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Home My WebLink About225-0011 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Monday, April 28, 2025 5:16 PM To:Scott Warner Subject:RE: [EXTERNAL] RE: HVB-18 AOGCC 10-403 325-181 PTD 225-001 Approved 04-04-25 Hilcorp has approval to add these additional perfs. 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, April 28, 2025 1:52 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: HVB-18 AOGCC 10-403 325-181 PTD 225-001 Approved 04-04-25 Bryan, We are looking to add additional perforations to HVB-18. All of these additional perforations are within the HV Beluga- Tyonek pool and within the top and bottom MD of the original perf table that was approved. Sand Top MD Btm MD Top TVD Btm TVD Interval T3 7029 7049 5856 5876 20 T6 7110 7130 5935 5955 20 T6 7169 7179 5993 6003 10 T6A 7189 7220 6012 6042 31 T6A 7250 7270 6072 6091 20 T7 7305 7319 6125 6139 14 T7 7334 7348 6153 6167 14 T14 7691 7697 6502 6508 6 T15 7707 7727 6517 6537 20 T17 7786 7796 6595 6605 10 T17 7801 7832 6609 6640 31 T17 7832 7852 6640 6659 20 T17 7866 7876 6673 6683 10 T17 7885 7891 6692 6698 6 T26 8146 8160 6947 6961 14 T42 8838 8858 7625 7644 20 2 T43 8966 8980 7750 7764 14 T47 9090 9100 7871 7881 10 T54 9293 9313 8068 8088 20 Thanks, ScoƩ Warner Kenai – OperaƟons Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, April 4, 2025 4:05 PM To: Scott Warner <Scott.Warner@hilcorp.com> Subject: [EXTERNAL] RE: HVB-18 AOGCC 10-403 325-181 PTD 225-001 Approved 04-04-25 Scott, Hilcorp has approval to add these additional perfs under the sundry 325-181. 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: Friday, April 4, 2025 3:51 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: FW: HVB-18 AOGCC 10-403 325-181 PTD 225-001 Approved 04-04-25 Bryan, Hilcorp would like to add a sand below the bottom interval of the already approved perf table. We just cleaned out to the float collar at 10,672’ with coil tubing which accessed this zone we did not think was accessible. The T120 was CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 3 originally tagged as 10,532’ – 10,552’ but that sand was named incorrectly. The new T120 depths are below which were not included in the original perf table and the T125 was added which included part of the old T120 sand but extended the interval from 10,552’ to 10,567’. Sand Top MD Btm MD Top TVD Btm TVD Interval T120 10,507 10,521 9267 9281 14 T125 10,532 10,567 9292 9326 35 Thanks, ScoƩ Warner Kenai – OperaƟons Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: Donna Ambruz <dambruz@hilcorp.com> Sent: Friday, April 4, 2025 8:53 AM To: Scott Warner <Scott.Warner@hilcorp.com> Cc: Noel Nocas <Noel.Nocas@hilcorp.com> Subject: HVB-18 AOGCC 10-403 325-181 PTD 225-001 Approved 04-04-25 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 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, 4 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. David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 04/25/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: Happy Valley B-18 (HV B-18) PTD: 225-001 API: 50-231-20121-00-00 FINAL LWD FORMATION EVALUATION LOGS (03/05/2025 to 03/22/2025) DGR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Folder Contents: Please include current contact information if different from above. 225-001 T40341 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.28 09:07:09 -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: 4/22/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#2025022 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 14B 50133205390200 222057 4/10/2025 AK E-LINE CBL BRU 241-23 50283201910000 223061 4/7/2025 AK E-LINE Perf BRU 241-26 50283201970000 224068 4/12/2025 AK E-LINE CIBP BRU 244-27 50283201850000 222038 4/8/2025 AK E-LINE Perf MPU B-21 50029215350000 186023 4/7/2025 AK E-LINE LDL MPU C-24A 50029230200100 209134 4/6/2025 AK E-LINE CBL MPU J-25 50029232070000 204073 4/5/2025 AK E-LINE JetCut NCIU A-21 50883201990000 224086 4/4/2025 AK E-LINE Perf NCIU A-18 50883201890000 223033 4/5/2025 AK E-LINE Perf PBU Z-235 50029237600000 223055 4/1/2025 READ InjectiojnProfile HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL HVB 18 50231201210000 225001 4/4/2025 YELLOWJACKET SCBL Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40328 T40329 T40330 T40331 T40332 T40333 T40334 T40335 T40336 T40337 T40338 T40339HVB 18 50231201210000 225001 4/4/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.28 08:42:09 -08'00' 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Friday, April 4, 2025 4:05 PM To:Scott Warner Subject:RE: HVB-18 AOGCC 10-403 325-181 PTD 225-001 Approved 04-04-25 Scott, Hilcorp has approval to add these additional perfs under the sundry 325-181. 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: Friday, April 4, 2025 3:51 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: FW: HVB-18 AOGCC 10-403 325-181 PTD 225-001 Approved 04-04-25 Bryan, Hilcorp would like to add a sand below the bottom interval of the already approved perf table. We just cleaned out to the float collar at 10,672’ with coil tubing which accessed this zone we did not think was accessible. The T120 was originally tagged as 10,532’ – 10,552’ but that sand was named incorrectly. The new T120 depths are below which were not included in the original perf table and the T125 was added which included part of the old T120 sand but extended the interval from 10,552’ to 10,567’. Sand Top MD Btm MD Top TVD Btm TVD Interval T120 10,507 10,521 9267 9281 14 T125 10,532 10,567 9292 9326 35 Thanks, ScoƩ Warner Kenai – OperaƟons Engineer 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 Office: (907) 564-4506 Cell: (907) 830-8863 To help protect your priv acy, Microsoft Office prevented automatic download of this picture from the Internet. From: Donna Ambruz <dambruz@hilcorp.com> Sent: Friday, April 4, 2025 8:53 AM To: Scott Warner <Scott.Warner@hilcorp.com> Cc: Noel Nocas <Noel.Nocas@hilcorp.com> Subject: HVB-18 AOGCC 10-403 325-181 PTD 225-001 Approved 04-04-25 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 the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Scott Warner Cc:Rixse, Melvin G (OGC) Subject:RE: HVB-18 (PTD 225-001) SCBL Date:Friday, April 4, 2025 3:58:00 PM Attachments:HVB-18 SCBL LOG FINAL 4-1-25.pdf Scott, Hilcorp has approval to perf the Tyonek perfs that are already approved in the Sundry 325- 181), as shallow as 6895’ MD. Any shallower perforating will need further cement log analysis or possibly remedial cement as the cement quality above 6770’ md is getting progressively more suspect. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Thursday, April 3, 2025 4:29 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: HVB-18 SCBL Bryan, Attached is the cbl for hvb-18. I would like to give you a call in the morning to discuss this further when I am back in the office if you are available. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 Image 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. rvvrn0 c o? c m ;o ? <� N r o m d � � m m m a �O�`< x m 'w 0� a ? o a M o o 00 m m X0 c m Company HILCORP ALASKA LLC. q m� c 0,^� m o m m'�E. a 3 o O 3 Well HVB-18 �' n o N g W m Z m _ 0- m Q N �'^� m Field DEEP CREEK UNIT r r S. a l 3 3 m m m n l n a County KENAI r Q m < ? � m a 2 State ALASKA Q m � o M o 3 o — r O ? 