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Home My WebLink About221-086MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, January 16, 2026 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC L-240 PRUDHOE BAY UN ORIN L-240 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 01/16/2026 L-240 50-029-23703-00-00 221-086-0 G SPT 4033 2210860 2600 1236 1247 1237 1235 0 0 0 0 4YRTST P Adam Earl 12/7/2025 MIT-IA tested to cover 4-year but also under evaluation for possible TxIA tested to MAIP 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:PRUDHOE BAY UN ORIN L-240 Inspection Date: Tubing OA Packer Depth 352 2850 2787 2757IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE251209162010 BBL Pumped:3.1 BBL Returned:3 Friday, January 16, 2026 Page 1 of 1            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:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: OPERABLE: Injector L-240 (PTD 221086) Passing AOGCC MIT-IA Date:Wednesday, December 17, 2025 4:48:01 PM From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Wednesday, December 17, 2025 3:58 PM To: PB Wells Integrity <PBWellsIntegrity@hilcorp.com>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: OPERABLE: Injector L-240 (PTD 221086) Passing AOGCC MIT-IA Mr. Wallace, WAG injector L-240 (PTD 221086) extended packing DGLV was run on 12/04 and AOGCC MIT-IA passed on 12/07. IAP has not increased during the monitoring period. The well is now classified as OPERABLE. Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Friday, November 21, 2025 9:03 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov>; Oliver Sternicki <oliver.sternicki@hilcorp.com>; Torin Roschinger <torin.roschinger@hilcorp.com> Subject: UNDER EVALUATION: Injector L-240 (PTD 221086) Slow TxIA Mr. Wallace, WAG injector L-240 (PTD 221086) requires AOGCC witnessed 4 year MIT-IA in December 2025. During pre test surveillance, gas was discovered in the IA. The casing pressure was bled from ~600 psi to ~300 psi and re-pressurization monitoring confirmed ~10 psi / day build up. The well is now classified as UNDER EVALUATION and on a 28 day clock to be resolved. Plan Forward 1. Slickline: Run extended packing DGLV 2. Fullbore: AOGCC MIT-IA 3. Well Integrity: AA or further action as needed Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 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. 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:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: UNDER EVALUATION: Injector L-240 (PTD 221086) Slow TxIA Date:Friday, November 21, 2025 9:22:55 AM Attachments:L-240.docx From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Friday, November 21, 2025 9:03 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; Torin Roschinger <Torin.Roschinger@hilcorp.com> Subject: UNDER EVALUATION: Injector L-240 (PTD 221086) Slow TxIA Mr. Wallace, WAG injector L-240 (PTD 221086) requires AOGCC witnessed 4 year MIT-IA in December 2025. During pre test surveillance, gas was discovered in the IA. The casing pressure was bled from ~600 psi to ~300 psi and re-pressurization monitoring confirmed ~10 psi / day build up. The well is now classified as UNDER EVALUATION and on a 28 day clock to be resolved. Plan Forward 1. Slickline: Run extended packing DGLV 2. Fullbore: AOGCC MIT-IA 3. Well Integrity: AA or further action as needed Please call with any questions or concerns. Ryan Holt Hilcorp Alaska LLC Field Well Integrity / Compliance Ryan.Holt@Hilcorp.com P: (907) 659-5102 M: (907) 232-1005 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/12/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230912 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 18RD 50133205840100 222033 9/6/2023 YELLOW JACKET GPT-PERF BCU 18RD 50133205840100 222033 8/24/2023 YELLOW JACKET PLUG BCU 18RD 50133205840100 222033 8/28/2023 YELLOW JACKET PLUG-PERF BCU 18RD 50133205840100 222033 9/9/2023 YELLOW JACKET PLU-GPT-PERF BCU 18RD 50133205840100 222033 9/4/2023 YELLOW JACKET SCBL BRU 211-35 50283201890000 223050 7/31/2023 AK E-LINE CBL BRU 211-35 50283201890000 223050 8/19/2023 AK E-LINE GPT/Plug/Perf BRU 211-35 50283201890000 223050 8/10/2023 AK E-LINE Perf BRU 212-26 50283201820000 220058 8/20/2023 AK E-LINE GPT IRU 11-06 50283201300000 208184 8/1/2023 AK E-LINE Perf IRU 41-01 50283200880000 192109 9/3/2023 AK E-LINE GPT/Perf KTU 43-6XRD2 50133203280200 205117 9/4/2023 YELLOW JACKET CALIPER KU 42-12 50133206890000 220045 8/31/2023 YELLOW JACKET GPT-PERF KU 42-12 50133206890000 220045 8/20/2023 YELLOW JACKET SCBL MPU E-23 50029225700000 195094 8/18/2023 YELLOW JACKET CBL-PLUG MPU E-23 50029225700000 195094 8/20/2023 YELLOW JACKET PERF Paxton 12 50133207100000 223014 8/20/2023 AK E-LINE GPT/Perf Paxton 12 50133207100000 223014 8/14/2023 AK E-LINE Patch/Perf PBU L-240 50029237030000 221086 8/30/2023 READ IPROF Please include current contact information if different from above. T37983 T37983 T37983 T37983 T37983 T37984 T37984 T37984 T37985 T37986 T37987 T37988 T37989 T37989 T37990 T37990 T37991 T37991 T37992 9/13/2023 PBU L-240 50029237030000 221086 8/30/2023 READ IPROF Kayla Junke Digitally signed by Kayla Junke Date: 2023.09.13 10:28:30 -08'00' DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23703-00-00Well Name/No.PRUDHOE BAY UN ORIN L-240Completion StatusWAGINCompletion Date11/23/2021Permit to Drill2210860OperatorHilcorp North Slope, LLCMD12310TVD4544Current StatusWAGIN2/25/2022UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:PB1: ROP, AGR, EWR MD & TVD... ROP, AGR, EWR, DGR, ADR, ALD, CTN MD & TVD, Cement EvaluationNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleDF12/6/2021140 12310 Electronic Data Set, Filename: PBU L-240 LWD FInal.las36058EDDigital DataDF12/6/2021 Electronic File: PBU L-240 LWD Final MD.cgm36058EDDigital DataDF12/6/2021 Electronic File: PBU L-240 LWD Final TVD.cgm36058EDDigital DataDF12/6/2021 Electronic File: L-240_Definitive Survey Report.pdf36058EDDigital DataDF12/6/2021 Electronic File: L-240_Definitive Survey Report.txt36058EDDigital DataDF12/6/2021 Electronic File: L-240_GIS.txt36058EDDigital DataDF12/6/2021 Electronic File: L-240_Plan.pdf36058EDDigital DataDF12/6/2021 Electronic File: L-240_VSec.pdf36058EDDigital DataDF12/6/2021 Electronic File: PBU L-240 LWD Final MD.emf36058EDDigital DataDF12/6/2021 Electronic File: PBU L-240 LWD Final TVD.emf36058EDDigital DataDF12/6/2021 Electronic File: PBU L-240 LWD Final MD.pdf36058EDDigital DataDF12/6/2021 Electronic File: PBU L-240 LWD Final TVD.pdf36058EDDigital DataDF12/6/2021 Electronic File: PBU L-240 LWD Final MD.tif36058EDDigital DataDF12/6/2021 Electronic File: PBU L-240 LWD Final TVD.tif36058EDDigital Data0 0 2210860 PRUDHOE BAY UN ORIN L-240 LOG HEADERS36058LogLog Header Scans0 0 2210860 PRUDHOE BAY UN ORIN L-240 PB1 LOG HEADERS36059LogLog Header ScansDF12/6/2021140 6252 Electronic Data Set, Filename: PBU L-240 PB1 LWD FInal.las36059EDDigital DataFriday, February 25, 2022AOGCC Page 1 of 4PBU L-240 LWD