline Unit. RU Slickline Unit. Conduct gauge ring drift run, tag at 9,289'. POH, clean run. Change out to 4.5" LIB, run to fish and get impression, POH. no impression on block. MU, RIH with Pump Bailer. combined grease / paraffin / metal shavings resembling coarse salt grains - total 3 runs, ~4 cups of debris. Last run fluid only. Gained 1' of measured depth with each run. Break off Pump Bailer, make up bow spring centralizer and Spear onto Slickline BHA. RIH, bang down ~12 times after tag. PU, PUW is 50 lbs over initial clean PUW. POH, no fish. Run back down for second attempt, tags consistent at 9,289'-9,290'. POH, Slickline tool has sheared off leaving fishing neck looking up. Close Blinds on well. LD BHA, secure equipment for next morning operation. Night watch crew to monitor location. 12/21/2020 - Monday Rig Start Date End Date 12/8/20 1/14/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 Daily Operations: 12/23/2020 - Wednesday Safety Meeting with crew, emphasis on handling tongs, monitoring well, proper lift procedures, awareness while walking location due to ice. Complete RU and prep for running completion. MU, RIH with 281 joints of 2-7/8" 6.5# L-80 EUE tubing completion with Muleshoe on bottom. MU X-profile Sliding Sleeve w/pups (uppermost), 2-7/8" x 5-1/2" DLH Retrievable Packer w/45k shear release w/pups, and 2.313" ID X Nipple (lowermost) between joints 93 and 94 (from Muleshoe). Tally is in well folder on O: drive. MU hanger and pup to string, land out and run in LDS. Test void. Drop rod, pressure up and set packer. Test 2-7/8" x 5-1/2" annulus above packer to 1,500 psi, chart for 30 minutes. Install BPV. ND BOP, move away from wellhead. NU Production tree. Fluid pack with diesel, PT to 5,000 psi. Prep for rigging down and moving off location. 12/24/2020 - Thursday PJSM with incoming crew, emphasis on updating crew of last well ops, Lessons Learned. Continue to RD in preparation for move from BCU 19 to CLU-006. 12/29/2020 - Tuesday Petrospec Coiled Tubing arrive in Beaver Creek. Conduct JSA and approve PTW. MIRU coil equipment. Spot return tank, choke skid. Nipple up BOPE on well. Test blind/shear ram to 250/4,000 psi. Test Pipe/slip ram to 250/4,000 psi. Test choke and kill lines. Test accumulator system. AOGCC BOP test witness waived by Jim Regg. Install night cap on BOP's for the night. Prep for spotting N2 equipment in morning. 12/30/2020 - Wednesday Petrospec coiled tubing and SLB nitrogen equipment arrive at location. Conduct JSA and approve PTW. MU CTC and dual check valves. MU injector on top of BOP's. Pressure test lubricator, stripper, and checks to 250/4000 psi. RIH with 1.75" coil and 2.0" NoGo. Start pumping N2 at 5,000' @ rate of 550 scf/m. Stop coil at 8,940' and watch for returns to tank. Small amount of mud returning to tank, no nitrogen to return tank. RIH to 10,850' pumping N2. Park coil and pump N2. CTP = 2,200 psi with minimal returns to surface. POOH with coil to 9,150' and stop. Getting return rate of ~ 0.5 bpm of fluid and N2/gas back at return tank. Stay at 9,150' until most all fluid returns have stopped. Returned total of 32 bbls at this point. POOH with coil. No fluid returns back to surface. Shut down N2 at 8,000' while flowing to return tank, wide open choke. Check LEL and ensure minimal N2 before going to production line. Pump total of 134,262 scf of Nitrogen. Coil at surface. Stack back injector. Leave BOP's installed. Dropped soap sticks, install night cap with blinds closed and handover to production for the night. Rig Start Date End Date 12/8/20 1/14/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 Daily Operations: 01/14/2021 - Thursday RIH WITH 1-11/16" GG AND 17' OF 2" RAZOR 6/60. PERF DEPTH 9,979'-9,996', 13.5' FROM CCL TO TS, CCL DEPTH 9,965.5', 87 PSI BEFORE PERF, WELL WAS SHOT FLOWING. RIH WITH 1-11/16" GG AND 39' OF 2" RAZOR 6/60. PERF DEPTH 10,898'- 10,937', 11' FROM CCL TO TS, CCL DEPTH 10,887', 89 PSI BEFORE PERF, WELL WAS SHOT FLOWING. RIH WITH 7' 1-11/16" WB, 1-11/16" GG AND 12' OF 2" RAZOR 6/60. PERF DEPTH 9,020'-9,032', 11' FROM CCL TO TS, CCL DEPTH 9,009', 90 PSI BEFORE PERF, WELL WAS SHOT FLOWING. RIH WITH 7' 1-11/16" WB, 1-11/16" GG AND 14' OF 2" RAZOR 6/60. PERF DEPTH 8,952'-8,966', 9' FROM CCL TO TS, CCL DEPTH 8,943’, 91 PSI BEFORE PERF, WELL WAS SHOT FLOWING. Rig down lubricator and equipment. Turn well over to production. 12/31/2020 - Thursday Petrospec coiled tubing and SLB N2 personnel arrive on location. Conduct JSA and approve PTW. MU dual check valves and MU injector on top of BOPs. PT stripper and injector. Open well and RIH with 1.75" coiled tubing. SLB N2 unit cooling down while RIH. PT N2 lines. Have well open to return tank while RIH. Start pumping N2 @ 500 scfm at 2,500'. CTP = 390 psi. Stop coil at 9,500'. Getting only N2/gas to surface, no fluid to surface. CTP stayed at 390 psi, appears no fluid down to 9,500'. RIH to 10,000'. Stopped getting returns to surface, CTP increased, appear to be in fluid downhole. Increase N2 rate to 700 scfm. Start to get soapy water to surface. Fluid returns tapered off, now getting only N2/gas. POOH with coil. Shut down N2 once up in tubing tail. Hold ~ 100 psi on wellhead. Get back 6 bbls of fluid. Coil at surface. Shut in swab valve. RDMO. Hand over to production. 01/13/2021 - Wednesday PTW and JSA. Spot equipment and rig up lubricator. PT lubricator to 250 psi low and 3,500 psi high. RIH w/ gun #1, 2" x 14' Razor HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Town said to subtract 2' and perforate from 9,083' to 9,097' w/100K/348 psi. Spotted and fired gun. After 5 min - 100K/340 psi, 10 min - 114K/346psi and 15 min - 113K/343 psi. POOH. All shots fired/Gun was wet. RIH w/gun #2, 2" x 7' Razor HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Town said we were on depth and perforate from 9,224' to 9,231' w/114K/340 psi. Spotted and fired gun. After 5 min - 122K/342 psi, 10 min - 116K/345psi and 15 min - 119K/338 psi. POOH. All shots fired/Gun was wet. RIH w/gun #3, 2" x 11'' Razor HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Town said we were on depth and perforate from 9,451' to 9,462' w/114K/341 psi. Spotted and fired gun. After 5 min - 115K/338 psi, 10 min - 162K/339psi and 15 min - 132K/337 psi. POOH. All shots fired/Gun was wet. RIH w/gun #4, 2" x 16'' Razor HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Town said we were on depth and perforate from 10,898' to 10,937' w/116K/335 psi. Spotted and fired gun. After 5 min - 126K/337 psi, 10 min - 135K/337 psi and 15 min - 141K/336 psi. POOH. All shots fired/Gun was wet. Rig down for the night. Will be back in am. Put soap launcher back on and turn well over to field. _____________________________________________________________________________________ Updated by DMA 01-31-21 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730” Surf 106’ 13-3/8” Surface 68 /L-80 – J-55 /BTC 12.415” Surf 2,510’ 9-5/8" Intermediate 40 / L-80 / BTC 8.835” Surf 7,447’ 5-1/2" Production 17 / P-110 / CDC-DWC 4.892” Surf 12,841’ JEWELRY DETAIL No Depth ID Item 1 4,295’ 7.0” 9-5/8” Swell Packer 2 6,084’ 2.313” 2-7/8” Sliding Sleeve [CLOSED] (Shift Up to Open) 12/23/20 3 6,097’ 2.390” 2-7/8” x 5-1/2” Retrievable Packer (45K# Shear) 4 6,114’ 2.313” 2-7/8” X Profile Nipple 5 9,041’ 2.441” 2-7/8” WLEG 6 10,950’ N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’ N/A CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Gun Size Date Comments B31C 8,952 8966’ 8,263 8,276’ 14 2” 1/14/21 Open B32 9,020 9,032’ 8,330’ 8,338’ 12 2” 1/14/21 Open T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 2-7/8” 5/19/20 Open 9,083’ 9,097’ 8,565’ 8,579’ 14’ 2” 1/13/21 Open T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 2-7/8” 5/19/20 Open 9,224’ 9,231’ 8,669’ 8,706’ 7’ 2” 1/13/21 Open T4 9,451’ 9,462’ 8,916’ 8,927’ 11’ 2” 1/13/21 Open 9,452’ 9,462’ 8,916’ 8,925’ 10’ 2-7/8” 5/18/20 Open T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 2-7/8” 5/18/20 Open T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 2-7/8” 5/18/20 Open 9,979’ 9,996’ 9,416’ 9,432’ 17’ 2” 1/14/21 Open T19 10,898’ 10,937’ 10,290’ 10,328’ 39’ 2” 1/13/21 Open 10,898’ 10,937’ 10,290’ 10,328’ 39’ 2” 1/14/21 Open 10,899’ 10,923’ 10,293’ 10,315’ 24’ 2-7/8” 5/9/20 Open 10,923’ 10,937’ 10,315’ 10,328’ 14’ 2-7/8” 5/9/20 Open T19A 10,957’ 10,970’ 10,347’ 10,359’ 23’ 3-1/8” 4/13/20 Isolated T66 12,683’ 12,708’ 12,003’ 12,027’ 25’ 3-1/8” 4/8/20 Isolated TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8" Velocity 6.5 / L-80 / 8RD EUE 2.44” Surf 9,041’ B31C 8,952 8966’8,263 8,276’14 2” 1/14/21 Open B32 9,020 9,032’ 8,330’ 8,338’12 2” 1/14/21 Open New perfs CIBP remnants pushed to PBTD, Dec 2020. 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,850'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 7,460psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng todd.sidoti@hilcorp.com 12,166'10,950'10,340'2,881 10,950' Swell Pkr; N/A 4,295' MD/4,208' TVD; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 219-188 50-133-20579-01-00 Beaver Creek Unit (BCU) 19RD Beaver Creek Unit / Tyonek Gas Pool Length Size CO 237B Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 6.5# / L-80 TVD Burst 9,041' 10,640psi MD 5,750psi 3,060psi 3,450psi 106' 2,509' 7,057' 106' 2,510' 12,157'5-1/2" 20" 13-3/8" 106' 9-5/8"7,447' 2,510' 12,841' Perforation Depth MD (ft): 7,447' See Attached Schematic 12,841' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: January 13, 2021 2-7/8" Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 2:57 pm, Jan 06, 2021 321-003 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2021.01.06 14:43:56 -09'00' Taylor Wellman X 10-404 gls 1/7/21 Perforate DSR-1/6/21DLB 01/06/2021Comm 1/8/21 dts 1/7/2021 JLC 1/7/2021 RBDMS HEW 1/11/2021 Well Prognosis Well: BCU-19RD Date: 1/5/2021 Well Name: BCU-19RD API Number: 50-133-20579-01-00 Current Status: Sidetrack Leg: N/A Estimated Start Date: 1/13/2021 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-188 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number: Max. Expected BHP: 3,750 psi @ 8,699’ TVD (Based on Geotap Reading) Max. Anticipated Surface Pressure: 2,881 psi (BHP - 0.1 psi/ft gas gradient to surface) Brief Well Summary Beaver Creek Unit #19RD is a producing gas well that was recently drilled. The well’s production rate quickly dropped off due to a water influx causing the 5-1/2 Inch monobore to load up. A 2-7/8” velocity string was ran in the well in order to reduce the liquid unloading rate for the well. The through tubing plug milling operation with CTU was not successful in removing the CIBPs set prior to running the velocity string. 401 was mobilized to work the well over. The plugs were removed and a velocity string was re-installed. The purpose of this work is to re-perforate zones that may have been damaged during the workover. E-line Procedure 1. MIRU E-line. Pressure test lubricator to 250 psi low / 3500 psi high. 2. Perforate per the table below from the top down with 2-1/8” Shogun Spiral strip guns. Zone Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Tyonek T1XX ±9,083’ ±9,097’ ±8,565’ ±8,579’ 14’ Tyonek T1X ±9,224’ ±9,231’ ±8,699’ ±8,706’ 7’ Tyonek T4 ±9,451’ ±9,462’ ±8,916’ ±8,927’ 11’ Tyonek T7B ±9,846’ ±9,862’ ±9,291’ ±9,307’ 16’ Tyonek T8 ±9,979’ ±9,996 ±9,416’ ±9,433’ 17’ Tyonek T19 ±10,898’ ±10,937’ ±10,289’ ±10,328’ 39’ a. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation (Ben Siks- Geologist, Trudi Hallett – Reservoir Engineer). 3. POOH. RD E-line. 4. Turn well over to production. Attachments: 1. Current Schematic Re-perforating these zones. Post RWO _____________________________________________________________________________________ Updated by TCS 1-2-21 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730” Surf 106’ 13-3/8” Surface 68 /L-80 – J-55 /BTC 12.415” Surf 2,510’ 9-5/8" Intermediate 40 / L-80 / BTC 8.835” Surf 7,447’ 5-1/2" Production 17 / P-110 / CDC-DWC 4.892” Surf 12,841’ JEWELRY DETAIL No Depth ID Item 1 4,295’ 7.0” 9-5/8” Swell Packer 2 6,084’ 2.313” 2-7/8” Sliding Sleeve (Shift Up to Open) 3 6,097’ 2.390” 2-7/8” x 5-1/2” Retrievable Packer (45K# Shear) 4 6,130’ 2.313” 2-7/8” X Profile Nipple 5 9,041’ 2.441” 2-7/8” WLEG 6 10,950’ N/A Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 7 12,660’ N/A CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Comments T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 5/19/20 2-7/8” T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 5/19/20 2-7/8” T4 9,452’ 9,462’ 8,916’ 8,925’ 10’ 5/18/20 2-7/8” T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 5/18/20 2-7/8” T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 5/18/20 2-7/8” T19 10,899’ 10,923’ 10,293’ 10,315’ 24’ 5/9/20 2-7/8” T19 10,923’ 10,937’ 10,315’ 10,328’ 14’ 5/9/20 2-7/8” T19A 10,957’ 10,970’ 10,347’ 10,359’ 23’ 4/13/20 3-1/8” Isolated T66 12,683’ 12,708’ 12,003’ 12,027’ 25’ 4/8/20 3-1/8” Isolated TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8" Velocity 6.5 / L-80 / 8RD EUE 2.44” Surf 9041’ T1XX 9,083’9,093’8,566’8,575’10’5/19/20 2-7/8” T1X 9,224’9,229’8,699’8,704’ 5’5/19/20 2-7/8” T4 9,452’9,462’8,916’8,925’10’ 5/18/20 2-7/8” T7B 9,850’9,860’9,295’9,304’10’ 5/18/20 2-7/8” T8 9,979’9,994’9,416’9,430’15’ 5/18/20 2-7/8” T19 10,899’ 10,923’10,293’ 10,315’ 24’5/9/20 2-7/8” T19 10,923’ 10,937’10,315’ 10,328’ 14’5/9/20 2-7/8” Reperfing 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: Install Velocity String & N2 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,850'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 7,460psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng todd.sidoti@hilcorp.com 12,166'10,950'10,340'2,881 10,950' Swell Pkr; N/A 4,295' MD/4,208' TVD; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 219-188 50-133-20579-01-00 Beaver Creek Unit (BCU) 19RD Beaver Creek Unit / Tyonek and Beluga Gas Pools Length Size CO 237A & CO 237B Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY N/A TVD Burst N/A 10,640psi MD 5,750psi 3,060psi 3,450psi 106' 2,509' 7,057' 106' 2,510' 12,157'5-1/2" 20" 13-3/8" 106' 9-5/8"7,447' 2,510' 12,841' Perforation Depth MD (ft): 7,447' See Attached Schematic 12,841' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: December 15, 2020 N/A Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:42 am, Nov 25, 2020 320-500 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.24 16:51:32 -09'00' Taylor Wellman Tyonek and Beluga Gas Pools DSR-11/25/2020 SFD 11/25/2020 *3000 psi BOPE test (401) *4000 psi BOPE test (CTU) 10-404 Perforate Perforate New Pool SFD 11/25/2020 401 / CTU X SFD 11/25/2020 gls 11/30/20 Comm. 12/1/2020 dts 12/2/2020 JLC 12/1/2020 RBDMS HEW 12/2/2020 Well Prognosis Well: BCU 19RD Date: 11/12/2020 Well Name: BCU 19RD API Number: 50-133-20579-01-00 Current Status: Gas Well Leg: Estimated Start Date: 12/10/2020 Rig: HAK 401 Reg. Approval Req’d? Yes: 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-188 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907)-632-4113 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985)-867-0665 (C) AFE Number: Max. Expected BHP: ~ 3750 psi @ 8699’ TVD Geotap pressure measurement Max. Potential Surface Pressure: ~ 2881 psi (0.1 psi/ft gas gradient to surface) Brief Well Summary Beaver Creek Unit #19RD is a producing gas well that was recently drilled. The well’s production rate quickly dropped off due to a water influx causing the 5-1/2 Inch monobore to load up. A 2-7/8” velocity string was ran in the well in order to reduce the liquid unloading rate for the well. The through tubing plug milling operation with CTU was not successful in removing the CIBPs set prior to running the velocity string. The purpose of this work is to pull the velocity string, mill up the CIBPs, re-install a velocity string with a packer and add Beluga perforations. Well Condition - Well is currently plugged back @ 10,946’ MD with a cement capped CIBP. - A CIBP with a ~2.34” hole cored through it is set at 9055’ CTMD. - A CIBP has been pushed down to 9278’ CTMD. - A 2-7/8” velocity string is installed down to 9043’ MD. Procedure Rig 401 1. MIRU 401 Work over rig. 2. Load well with 6% KCL by pumping down the 2-7/8” velocity string and the 2-7/8” x 5-1/2” annulus. a) Hole volume with velocity string installed is ~195 bbls from surface to CIBP set @ 9278’ 3. Set TWC. 4. ND production tree, NU 7-1/16” BOP and test to 250 psi low & 3000 psi high, annular to 250 psi low & 2500 psi high. a) Notify AOGCC 24 hours in advance of test to extend the opportunity to witness. b) Test rams on 2-7/8” test joint. c) Record accumulator pre-charge pressures and chart tests. d) Submit completed form 10-424 to AOGCC within 5 days of BOPE test. 5. Pull TWC. 6. Stab landing joint into hanger, pull 2-7/8” velocity string & rack back. a) Velocity string is 2-7/8” 6.5# L-80 EUE. 7. PU & RIH with BHA including 4.80” 5 blade junk mill. 8. Mill up CIBPs at 9056’ and 9278’ and push down to PBTD. 9. PU & RIH with 2-7/8” completion. 10. Land tubing in hanger to position packer at ~6120’. Run in lockdown pins. 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J<7; J<<;’/5"),4!4J4! ?<K 7;K%!/!,@#############*&,C;<(@!,#+$-0&)/(#’/+#’""#(@)#!/%$*&’(!$/#-$/(’!/)+#@)*)!/#!,#(@)#,$")#’/+#)4-"0,!H)#.*$.)*(2#$%#!/()5*’()+#)10!.&)/(#’/+#,@’""#/$(# )#0,)+3#+!,-"$,)+3#$*#-$.!)+#=!(@$0(#(@)#)4.*),,#=*!(()/#.)*&!,,!$/#$%#!/()5*’()+#)10!.&)/(J#(@!,#+$-0&)/(#!,#"$’/)+.0*,0’/(#($#’5*))&)/(#($#(@)#%$*)5$!/5#’/+#,@’""# )#*)(0*/)+#($#!/()5*’()+#)10!.&)/(J#0.$/#+)&’/+3#!/()5*’()+#)10!.&)/(#*),)*H),#(@)#*!5@(#($#-@’/5)#+),!5/,3#&’()*!’",3#’/+#,.)-!%!-’(!$/,#=!(@$0(#/$(!-)J*)H:#:,@))(7#87# !"#$%&"#’)10!.&)/()-//$J,(’-D# $.3#6#7879L:#;D####J<?<#&!/!&0&#J<7;#&’4!&0&-$/-)/(*!-!(2-$*/)*#*’+!! *)’D#,@’*.#)+5),#J<7<#!/#7<LJ.’*’"")"!,&#J<7<#!/#7<LJ#J<7<#(J!J*J,10’*)/),,+$#/$(#,-’")#(@!,#+*’=!/5J’""#+!&)/,!$/,#!/#!/-@),J’""#%"’/5)#+*!""!/5#&0,(#,(*’++")#-$&&$/#-)/()*"!/)J*%,#)4-).(#=@)/###&###&$+!%!)+J+*’=!/5#!,#’#(@!*+’/5")#.*$M)-(!$/J 2)-/#+),-*!.(!$/+’().’*(#/$J?7:<<77E6A9;J?BA?<J>BAC>JFB77C7 Coiled Tubing Services Pressure Category 1 BOP Configuration (0-3,500 psi) Client: Hilcorp Date: April 3rd, 2017 Drawn: Chad Barrett Revision: 0 Well Category: CAT I 4-1/16" 10K Combi BOP Top Set: Blind/Shear Second Set: Pipe/Slip Wellhead 4-1/16" 10K Conventional Stripper 4-1/16" 10K x Wellhead Adapter Flange 5K CO62 x 4-1/16" 10K Flange 5K CO62 Lubricator 4-1/16" 10K Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange 21 3 4 WH PSI 2" 1502 x 2-1/16 10K Flanged Valve (Manual) 2-1/16 10K x 2-1/16 10K Flanged Valve (Manual) Kill Port Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs Beaver Creek Field BCU 19RD 11/12/2020 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. Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well BCU-19RD (PTD 219-188) Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Install Velocity String & N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: 9,056; 9,278; Total Depth measured 12,850 feet 10,950; 12,660 feet true vertical 12,166 feet N/A feet Effective Depth measured 10,950 feet N/A feet true vertical 10,340 feet N/A feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) V String 2-7/8" 6.5# / L-80 9,043' MD 8,527' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 4,295' MD 4,208' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 WINJ WAG 0 Water-Bbl MD 106' 2,510' 0 Oil-Bbl measured true vertical Packer 5-1/2"12,841' 7,057' 12,157' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Beaver Creek / Tyonek Gas PoolN/A measured TVD Tubing Pressure 00 Beaver Creek Unit (BCU) 19RD N/A FEDA 028083 7,447' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-188 50-133-20579-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-374 332 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Authorized Signature with date: Authorized Name: 0 Casing Pressure Liner 213 0 Representative Daily Average Production or Injection Data 106' 2,510' 7,447' 12,841' Conductor Surface Intermediate Production 7,460psi Casing Structural 20" 13-3/8" 9-5/8" Length 5,750psi 3,450psi Collapse 1,500psi 1,950psi 3,090psi todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 3,060psi 10,640psi 106' 2,509' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 3:29 pm, Nov 18, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.18 13:43:04 -09'00' Taylor Wellman RBDMS HEW 11/20/2020 11/23/20 gls DSR-11/19/2020 SFD 11/24/2020 Rig Start Date End Date 9/18/20 10/24/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 09/18/2020 - Friday 09/22/2020 - Tuesday PTSM, check well no pressure build, filled 1 bbl, set BPV. N/D tree. N/U 11" 5M x 7-1/16" 5m tubing head over 5-1/2" tubing hanger neck, test void 250/5,000,. N/U BOPE, install 11" x 7-1/16" xo spool, flow cross, double-gate & annular, tq flange bolts t/spec. r/u choke & kill lines. R/U accumulator lines, pressure up accumulator, function test BOPE. R/U floor, stairs, hand rails. M/U test joint, fill surface eq. w/ test water, shell test 2-7/8" TJ, had leak on HCR body, started mobing a replacement. shell test rest of stack 250/3,000 good. Change out HCR valve. SDFN. 09/19/2020 - Saturday Safety meeting with rig crew and loader operator regarding completing rigging down and moving off location. Complete rigging down and securing equipment. Load trucking, personnel off location and moving to BCU-19. Move in and rig up on BCU-19. Lay Herculite, stage equipment, begin rigging up. 09/21/2020 - Monday PJSM, check well pressure= 400psi, bleed down t/ 280 psi built back up t/ 290 in 1 hour. Bleed pressure off well, shut in & r/u e-line, p/u GR/CCL, & 4.4GR/junk basket. P/T 250/3,500 good, RIH w/GR & tag 9,224', POOH l/d GR/junk basket. RIH w/ GR/CCL & weight bar t/ tag @ same 9,224', POOH, discuss options & decide to run a different manufactures plug. M/U CIBP w/running tool, GR/CCL. RIH w/CIBP, tie into perf log with RA marker, set top of plug @ 9,038.6', pu 30' rih tag plug on depth, POOH r/d e-line. R/U fill hole 26 bbls s/d. Monitor hole 30 min. R/U & test CIBP t/2,200 psi f/15min good, r/d test eq. secure well for night. Safety meeting with crew and Wellhead Specialists. Emphasis on working in dark, overhead lifts of tree equipment, hazards associated with opening to well. Complete rigging up support equipment. Suck water from cellar, take on fluids into reserve tank. Open tree cap valve to determine if gas packed, gas pressure of 2,900 psi. Rig up circulation and flow back lines, PT. Conduct Lube and Bleed to fluid pack well. Lube in 115 bbls using MGS, mix of gas and fluid returns each time opened up (well volume to CIBP 210 bbls). Close in well, allow gas to migrate up overnight. 09/20/2020 - Sunday Safety meeting with the crew, emphasis on controlling bleed from the well, working in dark, ensuring to blow down lines. Open to well, 2,750 psi. Attempt to bleed, gas and fluid returns. Resume Lube and Bleed process through MGS. Total volume pumped in 210 bbls (complete casing volume down to CIBP). Down on pumps, monitor well, flow out. Break circulation again through MGS times 2 to bleed gas. PT to 2,000 psi against CIBP, held. Conduct bleed after PT, gas bubble, bleed to 0 psi. Fill with 36 bbls to gain returns. Flow check to zero returns, fill across top, flow check and still have returns. Close in, pressure on well up to 60 psi. Open up, circ again to pressure up on well in attempt to flip gas. Pressure up to 2,500 psi, bled off quickly, leveled out at 1,000 psi. Bleed off, flow check, returns equal amount pumped in during pressuring up at 11 bbls. Discuss with ODE, develop plan forward to have E-Line come out for evaluation. Break circulation across top, 5.3 bbls to gain returns. Continue to circulate across top. Stop circulation, flow check, 1.6 bbls back and continued to have 2-3 finger flow with no drop off. Plan discussed was to blow down lines from possible freezing, let well sit overnight in attempt to allow gas to migrate to surface. Coordinate with E-line. SET ANOTHER CIBP 401 CIBP is leaking ?? ADD tubing head for 2 7/8" Rig Start Date End Date 9/18/20 10/24/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 09/23/2020 - Wednesday PTSM, check well static, r/u & setup for BOPE test, re-flood surface eq. Shell test 250/3,000 good. Test BOPE as per Hilcorp & AOGCC requirements, test was witnessed by inspector Austin McLeod, tested w/ 2-7/8" tj, 250/3,000 psi, had one FP on K-2 valve, tested PVT & gas system good. R/D test eq. blow down, pull test plug & break down test jt. Prepare to P/U & TIH with 2-7/8" production tbg. P/U & TIH with 2-7/8" EUE production tbg using hand slips & collar clamp until 10k pipe weight obtained. Continue TIH picking up 2-7/8" EUE production tbg. Total of 156 jts in hole @ 1800 hrs, depth = 4,875'. 09/24/2020 - Thursday Hold PTSM & Review jsa/s with rig personnel. Open well, well static. Continue picking up 2-7/8" 6.5# L-80 EUE tbg. Total of 281 jts in hole. P/U & install tbg hanger, P/U & S/O WT = 35K. Land out & hang off tbg with 35k on tbg hanger. End of WLEG @9,008.89' ORIGINAL KB MEASUREMENT. L/D tbg handling equipment, R/D hand rails, stairs, & rig floor. N/D hydril, double ram bop, mud cross, & dsa. Dress tbg spool & hanger, Install & N/U 3-1/16" X 5M production tree, confirm tree wing to flow line angle with Beaver Creek production lead. Test void & tree to 250/5,000, all held same. Rig released from BCU-19RD @ 1600 hrs. R/D pump, choke, & kill lines. Roll up Koomey lines, R/D pvt & gas detection equipment. Haul off all remaining fluids to G&I. Perform derrick inspection, scope in derrick & prep to lower onto carriage in the morning. Rest crew for night. 10/20/2020 - Tuesday Safety meeting with crew on rigging up. Discuss environmental practices, lifting operations, pressure during BOP test. MIRU with coil unit. Lay Herculite, stage and rig up circulation lines, take on fluids into tank. Conduct BOP test per procedure and Sundry. Test to 250 psi low / 4,000 psi high. Triplex pump failed, retrieve pump from Farmyard. Swap out and continue test. Secure well for evening. 10/21/2020 - Wednesday Safety meeting with crew, emphasis on working in icy and dark conditions, lifting ops, opening to well. Make up lubricator assembly. Re-head with slip on coil connector, pull test to 25k. Drift and prepare BHA. Attempt to pressure test circulation lines, coil, and BHA, lines frozen. Break apart lines and replace same. Thaw Chicksans and hard line that could not be replaced. Pressure test lines and BHA. Break apart lines and replace same. Thaw Chicksans and hard line that could not be replaced. Pressure test lines and BHA. MU Mill, stab on with lubricator and pressure test. Attempt to RIH, cannot get past hanger. Make 15 attempts using different setdown weights and minimum pump action. No go. Pop off, inspect BHA, no indication of damage. Make calls to wellhead company to ensure no BPV / TWC in tree hanger. Confirm all measurements of BHA, milk motor to rotate mill to different orientation. Stab on, PT lubricator, RIH, "pop" thru. Discuss timing of operation with Field Operator. Decide to blowdown and freeze protect surface equipment and tree with methanol, start early in next morning. Secure well for evening. CTU on well 401 Rig Start Date End Date 9/18/20 10/24/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 10/23/2020 - Friday Safety Meeting with crew, emphasis on using right tools for heading up coil, making up new BHA. Rig up Lubricators with additional extension due to BHA length. Head up with coil connector, pull test to 25k. MU BHA, break circulation to fill coil. PT lines and BHA. Make up motor, function test at surface, good test. Stab on, PT lubricator. RIH with Milling BHA: Dual Flapper Check Valve, Bi-Directional Jars, Hydraulic Disconnect, Circulation Sub, 2-1/8" motor, Under-Reamer tool with 3.70" lower Reamers and 4.75" upper Reamers, 2.30" Concave Mill. Record weight checks, exit tubing. Dry tag at 9,055' and set down with 30k. No movement. Make several attempts to run into and set down and move plug, no go. Pick up, come on with pumps. Move down, slight motorwork but no indication of reaming through. Vary flow rates, set down weights with no movement. Measurements are that 2.30" mill and first set of 3.70" reamer blades are through plug based upon initial tag depth. POH with workstring. Change out BHA, pull Under Reamer assembly and swap out to 2.32" Concave Mill. Stab back on, PT lubricator. RIH with Milling BHA. Tag up on CIBP at 9055'. Attempt to push plug down, no-go. Bring on pumps, immediately roll through. Down on pumps, RIH to tag at 9247'. Make attempts to push down, jar down, no-go. Begin milling, no progress for 4 hours. POH. Tag upper mill dry and confirm depth. POH with milling BHA. Function test Motor, worked but indicated wear. Stand back lubricators. Secure well. 10/22/2020 - Thursday PJSM with crew, emphasis on rigging up in dark and icy conditions, lifting ops. MU Milling BHA: Dual Flapper Check Valve, Bi-Directional jars, Hydraulic Disconnect, Circulation Sub, 2-1/8" motor, Under reamer with 3.5" lower and 4.75" upper blades, 2.30" Concave Mill. RIH with BHA, tag CIBP at 9,050' MD. Pick up, pull into tubing, go back down and confirm. Conduct milling operations per Yellow Jacket rep. Vary pump and weight parameters while milling. Initial milling went well, punched through fairly quickly. First set of 3.5" Under reamer also reamed through fairly quickly. Second set of 4.75" Under reamer worked through slowly. POH with BHA. Function test motor at surface. Motor is strong, mill and reamers show wear but functioned as expected. Cut 50' of coil due to fatigue from cycling. blow down with Nitrogen. Secure well. CTU Rig Start Date End Date 9/18/20 10/24/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-19RD 50-133-20579-01-00 219-188 10/24/2020 - Saturday Safety Meeting with crew. Emphasis on fatigue, testing tools. Conduct walkaround, prep equipment. MU BHA, pressure test. MU Motor, test motor, good test but leak above. Chase leak, jars are leaking. Swap out and re-pressure test. Stab on with lubricator, pressure test. RIH with Milling BHA: Dual Flapper Check Valve, Bi-Directional jars, Hydraulic Disconnect, Circulation sub, 2-1/8" motor, 2.32" 5-Blade Junk Mill. Tag first plug at depth of 9,056' and able to set down. Pick up, come on with pumps and roll right through plug. continue to move down to second plug, tag up at 9,250'. On with pumps, attempt to mill ahead, no progress. After third stall, pick up, set down and plug begins to move down hole. Set down with steady 30k and plug moving slowly downhole. Movement stopped at 9,278', attempt to jar down, no movement. Bring on pumps to attempt milling again. Continue with attempts to push down with SOW and backside pressure, no-go. Discuss with Engineer and Lead Operator, blow down well w/Nitrogen. Prepare to blow down with Nitrogen. Drop ball to open circ sub, cannot move down past CIBP at 9,050'. Begin blow down from 9,050'. Make several attempts, very slow process. POH with milling BHA. Lay Down BHA, recover ball. Stand back lubricators, secure well. SLB crew have all houred-out for DOT standards so equipment cannot be moved. Will return on Monday morning to RDMO to KU 24-32. CTU _____________________________________________________________________________________ Updated by TCS 11-12-20 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730” Surf 106’ 13-3/8” Surface 68 /L-80 – J-55 /BTC 12.415” Surf 2,510’ 9-5/8" Intermediate 40 / L-80 / BTC 8.835” Surf 7,447’ 5-1/2" Production 17 / P-110 / CDC-DWC 4.892” Surf 12,841’ JEWELRY DETAIL No Depth Item 1 4,295’ 9-5/8” Swell Packer 2 9,056’ CIBP with 2.4” hole cored through (set 10/21/2020) 3 9,278’ CIBP (set 10/14/2020) 4 10,950’ Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 5 12,660’ CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Comments T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 5/19/20 2-7/8” T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 5/19/20 2-7/8” T4 9,452’ 9,462’ 8,916’ 8,925’ 10’ 5/18/20 2-7/8” T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 5/18/20 2-7/8” T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 5/18/20 2-7/8” T19 10,899’ 10,923’ 10,293’ 10,315’ 24’ 5/9/20 2-7/8” T19 10,923’ 10,937’ 10,315’ 10,328’ 14’ 5/9/20 2-7/8” T19A 10,957’ 10,970’ 10,347’ 10,359’ 23’ 4/13/20 3-1/8” Isolated T66 12,683’ 12,708’ 12,003’ 12,027’ 25’ 4/8/20 3-1/8” Isolated TUBING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 2-7/8" Velocity 6.5 / L-80 / 8RD EUE 2.44” Surf 9,043’ 2-7/8" Velocity 6.5 / L-80 / 8RD EUE 2.44” Surf 9,043’ CIBP 2.4"hole PUSHED FROM ???????TO 9278 WITH CT CIBP moved from uphole... leaking SET9/21/20 STATE OF ALASKA Reviewed By: :Ac— OIL AND GAS CONSERVATION COMMISSION P.I. Supry 1, ?2 BOPE Test Report for: BEAVER CK UNIT 19RD ' Comm Contractor/Big No.: Hilcorp 401 - Operator: Hilcorp Alaska, LLC Type Operation: WRKOV Sundry No: Type Test: INIT 320-374 - MISC. INSPECTIONS: PTD#: 2191880 ' DATE: 9/23/2020 Operator Rep: Harold Soule Test Pressures: Rams: Annular- Valves- MASP: 250/3000 " 250/3000' 250/3000' 2881- TEST 881- TEST DATA MUD SYSTEM: Visual Alarm Trip Tank NA, NA Pit Level Indicators P/F Location Gen.: P Housekeeping: P PTD On Location P_ Standing Order Posted P Well Sign P _ _ Drl. Rig P Hazard Sec. NA _ Misc NA PTD#: 2191880 ' DATE: 9/23/2020 Operator Rep: Harold Soule Test Pressures: Rams: Annular- Valves- MASP: 250/3000 " 250/3000' 250/3000' 2881- TEST 881- TEST DATA MUD SYSTEM: Visual Alarm Trip Tank NA, NA Pit Level Indicators IF r Flow Indicator NA NA Meth Gas Detector P_ ' P ' H2S Gas Detector P P _ MS Misc NA NA Inspector Austin McLeod Insp Source Rig Rep: Chris Hannevold Inspector Inspection No: bopSAM200926110936 Related Insp No: ACCUMULATOR SYSTEM: BOP STACK: Time/Pressure P/F System Pressure _ 3025 P_ Pressure After Closure 2100 P 200 PSI Attained 45 P Full Pressure Attained 166_ P Blind Switch Covers: All stations P Nitgn. Bottles (avg): __1900__ P ACC Mise 0 NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly 0 - NA,_ Stripper 0 NA No. Valves 8 - P _ Lower Kelly ---0- NA_, Annular Preventer 1 _11." _ _ —P _ Manual Chokes 2 P - Ball Type _ 1 P _ #1 Rams - 1 2-7/8"x5" P Hydraulic Chokes 0 - NA Inside BOP 1 P, #2 Rams 1 Blinds P CH Misc 0 NA FSV Misc 0 NA #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA INSIDE REEL VALVES: #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1- 2-1/16" P - Quantity P/F HCR Valves 1 2-1/16' P Inside Reel Valves 0 NA Kill Line Valves 3 ' 2-1/16" FP Check Valve 0 NA BOP Misc 0 NA Number of Failures: 1 f Test Results Test Time 3 Remarks: 2-7/8" joint. No tubing in well currently. Running 2-7/8" completion. K-2 passed retest after cvraled. 