6 r C) Tl O 3 3 c rb m N A A �, M y �: �- — m N N N T 3 p c C M LV = 7 TT N ' n T c T 3 3 cl) M 0 S O 2 2 C o m3 `5>m��mmzzn�a�om0-0 y __ g a 3 N m z D m M < W n O n m co �1 (rn�z#a far DD m c;onc'i nG m� nNi n W �0 N N 0 Z m Z DNti+o0 o 'n -w� ZI n n T O CO m D C r D IM r N o rn > m r v # C 371, D m m m Ln r r _ m CJ d n N /U) pMj = 11TJ1 r o r �o a W o F- D O 3 oCn C G) cox 0 o� o r?tm m g N 3 w V OJ 0 rn O Z (n m N «< Fold Here >>> All interpretations are opinions based on inferences from electrical or other measurements and we cannot and do not guarantee the accuracy or correctness of any interpretation, and we shall not, except in the case of gross or willful negligence on our part, be liable or responsible for any loss, costs, damages, or expenses incurred or sustained by anyone resulting from any interpretation made by any of our officers, agents or employees. These interpretations are also subject to our general terms and conditions set out in our current Price Schedule. Comments THIS LOG WAS CORRELATED TO HALIBURTON LWD LOG DATED 22-MAR-2025 Sensor Offset (ft) Schematic Description Length (ft) O.D. in Weight (Ib CHD-1 4 CCL-27CCL45 (27CCL45-xxxx) 1.00 1.81 1.68 2.75 5.00 10.00 CCL 22.88 r- 1 2 3/4" Tek-Co CCL mum .CENT-2.75Roller 2.83 2.75 35.00 2.75" Roller Centrilizers ITEMP 18.00 WVFSYNC 18.00 BHTEMP 16.09 i Y WVFS8 14.75 DSCBL-27DST40(27DST40-0131) 9.71 2.75 75.00 WVFS7 14.75 2.75' Titan Digital Sector Bond Temp WVFS6 14.75 WVFS5 14.75 WVFS4 14.75 0 WVFS3 14.75 WVFS2 14.75 WVFS1 14.75 WVF3FT 14.00 El S WVF5FT 13.00 LineV WVFCAL 9.67 9.67 GR 1 4.25 CENT-275Roller 2.83 2.75 35.00 2.75" Roller Centrilizers GR-27DGR45 (27DGR45-XXXX) 4.01 2.75 I 25.00 2 3/4" Titan Digital Gamma Ray CENT-2.75Roller 2.83 2.75 I 35.00 2.75' Roller Centrilizers Dataset: 040125 hvb-18.db: field/well/run3/pass5 Total length: 25.02 ft Total weight: 220.00 lb O.D.: 2.75 in IYI[16WJA RIt HVB-18 SCBL FREE PIPE PASS 4-1-25 W&W a T 240 Travel Time (usec) 140 LTEN Amplitude 0 Amp Avg 150 ------------------------------ -18 Casing Collars 2 0 (lb3500 ------------------- 0 (mV) 100 0 - - Amp Max 150 - - - - - - - - - - - - 200 0 Gamma Ray (GAPI) 150 0 ------------------------------ X5 (mV) 20 0 Amp Min 150 0 Line Speed (fUmin) 100 VDL 1 Sector Map 8 (usec) 1200 Calibration Report Database File d:\040125 hvb-18.db Dataset Pathname run3/pass5 Dataset Creation Tue Apr 01 17-45-36 2025 Gamma Ray Calibration Report Serial Number: 27DGR45-XXXX Tool Model: 27DGR45 Performed: Thu Feb 4 12-36-06 2021 Calibrator Value: 1.0 GAPI Background Reading: 0.0 cps Calibrator Reading: 1.0 cps Sensitivity: 5.0000 GAPI/cps Segmented Cement Bond Log Calibration Report Serial Number: 27DST40-0131 Tool Model: 27DST40 Calibration Casing Diameter: 4.500 in Calibration Depth: 747.092 ft Master Calibration, performed Tue Apr 1 16-35-10 2025: Raw (v) Calibrated (mv) Results Zero Cal Zero Cal Gain Offset 3' 0.008 0.568 1.000 81.196 143.311 -0.197 CAL 0.008 0.672 5' 0.008 0.669 1.000 81.196 121.465 -0.011 SUM S 1 0.010 2.139 0.000 100.000 46.976 -0.467 S2 0.010 2273 0.000 100.000 44.194 -0.436 S3 0.010 2.312 0.000 100.000 43.437 -0.435 S4 0.011 2.394 0.000 100.000 41.959 -0.447 S5 0.010 2.416 0.000 100.000 41.571 -0.422 S6 0.010 2.418 0.000 100.000 41.519 -0.413 S7 0.010 2.357 0.000 100.000 42.608 -0.431 S8 0.011 2.315 0.000 100.000 43.394 -0.473 Internal Reference Calibration, performed (Not Performed): Rmei Ail Ail Roca dTc Zero Cal Zero Cal Gain Offset CAL 0.000 0.000 0.008 0.672 1.000 0.000 Air Zero Calibration, performed (Not Performed): Raw (v) Calibrated (v) Results Zero Zero Offset 3' 0.000 0.000 0.000 5' 0.000 0.000 0.000 SUM S 1 0.000 0.000 0.000 S2 0.000 0.000 0.000 S3 0.000 0.000 0.000 S4 0.000 0.000 0.000 S5 0.000 0.000 0.000 S6 0.000 0.000 0.000 S7 0.000 0.000 0.000 S8 0.000 0.000 0.000 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Initial Completion, N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,660'N/A Casing Collapse Structural Conductor 1,410psi Surface 1,086psi Intermediate Production 7,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Warner, 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 C061589, C061590, ADL 384380 225-001 50-231-20121-00-00 Hilcorp Alaska, LLC Proposed Pools: 12.6# / L-80 TVD Burst 3,644' 8,430psi 2,832' Size 120' 3,833' MD See Attached Schematic 2,980psi 4,750psi 120'120' 3,833' April 2, 2025 Tieback 4-1/2" 10,658' Perforation Depth MD (ft): 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Happy Valley B-18CO 553A.001 Same 9,417'4-1/2" 3166 psi 7,047' N/A Length LTP; N/A 3,611' MD/ 2,976' TVD; N/A, N/A 9,417'10,613'9,372' Deep Creek Unit Beluga/Tyonek Gas 16" 9-5/8" See Attached Schematic m n P s 66 t 2 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 9:53 am, Mar 28, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.03.27 16:23:46 - 08'00' Noel Nocas (4361) 325-181 SFD 4/1/2025 Perforate BJM 4/3/25 DSR-4/2/25 Mar 28, 2025 RUSH SFD Perforations shallower than 5700' TVD require separate AOGCC approval. 10-404 Yes, for CTCO only 3/28/25 Bryan McLellan April 2, 2025 CT BOP test to 3500 psi. Submit CBL to AOGCC and obtain approval before perforating. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.04 08:13:17 -08'00'4/4/25 RBDMS JSB 040425 Well Prognosis Well Name: HVB-18 API Number: 50-231-20121-00-00 Current Status: New Drill Well Permit to Drill Number: 225-001 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP: 4097 psi @ 9312’ TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure: 3166 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: .68 psi/ft using 13.0 ppg EMW FIT at the 9-5/8” surface casing shoe Shallowest Allowable Perf TVD: MPSP/(0.68-0.1) = 3166 psi / 0.58 = 5458’ TVD Top of Applicable Gas Pool: 2494’ MD/2111’ TVD (HV Beluga-Tyonek) Well Status: New Drill Initial Completion Brief Well Summary HVB-18 is a new drill, grassroots well targeting the Tyonek and Beluga sands. This objective of this sundry is to clean out the liner with coil tubing/nitrogen and perforate the Bel 33 through T-120. Wellbore Conditions: - Max Inclination – 62.66° at 2,991’ MD - Max DLS °/100’ – 4.88° at 3,741’ MD - Liner is full of ~9.1 ppg 6% KCl mud - Tubing and IA are displaced to 8.4 ppg CIW - T & IA will be pressure tested to 2500 psi Pre-Sundry Work: 1. Review all approved COAs 2. MIRU E-line and pressure control equipment 3. Log well with CBL tool in 3-1/2” liner a. Send results to AOGCC to review prior to perforating 4. RDMO E-line 5. Pressure test tubing to 3500 psi – chart for 30 min Procedure: 1. MIRU Coil Tubing and pressure control equipment 2. PT BOPE to 250 psi low / 3,500 psi high a. Provide AOGCC 24hr notice for BOP test 3. RIH & clean out wellbore to ~10,564’ MD (~8’ above landing collar), displace liner to 8.4 ppg water 4. Reverse out wellbore with nitrogen, trap ~2400 psi on wellbore a. ~92 bbls total wellbore volume 5. RDMO Coil Tubing 6. MIRU E-line and pressure control equipment 7. PT lubricator to 250 psi low / 3,500 psi high 8. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 9. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Well Prognosis Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Sand Top MD Btm MD Top TVD Btm TVD Interval BEL 33 ±4,264' ±4,278' ±3,161' ±3,189' ±14' BEL 34 ±4,341' ±4,361' ±3,244' ±3,262' ±20' BEL 37 ±4,520' ±4,534' ±3,408' ±3,421' ±14' BEL 38 ±4,632' ±4,662' ±3,514' ±3,542' ±30' BEL 38 ±4,745' ±4,765' ±3,622' ±3,642' ±20' BEL 42 ±4,924' ±4,949' ±3,797' ±3,821' ±25' BEL 43 ±4,965' ±4,990' ±3,837' ±3,861' ±25' BEL 46 ±5,132' ±5,152' ±4,000' ±4,020' ±20' BEL 49 ±5,261' ±5,267' ±4,126' ±4,132' ±6' BEL 50 ±5,284' ±5,315' ±4,149' ±4,179' ±31' BEL 51 ±5,325' ±5,350' ±4,189' ±4,213' ±25' BEL 72 ±5,615' ±5,625' ±4,472' ±4,482' ±10' BEL 73 ±5,670' ±5,684' ±4,526' ±4,540' ±14' BEL 73 ±5,703' ±5,713' ±4,559' ±4,568' ±10' Perforations above 5458’ TVD will not be added until a plug is set and/or lower perforations are depleted. Perforations will not be added without further AOGCC approval. T1A ±6,895' ±6,920' ±5,725' ±5,750' ±25' T1A ±6,920' ±6,940' ±5,750' ±5,769' ±20' T5 ±7,091' ±7,097' ±5,916' ±5,922' ±6' T6A ±7,189' ±7,220' ±6,012' ±6,042' ±31' T6A ±7,250' ±7,270' ±6,072' ±6,091' ±20' T7 ±7,305' ±7,319' ±6,125' ±6,139' ±14' T7 ±7,334' ±7,348' ±6,153' ±6,167' ±14' T10 ±7,459' ±7,494' ±6,275' ±6,309' ±35' T17 ±7,801' ±7,832' ±6,609' ±6,640' ±31' T17 ±7,832' ±7,852' ±6,640' ±6,659' ±20' T27 ±8,221' ±8,235' ±7,020' ±7,034' ±14' T28 ±8,285' ±8,305' ±7,083' ±7,102' ±20' T33 ±8,400' ±8,406' ±7,195' ±7,201' ±6' T40 ±8,730' ±8,740' ±7,519' ±7,528' ±10' T47 ±9,100' ±9,110' ±7,881' ±7,890' ±10' T54 ±9,240' ±9,250' ±8,018' ±8,027' ±10' T60 ±9,424' ±9,430' ±8,198' ±8,204' ±6' T70 ±9,698' ±9,729' ±8,468' ±8,499' ±31' T70 ±9,729' ±9,743' ±8,499' ±8,512' ±14' T80 ±9,828' ±9,838' ±8,596' ±8,606' ±10' Perforations shallower than 5700' TVD require separate AOGCC approval. SFD Well Prognosis T99 ±10,091' ±10,111' ±8,855' ±8,875' ±20' T100 ±10,147' ±10,172' ±8,911' ±8,935' ±25' T105 ±10,188' ±10,198' ±8,951' ±8,961' ±10' T120 ±10,532' ±10,552' ±9,292' ±9,312' ±20' a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Pending well production, all perf intervals may not be completed ii. Note: Note: A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. iii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 10. RDMO 11. Turn well over to production & flow test well 12. Test SVS as necessary once well has reached stable flow rates a. Notify state 24 hrs prior to testing within 5 days of stable production Coil Procedure (Contingency) 1. MIRU Coil Tubing, PT BOPE to 250 psi low / 3,500 psi high a. Provide AOGCC 24 hr notice for BOP test 2. PU wash nozzle and/or motor and mill, RIH and cleanout well to below perfs or proposed plug depth 3. PU CT jet nozzle and RIH, unload fluid from wellbore with nitrogen Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Schematic 4. Standard Well Procedure – N2 Operations Updated by DMA 03-26-25 CURRENT SCHEMATIC Deep Creek Unit HVB-18 PTD: 225-001 API: 50-231-20121-00-00 PBTD = 10,613’ / TVD = 9,372’ TD = 10,660’ / TVD = 9,417’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120’ 9-5/8" Surf Csg 47 L-80 DWC/C 8.681” Surf 3,862’ 4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” ±3,662’ 10,540’ 4-1/2" Prod Tieback 12.6 L-80 GBCD 3.958” Surf ±3,662’ 16” 9-5/8” 12-1/4” hole 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 3,862’ 4.875” 6.540” Liner hanger / LTP Assembly 2 3,862’ 4.790” 6.340” Seal Stem OPEN HOLE / CEMENT DETAIL 9-5/8" Est. TOC @ Surface (75% Lead excess) 4-1/2” Est. TOC @ TOL (40% excess) 8-1/2” hole 1/2 OPEN HOLE / CEMENT DETAIL 9-5/8" Est. TOC @ Surface (75% Lead excess) 4-1/2” Est. TOC @ TOL (40% excess) Updated by SRW 03-26-25 PROPOSED Deep Creek Unit HVB-18 PTD: 225-001 API: 50-231-20121-00-00 PBTD = 10,613’ / TVD = 9,372’ TD = 10,660’ / TVD = 9,417’ RKB to GL = 18’ CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven to Set Depth 84 X-56 Weld 15.01” Surf 120’ 9-5/8" Surf Csg 47 L-80 BTC 8.681” Surf 3,833’ 4-1/2" Prod Lnr 12.6 L-80 GBCD 3.958” 3,611’ 10,658’ 4-1/2" Prod Tieback 12.6 L-80 GBCD 3.958” Surf ±3,644’ 16” 9-5/8” 12-1/4” hole 4-1/2” JEWELRY DETAIL No. Depth ID OD Item 1 3,611’ 4.875” 6.540” Liner hanger / LTP Assembly 2 3,644’ 4.790” 6.340” Seal Stem 8-1/2” hole 1/2 PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Date Comment BEL 33 ±4,264' ±4,278' ±3,161' ±3,189' ±14' Proposed TBD BEL 34 ±4,341' ±4,361' ±3,244' ±3,262' ±20' Proposed TBD BEL 37 ±4,520' ±4,534' ±3,408' ±3,421' ±14' Proposed TBD BEL 38 ±4,632' ±4,662' ±3,514' ±3,542' ±30' Proposed TBD BEL 38 ±4,745' ±4,765' ±3,622' ±3,642' ±20' Proposed TBD BEL 42 ±4,924' ±4,949' ±3,797' ±3,821' ±25' Proposed TBD BEL 43 ±4,965' ±4,990' ±3,837' ±3,861' ±25' Proposed TBD BEL 46 ±5,132' ±5,152' ±4,000' ±4,020' ±20' Proposed TBD BEL 49 ±5,261' ±5,267' ±4,126' ±4,132' ±6' Proposed TBD BEL 50 ±5,284' ±5,315' ±4,149' ±4,179' ±31' Proposed TBD BEL 51 ±5,325' ±5,350' ±4,189' ±4,213' ±25' Proposed TBD BEL 72 ±5,615' ±5,625' ±4,472' ±4,482' ±10' Proposed TBD BEL 73 ±5,670' ±5,684' ±4,526' ±4,540' ±14' Proposed TBD BEL 73 ±5,703' ±5,713' ±4,559' ±4,568' ±10' Proposed TBD T1A ±6,895' ±6,920' ±5,725' ±5,750' ±25' Proposed TBD T1A ±6,920' ±6,940' ±5,750' ±5,769' ±20' Proposed TBD T5 ±7,091' ±7,097' ±5,916' ±5,922' ±6' Proposed TBD T6A ±7,189' ±7,220' ±6,012' ±6,042' ±31' Proposed TBD T6A ±7,250' ±7,270' ±6,072' ±6,091' ±20' Proposed TBD T7 ±7,305' ±7,319' ±6,125' ±6,139' ±14' Proposed TBD T7 ±7,334' ±7,348' ±6,153' ±6,167' ±14' Proposed TBD T10 ±7,459' ±7,494' ±6,275' ±6,309' ±35' Proposed TBD T17 ±7,801' ±7,832' ±6,609' ±6,640' ±31' Proposed TBD T17 ±7,832' ±7,852' ±6,640' ±6,659' ±20' Proposed TBD T27 ±8,221' ±8,235' ±7,020' ±7,034' ±14' Proposed TBD T28 ±8,285' ±8,305' ±7,083' ±7,102' ±20' Proposed TBD T33 ±8,400' ±8,406' ±7,195' ±7,201' ±6' Proposed TBD T40 ±8,730' ±8,740' ±7,519' ±7,528' ±10' Proposed TBD T47 ±9,100' ±9,110' ±7,881' ±7,890' ±10' Proposed TBD T54 ±9,240' ±9,250' ±8,018' ±8,027' ±10' Proposed TBD T60 ±9,424' ±9,430' ±8,198' ±8,204' ±6' Proposed TBD T70 ±9,698' ±9,729' ±8,468' ±8,499' ±31' Proposed TBD T70 ±9,729' ±9,743' ±8,499' ±8,512' ±14' Proposed TBD T80 ±9,828' ±9,838' ±8,596' ±8,606' ±10' Proposed TBD T99 ±10,091' ±10,111' ±8,855' ±8,875' ±20' Proposed TBD T100 ±10,147' ±10,172' ±8,911' ±8,935' ±25' Proposed TBD T105 ±10,188' ±10,198' ±8,951' ±8,961' ±10' Proposed TBD T120 ±10,532' ±10,552' ±9,292' ±9,312' ±20' Proposed TBD OPEN HOLE / CEMENT DETAIL 9-5/8" Est. TOC @ Surface (75% Lead and tail excess). 60 bbl 10.5 ppg spacer, 340 bbl 12 ppg lead followed by 55 bbls 15.8 ppg tail cement. 4-1/2” Est. TOC @ TOL . (40% excess) 50 bbl 10.5 ppg spacer followed by 450 bbl 12 ppg lead cement and 37 bbl 15.3 ppg tail cement. STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Scott Warner Cc:Roby, David S (OGC); Dewhurst, Andrew D (OGC); Davies, Stephen F (OGC) Subject:RE: HVB-18 AOGCC 10-403 PTD 225-001 Submitted 03-28-25 - Sundry Application Date:Friday, March 28, 2025 12:20:00 PM Scott, Hilcorp has approval to complete the CBL logging and CT cleanout portions of the sundry application. Condition of approval: 1. CT BOP test to 3500 psi. Provide 24 hrs for AOGCC opportunity to witness test 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: Friday, March 28, 2025 9:23 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: FW: HVB-18 AOGCC 10-403 PTD 225-001 Submitted 03-28-25 - Sundry Application Bryan, I have attached the supporting documents for HVB-18 that have been requested to be included with the initial perf sundry applications. Direction survey Open hole data Daily reports CBL is scheduled to be run within the next week and I will send that as soon as it is available. 