FInal.lasPB1PBU L-240 PB1LWD FInal.las DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23703-00-00Well Name/No.PRUDHOE BAY UN ORIN L-240Completion StatusWAGINCompletion Date11/23/2021Permit to Drill2210860OperatorHilcorp North Slope, LLCMD12310TVD4544Current StatusWAGIN2/25/2022UICYesDF12/6/2021 Electronic File: PBU L-240 PB1 LWD Final MD.cgm36059EDDigital DataDF12/6/2021 Electronic File: PBU L-240 PB1 LWD Final TVD.cgm36059EDDigital DataDF12/6/2021 Electronic File: L-240 final surveys.xlsx36059EDDigital DataDF12/6/2021 Electronic File: L-240 PB1_Definitive Survey Report.txt36059EDDigital DataDF12/6/2021 Electronic File: L-240 PB1_GIS.txt36059EDDigital DataDF12/6/2021 Electronic File: L-240PB1_Definitive Survey Report.pdf36059EDDigital DataDF12/6/2021 Electronic File: PBU L-240 PB1 LWD Final MD.emf36059EDDigital DataDF12/6/2021 Electronic File: PBU L-240 PB1 LWD Final TVD.emf36059EDDigital DataDF12/6/2021 Electronic File: PBU L-240 PB1 LWD Final MD.pdf36059EDDigital DataDF12/6/2021 Electronic File: PBU L-240 PB1 LWD Final TVD.pdf36059EDDigital DataDF12/6/2021 Electronic File: PBU L-240 PB1 LWD Final MD.tif36059EDDigital DataDF12/6/2021 Electronic File: PBU L-240 PB1 LWD Final TVD.tif36059EDDigital DataDF12/6/2021 Electronic File: EMFView3_1.zip36059EDDigital DataDF12/6/2021 Electronic File: Readme.txt36059EDDigital DataDF12/8/2021819 648 Electronic Data Set, Filename: PBU_L-240_RBT_21NOV21_FreePipe.las36076EDDigital DataDF12/8/20217500 12000 Electronic Data Set, Filename: PBU_L-240_RBT_21NOV21_MainPass.las36076EDDigital DataDF12/8/202112033 11822 Electronic Data Set, Filename: PBU_L-240_RBT_21NOV21_RepeatPass.las36076EDDigital DataDF12/8/2021 Electronic File: PBU_L-240_RBT_21NOV21.pdf36076EDDigital DataDF12/8/2021 Electronic File: PBU_L-240_RBT_21NOV21_FreePipe.dlis36076EDDigital DataDF12/8/2021 Electronic File: PBU_L-240_RBT_21NOV21_img.tiff36076EDDigital DataFriday, February 25, 2022AOGCC Page 2 of 4 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23703-00-00Well Name/No.PRUDHOE BAY UN ORIN L-240Completion StatusWAGINCompletion Date11/23/2021Permit to Drill2210860OperatorHilcorp North Slope, LLCMD12310TVD4544Current StatusWAGIN2/25/2022UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsTotalBoxesSample SetNumberNameIntervalINFORMATION RECEIVEDCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYMud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NADF12/8/2021 Electronic File: PBU_L-240_RBT_21NOV21_MainPass.dlis36076EDDigital DataDF12/8/2021 Electronic File: PBU_L-240_RBT_21NOV21_RepeatPass.dlis36076EDDigital Data0 0 2210860 PRUDHOE BAY UN ORIN L-240 LOG HEADERS36076LogLog Header ScansDF1/3/2022819 648 Electronic Data Set, Filename: PBU_L-240_RBT_21NOV21_FreePipe.las36160EDDigital DataDF1/3/20227500 12000 Electronic Data Set, Filename: PBU_L-240_RBT_21NOV21_MainPass.las36160EDDigital DataDF1/3/202212033 11822 Electronic Data Set, Filename: PBU_L-240_RBT_21NOV21_RepeatPass.las36160EDDigital DataDF1/3/2022 Electronic File: PBU_L-240_RBT_21NOV21.pdf36160EDDigital DataDF1/3/2022 Electronic File: PBU_L-240_RBT_21NOV21_FreePipe.dlis36160EDDigital DataDF1/3/2022 Electronic File: PBU_L-240_RBT_21NOV21_img.tiff36160EDDigital DataDF1/3/2022 Electronic File: PBU_L-240_RBT_21NOV21_MainPass.dlis36160EDDigital DataDF1/3/2022 Electronic File: PBU_L-240_RBT_21NOV21_RepeatPass.dlis36160EDDigital Data0 0 2210860 PRUDHOE BAY UN ORIN L-240 LOG HEADERS36160LogLog Header ScansFriday, February 25, 2022AOGCC Page 3 of 4 DATA SUBMITTAL COMPLIANCE REPORTAPI No.50-029-23703-00-00Well Name/No.PRUDHOE BAY UN ORIN L-240Completion StatusWAGINCompletion Date11/23/2021Permit to Drill2210860OperatorHilcorp North Slope, LLCMD12310TVD4544Current StatusWAGIN2/25/2022UICYesComments:Compliance Reviewed By:Date:COMPLIANCE HISTORYDate CommentsDescriptionCompletion Date:11/23/2021Release Date:10/15/2021Friday, February 25, 2022AOGCC Page 4 of 4M.Guhl2/25/2022 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 12/30/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PBU L-240 (PTD 221-086) Tractor RBL 11/21/2021 Please include current contact information if different from above. Received By: 01/03/2022 37' (6HW By Abby Bell at 9:41 am, Jan 03, 2022 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission To: Jim ReDATE: Tuesday, December 21, 2021 gg � - P.I. Superviso\��r SUBJECT: Mechanical Integrity Tests Hilcorp North Slope, LLC L-240 FROM: Adam Earl PRUDHOE BAY UN ORIN L-240 Petroleum Inspector Sre: Inspector Reviewed By P.I. Supry J NON -CONFIDENTIAL Comm Well Name PRUDHOE BAY UN ORIN L-240 API Well Number 50-029-23703-00-00 Inspector Name: Adam Earl Permit Number: 221-086-0 Inspection Date: 12/9/2021 Insp Num: mitAGE211213170746 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well L-240 Type Inj W ' TVD 4033 Tubing 1943 - 1945 - 1952 1962 PTD 2210860 Type Test sPT Test psi 1500 IA 133 2723 — 2649- 2618- 618-BBL BBLPumped: 2.4 BBL Returned: 2.4 - OA 581 - 915 897 - 888 - Intervalt nNITAL - P/F P ' Notes: Initial MIT IA on new inj. 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&203$66%XLOG(3DJH Chelsea Wright Digitally signed by Chelsea Wright Date: 2021.11.17 10:25:01 -09'00' Benjamin Hand Digitally signed by Benjamin Hand Date: 2021.11.19 08:16:59 -09'00' 'HILQLWLYH6XUYH\5HSRUW 1RYHPEHU +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ / /3% 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS1RUWK6ORSH//& 3UXGKRH%D\ / 'HILQLWLYH6XUYH\5HSRUW :HOO :HOOERUH / /3%6XUYH\&DOFXODWLRQ0HWKRG0LQLPXP&XUYDWXUH /$FWXDO5.%#XVIW 'HVLJQ/3%'DWDEDVH1257+86&$1$'$ 0'5HIHUHQFH/$FWXDO5.%#XVIW 1RUWK5HIHUHQFH :HOO/ 7UXH 0DS6\VWHP *HR'DWXP 3URMHFW 0DS=RQH 6\VWHP'DWXP866WDWH3ODQH([DFWVROXWLRQ 1$'1$'&21&2186 3UXGKRH%D\1RUWK6ORSH81,7('67$7(6 $ODVND=RQH 0HDQ6HD/HYHO 8VLQJ:HOO5HIHUHQFH3RLQW 8VLQJJHRGHWLFVFDOHIDFWRU :HOO :HOO3RVLWLRQ /RQJLWXGH /DWLWXGH (DVWLQJ 1RUWKLQJ XVIW (: 16 3RVLWLRQ8QFHUWDLQW\ XVIW XVIW XVIW*URXQG/HYHO / XVIW XVIW :HOOKHDG(OHYDWLRQXVIW 1 : :HOOERUH 'HFOLQDWLRQ )LHOG6WUHQJWK Q7 6DPSOH'DWH 'LS$QJOH /3% 0RGHO1DPH0DJQHWLFV ,)5 3KDVH9HUVLRQ $XGLW1RWHV 'HVLJQ /3% $&78$/ 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Wright Digitally signed by Chelsea Wright Date: 2021.11.17 10:27:32 -09'00'Benjamin Hand Digitally signed by Benjamin Hand Date: 2021.11.19 08:12:06 -09'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 12/08/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PBU L-240 (PTD 221-086) Tractor Radial Bond Log 11/21/2021 Please include current contact information if different from above. 