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: Install Velocity String & N2 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 12,850'N/A Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 7,460psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: September 18, 2020 N/A 12,841' Perforation Depth MD (ft): 7,447' See Attached Schematic 12,841' 12,157'5-1/2" 20" 13-3/8" 106' 9-5/8"7,447' 2,510' 3,060psi 3,450psi 106' 2,509' 7,057' 106' 2,510' N/A TVD Burst N/A 10,640psi MD 5,750psi Length Size CO 237A & CO 237B Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 219-188 50-133-20579-01-00 Beaver Creek Unit (BCU) 19RD Beaver Creek Unit / Tyonek Gas Pool COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic tkramer@hilcorp.com 12,166'10,950'10,340'2,881 10,950' Swell Pkr; N/A 4,295' MD/4,208' TVD; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 3:17 pm, Sep 11, 2020 320-374 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.09.11 13:42:40 -08'00' Taylor Wellman 10-404 SFD 9/11/2020 X Install Velocity String & N2 401/CT *3000 psi BOPE test (401) *4000 psi BOPE test (CT) gls 9/15/20 DSR-9/15/2020Comm. 9/16/2020 dts 9/16/2020 JLC 9/16/2020 RBDMS HEW 9/17/2020 Install V String Well: BCU-19RD Date: 9/3/2020 Well Name: BCU-19RD API Number: 50-133-20579-01-00 Current Status: Gas Well Leg: N/A Estimated Start Date: 9/18/2020 Rig: Rig 401 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-188 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) Second Call Engineer: Ryan Rupert (907) 777-8503 (O) (907) 301-1736 (M) AFE Number: Max. Expected BHP: 3,750 psi @ 8,699’ TVD (Based on Geotap Reading) Max. Anticipated Surface Pressure: 2,881 psi (Based on Max. BHP minus 0.1 psi/ft gas gradient to Surface) Brief Well Summary Beaver Creek Unit #19RD is a producing gas well that was recently drilled. Production rate is dropping in the well due to a water influx causing the 5-1/2 Inch monobore to load up. The purpose of this work/sundry is to run and set a 2-7/8” velocity string in the well to reduce the liquid unloading rate for the well. E-line Procedure 1. MIRU E-line. Pressure test lubricator to 250 psi low/ 3,500 psi high. 2. PU, RIH W/ plug to 9,060’ (+/-). Set same. POOH W/ E-line. (Note: No open perforations at this point.) 3. Fill hole W/ 3% KCL fluid equivalent (Note: Fluid Weight is still 8.4 PPG). Rig 401 Procedure Well Head Change for Tubing Spool 1. ND 11” 5M tree adapterand tree. 2. Install new 11” 5M x 7 1/16 5M tubing head over 5 1/2 tubing hanger neck. 3. Test tubing head to 250/5000psi—-this isolates and tests your 11” 5M break on the ring gasket also. 4. Nipple Up BOP. 5. Install test plug in new 11” 5M x 7 1/16 5M tubing head. 6. Test BOPE on 2-7/8” Test Joint. 7. Retrieve test plug and remove 5” bpv from 5 1/2 tubing hanger. a. Submit completed form 10-424 to AOGCC within 5 days of BOPE test. Copy to BLM. 8. PU RIH W 2-7/8” Tubing string to 9,043’. Hang off tubing. 9. ND Bop, NU Well head and test. 10. RDMO Rig 401. Coil Tubing 1. MIRU Coiled Tubing Unit (CTU), onto the 2-7/8” tubing wellhead. 2. Pressure test BOPs to 4,000 psi. 3. PU Motor, under reamer, and mill, RIH to Plug @ 9,060’. Establish parameters, Mill up plug and push to bottom. RIH to 10,950’. CBU W/foam and N2 to lift/blow dry well. POOH W/ Motor and mill. 4. POOH with coiled tubing. 5. RDMO CTU. (3000 psi BOPE test ) updated 9/15/20 (notify inspector to witness CT BOPE test ) 3a. Test plug to 2000 psi (15 min / chart) 8.3 ppg EMW *set TWC/BPV and test (5 1/2 hanger) updated 9/15/20 Install V String Well: BCU-19RD Date: 9/3/2020 6. Turn well over to production. 7. Return well to service. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. Rig 401 BOP Stack 4. Coil BOP stack 5. Wellhead Drawing 6. Standard Well Procedure – N2 Operations 7. RWO Sundry Revision Change Form updated 9 15/20 Install V String Well: BCU-19RD Date: 9/3/2020 Well Name: BCU-19RD API Number: 50-133-20579-01-00 Current Status: Gas Well Leg: N/A Estimated Start Date: 9/18/2020 Rig: Rig 401 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-188 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) Second Call Engineer: Ryan Rupert (907) 777-8503 (O) (907) 301-1736 (M) AFE Number: Max. Expected BHP: 3,750 psi @ 8,699’ TVD (Based on Geotap Reading) Max. Anticipated Surface Pressure: 2,881 psi (Based on Max. BHP minus 0.1 psi/ft gas gradient to Surface) Brief Well Summary Beaver Creek Unit #19RD is a producing gas well that was recently drilled. Production rate is dropping in the well due to a water influx causing the 5-1/2 Inch monobore to load up. The purpose of this work/sundry is to run and set a 2-7/8” velocity string in the well to reduce the liquid unloading rate for the well. E-line Procedure 1. MIRU E-line. Pressure test lubricator to 250 psi low/ 3,500 psi high. 2. PU, RIH W/ plug to 9,060’ (+/-). Set same. POOH W/ E-line. (Note: No open perforations at this point.) 3. Fill hole W/ 3% KCL fluid equivalent (Note: Fluid Weight is still 8.4 PPG). Rig 401 Procedure 4. ND wellhead, NU BOP and test to 250 psi low & 3,500 psi high, annular to 250 psi low & 2,500 psi high. Record accumulator pre-charge pressures and chart tests. a. Perform Test. b. Test Dual VBR rams on 2-7/8” test joint. c. Submit completed form 10-424 to AOGCC within 5 days of BOPE test. Copy to BLM. 5. PU RIH W 2-7/8” Tubing string to 9,043’. Hang off tubing. 6. ND Bop, NU Well head and test. 7. RDMO Rig 401. Coil Tubing 8. MIRU Coiled Tubing Unit (CTU), onto the 2-7/8” tubing wellhead. 9. Pressure test BOPs to 4,000 psi. 10. PU Motor, under reamer, and mill, RIH to Plug @ 9,060’. Establish parameters, Mill up plug and push to bottom. RIH to 10,950’. CBU W/foam and N2 to lift/blow dry well. POOH W/ Motor and mill. 11. POOH with coiled tubing. 12. RDMO CTU. 13. Turn well over to production. 14. Return well to service. SUPERCEDED 8.3 ppg EMW el 2 In ru e t 9, KCL ad d ac a l -0 18 (98 MW l t mo 7/8 0 p (No 8.4 to 2 Na Sta Sta l R ac ure ll SUPERCEDED 4.Test plug 1500 psi /15 min chart No packer Install V String Well: BCU-19RD Date: 9/3/2020 Attachments: 1. As-built Schematic 2. Proposed Schematic 3. Rig 401 BOP Stack 4. Coil BOP stack 5. Wellhead Drawing 6. Standard Well Procedure – N2 Operations 7. RWO Sundry Revision Change Form e Form _____________________________________________________________________________________ Updated by DMA 06-05-20 SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730” Surf 106’ 13-3/8” Surface 68 /L-80 – J-55 /BTC 12.415” Surf 2,510’ 9-5/8" Intermediate 40 / L-80 / BTC 8.835” Surf 7,447’ 5-1/2" Production 17 / P-110 / CDC-DWC 4.892” Surf 12,841’ JEWELRY DETAIL No Depth Item 1 4,295’ 9-5/8” Swell Packer 2 10,950’ Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 3 12,660’ CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Comments T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 5/19/20 2-7/8” T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 5/19/20 2-7/8” T4 9,452’ 9,462’ 8,916’ 8,925’ 10’ 5/18/20 2-7/8” T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 5/18/20 2-7/8” T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 5/18/20 2-7/8” T19 10,899’ 10,923’ 10,293’ 10,315’ 24’ 5/9/20 2-7/8” T19 10,923’ 10,937’ 10,315’ 10,328’ 14’ 5/9/20 2-7/8” T19A 10,957’ 10,970’ 10,347’ 10,359’ 23’ 4/13/20 3-1/8” Isolated T66 12,683’ 12,708’ 12,003’ 12,027’ 25’ 4/8/20 3-1/8” Isolated _____________________________________________________________________________________ Updated by DMA 06-05-20 PROPOSED SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730” Surf 106’ 13-3/8” Surface 68 /L-80 – J-55 /BTC 12.415” Surf 2,510’ 9-5/8" Intermediate 40 / L-80 / BTC 8.835” Surf 7,447’ 5-1/2" Production 17 / P-110 / CDC-DWC 4.892” Surf 12,841’ JEWELRY DETAIL No Depth Item 1 4,295’ 9-5/8” Swell Packer 2 10,950’ Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 3 12,660’ CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Comments T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 5/19/20 2-7/8” T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 5/19/20 2-7/8” T4 9,452’ 9,462’ 8,916’ 8,925’ 10’ 5/18/20 2-7/8” T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 5/18/20 2-7/8” T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 5/18/20 2-7/8” T19 10,899’ 10,923’ 10,293’ 10,315’ 24’ 5/9/20 2-7/8” T19 10,923’ 10,937’ 10,315’ 10,328’ 14’ 5/9/20 2-7/8” T19A 10,957’ 10,970’ 10,347’ 10,359’ 23’ 4/13/20 3-1/8” Isolated T66 12,683’ 12,708’ 12,003’ 12,027’ 25’ 4/8/20 3-1/8” Isolated Coil Velocity String 2.875" 8rd EUE Velocity String. 2.441” I.D. EOT @ 9,043’ (+/-)' RKB swell packer Jointed tubing Velocity string 27/8" The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 11" Spherical Annular Height: 42" 11" LWS Double BOP 2-7/8" to 5" Multirams top Blind rams bottom Height:33" 11" Mud Cross W/ 4-1/16" Outlets Dual 2-1/16" Manual Gate Valves W/ DSA to 4-1/16" Width to flange: 34" 2-1/16" Manual Gate Valve & 2-1/16" HCR W/ DSA to 4- 1/16" Full Mud Cross Assy. width w/ valves installed Width: 96" Kill side Choke side BOP Stack Width: 96" @ valves Height Addition for Ring Gaskets: .75" BOP Total Height: 101.75" 11" 5m BOP Package W/ 2-1/16" Valves New Tubing spool for 2 7/8" SSV David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 CenterPoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE 9/14/2020 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL BCU-19RD PTD 219-188 Halliburton Plug Setting Record 4/27/2020 Please include current contact information if different from above. Received by the AOGCC 09/14/2020 PTD: 2191880 E-Set: 33836 Abby Bell 09/14/2020 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:CBL 3-11-20 / ROP, DGR, AGR, ABG, ADR, EWR MD & TVD, mudlogNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF4/22/20204350 12890 Electronic Data Set, Filename: BCU-19RD.las32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-10-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-11-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-12-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-13-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-14-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-15-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-16-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-17-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-18-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-19-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-20-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-21-20.pdf32778EDDigital DataWednesday, July 22, 2020AOGCCPage 1 of 13Supplied by OPSupplied by OPBCU-19RD.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-22-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-23-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-24-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-25-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-26-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-27-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-28-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-29-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-7-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-8-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: Hilcorp BCU 19RD Nabors AM Report 2-9-20.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD.dbf32778EDDigital DataDF4/22/2020 Electronic File: bcu19rd.hdr32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD.mdx32778EDDigital DataDF4/22/2020 Electronic File: bcu19rdr.dbf32778EDDigital DataDF4/22/2020 Electronic File: bcu19rdr.mdx32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD_SCL.DBF32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD_SCL.MDX32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD_tvd.dbf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD_tvd.mdx32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD Final Well Report.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in Drilling Dynamics Log MD.pdf32778EDDigital DataWednesday, July 22, 2020AOGCCPage 2 of 13 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoDF4/22/2020 Electronic File: BCU19RD - 5in Drilling Dynamics Log TVD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in Formation Log MD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in Formation Log TVD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in Gas Ratio Log MD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in Gas Ratio Log TVD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in LWD Combo Log MD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in LWD Combo Log TVD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Drilling Dynamics Log MD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Drilling Dynamics Log TVD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Formation Log MD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Formation Log TVD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Gas Ratio Log MD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Gas Ratio Log TVD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - LWD Combo Log MD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - LWD Combo Log TVD.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in Drilling Dynamics Log MD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in Drilling Dynamics Log TVD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in Formation Log MD.tif32778EDDigital DataWednesday, July 22, 2020AOGCCPage 3 of 13 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoDF4/22/2020 Electronic File: BCU19RD - 5in Formation Log TVD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in Gas Ratio Log MD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in Gas Ratio Log TVD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in LWD Combo Log MD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - 5in LWD Combo Log TVD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Drilling Dynamics Log MD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Drilling Dynamics Log TVD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Formation Log MD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Formation Log TVD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Gas Ratio Log MD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - Gas Ratio Log TVD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - LWD Combo Log MD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU19RD - LWD Combo Log TVD.tif32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 10850'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 10880'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 10885'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 10904'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 10915'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 10930'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 10940'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 10955'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 10971'.jpg32778EDDigital DataWednesday, July 22, 2020AOGCCPage 4 of 13 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoDF4/22/2020 Electronic File: BCU 19RD 10985'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11000'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11018'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11030'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11043'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11060'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11070'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11082'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11090'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11100'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11120'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11135'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11135'a.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11141'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11150'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11155'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11155'a.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 11155'b.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 5270'a.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 5330'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 5440'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 5480'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 5480'a.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 5500'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 5500'a.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6200'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6280'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6315'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6370'.jpg32778EDDigital DataWednesday, July 22, 2020AOGCCPage 5 of 13 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoDF4/22/2020 Electronic File: BCU 19RD 6415'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6437'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6450'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6480'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6485'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6495'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6500'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6515'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6530'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 6550'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7220'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7250'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7340'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7410'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7505'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7520'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7540'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7570'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7596'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7596'a.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD 7604'.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10080.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10100.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10140.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10155.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10250.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10260.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10300.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10315.jpg32778EDDigital DataWednesday, July 22, 2020AOGCCPage 6 of 13 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoDF4/22/2020 Electronic File: BCU-19RD_10820.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10885.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10930.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10940.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10955.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_10985.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11000.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11505.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11520.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11530.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11540.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11550.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11560.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11570.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11580.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11590.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11600.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11610.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11620.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11630.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11640.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11650.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11660.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11670.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11670a.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11670b.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11680.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11690.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11704.jpg32778EDDigital DataWednesday, July 22, 2020AOGCCPage 7 of 13 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoDF4/22/2020 Electronic File: BCU-19RD_11717.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11724.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11740.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11750.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11760.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_11770.jpg32778EDDigital DataDF4/22/2020 Electronic 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BCU-19RD_12300a.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_12315.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_12333.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_12350.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_12360.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_12370.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_12380.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_12390.jpg32778EDDigital DataWednesday, July 22, 2020AOGCCPage 8 of 13 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoDF4/22/2020 Electronic File: BCU-19RD_12410.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_12415.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_12420.jpg32778EDDigital DataDF4/22/2020 Electronic 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BCU-19RD_7190a.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_8502.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_8525.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_8534.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_8538.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_8750.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_8810.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_8840.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9230.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9245.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9260.jpg32778EDDigital DataWednesday, July 22, 2020AOGCCPage 9 of 13 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoDF4/22/2020 Electronic File: BCU-19RD_9320.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9335.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9410.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9440.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9455.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9470.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9470a.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9510.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9530.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9597.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9800.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9890.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU-19RD_9950.jpg32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 1 5234-5380.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 10 9299-9326.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 11 9451-9462.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 12 9478-9483.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 13 9575-9598.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 14 9789-9809.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 15 9845-9862.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 16 9979-9996.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 17 10571-10601.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 18 10613-10626.pdf32778EDDigital DataWednesday, July 22, 2020AOGCCPage 10 of 13 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 19 10729-10768.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 2 6020-6125.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 20 10826-10832.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 21 10890-10950.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 22 10952-10985.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 23 12683-12707.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 3 6150-6230.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 4 6490-6740.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 5 8495-8538.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 6 8952-8964.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 7 9010-9037.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 8 9083-9097.pdf32778EDDigital DataDF4/22/2020 Electronic File: BCU 19RD Gas Show Report 9 9224-9231.pdf32778EDDigital DataDF7/20/20203502 5855 Electronic Data Set, Filename: (3022) BCU 19RD, CBL, 3-11-2020, Field Log.las33555EDDigital DataDF7/20/2020 Electronic File: (3022) BCU 19RD, CBL, 3-11-2020, Field Log.pdf33555EDDigital Data0 0 2191880 BEAVER CK UNIT 19RD LOG HEADERS33555LogLog Header Scans0 0 2191880 BEAVER CK UNIT 19RD LOG HEADERS33556LogLog Header ScansDF7/20/20204452 12850 Electronic Data Set, Filename: BCU-19RD LWD Final.las33556EDDigital DataWednesday, July 22, 2020AOGCCPage 11 of 13BCU-19RD LWDFinal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:4/8/2020Release Date:12/18/2019DF7/20/2020 Electronic File: BCU-19RD LWD Final MD.cgm33556EDDigital DataDF7/20/2020 Electronic File: BCU-19RD LWD Final TVD.cgm33556EDDigital DataDF7/20/2020 Electronic File: BCU 19RD Surveys.xlsx33556EDDigital DataDF7/20/2020 Electronic File: BCU 19RD_Definitive Survey Report.pdf33556EDDigital DataDF7/20/2020 Electronic File: BCU 19RD_Definitive Survey Report.txt33556EDDigital DataDF7/20/2020 Electronic File: BCU 19RD_GIS.txt33556EDDigital DataDF7/20/2020 Electronic File: BCU 19RD_Plan.pdf33556EDDigital DataDF7/20/2020 Electronic File: BCU 19RD_VSec.pdf33556EDDigital DataDF7/20/2020 Electronic File: BCU-19RD LWD Final MD.pdf33556EDDigital DataDF7/20/2020 Electronic File: BCU-19RD LWD Final TVD.pdf33556EDDigital DataDF7/20/2020 Electronic File: BCU-19RD LWD Final MD.tif33556EDDigital DataDF7/20/2020 Electronic File: BCU-19RD LWD Final TVD.tif33556EDDigital Data7/9/20204464 128501747CuttingsWednesday, July 22, 2020AOGCCPage 12 of 13 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-133-20579-01-00Well Name/No. BEAVER CK UNIT 19RDCompletion Status1-GASCompletion Date4/8/2020Permit to Drill2191880Operator Hilcorp Alaska, LLCMD12850TVD12166Current Status1-GAS7/22/2020UICNoComments:Compliance Reviewed By:Date:Wednesday, July 22, 2020AOGCCPage 13 of 13M. Guhl 7/22/2020 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 7/16/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU-19RD PTD 219-188 CBL Please include current contact information if different from above. Received by the AOGCC 07/20/2020 PTD: 2191880 E-Set: 33555 Abby Bell 07/20/2020 Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 7/11/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU -19RD PTD 219-188 DGR ADR CTN ALD MD /TVD CD: HALLIBURTON FINAL ELECTRIC LOGS Please include current contact information if different from above. Received by the AOGCC 07/20/2020 PTD: 2191880 E-Set: 33556 Abby Bell 07/20/2020 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval: 9. Ref Elevations: KB: 17. Field / Pool(s): GL: 160.5' BF:160.5' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22. Logs Obtained: 23. BOTTOM 5-1/2" P-110 12,158' 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 N/AN/A SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 8-1/2" L - 485 sx / T - 1220 sx STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 4/8/2020 1196' FNL, 1657' FWL, Sec 34, T7N, R10W, SM, AK 1232' FSL, 2569' FWL, Sec 34, T7N, R10W, SM, AK 219-188 / 320-107 Beaver Creek Unit / Tyonek Gas Pool 178.5' 10,950' MD / 10,340' TVD HOLE SIZE AMOUNT PULLED 50-133-20579-01-00 BCU-19RD 317469 2433994 2332' FSL, 2624' FEL, Sec 34, T7N, R10W, SM, AK CEMENTING RECORD 2432227 SETTING DEPTH TVD 2431129 BOTTOM TOP Surface CASING WT. PER FT.GRADE 318445 318342 TOP SETTING DEPTH MD Surface Per 20 AAC 25.283 (i)(2) attach electronic information DEPTH SET (MD) N/A PACKER SET (MD/TVD) 17# 12,841' Gas-Oil Ratio:Choke Size:Water-Bbl: PRODUCTION TEST 5/1/2020 Date of Test: 0 5/25/2020 24 Flow Tubing 0 2538 Oil-Bbl: suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary N/A2538 Flowing **Please see attached schematic for perforation detail** 0 CBL 3-11-20 / ROP, DGR, AGR, ABG, ADR, EWR MD & TVD Sr Res EngSr Pet GeoSr Pet Eng N/A N/A Oil-Bbl: Water-Bbl: 00406 February 22, 2020 February 8, 2020 A028083 N/A N/A 4,464' MD / 4,352' TVDN/A N/A 12,850' MD / 12,166' TVD WINJ SPLUG Other Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 10:14 am, Jun 05, 2020 Completion Date 4/8/2020 HEW RBDMS HEW 6/9/2020 mudlog MDG SFD 6/11/2020 gls/6/22/20 G DSR-6/10/2020DLB 06/10/2020 G Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval 9,083' T1XX 8,566' 8,894' 8,387' 9,040' 8,524' 9,204' 8,681' 9,260' 8,734' 9,362' 8,831' 9,473' 8,937' 9,737' 9,188' 9,807' 9,254' 9,857' 9,302' 10,509' 9,923' 10,596' 10,005' 10,726' 10,128' 10,789' 10,188' T66 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS B-31C This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inc lination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager T5 T7A T1X Permafrost - Base Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME T7B Permafrost - Top T4 T1XX T8 Formation at total depth: T2 Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Survey, Csg and Cmt report. Signature w/Date: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. INSTRUCTIONS Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). T14 T15 T17 T18 Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2020.06.04 17:17:42 -08'00' Monty M Myers _____________________________________________________________________________________ Updated by CJD 06-04-20 PROPOSED SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730” Surf 106’ 13-3/8” Surface 68 /L-80 – J-55 /BTC 12.415” Surf 2,510’ 9-5/8" Intermediate 40 / L-80 / BTC 8.835” Surf 7,447’ 5-1/2" Production 17 / P-110 / CDC-DWC 4.892” Surf 12,841’ JEWELRY DETAIL No Depth Item 1 4,295’ 9-5/8” Swell Packer 2 10,950’ Halliburton EZ Drill Bridge Plug (4’ cmt on top) TOC 10,946’ MD 3 12,660’ CIBP (43’ cmt on top) TOC 12,617’ MD PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Comments T1XX 9,083’ 9,093’ 8,566’ 8,575’ 10’ 5/19/20 2-7/8” T1X 9,224’ 9,229’ 8,699’ 8,704’ 5’ 5/19/20 2-7/8” T4 9,452’ 9,462’ 8,916’ 8,925’ 10’ 5/18/20 2-7/8” T7B 9,850’ 9,860’ 9,295’ 9,304’ 10’ 5/18/20 2-7/8” T8 9,979’ 9,994’ 9,416’ 9,430’ 15’ 5/18/20 2-7/8” T19 10,899’ 10,923’ 10,293’ 10,315’ 24’ 5/9/20 2-7/8” T19 10,923’ 10,937’ 10,315’ 10,328’ 14’ 5/9/20 2-7/8” T19A 10,957’ 10,970’ 10,347’ 10,359’ 23’ 4/13/20 3-1/8” Isolated T66 12,683’ 12,708’ 12,003’ 12,027’ 25’ 4/8/20 3-1/8” Isolated CBL ran 3/11/20 Note: 9 5/8" window at 4464 ft MIT-IA 2000 psi TOC at 4000 ft 6/20/20 Activity Date Ops Summary 1/27/2020 Held PJSM with Peak operators and rig crew on tear out and rig move. Tore out degasser skid, all three pit modules, pumps and gen 1-2 skid. PU rig mats, removed ice and loaded same. Had rig mats pits and pumps on the road to BCU at 09:00 as per permit. Spotted crane, removed derrick hooch and;layed down windwalls. Removed choke house, spotted second crane, picked derrick off carrier, picked carrier off sub, picked sub off pony walls. Transported doghouse and gen skid to BCU, cont cleaning and loading mats and pony walls. transported sub, derrick, carrier, mats, pony walls and cranes;to BCU. No issue crossing the bridge. Set pony walls at cellar, spotted cranes, set sub on pony walls and centered up over wellhead, set carrier on sub, set derrick on carrier, stood "v-door" windwall, stood derrick windwalls and set hooch. SIMOPS: cut up and policed up liner and felt at Peak yard;Rest all hands for the night. No night crew. 1/28/2020 Held PJSM with Peak operators and rig crew. Started bed truck, crane, loaders and light plants. Staged crane and flew iron roughneck to rig floor. set pit mods 1 and 2. Flew choke house to rig floor, allowing rig Foreman to obtain measurements of sag of outriggers. Set pump skids, stood mast, set;doghouse skid and raised same, set gen 1-2 skid, took on rig fuel in gen skid tank, set both boiler skids, set pit mod #3, raised pit roof tops, layed out felt and liner for catwalk, set mat boards for catwalk, set catwalk and beaver slide. Flew windwall behind iron roughneck,;Fired up rig gen and turned on the lights, Peak welder finished up a handful of small projects, set feed pump and centrifuge, set degasser skid, set 4 trailers, genset and transformer, wired in and powered up same, hung a couple windwalls on pits and shut down for the night.;Rest all hands for the night. No night crew. 1/29/2020 Fired up rig gen and turned on lights, checked air system throughout the rig and pressured up same, heated up change shack genset and fired up, powered up safety shack, Peak on location at 7AM, warmed up crane, spotted and hung remaining windwalls on pits, installed tarps throughout the rig,;installed ventline on poor boy and raised same, shimmed end of poorboy skid to better align piping, rig Foreman brought out Atlas Rep to monitor air dryer system, Handy Berm installed around entire rig footprint, set liner and set gen 3, set service shacks, set liner and upright water tank near rig;water tank (for cementing), raised sub 1/2" to keep choke house outriggers off pit roof, set comm tower and RU comm’s, prepped drill line for spool up on drum, spooled drill line onto drum, installed standpipe bleeder and valve assembly on rig floor, policed up scrap liner around rig, had heater;trunk in covered cellar box most of the day to thaw any ice in wellhead.;Rest all hands for the night. No night crew. Night Drilling Foreman keeping watch over rig gen. 1/30/2020 Swapped out camp gen set, shutting down on fault, inspect and prep derrick to scope, scope derrick, Clean and prep to dress pumps w/ 5'' Liners, Set centrifuge control panel and hurricane vac, r/u derrick climber, hang lower torque tube and pin, Stage and P/U top drive to rig floor, hook up top;drive, service loop and Kelly hose, trouble shoot alignment issues with service loop and Kelly hose vs choke house wall, window and lights, build containment and lay liner for auxiliary fuel