3 We plan to have coil on the well to blow dry as early as Tuesday 4/1. Hilcorp is requesting verbal approval to proceed with the coil blowdown operations as laid out in the sundry. Perforations are not planned to begin until ~4/7 most likely but Hilcorp will not proceed with perforations of course until receiving final approval from the AOGCC pending review and CBL submission. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: Donna Ambruz <dambruz@hilcorp.com> Sent: Friday, March 28, 2025 8:30 AM To: aogcc.permitting@alaska.gov Cc: Scott Warner <Scott.Warner@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: HVB-18 AOGCC 10-403 PTD 225-001 Submitted 03-28-25 - Sundry Application Application for Sundry Approvals 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 the individual 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 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 ________HAPPY VALLEY B-18 JBR 04/28/2025 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:0 4-1/2" joint. Test Results TEST DATA Rig Rep:Van Evera/DeshotelOperator:Hilcorp Alaska, LLC Operator Rep:Pedereson/Richardson Rig Owner/Rig No.:Hilcorp 169 PTD#:2250010 DATE:3/13/2025 Type Operation:DRILL Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopSAM250319125230 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 4 MASP: 1571 Sundry No: Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 15 PNo. Valves 1 PManual Chokes 1 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 11"P #1 Rams 1 2-7/8"x5"P #2 Rams 1 Blinds P #3 Rams 1 2-7/8"x5"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 2-1/16"&3-1/P Kill Line Valves 3 2-1/16"P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P1700 200 PSI Attained P21 Full Pressure Attained P91 Blind Switch Covers:PAll stations Bottle precharge P Nitgn Btls# &psi (avg)P4@2525 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P17 #1 Rams P5 #2 Rams P4 #3 Rams P4 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill P1 9 9 9 9999 9 9 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION DIVERTER Test Report for: Reviewed By: P.I. Suprv Comm ________HAPPY VALLEY B-18 JBR 04/28/2025 MISC. INSPECTIONS: GAS DETECTORS: DIVERTER SYSTEM:MUD SYSTEM: P/F P/F P/F Alarm Visual Alarm Visual Time/Pressure Size Number of Failures:0 Remarks:good test TEST DATA Rig Rep:Jon Van EveraOperator:Hilcorp Alaska, LLC Operator Rep:Rance Pederson Contractor/Rig No.:Hilcorp 169 PTD#:2250010 DATE:3/4/2025 Well Class:DEV Inspection No:divAGE250309133527 Inspector Adam Earl Inspector Insp Source Related Insp No: Test Time:1 ACCUMULATOR SYSTEM: Location Gen.:P Housekeeping:P Warning Sign P 24 hr Notice:P Well Sign:P Drlg. Rig.P Misc:NA Methane:P P Hydrogen Sulfide:P P Gas Detectors Misc:0 NA Designed to Avoid Freeze-up?P Remote Operated Diverter?P No Threaded Connections?P Vent line Below Diverter?P Diverter Size:21.25 P Hole Size:12.25 P Vent Line(s) Size:16 P Vent Line(s) Length:109 P Closest Ignition Source:87 P Outlet from Rig Substructure:98 P Vent Line(s) Anchored:P Turns Targeted / Long Radius:NA Divert Valve(s) Full Opening:P Valve(s) Auto & Simultaneous: Annular Closed Time:24 P Knife Valve Open Time:2 P Diverter Misc:0 NA Systems Pressure:P3000 Pressure After Closure:P1525 200 psi Recharge Time:P25 Full Recharge Time:P120 Nitrogen Bottles (Number of):P4 Avg. Pressure:P2525 Accumulator Misc:NA0 P PTrip Tank: P PMud Pits: P PFlow Monitor: 0 NAMud System Misc: 9 9 9 9 3KRWRRI9HQWOLQHDWWDFKHG +LOFRUS'LYHUWHU9HQW/LLQH 1LQLOFKLN.DORWVD37' $2*&&,QVSGLY$*( Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean Mclaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint, Suite 1400 Anchorage, AK, 99503 Re: Deep Creek, Beluga/Tyonek Gas, HVB-18 Hilcorp Alaska, LLC Permit to Drill Number: 225-001 Surface Location: 2290’ FSL, 427’ FEL, Sec. 21, T2S, R13W, SM, AK Bottomhole Location: 87’ FNL, 2018’ FWL, Sec. 22, T2S, R13W, SM, AK Dear Mr. McLaughlin Enclosed is the approved application for the permit to drill the above referenced well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski &RPPLVVLRQHU '$7(')HEUXDU\ Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.14 08:07:12 -09'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 10,540' TVD: 9,286' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 611.5 15. Distance to Nearest Well Open Surface: x-223599 y-2190904 Zone-4 593.5 to Same Pool: 1160' to HVA-10 16. Deviated wells:Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 62 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 120' Surface Surface 120' 120' 12-1/4" 9-5/8" 47# L-80 DWC/C 3,862' Surface Surface 3,862' 2,845' 8-1/2" 4-1/2" 12.6# L-80 GBCD 6,878' 3,662' 2,701' 10,540' 9,286' Tieback 4-1/2" 12.6# L-80 GBCD 3,662' Surface Surface 3,662' 2,701' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 3/9/2025 87' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 Tieback Assy. 7708 Cement Volume MD Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate LengthCasing Size Plugs (measured): (including stage data) Driven L - 1864 ft3 / T - 307 ft3 Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 1571 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 2513 ft3 / T - 205 ft3 2500 2191' FNL, 250' FWL, Sec 22, T2S, R13W, SM, AK 87' FNL, 2018' FWL, Sec 22, T2S, R13W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 2290' FSL, 427' FEL, Sec 21, T2S, R13W, SM, AK C061589, C061590, ADL 384380 HVB-18 Deep Creek Unit Beluga/Tyonek Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. s N ype of W L l R L 1 Class: os N s No s N o D s s sD 84 o : well is p G S S 20 A SS S s Nos No S G s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Samantha Coldiron at 3:04 pm, Jan 08, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.01.08 12:05:40 - 09'00' Sean McLaughlin (4311) 1571 psi -bjm Submit FIT/LOT data within 48 hrs of obtaining data. A.Dewhurst 11FEB25 2/20/2025 50-231-20121-00-00 BJM 2/12/25 2500 psi 225-001 BOP test to 3000 psi. Annular test to 2500 psi. DSR-1/8/25*&: 2/14/2025 2/14/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.14 08:07:26 -09'00' RBDMS JSB 021825 HVB-18 PTD Program Happy Valley Field January 3, 2025 HVB-18 Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Planned Wellbore Schematic........................................................................................................6 7.0 Drilling / Completion Summary...................