37' (6HW Received By: 12/09/2021 By Abby Bell at 4:29 pm, Dec 08, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By:Date: Hilcorp North Slope, LLC Date: 12/06/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PBU L-240 + L-240PB1 (PTD 221-086) FINAL LWD FORMATION EVALUATION LOGS (11/02/2021 to 11/14/2021) x AGR, EWR-M5, DGR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer – Main Folders: Subfolders: Please include current contact information if different from above. Received By: 12/06/2021 By Abby Bell at 2:28 pm, Dec 06, 2021 PTD: 2210860 E-Set: 36059 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: Hilcorp North Slope, LLC Date: 12/06/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PBU L-240 + L-240PB1 (PTD 221-086) FINAL LWD FORMATION EVALUATION LOGS (11/02/2021 to 11/14/2021) x AGR, EWR-M5, DGR, ADR, ALD, CTN (2” & 5” MD/TVD Color Logs) x Final Definitive Directional Survey SFTP Transfer – Main Folders: Subfolders: Please include current contact information if different from above. Received By: 12/06/2021 37' (6HW By Abby Bell at 2:28 pm, Dec 06, 2021 STATE OF ALASKA Reviewed By: or, OIL AND GAS CONSERVATION COMMISSION P.I. Supry i Z BOPE Test Report for: PRUDHOE BAY UN ORIN L-240 Comm Contractor/Rig No.: Hilcorp Innovation PTD#: 2210860 DATE: 11/9/2021 Inspector Matt Herrera Insp Source Operator: Hilcorp North Slope, LLC Operator Rep: Barber/Amend Rig Rep: Evans/Sture Inspector Test Type Operation: DRILL Sundry No: Annul Pressures:ar: Valves: MASP: Rams: AnnulInspection No: bopMFH211109143300 Type Test: INIT250/3000 250/3000 250/3000 1572 Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: Upper Kelly 1 P/F Lower Kelly Visual Alarm ( Time/Pressure P/F Location Gen.: P Trip Tank _ P P System Pressure 2975 P " Housekeeping: P Pit Level Indicators P P Pressure After Closure 1550 P " PTD On Location P Flow Indicator P P 200 PSI Attained 23 P Standing Order Posted P Meth Gas Detector P P " Full Pressure Attained 75 P Well Sign P H2S Gas Detector P P Blind Switch Covers: YES P DO. Rig P MS Misc _NA NA Nitgn. Bottles (avg): 6g_2350 P - Hazard Sec. P ACC Misc 0 NA Misc NA FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Upper Kelly 1 P - Lower Kelly 1_ P " Ball Type 2 P " Inside BOP 1 _ P FSV Misc 0 NA BOP STACK: Quantity Size P/F Stripper 0_ Manual Chokes NA Annular Preventer I " 13 5/8" P #1 Rams _1 2 7/8 x 5 1/2 P #2 Rams 1 Blinds P #3 Rams 1 2 7/8 x 5 1/2 P #4 Rams 0 NA #5 Rams 0 _ NA #6 Rams 0 NA Choke Ln. Valves 1 31/8 P - HCR Valves 2 '3 1/8 P " Kill Line Valves 2 31/8 P Check Valve 0 _ NA BOP Misc 0 NA CHOKE MANIFOLD: _ Quantity P/F No. Valves 15 P - Manual Chokes 1 P " Hydraulic Chokes 1 FP CH Misc 0 NA INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves 0 NA Number of Failures: 1 ' Test Results Test Time 5 Remarks: All PVT and Gas Systems Tested Good. Two test joint sizes 4 1/2" and 5" Hydraulic Super choke failed initially was flushed and functioned and retested good. Accumulator Closing Times: Annular 9 Seconds 8 Seconds LP econds CR . CHK/KILL 1 Second Each Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Monty Myers Drilling Manager Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK, 99503 Re: Prudhoe Bay Field, Schrader Bluff Oil Pool, PBU L-240 Hilcorp North Slope, LLC Permit to Drill Number: 221-086 Surface Location: 2336’ FSL, 3887’ FEL, Sec. 34, T12N, R11E, UM Bottomhole Location: 717’ FSL, 768’ FEL, Sec. 21, T12N, R11E, UM Dear Mr. Myers: Enclosed is the approved application for the permit to drill the above referenced well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie Chmielowski Commissioner DATED this ___ day of October, 2021. 15 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.10.15 11:52:27 -08'00' 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 12,443' TVD: 4,626' 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: 8,541' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 72.3' 15. Distance to Nearest Well Open Surface: x-583030 y- 5978055 Zone- 4 45.8' to Same Pool: 1010' 16. Deviated wells: Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 75 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Driven 20" 129.5# X-52 161' Surface Surface 161' 161' 47# L-80 Vam21 2500' Surface Surface 2,500' 1,859' 40# L-80 BTC 3,700' 2,500' 1,859' 6,200' 2,835' Tieback 7" 26# L-80 BTC 6,000' Surface Surface 6,000' 2,782' 8-1/2" 7"x4-1/2" 29#/11.6# L-80 Hyd563/ EzgoHT 6,443' 6,000' 2,782' 12,443' 4,626' 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: Joe Engel Monty Myers Contact Email:jengel@hilcorp.com Drilling Manager Contact Phone:777-8395 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 PBU L-240 Prudhoe Bay Field Schrader Bluff Oil Pool, Orion Development Area Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft): Total Depth TVD (ft): 107205344 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Stg 2 L - 439 sx / T - 268 sx 1572 56' FNL, 1707' FWL, Sec. 28, T12N, R11E, UM, AK 717' FSL, 768' FWL, Sec. 21, T12N, R11E, UM, AK 00-001 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 Hilcorp North Slope, LLC 2336' FSL, 3887' FEL, Sec. 34, T12N, R11E, UM, AK ADL 028239 & 047447 5120 18. Casing Program: Top - Setting Depth - BottomSpecifications 2035 Cement Volume MDSize Plugs (measured): (including stage data) Stg 1 L - 467 sx / T - 395 sx LengthCasing Conductor/Structural Effect. Depth MD (ft): Effect. Depth TVD (ft): Authorized Title: Authorized Signature: Production Liner Intermediate Authorized Name: November 5, 2021 12-1/4" 9-5/8" 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): GL / BF Elevation above MSL (ft): Perforation Depth MD (ft): Uncemented Tieback Lead - 350 sx / Tail - 467 sx oo oo oo oo Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) 10.13.2021 By Samantha Carlisle at 8:25 am, Oct 13, 2021 Digitally signed by Monty M Myers DN: cn=Monty M Myers, c=US, o=Hilcorp Alaska, LLC, ou=Technical Services - AK Drilling, email=mmyers@hilcorp.com Reason: I am approving this document Date: 2021.10.13 06:59:51 -08'00' Monty M Myers SFD 10/13/2021MGR14OCT2021 DSR-10/13/21 Service - WAG 50-029-23703-00-00 BOPE test to 3000 psi. Annular to 2500 psi. CBL to AOGCC before put on injection. 221-086 dts 10/15/2021 10/15/2021Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.10.15 11:44:28 -08'00' 2728L-117L-118L-124L-200L-200L1L-200L2L-211L-211PB1L-212L-212PB2L-218NWEILEEN-1L-240_wp03HILCORP NORTH SLOPEGreater Prudhoe BayAOR MapL-240 Injector (Proposed)FEET07501,500POSTED WELL DATAWell LabelWELL SYMBOLSShut In OilINJ Well (Water Flood)Abandoned InjectorP&A Oil/GasJ&ATemporarily AbandonedInjector LocationREMARKSWell Symbols at top of Schrader OA Sand. BlackDashed Circle = 1320' radius from OA sand in L-240.(OA sand is top proposed sand for injection).By: KREOctober 1, 2021PETRA 10/1/2021 11:51:28 AMSFD 10/13/2021NOTE: Three cement plugs isolate the lower Ugnu and Schrader Bluff intervals in L-211PB1.SFD 10/13/2021NOTE: L-200 and its laterals (L1 and L2) are all cement-isolated. Area of Review PBU L-240iPTDAPIWELL STATUSSchraderSandTop of SB(MD)Top of SB(TVD)Top ofCement(MD)Top ofCement(TVD)ZonalIsolationComments204-001 50-029-23191-00-00 L-200 Suspended OBd 7872 4498 5,800 3,675 OpenWell abandoned with cement plug in intermediatecasing, TOC 5050 MD / 3277 TVD. Lateral in SchraderObd. No risk for out of zone migration of injected fluidsfrom L-240. 