tank, set fuel tank inside containment, hook up power to third party service shacks, string cord out for;centrifuge control panel, Install/replace certified chart recorder in choke room.;Night Drilling foreman watching generators while Day crew rests 1/31/2020 Ridgeline crew started at 8AM, cont working on kelly hose adjustment, prepped boiler #1 to take on hot water, sent clean Peak vac truck to Swanson River for load of hot water, troubleshoot topdrive HPU electrical and started same, installed new hadrails on mezz deck, installed hardline from choke;manifold to degasser shock hose, obtained measurements for 2" gaurd over choke house wall lights and window, set liner, mat and upright water tank at water well on pad, Swaco Rep came out, removed shipping blocks from centrifuge and test ran OK, wired in Sperry shack,;Orient parker hands,Take on load of hot water to boilers, stage boiler temp and pressure up open steam around to rig and let boilers pressure up, open steam to rig, put heater trunk in boiler #2 begin warming it up, take on load of hot water to pill pit, clean and inspect pits f/ welding debris;Finish dressing pumps w/ 5'' Liners, clean and inspect valves and seats, peak off loading mud products and building drum storage docks 2/1/2020 Continue to warm rig w/ #1 boiler, Continue warm # 2 boiler and prep to fire same, continue work on de-gasser chg out of elect mtr. Install spacer spool on btm of single gate. set test plug. trouble shoot bridge cranes and re plumb same start to put water in pits,;Charge loader and chg out belt on same, Thaw ice and froze open valves, r/up Pason rig watch system, PTSM w/ new crew chg out and walk dn of rig, continue nip/up bopes, Continue warm rig w/ #1 boiler and continue to pre warm #2 boiler for fire up continue chg out of degasser elect mtr;Continue N/U BOP Stack, thawing pits and lines, Continue warming boiler #2, Fuel Boiler #2 and prep to fire, general house keeping around rig, turn steam loop on to water tank begin thawing;Continue tightening bolts on BOP Stack, both boilers online, chink holes around rig, continue working in pits thawing suction lines equalizers and suction valves, unbolt stack (riser air boot adaptor wouldn't fit) remove 1' spacer spool, reinstall stack and tighten bolts, Install drip pan, open;steam loop to water tank thaw snow and ice, begin thawing valves on water tank boiler #2 hot well fluid increasing, trouble shoot found equalizer valve shut in and froze, remove and thaw 2/2/2020 Continue r/up and warm rig. Continue thaw equalizer line and heat trace same on boiler #2, Hook up koomey lines, and flow nipple to stack. Continue Thaw mud tank #6 and pit lines. R/up new tongs, house keeping, chinking rig and install exterior lighting. Continue and finish R/up of pason;Rig watch system. Continue r/up and warm rig w/ both boilers. Warm TDS HPU, Set two cmt silos, continue and finish thawing Pits and lines. house keeping and chink rig. Start Thawing water tank w/ steam blanket. Install 2-7/8" X 5" VBR's in Top and btm rams & Swap Koomey line fittings;Install double valve on TDS work on plumbing manual guages on choke manifold;Install floor handling equipment bails and elevators, continue thawing out the water tank, steam loop froze, send truck after load of hot water for water tank, continue warming rig and chinking holes install curtain on rig floor across beaver slide opening, install guards over window and lights on;choke house, fill upright water tank w/ 350 bbls H2O approximate rate is 100 bph;Finish installing guards on lights and windows on choke house, R/U test equipment to new test pump, R/U water lines for water tank n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: BCU-019RD Beaver Creek Hilcorp Energy Company Composite Report Kenai, Alaska Contractor AFE #: AFE $: HEC 169 Job Name:2010015D BCU-19RD Drilling Spud Date: 2/3/2020 Purge air and get a circulating water system. Fill test pump water tank and fill stack (leak at top of annular btm of air boot flange. tightin same School on use of new grease gun and gresase choke manifold, hcrs and manuals valves. start mix first batch of 6% KCL/EZ mud.;Pre test BOP's t/ 250/5000 psi f/ 5 min w/ 3.5'' and 4.5'' test jts, test top drive man and auto IBOP, Choke valves inside man choke and kill, HCR choke and kill, kill line mezz valve, upper lower and blind rams, annular, perform Accumulator draw down test 20 sec to 200 psi 90 sec to full pressure.;Blow down lines and R/D test equipment, pull test plug set wear ring, take on water to pits for second batch of KCL mud.;General housekeeping on rig, hands cleaning each module picking up tools and hoses and equipment putting back in proper place, continue mixing second batch of 6% KCL mud.;Work on rig acceptance check list. Compare torque values on top drive iron roughneck and rig tongs, perform derrick inspection, dress board for sanding back pipe, set up pipe racks, load racks w/ DP stap and tally Dp. 2/4/2020 Continue Work on rig acceptance check list. house cleaning Continue mixing Batch #2 of 6%/KCL/EZ mud @ 9.5 ppg all hands attend Pre spud meeting continue trouble shoot derrick camera issue receive tools and r/up Sperry.;Cont. mixing batch #2, Continue trouble shoot derrick camera issue, installed draw works decoder, shim ODS sub 1/2" adjust Kelly hose, Compare torque values on top drive iron roughneck and rig tongs, install HES standpipe sensor, perform derrick inspection, P/U DP, rabbit, strap and rack back std.;Cont. P/U 4.5" DP, rabbit, strap and rack back stds in the derrick while using the make & brake procedure on the re-cut threads., finished mixing 2nd batch of mud & started mixing 3rd batch, worked on derrick light issue.;Cont. P/U 4.5" DP & racking back in derrick for a total of 55 stds, blew down TD, pulled wear ring, installed test plug, R/U BOP testing equip, serviced rig, finishing up 3rd batch of mud, cont. housekeeping & cleaning around rig. 2/5/2020 Cont. w/ housekeeping & cleaning till 08:00 hrs. when AOGCC & BLM Rep's arrived on location to witness BOP test. Preformed rig inspection & tested gas alarm system (ok), Flooded stack, purged out air, started testing BOP's, 5 min 250 Low/10 min 4500 High, had 1 FP on test #5 HCR choke,;functioned HCR choke, re-tested and passed. R/D testing equip., blew down choke manifold, installed wear bushing and run in lock downs.;Gathered up XO's, C/O boot on mud pump suction, primed both pumps w/ water, M/U XO's to Tri-Point's running tool, RIH w/ tool, 1 std. of DP, 10' pup, TIW, and 5' pup, tagged up @ 70' in, closed TIW, screwed into retrievable packer w/ 11 turn to the right, filled hole off trip tank, M/U TD;open TIW and cracked bleeder at floor manifold (static), pulled retrievable packer free, travel weight 54K, monitored well (static). Started circulating STS w/ pump #2, had issues w/ pop off, switched over to pump #1 and pumped 1700 stks, switched back over to pump #2, 2" bleeder value at the pump;started leaking, swapped back to pump #1 while re-building value, once valve was fixed finished pumping STS w/ pump #2, shut down pump, lined up both pumps and noticed pulsation dampener pressure on pump #1 bleed off to zero, started to trouble shoot pulsation dampener on pump #1 while cont.;to circ. w/ pump #1.;Made decision to shut down pump, blow down TD, POOH and L/D pups, TIW, 1 std. of 4.5", & Tri-point packer (18' total in length), R/U Weatherford, held PJSM, started L/D 3.5" tubing making sure to wipe pipe clean and getting correct calculated hole fill. Currently L/D 1887' of 3.5" tubing. 2/6/2020 Continue and finish l/dn of 3-1/2" 9.3# 8rd tbg kill string total recovered 132 jts and (1) 4' pup and (1) 10' pup w/ 18' of a Tri-point packer assy.;R/DN Weatherford, and clear & clean floor string shaker camera cable.;Service rig Replace liner gasket on MP #2, chg out pulsation dampener bladder on MP #1.;P/up and rack back 2 jt dp . R/up drain hose on rig floor Install keepers in pins on monkey board replace flow paddle sensor in flow line.;PJSM w/ Yellow jacket P/up and M/up Bha #1, 8-1/2" window mills for Gauge and drift run for whip stock.;Slip & cut 294' of drill line due to bad line on drum, had new pulsation dampener bladder fail on MP #1, cont. work on MP.;Adjusted load collar on TD, started strapping, rabbiting, and P/U 4.5" DP & singling in the hole w/ BHA#1 F/13' T/2,300', while using the make & brake procedure on the re-cut threads. Kicked out 3 jts. of DP due to galled threads. Brought out Peak welder, welded new screen in the body of the;pulsation dampener on MP #1.;Held PTSM, crew change, cont. strapping, rabbiting, and P/U 4.5" DP & singling in the hole w/ BHA#1 F/2300'' T/4,403', cont. to use the make & brake procedure, eased in the hole F/4,403 and tagged up on CIBP @ 4,489', POOH racked back 9 stds of 4.5" DP.;Check depth & eased in the hole F/4,403 and tagged up on CIBP @ 4,489', POOH racked back 9 stds of 4.5" DP, currently adjusting Kelley hose. Got calculated pipe displacement during trip. 2/7/2020 Adjusting Kelly hose.;P/up rabbit and strap 18 jts of 4-1/2" CDS- 40 36.86 # HWDP.;PJSM on testing and displacement Test TDS swivel packing , Kelly hose and HP mud line t/ 4500 Psi (ok).;Displace well f/ lease water t/ 9.5 ppg 6% KCL EZ mud, Hilary Garney stop by and conducted a VE on both of the boilers.;Rack back HWDP adjust link tilt bail clamps while mixing pump dry job.;Pooh racking back Dp f/ 4279' t/ Bha#1, L/D top follow through mill, had calculated hole fill during trip.;R/U to test casing, pressure tested casing T/2800 psi for 15 min (ok), pumped 179 gals, bled back 126 gals, R/D testing equip, blew down choke manifold and stand pipe.;P/U & M/U BHA #2 -mills, TM, DM, and float sub w/ solid float, TIH w/ 2 stds of HWDP, shallow tested MWD tools for detection (ok), GPM-315 SPP-440 psi.;POOH & rack back 2 stds, P/U & M/U whip stock on bottom of BHA #2, eased in the hole w/ BHA #2 & whip stock F/surface-T/458', running speed @ 1 std. per min.;Held PTSM, crew change, cont TIH F/458'-T/2477', replaced U-bolt on hobble clamp on bales, filled pipe @ 2,500' and get calculated pipe displacement.;Cont. TIH F/2477'-T/4468', broke circulation, currently orientating tool face 45 degrees left, had calculated pipe displacement for trip.;At about 05:30 hrs. Peak hand notice a small drip coming from the sewer cap on the office trailer, the cap was re-secured and the valve was re-shut to stop the leak, the spill was estimated to be a 5 gal spill and HSE Matt Hogge was contacted.;-Hauled 0 bbls fluid to KGF G&I -Cumulative: 0 bbls -Hauled 0 bbls solids to KGF G&I -Cumulative: 0 bbls -Daily Metal: 0 lbs. -Cumulative: 0 lbs. 2/8/2020 Slack off and seen good indication of anchor trip w/ whip stock @ 45L @ 4488', went to over pull anchor 10k and lost weight appeared to slide up hole, set dn 20k and confirmed movement up hole Worked pipe t/ 10k over and staged up dn weight t/ 40k w/ movement up hole twice for total of 6';or 4483' and sheared off work pipe up hole +- 6' and sat back dn on top of whip stock @ 4464' & applied 10k torque w/ no movement in tool face.;Establish parameters Mill window f/ 4464' T.O.W t/ 4476' B.O.W, mill rat hole t/ 4481' (Sample @ 4475' showing 10% metal 70% cmt 20% coal and 20% clay stone).;PTSM crew chg and PJSM continue mill rat hole f/ 4481' t/ 4496'.;drift window with and with out rotation and pumps and dress rough areas dn to slight over pull.;R/U & blew metal shaving back into well bore through manual choke & kill valves, R/U testing equip for FIT test, preformed FIT test T/960 psi EMW-13.6 ppg, pumped a total of 45 gals & bled back 42 gals (good test).;R/D testing equip. Blew down choke manifold & kill lines back through MP's.;Broke circulation, pumped dry job 2 lbs. over MW, blew down TD & stand pipe, started replacing bladder in pulsation dampener on #1 MP while POOH.;POOH F/4437'-T/632', finished replacing bladder in pulsation dampener on MP #1, currently hold 400 psi, completed rig acceptance check list, accepted rig at midnight.;Held PTSM, crew change, finished L/D BHA #2, watermelon mill was 1/16" under gauge (see photos), Cal Disp.=25 bbls Act Disp.= 30 bbls Diff Disp.=5 bbls.;Cleared & cleaned rig floor, serviced rig.;Held PJSM, started P/U directional BHA #3, currently uploading data to MWD tools.;-Hauled 0 bbls solids to KGF G&I -Cumulative: 0 bbls -Hauled 0 bbls fluid to KGF G&I -Cumulative: 5 bbls -Daily Metal: 191 lbs. -Cumulative: 191 lbs. Sidetrack well ggp preformed FIT test T/960 psi EMW-13.6 ppg, pumped FIT = 13.6 ppg 2/9/2020 Continue up load data , test tools ok, PJSM load Nukes P/up jars.;RIH out of derrick w/ bha #3 t/ 2650' fill pipe.;Service rig top off oil TDS, work on pump throttle chg out elect box in derrick, Test geo span 1200 psi , blow dn lines.;Continue rih t/ 4447'.;Fill pipe and orient mtr w/ whip stock @ 45L dn pump and slide f/ 4447' dn across whip stock t/ 4478' appears rat hole is under gauge w/ bit 2' out . bring pumps on and clean out under gauge hole t/ 4496' continue slide t/ 4533' Rotate drill t/ 4556' w/ torque climbing f/ 9k t/ 18k.;and ALD stabilizer right at top of whip stock and stacking weight unable to slide. pull bit back above top of window (ok).;Service rig grease dwk, IR and chk drive line bolts and chk fluid in mtrs while discussing issue w/ town.;Dumped NXS lube in suction , RIH and pump around and finesse slide drill and work ALD stab across whip stock f/4556' t/ 4590'.;Cont. rotary/slide drilling F/4490'-4758', mad passing all slides. P/U-104K S/O-98K ROT-100 SPP-1620 psi GPM-511 TQ-4K.;Cont. rotary/slide drilling F/4458'-T/4846', mad passing all slides. P/U-106K S/O-100K ROT-104 SPP-1620 psi GPM-510 TQ-4.4K.;Held PTSM, crew change, Cont. rotary/slide drilling F/4846'-T/4982', mad passing all slides. P/U-106K S/O-102K ROT-104 SPP-1667 psi GPM-510 TQ-6K.;Cont. rotary/slide drilling F/4846'-T/5128', mad passing all slides. P/U-108K S/O-103K ROT-105 SPP-1787 psi GPM-515 TQ-4.5K. Distance to Plan 5.95' 3.68' Low 4.68' Left.;Hauled 0 bbls solids to KGF G&I -Cumulative: 0 bbls -Hauled 95 bbls fluid to KGF G&I -Cumulative: 100 bbls -Daily Metal: 40 lbs. -Cumulative: 231 lbs. 2/10/2020 Continue Directional drilling 8-1/2" hole w/ slides as necessary to maintain WP#02 and mad passing slides f/ 5128' t/5502' Pump around 20 bbl high vis sweep while rotating at 5189' @ 23 bbls early w/ no increases in cutting w/ high gas 445 P/U-113K S/O-108K ROT-108 SPP-2010 psi GPM-550 TQ-5k.;Pump around 20 bbl high vis sweep back 23 bbls early w/ 10% increase. SPR and monitor well (ok).;pooh t/ 4452' w/ no issues in open hole, L/dn one jt do to bad face and replace same. pulled BHA through window w/ 10k drag and couple 20k bobbles. Monitor well (ok).;Continue pooh racking back 15 std t/ 3552'.;P/up rabbit and strap and m/up and service threads on 30jts blue banded recut fill pipe and orient to window 45L.;Rih f/4440 ' t/ 5436', seen 10/20K drag while exiting window w/ BHA #3, the rest of the trip was smooth to bottom, washed last std. down F/5436'-T/5502', filled pipe, warmed mud, & orientated tool face, lost liner pump on MP #1 (fixed). Pipe disp. Cal-18.1 Act-16.1 Diff-2.0 bbls.;Cont. directionally drilling 8.5" hole F/5502'-T/5562', mad passing side F/5502'-T/5522', started drilling our tangent section w/ correctional slides only as needed. P/U-118K S/O- 108K ROT-112 SPP-1885 psi GPM-500.;Cont. directionally drilling 8.5" hole F/5562'-T/5673', P/U-120K S/O-110K ROT-110 SPP-2106 psi GPM-550 TQ-6-7K.;Held PTSM, crew change, cont. directionally drilling 8.5" hole F/5673'-T/5810', P/U-124K S/O-114K ROT-118 SPP-2138 psi GPM-550 TQ- 7K.;Cont. directionally drilling 8.5" hole F/5810'-T/5934', pumped 20 bbl Hi-Vis sweep @ 5870', sweep came back 15 bbls early w/ a 40% increase in cuttings. P/U-129K S/O-115K ROT-119 SPP-2095 psi GPM-550 TQ-8K.;Cont. directionally drilling 8.5" hole F/5934'-T/5995', noticed TD load collar was riding on quill bushing, racked back 1 std. circulated @ 325 gpm while adjusted load collar spring (fixed).;TIH to bottom, oriented tool face. cont. directionally drilling 8.5" hole F/5995'-T/6090', P/U-130K S/O-116K ROT-119 SPP-2160 psi GPM-540 TQ-8K, Distance to plan: 2.83' High: 2.29 Right: 1.66.;Hauled 79 bbls solids to KGF G&I -Cumulative: 79 bbls -Hauled 97 bbls fluid to KGF G&I -Cumulative: 197 bbls -Daily Metal: 27 lbs. -Cumulative: 258 lbs. 2/11/2020 Cont drilling 8 1/2" hole from 6090’ to 6550’. Rotating WOB 6 to 7K, 559 gpm-2421 psi, 77 rpm-8800 to 9200 ft/lbs on bott torque. MW 9.6 ppg/vis 55, ECD's at 10.1 ppg, BGG 22 units, max gas 195 units. Last survey at 6514’ md, 24.60° Inc, 128.76° Azi, 6207’ tvd puts us 2.6’ left and 2.6’ high.;Pumped a 20 bbl hi-vis sweep around at 530 gpm-2089 psi, 76 rpm-8000 to 8300 ft/lbs off bott torque, up wt 128K, dwn wt 128K. Had 25% increase in cuttings with sweep to surface, came back 20 bbls early, cont circ until clean on shakers. Obtained survey on bottom and flow check = static.;Pulled up hole 17 stands on elevators, from 6550' to 5502' with no overpull, no issues. Up wt 143K. Calculated hole fill = 6 bbls, actual hole fill = 8 bbls.;Serviced rig and topdrive. Installed head pin and circ hose, circulated at 111 gpm-202 psi, changed gearbox oil on topdrive due to high temp of load collar riding against quill bushing, replaced grabber die block assembly, troubleshot and fixed suction cap leak on pump #2.;Removed head pin/circ hose, PU singled in hole 30 jnts 4 1/2" DP with no issue. Washed last stand to bottom, had +/- 10' of fill.;Resumed drilling 8 1/2" hole F/ 6550'- T/6990 ', added 1 drum of NXS lube to system to help with TQ & stick slip, pumped 20 bbls sweep @ 6862', sweep came back 10 bbls early w/ a 60% increase in cuttings. P/U-150K S/O-116K ROT-130K SPP-2104 psi GPM-511 TQ-9-10K WOB-8-10K.;Cont. directionally drilling 8.5" hole F/6990'- T/7112', P/U-150K S/O-118K ROT-128K SPP-2430 psi GPM-530 TQ-11K WOB-8-10K.;Made hook, got new SPR's, pumped 20 bbls Hi-vis sweep while drilling ahead, sweep came back 5 bbls early w/ a 25% increase in cuttings, cont. directionally drilling 8.5" hole F/7112'-T/7295', P/U-160K S/O- 118K ROT-132K SPP-2495 psi GPM-520 TQ-13K WOB-11K.;Cont. directionally drilling 8.5" hole F/7295'-T/7307', racked back 1 std. currently pulling liner in MP #1 pod #3 leaking, while circulating w/ MP #2 & reciprocating pipe. P/U-160K S/O-118K ROT-132K SPP-725 psi GPM-272 TQ-11K WOB- 11K, Distance to plan: 6.35' 1.67' High 6.12' Left.;Hauled 68 bbls solids to KGF G&I -Cumulative: 147 bbls -Hauled 102 bbls fluid to KGF G&I -Cumulative: 299 bbls -Daily Metal: 9 lbs. -Cumulative: 267 lbs. 2/12/2020 Both pumps on line, made connection, pumped 20 bbl hi-vis nutplug sweep and resumed drilling ahead once sweep exited bit. Drilled from 7307' to 7604'. Rot WOB 8K, 513 gpm-2510 psi, 77 rpm-10,900 to 13,000 ft/lbs on bott torque, 130 ft/hr ROP, MW 9.8/vis 54, ECD's at 10.3 ppg, BGG 8 units.;Pumped a second sweep at 7542'. Sweeps cont to come back with 25% increase in cuttings to surface. Added 1 drum an hour of NXS-Lube to suction pit to reduce stick/slip and drilling torque (4 drums total) while drilling ahead.;Cont circulating bottoms up after second sweep to surface. 520 gpm-2442 psi, 77 rpm-10,000 ft/lbs off bott torque. Up wt 130K, dwn wt 120K. Obtained SPR's and survey on bottom.;Pulled up hole 2 stands from 7604' to 7479', up wt 160K (no pumps, no rot), blew down topdrive and flow check = static. Cont pull up hole on elevators from 7479' to 6554' with no issue. Did have a couple 20K overpulls but nothing we had to work through. Parked string at 6617', dwn wt 104K.;Serviced rig and topdrive, checked driveline bolts, greased washpipe.;PU singled in hole 30 jnts 4 1/2" DP, from 6617' to 7548', dwn wt 110K. Filled pipe and washed last stand to bottom with no indication of fill.;Resumed drilling 8 1/2" hole from 7548' to 7796', Sliding F/7736'-T/7754', WOB-5K GPM-522 SPP-2304 psi Diff-13.8-44.5 psi, P/U-160K S/O-122K ROT-134K Rotary= WOB-3-8K GPM-522 SPP-2499 psi TQ-9-10K.;Resumed drilling 8 1/2" hole from 7796' to 7919', added 1 drum of NXS lube to help w/ slide. Sliding F/7860'-T/7883', WOB-5K GPM-532 SPP-2263 psi Diff-20.7-35.3 psi, P/U-160K S/O-122K ROT-134K Rotary= WOB-3-8K GPM-533 SPP-2458 psi TQ-8-10K.;Resumed drilling 8 1/2" hole from 7919' to 7981', P/U-170K S/O-122K ROT-138K WOB-8- 10K GPM-525 SPP-2370 psi TQ-9-11K.;Pumped Hi-Vis sweep around while rotating & reciprocating pipe, sweep came back on time w/ a 30% increase in cuttings, got SPR's & cont. drilling ahead F/7981'.;Held PTSM, crew change, cont. directionally drilling 8.5" hole F/7981-T/8165', Sliding F/7983'-T/8001', WOB-3K GPM-536 SPP-2456 psi Diff-95.4-112.6 psi, P/U-170K S/O-122K ROT-138K Rotary= WOB-8-9K GPM-510 SPP-2342 psi TQ-8-10K.;Resumed drilling 8 1/2" hole F/8165'-T/8226', pumped 20 bbl Hi-Vis sweep while rotating & reciprocating pipe, sweep came back on time, w/ a 20% increase in cuttings, P/U-170K S/O-122K ROT-138K WOB-8-10K GPM-510 SPP-2494 psi TQ-11K.;Resumed drilling 8 1/2" hole F/8226' to current depth 8291'. P/U-170K S/O-122K ROT-139K WOB-10K GPM-520 SPP-2517 psi TQ-11K, Distance to plan: 8.62' 7.67' Low 3.93' Right.;Hauled 72 bbls solids to KGF G&I -Cumulative: 219 bbls -Hauled 108 bbls fluid to KGF G&I -Cumulative: 407 bbls -Daily Metal: 6 lbs. -Cumulative: 273 lbs. 2/13/2020 Cont drilling 8 1/2" hole from 8291' to 8538'. Rot WOB 8 to 9K, 519 gpm-2569 psi, 50 rpm-11,000 ft/lbs on bott torque, 110 to 140 ft/hr ROP. Sliding WOB 5 to 6K, 531 gpm-2551 psi, 130 psi diff, 26 to 46 ft/hr ROP. MW 9.8+/vis 55, ECD's at 10.3 ppg, BGG 32 units. Obtained survey and SPR's.;Pumped 20 bbl hi-vis nutplug sweep around at 528 gpm-2491 psi, 80 rpm-11,000 ft/lbs off bott torque, cont to rotate and reciprocate string. Had a spike of 336 units gas prior to initial bottoms up. Mud logger says we drilled into a sand last stand down. Gas dropped to 18 units over 10 min circ.;Sweep came back on time with a 30% increase in cuttings. Circulated one additional bottoms up. Up wt 179K, dwn wt 125K, rot wt 142K.;Pulled up hole 2 stands from 8538' to 8414', up wt 178K with no pumps. At 8414' blew down topdrive. Fluid dropped in wellbore approx. 8' over 15 min. Filled hole, static loss rate at 8.5 bph. Cont pulling up hole on elevators from 8414' to 4463'. Had 17 tight spots ranging from 20 to 40K overpulls,;most that we had to work pipe 3 or 4 times. Did not pump or backream at all. At 5800' wellbore smoothed out significantly. Pulling BHA through window went good, saw 10K overpull as the small stab on upper ADL collar passed upper window then overpull dropped off. Calculated hole fill = 26 bbls.;Actual hole fill = 43.4 bbls for entire trip. Left well on trip tank to monitor and installed TIW on stump. MU topdrive and hung off same for cut and slip drill line. Mechanic repaired mount bracket for vac degasser motor and installed same, installed belts and belt guard, function tested OK.;Held PJSM, cut and slipped 92' of drill line, serviced rig and topdrive. Loss rate on trip tank reduced to just under 1/2 bph. Removed sling from blocks, broke off topdrive, checked crown saver, removed TIW.;RIH one stand to get BHA out window, from 4463' to 4551', no issues exiting window, P/U 46 jts. of 4.5" DP and RIH F/4551'-T5939'. P/U-94K S/O-88K.;Cont. RIH out of derrick F/5939'-T/7544' w/no issues, filled pipe. Cal Disp.=54.9 bbls Act Disp.=49.23 bbls Diff=-5.7 bbls. P/U-130K S/O-98K.;Held PTSM, crew change, cont. RIH out of derrick F/7544'-T/8039', had 30K set down @ 8012', tried working through X4, Kelley up, washed & reamed through tight spot (ok). P/U-143K S/O-106K ROT-120K GPM-307 SPP-1300 psi TQ-7/8K.;Blew down TD, cont. RIH out of derrick F/8039'-T/8473', had 20K set down @ 8437', tried working through X3, Kelley up, washed & reamed through tight spot (ok), P/U-145K S/O-106K ROT-120K GPM-317 SPP-1300 psi TQ-10/11K.;Washed last std. down F/8473' to bottom @ 8538', had 10' of fill, CBU to clean up hole while rotating & reciprocating the pipe, had max gas of 66 units at BU. P/U-145K S/O-108K ROT-120K GPM-519 SPP-2493 psi TQ- 10/11K.;Resume directionally drilling 8.5" hole F/8538' to current depth 8629', P/U-146K S/O-112K ROT-120K GPM-520 SPP-2350 psi TQ-10/11K. Distance to plan: 9.30' 8.89' Low 2.74' Right.;Hauled 64 bbls solids to KGF G&I -Cumulative: 283 bbls -Hauled 96 bbls fluid to KGF G&I -Cumulative: 503 bbls -Daily Metal: 0 lbs. -Cumulative: 273 lbs. 2/14/2020 Cont directionally drilling 8 1/2" hole from 8629' to 8790'. Sliding WOB 4K, 522 gpm-2661 psi, 140 psi diff, 20 to 60 ft/hr ROP. Rotating WOB 5K, 508 gpm-2720 psi, 60 rpm-11,900 ft/lbs on bott torque, 100 to 130 ft/hr ROP, MW 10.0/vis 55, ECD's at 10.5 ppg, BGG 29 units, mad pass slides.;Pumped a 20 bbl hi-vis weighted sweep around, 482 gpm-2300 psi, 60 rpm-11,000 ft/lbs off bott torque, sweep back on time with a 20% increase in cuttings to surface.;Cont directionally drilling 8 1/2" hole from 8790' to 9037'. Sliding WOB 4K, 522 gpm-2814 psi, 200 psi diff, 40 to 60 ft/hr ROP. Rotating WOB 8 to 13K, 524 gpm-2824 psi, 55 rpm-11,900 ft/lbs on bott torque, 126 ft/hr ROP, MW 10.1/vis 54, ECD's at 10.6 ppg, BGG 29 units, max gas 165 units.;Cont rack and drift 5 1/2" casing, received Sperry's GeoTap tool in a heated reefer van (kept on location), received swell packer and couplers.;Pumped a 20 bbl hi-vis nutplug sweep around, sweep came back on time w/ a 15% increase in cuttings. SPP-2593 psi GPM- 518.;Cont directionally drilling 8 1/2" hole F/9037'-T/9102', Sliding: (F/9042'-T/9102') WOB-5/9K SPP-2613 psi GPM-516 Diff-20-223 psi, Rotary: P/U- 160K S/O-110K ROT-126K SPP-2891 psi GPM-525 TQ-12.8K WOB-8K Diff-18-195 psi.;Cont directionally drilling 8 1/2" hole F/9102'-T/9118', Sliding: (F/9102'-T/9118') P/U-160K S/O-110K ROT-126K SPP-2891 psi GPM-525 TQ-12.8K WOB-8K Diff-15-198 psi.;Held PTSM, crew change, cont. directionally drilling 8 1/2" hole F/9118'-T/9165', Sliding: (F/9103'-T/9143') P/U-160K S/O-110K ROT-126K WOB-4/5K SPP-2864 psi GPM-510 Diff-20-223 psi TQ-11.5K.;Resumed directionally drilling 8 1/2" hole F/9165'-T/9225', Added 1 drum of NXS lube to suction pit to assist w/ sliding. Sliding: (F/9165'-T/9205') P/U-158K S/O-114K ROT-130K WOB-8.7K SPP-2833 psi GPM-500 Diff-20-223 psi TQ-12.5K Diff-23-219 psi.;Resumed directionally drilling 8 1/2" hole F/9225'-T/9287'. Sliding: (F/9226'-T/9266') P/U-158K S/O-114K ROT-132K WOB-5K SPP-2814 psi GPM-520 Diff-20- 223 psi TQ-11.8K Diff-33-289 psi.;Pumping 20 bbl Hi-Vis around at current time. Distance to plan: 9.50' 8.69' Low 3.83' Right.;Hauled 34 bbls solids to KGF G&I -Cumulative: 317 bbls -Hauled 146 bbls fluid to KGF G&I -Cumulative: 649 bbls -Daily Metal: 0 lbs. -Cumulative: 273 lbs. Cont drilling 8 1/2" hole f 2/15/2020 Cont pumping 20 bbl hi-vis nutplug sweep around at 530 gpm-2733 psi, 50 rpm-10,200 ft/lbs off bott torque. Sweep came back on time with a 20% increase in cuttings to surface.;Cont directional drilling 8 1/2" hole from 9287' to 9597'. Sliding WOB 4 to 9K, 511 gpm-2702 psi, 120 psi diff, 20 to 60 ft/hr ROP. Rotating WOB 5 to 8K, 513 gpm-2994 psi, 50 rpm-11,300 ft/lbs on bott torque, 120 to 140 ft/hr ROP, MW 10.2/vis 49, ECD's at 10.7 ppg, BGG 31 units, max gas 435 units.;Backreamed last stand, obtained survey and SPR's. Up wt 157K, dwn wt 116K, rot wt 130K.;Pumped 20 bbl hi-vis nutplug sweep around at 511 gpm-2704 psi, 50 rpm-11,400 ft/lbs off bott torque. Sweep back on time with a 30% increase in cuttings to surface. Fluid dropped 1' in wellbore during 15 min flowcheck.;Pulled up hole 170K on elevators from 9597', pulled 7 stands and blew down topdrive, cont pulling up hole to 8612' where we overpulled 40K four times, MU topdrive and attempted to pump up through tight spot 3 times, no luck, backreamed at 35 rpm- 9500 to 11,500 ft/lbs torque and got through. Reamed;through tight spot a couple times until it cleaned up (pulling through siltstone and two slide intervals). Racked back stand, had to pump next stand up hole with no rotation (overpull coming out of slips). Pulled one more stand to 8545' with no issue on elevators.;Serviced rig and topdrive, checked driveline bolts, greased crown.;TIH on elevators from 8545' to 9597' with no issues, filled pipe and washed last stand to bottom.;Cont directional drilling 8 1/2" hole F/9597'-T/9650', (Slide F/9597'-T/9638'), added 1 drum of NXS lube to suction pit to assist w/ slide. P/U-160K S/O-114K ROT-128K SPP-2961 psi GPM-510 TQ-11-13K WOB-8.6 Diff-55.4-236.8 psi.;Cont directional drilling 8 1/2" hole F/9650'-T/9721', No slide, P/U-160K S/O-114K ROT-128K SPP-2961 psi GPM-510 TQ-11-13K WOB-8.6.;Held PTSM, crew change, cont directional drilling 8 1/2" hole F/9721'-T/9785', Slide: (F/9733'-T/9785') bumped up MW to 10.35 ppg, BGG=130 units, max gas of 700 units. P/U-160K S/O-118K ROT-134K SPP-2895 psi GPM-500 TQ-13K WOB-4.5K Diff-23-297 psi.;Cont directional drilling 8 1/2" hole F/9785'-T/9905', Slide: (F/9846'- T/9886') added 1 drum of lube to suction pit. P/U-170K S/O-115K ROT-145K SPP-2802 psi GPM-490 TQ-13K WOB-2K Diff-42-217 psi.;Currently pumping Hi-Vis sweep around & rotating & reciprocating pipe while bringing MW up to 10.4+, BGG=86 units. Distance to plan: 15.46' 9.67' Low 12.06' Left.;Hauled 88 bbls solids to KGF G&I -Cumulative: 405 bbls -Hauled 267 bbls fluid to KGF G&I -Cumulative: 916 bbls -Daily Metal: 0 lbs. -Cumulative: 273 lbs. 2/16/2020 Cont circulating sweep around at 495 gpm-2630 psi, 40 rpm-11,800 ft/lbs off bott torque. Sweep came back on time with a 20% increase in cuttings to surface. Up wt 175K, dwn wt 116K, rot wt 146K.;Resumed drilling 8 1/2" hole from 9905' to 10,400'. Rot WOB 6-8K, 502 gpm-3100 psi, 50 rpm- 13,600 to 14,000 ft/lbs on bott torque, 90 to 125 ft/hr ROP. Sliding WOB 3 to 4K, 502 gpm-3058 psi, 278 psi diff, 15 to 50 ft/hr ROP. MW 10.4/vis 52, ECD's at 10.8 to 11.1 ppg, BGG 35 units, max gas 400 units.;Received 410 sx tail cement (total tail on location 1220 sx), received 3 more ISO's of OBM and transferred into BCU-04RD tank farm, received last two trailers of 5 1/2" casing and racked same.;After making connection at 10,400', lost swab on #1 pump, isolated to #2 pump and started circulating to replace swab. Washpipe started leaking on topdrive. Racked back stand, installed head pin and circ hose, cont circ while C/O swab and topdrive washpipe. RD headpin and circ hose. Obtained survey.;Cont directional drilling 8 1/2" hole from 10,400' to 10,464', (Slide: F/10,400'-T/10,406') P/U-175K S/O-116K ROT-134K SPP-3207 psi GPM-500 TQ-14K WOB-7.7K Diff-49.9-236.2 psi.;Cont directional drilling 8 1/2" hole from 10,464' to 10,525', (Slide: F/10,464'-T/10,525'), pumped 20 bbl Hi-Vis sweep, came back on time w/ 15% increase in cuttings. P/U-170K S/O-120K ROT-138K SPP-3023 psi GPM-500 TQ-13.5K WOB-8.5K Diff-27.7-356.4 psi.;Cont. directional drilling 8 1/2" hole from 10,525' to 10,557', P/U-170K S/O-120K ROT-138K SPP-3023 psi GPM-500 TQ-14K WOB-8.5K.;Held PTSM, crew change, cont. directional drilling 8 1/2" hole from 10,557' to 10,648', (Slide: F/10,586'-T/10,648') P/U-176K S/O-122K ROT-140K SPP-3051 psi GPM-505 TQ-14K WOB-8.5K Diff-63.5-364.5 psi.;Cont. directional drilling 8 1/2" hole from 10,648' to 10,708', pumped 20 bbl Hi-Vis sweep while cont. to drill ahead. P/U-176K S/O- 122K ROT-140K SPP-3057 psi GPM-500 TQ-15K WOB-5K.;Cont. directional drilling 8 1/2" hole F/10,708' to current depth 10,765, sweep came back on time w/ 10% increase in cuttings. Distance to plan: 6.24' 6.24' Low .05' Left.;Hauled 87 bbls solids to KGF G&I -Cumulative: 492 bbls -Hauled 273 bbls fluid to KGF G&I -Cumulative: 1,189 bbls -Daily Metal: 2.2 lbs. -Cumulative: 275 lbs. 2/17/2020 Cont drilling 8 1/2" hole from 10,765' to 11,018'. Rotating WOB 3 to 13K, 500 gpm-3038 psi, 65 rpm-11,300 to 13,400 ft/lbs on bott torque, 20 to 120 ft/hr ROP, MW 10.4+/vis 51, ECD's at 11.0 ppg, BGG 40 units, max gas 957 units (T-19 zone). Obtained survey and SPR's.;Pumped 20 bbl hi-vis sweep around at 507 gpm-2890 psi, 70 rpm-11,000 ft/lbs off bott torque. Sweep back on time with 10% increase in cuttings.;Pulled two stands from 11,018' and blew down topdrive, flow check fluid dropped slightly in wellbore over 15 min. Attempted to pull up hole on elevators, would not break loose. MU topdrive, went to one pump and rotated loose. Cont pulling up hole on elevators to 9967' with no issue.;Calculated hole fill = 6.79 bbls, actual hole fill = 8.5 bbls.;MU headpin and circ hose, on one pump circ at 142 gpm-408 psi, blew down topdrive then replaced sun cartridge and adjusted max torque. Serviced rig and topdrive.;Had to MU topdrive and rotate free, TIH from 9967' to 10,955' with no issue, MU last stand, filled pipe and washed to bottom. Down wt 115K.;Cont drilling 8 1/2" hole from 11,018' to 11,080'. Rotating WOB 6 to 15K, 501 gpm-3093 psi, 60 rpm-10,900 to 12,500 ft/lbs on bott torque, 9 to 50 ft/hr ROP. Just prior to bottoms up had 1477 units gas, then shortly after at bottoms up had 2765 units. Both dropped off pretty quick. Started;increasing background LCM to 30 ppb to help with differential sticking and increase mud weight a bit to control gas. Not seeing any connection gas on connection at 11,080', BGG at 30 units.;Cont. drilling 8.5" hole F/11,080'-T/11,154', @ 11.148' ROP slowed, began work w/ drilling parameters to get bit to drill off. P/U-178K S/O-124 ROT-140K SPP-3057 GPM-475 TQ-10-12K WOB-5-11K.;Held PTSM, crew change, cont. drilling 8.5" hole F/11,154''-T/11,156' stacking up to 20K on bit w/ no increase in ROP or TQ, pumped 20 bbl Hi-Vis sweep w/ walnut, came back on time, no increase in cuttings.;Added 1 drum of lube to suction pit to help increase ROP, attempted to drill ahead F/11,156' (no luck), made decision to short trip 1,000'. Finished strap & tally of 5-1/2" casing.;Circulated BU, pulled 5 stds. on elevators, flow check (static), blew down TD, TOOH T/10,154' cont. to see differential sticking, 10/20K over pull out of the slips, preformed rig service. P/U-176K S/O-124K Cal hole fill-6.9 bbls Act disp.-11.5 bbls Diff-4.6 bbls.;Currently TIH to bottom @ 10,650'. Distance to plan: 6.78' 6.77' Low .26' Left.;Hauled 93 bbls solids to KGF G&I -Cumulative: 585 bbls -Hauled 347 bbls fluid to KGF G&I -Cumulative: 1,536 bbls -Daily Metal: 0 lbs. -Cumulative: 275 lbs. Cont drilling 8 1/2" hole from 10,765' to 11,018'. 