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications....................................................................8 9.0 R/U and Preparatory Work........................................................................................................10 10.0 N/U 21-1/4” 2M Diverter.............................................................................................................11 11.0 Drill 12-1/4” Hole Section............................................................................................................12 12.0 Run 9-5/8” Surface Casing..........................................................................................................14 13.0 Cement 9-5/8” Surface Casing....................................................................................................16 14.0 BOP N/U and Test........................................................................................................................18 15.0 Drill 8-1/2” Hole Section..............................................................................................................19 16.0 Run 4-1/2” Production Liner......................................................................................................21 17.0 Cement 4-1/2” Production Liner................................................................................................24 18.0 4-1/2” Liner Tieback Polish Run................................................................................................27 19.0 4-1/2” Tieback Run, ND/NU, RDMO.........................................................................................28 20.0 Diverter Schematic ......................................................................................................................29 21.0 BOP Schematic.............................................................................................................................30 22.0 Wellhead Schematic.....................................................................................................................31 23.0 Anticipated Drilling Hazards......................................................................................................32 24.0 Hilcorp Rig 169 Layout...............................................................................................................34 25.0 FIT/LOT Procedure ....................................................................................................................35 26.0 Rig 169 Choke Manifold Schematic...........................................................................................36 27.0 Casing Design Information.........................................................................................................37 28.0 8-1/2” Hole Section MASP..........................................................................................................38 29.0 Spider Plot w/ 660’.......................................................................................................................39 30.0 Surface Plat As-Built...................................................................................................................40 Page 2 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 1.0 Well Summary Well HVB-18 Pad & Old Well Designation Happy Valley B pad – Grassroots Well Planned Completion Type 4-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Tyonek / Lower Beluga Planned Well TD, MD / TVD 10540 MD / 9286’ TVD PBTD, MD / TVD 10440’ MD AFE Number AFE Drilling Days AFE Drilling Amount Maximum Anticipated Pressure (Surface)1571 psi Maximum Anticipated Pressure (Downhole/Reservoir)2500 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 611.5’ Ground Elevation 593.5’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 2.0 Management of Change Information Page 4 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Cond 16”15.01”14.822”-84 X-56 Weld 2980 1410 - Surface 12-1/4”9.625”8.681”8.525”10.625”47 L-80 DWC/C 6870 4750 1086 Prod 8-1/2”4-1/2”3.958”3.833”5.0”12.6#L-80 GBCD 8430 7500 288 ** Liner must overlap surface casing by at least 100’. 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellView. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. Sean McLaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to Sean.McLaughlin@hilcorp.com,and cdinger@hilcorp.com Page 6 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 6.0 Planned Wellbore Schematic Page 7 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 7.0 Drilling / Completion Summary HVB-18 is an S-shaped directional grassroots development well to be drilled from Happy Valley B Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Tyonek and Lower Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~300’ MD. Maximum hole angle will be ~62 deg. and TD of the well will be 10540’ TMD/ 9286’ TVD, ending with 12 deg inclination. Drilling operations are expected to commence approximately March, 2025. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. Surface casing will be run to 3862’ MD / 2845’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a cement evaluation log (CBL/VDL or temperature log for example)maybe runto determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Hilcorp Rig # 169 to wellsite 2. N/U diverter and test. 3. Drill 12-1/4” hole to 3862’ MD. Run and cmt 9-5/8” surface casing. 4. Test casing to 3500 psi. Perform 13.0# FIT 5. ND diverter, N/U & test 11” x 5M BOP to 3000 psi 6. Drill 8-1/2” hole section to 10540’ MD. 7. Run and cmt 4-1/2” production liner. 8. POOH and LDDP. 9. RIH and land 4-1/2” tieback string in liner top. 10. Test IA to 2500; Test tubing to 2500 psi 11. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: Surface hole: GR + Res MWD Production Hole: Triple Combo Page 8 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC 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. x BOPs shall be tested at (2) week intervals during the drilling of HVB-18. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. Page 9 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4”x 21-1/4” x 2M Hydril MSP diverter Function Test Only 8-1/2” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Page 10 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) 9.0 R/U and Preparatory Work 9.1 Set 16” conductor at +/-120’ below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install landing ring on conductor. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.8 Mix mud for 12-1/4” hole section. 9.9 Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes with 5-1/2” liners. Page 11 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 10.0 N/U 21-1/4” 2M Diverter 10.1 N/U 21-1/4” Hydril MSP 2M diverter System. x N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. x N/U 21-1/4” diverter “T”. x Knife gate, 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 10.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x NOTE:Ensure closing time on diverter annular is in line with API RP 64: 2..1.1.Annular element ID 20” or smaller: Less than 30 seconds 2..1.2.Annular element ID greater than 20”: Less than 45 seconds 10.3 Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: x A prohibition on vehicle parking. x A prohibition on ignition sources or running equipment. x A prohibition on staged equipment or materials. x Restriction of traffic to essential foot or vehicle traffic only. 10.4 Set wear bushing in wellhead. 10.5 Estimated Diverter line orientation on Happy Valley Pad: Page 12 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 11.0 Drill 12-1/4” Hole Section 11.1 P/U 8” directional drilling assy: x Ensure BHA components have been inspected previously. x Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. x Ensure TF offset is measured accurately and entered correctly into the MWD software. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Workstring will be 4.5” 16.6# S-135 CDS40 11.2 4-1/2” Workstring & HWDP will come from Hilcorp. 11.3 Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 12-1/4” hole section to 3862’ MD/ 2845’ TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. x Utilize Inlet experience to drill through coal seams efficiently. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ or every couple days unless hole conditions dictate otherwise. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. x TD the hole section in a good shale x Take MWD surveys every stand drilled (60’ intervals). 11.5 12-1/4” hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Page 13 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-3862’8.8 – 9.5 85-150 20 - 40 25 - 45 <10 8.5-9.0 System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G X-TEND II 0.905 bbl 0.5 ppb 12-15 ppb 0.1 ppb (9 pH) as needed as required for weight if required for <12 FL 0.1 ppb 0.02 ppb 11.6 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16” conductor shoe. 11.7 TOH with the drilling assy, handle BHA as appropriate. Page 14 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Parker 9-5/8” casing running equipment. x Ensure 9-5/8” Casing x CDS 40 XO on rig floor and M/U to FOSV. x R/U fill-up line to fill casing while running. x Ensure all casing has been drifted on the location prior to running. x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ float shoe bucked on (thread locked). x (1) Joint with coupling thread locked. x (1) Joint with float collar bucked on pin end & thread locked. x Install (2) centralizers on shoe joint over a stop collar. 10’ from each end. x Install (1) centralizer, mid tube on thread locked joint and on FC joint. x Ensure proper operation of float equipment. 12.5 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install (1) centralizer every other joint to 300’. Do not run any centralizers above 300’ in the event a top out job is needed. x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 15 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Page 16 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls spacer. Test surface cmt lines. 13.5 Pump remaining spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 75% lead and tail open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cement Volume: Page 17 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx Class G 12.5 ppg lead - 2.1 cuft/sk 15.3 ppg tail - 1.23 cuft/sk 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets “sticky”, land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with spud mud. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.12 Do not overdisplace by more than 1 shoe track volume. Total volume in shoe track is 5.8 bbls. x Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. Verified cement calcs. -bjm Page 18 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 13.13 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 13.14 R/D cement equipment. Flush out wellhead with FW. 13.15 Back out and L/D landing joint. Flush out wellhead with FW. 13.16 M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.17 Lay down landing joint and pack-off running tool. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sean.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 14.0 BOP N/U and Test 14.1 ND Diverter line and diverter 14.2 N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test Packoff to 3000 psi. 14.3 N/U 11” x 5M BOP as follows: Page 19 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Land out test plug (if not installed previously). x Test BOP to 250/3000 psi for 5/10 min. x Test VBR’s with 4-1/2” test joint x Test annular to 250/2500 psi for 10/10 min with a 4-1/2” test joint x Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 9.0 ppg 6% KCL PHPA mud system. 14.7 Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. 15.0 Drill 8-1/2” Hole Section 15.1 Pull test plug, run and set wear bushing 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly. 15.5 Ensure TF offset is measured accurately and entered correctly into the MWD software. 15.6 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 15.7 Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 15.8 8-1/2” hole section mud program summary: Page 20 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, Toolpusher office, and mud loggers office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3862’- 10540’9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0–10ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 15.9 TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. x Triple Combo LWD tools required (DEN, POR, RES) 15.10 R/U and test casing to 3500 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst.9-5/8” 47# L-80 burst is 6870 psi / 2 = 3435 psi. 15.11 Drill out shoe track and 20’ of new formation. Page 21 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 13.0 ppg EMW. A 12# ppg FIT with 7 ppg BHP and 9.0 ppg MW will result in a 29 bbl KTV. 15.14 Drill 8-1/2” hole section to 10540’ MD / 9286’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at 400 - 500 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. x Trip back to the 9-5/8” shoe about ½ way through the hole section x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 15.15 At TD; pump sweeps, CBU, and pull a wiper trip back to the 9-5/8” shoe. 15.16 TOH with the drilling assy, standing back drill pipe. 15.17 LD BHA 15.18 RIH to TD, pump sweep, CBU and condition mud for casing run. 15.19 POOH LDDP and BHA 15.20 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 4-1/2” test joint. 16.0 Run 4-1/2” Production Liner 16.1. R/U Parker 4-1/2” casing running equipment. x Ensure 4-1/2” GBCD x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). Page 22 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly 16.4. Continue running 4-1/2” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to the 9-5/8” shoe. Leave the centralizers free floating. 16.5. Continue running 4-1/2” production liner Page 23 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 16.6. Run in hole w/ 4-1/2” liner to the 9-5/8” casing shoe. 16.7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 16.8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 16.9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 16.10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 16.11. Set casing slowly in and out of slips. 16.12. PU 4-1/2” X 9-5/8” liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 16.13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 16.14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 16.15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16.16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 24 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 17.0 Cement 4-1/2” Production Liner 17.1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 17.3. Pump 5 bbls spacer. 17.4. Test surface cmt lines to 4500 psi. 17.5. Pump remaining spacer. 17.6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Estimated Total Cement Volume: Page 25 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx Class G 12.5 ppg lead - 2.1 cuft/sk 15.3 ppg tail - 1.23 cuft/sk 17.7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 17.8. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. 17.9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. Verified cement volumes. -bjm Page 26 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 17.10. Bump the plug and pressure up to up as required to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure).Hold pressure for 3-5 minutes. 17.11. Slack off total liner weight plus 30k to confirm hanger is set. 17.12. Do not overdisplace by more than 1 shoe track. Shoe track volume is 1.2 bbls. 17.13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 17.14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. 