204-002 50-029-23191-60-00 L-200L1 Suspended OBb 7435 4381 5,800 3,675 OpenWell abandoned with cement plug in intermediatecasing, TOC 5050 MD / 3277 TVD. Lateral in SchraderObb. No risk for out of zone migration of injected fluidsfrom L-240.204-003 50-029-23191-61-00 L-200L2 Suspended OBa 7331 4336 5,800 3,675 OpenWell abandoned with cement plug in intermediatecasing, TOC 5050 MD / 3277 TVD. Lateral in SchraderOba. No risk for out of zone migration of injected fluidsfrom L-240.Note: L-200A is an approved PTD (221-077) with anticipated spud date of 10/13/2021. This sidetrack will abandon L-200 and its laterals No risk for out of zone migration of injected fluidsfrom L-240. No risk for out of zone migration of injected fluidsfrom L-240. No risk for out of zone migration of injected fluidsfrom L-240. Prudhoe Bay West (PBU) L-240 Drilling Program Version 2 10/12/2021 Table of 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 13-5/8” 5M Diverter System ............................................................................................. 11 11.0 Drill 12-1/4” Hole Section ........................................................................................................ 13 12.0 Run 9-5/8” Surface Casing ...................................................................................................... 16 13.0 Cement 9-5/8” Surface Casing ................................................................................................. 22 14.0 ND Diverter, NU BOPE, & Test .............................................................................................. 27 15.0 Drill 8-1/2” Hole Section .......................................................................................................... 28 16.0 Run & Cement 7” x 4-1/2” Injection Liner ............................................................................. 32 17.0 Run 7” Tieback ........................................................................................................................ 39 18.0 Run Upper Completion/ Post Rig Work ................................................................................. 41 19.0 Innovation Rig Diverter Schematic ......................................................................................... 43 20.0 Innovation Rig BOP Schematic ............................................................................................... 44 21.0 Wellhead Schematic ................................................................................................................. 45 22.0 Days Vs Depth .......................................................................................................................... 46 23.0 Formation Tops & Information............................................................................................... 47 24.0 Anticipated Drilling Hazards .................................................................................................. 49 25.0 Innovation Rig Layout ............................................................................................................. 53 26.0 FIT Procedure .......................................................................................................................... 54 27.0 Innovation Rig Choke Manifold Schematic ............................................................................ 55 28.0 Casing Design ........................................................................................................................... 56 29.0 8-1/2” Hole Section MASP ....................................................................................................... 57 30.0 Spider Plot (NAD 27) (Governmental Sections) ...................................................................... 58 31.0 Surface Plat (As Built) (NAD 27) ............................................................................................. 59 32.0 Offset Wells TVD MW............................................................................................................. 60 Page 2 Prudhoe Bay West L-240 SB Injector Drilling Procedure 1.0 Well Summary Well PBU L-240 Pad Prudhoe Bay L Pad Planned Completion Type 4-1/2” Injection Tubing Target Reservoir(s) Schrader Bluff OA, Oba, OBB, OBd Sand Planned Well TD, MD / TVD 12,443’ MD / 4,625’ TVD PBTD, MD / TVD 12,433’ MD / 4,625’ TVD Surface Location (Governmental) 2336' FSL, 3887' FEL, Sec 34, T12N, R11E, UM, AK Surface Location (NAD 27) X= 583,030.33, Y= 5,978,055.42 Top of Productive Horizon (Governmental)56' FNL, 1707' FWL, Sec 28, T12N, R11E, UM, AK TPH Location (NAD 27) X= 577959, Y=5986168 BHL (Governmental) 717' FSL, 768' FWL, Sec 21, T12N, R11E, UM, AK BHL (NAD 27) X= 577010, Y=5986832 AFE Number 211-00054 AFE Drilling Days 19 AFE Completion Days 3 Maximum Anticipated Pressure (Surface) 1572 psig Maximum Anticipated Pressure (Downhole/Reservoir) 2035 psig Work String 5” 19.5# S-135 NC 50 Innovation KB Elevation above MSL: 26.5 ft + 45.1 ft = 71.6 ft GL Elevation above MSL: 45.1 ft BOP Equipment 13-5/8” x 5M Annular, (3) ea 13-5/8” x 5M Rams f OA, Oba, OBB, OBd Sand Page 3 Prudhoe Bay West L-240 SB Injector Drilling Procedure 2.0 Management of Change Information Page 4 Prudhoe Bay West L-240 SB Injector Drilling Procedure 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 20” 19.25”---X-52Weld 12-1/4”9-5/8” 8.835”8.679”10.625”40 L-80 BTC 5,750 3,090 916 9-5/8” 8.681”8.525”10.625”47 L-80 VAM 21 6,870 4,750 1,086 Tieback 7” 6.276 6.151 7.565 26 L-80 BTC 7,240 5,410 604 8-1/2” 7” 6.276 6.151 7.656 26 L-80 H563 7240 5410 604 4-1/2” 4.0 3.833 5 11.6 L-80 EZGO HTGT 7780 6350 267 Tubing 4-1/2” 3.958 3.833 4.937 12.6 L-80 VAMTOP 8430 7500 288 4.0 Drill Pipe Information: Hole Section OD (in) ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn M/U (Min) M/U (Max) Tension (k-lbs) Surface & Production 5”4.276”3.25” 6.625”19.5 S-135 DS50 36,100 43,100 560klb 5”4.276”3.25” 6.625”19.5 S-135 NC50 30,730 34,136 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery). Page 5 Prudhoe Bay West L-240 SB Injector Drilling Procedure 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WellEz. x Report covers operations from 6am to 6am x Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area – this will not save the data entered, and will navigate to another data entry. x Ensure time entry adds up to 24 hours total. x Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. x Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 5.2 Afternoon Updates x Submit a short operations update each work day to pmazzolini@hilcorp.com, mmyers@hilcorp, nathan.sperry@hilcorp.com, jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.3 Intranet Home Page Morning Update x Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting x Health and Safety: Notify EHS field coordinator. x Environmental: Drilling Environmental Coordinator x Notify Drilling Manager & Drilling Engineer on all incidents x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to mmyers@hilcorp,com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.6 