2/18/2020 Cont TIH from 10,650' to to 11,081’ with no issue, dwn wt 110 to 115K. MU topdrive and filled pipe, washed down to 11,144’. Stayed 13' off bottom to be able to work full stand while circ.;CBU one time with 414 units gas at bottoms up, 510 gpm-3048 psi, 60 rpm-10,700 to 11,100 ft/lbs off bott torque. Up wt 143K, dwn wt 132K. Followed with a 20 bbl sweep. Sweep on time but no increase in cuttings. BGG 10 units.;Pulled 5 stands on elevators to 10,825’, up wt 180K with no pump-no rotary, blew down topdrive, flow check- fluid dropped about 1’ in 15 min. Cont POOH on elevators from 10,825’, did not have to rotate free to get pipe moving. Encountered tight hole at 8537’. Backreamed slowly from 8537' to 8488’;and racked back stand. Got hung up pulling 20K over just out of slips (sandstone/tuffaceous sandstone with soft clay matrix). Up wt 178K on elevators.;PU single and attempted to rotate free while working pipe and full circulation. Started jarring down with one pump at idle, started a drum of NXS lube in suction pit. String came free after an up jar at 178K followed with a down jar at 60K.;Cont backreaming slowly from 8488' to 8188', 500 gpm-2634 psi, 35 to 75 rpm-7600 to 19,000 ft/lbs torque.;Cont backreaming slowly from 8188' to 7607', 460 gpm-2264 psi, 50 rpm-7100 to 19,000 ft/lbs torque, pumped lube sweep around seemed to pull better not stalling as frequent.;Continue Pumping and back reaming out f/ 7607' t/ 6871' 480 gpm 2350 psi 50 rpm 5500- 19000k tq, found large chunks of coal approximately 6'' x 10'' x 1 1/2'' in possum belly, pulled smooth 2 stands, flow check well static, blow down top drive.;POOH on elevators f/ 6871' t/ 5842' Hole taking correct hole fill. 2/19/2020 Cont POOH racking back in derrick, from 5842’ and into window at 4476’ with no issue. Up wt 110K. Had a repeat of 12K increase in drag as ALD stab passed through window. Parked string at 4459'.;Flow check at 4459' = slight drop in wellbore. Pump at idle while building dry job, pumped same then blew down topdrive, mudline and pumps.;Cont POOH LD 4 1/2" DP from 4459' to 1947'. LD total 86 joints, used Peak vac system to drift pipe dry with wiper ball, staged pipe in pipe tub.;Cont POOH racking back in derrick from 1947' to HWDP. Racked back HWDP, jar stand and NM Flex DC's. Total Safety Rep was out and tested gas alarm system. Cellar H2S audio alarm wouldn't work, replaced same and tested OK.;Held PJSM with Halliburton MWD Rep on source removal, staged hands to block access to rig floor and cellar, pulled ALD collar to rig floor, removed sources, plugged in and downloaded MWD data. Removed pulser, LD smart tools. Flushed motor and broke off bit. Bit graded an 8-3 and 1/8 under gauge.;Bottom edge of ALD stabilizer worn and undercut, DM collar had two good grooves lathed into body, about 2' apart.;Cleaned and cleared rig floor, drained BOP stack. Staged test joints on catwalk in prep for bi-weekly BOP test.;MU run tool and retrieved wear ring from wellhead, set test plug R/U to test BOP's.;Test BOP's w/ 4.5'' and 2 7/8'' test joints t/ 250/4500 psi, 250/2500 psi on annular with both test jts, test upper lower and blind rams, CMV 1-13, HCR and man Choke and Kill. TIV and Dart, Auto and Man IBOP, Kill line valve 3'', man and hyd choke, Perform accumulator drawdown test 23 sec to;200 psi 88 sec to full pressure, 4 bottle 2550 avg psi, total safety tested all gas alarms, FP on Lower pipe rams on the high test Functioned rams and retested good, Fp on cellar H2S audio Alarm replaced sensor and retested good.;R/D Test equipment Blew down lines, Pulled test plug set wear ring clean and clear floor.;Pick up BHA Directional Assembly #4 RIH t/ 91' Bit, Motor, DM, ADR, DGR,PWD,TM.;Upload MWD, roll pumps through bleeders.;P/U Flex Collar stand and single flex collar from rack 183'. 2/20/2020 Uploaded MWD tools, shallow pulse tested OK, cont TIH jars, remaining HWDP and DP from derrick to 1762’. PU singled in hole 86 jnts 4 1/2" DP to 4418’. Up wt 89K, dwn wt 89K.;Serviced rig and topdrive, MU topdrive on stump and hung blocks, removed weight indicator sending units, cut and slipped 76' of drill line. Inspected saver sub threads (good) and grabber dies. Calibrated hook load and block height. Pumps on at 474 gpm-1888 psi, oriented tool face at 30 left.;Shut down pumps, made hook, eased down and out the window at 4476'. Set down 12K at 4471' then it fell off. Saw the usual 10K drag as larger BHA items exited window. Down weight 89 to 91K. Cont to ease in the hole to 8805' filling pipe every 1500'. Washed through 8805'. Set down again at 11,010'.;MU topdrive, filled pipe, washed/reamed down from 11,010' to 11,155' at 494 gpm-3070 psi, 60 rpm-10,400 to 12,000 ft/lbs torque, 0 to 3K WOB. Had a max of 4954 units gas at bottoms up along with a good amount of cuttings/thin coal chips. Gas dropped down fairly quick.;Resumed drilling 8 1/2" hole from 11,155' to 11,430' 480 gpm 3100 psi 60 rpm 12-14k tq on bottom 11-12k off bottom 12k wob 28.9 FPH Avg ROP ECD 11.03 ppg, 218k PUW 142k SOW 168k Rot, Distance to Plan - 8.47' 8.47 low .08 Right. 2/21/2020 Drilled 8 1/2" hole from 11,430' to 11,628'. Rot WOB 13K, 500 gpm-3197 psi, 55 rpm-12,400 to 15,400 ft/lbs on bott torque, 15 to 60 ft/hr ROP, MW 10.6/vis 52, ECD"s at 11.0 ppg, BGG 38 units, max gas 205 units. Pumped a 20 bbl sweep at 11,543' with 10% increase in cuttings to surface, back on time.;Drilled 8 1/2" hole from 11,628' to 11,853'. Rot WOB 4 to 15K, 493 gpm-3021 psi, 65 rpm-12,000 to 13,000 ft/lbs on bott torque, 45 to 60 ft/hr ROP, MW 10.6/vis 49, ECD's at 11.1 ppg, BGG 29 units, max gas 294 units. Up wt 230K, dwn wt 144K, rot wt 170K.;Drilled 8 1/2" hole from 11,853' to 12050' 500 gpm 3330 psi 60 rpm 12-14k tq on bottom 11-12 off 32.32 FPH Avg. ECD 11.16 ppg , BBG 27 units 240 units max gas 10.6 ppg MW 240k PUW 140k SOW 175k Rot.;Drilled 8 1/2'' hole from 12050' to 12164' 500 gpm 3350 psi 60 rpm 13-16k tq on bottom 12-14k tq off 162 PUW 150 SOW 162 ROT 11.1 ppg ECD Obtain slow pump rates and survey.;Short trip from 12164' t/ 11108' observe differential sticking unable to pull loose, break free with pumps and rotary POOH w/ pumps 3 bpm 550 psi, No other issues pulled clean. 2/22/2020 Performed rig service at 11,108’. Brake linkages, driveline bolts, greased topdrive and blocks and drawworks. Cont to circ at 3 bpm and rotate 30 rpm during rig service.;TIH from 11,108' on elevators to 12,099' with no issue. MU last stand and topdrive, filled pipe and washed/reamed to bottom at 12,164'. Made hook and started a 20 bbl hi-vis sweep around.;Resumed drilling 8 1/2" hole from 12,164' to 12,345'. Rotating WOB 9K, 495 gpm-3216 psi, 60 rpm-17,200 to 18,000 ft/lbs on bott torque, 75 to 80 ft/hr ROP, MW 10.6/vis 56, ECD's at 11.1 ppg, BGG 35 units, max gas 101 units drilling. Trip gas 416 units at initial bottoms up, sweep = 20% increase.;Cont drilling from 12,345' to 12,534'. Rotating WOB 9 to 16K, 502 gpm-3371 psi, 65 rpm-14,300 to 17,900 ft/lbs on bott torque, 16 to 80 ft/hr ROP, MW 10.6/vis 51, ECD’s at 11.1 ppg, BGG 34 units, max 249 units. Added NXS lube to reduce drilling torque as needed.;Continue Drilling f/ 12,534' t/ 12,850' 500 gpm 3400 psi 60 rpm 15-17k tq on bottom 12-14k tq off 235k PUW 155k SOW 180k ROT 14 to 16k WOB 11.1 ppg ECD MW 10.6 ppg BGG 24 units adding NXS Lube as needed to control torque, Distance to Plan 70.92' 69.21 low 15.47 left.;Pump Hi vis sweep around, circulate and clean hole 500 gpm 3400 psi sweep back 20 bbls late and 15% increase in cuttings, obtain SPR's flow check the well slight loss.;POOH w/ pumps 3 bpm differential sticking having to break free with rotary f/ 12850' t/ 12500'. 2/23/2020 Cont wiper trip up hole from 12,500’ to 11,820’. Idled one pump and rotate string to break free, then pulled with pump only. Up wt 240K. Just prior to 11,820’ floorhands noticed topdrive spit a shot of oil and Rineer motor making odd noise while MU on next stand. Makeup and break OK, no more noise.;Serviced rig and topdrive at 11,820'. Found no leaks on topdrive, possibly Rineer motor worn.;RIH on elevators to 12,814’ with no issue. Down wt 145K. MU topdrive on last stand, filled pipe and washed/reamed to bottom at 12,850' with no fill. 170K dwn wt pumping and rotating.;Pumped a hi- vis sweep around followed with a second surf to surf circulation. 489 gpm-3176 psi, 35 rpm-17,500 ft/lbs off bott torque, ECD's at 11.2 ppg, BGG 17 units. Added 1 drum NXS lube to suction pit after sweep. Had a spike of 199 units at bottoms up quickly followed with another of 228 units.;ECD's dropped to 11.1 ppg, BGG back down to 15 units. Hole unloaded pretty good prior to and with sweep to surface, 50% increase in cuttings. Changed a swab on #2 pump during second circ. Obtained new SPR's and LD one single. Released sample catchers.;Pulled up hole from 12,790’ to 10,397' on odd DP breaks, having to MU topdrive, idle pump and rotate to break free, then pump only. Up wt 240 to 250K coming off bottom. Pulled 10 stands and did 10 minute flow check. Fluid dropped 1' in wellbore. Had to backream from 11,096' to 11,016'.;Continue POOH f/ 10,397' t/ 9,520' differential sticking idling pump and breaking over in rotary then pumps only. No other areas that needed to be worked through.;POOH on elevators f/ 9520' t/ 4448' seen 5k over pull pulling bit through window, M/u TIW and Head Pin, P/U Dummy casing joint to verify windwall clearance.;Change out hydraulic reiner motor on top drive, change filters on Hydraulic HPU for top drive, function test top drive with new hydraulic motor. Top Off hydraulic tank. Drilled 8 1/2" hole from 11,430' to 11,628'. q ;Continue Drilling f/ 12,534' t/ 12,850' 5 TD well 12850ft 2/24/2020 Cont rotating topdrive on drill string and making/breaking in connection mode, topdrive functioning properly. Hole taking 2.5 bph. Blew down topdrive, flow check = slight drop in wellbore.;Cont to POOH racking back 18 more stands from 4448', then cont POOH LD 82 joints DP. Racked back HWDP, jar stand and NM flex DC’s. Calculated hole fill = 33 bbls, actual hole fill = 36 bbls.;Plugged in and downloaded MWD data, removed pulser, LD TM, PWD and DGR collars, LD ADR and DM collars. Drained and flushed motor, broke off Kymera bit. Bit graded: 1-3-CT-T-X-I-DL-TD on PDC side, 1-2- WT-C-E-I-NO-TD on roller cone side.;Cleaned and cleared rig floor, removed Sperry tools from catwalk, staged next BHA, removed GeoTap tool from heated refer van and staged on walk.;MU 8.5" Smith tricone on bit sub, 6.75" stab, DM collar, GeoTap collar, RFO = 114.58°, MU ALD, CTN, DGR, HCIM and TM collars. Plugged in and uploaded MWD tool, shallow pulse tested tools, held PJSM and loaded nuke sources.;RIH F/ 845' t/ 2383' Filling pipe, noticed grabber dies worn on the bottom.;Change out grabber dies on top drive.;Continue RIH f/ 2383' t/ 4423'.;Fill pipe break circulation 4.5 bpm 350 psi warm mud while slipping and cutting drilling line, Slip and cut drilling line service top drive and blocks.;RIH f/ 4423' t/ 5234' set down 20k at window 4472' P/U and set down again worked through with a few bobbles continue RIH with no issues. 2/25/2020 Cont trip in open hole from 5234' to 11,063'. Initial dwn wt 80K. Set down at 9613' twice at 20K, up wt 165K, dwn wt 95K, worked through ok. After filling pipe at 11,030' pipe, could not SO and break free, MU topdrive and string was free with no pump or rotation. Set down 3 times at 10,650', MU;topdrive, filled pipe, washed and reamed stand down to clean up (bott of a slide, coming into a coal). MU topdrive at 11,063', filled pipe and set depth.;CBU 235 gpm 1050 psi Max gas 412 units 175k PUW 104k SOW 128k ROT.;Madd Pass @ 200 fph f/ 11100' t/ 12010' 417 gpm 2220 psi 60 rpm 15-18k tq.;Continue Madd Passing f/ 12010' t/ 12590' 415 gpm 2200 psi 60 rpm 12-15k tq 200 fph logging speed, Added 2 drums of lube to control higher torque values. 2/26/2020 Continue Madd Passing f/12,590' t/ 12,724' 415 gpm 2250 psi 60 rpm 14-19k tq 200 fph logging speed, up/dn/rot 182/120/142k Adding lube to control higher torque values.;Lost +- 500 psi in SPP. Chk surface equipment . both suctions screen good, SPR shows issue w/ #2 MP go through pump chg out discharge valve and swab.;Continue Mad pass f/ 12,724' t/ TD @ 12,850' w/ #1 MP @ reduced rate of 262 gpm and 1050 psi 60 rpm @ 14.5-20k TQ. while working on MP#2.;Pump 18 bbl sweep high vis sweep around w/ both pumps @ 430 gpm @ 2450 psi, 60 rpm. B 40 bbls late w/ 20% in cress cuttings continue circ clean crew chg.;Pooh tie -in and Geo tapping stations as per DD & MWD sample station #1 and #2 @ 12,706, and 12,693' got good pressures w/ first set and knocked loose in dn stroke w/ +- 50k dn wt shoot station #3 @ twice 12,551' and 12,650' both bad.;Pooh on elevators f/ 12,674' t/ 11923'.;Correlate with gamma Geo tap station #4 & #5 @ 11724' and 11690'.;POOH f/ 11690' t/ 11246' on elevators.;Correlate with gamma geo tap stations #6and #7 @ 11245' & 11190'.;Stand back stand geo tap station #8 and #9 @ 11153' and 11122'.;Rack back stand Geo tap stations # 10 and @ 11060' and retook again @ 11058'.;Geo tap Station #11 @ 10999' and #12 10984', #13 10951', #14 10948' and 10944' reshoot stations.;POOH on elevators f/ 10942' t/ 10, 596'.;Correlate with gamma and geo tap Station #16 @ 10596', POOH t/ Station #17 @ 10437'. 2/27/2020 Continue Pooh rack back two std T/ 10,1033' Mad pass @ 100 fph and correlate and attempt pressure station @ 10,009', 10,008', 10,007' w/ no seal. Rack back one std and 100 fph mad pass correlation f/ 9910' t/ 9885' rack back other std and attempt pressure station at 9878' and 9877'.;Attempt pressure station @ 9824' Rih t/ 9975' (took weight again at 9920' last slide into coal +50k wipe X3 to clean up same) test pressure seal on engage shell area w/ good seal @ 9975'. Rack back two std and 100 fph mad pass correlation f/ 9793' t/ 9773' and attempt pressure station @ 9772'.;Continue geo tap stations as per DD/MWD w/ Geo revised sample stations attempting to get good seal correlate and attempt pressure sample @ 9587' 9586' & 9585'.;Pooh f/ 9605' t/ 9143' w/ 1.43 bbl over cal.;100 fph mad pass and Correlation f/ 9143' t/ 9114' and attempt pressure sample @ 9090' w/ one MP @ 290 gpm while going through other MP w/ no luck. Both pumps on line attempt pressure samples @ 9090' and 9087'.;Pooh rack back one std and collect pressure sample @ 9027'.;Pooh rack back one std and collect pressure sample @ 8957'.;Pooh rack back two std and collect pressure sample @ 8835'.;POOH and collect pressure sample at 8541'.;POOH and collect pressure sample @ 8383'.;POOH f/ 8383' t/ 6350' hole not taking correct displacement, Pump out 3 bpm 160 psi.;Take pressure samples @ 6310' and 6262'.;POOH f/ 6262' t/ 4421'.;Service rig and top drive, check the oil in the floor motor.;Pump Dry Job, R/U t/ L/D Drill Pipe.;POOH L/D DP f/ 4420' t/ 4150'. 2/28/2020 Continue POOH L/D DP f/4150' t/ jars. Cleaning ID and OD and servicing threads w/ 4.3 bbls over calc.;L/dn and inspect bha #5 bit graded 1-1-1/16 w/ 5.6 bbls over calc. Clean and clear floor.;M/U Bull Nose RIH w/ stands f/ derrick t/ 4335'.;Mix and pump dry job, had suction airboat leaking in hopper house replaced, finished pumping dry job, blew down top drive.;POOH f/ 4335' t/ 3477' L/D Dp Singles cleaning and re doping threads.;Continue POOH L/D DP Singles f/ 3477' t/ 590'. 2/29/2020 Continue POOH L/D DP Singles cleaning ID & OD & servicing threads f/ 590' t/ surface with an inhibited dry job and 8.8 bbls over calc. for trip.;service rig, Grease blocks, TDS Crown, linkage & DWK inspect linkages and drive shaft hardwear while monitoring well on trip tank @ +- 3/4 bph loss rate.;Rih w/ last 66 std of DP t/ 4117'.;kelly up and brk circ Pump a inhibited dry job and blow dn lines.;Resume POOH L/D DP Singles cleaning ID & OD & servicing threads f/ 4117' t/ surface with an inhibited dry job and 4.8 bbls over calc. for trip.;Monitor well on trip tank while clear and cleaning floor w/ .40 bph loss rate.;drain stack, Pull wear ring, set test plug, R/U t/ test BOP's, change upper rams t/ 5.5'' Solid body, fill stack and test jt.;Test upper rams and annular w/ 5.5'' test jt 250/4500 psi on rams 250/2500 psi on annular all tests for 5 min low 10 min high R/D test equipment.;R/U to run 5.5'' Casing, R/U Weatherford casing equipment, set up pipe racks for loading casing transfer casing to racks.;P/U shoe track clean and baker lock threads on first three jts, torque as per Weatherford, check floats floats held RIH w/ 5.5'' Casing as per detail filling pipe every jt topping off every 10 jts for displacement installing centralizers every jt t/ 4453'.;M/U Circulating head break circulation 3 bpm 50 psi 4 bpm 70 psi. 3/1/2020 Continue circulate btm/up and stage up rate 3 - 6 bpm @ 150 psi @ 4451' w/ max gas of 20 units and 10.7 MW.;Continue P/up rih w/ 5.5" 17# P- 110 CDC / CDCHT csg as per drillers running tally filling on fly t/ 6753'.;Continue stage in brk circulation and circ btm/up a nd stage up rate 3 - 6 bpm @160 psi w/ max gas of 27 units and 10.8 ppg mud weight.;Continue P/up rih w/ 5.5" 17# P-110 CDC / CDCHT csg as per drillers running tally filling on fly t/ 9093 ' started taking weight.;Kelly up, brk circulation and wash dn and work through pack-offs f/ 9093' t/ 9100' at work pipe and finish circ btm/up w/ max gas of 71 units and 11.0 ppg mud weight.;work wash dn t/ 9152' w/ Mud weight out at 11.0 ppg Then able rih w/ out washing t/ 9955'.;Break Circulation stage pumps up t/ 262 gpm 320 psi 128k PUW 86k SOW 310 units gas on bottoms up.;Continue RIH w/ 5.5'' Casing f/ 9955' t/ 12850', Work through tight spots @ 9974' and 10174' setting 30k down wt working through, observe differential sticking having to break over to get moving, tag bottom verify tag 180k PUW 90k SOW, L/D 2 jts of casing.;M/U Hanger and Landing jt, @ 0154hrs, While picking up on string hook load read 190k landing jt failed and parted @ IBTM pup jt connection above hanger, dropped approximately 6' wedging in the air slip bowl. Shut down verified personnel and equipment were safe. Notified management.;Perform derrick inspection, inspect top drive and drilling line sheaves, inspect draworks, Inspect rotary beams and bushings, No visible damage, L/D 5.5'' landing joint piece. Wellhead hand went to get new crossover to hanger. M/U new landing jt and circulating head. M/U new cross over to hanger on;new landing jt, back out parted joint and remove from hanger, M/U new landing joint.;P/U and remove slips f/ hanger inspect hanger, good to run, Establish circulation 3 bpm 300 psi PUW 220k SOW 80k Work string free, slack off and land on hanger Stage pumps 168 gpm 415 psi while waiting on new landing joint to be made, spot in cementers. yj p p , set test plug, R/U t/ test BOP's, change upper rams t/ 5.5'' Solid body, landing joint parted Continue Madd Passing f/12,590' t/ 12,724' pp ;R/U to run 5.5'' Casing, R gg gg f casing.;M/U Hanger and Landing jt, @ 0154hrs, While picking up on RIH with 5 1/2" csg ggg yg j string hook load read 190k landing jt failed and parted @ IBTM pup jt connection above hanger, g dropped approximately 6' wedging in the air slip ggj@ pg 3/2/2020 Continue circ @ 250 gpm and 370 psi and high gas at btm up of 570 units. while waiting on new landing joint to be made, only able to work hanger flutes in out bowl ( flat top hanger catching ram cavity) spot in cementers.;Short landing jt on location. land out hanger, dn pump, drain stack remove and l/dn jt csg w/ circ head. p/up and m/up new short landing jt chg to long bails r/ up cmt head and lines flush lines to cutting tank establish circ w/ rig.;Circulate and condition mud while waiting on Halliburton trucks to regen 259 gpm 525 psi.;Test Lines t/ 1200 psi low 4500 psi High Pump 30 bbls of 12 ppg spacer 4 bpm, Drop bottom plug pump 176 bbls 12.5ppg lead cement @ 5 bpm 125 psi followed by 267.1 bbls 15.3 ppg of tail cement 6 bpm 320 psi Drop top plug and displace with 198.8 bbls of mud, Did not bump plugs, checked floats held.;bled back 1.25 bbls floats good, R/D and flush lines, R/D cement equipment, release Halliburton, L/D Casing handling Equipment, total lost during cement job 39 bbls, CIP 2019 hrs, Changed out weight indicator.;Tubing began to have slight flow stabbed TIW and monitored pressure built up t/ 360 psi in and hour an a half, bled tubing down t/ 0 psi monitor build up in 30 min it had built up t/ 125 psi, Stage pipe racks and load w/ 2 7/8'' work string. bled off tubing slight weep, Pulled landing jt.;M/U Pack off, RIH land pack off and engage Lock down screws, Change out air boots on riser and flow box, continue working on 2 7/8'' work string strapping and tallying, get handling equipment to rig floor, slips elevators and bails. 3/3/2020 Replaced air boot on bell nipple, verified count of 2-7/8" PH-6 7.9 lbs. per/ft. work string on location (430 jts.), staged 2-7/8" BHA & handling equip. on rig floor, R/U air slips.;Hung off blocks, slip & cut 95' of drill line, changed out bad U-bolt on drill line dog knot.;Resumed strapping & tallying 2-7/8" pipe on racks, completed cleaning pits, 4-6, R/U Weatherford power tongs & air slips.;Finished strapping & tallying remainder of 410 jts. of 2-7/8" PH- 6 7.9 lbs. per/ft. work string, cont. working on cleaning pits 1-3 & 8 , prepped rig floor for TIH w/ work string.;Rig service- greased & inspected crown, TD, iron roughneck & DWKS.;Held PJSM w/ rig crew & Weatherford tong operators, started P/U & singling in the hole w/ 2-7/8" PH-6 7.9 ppf. work string, F/surface-T/4261', rabbiting pipe, cleaning & re-doping threads w/ Jet lube NCS-30 Arctic grade pipe dope, finished cleaning pits 1-3 & 8, flushed & cleaned centrifuge,;started mixing 1st 300 bbl batch of 6% KCL brine.;Held PTSM, crew change, resumed P/U & singling in the hole w/ 2- 7/8" PH-6 7.9 ppf. work string F/4261'-T/7300'.;Preformed rig service-greased & inspected DWKS, linkages. drive shaft, TD, blocks & crown, started POOH racking back pipe in derrick, current depth of 7118'.;Hauled 65 bbls solids to KGF G&I -Cumulative: 1173 bbls -Hauled 521 bbls fluid to KGF G&I -Cumulative: 3,647 bbls -Daily down hole losses: 0 bbls -Cumulative: 123 bbls -Daily Metal: 0 lbs. -Cumulative: 291 lbs. 3/4/2020 Tbg staying behind kelly hose adjust kelly hose. and attempt pump dry job.;Trouble shoot mud line found TDS and kelly hose and stand pipe froze thaw same re-install kelly hose.;Pump dry job and resume pooh rack back in derrick f/ 7118'-T/surface, called out NOS well head Rep Sam.;Cleaned & prepped rig floor for testing, removed air slips, R/U test pump to mezz, opened choke & kill HCR, purged air from lines & stack w/ water from test pump, closed blind rams, filled choke manifold w/ water and purged air.;Tested casing T/4500 psi for 30 min on chart (ok), pumped a total of 167 gals and bleed back 153 gals.;Blew down mud cross, TD, choke manifold, vacuumed out and rinsed stack.;Held PTSM, crew change, changed our 5.5" rams to 2-7/8" x 5" VBR's, tested TD, kelley hose, & standpipe connection T/4500 psi for 5 min (ok), blew down all mud lines.;Cleaned & prepped rig floor for P/U 2-7/8" PH-6 7.9 ppf work string.;Held PJSM w/ Weatherford & rig crew, R/U power tongs & air slips.;P/U & painted 1st jt of 2-7/8" work string, P/U & singling in the hole w/ 30 jts. of 2-7/8" PH-6 7.9 ppf work string, rabbiting pipe, cleaning & re-doping threads w/ Jet lube NCS-30 arctic grade pipe dope.;POOH & racked back 15 stds. in derrick on ODS, pulled air slips & set down power tongs.;Cleaned up rig floor, vacuumed out stack & set 2 way check, B/O TIW from XO & M/U dart valve to side entry sub, P/U test jt. & M/U top connection to side entry & bottom connection to blanking test sub.;Flood stack & choke, currently performing shell test, AOGCC Rep Adam Earl will be on location to witness BOP test @ 06:00 hrs.;Hauled 0 bbls solids to KGF G&I -Cumulative: 1173 bbls -Hauled 0 bbls fluid to KGF G&I -Cumulative: 3,647 bbls -Daily down hole losses: 0 bbls -Cumulative: 123 bbls -Daily Metal: 0 lbs. -Cumulative: 291 lbs. 3/5/2020 Continue test bops witnessed by Adam Earl w/ AOGCC. Amanda Eagle w/ BLM waived witness. Had Two F/P inside manual kill valve and choke HCR service both and re-test ok and one time variance from Jim Regg w/ AOGCC for no test of single gate w/ bag test of 4000 psi.;Blow dn Shim sub base, pull two way chk and clear clean floor finish tally 2-7/8" an entering in Pason.;P/up and M/up Bha #6 4-3/4" roller cone bit + -5-1/2" scraper + XO set TDS torque RIH out derrick F/ surface- T/1809'.;Broke circulation & pumped BU, GPM-260 SPM-107 SPP-830, blew down TD, blew down TD.;Re-checked TD torq. against WTC power tongs & adjusted to 4100 ft./lbs.;Cont. RIH out of derrick w/ 2-7/8" PH-6 7.9 ppf work string F/1809'-T/3940', P/U-28K.;Broke circulation & CBU, GPM-257 SPM-106 SPP-1615 psi, established rotary TQ values @ 10 RPM=1150 TQ, 20 RPM=1575 TQ , & 30 RPM=2050 TQ. Blew down TD.;Resumed RIH w/ 2-7/8" work string out of the derrick F/3940'-T/5506'.;Held PTSM, crew change, cont. RIH w/ 2-7/8" work string out of the derrick F/5506''-T/6084'.;Broke circulation & CBU, GPM-256 SPM-106 SPP-2350 psi, blew down TD.;Resumed RIH w/ 2-7/8" PH-6 7.9 ppf work string out of the derrick F/6084-T/8156'.;Broke circulation & CBU, GPM-252 SPM-104 SPP-2960 psi, established rotary TQ values @ 10 RPM=2630 TQ, 20 RPM=2950 TQ , & 30 RPM= 3050 TQ. P/U-49K S/O-42K ROT-41K Blew down TD.;Began P/U & singling in hole w/ 2-7/8" PH-6 7.9 ppf work string F/8156' to current depth of 9292', end up L/D 2 bad jts.;Hauled 0 bbls solids to KGF G&I -Cumulative: 1173 bbls -Hauled 0 bbls fluid to KGF G&I -Cumulative: 3,647 bbls -Daily down hole losses: 0 bbls -Cumulative: 123 bbls -Daily Metal: 0 lbs. -Cumulative: 291 lbs. cement 5 1/2" csg Continue test bops witnessed by Adam Earl w/ AOGCC. A p pg ;Tested casing T/4500 psi for 30 min on chart (ok) Continue circ @ 250 gpm and 370 psi test casing to 4500 psi 3/6/2020 Continue P/U & singling in hole w/ 2-7/8" PH-6 7.9 ppf work string F/9292' T/ 10033'.;Circ btm up X2 stage up t/ 244 gpm @ 3400 psi up/dn/rot 60/48/50 TQ 10 rpm @ 3350 and 20 rpm @ 3700 ft/lb, blow dn lines.;service rig and verify correct TDS torque settings.;Resume P/up 2-7/8" and singling in hole f/ 10033' t/ 11,984' up/dn 78/58k.;Circ clean stage rate t/ 247 gpm @ 3350 psi & blow dn lines.;Resume P/up 2-7/8" and singling in hole f/ 11,984'' t/ 11,522' w/ 2k tag work through t/ 4k tag @ 12,546' total 3 bad jts chg liners in #2 mp t/ 4-1/2".;Attempt wash thru @ 12, 546' @ 214 gpm @ 3450 no go discuss options w/ town.;Circ. and lube up short system t/ 2% w/ NXS swap to MP#2 w/ 4-1/2" liners & lost coupler on #2 pre charge pump work pipe and chg out same.;#2 MP back on line establish rotation and parameters 35-40 rpm w/ 2900-3650 ft/lbs @ 214 gpm @ 3342 psi Drill plugs and cmt f/ 12,546' t/12,693'. Turned on centrifuge and began cutting MW back.;Held PTSM, crew change, cont. drilling cmt. F/12,693'- T/12,769', GPM-205 SPM-105 SPP-2850 psi TQ-4.7/5.1K RPM-35 P/U-80K S/O-60K ROT-65K WOB-2/3K MW-9.5 ppg.;Cont. drilling cmt. F/12,769'- T/12,804, tagged bottom plug @ 12,804', P/U & verified tag. GPM-206 SPM-105 SPP-2750 psi TQ @ tag-5.2/5.5K RPM-36 P/U-81K S/O-60K ROT- 68K WOB-2/3K MW-9.4 ppg.;CBU to verify plug depth, upon BU started seeing bottom plug chunks (orange) coming across the shakers, currently cont. to circulate well clean. GPM-206 SPM-105 SPP-2640 psi TQ-5K RPM-38 P/U-81K S/O-60K ROT-65K MW-9.3 ppg.;Hauled 4 bbls solids to KGF G&I -Cumulative: 1177 bbls -Hauled 36 bbls fluid to KGF G&I -Cumulative: 3,682 bbls -Daily down hole losses: 0 bbls -Cumulative: 123 bbls -Daily Metal: 0 lbs. -Cumulative: 291 lbs. 3/7/2020 Rotate dn to verify tag did not take weight 12,804' rotate dn t/ 12,809' w/ no tag. Make connection and wash dn t/ 12,814' w/ 5k set dn X3.;CBU btm/up recovered some more bottom plug chunks (orange).;Rotate dn and work pipe t/ 5k set dn @ 12,820' and circ other btm up w/ minimal rubber.;Pre form csg test t/ 4500 psi for 10 min (ok).;Blow dn lines and r/up to reverse circ.;Reverse 200 bbls to ensure hole is clean @ 4.8 bpm @ 2597 psi.;Reverse circ 19 bbl high vis spacer and displace well t/ 6% KCL, pumped a total of 394 bbls of 6% KCL brine, over displace well by 132 bbls to clean up fluid.;R/D XO, side entry sub, TIW, & pup jt., filled trip tank & swapped elevators. Started flushing lines & cleaning pits.;POOH L/D 2-7/8" PH-6 7.9 ppf work string, vacuuming ball through pipe, cleaning threads, re-doping, and installing clean thread protectors F/12,820'-T/5997'. Cont. cleaning mud pits.;Held PTSM, crew change, cont. POOH L/D 2-7/8" PH-6 7.9 ppf work string, vacuuming ball through pipe, cleaning threads, re- doping, and installing clean thread protectors F/5997'-T/2,676', cont. cleaning pits & prepping for rig move.;Hauled 43 bbls solids to KGF G&I -Cumulative: 1,219 bbls -Hauled 642 bbls fluid to KGF G&I -Cumulative: 4,325 bbls -Daily down hole losses: 0 bbls -Cumulative: 123 bbls -Daily Metal: 0 lbs. -Cumulative: 291 lbs. 3/8/2020 Continue POOH L/D 2-7/8" PH-6 7.9 ppf work string, vacuuming ball through pipe, cleaning threads, re-doping, and installing clean thread protectors F/2676'-T/surface and cut hole short 50-100' and plan to top fill one bbl diesel for freeze protect continue clean pits.;Brk & inspect bit, scrapper wore but spring on pads still good bit cones very loose.;R/dn weatherford and pipe handling equipment set BPV clean clear floor. R/up flush clean fluid through TSD and MP #1 Blow dn lines r/dn same.;crew change Nip/dn bleed dn koomey, pull flow line, remove koomey lines from bope , Pull l/dn mouse hole, remove hole fill, 4 bolt stack, install bop trolly beam, remove choke and kill hoses, Pull flow nipple, remove flow box, removed/L/D both sets of tongs, removed saver sub from TD.;R/D gen #3, started on pickling MP 1 & 2, took boiler #2 off line, hooked up BOP trollies to BOP stack, finish N/D, rinsed out stack.;Cont. to inspect & pickle MP's, blew down & pickled test pump w/ RV antifreeze, removed Kelley hose & service loop from TD, removed TD torq bushing from torq tube, pined TD in cradle & L/D down TD using new L/D procedure (ok), Blew all lines down in pits, R/D transfer lines between hoppers.;Pulled equalizers lines between pit modules, R/D shaker slides, R/D poor boy dump line, vacuumed out water from snail pumps, R/D bleeder from MP & hopper #1, cleaned suction screens, drained centrifugal on MP's & rod wash pumps, disconnected shock hose & changed out hopper #1 mix pump.;Held PJSM, crew change, R/D pits & centrifuge pump/equip., complete MP suction teardown & cleanout, R/D misc. cables from doghouse to pits, cut & slip 9 wraps of drum (42'), prepping mast to scope down, shut down boiler #1, blew down all steam lines & removed steam trap disks.;R/D TD jumper lines to sub, R/D centrifuge roof & connecting tarps, R/D choke vent lines & jumper line to gas buster, L/D gas buster & R/d vent tube, R/D Pason cables & lines from choke, pits, & pumps. preformed mast inspection, disconnected all Pason or electrical lines from mast. R/D monkey board;in mast section prior to scoping mast down.;Hauled 7 bbls solids to KGF G&I -Cumulative: 1,226 bbls -Hauled 342 bbls fluid to KGF G&I -Cumulative: 4,667 bbls -Daily down hole losses: 0 bbls -Cumulative: 123 bbls -Daily Metal: 0 lbs. -Cumulative: 291 lbs. 3/9/2020 Continue r/dn and Scope dn mast and l/out lower section of torque tube. Tie up Kelly hose, hang off blocks, unspool drlg line and tie up lines. Disconnect elect. t/ pump house, TDS HPU, boilers and pits and prep for trucks. Disconnect koomey lines, and jumpers between remaining Modules;prep to lay over mast. R/dn misc. floor wind walls, tarps and frame works.;Crew change PTSM continue work on chipping thawing and removing handy berm from ice, stowing elect and grass hopper and prepping modules for trucks & work on Finial grade and shoot of BCU-04 pad.;Trucks and cranes on location remove pre mix tank and gas buster, pipe skate and rig mats under same and pit #2. Spot crane remove needed wind walls and Choke house continue removing and scattering pits pumps and boilers to access need rig matts for BCU-04rd.;Remove Bope and load on trailer, picked & loaded choke house, laid over derrick, scoped dog house into water tank, spotted crane, picked & loaded derrick and carrier onto trailers, tail rolled dog house/water tank, TD HPU, and Gen 1&2, picked sub off pony walls & tail rolled pony walls to Pad #4,;tail rolled sub and staged out of away, cleaned up loose debris on location, scraped mats to help clean off the majority of snow & ice. Electrician and motorman started installing electric motor on mix pump in hopper house #1 off line.;Held PTSM, crew change, Finished scraping mats, staged multiple stacks of iced up mats in rig containment in stacks of 9 w/ 4x4 in between them, covered w/ rig liner and warm w/ jet heaters to de-ice mats before setting at BCU- 04RD.;Cont. removing snow around office trailers & cleaning up pad. Final report for BCU-19RD, changing to BCU-04RD AFE at 06:00 hrs. 3/11/2020 Sign in. Mobe to location. PTW and JSA. Rig up lubricator and CBL tool string.;RIH w/3.25" CBL and centralizers. Found fluid level at 250' and tagged at 12,792' correlated to OHL. POOH at 70 fpm logging. Well has good cement bond from 12,792' to +/- 4026'. The lead/Tail interface is at +/- 5750'. POOH.;Rig down equipment and secure well. AKE-Line will be sending out finished log and invocie later. POOH L/D 2-7/8" PH-6 7.9 ppf work string, vacuuming ball through pipe, cleaning threads, re-doping, and installing clean thread protectors F/2676'-T/s Sign in. Mobe to location. PTW and JSA. Rig up lubricator and CBL tool string.;RIH w/3.25" CBL and centralizers. Found fluid level at 250' and taggedggpggg at 12,792' correlated to OHL. POOH at 70 fpm logging. Well has good cement bond from 12,792' to +/- 4026'. The lead/Tail interface is at +/- 5750'. rrpggg g POOH.;Rig down equipment and secure well. AKE-Line will be sending out finished log and invocie later. CBL on 5 1/2" Activity Date Ops Summary 3/27/2020 PTW, JSA with SLB, Cruz and Hilcorp Rep,MIRU SLB CTU equipment. CTU unit, pump truck, 2x iron racks, choke skid, BOPE skid. Spot equipment on Herculite pit liner. Spot 400 bbl rain for rent tank. Install BOPE stack on well. Function test. Spot in N2 pump and Air Liquid N2 transport.,24 hr BOPE test witness notification sent 3/26/2020. @1123 hrs. Test witness waived by Jim Regg on 3/26/2020 @ 2251 hrs. Test all rams and valves 250/5000 psi. Accumulator draw down test completed. 