17.15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 17.16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17.17. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 17.18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17.19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 17.20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. 17.21. WOC minimum of 12 hours, test casing to 3000 psi and chart for 30 minutes. Ensure to report the following on WellView: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Page 27 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 18.0 4-1/2” Liner Tieback Polish Run 18.1. PU liner tieback polish mill assy and RIH on drillpipe. 18.2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle. 18.3. POOH, and LDDP and polish mill. 18.4. If not completed, test 4-1/2” liner to 2500 psi and chart for 30 minutes Page 28 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 19.0 4-1/2” Tieback Run, ND/NU, RDMO 19.1 PU 4-1/2” tieback assembly and RIH with 4-1/2” 12.6# L-80. Ensure any jewelry is picked up per tally. x No SSSV, CIM, or GLM required. 19.2 No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 19.3 Circulate inhibited completion fluid. 19.4 PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance of seals from no-go. 19.5 Install packoff and test hanger void. 19.6 Test 4-1/2” liner and tieback to 2500 psi and chart for 30 minutes. 19.7 Test 9-5/8” x 4-1/2” annulus to 2500 psi and chart for 30 minutes. 19.8 Install BPV in wellhead 19.9 N/D BOPE 19.10 N/U dry-hole tree and test 19.11 RDMO Hilcorp Rig #169 Page 29 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 20.0 Diverter Schematic Page 30 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 21.0 BOP Schematic Page 31 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 22.0 Wellhead Schematic Page 32 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 23.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP between 25 – 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole-cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of ~50 - ~60 lbs/100ft2 to combat this issue. Maintain low flow rates for the initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help ensure good cement to surface after running the casing, condition the mud to a YP of 25 – 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. 8-1/2” Hole Section: Lost Circulation: Page 33 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. Reservoir Pressure: No abnormal pressures are present in this hole section. Page 34 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 24.0 Hilcorp Rig 169 Layout Page 35 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 25.0 FIT/LOT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at requiredsurface 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 36 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 26.0 Rig 169 Choke Manifold Schematic Page 37 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 27.0 Casing Design Information Page 38 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 28.0 8-1/2” Hole Section MASP Page 39 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 29.0 Spider Plot w/ 660’ Page 40 Rev PTD January 3, 2025 HVB-18 Drilling Procedure PTD xxx-xxx 30.0 Surface Plat As-Built !"##$ $"% && && 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750True Vertical Depth (1500 usft/in)-750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 Vertical Section at 40.00° (1500 usft/in) 9-5/8" x 12-1/4" 4-1/2" x 8-1/2" 500 1 0 0 0 1 5 0 0 20002500300035004 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 1 0 0 0 0 1 0 5 4 0 HVB-18 wp01a End Dir : 2466.67' MD, 2086.28' TVD Start Dir 3º/100' : 3166.67' MD, 2414.91'TVD End Dir : 4833.33' MD, 3704.13' TVD Total Depth : 10540' MD, 9286.1' TVD Sterling A Beluga 1 Beluga 51 Beluga 93 T-1A T-6 T-17 T-91 T-120 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Happy Valley B-18 593.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2190904.56 223599.43 59° 59' 18.8998 N 151° 30' 34.0683 W SURVEY PROGRAM Date: 2024-12-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 1400.00 HVB-18 wp01a (HVB-18)3_Gyro-CT_Drop 1400.00 3863.00 HVB-18 wp01a (HVB-18) 3_MWD+AX+Sag 3863.00 10540.00 HVB-18 wp01a (HVB-18) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1675.50 1064.00 1796.75 Sterling A 2061.50 1450.00 2415.18 Beluga 1 4156.50 3545.00 5295.81 Beluga 51 4957.50 4346.00 6114.70 Beluga 93 5704.50 5093.00 6878.39 T-1A 5956.50 5345.00 7136.02 T-6 6609.50 5998.00 7803.61 T-17 8817.50 8206.00 10060.93 T-91 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Happy Valley B-18, True North Vertical (TVD) Reference:RKB As-Built @ 611.50usft Measured Depth Reference:RKB As-Built @ 611.50usft Calculation Method:Minimum Curvature Project:Deep Creek Unit Site:Happy Valley B Pad Well:Happy Valley B-18 Wellbore:HVB-18 Design:HVB-18 wp01a CASING DETAILS TVD TVDSS MD Size Name 2845.00 2233.50 3862.38 9-5/8 9-5/8" x 12-1/4" 9286.10 8674.60 10540.00 4-1/2 4-1/2" x 8-1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 1º/100' : 300' MD, 300'TVD 3 400.00 1.00 40.00 399.99 0.67 0.56 1.00 40.00 0.87 Start Dir 2º/100' : 400' MD, 399.99'TVD 4 500.00 3.00 40.00 499.93 3.34 2.80 2.00 0.00 4.36 Start Dir 3º/100' : 500' MD, 499.93'TVD 5 2466.67 62.00 40.00 2086.28 777.52 652.42 3.00 0.00 1014.98 End Dir : 2466.67' MD, 2086.28' TVD 6 3166.67 62.00 40.00 2414.91 1250.98 1049.70 0.00 0.00 1633.04 Start Dir 3º/100' : 3166.67' MD, 2414.91'TVD 7 4833.33 12.00 40.00 3704.13 1995.20 1674.17 3.00 180.00 2604.54 End Dir : 4833.33' MD, 3704.13' TVD 8 10540.00 12.00 40.00 9286.10 2904.09 2436.82 0.00 0.00 3791.03 Total Depth : 10540' MD, 9286.1' TVD -200 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 South(-)/North(+) (400 usft/in)-200 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 South(-)/North(+) (400 usft/in)0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 West(-)/East(+) (400 usft/in) 9-5/8" x 12-1/4" 4-1/2" x 8-1/2" 2505 00 75 0 1 0 0 0 1 25 0 15 0 0 1 75 0 20 00 22 50 2 50 0 27 5 0 30 0 0 32 5 0 3 50 0 3 75 0 40 0 0 4 25 0 45 0 0 475 0 5 00 0 52 5 0 5 50 0 5 75 0 60 0 0 6 25 0 65 0 0 6 7 50 7 00 0 72 5 0 7 50 0 77 5 0 80 0 0 8 25 0 8 50 0 8 7 5 0 9 00 0 92 5 0 92 8 6 HVB-18 wp01a End Dir : 2466.67' MD, 2086.28' TVD Start Dir 3º/100' : 3166.67' MD, 2414.91'TVD End Dir : 4833.33' MD, 3704.13' TVD Total Depth : 10540' MD, 9286.1' TVD CASING DETAILS TVD TVDSS MD Size Name 2845.00 2233.50 3862.38 9-5/8 9-5/8" x 12-1/4" 9286.10 8674.60 10540.00 4-1/2 4-1/2" x 8-1/2" Project: Deep Creek Unit Site: Happy Valley B Pad Well: Happy Valley B-18 Wellbore: HVB-18 Plan: HVB-18 wp01a WELL DETAILS: Happy Valley B-18 593.