Casing and Cement report x Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel@hilcorp.com and joseph.lastufka@hilcorp.com 5.7 Hilcorp Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 jengel@hilcorp.com Drilling Engineer Nate Sperry 907.777.8450 907.301.8996 nathan.sperry@hilcorp.com Completion Engineer Brian Glasheen 907.564.5277 907.545.1144 Brian.Glasheen@hilcorp.com Completion Engineer Brodie Wages 907.564.5006 713.380.9836 David.wages@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Michael Mayfield 907.564.5097 713.205.0533 mmayfield@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 cajones@hilcorp.com Drilling Tech Joe Lastufka 907.777.8400 907.227.8496 Joseph.Lastufka@hilcorp.com _____________________________________________________________________________________ Revised By: JPE 10/12/2021 PROPOSED SCHEMATIC Prudhoe Bay Unit Well: PBU L-240 Last Completed: TBD PTD: TBD TD =12,443’ (MD) / TD =4,626’ (TVD) 4 20” Orig. KB Elev.: 72.3’ / GL Elev.: 45.8’ 7” 3 9-5/8 ” 1 2 See Sliding Sleeve Detail 7”x 4-1/2” XO @ 11,000’ PBTD =12,443’(MD) / PBTD =4,626’ (TVD) 9-5/8” ‘ES’ Cementer @ ±2,500’ 4-1/2” Shoe @ 12,443’8 5 7 6 6 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 129.5 / X52 / Weld N/A Surface 161’ N/A 9-5/8" Surface 47/ L-80 / Vam21 8.681 Surface 2,500’ 0.0732 9-5/8” Surface 40 / L-80 / BTC 8.835 2,500’ 6,200’ 0.0758 7” Tieback 26 / L-80 / BTC 6.276 Surface 6,000’ 0.0383 7” Liner 26 / L-80 / Hyd563 6.276 6,000 11,000 0.0383 4-1/2” Liner 11.6 / L-80 / Ezgo HT 3.833 11,000’ 12,443’ 0.0143 TUBING DETAIL 4-1/2" Tubing 12.6# / L-80 / VamTop 3.958 Surface 10995 0.0152 OPEN HOLE / CEMENT DETAIL Driven Conductor 12-1/4"Stg 1 – Lead – 467 sx / Tail – 395 sx Stg 2 – Lead – 439 sx / Tail – 268 sx 8-1/2” Lead – 350 sx / Tail – 467 sx WELL INCLINATION DETAIL KOP @ 400’ Max Hole Angle = 75° @ 2,307’ TREE & WELLHEAD Tree Cameron 3 1/8" 5M w/ 4-1/16” 5M Cameron Wing Wellhead FMC 11” 5K x sliplock bottom w/ (2) 2-1/16” 5K outs GENERAL WELL INFO API: TBD Completion Date: TBD JEWELRY DETAIL No. Top MD Item ID 1 ~2,200’ X Nipple 3.813” 2 TBD X Nipple 3.813” 3 ~5995 7” x 9-5/8” Seal Bore 4 ~6000 7” x 4-1/2” Liner Top Packer 5 ~10980 Production Packer 6 ~10990 X Nipple 3.813” 7 ~10995 WLEG – Bottom @ TBD 8 ~12,443’ Shoe 4-1/2” SLIDING SLEEVE DETAIL Sleeve # Est MD Est TVD 1 11136 4140 2 11210 4163 3 11284 4186 4 11358 4210 5 11432 4233 6 11506 4256 7 11580 4279 8 11654 4302 9 11728 4325 10 11802 4349 11 11876 4372 12 11950 4395 Page 7 Prudhoe Bay West L-240 SB Injector Drilling Procedure 7.0 Drilling / Completion Summary PBU L-240 is a grassroots injector planned to be drilled in the Schrader Bluff sand package. L-240 is part of a multi well program targeting the Schrader Bluff sand on PBU L-pad The directional plan is 12-1/4” surface hole and 9-5/8” surface casing set below SV1 and above the Ugnu 4A. An 8-1/2” section will be drilled through the Schrader Bluff sands. A 7” x 4-1/2” injection liner will be run in the open hole section and cemented, and the well will be completed with injection tubing. The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately November 3, 2021, pending rig schedule. Surface casing will be run to 6,200’ MD / 2,835’ TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to one of two locations: Primary: Prudhoe G&I on Pad 4 Secondary: the Milne Point “B” pad G&I facility General sequence of operations: 1. MIRU Innovation Rig to well site 2. N/U & Test 13-5/8” Diverter and 16” diverter line 3. Drill 12-1/4” hole to TD of surface hole section. Run and cement 9-5/8” surface casing 4. N/D diverter, N/U wellhead, NU 13-5/8” 5M BOP & Test 5. Drill 8-1/2” hole to TD 6. Run & cement 7” x 4-1/2” production liner 7. Run 7” tieback 8. Run Upper Completion 9. N/D BOP, N/U Tree, RDMO Reservoir Evaluation Plan: 1. Surface hole: No mud logging. Remote Ops geologist. LWD: GR + Res 2. Production Hole: No mud logging. Remote Ops geologist. LWD: GR + ADR (For geo-steering) a grassroots injector p ” surface casing set below SV1 and above the Ugnu 4A. p An 8-1/2” section will be drilled through the Schrader Bluff sands. g Page 8 Prudhoe Bay West L-240 SB Injector Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. 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 and completion of PBU L-240. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/3,000 psi & subsequent tests of the BOP equipment will be to 250/3,000 psi for 5/5 min (annular to 50% rated WP, 2,500 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 or control fluid flow from the well bore, AOGCC is to be notified and 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”. o Ensure the diverter vent line is at least 75’ away from potential ignition sources x Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. x Casing pressure test criteria in 20 AAC 25.030 (e) Casing and Cementing,“A casing pressure test must be performed if BOPE is to be installed on a casing. The casing must be tested to hold a minimum surface pressure equal to 50 percent of the casing internal yield pressure. The test pressure must show stabilizing pressure and may not decline more than 10 percent within 30 minutes. The results of this test and any subsequent tests of the casing must be recorded as required by 20 AAC 25.070(1)”. AOGCC Regulation Variance Requests: x No variance requests at this time. Page 9 Prudhoe Bay West L-240 SB Injector Drilling Procedure Summary of Innovation BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4”x 13-5/8” 5M CTI Annular BOP w/ 16” diverter line Function Test Only 8-1/2” x 13-5/8” x 5M Control Technology Inc Annular BOP x 13-5/8” x 5M Control Technology Inc Double Gate o Blind ram in btm cavity x Mud cross w/ 3” x 5M side outlets x 13-5/8” x 5M Control Technology Single ram x 3-1/8” x 5M Choke Line x 3-1/8” x 5M Kill line x 3-1/8” x 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3,000 Subsequent Tests: 250/3,000 Primary closing unit: Control Technology Inc. (CTI), 6 station, 3,000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to spud. x 24 hours notice prior to testing BOPs. x 24 hours notice prior to casing running & cement operations. x Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:Victoria.loepp@alaska.gov Mel Rixse / Petroleum Engineer / (O): 907-793-1231 / (C): 907-223-3605 / Email:melvin.rixse@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) Page 10 Prudhoe Bay West L-240 SB Injector Drilling Procedure 9.0 R/U and Preparatory Work 9.1 L-240 will utilize a newly set 20” conductor on L-pad. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4” nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Innovation. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4” surface hole section. Ensure mud temperatures are cool (<80qF). 