1 FP on outside choke block valve. Greased and re tested. Valve passed.,Rig up N2 transfer hose. Perform location walk around. Location secure. SDFN. 3/28/2020 PTW, JSA with SLB, Cruz, and Hilcorp Rep. Discuss dangers of multiple field operations and vehicle travel. E-line, drilling rig, and coil .,Pick injector head. Stab 10' lubricator. Make up roll on coil connector pull test 25k. Make up 1.75" stinger and 2.125" OD ball drop nozzle with 1x 1.2" ID hole for reverse N2 lift. Stab on well. PT stack 250/5000 psi.,Open master and swab. 0 psi WHP. RIH (cased hole). Start cooling down N2. Online with N2 Down production casing x CT annulus at 800 scf/min. CT depth 1600'. Taking returns up CT through choke skid into 400 bbl difuser tank.,CT @ 5700'. Fluid returns to surface. WT check 5700 lbs up -300 RIH weight. Park coil at 12,750'. Unload majority of well bore fluid from 12,750' so nozzle doesn't get plugged from debris sitting on top of PBTD. WHP (N2 pressure) 2717 psi. Fluid turning corner. Back side of CT all N2. Max WHP(N2) broke over at 3246 psi WHP. 298 bbls returned to surface. N2 at surface. 460,000 scf used to lift fluids.,Creep in hole to lift remaining fluid from 12,750' Started stacking weight at 12,795'. Stopped CT at Max depth of 12,808' due to loss of weight. POOH to surface while lifting the last 1.4 bbls of fluid to surface. CT @ 11,064' pulling OOH. Shut down N2 pump. 3128 psi WHP.,continue to POOH . Tagged up at surface. Shut master and swab. Pop off well and break down BHA and 10' lubricator. Set injector head on back deck. Install night cap on BOPE.,N2 cooled down. Open master and swab. N2 wellhead pressure 3100 psi. Bullhead N2 to pressure up wellbore. Out of N2 Close master and swab. 3860 PSI SITP. N2 tank gauge was off. Plan was to shut in well with 4100 psi N2. N2 pump will remain on location. Will bump up tubing pressure Monday 3/30/20 N2 pr oduct will arrive for BCU-07.,Rig down CTU equipment and stage on edge of pad. SLB will move equipment the following day to GO-1. 3/31/2020 Sign in. PTW and JSA. Mobe to location. Rig up on well. PT hard lines to 4500 psi. Pressure up tubing from 3800 psi to 42150 psi for perf job. Rig down hard lines and mobe to BCU-7A. 4/6/2020 PTW and JSA. Replaced wellhead connection with HLB, Put lub together. Found out that perf guns were 3-1/8" perf charges in 3-1/8" barrel. That gun can't be shot in gas. Called GEO and HLB took guns back to there shop to change the 3-1/8" charges and put them in a 3-3/8" gun that can be shot in gas. Well be back in am 4/7/2020 PTW and JSA, Rig up lubricator and PT to 250 psi low nd 5000 psi high. TP - 4245 psi,RIH w/3-3/8x25' (3-1/8"charges) Razor HC and tie into OHL. Got down to 12,100' and just had 1 wrap left on drum. HLB called town. Drum was suppose to have 13,700' of e-line on drum but did not. They didn't have enough line to reach the proposed perf depth. That was a 7/32" line. They have 20K feet of 5/16" line on truck but the crane isn't big enough. They are going to have grease tubes and everything they need to run,that line tomorrow morning. We will use Cruz crane also. POOH with 7 /32" line and tools. Secure well. 4/8/2020 Meet at Pad. PTW, JSA and SIMOPS with Halliburton and Cruz crane operator. Rig up lubricator, PT to 250 psi low and 5000 psi high. TP - 4250 psi.,RIH w/3-3/8" (3-1/8" charges)x25' Razor HC, 6 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perf from 12,683' to 12,708' with 4253.6 psi. Spotted and fired gun with 4253.6 psi. After 5 min - 4255.10 psi, 10 min - 4254.2 psi and 15 min - 4253.1 psi. POOH. All shots fired and gun was dry. They had to go in and out of hole slower due to bigger line and pressure.,Rig down equipment and turn well over to field. 4/10/2020 Spot and rig up equipment and lubricator. PT to 250 psi low and 3500 psi high.,RIH w/4.74" CIBP and tie into OHL. Run correlation log. There was a collar at 12,667'. Was going to set plug at 12,670' but collar was to close. We decided to set top of plug at 12,660'. That gave us some room. Spotted plug at 12,660' and set plug. Picked up 30' and went back down and tagged plug. POOH. Setting tool looked good.,Rig down lubricator and secure well. Will be back at 0700 hrs to make 2 runs of cement bailer (35') to dump on top of plug. 4/11/2020 PTW and JSA. Rig up lubricator and PT to 250 psi low and 3500 psi high. TP - 24 psi,RIH w/4"x30' (18') 17 ppg cement and tag plug at 12,660' correlated. Pick up 32' and dump cement. Watch weight drop about 50 lb as cement leaves bailer. POOH. Good dump.,RIH w/4"x30' (18') 17 ppg cement to 12,640' correlated. That is about 2' above first dump of cement. Dump cement out of bailer and watch weight drop about 50 lb as cement leaves bailer. Had PTW, JSA and SIMOPS w/SLB Coil. POOH. Good dump. Estimated Top Of Cement - 12,624' (36') and Cement In Place - 1300 hrs. The 2 cement samples are in the office. Coil tubing was spotting their equipment as we were dumping cement.,Just the equipment that was safe to do so.,Rig down E- line and finish rigging up coil tubing and BOPS.. Witness waived by Jim Regg of AOGCC for the Coil Tubing BOP Test. Pressure tested BOP's per AOGCC requirements. Secure well. Will be back in the morning at 0700 hrs to blow well dry and pressure up tubing for perf job. 4/12/2020 PTW, JSA. with SLB and Cruz. Pump ball thru 1.75" coil tubing reel to make sure its clear.,Stab on injector head. RIH w/2-1/8" Jet Nozzle to 3000'. Come on line with N2 at 1250 scf. RIH down to 6000' and stay at that depth for approx. 30 min. Unloaded 120 bbl of fluid from well. RIH pumping N2 down to 12,000'. Sat at this depth for 1 hour pumping N2 and unloading fluid. Started out of hole and 240 bbl of fluid had been unloaded from the well. When coil got to surface they had unloaded 300 bbls. It calls for,313 bbl counting coil tubing volume. SLB thinks fluid level is at 12,000' where its suppose to be. If not fluid level should be about 11,500'. Pressured tubing up to 3020'. Rigging down coil and sending to KGF. Pumped a total of 534,219 scf and have approx. 1600 gals left. NOTE: We will be perforating in the morning. 4/13/2020 PTW and JSA. Spot equipment and rig up lubricator. PT lubricator to 250 psi low and 3500 psi high. TP - 2930 psi.,RIH w/3-3/8" (3-1/8" charges)x13' Razor HC, 6 spf, 60 deg phase and tie into OHL. Went down and tagged TOC at 12,617' (43' of cement on top of plug). Run TOC log and send to town. Run correlation log and send to town. Get ok to perforate from 10,957' to 10,970'. Spot and fire gun with 2730 psi on tubing. After 5 min - 2779', 10 min - 2790 psi and 15 min - 2803'. POOH. All shots fired and gun was dry.,Rig down lubricator and turn well over to field. TP - 2920 psi. Field fixing to bled N2 off and bring on well. on (LAT/LONG): Elevation (RKB): API #: Well Name: Field: County/State: BCU-019RD Beaver Creek Hilcorp Energy Company Composite Report Kenai, Alaska Contractor AFE #: AFE $: Job Name:2010015C BCU-19RD Completion Spud Date: gg plug at 12,660' and set plug. g ok to perf from 12,683' gg Get ok to perforate from 10,957' to 10,970' ,MIRU SLB CTU equipment. j . Unloaded 120 bbl of fluid from well. RIH pumping N2 psi,RIH w/3-3/8x25' (3-1/8"charges) Razor HC and tie into OHL. Got gp p down to 12,100' and just had 1 wrap left on drum. Completion daily logs. p TOC at 12,617' gp Pick up 32' and dump cement. ?? (g) pgp g p 12,708' with 4253.6 psi. Spotted and fired gun with 4253.6 psi. After 5 min - 4255.10 psi, 10 min - 4254.2 psi and 15 min -4253.1 psi. POOH. All shots p CIBP @ 12660' 4/16/2020 PTW, JSA and SIMOPS with AKE-Line and SLB N2 crew. Rig up hard lines and lubricator. PT to 250 psi low and 4500 psi high. TP - 800 psi,RIH w/GPT tool and tie into perf log. Find fluid level at 9260'. Start pressuring well up with N2. SLB pumped N2 at 2500 scf and pressure rose to 4300 psi slowly. Had SLB shut down a couple times to check FL depth. Fluid was going away slow at first but started faster after about 2500 gals pumped. Stop at 4000 gal pumped with 4300 psi on tubing. Let pressure stabilize at approx. 3600 psi. Checked and fluid level was at,the perforations at 10,957'. We had waited about 30 min for pressure to stabilize and fluid did not come back in well. POOH. Rig down SLB N2. Pump 4000 gals of N2 and have between 2400 to 2600 gals left.,RIH w/4.24" OD CIBP, tie into GPT log (GPT log showed the perfs real good) and stop above perfs. Run correlation log. Spot and set CIBP at 10,947' w/3587.9' on tubing. Waited 5 min and pick up 30' and go back down and tag plug. POOH. Setting tool look good.,RIH w/3-3/8' (3- 1/8" charges) and tie into the plug correlation log. Tools set down at 10,917.5'. That makes the tag 29.5' high.Tried several times to go past but could not. We had bled tubing down from 3587.9 psi to 2985 psi while going in hole. . Hard to imagine plug moving up but can't think of anything else. If it is the plug it stopped right below a the tubing collar. Set logs to town . Called and discussed. Will,POOH and rig down.,Rig down lubr icator and secure well. 4/18/2020 PTW, JSA with SLB CT crew, Cruz crane operator, and Hilcorp rep.,Lay pit liner. Spot in Coil Unit, Coil fluid pump, Rain for rent supply and return tanks, Cruz Crane. Offload and spot auxiliary equipment. Pump iron, return iron, choke skid, BOP skid, Lubricator box. Br eak wellhead connection and install 4 1/16" 10K BOP's. Hook up BOP hydraulic hoses and function test. Rig up 1502 iron from pump reel and backside choke. .,Start BOPE test. 24 hr BOPE test witness notification sent 4/17/2020 @ 14:25 hrs. Test witness waived by Jim Regg on 4/17/2020 @ 14:49 hrs via email. Test all rams and valves 250/4900 psi for 5 minutes each. Perform BOP accumulator draw down test and passed.,Blow down BOPE stack with rig air to prevent freezing.. Location walk around complete. SDFN. Yellow jacket oil tools will arrive in AM with motor and mill ass embly. 4/19/2020 PTW, JSA with SLB Coil, Cruz crane operator, Yellow Jacket tool hand, HAK representative.,Pick injector head. Stab 20' of lubricator. Make up 2.875" external slip connector. Pull test 10K, 20K, 35K. Drift Disconnect with .75" ball , Circ sub 5/8" ball. Make up 2.875" DFCV . 2.875" bi di jars, 2.875" disco, 2.875" motor. Fluid pack reel with 33.7 bbls. Pt MHA 250/4900 psi . Good test. Stab on well break 4.06" BOP. One pick. MU 4.75" 3/2 concave junk mill.,Make up BOP lower flange on production stack. PT 250,4900 psi for 5 min. Bleed lubricator to 3000 psi. Open well. Initial WHP 2950 psi. RIH with choke closed. All N2 pressure. Previous E-line GPT found fluid level at 9260'. CT running in hole dry to attempt to push the moving CIBP without milling. Tag CIBP @ 10,901 with 6k down. PU . attempt to stack out on CIBP. Pushed plug from 10,901' to 10,906.2'.,Attempt down jar lick. Jars not firing. No luck to push CIBP further than 10,906.2' . Online down 1.75" CT at 1.8 bbls/min. Crack choke start bleeding down WHP from 3380 psi. After 6 bbls pumped caught fluid at motor.,Attempt mill CIBP at 10,906.2' Not able to make hole or get motor to stall. Pumping 1.8 to 2.0 BBLS/min. RIH at 1/10'/per minute not able to stall motor. PU RIH at 80 ft/min not able to stall motor. Tool hand advises to POOH to check BHA.,POOH to surface. Tag up. close master swab. Pop off well Break down Motor and mill assembly. small part of shear studs stuck in center of mill. Rig back injector head . SDFN. Plan to conference call with YJOS in AM to determine cause of failure. 4/22/2020 PTW, JSA.,Pick injector head. Make up motor and mill. Test motor and mill at surface. Stab on well. PT stack 250/3500 psi.,Open well. RIH with 4.5" 3 bladed concave junk mill. Dry tag 10,901' CTMD. WHP 809 psi.,Mill plug from 10,901' CTMD to break through at 10,907. Bleeding down whp while pumping. After 48 bbls pumped returns to surface. Getting 1:1's.,RIH to to tag TOC @ 12,550.,POOH to surface. Tagged up. Total fluid pump. 355 bbls of produced water.,Break down YJOS MHA. RIG down CTU. 4/24/2020 PTW, JSA with Yellow Jacket E-line and Hilcorp Rep.,MIRU E line unit, crane and support trailer. Make up lubricator and wireline valves. make up and test 40 ARM caliper logging tool. Stab on well. PT stack 250/3500 psi.,RIH Tag bottom 12,561' Uncorrected depth.,Open fingers and Log OOH with 40 ARM caliper from 12,561' -10,850. Tie into perfs from 10,957'-10,970' (13'). Casing looks to be in good shape where CIBP was set at 10,947'.,POOH to surface.,Tagged up. Close upper master and swab. Bleed fluid from lubricator. Pop off well. Install night cap. Rig down Yellow Jacket E-line unit. Send log to town. 4/27/2020 Sign in. Mobe to location. PTW, JSA and SIMOPS w/SLB N2 and Halliburton E-Line. Spot and rig up equipment. PT SLB hard lines and HLB lubricator to 250 psi low and 4500 psi high. TP - 0 psi,RIH w/GPT and find FL at 200'. Start pressuring up tubing with N2. Pressure broke over at 2700 psi. Fluid level went by 2500' and was moving down approx. 35 fpm at 1030 hrs. Should be pushed away about 1430 hrs. Finally got fluid pushed away. Ran correlation log and send to town. Town said we were on depth with log. Rate was 1500 scf at 4000 psi and static out at 3720 psi.,RIH w/Halliburton Easy Drill Bridge Plug and tie into Halliburton GPT log. Run correlation log . Spot and set plug at 10,950' with 3720 psi on tubing. Lost 200 lbs of line tension when plug set. Pick up 30' and went back and tag plug. POOH. Setting tool look good. Good set.,RIH w/2.5"x20' dump bailer loaded with 4 gals pf 16 ppg HLB cement and tag top of plug at 10,950'. Pick up 4' and dumped cement on top of plug (4'). CIP at 0:30 hrs and est rtop of cement at 10,946'. POOH. Good dump.,Rig down equipment and secure well. Will be rigging up at 0500 hrs to perforate, Cement sample is at office. TP - 3680 psi.,Sign In. Mobe to location. PTW and JSA with AKE-Line. Cont on next report date. 4/28/2020 Cont rigging up equipment. Pressure test lubricator to 250 psi low and 3500 psi low.,RIH w/3-3/8"x10' (3-1/8" charges) HC, 6 spf, 60 deg phase and tie into perf correlation log. Tagged TOC at 10,946'. Run correlation log and send to town. Town said to add 1' to our correlation log. Add 1' to log and spot perf gun from 10,925' to 10,935'. Bleed pressure from 3720 psi to 2785 psi. Fired gun with 2788 psi on tubing. After 5 min - 2790 psi, 10 min - 2792 psi and 15 min - 2792 psi. POOH. All shots fired and,gun was dry.,Rig down equipment off tree and turn well over to field. Finish rig down. 5/9/2020 Sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 psi low and 3500 psi high,RIH w/2-7/8"x14' Razor HC, 6spf, 60 deg phase and tie into OHL. Run correlation log. Get ok to perf from 10,923' to 10,937' (14') w/well flowing 777K at 411 psi. Spotted and fired gun. After 5' - 847K at 412 psi, 10 min - 806K at 412 psi and 15 min - 811K at 412 psi. POOH. All shots fired and gun was wet.,RIH w/2-7/8"x10' Razor HC, 6spf, 60 deg phase and tie into OHL. Run correlation log. Get ok to perf from 10,899' to 10,909' (10') w/well flowing 701K at 416 psi. Spotted and fired gun. After 5' - 830K at 416 psi, 10 min - 951K at 416 psi and 15 min - 910K at 417 psi. POOH. All shots fired an d gun was wet.,RIH w/2-7/8"x14' Razor HC, 6spf, 60 deg phase and tie into OHL. Run correlation log. Get ok to perf from 10,10,909'' to 10,923' (14') w/well flowing 1.172MMCF at 416 psi. Spotted and fired gun. After 5 min - 1,18 million at 418 psi, 10 min - 1.28 million at 418 psi and 15 min - 1.29 million at 418 psi. POOH. All shots fired and gun was wet with diesel. I think all runs were diesel.,Rig down lubricator and turn well over to field 5/18/2020 Sign in, mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 psi low and 3500 psi high. Well flowing 1.8 million at 400 psi.,RIH w/GPT tool and tag at 10,953' down pass not calibrated. Save log and come up hole an run a log across Gun 1 perf depth from 10,250' to 9850' correlated with OHL.. Send both logs to town. GPT log showed FL at approx. 10,946' (non correlated) and slugs of water about 200 ' apart up to 5000',RIH w/2-7/8"x15' Razor, HC. 6 spf, 60 deg phase and tie into OHL. Run correlation and send to town. Get ok to perf from 9979' to 9994' (T8 Sand) with well flowing 1706.7 mcfd at 382 psi. Spot and fired gun #1.. After 5 min - 1706.0 mcfd at 384 psi, 10 min - 1780.0 at 384 psi and 15 min - 1832 mcfd at 384 psi. POOH. All shots fired and gun was wet.,RIH w/2-7/8"x10' Razor, HC. 6 spf, 60 deg phase and tie into OHL. Run correlation and send to town. Get ok to perf from 9850' to 9860' (T7B Sand) with well flowing 1792 mcfd at 382 psi. Spot and fired gun gun #2. After 5 min - 1756 mcfd at 384.5 psi, 10 min - 1789.7 at 384.5 psi and 15 min - 1834.1 mcfd at 385.7 psi. POOH. All shots fired and gun was wet.,RIH w/2-7/8"x10' Razor, HC. 6 spf, 60 deg phase and tie into OHL. Run correlation and send to town. Get ok to perf from 9452'' to 9462' (T4 Sand) with well flowing 1744.3 mcfd at 387 psi. Spot and fired gun gun #3. After 5 min - 1837 mcfd at 387 psi, 10 min - 1839 at 385 psi and 15 min - 1858 mcfd at 386.8 psi. POOH. All shots fired and gun was wet.,Rig down off well and secure well. Will be back in am to finish up. g perf from 9452'' to 9462' p Tag CIBP @ 10,901 with ,Attempt mill CIBP at 10,906.2' 5/19/2020 Sign in. Mobe to location. Rig up lubricator. PT to 250 psi low and 3500 psi high. Well flowing 1.763 million at 371 psi,RIH w/2-7/8"x5' Razor, HC. 6 spf, 60 deg phase and tie into OHL. Run correlation and send to town. Get ok to perf from 9224' to 9229' (T1X Sand) with well flowing 1813 mcfd at 358 psi. Spot and fired gun gun #4. After 5 min - 1862 mcfd at 358 psi, 10 min - 1863mcfd at 358 psi and 15 min - 1920.4 mcfd at 358.5 psi. POOH. All shots fired and gun was wet.,RIH w/2-7/8"x10' Razor, HC. 6 spf, 60 deg phase and tie into OHL. Run correlation and send to town. Get ok to perf from 9083' to 9093' (T1XX Sand) with well flowing 1814 mcfd at 357 psi. Spot and fired gun gun #5. After 5 min - 1832 mcfd at 358 psi, 10 min - 1979 mcfd at 360 psi, 15 min - 2144 mcfd at 360 psi and 20 min - 2310 mcfd at 383 psi. POOH. All shots fired and gun was wet.,Rig down lubricator and equipment. Turn well over to field. o perf from 9083' to g 9093' (T1XX Sand) wit !"# $% &$##&%$ !'( )( *" ( +, ( ( -( -( ! ! ./"("## !$ %&'()* +!, 0( !(-./0 - . ( !$ %&'()* +!, 1/ ( 1 ! / . )( 2 )( !' .3( ) )( !2%*34 , - !2%*- .-.-, 5)6 " 71 77 - -! 0 "( "( 40( 1/0( 546*- 516* ! 2 "( ! )')) )')) 2 6 !!6'&! % 6+!' +)'()-/"4()')) )'() +)8!9)'2% - ( 8 92'%2%1 - 789 " 0/ 7+9 ) 0 789 ! ."1).0 ::"2) ! ;);2)2) ('22 %'+ (( 662'266)6%+) !/(,( "1( 0 ! 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'(! 6&6'6 2 6 &+('! & 62%'(( )'6& 2 6'%+ <"10?B 0"0 7*, ) ))'!( &' 6 &!'6( ! %22'+% C2 ') !&&'6!! (66' % 2 6 &6+'!+ & 626'6) ' 2 2') <"10?B 0"0 7*, ) + ' ( &'26 !)'2! ! %%!'&+ C2 ( '( !&('2%! +) '+ 2 6 &2&'() & 62)'&! )'6% 2 6&'+& <"10?B 0"0 7*, ) 622'&6 %' !)' % ! &&'+) C2 %)')% !& '!2! ++)' ) 2 6 & )') & 6 %'2+ '6& 2 +('( <"10?B 0"0 7*, ) 6&+' %'( !)'%( ! &!&'!! C2 &&'%) !%&'6&! %2)'6! 2 6 %! '66 & 6 '( )'6) 2 &2')% <"10?B 0"0 7*, ) (6&')( %'6+ &!'!% ! !(&')( C2 2)%')) !%(' ! %%!'(( 2 6 %%' ! & 6)!'!) )'! 2 !&'() <"10?B 0"0 7*, ) + )' &'(6 &&'6% ) ) %'2& C2 22+')) !%2')+! &&'%& 2 6 %(6'2( & 6)+'( '&! 2 6 ('+& <"10?B 0"0 7*, ) +%2'2 &'&& &%'( ) )%('! C2 26('++ !+!')! &!%'6 2 6 %6'+ & 6)'6% )'% 2 6'(! <"10?B 0"0 7*, ) %'6% &'+ &+'& ) '!) C2 2+(' ! !++'&6! !(('6) 2 6 % (' ( & 6))'% )'(& 2 6( '6+ <"10?B 0"0 7*, ) %!(' + &'2! &+'+& ) !2'62 C2 2&6'(& !+6'(( ) ) '!2 2 6 +!('&) & !&' 2 )'(2 2 6+!'2( <"10?B 0"0 7*, ) &(%'&! %' & &('&% ) 2(2' % C2 )'(% !+2'6( ) )%'+% 2 6 +%+'&6 & !('% '& 2 6&+'%2 <"10?B 0"0 7*, ) ! %'%6 %' &6'62 ) )!'( C2 2 ' ( !+)'&% ) )'&( 2 6 +(!'2! & !'&% )'%2 2 ()')) <"10?B 0"0 7*, ) !&)'(+ %'2) &6' + ) +!'& C2 !'+6 !(!'6& ) !)'&& 2 6 +6)'& & !2'2) )' % 2 (2)'2) <"10?B 0"0 7*, )6 ') %'+& &6'&& ) 62%'2 C2 (%'%& !(&')( ) 26&'&2 2 6 +22'%) & !)'6& )'&% 2 (%')% <"10?B 0"0 7*, )'!! %'( &('+6 ) 6&%')& C2 %+'+% !(+' ) )&'(& 2 6 +)'&( & &&'6( )'66 2 ((6'(6 <"10?B 0"0 7*, 6'% %'( &('%2 ) ( +'! C2 &('&& !(('! ) %'&! 2 6 (!6'++ & &%'6) )')& 2 (+')( <"10?B 0"0 7*, !+'+ %'6+ &+' 2 ) (%('6 C2 6)6'! !('6% ) !+'! 2 6 (%+' & & &(' ! )'22 2 (&)' <"10?B 0"0 7*, 2(&'! %'( &+'%6 ) +6'& C2 622'!! !( '& ) 6(+' 2 6 ((%'+ & &2'& )'2 2 (!%'2 <"10?B 0"0 7*, 2)'66 %' &+' ) +!'( C2 66 ' !6!' ) ( (') 2 6 (!' & &)'6+ )'6( 2 + 6')( <"10?B 0"0 7*, &2')( %'2& &('!( ) %(2'( C2 6(!'( !6%'! ) (%'&( 2 6 (2 ' 6 & %&'2( )' 2 +)'&6 <"10?B 0"0 7*, 666' %' 6 &+'(% ) & '&2 C2 6%%'&6 !6('& ) +'2 2 6 ()2'&+ & %('!+ )'% 2 +6%'+! <"10?B 0"0 7*, ()('6( %' ) &+'+( ) &%)'2+ C2 6!('%2 !6' ) +! '%+ 2 6 6&(')2 & %'+ )')& 2 ++6' ) <"10?B 0"0 7*, (+&'6% +'!6 &+'&! ) !)'(2 C2 ( 6')6 !6 ' ) %(2')2 2 6 6++'%6 & % ' + )'2& 2 +&)'! <"10?B 0"0 7*, +)'!+ +'!2 &+' ) !!)') C2 (2' 2 !!')6 ) & '&) 2 6 66&'%) & +&'%& )'2+ 2 +!%'() <"10?B 0"0 7*, +!'+( %'62 &+' )()' ! C2 (()'( !%') ) &% '+! 2 6 6)'6 & ++'6! )'&) 2 % 6'66 <"10?B 0"0 7*, %(+') %'( &%' ) )!'!( C2 (+!'2) !6'&% ) ! '6( 2 6 6 '+! & +6')6 )'( 2 % '(! <"10?B 0"0 7*, & +' %' 2 &('6) +%'26 C2 (&+'!+ !2'!2 ) !&&'%6 2 6 !'!+ & + '&2 ')! 2 %6%'!6 <"10?B 0"0 7*, &%+'+ +'+! &6'2 226'+! C2 +)6'+ ! '6+ )6+' ! 2 6 %+'(& & +)')& )'!2 2 %+6')& <"10?B 0"0 7*, !'( )( *" ( +, ( ( -( -( ! ! ./"("## !$ %&'()* +!, 0( !(-./0 - . ( !$ %&'()* +!, 1/ ( 1 ! / . 7 9 ; 789 < 789 546*- 7 9 516* 7 9 +, 7 9 +, 7 9 . 1/0 79 . 40 79 , 79 786$=9 +1) !&'& +'(+ &'+( 2&6' 2 C2 +22')+ !)'26 )('+2 2 6 (&'!) & (&'(! )' 2 %&)'(! <"10?B 0"0 7*, 2 )))'(! +'+( &'&6 6'%6 C2 +!'&) !2!')& +('26 2 6 6 ' & & (%' + )' % 2 %!%' ( <"10?B 0"0 7*, 2 )+'&( +'2& &2'% 6)6'6) C2 +(%'%) !2&')( 22('!) 2 6 2') & (('&( )'%% 2 & '!) <"10?B 0"0 7*, 2 2(' 2 ('%% &'2 6+'2! C2 +%6'(! !2%' & 2&6'%! 2 6 )+'6 & (6'%2 )'&+ 2 &2!'%6 <"10?B 0"0 7*, 2 &%'(( (' ) &2'+& (2'6% C2 +! ' ! !2+'2 66'!% 2 6 2&!'&( & ('+) ' ) 2 &6('2! <"10?B 0"0 7*, 2 26&'&6 6'!! &'2( (&2'++ C2 %)%')& !2('() 6)6' + 2 6 2%'!& & (2'( )') 2 &+)' ! <"10?B 0"0 7*, 2 )'%! 6'( &'6+ +62'(% C2 %22'&2 !26'(% 6+6')% 2 6 2(&'2( & ( '% )'%& 2 &%6'!2 <"10?B 0"0 7*, 2 %')+ 6'2( &'% %)2'&! C2 %&'2+ !2'+ (26'! 2 6 262'&6 & ()' + )'6 2 &&!'6 <"10?B 0"0 7*, 2 66'6+ 6')+ &'%+ %+2'62 C2 %('26 !22'+2 (&'!2 2 6 22%'&% & 6&'!( )' 2 !)' <"10?B 0"0 7*, 2 6!%'! '!& &'&) &2'6& C2 %+&'6( !2 '+2 +66'!& 2 6 2 2'+& & 6%'% )' 2 ! %'(2 <"10?B 0"0 7*, 2 ((!'6% '!+ &' &&'%2 C2 %&'6 !2)'+! %)('22 2 6 !%'%6 & 6+'(6 )' ! 2 ! '() <"10?B 0"0 7*, 2 + !'&2 '! &' 2 !62'2! C2 %!%'! ! !'&% %+'%! 2 6 &'2 & 6('() )' ) 2 !6(' ) <"10?B 0"0 7*, 2 +&2'&( '+ &2'!& 2 ))'( C2 & 2'! ! !')% &2(') 2 6 +&'2+ & 66'6% )'( 2 !(!' 6 <"10?B 0"0 7*, 2 %66'%& '( &2'+ 2 )+'% C2 &2%'6 ! &'! &&('2 2 6 ('%+ & 6'(% )'2% 2 !%2'%% <"10?B 0"0 7*, 2 &)+'2( '6+ & '!2 2 2'6! C2 &6 '%+ ! %'&+ !66'!! 2 6 !'66 & 62'& )'2) 2 !&+'2% <"10?B 0"0 7*, 2 &()')) '6+ & '!2 2 ++') C2 &( '!6 ! %'(2 !&%'( 2 6 2!'2% & 62' )')) 2 !!('&% .D3/3/ @E@ @ Benjamin Hand Digitally signed by Benjamin Hand Date: 2020.02.27 11:37:32 -09'00'Chelsea Wright Digitally signed by Chelsea Wright Date: 2020.03.02 14:18:37 -09'00' TD Shoe Depth: PBTD: Jts. 1 198 1 249 Yes X No Yes X No Fluid Description: Liner hanger Info (Make/Model):Liner top Packer?: Yes X No Liner hanger test pressure:X Yes No Centralizer Placement: Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Tail Slurry Type:Sacks: Yield: Density (ppg) Volume pumped (BBLs) Mixing / Pumping Rate (bpm): Post Flush (Spacer) Type: Density (ppg)Rate (bpm):Volume: Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: Yes X No Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job Cement returns to surface? Yes X No Spacer returns?Yes X No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol @ 0% excess: Total Volume cmt Pumped: Cmt returned to surface: Calculated cement left in wellbore: OH volume Calculated: OH volume actual: Actual % Washout: Float Shoe 6 Rotate Csg Recip Csg Ft. Min.PPG Shoe @ 12841.22 FC @ Top of Liner12,797.00 Floats Held 30 452.8 0 452.8 WBM CASING RECORD County Kenai State Alaska Supv.S Hauck / J Riley Hilcorp Energy Company CASING & CEMENTING REPORT Lease & Well No.BCU-019RD Date Run 1-Mar-20 Component Size Wt.Grade THD Make Length Bottom Top CDC 1.82 12,841.22 12,839.40 Csg Wt. On Hook:190,000 Type Float Collar:Antelope No. Hrs to Run: 10.7 5.4 98 1780FIRST STAGE12 30 298.8/298.8 413.8 Halliburton Cementers 15.3 276.1 Bump press Bond Log Bump Plug? 20:19 3/2/2020 4,026 12,841.2212,850.00 CEMENTING REPORT Csg Wt. On Slips: Water base mud 12.5 176.7 Type of Shoe:Inovex Casing Crew:Weatherford 5.5 5.5'' CDC Jt 5 1/2 17.0 P110 CDC 41.20 12,839.40 12,798.20 Float Collar 6 CDC 1.20 12,798.20 12,797.00 Casing 5 1/2 17.0 P110 CDC HT 2,290.91 12,797.00 4,306.98 Swell Packer 5 1/2 17.0 P110 CDC HT 11.70 4,306.98 4,295.28 Casing 5 1/2 17.0 P110 CDC HT 4,285.23 4,306.98 21.75 5.5'' Pup Jt on Hanger 5 1/2 17.0 P110 DWC 2.05 21.75 19.70 Hanger 9 7/8 DWC 0.70 19.70 19.00 485 2.07 1220 1.24 5.5 CBL ran 3/11/20 Swell Packer Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 4/22/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL BCU -19RD PTD 219-188 CD: NABORS FINAL MUDLOG DATA Please include current contact information if different from above. Abby Bell 04/22/2020 Received by the AOGCC on 04/22/2020 PTD: 2191880 E-Set: 32778 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Taylor Wellman Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Beaver Creek Field, Tyonek Gas Pool, BCU 19RD Permit to Drill Number: 219-188 Sundry Number: 320-107 Dear Mr. Wellman: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc-aloska.gov, Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, J sibs ehmielowski Commissioner DATED this 12 day of March, 2020. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED MAR 6 2020 77-5- 3i/ zltiv AOr vrn 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate Q Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Initial Completion, N2 Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑� Stratigraphic ❑ Service ❑ 219-188 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20579-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 237A & CO 2376 Will planned perforations require a spacing exception? Yes El❑ No ' BCU-19RD ' 9. Property Designation (Lease Number): 10. Field/Pool(s): A028083 • Beaver Creek Unit / Tyonek Gas Pool 11, PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD: Effective Depth ND: MPSP (psi): Plugs (MD): Junk (MD): 12,850' 12,166' TBD TBD 4,936 psi N/A N/A Casing Length Size MD ND Burst Collapse Structural Conductor 106' 20" 106' 106' 3,060psi 1,500psi Surface 2,510' 13-3/8" 2,510' 2,509' 3,450psi 1,950psi Intermediate 7,4471 9-5/8" 7,447' 7,057' 5,750psi 3,090psi Production 12,841' 5-1/2" 12,841' 12,157' 10,640psi 7,460psi Liner Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and ND (ft): Swell Pkr; N/A 4,300' MD/4,300' ND; N/A 12. Attachments: Proposal Summary 4 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: March 19, 2020 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Taylor Wellman 777-8449 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: 1kmamertoi3hi1c0m.com Contact Phone: 777-8420 Authorized Signature: Date: °j as Zoe COMMISSION USE ONLY Conditions of approval: Notify CmirnTission so that a representative may witness Sundry Number://it (h/ r -I O Plug Integrity ❑// BOP Test Mechanical Integrity Test E] Location Clearance El /❑' Other . �" r.P C --L - n'+'V.• O Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes ❑ No Subsequent Form Required: 1 0-4y07 - APPROVED BY Approved by: THE COMMISSION Date: ,3 [/ R f /�� Qf��(`/''� �� )L��.�/'�i� Submit Font and 50 (/�IOV!(7 �A,]C��O_MMMMISSIONER Mr^ v'7 7'9 rir0 Form loaoa vises 4/z 17 a c t i for 12 nths from the date of approval. Qnachments N Duplicate `� 5 3/0/a.0 H MI.,p M.A., U, Repair Wellhead Well: BCU-19RD Date:3/4/2020 Well Name: BCU-19RD API Number: 50-133-20579-01-00 Current Status: Sidetrack Leg: N/A Estimated Start Date: 3/19/2020 Rig: Coil /E -line Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Amt Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 219-188 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (M) AFE Number: ±8,952 ±8,964 ±8,440' Current Surface Pressure: Max. Expected BHP: Max. Anticipated Surface Pressure: Brief Well Summary 0 psi 6,138 psi @ 12,029' TVD 4,936 psi (No Open Perfs) (Based on Geotap Reading) (Based on Geotap Measurement in T66 formation and - 0.1 psi/ft gas gradient to Surface) Beaver Creek Unit #19RD is a side track that was drilled from the BCU -19 wellbore. The purpose of this work/sundry is to complete the BCU #19RD. The well will be blown dry with Nitrogen and then perforated starting with the lowest sand and working upward. Zones will be tested through the production system after each interval is shot. Coil Procedure: 1. MIRU RU Coil Tubing. RU BOP and test 250 psi low and 4,900 psi high (Note: BOP test pressure is lower than MASP due to no open perforations in this well while coil is on the well). 2. RIH With coil and jet nozzle using Nitrogen to blow well dry. Leave 4,100 psi Nitrogen pressure on the well. RDMO Coil. E -line Procedure 3. MIRU E -line. Pressure test lubricator to 250 psi low/ The Pressure indicated in the right hand column of the table below will be the high test pressure. 4. PU perf guns and RIH to depth and perforate the first sand starting at the bottom. ( Note: the anticipated Bottom Hole pressures in the table below are either Estimated (in Red) or Measured With a Geotap sidewall sampling tool (in black)). 41� (Note: A plug must be set between the Tvonek and the Lwr. Beluga before perforating the B -31C) Anticipated BH Lubricatorhigh Zone Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Pressure Test pressure Lwr B -31C ±8,952 ±8,964 ±8,440' ±8,452' 12, 3,376 psi 3,500 psi Beluga Lwr B -31C ±9,017' ±9,037' ±8,502' ±8,522' 20, 3,401 psi 3,500 psi Beluga Tyonek T1XX ±9,083' ±9,097' ±8,565' ±8,579' 14' 3,426 psi 3,500 psi Tyonek T1X ±9,224' ±9,231' ±8,699' ±8,706' 7' 3,480 psi 3,500 psi Tyonek T2 ±9,299 ±9,326' ±8,771' ±8,798' 27' 3,508 psi 3,500 psi Tyonek T4 ±9,451' ±9,462' ±8,916' ±8,927' 11' 3,566 psi 3,500 psi K Flilcory Alaska, LL, Repair Wellhead Well: BCU-19RD Date: 3/4/2020 Tyonek T4 ±9,478' ±9,483 ±8,942 ±8,947' 5' 3,577 psi 3,500 psi Tyonek T5 ±9,575' ±9,598' ±9,034' ±9,057' 23' 3,613 psi 3,500 psi Tyonek T7A ±9,789' ±9,809' ±9,237' ±9,257' 20' 3,695 psi 3,500 psi Tyonek T76 ±9,846' ±9,862' ±9,291' ±9,307' 16' 3,716 psi 3,500 psi Tyonek T8 ±9,979' ±9,996 ±9,416' ±9,433' 17' 3,766 psi 3,500 psi Tyonek T14 ±10,571' ±10,601' ±9,978' ±10,008' 30' 3,991 psi 3,500 psi Tyonek T15 ±10,613' ±10,626' ±10,019' ±10,032' 13' 4,150 psi 3,500 psi Tyonek T17 ±10,729' ±10,768' ±10,129' ±10,168' 39' 4,264 psi 3,500 psi Tyonek T18 ±10,826' ±10,832' ±10,222' ±10,228' 6' 4,450 psi 3,600 psi Tyonek T19 ±10,898' ±10,937' ±10,289' ±10,328' 39' 4,513 psi 3,600 psi Tyonek T19A ±10,953' ±10,983' ±10,341' ±10,371' 30' 4,687 psi 3,800 psi Tyonek T20A ±11,180' ±11,196' ±10,559' ±10,575' 16' 5,093 psi 4,200 psi Tyonek T20A ±11,237' ±11,251' ±10,613' ±10,627' 14' 5,112 psi 4,200 psi Tyonek T21 ±11,669' ±11,740' ±11,024' ±11,095' 71' 5,630 psi 4,600 psi Tyonek T40 ±12,646' ±12,654' ±11,967' ±11,975' 8' 6,050 psi 5,000 psi Tyonek T66 ±12,683 ±12,708 ±12,004' ±12,029' 25' 6,138 psi 5,100 psi a. Proposed perfs also shown on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation (Ben Siks- Geologist. Trudi Hallett- Reservoir Engineer). d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record a tubing Surface pressure before each run and after each gun firing of 5, 10, 15 min readingsintervals. e. The Beluga Sands are governed by Conservation Order 237A. The Tyonek Sands are governed by Conservation Order 237B f. Sand intervals may be grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolatation patch may be set prior to moving up to the next sand interval. S. POOH. RD E -line. 6. Turn well over to production. (Test SSV with -in 5 days of stable production on well -notify AOGCC 24hrs before testing) Attachments: 1. As -built Schematic 2. Proposed Schematic 3. Standard Well Procedure -N2 Operations 4. Procedure Change Form Beaver Creek Unit SCHEMATIC Well: BCU 19RD PTD: 219-188 nilcora Alaska, LLC API: 50-133-20579-01-00 CASING DETAIL Size Type Wt/Grade/Conn ID To312,84V 20" Conductor 133/K-55/Weld 18.730" Su 13-3/8" Surface 68/L-80-1-55/BTC 12.415" Su 9-5/8" Intermediate 40/L-80/BTC 8.835" Su 5-1/2" Production 17 / P-110 / CDC-DWC 4.892" Su JEWELRY DETAIL No Depth Item 1 4,295' 9-5/B" Swell Packer 13-3/8' ll.15 TI) =12,850' (MD) / 12,166 (TVD) PBTD=TBU (MD)/TBU (ND) Updated by DMA 03-05-20 K HileorP Almlca, 1J C RIB: MSL =38' 20' 13-3/8' M I lr-4on 1 1® Bw 19 PROPOSED SCHEMATIC CASING DETAIL Beaver Creek Unit Well: BCU 19RD PTD: 219-188 API: 50-133-20579-01-00 Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 133/K-55/Weld 18.730" Surf 106' 13-3/8" Surface 68/L-80-J-55/BTC 12.415" Surf 2,510' 9-5/8" Intermediate 40/L-80/BTC 8.835" Surf 7,447' 1 5-1/2" Production I 17/P-110/CDC-DWC 4.892" Surf 12,841' JEWELRY DETAIL No Depth Item 1 4,295' 9-5/8" Swell Packer 2 9,070' CIBP w/20'Cmt-TOC9,050' PERFORATION DETAIL Sand Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt Date Comments B -31C 18,952 ±8,964' ±8,440' ±8,452' 12' Proposed TBD B -31C ±9,017' ±9,037' ±8,502' ±8,522' 20' Proposed TBD 71XX ±9,083' ±9,097' ±8,565' ±8,579' 14' Proposed TBD T1X ±9,224' ±9,231' ±8,699' ±8,706' 7' Proposed TBD T2 ±9,299' ±9,326' ±8,771' ±8,798' 27' Proposed TBD T4 ±9,451' ±9,462' ±8,916' 18,927' 11' Proposed TBD T4 ±9,478' ±9,483' ±8,942' ±8,947' 5' Proposed TBD T5 ±9,575' ±9,598' ±9,034' ±9,057' 23' Proposed TBD T7A ±9,789' ±9,809' ±9,237' ±9,257' 20' Proposed TBD T713 ±9,846' ±9,862' ±9,291' ±9,307' 16' Proposed TBD TS ±9,979' ±9,996' ±9,416' ±9,433' 17' Proposed TBD T14 ±10,571' ±10,601' ±9,978' ±10,008' 30' Proposed TBD T35 ±10,613' ±10,626' ±10,019' ±10,032' 13' Proposed TBD T17 ±10,729' ±10,768' ±10,129' ±10,168' 39' Proposed TBD T18 ±10,826' ±10,832' ±10,222' ±10,228' 6' Proposed TBD T19 ±10,898' ±10,937' ±10,289' ±10,328' 39' Proposed TBD T19A ±10,953' ±10,983' ±10,341' ±10,371' 30' Proposed TBD T20A ±11,180' ±11,196' ±10,559' ±10575' 16' Proposed TBD T20A ±11,237' ±11,251' ±10,613' ±10,627' 14' Proposed TBD T21 ±11,669' ±11,740' ±11,024' ±11,095' 71' Proposed TBD T40 ±12,646' ±12,654' ±11,967' ±11,975' 8' Proposed TBD T66 ±12,683' ±12,708' ±12,004' ±12,029' 25' Proposed TBD 51/2' A TD =12,850' (MD) / 12,166 (TVD) PBTD = TBd (MD) / TBD' (ND) Updated by DMA 03-05-20 B -31C 2 TIX � T2 T4 T5 T5 T7A T7B T8 T14 T15 T17 T18 T19 T19A T20A 721 T40 T66 51/2' A TD =12,850' (MD) / 12,166 (TVD) PBTD = TBd (MD) / TBD' (ND) Updated by DMA 03-05-20 STANDARD WELL PROCEDURE I Illeorp Alaska. LIT NITROGEN OPERATIONS 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 02 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. 