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2190904.56 223599.43 59° 59' 18.8998 N 151° 30' 34.0683 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Happy Valley B-18, True North Vertical (TVD) Reference:RKB As-Built @ 611.50usft Measured Depth Reference:RKB As-Built @ 611.50usft Calculation Method:Minimum Curvature -825 -550 -275 0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 South(-)/North(+) (550 usft/in)-825 -550 -275 0 275 550 825 1100 1375 1650 1925 2200 2475 2750 3025 3300 3575 South(-)/North(+) (550 usft/in)-825 -550 -275 0 275 550 825 1100 1375 1650 1925 2200 2475 2750 West(-)/East(+) (550 usft/in)2505007501 00 012501 5 0 0 1 7 5 0 2 0 00 2 2 502500 2750300032503500375040004250450047505 0 0 0 5250550057506000625065006750700 0725075007 7 5 08 00082508500875090009250 950097501000010202HV #122505 0 0 750 1000 1250 1500 1750 2000 HV #15 2 5 050 0750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 7250 7500 7750 8000 8250 8500 8750 9000 9250 9500 9750 10000 10 11 8 HVB-17 2505 007 5 0 1 0 0 0 1 2 5 0 1500175020002250250027503000325035003750400042504500475050005250550057506000HVB-13A wp03a 2505 007 5 0 1 0 0 0 1 2 5 0 1 5 0 0 1 7 5 0 2 0 0 0 HV #13 2 5 05007501000125 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 025 0 02 7 5 0 3 0 0 0 3 2 503500375040004136HV #16 2 5 0500750100012 5 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 025 0 02 7 5 0 3 0 0 03250 35003750400042504500475050005250550057506000625065006 7 5 0 7000 7250 7500 7750 8000 8250 8500 8750 9000 9250 9500 961 2 HVB-16A 2 5 0500750100012 5 0 1 5 0 0 1 7 5 0 2 0 0 0 2 2 5 025 0 02 7 5 0 3 0 0 03250 350037503910HV #16PB1 250500750100012501 5 0 0175020002008HVB-14 775080008250850087509000925095009691HVA-02 20002250250027503000325035003750400042504500475050005250550057506000625065006583HVA-08 27503000325035003750400042504500475050005250550057506000625065006792HVA #10 5500575060006500675070007250750077508000825085008 7 50 9 0 0 092509441 HVA-11 9-5/8" x 12-1/4" 4-1/2" x 8-1/2" 25050 0 75 0 10 0 0 1 25 0 1 5 0 0 17 5 0 20 00 2 25 0 2 50 0 27 5 0 3 00 0 32 5 0 35 0 0 37 5 0 40 0 0 4 25 0 4 50 0 4 75 0 50 0 0 52 5 0 5 50 0 5 75 0 6 00 0 62 50 65 0 0 67 5 0 7 00 0 7 25 0 7 50 0 77 50 80 0 0 8 25 0 8 50 0 8 75 0 9 0 00 92 5 0 9 28 6 HVB-18 wp01a Project: Deep Creek Unit Site: Happy Valley B Pad Well: Happy Valley B-18 Wellbore: HVB-18 Plan: HVB-18 wp01a WELL DETAILS: Happy Valley B-18 593.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2190904.56 223599.43 59° 59' 18.8998 N 151° 30' 34.0683 W -75 0 75 150 225 South(-)/North(+) (150 usft/in)-75 0 75 150 225 West(-)/East(+) (150 usft/in)2505007501 0 0 01250 1 5 0 0 1 7 5 0 2 0 0 0 HV #12 2505 0 0 750 HV #15 2 5 050 0750 1000 1250 HVB-17 250500 7 5 0 1 0 0 0 HVB-13A wp03a 250500 7 5 0 1 0 0 0 HV #13 2 5 0 5 007 5 0 10001 25 01 5 0 0 1 7 5 0 2 0 0 0 HV #16 2 5 0 5 007 5 0 10001 25 01 5 0 0 1 7 5 0 2 0 0 0HVB-16A 2 5 0 5 007 5 0 10001 25 01 5 0 0 1 7 5 0 2 0 0 0 HV #16PB1 2505007501000125015 0 0175020002008 HVB-1425050 0 75 0 10 0 0 12 5 0 HVB-18 wp01a ' $ & # $ ( ) ( * * +,&$+ -. ! !" ! # !$%&'(!) /*( - (# !$%&'(!) 0 . 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'0 -?! -> "2& "/.& ')*"2" -4( *34 "/.& -/2,-& ')*"2" -456!7! 8 -/2,-& "/%.& ')*"2" -456!7! 8 ' #$%# #$%&$ 9 : ;(*& : <& 3 : : $ & 3 = $#> $* ?& 8 << & : :859:93: ; : 9& 0.00 1.50 3.00 4.50 Separation Factor0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 Measured Depth HVB-17HVB-13A wp03a HV #13 HV #16 HVB-16A HV #16PB1 No-Go Zone - Stop Drilling Collision Avoidance Required Collision Risk Procedures Req. NOERRORS WELL DETAILS:Happy Valley B-18 NAD 1927 (NADCON CONUS)Alaska Zone 04 593.50 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 2190904.56 223599.43 59° 59' 18.8998 N 151° 30' 34.0683 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Happy Valley B-18, True North Vertical (TVD) Reference: RKB As-Built @ 611.50usft Measured Depth Reference:RKB As-Built @ 611.50usft Calculation Method:Minimum Curvature SURVEY PROGRAM Date: 2024-12-26T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 1400.00 HVB-18 wp01a (HVB-18) 3_Gyro-CT_Drop 1400.00 3863.00 HVB-18 wp01a (HVB-18) 3_MWD+AX+Sag 3863.00 10540.00 HVB-18 wp01a (HVB-18) 3_MWD+AX+Sag 0.00 40.00 80.00 120.00 160.00 200.00 Centre to Centre Separation0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 Measured Depth HV #12 HV #15 HVB-17 HVB-13A wp03aHV #13 HV #16 HVB-16A HV #16PB1 HVB-14 GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference 18.00 To 10540.00 Project: Deep Creek Unit Site: Happy Valley B Pad Well: Happy Valley B-18 Wellbore: HVB-18 Plan: HVB-18 wp01a Ladder / S.F. Plots CASING DETAILS TVD TVDSS MD Size Name 2845.00 2233.50 3862.38 9-5/8 9-5/8" x 12-1/4" 9286.10 8674.60 10540.00 4-1/2 4-1/2" x 8-1/2" Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME:______________________________________ PTD:_____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD:__________________________POOL:____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in nogreater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. DCU Happy Valley B-18 DEEP CREEK HV BELUGA/TYONEK GAS 225-001 WELL PERMIT CHECKLIST Company Hilcorp Alaska, LLC Well Name:HAPPY VALLEY B-18 Initial Class/Type DEV / PEND GeoArea 820 Unit 50420 On/Off Shore On Program DEVField & Pool Well bore seg Annular DisposalPTD#:2250010 DEEP CK, HV BELUGA/TYONEK GAS - 160550 NA1 Permit fee attached Yes C061589, C061590, and ADL3843802 Lease number appropriate Yes3 Unique well name and number Yes DEEP CK, HV BELUGA/TYONEK GAS - 160550 - governed by CO 553A, 553A.0014 Well located in a defined pool No5 Well located proper distance from drilling unit boundary NA6 Well located proper distance from other wells Yes7 Sufficient acreage available in drilling unit Yes8 If deviated, is wellbore plat included Yes9 Operator only affected party Yes10 Operator has appropriate bond in force Yes11 Permit can be issued without conservation order Yes12 Permit can be issued without administrative approval Yes13 Can permit be approved before 15-day wait NA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 All wells within 1/4 mile area of review identified (For service well only) NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only) NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) Yes18 Conductor string provided Yes19 Surface casing protects all known USDWs Yes20 CMT vol adequate to circulate on conductor & surf csg Yes21 CMT vol adequate to tie-in long string to surf csg Yes22 CMT will cover all known productive horizons Yes23 Casing designs adequate for C, T, B & permafrost Yes24 Adequate tankage or reserve pit NA25 If a re-drill, has a 10-403 for abandonment been approved Yes26 Adequate wellbore separation proposed Yes27 If diverter required, does it meet regulations Yes28 Drilling fluid program schematic & equip list adequate Yes29 BOPEs, do they meet regulation Yes MPSP = 1571 psi (BOP rated to 5000 psi) (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments) Yes31 Choke manifold complies w/API RP-53 (May 84) Yes32 Work will occur without operation shutdown No33 Is presence of H2S gas probable NA34 Mechanical condition of wells within AOR verified (For service well only) Yes Measures not required. Nearby wells did not encounter H2S gas.35 Permit can be issued w/o hydrogen sulfide measures Yes Anticipating normally pressured (8.47 ppg EMW) to several severely underpressred (1.1 ppg EMW) reservoirs.36 Data presented on potential overpressure zones NA37 Seismic analysis of shallow gas zones NA38 Seabed condition survey (if off-shore) NA39 Contact name/phone for weekly progress reports [exploratory only] Appr ADD Date 2/11/2025 Appr BJM Date 2/13/2025 Appr ADD Date 2/10/2025 Administration Engineering Geology Geologic Commissioner:Date:Engineering Commissioner:Date Public Commissioner Date *&:JLC 2/14/2025