9.10 Ensure 5” liners in mud pumps. x White Star Quattro 1,300 HP mud pumps are rated at 4,097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 11 Prudhoe Bay West L-240 SB Injector Drilling Procedure 10.0 N/U 13-5/8” 5M Diverter System 10.1 N/U 13-5/8” CTI BOP stack in diverter configuration (Diverter Schematic attached to program). x N/U 20” x 13-5/8” DSA x N/U 13 5/8”, 5M diverter “T”. x NU Knife gate & 16” diverter line. x Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). x Diverter line must be 75 ft from nearest ignition source x Place drip berm at the end of diverter line. x Utilized extensions if needed. 10.2 Notify AOGCC. Function test diverter. x Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. x Ensure that the annular closes in less than 30 seconds (API Standard 64 3rd edition March 2018 section 12.6.2 for packing element ID less than or equal to 20”) 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. 24 hour notice to AOGCC to witness. Page 12 Prudhoe Bay West L-240 SB Injector Drilling Procedure 10.4 Rig & Diverter Orientation: x May change on location Page 13 Prudhoe Bay West L-240 SB Injector Drilling Procedure 11.0 Drill 12-1/4” Hole Section 11.1 P/U 12-1/4” directional drilling assembly: 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 Consider running a UBHO sub for wireline gyro.GWD will be the primary gyro tool. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. x Drill string will be 5” 19.5# S-135. x Run a solid float in the surface hole section. 11.2 Begin drilling out from 20” conductor at reduced flow rates to avoid broaching the conductor. x Consider using a trash bit to clean out conductor to mitigate potential damage from debris in conductor. 11.3 Drill 12-1/4” hole section to section TD, below SV1 and above the Ugnu 4A Sand. Confirm this setting depth with the Geologist and Drilling Engineer while drilling the well. x Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. x Efforts should be made to minimize dog legs in the surface hole. Keep DLS < 6 deg / 100. x Hold a safety meeting with rig crews to discuss: x Conductor broaching ops and mitigation procedures. x Well control procedures and rig evacuation x Flow rates, hole cleaning, mud cooling, etc. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Keep mud as cool as possible to keep from washing out permafrost. x Pump at 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. x There have been ‘directional dead zones’ noted in PBW. Directoinal plan has a build up in DLS from 2 – 4, to allow gradual build. If possible get ahead of build rates while still meeting tangent hold target. x Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen x Slow in/out of slips and while tripping to keep swab and surge pressures low x Ensure shakers are functioning properly. Check for holes in screens on connections. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. x Adjust MW and viscosity as necessary to maintain hole stability,ensure MW is at a 9.5 at base of perm and at TD (pending MW increase due to hydrates). This is to combat hydrates and free gas risk and offset any gas cut MW, based upon offset wells. x Perform gyro surveys until clean MWD surveys are seen. Take MWD surveys every stand drilled. Drill 12-1/4” hole section to section TD, below SV1 and above the Ugnu 4A Sand. Page 14 Prudhoe Bay West L-240 SB Injector Drilling Procedure x Be prepared for gas hydrates. In PBW they have been encountered typically around 1660’ TVD (Base of Perm) to 2740’ TVD (Top Ugnu). Be prepared for hydrates: x Gas Hydrates are present on L PAD x L-206 Encountered high gas hydrates at the base of the permafrost to the top of the Ugnu, with the majority of the hydrates occurring in the SV3 & SV2 Sand x Keep mud temperature as cool as possible, Target 60-70*F x Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold premade mud on trucks ready x Drill through hydrate sands and quickly as possible, do not backream. x Gas hydrates can be identified by the gas detector and a decrease in MW or ECD x Monitor returns for hydrates, checking pressurized & non-pressurized scales x Do not stop to circulate out gas hydrates – this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. x Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. x Take MWD and GWD surveys every stand until magnetic interference cleans up. After MWD surveys show clean magnetics, only take MWD surveys. x Surface Hole AC: x There are no wells with a clearance factor of <1.0 11.4 12-1/4” hole mud program summary: x Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid 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 and TD with 9.5+ ppg. MW for free gas and hydrates based upon offset wells Depth Interval MW (ppg) Surface – Base Permafrost 8.9+ Base Permafrost - TD 9.5+ (For Hydrates/Free Gas based on offset wells) x PVT System: 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. x Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. x Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. Page 15 Prudhoe Bay West L-240 SB Injector Drilling Procedure x Wellbore and mud stability:Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 – 9.0 range with caustic soda. Daily additions of ALDACIDE G / X-CIDE 207 MUST be made to control bacterial action. x Casing Running:Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Section Density Viscosity Plastic Viscosity Yield Point API FL pH Temp Surface 8.8 – 9.8 75-175 20 - 40 25-45 <10 8.5 – 9.0 70 F System Formulation: Gel + FW spud mud Product Concentration Fresh Water soda Ash AQUAGEL caustic soda BARAZAN D+ BAROID 41 PAC-L /DEXTRID LT ALDACIDE G 0.905 bbl 0.5 ppb 15 - 20 ppb 0.1 ppb (8.5 – 9.0 pH) as needed as required for 8.8 – 9.2 ppg if required for <10 FL 0.1 ppb 11.5 At TD; PU 2-3 stands off bottom to avoid washing out the hole at TD, CBU, pump tandem sweeps and drop viscosity. Drop mud temp as low as possible as well. 11.6 RIH to bottom, proceed to BROOH to HWDP x Pump at full drill rate (400-600 gpm), and maximize rotation. x Pull slowly, 5 – 10 ft / minute, adjust as dictated by hole conditions x Monitor well for any signs of packing off or losses. x Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. x If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. x Ensure mud temp is as low as possible when backreaming before and through the SV 2 & 3 11.7 TOOH and LD BHA 11.8 No open hole logging program planned. Page 16 Prudhoe Bay West L-240 SB Injector Drilling Procedure 12.0 Run 9-5/8” Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8” casing running equipment (CRT & Tongs) x Ensure 9-5/8” BTC x NC50, and VAM 21 x NC50 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x R/U of CRT if hole conditions require. x R/U a fill up tool to fill casing while running if the CRT is not used. x Ensure all casing has been drifted to 8.75” on the location prior to running. x Top 2,500’ of casing 47# drift 8.525” 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 120’ shoe track assembly consisting of: 9-5/8” Float Shoe 1 joint – 9-5/8” , 2 Centralizers 10’ from each end w/ stop rings 1 joint –9-5/8” , 1 Centralizer mid joint w/ stop ring 9-5/8” Float Collar w/ Stage Cementer Bypass Baffle ‘Top Hat’ 1 joint –9-5/8” , 1 Centralizer mid joint with stop ring 9-5/8” HES Baffle Adaptor x Ensure bypass baffle is correctly installed on top of float collar. x Ensure proper operation of float equipment while picking up. x Ensure to record S/N’s of all float equipment and stage tool components. This end up. Bypass Baffle Page 17 Prudhoe Bay West L-240 SB Injector Drilling Procedure 12.5 Float equipment and Stage tool equipment drawings: Page 18 Prudhoe Bay West L-240 SB Injector Drilling Procedure 12.6 Continue running 9-5/8” surface casing x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: x 1 centralizer every joint to ~ 1000’ MD from shoe x 1 centralizer every 2 joints to ~2,500’ above shoe (Top of Lowest Ugnu) x Verify depth of lowest Ugnu water sand for isolation with Geologist x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. x Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cement returns to surface. 