12/08/2015 FINALvl Page 1 of 1 F\ ME ii i a ERB c N Y V ' R LL U � c CD 0y O L L ¢ as ¢ d = G c a dN CLCo Y L L CL - M Cl .i L `Z d Q/ Z d m c m r U m a m U O a` Y R Q d m a U 1 cc O CL a 2 Y 79Q d R c N N 0 O CL O E d 0 N v CL d a Y Q 12 W ALASKA OIL AND GAS CONSERVATION COMMISSION RIG INSPECTION REPORT P.I. supv 6r- Zi1 i 4� , Lo INSPECT DATE 2/5/2020 11 AOGCC INSPECTOR Guy Cook Comm: Rig Hilcorp 169 Coil Tubing Unit? No Rig Contractor All American Rig Representative Brandon Davis Operator Hilcorp Alaska Contractor Representative Shane Hauck Well BCU-19RD Permit to Drill # 219-188 Sundry Approval # Operation IlDrilling Inspection Location Beaver Creek Unit Pad 3 BOP STACK MUD SYSTEM CLOSING UNIT Working Pressure, W/H Flange P Pit Fluid Measurement P Working Pressure P Working Pressure, BOP Stack P Flow Rate Sensor P Operating Pressure P Annular Preventer P Mud Gas Separator P Fluid Level/Condition P Pipe Rams P Degasser P Pressure Gauges P Blind Rams P Separator Bypass P Sufficient Valves P Locking Devices, Rams P Gas Detectors P Regulator Bypass P Stack Anchored P Alarms Separate/Distinct P Actuators (4 -way valves) P Choke Line P Choke/Kill Line Connections P Blind Ram Handle Cover P Kill Line P Reserve Pits P Control Panel, Driller P Targeted Turns P Trip Tank P Control Panel, Remote P HCR Valve(s) P Firewall P Manual Valves P RIG FLOOR 2 or More Pumps P Flange/Hub Connections P Kelly or TD Valves P Independent Power Supply P Drilling Spool Outlets P Floor Safety Valves P N2 Backup P Flow Nipple P Driller's Console P Condition of Equipment P Control Lines P Flow Monitor P Flow Rate Indicator P CHOKE MANIFOLD MISCELLANEOUS 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 P Bypass Line P FAILURES: 0 CORRECT BY: New choke manifold added just off the rig floor. Accumulator unit has been moved closer to the rig floor in a different connex. Both COMMENTS nice improvements to the rig. New choke manifold bypass line added as well that looked to be in good order. Rig is in good shape and ready to work. 2020-0205_Rig_Hilcorp169_BCU-19RD_gc.docx rev. 5-8-18 Bo York THE STATE IU"MA GOVERNOR MIKE DUNLEAVY Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Beave Creek Field, Tyonek Gas Pool, BCU 19RD Hilcorp Alaska, LLC Permit to Drill Number: 219-188 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Surface Location: 1657' FWL, 1196' FNL, SEC. 34, T7N, R10W, SM, AK Bottomhole Location: 1227' FNL, 2558' FWL, SEC. 34, T7N, RIOW, SM, AK Dear Mr. York: Enclosed is the approved application for the permit to redrill the above referenced development well. Per Statute AS 3 1.05.03 0(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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, Jssie L. Chmielowski Commissioner DATED this I S day of December, 2019. STATE OF ALASKA ALH,3KA OIL AND GAS CONSERVATION COMMIb ,SON DEC 10 2019 PERMIT TO DRILL 20 AAC 25.005 A n f --% i1 f'% 1 a. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c.peri ife Ii pr osed for: Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj ❑ Single Zone El - Coalbed Gas ❑ Gas Hydrates ❑ Redrill 211 Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑� " Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑✓ • Single Well F] 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. 0220282'44 I>2 7iZ" 7 BCU-19RD 3. Address: 6. Proposed Depth: /x . Z - 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 r MD: 12,657' TVD: 11,959' Beaver Creek Unit ' Tyonek Gas Pool ` 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 1,657' FWL, 1,196' FNL, Sec 34, T7N, R10W, SM, AK A028083 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1,980' FNL, 1524' FWL, Sec 34, T7N, R10W, SM, AK N/A 1/15/2020 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 1,227' FNL, 2,558' FWL, Sec 34, T7N, R10W, SM, AK 2560 3,755'to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 178.5 • 15. Distance to Nearest Well Open Surface: x-317469 ' y- 2433994 ' Zone -4 GL / BF Elevation above MSL (ft): 160.5 - to Same Pool: 960' to BCU 24 16. Deviated wells: Kickoff depth: 4,500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 32 degrees Downhole: 5301 Surface: 4189 ' 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 8-1/2" 5-1/2" 17# Pilo CDC, CDC HT, DWC 8,307' 4,350' 4,255' 12,657' • 11,959' L - 992 ft3 / T - 1500 ft3 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 9,068' 8,678' 5,500' 9,016' 8,626' 6,454' (3.5" tbg) Casing Length Size Cement Volume MD TVD Conductor/Structural 106' 20" 106' 106' Surface 2,510' 13-3/8" 869 sx 2,510' 2,509' Intermediate 7,447' 9-5/8" 505 sx 7,447' 7,057' Production Liner Perforation Depth MD (ft): 5,515' - 5,525', 6,424' - 6,431', 6,435' - Perforation Depth TVD (ft): 5,249' - 5,258', 6,054' - 6,061', 6,065' - 6,071' 6,442' 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 ❑✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: David Gorm Authorized Name: Monty Myers Contact Email: d Orm hIIcor .COm Authorized Title: Drilling Manager Contact Phone: 777-8333 Authorized Signature —' Date: Commission Use Only Permit to Drill ZlAPI Number: r l Permit 150- � _tl,cam Approval �, See cover letter for other Number: l% ! �3' !y >-� Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methatie gas hydrates, or gas contained in shales: � Other: �( L, Too p s � � �� P � f — Samples req'd: Yes ❑ Nc [��/// Mud log req'd: Yes ❑ No E %I 1 HZS measures: Yes ❑ No Directional svy req'd: Yes [No ❑ / DO S n �` wLc� Y lc 5 2 ` Spacing Inclination -only sv req'd: Yes No exception req'd: Yes ❑ No Y Y q' ❑ cPost initial injection MIT req'd: Yes ❑ No[-] APPROVED BY Date: 1.2 I Approved by: L% COMMISSIONER THE COMMISSION Submit Form and Form ii Revised 5/2017 This permit is h r ¢ �o?t s�°� a ate of approval per 20 AAC 25.005(8) A achments in Duplicate va l2(l L. (l�1 IO RI V i V ��z�/—b i2 t2.�1 Hilcorp Alaska, LLC BCU 19RD Drilling Program Beaver Creek Unit Rev 0 December, 2019 ff HilmEnergy Company Contents BCU 19RD Drilling Procedure 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications .....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................11 10.0 BOP N/U and Test.........................................................................................................................12 11.0 Whipstock Running Procedure....................................................................................................13 12.0 Whipstock Setting Procedure.......................................................................................................15 13.0 Drill 8-1/2" Hole Section..............................................................................................................16 14.0 Run 5-1/2" Production Casing.....................................................................................................18 15.0 Cement 5-1/2" Production Casing...............................................................................................23 16.0 RDMO............................................................................................................................................25 17.0 Completions....................................................................................................................................25 18.0 BOP Schematic...............................................................................................................................26 19.0 Wellhead Schematic......................................................................................................................27 20.0 Days Vs Depth................................................................................................................................28 21.0 Geo-Prog.........................................................................................................................................29 22.0 Anticipated Drilling Hazards.......................................................................................................30 23.0 Hilcorp Rig 169 Layout.................................................................................................................31 24.0 FIT Procedure................................................................................................................................32 25.0 Choke Manifold Schematic...........................................................................................................33 26.0 Casing Design Information...........................................................................................................34 27.0 8-1/2" Hole Section MASP............................................................................................................35 28.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................36 29.0 Surface Plat (NAD 27)...................................................................................................................37 30.0 Directional Plan (wp2)..................................................................................................................38 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 1 0 Well Summar V' V y fig- _ / 6 1 Well BCU 19RD Pad & Old Well Designation Sidetrack of existing well BCU 19 (PTD#208-123) Planned Completion Type 5-1/2" Production CSG Target Reservoir(s) T onek Sands Planned Well TD, MD / TVD 12,657 MD / 11,970' TVD PBTD, MD / TVD 12,577' MD / 11,893' TVD Surface Location (Governmental) 1,657' FWL, 1,196' FNL, Sec 34, T7N, R10W, SM, AK Surface Location (NAD 27) X=317469.107, Y=2433994.889 Surface Location (NAD 83) X=1457490.275, Y=2433755.779 Top of Productive Horizon (Governmental) 1,980' FNL, 1524' FWL, Sec 34, T7N, R10W, SM, AK TPH Location (NAD 27) X=317326.99, Y=2433212 TPH Location (NAD 83) X=1457348.149, Y=2432972.891 BHL (Governmental) 1,227' FNL, 2,558' FWL, Sec 34, T7N, R10W, SM, AK BHL (NAD 27) X=318330.80, Y=2431123.75 BHL (NAD 83) X=1458351.94, Y=2430884.581 AFE Number AFE Drilling Das 30 Days AFE Completion Days AFE Drilling Amount AFE Completion Amount Maximum Anticipated Pressure (Surface) 4,189 psi Maximum Anticipated Pressure (Downhole/Reservoir) 5,301 psi Work String 4-1/2" 16.64 S-135 CDS-40 RKB — GL 178.5'(160.5 + 18) Ground Elevation 160.5 BOP Equipment 11" 5M T3 -Energy Annular BOP 11" 5M T3 -Energy Double Ram 11" 5M T3 -Energy Single Ram Page 2 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Ene`gy Company 2.0 Management of Change Information If Hilcorp Alaska? LLC t3iic rp Changes to Approved Permit to Drill Date: Subject: Changes to Approved Permit to Drill for BCU 19RD File #: BCU 19RD Drilling and Completion Program Any modifications to BCU 19RD Drilling R Completion Program will be documented and approved below. Changes to an approved APD will be aommunicated.to the BLM and AOGCC. f G2✓�✓'> r`�" ��-�_�� C2�- ��L� SCC � �✓ Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Version 0 November, 2019 Hilcorp Energy Company 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Section (in) OD in 8-1/2" 5-1/2" 4.892" 4.653" 5.929" BCU 19RD Drilling Procedure Rev 0 Wt Grade T—Conn -Burst Collapse Tension (#/ft) (psi) (psi) (k -lbs) 17 P-110 1 Dwc/CDC/CDC 10,640 7,460 546 4.0 Drill Pipe Information: bole OD (in) H) (in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section ' in in (#/ft) si. (psi)(k-lbs) All t 4-1/2" 3.826 2.6875" 5.25" 1 16.6 1 S-135 CDS40 1 17,693 1 16,769 1 468k All casing will be new Page 4 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates • Submit a short operations update each work day to dgorm@hilcorp.com, mmyers(d%ilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 5.4 EHS Incident Reporting • Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! a. John Coston: O: (907) 777-6726 C: (907) 227-3189 b. Matt Hogge: O: (907) 777-8418 C: (907) 227-9829 2. Spills: Keegan Fleming: 0:907-777-8477 C:907-350-9439 Notify Drlg Manager 1. Monty M Myers: O: 907-777-8431 C: 907-538-1168 Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to ddgonn@hilcorp.com, and cdin er e,hilcorp.com 5.6 Casing and Cmt report • Send casing and cement report for each string of casing to dgormghilcorp.com, and cdin eg_rghilcorp.com Page 5 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hi1COIp Energy Company 6.0 Planned Wellbore Schematic Page 6 Version 0 November, 2019 ,.I.LC PROPOSED SCHEMATIC Beaver Creek Unit Well: BCU 19RD PTD: TBD CASING DETAIL MB MSL 3F Size Type Wt/ Grade/ Conn ID Top Sam w 20" Conductor 133 / K -SS /Weld 18.730" Surf 106' 13-3/8" Surface 68 fL-80—}-55 /8TC 12.4f5" Surf 2,510'. 9-S/8" Intermediate 40 / L-80 / STC 8.835` Suri 7,A47' • 29 5-1/2` Production 17 / P-110 /CDC-CriVC 4.892" Surf 12.657' k a x� x; ` JEWELRY DETAIL P5 No Depth Item 1 4,300' 9-5/8" Swell Packer 4 t Yl �"•. f f 3�"�� sC OPEN HOLE/ CEMENT DETAIL a r d41 BBL's I2,d81 aft) of cement in 85'Hoge. Est. TOC 4,300' (30%excess ) A 110.119 kr" TI)_A1557( 11-M MV) PBiD=12,W (MD) / 11,893 " Page 6 Version 0 November, 2019 7.0 Drilling / Completion Summary BCU 19RD Drilling Procedure Rev 0 BCU 19RD is a gas producer planned to be re -drilled in a South-westerly direction from the existing BCU 19 utilizing the existing casing program down to 4,500' MD / 4,386' TVD. At 4,500' MD the parent wellbore will be sidetracked and a new wellbore drilled penetrating Beluga and Tyonek sands. A 8,145' X 8-1/2" production hole section is planned with a 5-1/2" production string run to surface, cemented and perforated based on data obtained while drilling the interval. Drilling operations are expected to commence approximately January 15"', 2020. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal. A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack and for perforating the production intervals. c ' . rd �°`� S1 General sequence of operations: 1. MOB Hilcorp Rig 9 169 to well site 2. ND Tree N/U Test BOP 3. CIBP set during de -completion of BCU 19. 4. PU 8.5" window milling assembly and DP and cleanout to CIBP 5. POOH standing back, PU whipstock, and mills and TIH to CIBP 6. Orient whipstock and set. 7. Drill 8-1/2" hole to 12,657' MD. Run and cmt 5-1/2" production casing. 8. POOH laying down drill pipe. 9. N/D BOP, RDMO. Reservoir Evaluation Plan: J 1. Production Hole: GR + Res + Den/Neu (LWD). 2. Mud loggers from window point to TD. C-6 L - Page 7 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC/BLM regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling of BCU 19RD. Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. • The initial test of BOP equipment will be to 250/45x0 psi & subsequent tests of the BOP equipment will be to 250/4500 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. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" Ensure AOGCC and BLM approved drilling permit is posted on the rig floor and in Co Man office. Cgula�tionVariance Requests: Onshore Oil and Gas Order No. 2, Section III. A. 2. a. iv. o Hilcorp requests approval to install a 2-1/16" 5M HCR valve on kill line in lieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. U° Page 8 Version 0 November, 2019 Hilcorp Energy Company Summary of BOP Equipment and Test Requirements BCU 19RD Drilling Procedure Rev 0 Hole Section Equipment Test Pressure(psi) • 11" x 5M Townsend Annular BOP • 11" x 5M Townsend Double Ram Initial Test: 250/4500 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 8-1/2" • 11" x 5M Townsend Single Ram • 3-1/8" 5M Choke Line Subsequent Tests: • 2-1/16" x 5M Kill line 250/4500 • 3-1/8" x 2-1/16" 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event (BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Required BLM Notifications: • 48 hours before spud. Follow up with actual spud date and time. • 48 hours before casing running and curt operations • 48 hours before BOPE tests • 48 hours before logging, coring, & testing • Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Page 9 Version 0 November, 2019 Regulatory Contact Information: BCU 19RD Drilling Procedure Rev 0 AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / Email: melvin.rixsekalaska.gov Victoria Loepp / Petroleum Engineer / (0): 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/TestWitnessNotifhtml Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) BLM Amanda Eagle / BLM Petroleum Engineer / (0): 907-271-3266 (C): 907-538-2300 Email: aeagle(2blm.gov Mutasim Elganzoory / BLM Petroleum Engineer / (0): 907-271-4224 Email: mel ag nzooa@blm.g_ov_ Use the below email address for BOP notifications to the BLM: BLM �AK�AKSO EnergySection Notifications@blm.gov Page 10 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 9.0 R/U and Preparatory Work 9.1 A separate sundry will be submitted that will include the following: • P&A lower perfs with a plug • Pull tubing 9.2 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.3 Mix water based mud for 8-1/2" hole section. 9.4 Check wellhead for pressure 9.5 Remove attachment spool and original tubing head 9.6 Set test Plug in wellhead prior to N/U BOP to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.7 Rig up BOPE 9.8 Verify 5" liners installed in mud pumps. • HHF-1000 Pumps are rated at 3457 psi (80%) with 5" liners and can deliver 306 gpm at 120 spm. This will allow us to drill the 8-1/2" hole section with (1) mud pump. Page 11 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcoip Energy Company 10.0 BOP N/U and Test 10.1 N/U 11"x 5M T3 -Energy BOP as follows: • BOP configuration from Top down: 11" x 5M T3 -Energy annular BOP/11" x 5M T3 -Energy Model 6011i double ram /11" x 5M mud cross/11" x 5M T3 -Energy Model 6011i single ram • Double ram should be dressed with 2-7/8 x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8 x 5" VBRs. • N/U bell nipple, install flowline. • Install (1) manual valves & (1) HCR valve on kill side of mud cross. • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 10.2 Run 4-1/2" BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/4500 psi for 5/10 min. Test annular to 250/2500 psi for 511.0 min. • Ensure to leave "A" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 10.3 R/D BOP test assy. 10.4 Mix 9.5 ppg 6% KCL PHPA mud system. 10.5 R/U mud loggers for production hole section. 10.6 Set wear bushing in wellhead. Page 12 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcoip Energy Company It. Whipstock Running Procedure 11.1 M/U window milling assembly and TIH to CIBP. • Use an 8-3/4" taper mill and a 8-3/4" string mill above to ensure whipstock assy will pass freely. • Ensure BHA components have been inspected previously. • Caliper and drift all BHA components before running them in the hole. • Drift DP prior to RIH. • Lightly wash and ream any tight spots noted. 11.2 TIH to CIBP (4,500' MD). Note actual depth tagged may vary slightly. Keep up with the # of joints picked up so we know where we are. 11.3 Pressure test casing to 2800 psi / 30 min. Chart record casing test & keep track of the amount of fluid pumped. Stage up to 2800 psi in 500 psi increments. 11.4 CBU & circ at least (1) hi -vis sweep to remove any debris created by the clean out run. Anything left in the wellbore could affect the setting of the whipstock. 11.5 TOH. 11.6 Make up mills on a joint of HWDP. 11.7 RIH & set in slips. 11.8 Make up float sub, install float. 11.9 Make up UBHO sub. 11.10 Orient UBHO to starter mill. 11.11 Leave assembly hanging in the elevators, and stand back on floor. 11.12 Bring whipstock to rig floor on the pipe skate. Do not slam into bottom of whipstock with pipe skate. 11.13 Pickup whipstock per rep using the whipstock handling system using air hoist. Allow assy to hang while Rep inspects and removes shear screws as needed and any safety screws. Note: Attach mills to Whipstock with (I) 35k mill shear bolt. 11.14 If needed, open BOP Blinds. 11.15 Run the whipstock in the hole, install safety clamp as per Rep, and install hole cover wrap. Page 13 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 11.16 Release pickup system at this point, makeup mills. 11.17 With the top drive, pick the assembly and position the starting mill to align with the hole in the slide. The Rep will instruct the driller when the slot is lined up, the shear bolt then can be made up by the Rep. 11.18 The assembly can now be picked up to ensure that the shear bolt is tight. 11.19 Remove the handling system. 11.20 Slowly run in the hole as per Rep. Run extremely slow through the BOP & wear bushing. 11.21 Run in hole at 1 '/z to 2 minutes per stand. 11.22 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 11.23 Call for Rep. 15 — 10 stands before getting to bottom. 11.24 Orient at least 30' — 45' above the CIBP. Page 14 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp En.rgy Company 12.0 Whipstock Setting Procedure 12.1 With the bottom of the Whipstock 30 - 45' above the CIBP, measure and record P/U and S/O weights. Orient the whipstock per the directional driller. 12.2 Orient Whipstock to desired direction by turning DP in 1/4 round increments. P/U and S/O on DP to work all torque out. 12.3 Once Whipstock is in desired orientation, slack off and tag CIBP to set Bottom Trip Anchor. 12.4 Set down 12-15K on anchor to trip, P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the Whipstock shear bolt. (35k shear value). 12.5 P/U 5-10' above top of Whipstock. 12.6 Displace to 9.5 ppg 6% KCL PHPA water based mud. 12.7 Record P/U, S/O weights, and free rotation. Slack off to top of whipstock and with light weight and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings. 12.8 Install catch trays in shaker underflow chute to help catch iron. 12.9 Keep iron in separate bbls. Record weight of iron recovered on ditch magnets. 12.10 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 12.11 Circulate Bottoms Up until MW in = MW out. 12.12 Conduct FIT to 13.5 ppg EMW. • (13.5 - 9.5) * 0.052 * 4,402' tvd = 915 psi Kick Tolerance • (13.5 - 11) * (4386/11970) = 0.92 Note: Offset field test data predicts frac gradients at the window to be between 14 ppg and 15 ppg. A 13.5 ppg FIT results in a 0.92 ppg kick tolerance while drilling the interval with a 11.0 ppg fluid density. - 12.13 Slug pipe and POOH. Gauge Mills for wear. Page 15 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 13.0 Drill 8-1/2" Hole Section 13.1 P/U 8-1/2" drilling assy. 13.2 Ensure BHA components have been inspected previously. 13.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 13.4 Bit TFA should be —.8 in2. We need to pump at —275- 350 gpm to clean the hole effectively. Have the directional driller run hydraulics calculations to confirm optimum TFA. 13.5 8-1/2" hole section mud program summary: Primary weighting material to be used for the hole section will be Calcium Carbonate to minimize solids. We will have barite on location to weight up the active system 1ppg above ✓ highest anticipated MW in the event of a well control situation. 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 logger's office. System Type: 9.5 — 11.0 ppg 6% KCl/EZ MUD/BDF-976 fresh water based drilling fluid. Properties: 13.6 Product Mud Water Plastic KCl 22 ppb (29 K chlorides) Caustic NID BARAZAN D+ Viscosity BDF-976 Point pH HPHT DEXTRID LT Weight PAC -L ViscosityYield BARACARB 5/25/50 15 - 20 ppb (5 ppb of each) BAROTROL/Soltex 4,500'- 9.5-11.0. 40-53 15-25 15-25 8.5-9.5 < 11.0 12,657' 0.5 ppb (maintain per dilution rate 13.6 Product Concentration Water 0.905 bbl KCl 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) BDF-976 2 - 4 ppb EZ MUD DP 0.75 ppb DEXTRID LT 1-2 ppb PAC -L 1 ppb BARACARB 5/25/50 15 - 20 ppb (5 ppb of each) BAROTROL/Soltex 2 — 4 ppb as needed BAROID 41 as required for a 9.0 — 9.5 ppg ALDACIDE G 0.1 ppb BARACOR 700 1 ppb BARASCAV D 0.5 ppb (maintain per dilution rate TIH, Conduct shallow hole test of MWD and confirm LWD functioning properly. Page 16 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 13.7 TIH through window, ensure MWD service rep on rig floor during this operation. Do not rotate string while bit is across face of Whipstock. 13.8 Triple combo LWD will be run in 8-1/2" hole section: • Gamma Ray (DGR: Combined Gamma Ray) • Resistivity (EWR: Shallow/Med/Deep) • Density (DEN: Bulk Density) • Neutron (NEU: Thermal neutron porosity) • Density Image, dip picks, and additional engineer for same. 13.9 Drill 8-1/2" hole section to 12,657' MD / 11,970' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 275 - 350 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. If tight hole is encountered, screw in and begin backreaming connections until hole conditions improve. Shales in the Beluga formations are notorious for swelling and causing tight hole. Most of the time, backreaming them on a short trip is the only solution. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. • Take MWD surveys every other stand drilled. Surveys can be taken more frequently if deemed necessary. 13.10 Hilcorp Geologists will follow LWD log closely to determine exact TD. 13.11 At TD pump sweeps, CBU, and pull a wiper trip back to the 9-5/8" window. 13.12 POOH LDDP and BHA Page 17 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Fu -u Company 14.0 Run 5-1/2" Production Casing 14.1 Install 5-1/2" CSG rams, and pressure test 250/4500 psi. 14.2 R/U 5-1/2" casing running equipment. • Ensure 5-1/2" CDC x CDS 40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure all casing has been drifted prior to running. • Be sure to count the total # of joints before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 14.3 P/U shoe joint, visually verify no debris inside joint. 14.4 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • Solid body centralizers will be pre-installed on shoe joint an FC joint. • Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe and float collar. • Utilize a collar clamp until weight is sufficient to keep slips set properly 14.5 Continue running 5-1/2" production casing • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every joint to 9000' MD. Leave the centralizers free floating. Install solid body centralizers on every other joint from 9000' MD to the window. Leave the centralizers free floating. Pick up the swell packer and place in the string at approximately 4,300' MD. 14.6 Continue running 5-1/2" production casing 5-1/2" BTC M/U torques Connection Casing OD Minimum Maximum Yield Torque CDC 5-1/2" 8,500 ft -lbs 10,500 ft -lbs 13,000 ft -lbs CDC HTQ 5-1/2" 10,000 ft -lbs 14,000 ft -lbs 17,400 ft -lbs DWC 5-1/2" 13,100 ft -lbs 15,100 ft -lbs 17,100 ft -lbs 4/ Page 18 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company USS U. S. Steel Tubular Products 5.5 17/0.304 P110 HC USS-CDC"m 711=4103 52 PM JI MECHANICAL PROPERTIES Pipe USS•CDC'w Minimum Yield Strength 110,000 psi Maximum Yield Strength 140,000 psi Minimum Tensile Strength 125,000 psi DIMENSIONS Pipe USS -CDC' Outside Diameter 5.500 6.050 in. Wall Thickness 0.304 — in. Inside Diameter 4.892 4.892 in. Standard Drift 4.767 4.767 in. Alternate Drift in. Coupling Length 9.250 in. Nominal Linear Weight, T&C 17.00 lbs/ft Plain End Weight 16.89 lbs/ft SECTION AREA Pipe USS.CDC= Critical Area — 4.962 sq. in. Joint Efficiency — 100.0 % PERFORMANCE Pipe USS,== Minimum Collapse Pressure 8,730 8,730 psi External Pressure — 6,984 psi Minimum Internal Yield Pressure 10,640 10,600 psi Minimum Pipe Body Yield Strength 545 1000 lbs Joint Strength 568,000 1000 lbs Compression Rating 340,800 lbs Reference Length 71,275 ft Maximum Uniaxial Send Rating 57.2 deg/100 It Make -Up Loss 4.63 in. Minimum Make -Up Torque 8,500 ft -lbs Maximum Make -Up Torque 10,500 ft -lbs Connection Yield Torque 13,000 ft -lbs Verification of connection shoulder required. Two/cal shoulder range Page 19 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company USS U. S. Steel Tubular Products 5.500" 17.00lbsift (0.304" Wall) 6-M'20171238:53PM P110 HC USS -CDC HTQ� I MECHANICAL PROPERTIES Pipe USS -CDC HTO Minimum Yield Strength 110,000 — psi Maximum Yield Strength 140,000 — psi Minimum Tensile Strength 125.000 — psi DIMENSIONS Pipe USS -CDC HTO Outside Diameter 5.500 6.300 in. "gall Thickness 0.304 — in. Inside Diameter 4.892 4.89E in. Standard Drift 4.767 4.767 in. Alternate Drift — — in. Coupling Length — 9250 in. Nominal Linear Weight, T&C 17.00 Ibs,`ft Plain End Weight 16.89 tbslft SECTION AREA Pipe USS -CDC HTQO Critical Area 4.962 4-962 sq. in_ Joint Efficiency — 100.0 q,8 PERFORMANCE Ripe USS -CDC HTQO Minimum Collapse Pressure 8.730 8.730 psi External Pressure Leak Resistance — 6,980 psi Minimum Internal Yield Pressure 10.640 10.640 psi Minimum Pipe Body Yield Strength 546,000 — IIx; Joint Strength — 568,000 lbs Compression Rating — 341,000 lbs Reference Length — 22,275 ft Maximum Uniaxial Bend Rating 57.3 degM00 It A-" P30 YSS.CDC HTQ� Make -Up Loss — 4.63 in. Minimum Make -Up Torque — 10,000 ft -lbs Maximum Make -Up Torque — 14.000 ft -lbs Connection Yield Torque — 17,400 ft -lbs Verification of connection shoulder required. Typical 5,000 - 7,500 ft -lbs shoulder range Page 20 Version 0 November, 2019 Hilcorp Energy Company Technical Specifications Connection Type: Siie(O.D.): DVVC/C Casing 5-112 in STANDARD Material VST Pt 10 EC Grade BCU 19RD Drilling Procedure Rev 0 Weight (Wall): Grade: 17.00 Ib1tt (0.304 in) VST P110 EC 125,000 Minimum Yield Strength (psi.) 135,000 Minimum Ultimate Strength (psi.) IP" Mlllllllllll1rL12A Page 21 Version 0 November, 2019 Pipe Dimensions VAM USA 5.500 Norninal Pipe Body A.D. (kn.) 2107 QtyViast Boulevard Suke 1300 4.892 Nominal Pipe B I.D. in. p ) Houston, Tx 77042 Phone: 713479-320Q 0.304 Nominal Wall Thickness (in.) Fax: 713-479-3234 17.00 Nominal Weight (lbsJft.) E -mat: VAMP—§ARes,V?v�rr,: s corn 16.89 Plain End Weight (lbsJR ) Connection Drift Diameter (in.) 4.13 4.962 Nominal Pipe Body Area (sq. in.) Critical Area (sq. in.) 100.0 Page 21 Version 0 November, 2019 Pipe Body Performance Properties 620,000 Minimum Pipe Body Yield Strength (lbs.) 8,840 Minimum Collapse Pressure (psi.) 12,090 Minimum Internal Yield Pressure (psi.) 11,100 Hydrostatic Test Pressure (psi.) Connection Dimensions 6.050 Connection O.D. (in.) 4.892 Connection I.D. (in.) 4.767 Connection Drift Diameter (in.) 4.13 Make-up Loss {in.) 4.962 Critical Area (sq. in.) 100.0 Joint Efficiency (°%) Connection Pedorrnance Properties 620,000 Joint Strength {lbs.) 26,050 Reference String Length (ft)1.4 Design Factor 620,000 API Joint Strength (lbs,) 620,000 Compression Rating (lbs.) 8.840 API Coilapse Pressure Rating (psi.) 12,090 API Internal Pressure Resistance (psi.) 104.2 Maximum Uniaxial Bend Rating [degrees/100 g1 Approximated Motel End Torque Values 13,100 Minimum Final Torque (ft. -lbs<) 15,100 Maximum Final Torque ft -lbs.) 17,100 Connection Yield Torque (ft,-Ibs.) Page 21 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 14.6 Run in hole w/ 5-1/2" casing to the window. 14.7 Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 14.8 Obtain slack off weight, PU weight, rotating weight and torque of the casing. 14.9 Circulate 2X bottoms up at the window, ease casing thru the window. 14.10 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. 14.11 Set casing slowly in and out of slips. 14.12 PU swell packer to be placed at approximately 4,300'. Swell packer should have 10' handling pups installed on both ends with bow spring centralizers on pups. 14.13 Swedge up and wash last 2 joints to bottom. P/U 5' off bottom. Note slack -off and pick-up weights. 14.14 Stage pump rates up slowly to circulating rate. Circ and condition mud with casing on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 14.15 Reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 22 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 15.0 Cement 5-1/2" Production Casing 15.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • Pump 20 bbls of freshwater through all of Cementers equipment, taking returns to cuttings bin, prior to pumping any fluid downhole • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the cmt operation. • Document efficiency of all possible displacement pumps prior to cement job. 15.2 Attempt to reciprocate the casing during cmt operations until hole gets sticky 15.3 Pump 5 bbls of 12 ppg Mud Push spacer. 15.4 Test surface cmt lines to 4500 psi. 15.5 Pump remaining 25 bbls 12 ppg Mud Push spacer. 15.6 Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 30% OH excess. PRODUCTION CEMENT CALCULATIONS CSG BTM (ft) 12,657 CSG Size 51/2 Section: Calculation: Vol (BBLS) Vol ft3 LEAD: 9-5/8" CSG x 5.5" CSG Casing Annulus: (4500' -4300') x 0.046 b f = 9.29 / 52.2 LEAD: 8.5" OH x 5.5" CSG Casing Annulus: (7657'-4500') x 0.041 b f x 1.3 = 167.46 / 940.2 Total LEAD: 176.74 992.4 TAIL: 8-1/2" OH x 5-1/2" Casing annulus: (12657'- 7657) x 0.041 x 1.3 = 265.20 1489.0 TAIL: 5.5" CSG Shoe Track: 80'x 0.023 b f = 1.86 10.4 80 x 0.15 b f = Total TAIL: 267.06 1499.5 Total Cement: 443.81 2491.8 Page 23 Version 0 November, 2019 qo3 5,Y, BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company Slurry Information: 15.7 Drop wiper plug and displace with 6% KCl 15.8 If hole conditions allow — continue reciprocating casing throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 15.9 If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 15.10 Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3 minutes. 15.11 Do not over -displace by more than'/2 shoe track. Shoe track volume is 1.8 bbls. 15.12 Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 15.13 RD cementers and flush equipment. 4'�-vJ -315co_ 15.14 WOC minimum of 12 hours, tut casing to 4,50 psi and chart for 30 minutes. 15.15 PU 2-7/8" work string/scraper and bit. Clean out to PBTD. NL l J.A W .D. C S�Uv Page 24 Version 0 November, 2019 s�- Lead Slurry (7,657' MD to 4,300' MD) Tail Slurry (12,657' to 7,657' MD) System Extended Extended Density 12.5 Ib/gal 15.4 Ib/gal Yield 2.46 ft3/sk v1 1.22 ft3/sk Mixed Water 14.349 gal/sk 5.507 gal/sk Mixed Fluid 14.469 gal/sk 5.507 gal/sk 15.7 Drop wiper plug and displace with 6% KCl 15.8 If hole conditions allow — continue reciprocating casing throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 15.9 If elevated displacement pressures are encountered, position casing at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 15.10 Bump the plug and pressure up to 500 psi over final lift pressure. Hold pressure for 3 minutes. 15.11 Do not over -displace by more than'/2 shoe track. Shoe track volume is 1.8 bbls. 15.12 Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 15.13 RD cementers and flush equipment. 4'�-vJ -315co_ 15.14 WOC minimum of 12 hours, tut casing to 4,50 psi and chart for 30 minutes. 15.15 PU 2-7/8" work string/scraper and bit. Clean out to PBTD. NL l J.A W .D. C S�Uv Page 24 Version 0 November, 2019 s�- Hilcorp EneW Company BCU 19RD Drilling Procedure Rev 0 Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold • Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure • Note if pre flush or cement returns at surface & volume • Note time cement in place • Note calculated top of cement • 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 d orm e hilcorp. com, cdin eg_rghilcorp. com. This will be included with the EOW documentation that goes to the AOGCC. 