12.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at least 100’ TVD below the permafrost (~ 2,500’ MD). x Confirm depth of first major hydrates seen (possibly SV3) and position stage tool above if possible, confirm with geo and drilling engineer before adjusting depth and ensure there is enough 1st stage cement available x Install centralizers over couplings on 5 joints below and 5 joints above stage tool. x Do not place tongs on ES cementer, this can cause damaged to the tool. x Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/8” 47# L-80 VAM21 Make-Up Torques: Casing OD Minimum Optimum Maximum 9-5/8”28,400 ft-lbs 31,550 ft-lbs 34,650 ft-lbs 9-5/8” 40# L-80 BTC MUT: Casing OD Minimum Optimum Maximum 9-5/8”29,800 ft-lbs -34,800 ft-lbs Page 19 Prudhoe Bay West L-240 SB Injector Drilling Procedure Page 20 Prudhoe Bay West L-240 SB Injector Drilling Procedure 12.8 Continue running 9-5/8” surface casing Page 21 Prudhoe Bay West L-240 SB Injector Drilling Procedure x Centralizers: 1 centralizer every 3rd joint to 200’ from surface x Fill casing while running using fill up line on rig floor. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 The last 2,500’ of 9-5/8” will be 47#, from 2,500’ to Surface x Ensure drifted to 8.525” 12.10 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.11 Slow in and out of slips. 12.12 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10’ from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.13 Lower casing to setting depth. Confirm measurements. 12.14 Have slips staged in cellar, along with necessary equipment for the operation. 12.15 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 22 Prudhoe Bay West L-240 SB Injector Drilling Procedure 13.0 Cement 9-5/8” Surface Casing 13.1 Hold a pre-job safety meeting over the upcoming cement 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 cementing unit at acceptable rates. x How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. x Which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. x Positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) – HEC rep to witness. Mix and pump cement per below calculations for the 1st stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1st Stage Total Cement Volume: Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 12-1/4" OH x 9-5/8" Casing (6,200'-1,000'-2,500') x 0.0558 bpf x 1.3 195.8 1098.4 Total Lead 195.8 1098.4 467.4 12-1/4" OH x 9-5/8" Casing 1000' x 0.0558 bpf x 1.3 = 72.5 406.7 9-5/8" Shoetrack 120' x 0.0758 bpf = 9.1 51.1 Total Tail 81.6 457.8 394.6Tail Lead Page 23 Prudhoe Bay West L-240 SB Injector Drilling Procedure Cement Slurry Design (1st Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. x Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5” liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: (2,500’ x .0732 bpf) + ((6200-120-2500) x .0758 bpf) = 183 bbl + 271.4 bbl = 454.4 80 bbls of tuned spacer to be placed across the stage tool during displacement to prevent flash setting the cement that is in the annulus after the stage tool is open 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, ±4.5 bbls before consulting with Drilling Engineer. 13.14 If plug is not bumped, consult with Drilling Engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 13.15 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 Lead Slurry Tail Slurry Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 24 Prudhoe Bay West L-240 SB Injector Drilling Procedure cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 13.16 Increase pressure to 3,300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 25 Prudhoe Bay West L-240 SB Injector Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2 nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Try to maintain flow rate through stage tool until 2nd stage is ready. Hold pre-job safety meeting. x Past wells have seen pressure increase while circulating through stage tool after reduced rate 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2 nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2nd Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 20" Cond x 9-5/8" Casing 110' x 0.26 bpf 28.6 160.4 12-1/4" OH x 9-5/8" Casing (2000' - 110) x .0558 x 3 316.4 1775.0 Total Lead 345.0 1935.5 438.9 12-1/4" OH x 9-5/8" Casing (2500 - 2000' x .0558 bpf x 2 55.8 313.0 Total Tail 55.8 313.0 267.6Tail Lead Lead Slurry Tail Slurry System Permafrost L G Density 10.7 lb/gal 15.8 lb/gal Yield 4.41 ft3/sk 1.17 ft3/sk Mixed Water 22.02 gal/sk 5.08 gal/sk Page 26 Prudhoe Bay West L-240 SB Injector Drilling Procedure 13.26 Displacement calculation: 2500’ x 0.0732 bpf = 183 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 Land closing plug on stage collar and pressure up to 1,000 – 1,500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips. 13.30 Make initial cut on 9-5/8” final joint. L/D cut joint. Make final cut on 9-5/8”. Dress off stump. Install 9-5/8” wellhead. If transition nipple is welded on, allow to cool as per schedule. Ensure to report the following on wellez: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to jengel@hilcorp.com and joseph.lastufka@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. Page 27 Prudhoe Bay West L-240 SB Injector Drilling Procedure 14.0 ND Diverter, NU BOPE, & Test 14.1 ND the diverter T, knife gate, diverter line & NU 11” x 13-5/8” 5M casing spool. 14.2 NU 13-5/8” x 5M BOP as follows: x BOP configuration from top down: 13-5/8” x 5M annular / 13-5/8” x 5M double gate / 13- 5/8” x 5M mud cross / 13-5/8” x 5M single gate x Double gate ram should be dressed with 2-7/8” x 5-1/2” VBRs in top cavity,blind ram in bottom cavity. x Single ram can be dressed with 2-7/8” x 5-1/2” VBRs or 5” solid body rams x NU bell nipple, install flowline. x Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). x Install (1) manual valve on choke side of mud cross. Install an HRC outside of the manual valve 14.3 RU MPD RCD and related equipment 14.4 Run 5” BOP test plug 14.5 Test BOP to 250/3,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. x Test with 5” test joint and test VBR’s with 3-1/2” test joint x Confirm test pressures with PTD x Ensure to monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug x Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.6 RD BOP test equipment 14.7 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.8 Mix 9.5 ppg Baradrill-N fluid for production hole. 14.9 Set wearbushing in wellhead. 