16.0 RDMO 16.1 Install BPV in wellhead 16.2 N/D BOPE 16.3 N/U production tree 16.4 RDMO Hilcorp Rig # 169 17.0 Completions 17.1 A separate Sundry will be submitted to the AOGCC and BLM that will cover the completion operations for BCU 19RD. �1 a�I SIIL" C,, -5,y . 6- s S'yS J 41t�L i g .�D 7- S76 p� 5 Page 25 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 18.0 BOP Schematic Page 26 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilco p Energy Company 19.0 Wellhead Schematic 8eav_r Creel r -m g lurb s, CW, 11 x 5 % 11C N19RD t VXX bax axon x 6-125- U1 133/9 x95/9 x5t/e sLb—bo. tap, w/75/8 ad neck } type 114pV profie, LD -!X nn lend M RA, Ota., 5 1/8 961 FC x9..5 Ota quirk urnan top 'Tz Valve, Swab, CiW -Fis 5 I185MFL41VrO. It tfim iia lr e, wing. C:f1q+C' 3 1/9 SPA FE, itwo, Cc VM V.hw, tis mann, aw-Fts, 5 US 5M Ft. I-NVO, Et vim Valve, Mawr. Ci WFLS. 5 1135161FE'tMO, EE trim Tu by S head, Cactus C 29t - U PS, 1-3 UJI SM x 11 SM, wj 2-21/16SMSSO Starting stead, Veteo hts-196, U 5/8 hl X 13 3j% VG-1cs - bottam, w/2- — LPO DTi Page 27 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 20.0 Days Vs Depth Page 28 Version 0 November, 2019 Days Vs Depth 0 - BCU 23 % BCU 24 BCU 25 2000 BCU 19RD Planned 4000 w 6000 Q a� 0 a� 8000 10000 12000 14000 0 5 10 15 20 25 30 35 Days Page 28 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 21.0 Geo-Prog BCU 19RD Proposed - - f . KB Beaver Creek Unit x = 317,469.11 r = 2,433.994.P � ' - i37.5 BEAVER CREEK. TY01r' x 318,330.50 ti = 2.43] 12'K HAK 169 Alaska 12,047' hID 11.96V TAT • 21.5 onshore • ' ItiAD_'? Zonc4 .. . +[6 Kenai Peninsula BoWh tFT) Drirl and complete a sidetrack out of existing parent BCU 19 targeting gas in the Upper Tyonek sands. Deeper targets have never been drilled on the top of structure and will be evaluated. Drill and complete a sidetrack out of existing parent BCU 19 targeting gas in the Upper Tyonek sands. Deeper targets have never been drilled on the top of structure and will be evaluated. Page 29 Version 0 November, 2019 CTED 1 D-- TVD T""3' at. TOP NAIVE LtTNOLf4GY - Nf1'R7i!!NG_,[ EF,STlNG Gradient t} LM tFT) sselrr tuhno434 Sand"Coa[ GssMatcr 5341.1' 4,9$2.3 4960.83 243_,215.06 317365.58 2232.37 2.45 'Op Beluga San Coal GavWatcr 6094.90 5,6.74.5 -5652.48 2433012..22 31760112 2543.84 0.45 fiddle Bclup Sand -Coal Gavk4atcr 6703.64 6,225.1 -0203.62 2432850.97 317789.2_1 2791.63 0.45 aiver Mop Sand Coal Gas:} lff 7572.0; 7,290.9 -7269.35 432538.57 315152.49 3271.21 0.45 .K TYO..'EK T1 Sand'Coal Gas'Water 9204.47 8,524.1 -5502.6 2432167.58 318462.70 3826.17 045 R TYGNEK T[ 1 Sand,'Coal GavAl'atcr o2" py 8,540.9 -8519.36 243216? 17 318402.42 3833.71 0.45 K TYONEK TI 2 Sand'Coal Gax°Water 42ja.911 8,576.9 -8555.39 243215018: 318401.14 3849.93 0.45 K TYi?N EK -TI 3 SaM Coal GaxMto u:2j.02' 8,641.6 4620.14 2432129.75 3184iss.0t, 3879.06 0.45 K TYONTEK T1 4 Sa tCoal Gas,''l44cr 93 23 8,674.3 -8652.82 2432119.28 31445,7.4 3893.77 0.45 K TYON'EK T[ 5 San t'Coal Gas`kvata 04 3.33 8,779.9 -8758.39 2433085.36 31IS45?.35 3941.28 i 0.45 9l ST Sarut''Caal GaV'Water 962123 8,920.6 8594.12 2.132044,15 318447.94 4044.60 0.45 9l SB Sanst`Coal GwWaer 9654.65 8,952.4 4934:91 24320_'9.94 318446.72 4018.91 0.45 K TYGNNEK T * San Coal Gas 3k ater 4557.52 9,145.4 -9123.93 2431967 93 3184_+9.31 4105.77 0.45 C T19ST Sand Coal Gas,''watcr 10561.52 10.100.7 -10079.17 2431661.05 318102.62 4535.63 0.45 C T19SB Sand Coal GasMa err 11010,07 10,242.9 -10221.36 2431615.37 318397.16 4599.61 0.45 C TPUST Sand"Coal Ga&VR' a Ilttt'.o, 10,297.0 -10275.53 2431597.97 3[8;93.O55 4623.99 0.45 C T20SB Sanet'Coal Gu Vater It 103.37 10,387.9 -10366.35 2.13150.4.79 318391.54 4664.86 0.45 K TYGNEK T4 4 Sm Coal Gasp°\Vater [2383.31 11,548.6 -115_77.05 2431195.9 318347.02 5187.17 0.45 D Sand-toal GavWater 12647; 11,802.5 -11781 431195.9 318347.0 5301.45 0.45 Page 29 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 22.0 Anticipated Drilling Hazards 8-1/2" 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. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control running coals. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: ✓ 1-12S is not present in this hole section. i No abnormal pressure/temperatures are present in this hole section. Page 30 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 23.0 Hilcorp Rig 169 Layout Page 31 Version 0 November, 2019 24.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: BCU 19RD Drilling Procedure Rev 0 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 32 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 25.0 Choke Manifold Schematic Page 33 Version 0 November, 2019 Hilcorp Energy Company BCU 19RD Drilling Procedure Rev 0 26.0 Casing Design Information Calculation & Casing Design Factors Hole Size 8-112" Drilling Mode MASP: 4189 Well: BCU 19RD Field: Beaver Creek DESIGN BY: David Goan Design Criteria: Mud Density: 11 ppg Production Mode MASP: 4189 psi (See attached NIASP determination & calculation) Collapse Calculation: Section Calculation 1,2 Normal gradient external stress (0.45 psifft) and the casing evacuated for the internal stress Calculationl, Cash Top Tap Bottor Bottan Lei Weigl Gr Conn Weight vffo Bou, Tension at Top Min strength If Worst Case Safel Collapse Pressu Collapse Resistarai Worst Case Safet lAAiSl Minimum Worst case safi 3pecificatlon °g OD (h�_� Casing Section 3 3 5112 _ 0 4 _ i 1( ! 9 58 0 I (MD)4, i M)D) _ I 4, 9th_ _ . 4, it (PPS - )de I - action B ancy f=actor (Ibs) 1 , d'Sec6ion(lbs) 1 , 12,657 11,97(1 _..,..._._. 12,657 17 _ P-110 _ BTC 215,171 215,171 rasion (1000 lbs) 1 546 y Factor (Tension) e at bottom (ks 1, ;e wro tension (Psi) 3, 0 2.5111 5,386 7,460 r Fadhir ( - lapse) ! 1.38 ✓ .......... ? 4 (psi) , 89 4,189 Yield (psi) 5 10.640 - - ty factor (Burst) 1. 7 Z.S4 i Page 34 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 27.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 8 tt2 Hole Section Hilcur BCU 19RD Beaver Creek MD TVD Planned Tap: 4508 4386 P:lannEd TD: 12657 119T'+ Anticipated Formations and Pressures: Forms ion TVD Est Pressure 0irlar 4Vet PPG Grad Sterling B4 4982.33 22323735 _ GasiWater 8.6 0.45 Top Beluga 5674.48 2543.841 Gas,Water 8.6 0.45 Middle Beluga 6225.12 2781.624 Gas,'Water 8.6 0.45 Loner BelLga 72K85 3271-'075 Gas,'Water 8.6 0.45 TK TYCNEl4 Ti 8524.1 3826.17 GastWata 8.6 0.45 TK TYONEK TI -11 8540.86 3833.712 Gas,'Watw 8.6 0.45 K TY0NEK T9 8576.89 3849-9255 GaiMaler U5 0.45 K TYDNEK T1 31 8641.64 3879.063 GasPWakw 8.6 0.45 K T fCNEK T1 8674.32 3893.769 GasWater 8.6 0.45 K TYDNEK T1 8779.69 3941.2755 Gas1waler 8.6 0.45 T 91 ST 8920,62 4004.604 Gas,'Water 8.6 0.45 T 91 SB 8952.41 4018.9'+95 Gas,'Water 8.6 0.45 TK TYONEK T3 914:5.43 4105.7685 Gas,Water 8.6 0.45 BC TMT 10100.67 4535-6265 Gas,'Water 8.6 0.45 BC T19SB 10242.86 4599.612 GasrWater 8-6 0.45 BC T20ST 10297.03 46'13.9885 Gas,'Water 8-6 0.45 BC T20SB 10397.85 4664.8575 Gas,Water 8.6 0.45 K rfONELL4A 1154B.55 5187.1725 Gas,'Water 1 8.6 1 0.45 TD 11 K2.5 53(71 AS Gas,'Water Offset Well Mud Densities Well bMr range Tep 'T1.0 Bodam Date B, --U 23 9.0-110.7 ppg 0 1 1D'8522014 BC:U 24 9.0 -103 ppg 0 1D,696 2014 BCU 25 9-0-1).9 0 5.264 2014 Assumptions: 1. MaDdmum planned mud density for the 84a- hole section is 11.0 ppg_ 2. Calmdations assume reserve airs contain 1DD%. gas (worst case). 3. Calsdations assume wast case went is caa ;Rete evacuation of wellbore to gas. 4. Antic ed fracture gradient at 45N TND = 14.2 pqg EMW Fracture Pressure at 4-5/9" shoe considering a full column of Sas from shoe to surface: 4,386 eft;+ x 0.74 (psWft)= 3246 psi 3,246 (rsi) - [0.1{Ipsi�f x4.386 (ft)j= 2807 psi Pit" from pore pressure; entire wellbore evacu Sas fr07:11 m TD 11,1370 (11' x 4.45 fpsbYt 538E 7 - [0.1 �F )'11.970 (ft))= 4189 r/ Summary: 1. Ia+thSP daring Dr9ing0productim,� mode is gc erned t y SISHP minus enter wellbore evacuated to gas ",Toad TD. Page 35 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hilcorp Energy Company 28.0 Spider Plot (NAD 27) (Governmental Sections) BCU 04 Urd Fad 4 Pad S007N010W : N\ Ap280$ak BCU 19 BH4 1 BCU 09 BEAVER CREEK UNIT � 1` BCU 14 BH LAPW 14A IHl! BCU 11 SHLP Plan BCU 19RD SHL 1 ♦ 1. Plan BCU 19RDTPH BCU 13 WHO NA' \\ 8CU125 BHLi. BCU 04RD 81-ibllaCU 15 BHL BCU 01 BHk• L 1 1 BCU 04RD P81 BHI BCU 05BHbr BCU 23 BCU 24 BCU I BHL Plan BE 19RD BHL Legend Plan BCU 19RD SHL • Other Surface Well Locations X Plan BCU 19RD TPH • Other Bottom Hole Locations Plan BCU 19RD_BHL — Well Paths Oil and Gas Unit Boundary M ` �tx,a vad z P— ad 500 1,000 1,500 Beaver Creek Unit BCU-19RD Feet Kaska State Plane Zone 4, NAD27 A 101—rp Al-ka, LI,f: WPM Map Date= 1 114120 1 9 Page 36 Version 0 November, 2019 Hilcorp Energy Cmnpmy 29.0 BCU 19RD Drilling Procedure Rev 0 Surface Plat (NAD 27) ✓ N?a3621Sansa SECTION LINE NOT TO SCALE E 335Etis.SdW g SECTION 14 T7N R10W SM, AMC N C1R TI -'I W y ..nwKa. _-= rro saaw.rr. i9 O H h O Z' cru �•J 1 cu w c r�rr •i .urr f�l.� na 8.C.0 NO, 19 C DIK WELL CECAAR ONLY W -AVM VWEK UN&r PAa a A••4-BV'L'r �••'�••` � N3#99Afl-0.880 E:317469.107 �Lw+ wo • LAr: S6*" 271 N 1e5rFWL ut c.nr�'- '�:�=:� LONG_ 151b1V2.72T`W NAD27ASPZ"A 4 1 NAVON MST FWL f w.lrcvnr. f j 1396 FM e�sn /�� l r... '.. � {.t,..z •. mei `_ s �%— ® . v�— BASIS OF GEODETIC CONTROL WERE DETERMINED FROM A DIRECT TIE TO U.S_CAG.S. STATION AUDRY 14AMNO A HAD27 PUBLISHED VALUE OF LATITUDE: 8 0°30'50.55OW LO#OGITU DE: 151' 18'37.445"YY. ALASKA STATE PLANE COORDINATES IASP) ZONE 4 "AD 2' 1-2,382,045.42 E=269,$6$.75 - BASIS OF VERTICAL CONTROL IS "OS SM DB7 LOCATED IN THE KEP" SPUR HIGHWAY RMGHT OF WAX DOWNTOWN KENAI HAVING AN ELEVATION OF $4,11 FEET "AVD 86 ACCORDING TO NGS PUBLISHED DATA :""'°.!�# a *,-'49 _, Tti /Ft.#.A+ �'1..a_ s "'.M. SCOTT McLANE. jop 492B-5 w Vi ,tio•,.�: SCALE I�`FsgstNM� ti �� 0 100 zoo 1 \t�►�� MAMMON -8GU � � FOR INFORMATIONAL PURPOSES ONLY 19 WELL ON BCU PAD 3 AS -BUILT SURFACE LOCATION DIAGRAM INA027 CAM, Iia cm. lsr us" �lz �--j" �.pKGr MG. 91?K2 lM7Kl6ASI21NAMg1NJ4VE�'.tY.:I,LE'1i16 il. �4l04W SgA4RM_.K �GPPP h'rK LFdri LCVtIpi $34 T7N R10W SEWARD MERIDIAN, ALASKA 4rFii 1 Page 37 Version 0 November, 2019 BCU 19RD Drilling Procedure Rev 0 Hi1COIp Energy Company 30.0 Directional Plan (wp02) Page 38 Version 0 November, 2019 Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Pad 3 Beaver CK Unit 19 BCU 19RD Plan: BCU 19RD Wp02 Standard Proposal Report 05 December, 2019 HALLIBURTON Sperry Drilling Services ~ALL BVRTON�_C.lculation Sperry [3rilling LLC Inc i REFERENCE INFORMATION Method: Minimum CurvatureHllcorpAlaska, i Error System: ISCWSA Scan Method: Closest Approach 3D Error Surface: Pedal Curve Warning Method: Error Ratio Coordinate (N/E) Reference: Well Beaver CK Unit 19, True North Vertical (TVD) Reference: BCU 19RD @ 178.50usft (HAK 169) Measured Depth Reference: BCU 19RD @ 178.50usft (HAK 169) Calculation Method: Minimum Curvature SECTION DETAILS Sec MD Inc Azi TVD +N/ -S +E/ -W Dleg TFace VSect Target Annotation 1 4500.00 31.29 203.77 4382.30 -449.09 -162.05 0.00 0.00 379.10 7877.34 KOP: 12.50/100': 4500' MD, 4382.37VD : 30° LT TF 2 4513.00 32.70 202.27 4393.33 -455.43 -164.74 12.50 -30.00 384.33 1 End Dir : 4513' MD, 4393.33' TVD 3 4533.00 32.70 202.27 4410.16 465.43 -168.84 0.00 0.00 392.63 8652.82 Start Dir 40/100': 4533' MD, 4410.16'TVD 4 5384.74 24.46 128.46 5178.96 -797.89 -116.41 4.00 -134.78 725.38 _T1_5 T 91 ST End Dir : 5384.74' MD, 5178.96' TVD 5 8555.71 24.46 128.46 8065.34 -1614.59 911.62 0.00 0.00 1814.61 10257.67 Start Dir 30/100': 8555.71' MD, 8065.34'TVD 6 9190.38 18.00 180.00 8661.50 -1796.06 1015.46 3.00 132.13 2018.97 Tyonek T1 BC T20ST 7 9251.42 17.93 185.93 8719.56 -1814.83 1014.49 3.00 94.97 2036.58 End Dir : 9251.42' MD, 8719.56' TVD 8 12656.76 17.93 185.93 11959.50 -2857.63 906.09 0.00 0.00 2997.84 BCU-19RD TO Total Depth: 12656.76' MD, 11959.5' TVD WELL DETAILS: Beaver CK Unit 19 Ground Level: 160.50 +N/ -S +E/ -W Northing Easting Latittude Longitude 0.00 0.00 2433994.89 317469.11 60° 39'30.271 N 151' 1'2.727 W 2250 13 3/8" 500 3000 3000 Sterling 134 6000 Top Beluga NMiddle Beluga 3 6750 0 0 7500 CL (1) C1 _U r 8250 0) 9000 9750 1 11250 3500 Q0p0 KOP: 12.51/100 : 4500' MD, 4382.3 TVD : 30° LT TF �SqO End Dir : 4513' MD, 4393.33' TVD ��®®® Start Dir 4°/100' :4533' MD, 4410.16'TVD Project: Beaver Creek Unit Site: Beaver Creek Unit Pad 3 Well: Beaver CK Unit 19 Wellbore: BCU 19RD Design: BCU 19RD Wp02 IC p End Dir : 5384.74' MD, 5178.96' TVD @�''," 1000 9 5/8" x 12 1/4" Lower Beluga 8A TVDPath TVDssPath MDPath Formation Date: 2019-12-05T00:00:00 5139.33 4960.83 5341.31 Sterling B4 Depth To 5831.48 5652.98 6101.60 Top Beluga BCU 19 (BCU 19) 6382.12 6203.62 6706.53 Middle Beluga 3 MWD_Interp Azi+Sag 7447.85 7269.35 7877.34 Lower Beluga 7447.00 8681.10 8502.60 9210.99 TK TYONEK T1 8697.86 8519.36 9228.61 TK TYONEK T1 1 8733.89 8555.39 9266.48 TK TYONEK 8798.64 8620.14 9334.53 _T1_2 TK TYONEK T1_3 8831.32 8652.82 9368.88 TK TYONEK T1_4 8936.89 8758.39 9479.84 TK TYONEK 9077.62 8899.12 9627.75 _T1_5 T 91 ST 9109.41 8930.91 9661.17 T 91 SB 9302.43 9123.93 9864.04 TK -IYONEK_T3 10257.67 10079.17 10868.05 BC T19ST 10399.86 10221.36 11017.50 BC T19SB 10454.03 10275.53 11074.43 BC T20ST 10544.85 10366.35 11169.89 BC T20SB 11705.55 11527.05 12389.85 TK TYONEK_T4_4 00 Start Dir 31/100' : 8555.71' MD, 8065.34'TVD 8500 BEN - - - -- - -- TK TYONEK T1 0 TK_TYONEK_T1_1 BCU 19 g00 TK TYONEK_T1_2-_ -TK TYONEK T1 a- -- - - �- 0 End Dir : 9251.42' MD, 8719.56' TVD TK TYONEI, Tt 4 SURVEY PROGRAM i Date: 2019-12-05T00:00:00 Validated: Yes Version: Tyonek T1 1p000 Depth From Depth To Survey/Plan Tool 210.50 4500.00 BCU 19 (BCU 19) 3 MWD -AX 4500.00 4900.00 BCU 19RD Wp02 (BCU 19RD) 3 MWD_Interp Azi+Sag 4900.00 7447.00 BCU 19RD Wp02 (BCU 19RD) 3 MWD+IFRI+MS+Sag 7447.00 12656.76 BCU 19RD Wp02 (BCU 19RD) 3_MWD+IFRI+MS+Sag CASING DETAILS TVD TVDSS MD Size Name 7056.14 6877.64 7447.00 9-5/8 9 5/8" x 12 1/4" 11959.50 11781.00 12656.76 5-1/2 51/2"x81/2" 00 Start Dir 31/100' : 8555.71' MD, 8065.34'TVD 8500 BEN - - - -- - -- TK TYONEK T1 0 TK_TYONEK_T1_1 BCU 19 g00 TK TYONEK_T1_2-_ -TK TYONEK T1 a- -- - - �- 0 End Dir : 9251.42' MD, 8719.56' TVD TK TYONEI, Tt 4 �TK_TYONEK 77_5 i ,T 9,_sB Tyonek T1 1p000 TK TYONEK_T3 1p500 8C T19ST BC T196Et _ 11p00 BC T20ST- - - - - - - - BC T20S8 11y00 12p00 Total Depth- : 12656.76' MD, 11959.5' TVD 12000 TYONEK_T4_4 BCU-19RD TD - - 26- - - - - - - 5 1/2" x 8 1/2" BCU 19RD Wp02 12750- -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 Vertical Section at 162.41 ° (1500 usft/in) 6perry OrNllee® 13 318" -250 - 4000 KOP: 12.5°/100' : 4500' MD, 4382.3TVD: 30° LT TF _ __ _____ -500 End Dir : 4513' MD, 4393.33' TVD 4750 q 0Start Dv4°/10(1: 4533'3dD,441LI6TVD -750 5� ho ti }'per-4-wa3-----End Da :5384.74hID, 5178.96'TVD 0 hn -1000 SZSO btih SSOO l b � h -1250 S7S0 bn Start Dv 3'/100': 8555 71' MD, 8065 34'TVD w bn,p 6000 nti� 8 0 nh 9 5/8" x 12 1/4" o o -1500 nnh + C BCU 19 0 0 -1750 85p0 8750- ----� End Dil : 9251.42'MD,8719.56TVD O v� 9D00 Lound Level: 160.50 +N/ -S +F/.W Northing Fasting Latittude Longitude 0.00 000 2433994.89 317469.11 60° 39'30.271 N 151° L2.727 W -2250 -2000 -1750 -1500 -1250 -1000 -750 -500 -250 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 West( -)/Hast(+) (500 usf /in) -50 Project: Beaver Creek Unit 95oo Site: Beaver Creek Unit Pad 3 Well: Beaver CK Unit 19 97so Wellbore: BCU 19RD l0000 Plan: BCU 19RD Wp02 025o REFERENCE INFORMATION 0500 1175o Co-ordinate (NIE) R.—..e: Well Beaver CK Una 19, True Nonh 0750 Vertical (TVO) Reference: BCU 19RD @ 178+a — (HAK 169) Measured Depth Relevance: BCU 19RD @ 178.50.ft (HAK 169) poo Calculation Method: Minimum Curvature 250 5 1/2" x 8 12"0o CASING DETAILS TVD TVDSSMDSize Name60 -ToW Depth: 1265676'MD, 11959.5'TVD 7056.14 6877.64 7447.00 9-5/8 95/8"x121/4" BCU-19AD 11959.50 11781.00 12656.76 5-1/2 5112"x81/2" BCU 19RD WP02 WELL Hl 19 DETAILS B. ' CK Um Lound Level: 160.50 +N/ -S +F/.W Northing Fasting Latittude Longitude 0.00 000 2433994.89 317469.11 60° 39'30.271 N 151° L2.727 W -2250 -2000 -1750 -1500 -1250 -1000 -750 -500 -250 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 West( -)/Hast(+) (500 usf /in) HALLIBURTON Database: NORTH US + CANADA Companv: Hilcorp Alaska, LLC Proiect: Beaver Creek Unit Site: Beaver Creek Unit Pad 3 Well: Beaver CK Unit 19 Wellbore: BCU 19RD Desiqn: BCU 19RD Wp02 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Beaver CK Unit 19 TVD Reference: BCU 19RD @ 178.50usft (HAK 169) MD Reference: BCU 19RD @ 178.50usft (HAK 169) North Reference: True Survey Calculation Method: Minimum Curvature Proiect Beaver Creek Unit Map System: US State Plane 1927 (Exact solution) - System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Usinq Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Beaver Creek Unit Pad 3 317,314.56 usft Longitude: Site Position: 13-3/16" Grid Convergence: Northing: From: Map Eastinq: Position Uncertainty: 5.00 usft Slot Radius: J Phase: Well Beaver CK Unit 19 Vertical Section: Well Position +N/ -S 0.00 usft Northinq: (TVD) +E/ -W 0.00 usft Eastinq: Position Uncertainty 0.50 usft Wellhead Elevation Wellbore BCU 19RD (°/100usft Magnetics Model Name Sample Date 0.00 BGGM2019 1/15/2020 2,433,965.77 usft Latitude: 60° 39'29.960 N 317,314.56 usft Longitude: 151' 1'5.819 W 13-3/16" Grid Convergence: -0.89 ° 2,433,994.89 usft Latitude: 600 39'30.271 N 317,469.11 usft Longitude: 151° V2.727 W 0.00 usft Ground Level: 160.50 usft J Phase: 162.41 Declination Desiqn BCU 19RD Wp02 +E/ -W Audit Notes: (usft) (°) Version: 0.00 Phase: 162.41 PLAN Vertical Section: Dogleg Depth From (TVD) +N/ -S +E/ -W Rate Rate (usft) Tool Face (usft) (°/100usft (°/100ustt (°) 18.00 0.00 0.00 Plan Sections 0.00 -164.74 12.50 10.90 -11.57 Measured -168.84 0.00 Vertical TVD 0.00 Depth Inclinatio Azimut Depth System +N/ -S (usft) n In (usft) usft (usft) 4,500.00 31.29 203.77 4,382.30 4,203.80 -449.09 4,513.00 32.70 202.27 4,393.33 4,214.83 -455.43 4,533.00 32.70 202.27 4,410.16 4,231.66 -465.43 5,384.74 24.46 128.46 5,178.96 5,000.46 -797.89 8,555.71 24.46 128.46 8,065.34 7,886.84 -1,614.59 9,190.38 18.00 180.00 8,661.50 8,483.00 -1,796.06 9,251.42 17.93 185.93 8,719.56 8,541.06 -1,814.83 12,656.76 17.93 185.93 11,959.50 11,781.00 -2,857.63 15.23 Dip Angle Field Strength (°) (nT) 73.63 55,445.31740516 Tie On Depth: 4,500.00 +E/ -W Direction (usft) (°) 0.00 162.41 Dogleg Build Turn +E/ -W Rate Rate Rate Tool Face (usft) (°/100usft) (°/100usft (°/100ustt (°) -162.05 0.00 0.00 0.00 0.00 -164.74 12.50 10.90 -11.57 -30.00 -168.84 0.00 0.00 0.00 0.00 -116.41 4.00 -0.97 -8.67 -134.78 911.62 0.00 0.00 0.00 0.00 1,015.46 3.00 -1.02 8.12 132.13 1,014.49 3.00 -0.11 9.72 94.97 906.09 0.00 0.00 0.00 0.00 12/5/2019 3:50:37PM Pape 2 COMPASS 5000.15 Build 91E Database: Company: Project: Site: Well: Wellbore: Design: Planned Survey Measured Depth (usft) 18.00 210.50 330.50 450.50 570.50 690.50 813.50 940.50 1,066.50 1,192.50 1,318.50 1,444.50 1,570.50 1,697.50 1,824.50 1,951.50 2,077.50 2,203.50 2,330.50 2,453.50 2,506.50 13 318" 2,563.50 2,626.50 2,689.50 2,752.50 2,816.50 2,879.50 2,941.50 3,005.50 3,068.50 3,131.50 3,193.50 3,257.50 3,319.50 3,382.50 3,446.50 3,508.50 3,572.50 3,635.50 3,697.50 3,760.50 3,824.50 3,888.50 3,950.50 NORTH US + CANADA Local Co-ordinate Reference: Hilcorp Alaska, LLC TVD Reference: Beaver Creek Unit MD Reference: Beaver Creek Unit Pad 3 North Reference: Beaver CK Unit 19 Survev Calculation Method: BCU 19RD Azimuth BCU 19RD Wp02 TVDss Halliburton Standard Proposal Report Well Beaver CK Unit 19 BCU 19RD @ 178.50usft (HAK 169) BCU 19RD @ 178.50usft (HAK 169) True Minimum Curvature 1.94 60.23 Vertical 2,384.19 26.58 56.17 Map Map 0.39 -8.36 Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert (°) (1) (usft) usft (usft) (usft) (usft) (usft) -160.50 Section 0.00 0.00 18.00 -160.50 0.00 0.00 2,433,994.89 317,469.11 0.00 0.00 0.98 53.06 210.49 31.99 0.99 1.32 2,433,995.86 317,470.44 0.51 -0.55 0.98 58.69 330.47 151.97 2.14 3.01 2,433,996.98 317,472.15 0.08 -1.13 1.07 58.08 450.45 271.95 3.27 4.84 2,433,998.08 317,474.00 0.08 -1.65 1.22 60.35 570.43 391.93 4.49 6.90 2,433,999.27 317,476.08 0.13 -2.19 1.58 62.17 690.39 511.89 5.89 9.47 2,434,000.64 317,478.67 0.30 -2.75 1.30 64.17 813.35 634.85 7.29 12.23 2,434,001.99 317,481.45 0.23 -3.26 1.23 69.95 940.32 761.82 8.39 14.81 2,434,003.05 317,484.04 0.11 -3.52 1.42 68.34 1,066.29 887.79 9.43 17.53 2,434,004.04 317,486.78 0.15 -3.69 1.51 67.70 1,192.25 1,013.75 10.63 20.52 2,434,005.20 317,489.78 0.07 -3.94 1.66 71.53 1,318.20 1,139.70 11.84 23.78 2,434,006.36 317,493.07 0.15 -4.10 1.61 69.52 1,444.15 1,265.65 13.04 27.17 2,434,007.51 317,496.48 0.06 -4.22 1.63 68.07 1,570.10 1,391.60 14.33 30.49 2,434,008.74 317,499.82 0.04 -4.44 1.79 69.27 1,697.04 1,518.54 15.71 34.02 2,434,010.06 317,503.37 0.13 -4.69 1.66 67.24 1,823.99 1,645.49 17.12 37.57 2,434,011.42 317,506.94 0.11 -4.96 1.66 69.76 1,950.93 1,772.43 18.47 41.00 2,434,012.72 317,510.38 0.06 -5.21 1.48 63.75 2,076.88 1,898.38 19.82 44.17 2,434,014.02 317,513.57 0.19 -5.54 1.61 57.78 2,202.84 2,024.34 21.48 47.13 2,434,015.64 317,516.56 0.16 -6.23 1.68 65.27 2,329.79 2,151.29 23.21 50.33 2,434,017.32 317,519.78 0.18 -6.92 1.52 56.80 2,452.74 2,274.24 24.86 53.33 2,434,018.92 317,522.81 0.23 -7.58 1.72 58.66 2,505.72 2,327.22 25.66 54.60 2,434,019.70 317,524.09 0.39 -7.96 1.94 60.23 2,562.69 2,384.19 26.58 56.17 2,434,020.60 317,525.67 0.39 -8.36 1.58 76.70 2,625.66 2,447.16 27.31 57.94 2,434,021.30 317,527.46 0.98 -8.52 1.11 132.65 2,688.64 2,510.14 27.10 59.23 2,434,021.07 317,528.75 2.11 -7.93 1.15 157.01 2,751.63 2,573.13 26.10 59.93 2,434,020.06 317,529.43 0.76 -6.77 1.08 161.80 2,815.62 2,637.12 24.94 60.37 2,434,018.89 317,529.85 0.18 -5.53 1.87 179.03 2,878.60 2,700.10 23.35 60.57 2,434,017.29 317,530.03 1.42 -3.95 2.90 180.20 2,940.54 2,762.04 20.77 60.58 2,434,014.71 317,530.00 1.66 -1.49 3.71 190.16 3,004.44 2,825.94 17.11 60.21 2,434,011.06 317,529.57 1.55 1.89 4.64 189.90 3,067.27 2,888.77 12.59 59.41 2,434,006.56 317,528.70 1.48 5.95 5.16 188.55 3,130.04 2,951.54 7.28 58.55 2,434,001.26 317,527.76 0.85 10.76 6.19 193.58 3,191.74 3,013.24 1.27 57.35 2,433,995.28 317,526.47 1.84 16.12 7.71 196.97 3,255.26 3,076.76 -6.19 55.29 2,433,987.85 317,524.29 2.46 22.61 9.13 202.47 3,316.59 3,138.09 -14.71 52.20 2,433,979.37 317,521.06 2.63 29.80 10.78 205.12 3,378.64 3,200.14 -24.66 47.78 2,433,969.49 317,516.50 2.72 37.95 12.63 207.28 3,441.31 3,262.81 -36.30 42.04 2,433,957.94 317,510.57 2.97 47.31 14.98 208.09 3,501.52 3,323.02 -49.40 35.15 2,433;944.96 317,503.49 3.80 57.71 17.25 209.52 3,563.00 3,384.50 -64.95 26.58 2,433,929.53 317,494.68 3.60 69.95 19.20 209.30 3,622.83 3,444.33 -82.12 16.91 2,433,912.52 317,484.74 3.10 83.39 20.60 208.49 3,681.13 3,502.63 -100.60 6.72 2,433,894.21 317,474.27 2.30 97.92 22.73 208.68 3,739.68 3,561.18 -121.02 -4.41 2,433,873.96 317,462.82 3.38 114.02 24.94 208.36 3,798.21 3,619.71 -143.74 -16.76 2,433,851.43 317,450.13 3.46 131.95 26.32 209.06 3,855.92 3,677.42 -168.02 -30.06 2,433,827.37 317,436.45 2.21 151.08 27.48 209.28 3,911.21 3,732.71 -192.51 -43.73 2,433,803.09 317,422.40 1.88 170.29 121512019 3:50:37PM Paae 3 COMPASS 5000.15 Build 91E Database: NORTH US + CANADA Local Co-ordinate Reference: Companv: Hilcorp Alaska, LLC TVD Reference: Protect Beaver Creek Unit MD Reference: Site: Beaver Creek Unit Pad 3 North Reference: Well: Beaver CK Unit 19 Survev Calculation Method: Wellbore: BCU 19RD Map +E/ -W Desiqn: BCU 19RD Wp02 Vert (usft) (usft) Planned Survey 3,789.06 Section -58.00 2,433,776.55 317,407.73 Measured 191.49 -71.83 Vertical 317,393.46 1.89 Depth Inclination -85.39 Azimuth Depth TVDss +N/ -S (usft) (°) (°) (usft) usft (usft) 4,014.50 29.10 206.91 3,967.56 3,789.06 -219.27 4,077.50 30.17 205.84 4,022.32 3,843.82 -247.1 E 4,140.50 31.26 204.02 4,076.48 3,897.98 -276.3E 4,204.50 31.58 203.63 4,131.10 3,952.60 -306.88 4,267.50 31.79 203.99 4,184.71 4,006.21 -337.16 4,330.50 31.97 203.62 4,238.21 4,059.71 -367.60 4,393.50 32.04 204.81 4,291.63 4,113.13 -398.05 4,455.50 31.55 203.58 4,344.33 4,165.83 -427.84 4,500.00 • 31.29 203.77 4,382.30 4,203.80 -449.09 KOP: 12.51/100' : 4500' MD, 4382.3'TVD : 30° LT TF 317,262.46 4,513.00 32.70 202.27 4,393.33 4,214.83 -455.43 End Dir : 4513' MD, 4393.33' TVD -166.09 2,433,253.24 317,291.53 4,533.00 32.70 202.27 4,410.16 4,231.66 -465.43 Start Dir 4°/100' : 4533' MD, 4410.16'TVD 2,433,210.68 317,327.02 4,600.00 30.87 198.56 4,467.11 4,288.61 -498.47 4,700.00 28.35 192.26 4,554.07 4,375.57 -546.01 4,800.00 26.18 184.92 4,642.98 4,464.48 -591.21 4,900.00 24.43 176.49 4,733.41 4,554.91 -633.84 5,000.00 23.21 167.04 4,824.93 4,646.43 -673.70 5,100.00 22.61 156.88 4,917.07 4,738.57 -710.60 5,200.00 22.66 146.47 5,009.41 4,830.91 -744.35 5,300.00 23.38 136.40 5,101.48 4,922.98 -774.79 5,341.31 23.86 132.45 5,139.33 4,960.83 -786.37 Sterling B4 0.00 1,005.43 180.32 2,432,958.67 317,633.39 5,384.74 24.46 128.46 5,178.96 5,000.46 -797.89 End Dir : 5384.74' MD, 5178.96' TVD 2,432,906.16 317,697.42 0.00 5,400.00 24.46 128.46 5,192.85 5,014.35 -801.82 5,500.00 24.46 128.46 5,283.88 5,105.38 -827.57 5,600.00 24.46 128.46 5,374.90 5,196.40 -853.33 5,700.00 24.46 128.46 5,465.93 5,287.43 -879.08 5,800.00 24.46 128.46 5,556.95 5,378.45 -904.84 5,900.00 24.46 128.46 5,647.98 5,469.48 -930.60 6,000.00 24.46 128.46 5,739.00 5,560.50 -956.35 6,100.00 24.46 128.46 5,830.03 5,651.53 -982.11 6,101.60 24.46 128.46 5,831.48 5,652.98 -982.52 Top Beluga 6,200.00 24.46 128.46 5,921.05 5,742.55 -1,007.86 6,300.00 24.46 128.46 6,012.08 5,833.58 -1,033.62 6,400.00 24.46 128.46 6,103.10 5,924.60 -1,059.37 6,500.00 24.46 128.46 6,194.13 6,015.63 -1,085.13 6,600.00 24.46 128.46 6,285.15 6,106.65 -1,110.89 6,700.00 24.46 128.46 6,376.18 6,197.68 -1,136.64 6,706.53 24.46 128.46 6,382.12 6,203.62 -1,138.32 Middle Beluga 6,800.00 24.46 128.46 6,467.20 6,288.70 -1,162.40 Halliburton Standard Proposal Report Well Beaver CK Unit 19 BCU 19RD @ 178.50usft (HAK 169) BCU 19RD @ 178.50usft (HAK 169) True Minimum Curvature 12152019 3:50:37PM Paoe 4 COMPASS 5000.15 Build 91E Map Map +E/ -W Northing Easting DLS Vert (usft) (usft) (usft) 3,789.06 Section -58.00 2,433,776.55 317,407.73 3.08 191.49 -71.83 2,433,748.86 317,393.46 1.89 213.91 -85.39 2,433,719.90 317,379.46 2.27 237.63 -98.86 2,433,689.59 317,365.51 0.59 262.65 -112.22 2,433,659.53 317,351.69 0.45 287.47 -125.65 2,433,629.30 317,337.79 0.42 312.43 -139.35 2,433,599.07 317,323.62 1.01 337.31 -152.74 2,433,569.49 317,309.78 1.31 361.67 -162.05 2,433,548.39 317,300.13 0.64 379.10 -164.74 2,433,542.10 317,297.34 12.50 384.33 -168.84 2,433,532.16 317,293.10 0.00 392.63 -181.17 2,433,499.31 317,280.25 4.00 420.40 -194.38 2,433,451.98 317,266.31 4.00 461.72 -201.32 2,433,406.90 317,258.67 4.00 502.71 -201.94 2,433,364.29 317,257.39 4.00 543.16 -196.26 2,433,324.34 317,262.46 4.00 582.88 -184.29 2,433,287.27 317,273.85 4.00 621.67 -166.09 2,433,253.24 317,291.53 4.00 659.34 -141.75 2,433,222.43 317,315.39 4.00 695.71 -129.93 2,433,210.68 317,327.02 4.00 710.32 -116.41 2,433,198.95 317,340.36 4.00 725.38 -111.46 2,433,194.94 317,345.25 0.00 730.63 -79.04 2,433,168.69 317,377.27 0.00 764.98 -46.62 2,433,142.44 317,409.28 0.00 799.33 -14.20 2,433,116.18 317,441.30 0.00 833.68 18.22 2,433,089.93 317,473.31 0.00 868.03 50.64 2,433,063.68 317,505.33 0.00 902.38 83.06 2,433,037.43 317,537.34 0.00 936.73 115.48 2,433,011.17 317,569.36 0.00 971.08 115.99 2,433,010.75 317,569.87 0.00 971.62 147.90 2,432,984.92 317,601.38 0.00 1,005.43 180.32 2,432,958.67 317,633.39 0.00 1,039.78 212.74 2,432,932.42 317,665.41 0.00 1,074.13 245.16 2,432,906.16 317,697.42 0.00 1,108.48 277.58 2,432,879.91 317,729.44 0.00 1,142.83 310.00 2,432,853.66 317,761.45 0.00 1,177.18 312.11 2,432,851.94 317,763.54 0.00 1,179.42 342.42 2,432,827.40 317,793.47 0.00 1,211.52 12152019 3:50:37PM Paoe 4 COMPASS 5000.15 Build 91E 12/5/2019 3:50:37PM Paae 5 COMPASS 5000.15 Build 91E Halliburton HALLIBURTON Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Beaver CK Unit 19 Companv: Hilcorp Alaska, LLC TVD Reference: BCU 19RD @ 178.50usft (HAK 169) Proiect: Beaver Creek Unit MD Reference: BCU 19RD @ 178.50usft (HAK 169) Site: Beaver Creek Unit Pad 3 North Reference: True Well: Beaver CK Unit 19 Survey Calculation Method: Minimum Curvature Wellbore: BCU 19RD Desiqn: BCU 19RD Wp02 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +EI-W Northing Easting DLS Vert (usft) (usft) usft (usft) (usft) (usft) (usft) 6,379.73 Section 6,900.00 24.46 128.46 6,558.23 6,379.73 -1,188.15 374.84 2,432,801.15 317,825.48 0.00 1,245.87 7,000.00 24.46 128.46 6,649.25 6,470.75 -1,213.91 407.26 2,432,774.90 317,857.50 0.00 1,280.22 7,100.00 24.46 128.46 6,740.28 6,561.78 -1,239.66 439.68 2,432,748.65 317,889.52 0.00 1,314.57 7,200.00 24.46 128.46 6,831.30 6,652.80 -1,265.42 472.10 2,432,722.39 317,921.53 0.00 1,348.92 7,300.00 24.46 128.46 6,922.33 6,743.83 -1,291.17 504.52 2,432,696.14 317,953.55 0.00 1,383.27 7,400.00 24.46 128.46 7,013.35 6,834.85 -1,316.93 536.94 2,432,669.89 317,985.56 0.00 1,417.62 7,447.00 24.46 128.46 7,056.14 6,877.64 -1,329.04 552.17 2,432,657.55 318,000.61 0.00 1,433.77 9 5/8" x 121 /4" 7,500.00 24.46 128.46 7,104.38 6,925.88 -1,342.69 569.36 2,432,643.63 318,017.58 0.00 1,451.97 7,600.00 24.46 128.46 7,195.40 7,016.90 -1,368.44 601.78 2,432,617.38 318,049.59 0.00 1,486.32 7,700.00 24.46 128.46 7,286.43 7,107.93 -1,394.20 634.20 2,432,591.13 318,081.61 0.00 1,520.67 7,800.00 24.46 128.46 7,377.46 7,198.96 -1,419.95 666.62 2,432,564.88 318,113.62 0.00 1,555.02 7,877.34 24.46 128.46 7,447.85 7,269.35 -1,439.87 691.69 2,432,544.57 318,138.38 0.00 1,581.59 Lower Beluga 7,900.00 24.46 128.46 7,468.48 7,289.98 -1,445.71 699.04 2,432,538.62 318,145.64 0.00 1,589.37 8,000.00 24.46 128.46 7,559.51 7,381.01 -1,471.46 731.46 2,432,512.37 318,177.66 0.00 1,623.72 8,100.00 24.46 128.46 7,650.53 7,472.03 -1,497.22 763.88 2,432,486.12 318,209.67 0.00 1,658.07 8,200.00 24.46 128.46 7,741.56 7,563.06 -1,522.97 796.30 2,432,459.87 318,241.69 0.00 1,692.42 8,300.00 24.46 128.46 7,832.58 7,654.08 -1,548.73 828.72 2,432,433.61 318,273.70 0.00 1,726.77 8,400.00 24.46 128.46 7,923.61 7,745.11 -1,574.49 861.14 2,432,407.36 318,305.72 0.00 1,761.12 8,500.00 24.46 128.46 8,014.63 7,836.13 -1,600.24 893.56 2,432,381.11 318,337.73 0.00 1,795.47 8,555.71 24.46 128.46 8,065.34 7,886.84 -1,614.59 911.62 2,432,366.48 318,355.57 0.00 1,814.61 Start Dir 31/100' : 8555.71' MD, 8065.347VD 8,600.00 23.59 130.93 8,105.80 7,927.30 -1,626.10 925.49 2,432,354.76 318,369.26 3.00 1,829.77 8,700.00 21.78 137.14 8,198.07 8,019.57 -1,652.81 953.24 2,432,327.62 318,396.59 3.00 1,863.62 8,800.00 20.24 144.33 8,291.43 8,112.93 -1,680.47 975.95 2,432,299.62 318,418.86 3.00 1,896.85 8,900.00 19.04 152.52 8,385.63 8,207.13 -1,709.00 993.56 2,432,270.82 318,436.04 3.00 1,929.37 9,000.00 18.24 161.58 8,480.41 8,301.91 -1,738.33 1,006.04 2,432,241.31 318,448.05 3.00 1,961.10 9,100.00 17.90 171.20 8,575.50 8,397.00 -1,768.36 1,013.33 2,432,211.16 318,454.88 3.00 1,991.93 9,190.38 18.00 180.00 8,661.50 8,483.00 -1,796.06 1,015.46 2,432,183.44 318,456.58 3.00 2,018.97 Tyonek T1 9,200.00 17.98 180.93 8,670.65 8,492.15 -1,799.03 1,015.43 2,432,180.47 318,456.51 3.00 2,021.80 9,210.99 17.96 182.00 8,681.10 8,502.60 -1,802.42 1,015.35 2,432,177.08 318,456.37 3.00 2,025.00 TK_TY0NEK_T1 9,228.61 17.94 183.71 8,697.86 8,519.36 -1,807.84 1,015.08 2,432,171.67 318,456.02 3.00 2,030.09 TK TYONEK T1_1 9,251.42 17.93 185.93 8,719.56 8,541.06 -1,814.84 1,014.49 2,432,164.68 318,455.32 3.00 2,036.58 End Dir : 9251.42' MD, 8719.56' TVD 9,266.48 17.93 185.93 8,733.89 8,555.39 -1,819.45 1,014.01 2,432,160.08 318,454.77 0.00 2,040.83 TK TYONEK_T1_2 9,300.00 17.93 185.93 8,765.79 8,587.29 -1,829.71 1,012.94 2,432,149.83 318,453.54 0.00 2,050.29 9,334.53 17.93 185.93 8,798.64 8,620.14 -1,840.29 1,011.84 2,432,139.28 318,452.28 0.00 2,060.04 TK_TYONEK_T1_3 9,368.88 17.93 185.93 8,831.32 8,652.82 -1,850.80 1,010.75 2,432,128.78 318,451.02 0.00 2,069.74 TK TYONEK T1 4 12/5/2019 3:50:37PM Paae 5 COMPASS 5000.15 Build 91E I =".A 01011 =10 T�T►�l Halliburton Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Beaver CK Unit 19 Company: Hilcorp Alaska, LLC TVD Reference: BCU 19RD @ 178.50usft (HAK 169) Prosect: Beaver Creek Unit MD Reference: BCU 19RD @ 178.50usft (HAK 169) Site: Beaver Creek Unit Pad 3 North Reference: True Well: Beaver CK Unit 19 Survev Calculation Method: Minimum Curvature Wellbore: BCU 19RD Map +EI -W Design: BCU 19RD Wp02 Vert (usft) (usft) Planned Survey 8,682.43 Section 1,009.76 2,432,119.26 318,449.89 Measured 2,078.52 1,007.22 Vertical 318,446.97 0.00 Depth Inclination Azimuth Depth TVDss +N( -S (usft) (°) (°) (usft) usft (usft) 9,400.00 17.93 185.93 8,860.93 8,682.43 -1,860.33 9,479.84 17.93 185.93 8,936.89 8,758.39 -1,884.78 TK_TYONEK_Ti_5 0.00 2,163.21 997.02 2,431,996.99 9,500.00 17.93 185.93 8,956.07 8,777.57 -1,890.96 9,600.00 17.93 185.93 9,051.21 8,872.71 -1,921.58 9,627.75 17.93 185.93 9,077.62 8,899.12 -1,930.08 T -91 -ST 2,431,905.29 318,424.29 0.00 2,276.12 984.29 9,661.17 17.93 185.93 9,109.41 8,930.91 -1,940.31 T -91 -SB 0.00 2,332.57 977.93 2,431,813.59 318,413.32 9,700.00 17.93 185.93 9,146.36 8,967.86 -1,952.20 9,800.00 17.93 185.93 9,241.50 9,063.00 -1,982.82 9,864.04 17.93 185.93 9,302.43 9,123.93 -2,002.44 TK_TYONEK_T3 318,398.69 0.00 2,473.72 963.03 2,431,670.52 9,900.00 17.93 185.93 9,336.64 9,158.14 -2,013.45 10,000.00 17.93 185.93 9,431.78 9,253.28 -2,044.07 10,100.00 17.93 185.93 9,526.93 9,348.43 -2,074.69 10,200.00 17.93 185.93 9,622.07 9,443.57 -2,105.31 10,300.00 17.93 185.93 9,717.21 9,538.71 -2,135.94 10,400.00 17.93 185.93 9,812.36 9,633.86 -2,166.56 10,500.00 17.93 185.93 9,907.50 9,729.00 -2,197.18 10,600.00 17.93 185.93 10,002.64 9,824.14 -2,227.80 10,700.00 17.93 185.93 10,097.78 9,919.28 -2,258.43 10,800.00 17.93 185.93 10,192.93 10,014.43 -2,289.05 10,868.05 17.93 185.93 10,257.67 10,079.17 -2,309.89 BC_T19ST 2,756.00 930.18 2,431,355.07 318,358.47 0.00 10,900.00 17.93 185.93 10,288.07 10,109.57 -2,319.67 11,000.00 17.93 185.93 10,383.21 10,204.71 -2,350.29 11,017.50 17.93 185.93 10,399.86 10,221.36 -2,355.65 BC_T19SB 11,074.43 17.93 185.93 10,454.03 10,275.53 -2,373.09 BC_T20ST 11,100.00 17.93 185.93 10,478.35 10,299.85 -2,380.92 11,169.89 17.93 185.93 10,544.85 10,366.35 -2,402.32 BC_T20SB 11,200.00 17.93 185.93 10,573.50 10,395.00 -2,411.54 11,300.00 17.93 185.93 10,668.64 10,490.14 -2,442.16 11,400.00 17.93 185.93 10,763.78 10,585.28 -2,472.78 11,500.00 17.93 185.93 10,858.92 10,680.42 -2,503.41 11,600.00 17.93 185.93 10,954.07 10,775.57 -2,534.03 11,700.00 17.93 185.93 11,049.21 10,870.71 -2,564.65 11,800.00 17.93 185.93 11,144.35 10,965.85 -2,595.27 11,900.00 17.93 185.93 11,239.50 11,061.00 -2,625.89 12,000.00 17.93 185.93 11,334.64 11,156.14 -2,656.52 12,100.00 17.93 185.93 11,429.78 11,251.28 -2,687.14 12,200.00 17.93 185.93 11,524.92 11,346.42 -2,717.76 12/52019 3:50:37PM Paw 6 COMPASS 5000.15 Build 91E Map Map +EI -W Northing Easting DLS Vert (usft) (usft) (usft) 8,682.43 Section 1,009.76 2,432,119.26 318,449.89 0.00 2,078.52 1,007.22 2,432,094.86 318,446.97 0.00 2,101.06 1,006.57 2,432,088.70 318,446.23 0.00 2,106.75 1,003.39 2,432,058.13 318,442.57 0.00 2,134.98 1,002.51 2,432,049.64 318,441.56 0.00 2,142.81 1,001.44 2,432,039.43 318,440.34 0.00 2,152.24 1,000.21 2,432,027.56 318,438.92 0.00 2,163.21 997.02 2,431,996.99 318,435.26 0.00 2,191.43 994.99 2,431,977.42 318,432.92 0.00 2,209.51 993.84 2,431,966.43 318,431.60 0.00 2,219.66 990.66 2,431,935.86 318,427.95 0.00 2,247.89 987.48 2,431,905.29 318,424.29 0.00 2,276.12 984.29 2,431,874.72 318,420.63 0.00 2,304.35 981.11 2,431,844.16 318,416.98 0.00 2,332.57 977.93 2,431,813.59 318,413.32 0.00 2,360.80 974.74 2,431,783.02 318,409.66 0.00 2,389.03 971.56 2,431,752.45 318,406.01 0.00 2,417.26 968.38 2,431,721.89 318,402.35 0.00 2,445.49 965.19 2,431,691.32 318,398.69 0.00 2,473.72 963.03 2,431,670.52 318,396.21 0.00 2,492.92 962.01 2,431,660.75 318,395.04 0.00 2,501.94 958.83 2,431,630.18 318,391.38 0.00 2,530.17 958.27 2,431,624.83 318,390.74 0.00 2,535.11 956.46 2,431,607.43 318,388.66 0.00 2,551.18 955.64 2,431,599.61 318,387.72 0.00 2,558.40 953.42 2,431,578.25 318,385.17 0.00 2,578.13 952.46 2,431,569.05 318,384.07 0.00 2,586.63 949.28 2,431,538.48 318,380.41 0.00 2,614.86 946.09 2,431,507.91 318,376.75 0.00 2,643.08 942.91 2,431,477.34 318,373.10 0.00 2,671.31 939.73 2,431,446.78 318,369.44 0.00 2,699.54 936.55 2,431,416.21 318,365.78 0.00 2,727.77 933.36 2,431,385.64 318,362.13 0.00 2,756.00 930.18 2,431,355.07 318,358.47 0.00 2,784.22 927.00 2,431,324.51 318,354.81 0.00 2,812.45 923.81 2,431,293.94 318,351.16 0.00 2,840.68 920.63 2,431,263.37 318,347.50 0.00 2,868.91 12/52019 3:50:37PM Paw 6 COMPASS 5000.15 Build 91E HALLIBURTON Halliburton Standard Proposal Report Database: NORTH US + CANADA Casing Points Diameter Local Co-ordinate Reference: Well Beaver CK Unit 19 Vertical Companv: Hilcorp Alaska, LLC (usft, (usft) Name TVD Reference: BCU 19RD @ 178.50usft (HAK 169) 12,656.76 Proiect: Beaver Creek Unit MD Reference: BCU 19RD @ 178.50usft (HAK 169) Site: Beaver Creek Unit Pad 3 North Reference: True Well: Beaver CK Unit 19 Survev Calculation Method: Minimum Curvature Wellbore: BCU 19RD Design: BCU 19RD Wp02 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 11,441.57 Section 12,300.00 17.93 185.93 11,620.07 11,441.57 -2,748.38 917.45 2,431,232.80 318,343.85 0.00 2,897.14 12,389.85 17.93 185.93 11,705.55 11,527.05 -2,775.90 914.59 2,431,205.34 318,340.56 0.00 2,922.50 TK_TYONEK_T4_4 12,400.00 17.93 185.93 11,715.21 11,536.71 -2,779.01 914.26 2,431,202.24 318,340.19 0.00 2,925.37 12,500.00 17.93 185.93 11,810.35 11,631.85 -2,809.63 911.08 2,431,171.67 318,336.53 0.00 2,953.59 12,600.00 17.93 185.93 11,905.49 11,726.99 -2,840.25 907.90 2,431,141.10 318,332.88 0.00 2,981.82 12,656.76 17.93 185.93 11,959.50 11,781.00 -2,857.63 906.09 2,431,123.75 318,330.80 0.00 2,997.84 Total Depth : 12656.76' MD, 11959.5' TVD - 5 1/2" x 8 1/2" - BCU-19RD TD Targets Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) TyonekTI 0.00 0.00 8,661.50 -1,796.06 1,015.46 2,432,183.44 318,456.58 - plan hits tarqet center - Circle (radius 150.00) BCU-19RDTD 0.00 0.00 11,959.50 -2,857.63 906.09 2,431,123.75 318,330.80 - plan hits tarqet center - Circle (radius 50.00) Hole Casing Points Diameter Measured Vertical Depth Depth (usft, (usft) Name 7,447.00 7,056.14 9 5/8" x 12 1/4" 12,656.76 11,959.50 5 1/2" x 8 1/2" Casing Hole Diameter Diameter 9-5/8 12-1/4 5-1/2 8-1/2 121512019 3:50:37PM Paae 7 COMPASS 5000.15 Build 91E Database: NORTH US + CANADA Company: Hilcorp Alaska, LLC Proiect: Beaver Creek Unit Site: Beaver Creek Unit Pad 3 Well: Beaver CK Unit 19 Wellbore: BCU 19RD Desiqn: BCU 19RD Wp02 Formations 4,382.30 -449.09 Measured Vertical Vertical KOP: 12.5'/100': 4500' MD, 4382.3'TVD : 30° LT TF Depth Depth Depth SS 4,393.33 (usft) (usft) -164.74 10,868.05 10,257.67 4,533.00 6,706.53 6,382.12 -465.43 9,228.61 8,697.86 Start Dir 4°/100' : 4533' MD, 4410.16'TVD 11, 074.43 10,454.03 5,178.96 9,661.17 9,109.41 -116.41 9,864.04 9,302.43 8,555.71 9,266.48 8,733.89 -1,614.59 9,479.84 8,936.89 Start Dir 30/100' : 8555.71' MD, 8065.34'TVD 11,169.89 10,544.85 8,719.56 9,627.75 9,077.62 1,015.46 9,334.53 8,798.64 12,656.76 6,101.60 5,831.48 -1,814.83 9,210.99 8,681.10 Total Depth : 12656.76' MD, 11959.5' TVD 9,368.88 8,831.32 12,389.85 11,705.55 11,017.50 10,399.86 5,341.31 5,139.33 7,877.34 7,447.85 Plan Annotations Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Name BC_T19ST Middle Beluga TK_TYONEK_T1_1 BC_T20ST T_91_SB TK_TYONEK_T3 TK_TYONEK_T1_2 TK_TYONEK_T1_5 BC_T20SB T_91_ST TK_TYON E K_T1 _3 Top Beluga TK_TYONEK_T1 TK_TYONEK_T1_4 TK_TYO N EK_T4_4 BC_T19SB Sterling B4 Lower Beluga Halliburton Standard Proposal Report Well Beaver CK Unit 19 BCU 19RD @ 178.50usft (HAK 169) BCU 19RD @ 178.50usft (HAK 169) True Minimum Curvature Dip Dip Direction Lithology (1) (1 Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 4,500.00 4,382.30 -449.09 -162.05 KOP: 12.5'/100': 4500' MD, 4382.3'TVD : 30° LT TF 4,513.00 4,393.33 -455.43 -164.74 End Dir : 4513' MD, 4393.33' TVD 4,533.00 4,410.16 -465.43 -168.84 Start Dir 4°/100' : 4533' MD, 4410.16'TVD 5,384.74 5,178.96 -797.89 -116.41 End Dir : 5384.74' MD, 5178.96' TVD 8,555.71 8,065.34 -1,614.59 911.62 Start Dir 30/100' : 8555.71' MD, 8065.34'TVD 9,251.42 8,719.56 -1,796.06 1,015.46 End Dir : 9251.42' MD, 8719.56' TVD 12,656.76 11,959.50 -1,814.83 1,014.49 Total Depth : 12656.76' MD, 11959.5' TVD 12/5/2019 3:50:37PM Paae 8 COMPASS 5000.15 Build 91E Hilcorp Alaska, LLC Beaver Creek Unit Beaver Creek Unit Pad 3 Beaver CK Unit 19 BCU 19RD PTD 208-123 BCU 19RD Wp02 Sperry Drilling Services Clearance Summary Anticollision Report 05 December, 2019 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: Beaver Creek Unit Pad 3 - Beaver CK Unit 19 - BCU 19RD - BCU 19RD Wp02 Well Coordinates: 2,433,994.89 N, 317,469.11 E (60° 39'30.27" N, 151' 01' 02.73" W) Datum Height: BCU 19RD [a7178.50usft (HAK 169) Scan Range: 4,500.00 to 12,656.76 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Geodetic Scale Factor Applied Version: 5000.15 Build: 91E Scan Type: GLOBAL FILTER APPLIED: All wellpalhs within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Drilling Services HALLIBURTON Anticollision Report for Beaver CK Unit 19 - BCU 19RD Wp02 Hilcorp Alaska, LLC Beaver Creek Unit Closest Approach 3D Proximity Scan on Current Survey Data (Hiohside Reference) Reference Design: Beaver Creek Unit Pad 3 - Beaver CK Unit 19 - BCU 19RD - BCU 19RD W002 Scan Range: 4,500.00 to 12,656.76 usft. Measured Depth. Scan Radius is Unlimited . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Measure Minimum @Measure Ellipse @Measure Clearance Summary Based Site Name d Distance d Separation d Factor on Minimum Separation Warning Comparison Well Name - Wellbore Name - Design Denth /nsftl D.mh 1-fil nenth Beaver Creek Unit Pad 1A Beaver CK Unit 1 A - BCU 1A - BCU -IA Beaver CK Unit 1 A - BCU 1A - BCU -1A Beaver CK Unit 1 A - BCU IA - BCU -1 A Beaver Creek Unit Pad 3 Beaver CK Unit 10 - BCU 10 - BCU 10 Beaver CK Unit 10 - BCU 10 - BCU 10 Beaver CK Unit 11 - BCU 11 - BCU 11 Beaver CK Unit 13 - BCU 13 - BCU 13 Beaver CK Unit 13 - BCU 13 - BCU 13 Beaver CK Unit 13 - BCU 13 - BCU 13 Beaver CK Unit 16 - BCU 16 - BCU 16 Beaver CK Unit 16 - BCU 16 - BCU 16 Beaver CK Unit 16 - BCU 16RD - BCU 16RD Beaver CK Unit 16 - BCU 16RD - BCU 16RD Beaver CK Unit 16 - BCU 16RD - BCU 16RD Beaver CK Unit 19 - BCU 19 - BCU 19 Beaver CK Unit 23 - BCU 23 - BCU 23 Beaver CK Unit 23 - BCU 23 - BCU 23 Beaver CK Unit 24 - BCU 24 - BCU 24 Beaver CK Unit 24 - BCU 24 - BCU 24 Beaver CK Unit 24 - BCU 24 - BCU 24 Beaver CK Unit 25 - BCU -25 - BCU -25 Beaver CK Unit 25 - BCU -25 - BCU -25 Beaver CK Unit 5 - BCU 5 - BCU 5 Beaver CK Unit 5 - BCU 5RD - BCU 5RD Beaver CK Unit 5 - BCU 5RD2 - BCU 5RD2 Beaver CK Unit 6 - BCU 6 - BCU 6 10,075.00 1,205.48 10,075.00 1,023.61 10,296.00 6.628 Clearance Factor Pass - 10,250.00 1,182.48 10,250.00 1,008.20 10,296.00 6.785 Ellipse Separation Pass - 10,319.39 1,180.45 10,319.39 1,010.16 10,296.00 6.932 Centre Distance Pass - 4,500.00 1,411.24 4,500.00 1,374.86 4,056.95 38.795 Ellipse Separation Pass - 4,525.00 1,429.67 4,525.00 1,392.66 4,076.93 38.632 Clearance Factor Pass - 4,500.00 635.40 4,500.00 605.36 4,243.20 21.156 Clearance Factor Pass - 8,150.00 388.20 8,150.00 317.34 8,016.23 5.478 Clearance Factor Pass - 8,200.00 387.33 8,200.00 316.76 8,062.69 5.489 Ellipse Separation Pass - 8,220.27 387.25 8,220.27 316.82 8,081.30 5.499 Centre Distance Pass - 6,535.86 1,153.29 6,535.86 1,108.68 6,422.00 25.857 Ellipse Separation Pass - 6,550.00 1,153.37 6,550.00 1,108.76 6,422.00 25.853 Clearance Factor Pass - 9,372.62 1,035.27 9,372.62 982.36 9,421.00 19.567 Centre Distance Pass - 9,375.00 1,035.27 9,375.00 982.36 9,421.00 19.565 Ellipse Separation Pass - 9,400.00 1,035.63 9,400.00 982.65 9,421.00 19.549 Clearance Factor Pass - 4,800.00 20.69 4,800.00 14.00 4,802.46 3.090 Clearance Factor Pass - 4,500.00 814.31 4,500.00 785.23 4,288.44 27.999 Ellipse Separation Pass - 8,700.00 1,253.77 8,700.00 1,203.59 8,386.17 24.986 Clearance Factor Pass - 9,210.69 927.88 9,210.69 852.87 9,291.53 12.371 Centre Distance Pass - 9,250.00 928.31 9,250.00 852.70 9,331.33 12.277 Ellipse Separation Pass - 10,175.00 993.32 10,175.00 906.09 10,212.10 11.388 Clearance Factor Pass - 5,550.00 366.70 5,550.00 321.38 7,062.36 8.092 Clearance Factor Pass - 5,569.00 366.21 5,569.00 321.41 7,062.36 8.175 Centre Distance Pass - 4,500.00 444.00 4,500.00 401.19 4,376.90 10.371 Clearance Factor Pass - 4,500.00 444.00 4,500.00 401.19 4,376.90 10.371 Clearance Factor Pass - 4,500.00 444.00 4,500.00 401.19 4,382.30 10.371 Clearance Factor Pass - 4,500.00 471.03 4,500.00 416.51 4,379.19 8.639 Clearance Factor Pass - 05 December, 2019 - 15:54 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Beaver CK Unit 19 - BCU 19RD Wp02 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) SunmylPlan !usft) (usft) 210.50 4,500.00 Reference Design: Beaver Creek Unit Pad 3 - Beaver CK Unit 19 - BCU 19RD - BCU 19RD Wp02 4,500.00 4,900.00 BCU 19RD Wp02 4,900.00 7,447.00 Scan Range: 4,500.00 to 12,656.76 usft. Measured Depth. 7,447.00 12,656.76 BCU 19RD Wp02 Ellipse error terms are correlated across survey tool tie -on points. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is 1,000.00 usft Distance Between centres is the straight line distance between wellbore centres. Measure Minimum @Measure Ellipse @Measure Site Name d Distance d Separation d Comparison Well Name - Wellbore Name - Design Deoth f—ftl Denth (rrsftl Dcnth Beaver CK Unit 9 - BCU 9 - BCU 9 6,152.76 813.22 6,152.76 766.38 6,267.38 Beaver CK Unit 9 - BCU 9 - BCU 9 6,275.00 814.40 6,275.00 765.48 6,387.86 Beaver CK Unit 9 - BCU 9 - BCU 9 7,150.00 912.30 7,150.00 849.47 7,183.33 $urveV tool program From To SunmylPlan !usft) (usft) 210.50 4,500.00 4,500.00 4,900.00 BCU 19RD Wp02 4,900.00 7,447.00 BCU 19RD Wp02 7,447.00 12,656.76 BCU 19RD Wp02 Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor= Distance Between Profiles / (Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Alaska, LLC Beaver Creek Unit Clearance Summary Based Factor on Minimum Separation Warning 17.360 Centre Distance Pass - 16.649 Ellipse Separation Pass - 14.520 Clearance Factor Pass - Survey Tool 3_MWD+AX 3_MWD _Interp Azi+Sag 3 MWD+IFRI+MS+Sag 3_MWD+IFRI+MS+Sag 05 December, 2019 - 15:54 Page 3 of 5 COMPASS HALLIBURTON Project: Beaver Creek Unit REFERENCE INFORMATION WELL DFIAIIS: Beava CK Unit 19 NAD 1927(NADCON CONUS) Alaska Zone 04 Rarer-- Well BsR. 1 Unrt 19. IHA Rodh Co-oNinata (TVD) Site: Beaver Creek Unit Pa 3 VeMwl (ND) Reference: BCU 19R0 @ 17 .ft IHAK 169) Gmimd ]evel: 160.50 Well: Beaver CK Unit 19 Measured O pih Rersran- BCU 19RD a 1]fi.50use (H-1as) +N/ -S +F/ -W Nontdng East4 L.Uthde L-gi.& S,o - , 0-6,,e Wellbore: BCU 19RD Calculation M -d: Minimum curvature 0.00 0.00 2433994.89 317469.11 60°3930271 N 151° 1'2,727W Plan: BCU 19RD Wp02 GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference SURVEY PROGRAM 4500.00 To 12656.76 Date: 201312-05T00:00:00 Validated: Yes Version: CASING DETAILS Depth From Depth To Survey/Plan Tool TVp TVDSS MD Size Name 210.50 4500.00 BCU 19 (BCU 19) 3 MWD+AX 7056.14 6877.64 7447.00 9-5/8 95/8"x121/4" 4500.00 4900.00 BCU 19RD WP02 (BCU 19RD) 3_MWD_Interp A -Sag 4900.00 7447.00 BCU 19RD Wp02 (BCU 19RD) 3_MWD+IFRI+MS+Sag 11959.50 11781.00 12656 76 5-1/2 51/2".8112" Ladder/S.F. Plots 7447.00 12656.76 BCU 19RD Wp02(BCU 19RD) 3_MWD+IFRI+MS+Sag BCU 19 0160.00 o 0 i I i c 0120.00 at 80.00 Q) O I a 40.00 f I U 0.00 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550 9000 9450 9900 10350 10800 11250 11700 12150 12600 13050 Measured Depth (900 usft/in) 4.00 i I --- I is 3.00 LL c ° Collision Risk Procedures R, q. 2.00 - Collision Avoidance Req. No -Go Zone - Stop Drilling 1.00 NOERRORS i a.00 4500 4950 5400 5850 6300 6750 7200 7650 8100 8550 9000 9450 9900 10350 10800 11250 11700 12150 12600 13050 Measured Depth (900 usft/in) Y w E _3 O u O E > Y m 3 ° O E E o 3 m O Y E @ ^ w w CD m to +L 3 L O m y w � an w m O w O Y Q L w w E L °1 3 O L C >> N 3 3 V O w v w m 3 J / Y m 'au) c w m E 3 N w O> 30 O Q u L y y N U N3 w � 3 U EF O- � 3 '6 E w O n O L = U W U Z W J O F Y U Y N C O m 3 _V m V >. y w U a 7 U � U V m m w 3 L O c E O w W c � E QI H C. E N 00 �00 0O C w p N-1 N w0 3 N L T W to Y C c 3 � U a u � p t > •N p mcr- y V w O Y m O U `i w m _ m > c 3 o E U on m a m E O a Q c o H v w O 2 w V m m � 0w U Y s ++ m w H 3 � y m ++ y wo m w C — w O C y O Q mc n 0 '0Y S m d p H -E w w w w QN _ m++ 3 m to w y -o y O c 2. m 0 0 3 r Q o Q O c a p m c o O i V C Y w CL "� w 3 O m T m T w C O O m m 7 � C E m c m i w S H .,,_T, c cu O O L O w C Q c O CL w O Y Y CC i N w v i m L w c w w U U ' c w c° N V Y �' x y w 3 w 3 V `t Y w Y w «• a m m v I --v v E E n a) y w w m tw o L 3 Y O 3 3 C c M wa o o Y > 'U - v 0 OCO Q Q O Y m >' �n U w V Y O m ow CL m N E m '0 w = m m o v m a E E° ou c r U Q w C L 3 p vii L f° m 1 o �a- .. LL o Q v _ C 3 r L c cw E� p p cn a m Q N w r t t w Qa�y++ CL 4y- fl. ay.. Q U U U C c C Q -0 L -0 V1 VI CL Q V1 Q 4w- L -0 Q -0 .Li NLn O Ln O -4v1 u1 IA O Ln 01 N V kO V � 1-+ =u O O OD N On N ci L6 N N O O Ln O O ~ M N Ln O O v v \ V C O O_ Q x U Y Q Y O CO V1 Y p Q m m "O 0 m G y c w Q UOv c c O V m x O Ow m c Y �.- O- F— m ° LL u Y O O_ p O '^ a 0 y0 w .0 E w w E w w U o E L ?) F— p Y p VI L — QC L 00 7� 3 H 3 fl. p> w m O Z S w v o y o O w J> Y F- (D S p m J S > m > m> 'o w E _3 O u O E > Y m 3 ° O E E o 3 m O Y E @ ^ w w CD m to +L 3 L O m y w � an w m O w O Y Q L w w E L °1 3 O L C >> N 3 3 V O w v w m 3 J / Y m 'au) c w m E 3 N w O> 30 O Q u L y y N U N3 w � 3 U EF O- � 3 '6 E w O n O L = U W U Z W J O F Y U Y Beaver Creek Unit PRG, OSED SCHEMATIC Well: BCU 19RD PTD: TBD Hilcorp Alaska. LLC RKB: MSL = 38' CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / Weld 18.730" Surf 106' 13-3/8" Surface 68/L-80—J-55/BTC 12.415" Surf 2,510' 9-5/8" Intermediate 40 / L-80 / BTC 8.835" Surf 7,447' 5-1/2" 1 Production I 17 / P-110 / CDC-DWC 1 4.892" Surf 12,657' JEWELRY DETAIL No Depth Item 1 4,300' 9-5/8" Swell Packer w'. OPEN HOLE / CEMENT DETAIL 5-1/2" 441 BBL'S (2,481 cuft) of cement in 8.5" Hole. Est. TOC 4,300' (30% excess) ) sYe . r w•l TD =12,657 (MD) / 11,970' (TVD) PBTD =12,577 (MD) / 11,893' (TVD) Updated by DWG 10-22-19 THE STATE 01ALfisK-A- GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 RECEIVED Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Hilcorp Alaska, LLC Re: Beaver Creek Field, Beluga Gas and Sterling Gas Pools, BCU 19 Permit to Drill Number: 208-123 Sundry Number: 319-483 Dear Mr. York: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, I1 l Q, J y . Price Chair DATED this Jvday of October, 2019. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ►QZ.0.y-1;ii►� RECEIVED Orl 2 2 2019 AOGiCC 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 ❑ ,. e, the,: ❑" 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: St, Hilcorp Alaska, LLC Exploratory ❑ Development ❑✓ Stratigraphic ❑ Service ❑ 208-123 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20579-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 237A ❑ ❑✓ Beaver Creek Unit (BCU) 19 Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028083 Beaver Creek Field J Beluga Gas - Sterling Gas Pools 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (PAD): Junk (MD): 9,068' 8,678' 9,016' 8,626' 1,772 psi 5,500' 6,454'(3.5" tbg) Casing Length Size MD TVD Burst Collapse Structural Conductor 106' 20" 106' 106' 3,060 psi 1,500 psi Surface 2,510' 13-3/8" 2,510' 2,509' 3,450 psi 1,950 psi Intermediate 7,447' 9-5/8" 7,447' 7,057' 5,750 psi 3,090 psi Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3# / L-80 5,272' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): DLH Hydraulic Packer; NIA 5,245' MD/5,020' TVD; N/A 12, Attachments: Proposal Summary Wellbore schematic [./1 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: January 1, 2020 OIL❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS Q WAG ❑ GSTOR ElSPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ E]Op Shutdown E]Abandoned El 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer hilcor .com / Contact Phone: 777-8420 Authorized Signature: / / z Date: 3 (-1 0 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3,q_cj?3 Plug Integrity ❑ BOP Test [ Mechanical Integrity Test ❑ Location Clearance ❑ Other: ,�360r Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Subsequent Form Required: `\\ ` I APPROVED BY O ? 1 Approved by: ` COMMISSIONER THE COMMISSION Date:` G } UvSubmit Fore and Form 10-403 Revised 4/2017 Approved application is vaBV ^.toChINaToEproval. Attachments in Duplicate I ilcorp Alaska, LL Repair Wellhead Well: BCU -19 Date: 10/21/2019 Well Name: BCU -19 API Number: 50-133-20579-00-00 Current Status: Shut -In Gas Well Leg: N/A Estimated Start Date: 1/1/2020 Rig: 401 Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 208-123 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (M) AFE Number: Current Surface Pressure: Max. Expected BHP: Max. Potential Surface Pressure: Brief Well Summary 10 psi 2,300 psi @ 5,258' TVD 1,772 psi @ 5,258' TVD (Shut -In) (Based on normal gradient) (Based on expected BHP and gas gradient to surface) Beaver Creek Unit #19 was drilled as a Grass roots EXCAPE monobore completion in 2009 to target gas sands in the lower Beluga formation. The bottom 5 EXCAPE modules were perforated and fracture stimulated and additional zones were wireline perforated in 2009. The well performance was initially poor and was shut-in shortly after completion. Recently added perforations in July and August of 2013 were unproductive. The well was plugged back and recompleted in the Upper Beluga C-3 in May 2014. However, the Upper Beluga C-3 interval came in wet. This zone was then plugged back and the Sterling B4 perforated in June 2014. The Sterling B4 IP'd at 750 Mcfd but was short lived and the well was shut in by August 51h 2014. All perforations are currently isolated by a plug set in the X -Nipple at 5,271' set in May 2017 and a Posi-set plug W/35' of cement at 5,500'. The purpose of this work/sundry is to repair the wellhead, Run a CBL and prepare the well to be sidetracked in early 2020. Notes Regarding Wellbore Condition • Well has a packoff leak from the IA to the OA. • All perforations are isolated with a X -plug at 5,271' and a Posi-set plug and 35' of cement @ 5,500'. Procedure: 1. RU SL and Pull X -plug @ 5,271'. 2. MIRU Rig 401. 3. Notify AOGCC and BLM 24 hours in advance of BOP test to extend the opportunity to witness. a. Set Back pressure valve. b. ND wellhead, NU BOP and test to 250 psi low & 3,000 psi high, annular to 250 psi low & 2,500 psi high. Record accumulator pre -charge pressures and chart tests. c. Test VBR rams on, -3 %wtggestjoint. rd d. Submit completed fo1D=424 to AOGCC within 5 days of BOPE test. Copy to BLM. N i L- , Ta 4. Circulate well with brine to remove any gas. `� llileurp Alaska, LL Repair Wellhead Well: BCU -19 Date: 10/21/2019 5. Bleed all pressure from 13-3/8" X 9-5/8" annulus. 6. PU on tubing to release Hydraulic Packer (50K shear). 7. PU, POOH W/ Tubing racking back laying down all GLM's and capillary line. 8. RU E -line. Run CBL from PBTD (5,465') up to 2,510'. POOH and RD E -line. 9. RIH W/ Tubing and Test packer. Set Pkr @ 300'. Pressure test 9-5/8" casing to 2,500psi for 30 min. on chart. POOH with test packer. 10. Change out wellhead packoff. 11. RIH With kill strinF. 7 12. ND BOP. NU Well head and pressure test tree. 13. RDMO Rig 401. �4-- 4e_ I> Attachments: 1. As -built Schematic (proposed Schematic is the same) Of/- /&-ul-/I 2. BOP Schematic 3. Forward Fluid Flow 4. Wellhead Diagram 5. Procedure Change Form Ililcorp Alaska, LLC Permit #: 208-123 API #: 50-133-20579-00-S1 Prop. Des: A - 028083 KB elevation. 182' (21' AGL) Latitude: 60° 39' 28.14" N Longitude: 151° 01' 10.61'W X: 317,471.6 (NAD 27) Y: 2,433,991.7 (NAD 27) Spud: 9/14/2008 TD: 10101/2008 Rig Released: 1114/09 12:00 hrs BC -19 Pad 3 1,196' FNL, 1,657' FWL, Sec. 34, WN, R1OW, S.M. Tree cap = 6-112" Otis t.+ �CT Top of 9-518" Casing Cement CBL 4118114 @ 3,880' MD t't Annulus filled with Nitrogen (Currently bled to 500 psi) Packer/Casing test to 2,000 psi Last Taft: Depth: 6,130' SLM SizelTool: 2.50" Bailer Date: 6125114 Completion Assembly (ran 4121114) Includes: 1 - Gaslift Mandrel, 1,413' MD (dummy valve) 2 - Chem Inj Mandrel, 1,807' MD (inj valve) 60 bands attached to control line 3 - Gaslift Mandrel, 2,799' MD (dummy valve) 4 - Gaslift Mandrel, 4,015' MD (dummy valve) 5 - Gaslift Mandrel, 5,202' MD (dummy valve) 05-28-17 6 - Hydraulic Packer, 5,245' MD (50k shear) 7 - X -Profile, 5,262' MD 8 - X -Nipple, 5,271' MD - Set Plug 05-28-17 9 - WLEG, 5,272' MD Top of 3-1/2" Cut Tubing @ 6,464' MD Top of 3-1/2" Tubing Cement @ 6,476' MD Plug @ 7,550' MD Capped w/ 35' of cement 1 2 3 SCHEMATIC J Conductor 20" K-55 133 ppf Top Bottom MD 0' 106' TVD 0' 106' Surface Casing 13-3/8" J-55 & L-80 68 ppf BTC Top Bottom MD 0' 2,510' TVD 0' 2,509- 16" Hole Cmt w/ 869 sks (384 bbis) of 12.0 ppg, Type 1 cmt . 113 sks (60 bbls) cmt to surface Intermediate Casing 9-518" L-80 40 ppf BTC Top Bottom MD 0' 7,447' TVD 0' 7,057' 12-114" Hole Cmt wl 345 sks (204 bbis) of Class G Lead @ 10.5 ppg & w/ 160 sks (34 bbis) of Class G Tall @ 16.8 ppg. Production Tubing 3-1/2" L-80 9.3 ppf EUE 8RD Top Bottom MD 0' 5,272' TVD 0' 5,043' Perforations: Zone MD TVD Size SPF Date Sterling B45,515'-5,525' 5,249'-5,258' 2-1/2" 12 6127/14 UB C-3 6,424' - 6,431' 6,054'-6,061' 2-1/2" 6 5108/14 UB C-3 6,435'-6,442- 6,065'-6,071' 2-112" 6 5/08/14 Production Tubing (Abandoned) C~ I I I [I r I 3-1/2" L-80 9.3 ppf EUE 8RD Top Bottom TD PBTD MD 6,465' 9,052' TVD 6,093' 8,662' 9,068' MD 9,016' MD 8-1/2" Hole Cmt w/ 807 sks (168 bbis) 8,678' TVD 8,626' TVD Class G @ 15.8 ppg, 100% returns. PosiSet Plug @ t5,500' MD Capped wl 35' of cement PosiSet Plug @ 6,100' MD Capped w/ 10' of cement Set (6123114) Plug @ 6,390' MD Capped w/ 40' of cement Tag top @ 6,204' (5124114) (Plug moved, cement not set) Directional Data: KOP - 2,800' at 3.5 deg/100' build EOB - 4,271', 32.0 deg hole angle Drop - 5,533' @ 2.0 deg/100' Hold - 7,494', 1 deg hole angle to TO Well Name & Number: Beaver Creek Unit #19 Lease: A - 028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA Angle @KOP and Depth: 1.2° 1100 ft @2,800- 1 Angle/Perfs: 1° Maximum Deviation: 32° @ 4,397' Date Completed: 10/07/08 Ground Level (above MSL): 161' RKB (above GL): 21' Revised By: 1 Donna Ambruz Downhole Revision Date: 6/27120141 Schematic Revision Date: 1 6/21/2017 0 o m < A o \ \ ` / WLLJ w g zbg | } En \A\ x \ �� 00 R-0 /\ �0 \ \� $\ \ W/ z% CN \ ~» § \ \ \ a ® § )\ § \ \(§%» j )#w_�� »%e j7» } /s/x / ca m \\ ( 7§ 2 § 2 w o < % { 9 § } § f / » § § k k » §) 2§ § � z [ 0 2 E 2 $ | FR \ §. § ° -!13 �E # # o # o # ¢ a§w¥. o/°a\°,\o § \\/ // /H /« a o� o� o= = u!Hgoi! 0 0 o ;]4§;!r§|,!, o�#o�#o�# I "e§B 2.| 0 0 0 »`f■ ( £ &lol oill / / RUH�.m�.�K co co < Ildrnrp Alu.ke, I.I,t: Beaver Creek BC 419 -Current 09/14/2019 Beaver Creek Tubing hanger, Vetco Gray BC k19 M13-196,13 5/8 SM x 3 K IBT 13 3/8 x 9 S/8 x 3 1/2 susp x 3.725 MCA lift w/ 3" CIW Type H BPV profile, X npt control line exit Tree cap, Otis, 3 1/8 SM FE X 6 % Otis Quick Union Valve, Swab, WKM-M, 3 1/8 SM FE, HWO,O"�4 EE trim IZtt 67 Valve, Master, WKM-M, 3 1/8 SM FE, HWO, EE trim �l Valve, Master, WKM-M, 3 1/8 5M FE, HWO, EE trim Multibowl, Vetco MB -196, 13 5/8 3M stdd bottom X 13 5/8 5M FE top, w/ 2- 2 1/16 5M SSO Void test failed Packoff bad Starting head, Vetco MB -196, 13 5/8 3M X 13 3/8 VG -Loc bottom, w/ 2- 2" LPO Valve, wing, WKM-M, 3 1/8 5M FE, HWO, EE trim Adapter, Vetco, 13 5/8 5M FE X 3 1/8 5M stdd top, prepped f/ 6 Y, hanger neck Valve, VG -200, 2 1/16 SM FE, HWO, AA trim U a a CC h cS Q a O V L7\ a� _ cn 0 m � U L U C � U c U C E w �> a >,.E L •- w � L � O N w -0_0 w > ow L a� a a- c� w C: to m '- o rn N c (D M U) L C U (6 w � L U w 0 N q)0 a a w a 0 c a� ca 3 �U C) (D CD O cQ w E C) w U C 0. w c 'S U L N C , 7 N � a o- Q Q> o C Y O 0 3 c 0 w iu U >, oU EU CD QO 0 L a El N 0) R c m N c O m CL O E m w I— a� N N il a a� m CL w r., CD w O LL w > ca L� U c > C7 0 L L. Q as � N Q 0 2 Qm Q C Q d N Y L m 2 � L c n. M � � � Z Z � m rn c �o t U _ G1 U O a` a� m O w rn M a - 0 L a El N 0) R c m N c O m CL O E m w I— a� N N il a a� m CL w r., CD w O LL TRANSMITTAL LETTER CHECKLIST WELL NAME: PTD: Development — Service _ Exploratory _ Strati graphic Test _Non -Conventional FIELD: ;� env' POOL: 71 Check Box for Appropriate Letter/ Paragraphs to be Included in Transmittal Le CHECK OP ONS Iter TEXT FOR APPROVAL LETTER The permit is for anew wellbore segment of existing well Permit LATERAL No, API No. 50 - (If last two digits in API number Production should continue to be reported as a function of the original are API number stated above. between 60-69 In accordance with 20 AAC 25.005(f), all records, data and logs Pilot Hole acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - _) from records, data and logs acquired for well name on rmit . The permit is approved subject to full compliance with 20 AAC 25.055. Spacing Exception Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (Comuan Name operator p assumes the "abilityof any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first cauSht and 10' sample intervals throw tar et zones. Please note the following special condition of this permit: Non -Conventional production or production testing of coal bed methane is not allowed for (name of well) until after (ComganAame) has designed Well and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AA—L:25—.U71 (a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Comgany Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 da s after com letion, susperasion or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool BEAVER CREEK, TYONEK GAS - 80530 Well Name: BEAVER CK UNIT 19RD Program DEV Well bore seg ❑ PTD#:2191880 Company Hilco%-Alaska LLC Initial Class/Type DEV / PEND GeoArea 820 Unit 50212 On/Off Shore On Annular Disposal ❑ Administration 1 Permit_ fee attached ----- - - --- - - - - - - - - - - - - - - - - - - - - - - - - - - - NA- - - - - -- - - -- - - - - - - - - - - - - - - ---- - - - - 2 Lease number appropriate----------- - - - - - - - - - - - - - - - - - - - Yes - -- --EntirewellinFEDA028083-- - - - - - - - - - - - - - - - - 3 Unique well name and number - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4 Well located in_a_defined pool - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - BEAVE_R_ CREEK, TYONEL GAS POOL - 80530 - governed by -CO 2378 issued_ May -6-.201-65 Well located proper distance from drilling unit -boundary - - - . - - - - - - - - - - - - - - Yes - - - - - - - - Rule 3(a): There shall be no restrictions as to well spacing in the Sterling,_ Beluga, -and Tyonek Gas --- 6- 6 Well located proper distance from other wells- - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - except that no. pay shall be opened in a well within 1,500 feet from the_exterior boundary of the Beaver - - - - 7 Sufficient acreage available in drilling unit- - - - - - - - - - - - - - - _ - . - - - - Yes - - - - - Creek Unit -where -owners and landowners are not the same on both sides of the -line. As planned, well - 8 If deviated, Js -wellbore plat_included - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes conforms to spacing requirements. - _ _ _ - - - - - - - - - - - - - - - - - - - _ - - - _ - - - - - 9 Operator only affected party - - - - - - - - - - - - Yes ------ --------------------------- 10 Operator hasappropriate_bondinforce----- - - - - --- - - - - -- - Yes--- ------------- 11 Permitcanbeissuedwithoutconservationorder- - - - - - - -- - - - - - - - - - - - - - - Yes- - - - - - - - - - - - - - - - - - - - - - - .. - - - - - - - - Appr Date 12 Permit_ can be issued without administrative_approval - - - - - - - - - -- - - - - - - - - - - - - - - Yes_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - .. - - _ _ - _ 13 Can permit be approved before 15 -day wait- - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - ----- SFD 12/12/2019 14 Well located within area and -strata authorized by Injection Order# (put 10# in-comments)_(For_ NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 15 All wells -within -114 mile area of review identified (For service well only)_ - _ _ - _ _ _ - - NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 16 Pre -produced injector duration of pre production less than 3 months -(For service well only) NA_ 17 Nonconven. gas conforms to AS3-1.05 030([.1_.A),(j.2.A-D) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ - - - - - - - - - - _ _ _ _ _ _ - - - - - _ _ _ _ _ - - - - - - 18 Conductor string_provided---------------------------------- - - - - -- NA_ Sidetrack of existing BCU _19_.._mil lwindowin95/8"at_4.500ft -__------ Engineering 19 Surface casing_ protects all -known _USDWs - - - - -- - - - - - - - - - - - - - - -- - - - - - - - - - NA_ .. - . - - - - - - - _ - - - - - --- - - - -------------------------- 20 CMT _ vol adequate _ to circulate -on conductor_ & surf - c s g - - - - - - - - - - - - - - - - - - - - - - - - N A - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - - - . - -- -21 21 CMT_ vol adequate_ to tie-in long string to surf csg----------------------- No - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - . - - - - - 22 CMT -will cover all known productive horizons_ - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - _ _ 5 1/21' casing will be cemented back to 9 5/8" window... will be cement packer._ - - - - - - - - - - - -- - - 23 Casing designs adequate for CJ, B &_permafrost_ - - - - - _ - _ _ _ - - - - - - Yes - - _ _ BTC for 5 1/2"liner_provided - - - - - - - - - - - - - - - - - - - - - - - - - - - 24 Adequate -tankage or reserve pit - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - Hilcorp rig 169 has steel_pits-- - - - - - - - - - . - - - _ - - - 25 Ifa_re-drill, has_a 10-403 for abandonment been approved - - - - - - - - - - - - - - - - - - - - - - Yes - - _ . - - - 319-559 - - - - - - - - - - - - - - - - - - - - - - - - - _ - _ - - - - 26 Adequate wellbore separation proposed - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - No collision issues..._ new well path is southeast of ---------- 27- 27 If_diverter required, does it meet regulations- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ _ _ _ - _ - - Wellhead inplace- - - - - - - - - - _ - - - - - - - - - - - - - - _ - - - - - - - - - Appr Date 28 Drilling fluid program schematic & equip list adequate_ _ _ - - - - Yes - _ _ _ _ _ - Max form pressure =_5301_ psi (8.6_ppg E- - - will drill with - - - 11.0 mud GLS 12/13/2019 29 BOPEs,_do they meet regulation - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - Rig 169 has 5000 psi WP_11"T3 BOPE 2 5/16" kill line outlet_ - - - - - - - - - - - - - - - - - - - - _ - - - - 30 BOPE_press rating appropriate; test to -(put psig in comments)- - - - - - - - - - - - - - - - - - - Yes - - - - - - - MASP= 4189 psi Will test -ROPE -to 4500 psi_ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 31 Choke -manifold complies w/AP1RP-53 (May 84)- - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 32 Work will occur without operation shutdown- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes Sundry -required to perforate well, - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - - - - - - - - - - - - 33 Is presence of H2S gas probable - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - No_ _ - - - - - - H2S not expected. - - - _ _ _ _ - - - - _ - . - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - - _ _ - - - - - - - 34 -Mechanical -condition of wells within AOR verified (For service well only) _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 35 Permit can be issued w/o hydrogen_ sulfide measures- - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - . - . - 1-12S has not been encountered at BCU, - - - - - - - - - - - - - - - - - - - - - - - - - - - ---------------- Geology 36 Data -presented on potential overpressure zones - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - No abnormally geo-pressured strata_ expected: the max. esti mated.pressures and corresponding TVDs - - - - - - - Appr Date 37 Seismic_ analysis_ of shallow gas_zones- - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ _ _ _ _ provided in the geologic prognosis_yield_pressure gradients <0.50 psi/ft.-The planned mud conforms to - SFD 12/12/2019 38 Seabed _condition survey (if off -shore) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA- - - - - - - - mud programs used in -nearby wells._ Plan calls for materials onsite_ sufficient to increase mud - - - - - - - - - - - - - 39Contact name/phone for weekly_ progress reports_ [exploratory only] - - - - - - - - - - - - - - - - - NA_ _ - - - - - - weight to_1-ppg above the_operatoes maximum - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Geologic Engineering Public Cement packer completion... requires CBL and MIT -IA before perforating well. GIs Commissioner: Date: Commissioner: Date Commissioner Date O� > 16 I 1 z 11 -(IG /