14.10 If needed, rack back as much 5” DP in derrick as possible to be used while drilling the hole section. 14.11 Ensure 5” liners in mud pumps. 24 hour notice to AOGCC to witness. Page 28 Prudhoe Bay West L-240 SB Injector Drilling Procedure 15.0 Drill 8-1/2” Hole Section 15.1 MU 8-1/2” directional BHA x Motor and Triple Combo x Ensure BHA components have been inspected previously. x Drift and caliper all components before MU. 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 Ensure MWD is RU and operational. x Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. x Drill string will be 5” 19.5# S-135 NC50. x Run a solid float in the production hole section. Schrader Bluff Bit Jetting Guidelines Formation Jetting TFA NB 6 x 14 0.902 OA 6 x 13 0.778 OB 6 x 13 0.778 15.2 TIH w/ 8-1/2” BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 RU and test casing to 2,500 psi / 30 min. Ensure to record volume / pressure (every ¼ bbl) and plot on FIT graph. AOGCC reg is 50% of burst = 5,750 / 2 = ~2,875 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20’ of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12.0 ppg EMW. Chart Test. Ensure test is recorded on same chart as casing test. Document incremental volume pumped (and subsequent pressure) and volume returned. Submit casing test and FIT digital data to AOGCC. Page 29 Prudhoe Bay West L-240 SB Injector Drilling Procedure 15.8 8-1/2” hole section mud program summary: x Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. x Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. x Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning x Run the centrifuge continuously while drilling the production hole, this will help with solids removal. x Dump and dilute as necessary to keep drilled solids to an absolute minimum. x MD Totco 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. System Type:8.9 – 9.5 ppg Baradrill-N drilling fluid Properties: Interval Density PV YP LSYP Total Solids MBT HPH T Hardness Production 8.9-9.5 15-25 - ALAP 15 - 30 4-6 <10% <8 <11.0 <100 System Formulation: Product Concentration Water KCL KOH N-VIS DEXTRID LT BARACARB 5 BARACARB 25 BARACARB 50 BARACOR 700 BARASCAV D X-CIDE 207 0.955 bbl 11 ppb 0.1 ppb 1.0 – 1.5 ppb 5 ppb 4 ppb 4 ppb 2 ppb 1.0 ppb 0.5 ppb 0.015 ppb Page 30 Prudhoe Bay West L-240 SB Injector Drilling Procedure 15.9 Install MPD RCD 15.10 Displace wellbore to 9.5 ppg Baradrill-N drilling fluid 15.11 Begin drilling 8-1/2” hole section, on-bottom staging technique: x Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8K. x Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations x If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to PU off bottom and restart on bottom staging technique. If stick slip continues, consider adding 0.5% lubes 15.14 Drill 8-1/2” hole section to section TD per Geologist and Drilling Engineer. x Flow Rate: 350-550 GPM, target min. AV’s 200 ft/min, 385 GPM x RPM: 120+ x Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. x Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low x Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection x Monitor Torque and Drag with pumps on every 5 stands x Monitor ECD, pump pressure & hookload trends for hole cleaning indication x Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. x Reservior plan is to cross all lobes of the Schrader Bluff sand and TD beneath the OBD. x Limit maximum instantaneous ROP to < 250 FPH. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. x Target ROP is as fast as we can clean the hole without having to backream connections x MPD will be utilized to monitor pressure build up on connections. x 8-1/2” Hole Section A/C: x There are no wells with CF <1.0 15.15 Reference:Halliburton has a procedure for Schrader OH sidetracks based on lessons learned and best practices. Ensure the DD is referencing their procedure. x Patience is key! Getting kicked off too quickly might have been the cause of failed liner runs on past wells. x If a known fault is coming up, put a slight “kick-off ramp” in wellbore ahead of the fault so we have a nice place to low side. x Attempt to lowside in a fast drilling interval where the wellbore is headed up. x Orient TF to low side and dig a trough with high flowrates for the first 30 feet, working string back and forth. Trough for approximately 30 minutes. x Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. Page 31 Prudhoe Bay West L-240 SB Injector Drilling Procedure 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ GPM) and rotation (120+ RPM). Pump tandem sweeps if needed x Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary x If seepage losses are seen while drilling, consider reducing MW at TD to 9.0 ppg minimum 15.17 BROOH with the drilling assembly to the 9-5/8” casing shoe x Circulate at full drill rate (less if losses are seen, 350 GPM minimum). x Rotate at maximum RPM that can be sustained. x Pulling speed 5 – 10 min/stand (slip to slip time, not including connections), adjust as dictated by hole conditions x If backreaming operations are commenced, continue backreaming to the shoe 15.18 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH. 15.19 CBU minimum two times at 9-5/8” shoe and clean casing with high vis sweeps. 15.20 Monitor well for flow/pressure build up with MPD. Increase fluid weight if necessary. x Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise x If necessary, increase MW at shoe for any higher than expected pressure seen x Ensure fluid coming out of hole has passed a PST at the possum belly 15.21 POOH and LD BHA. 15.22 Continue to POOH and stand back BHA if possible. Rabbit DP on TOOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 32 Prudhoe Bay West L-240 SB Injector Drilling Procedure 16.0 Run & Cement 7” x 4-1/2” Injection Liner 16.1 Well control preparedness: In the event of an influx of formation fluids while running the 7” x 4-1/2” liner, the following well control response procedure will be followed: x P/U & M/U the applicable 5” safety joint x 4-1/2” crossover installed on bottom, TIW valve in open position on top, 4-1/2” handling joint above TIW) x -OR- x 7” xo installed on bottom, TIW valve in open position on top, 7” handling joint above TIW x These joints shall be fully M/U and available prior to running the first joint of 4-1/2” liner or 7” liner, respectively x Slack off and with 5” DP across the BOP, shut in ram or annular on 5” DP. Close TIW. x Proceed with well kill operations. 16.2 R/U 4-1/2” liner running equipment. x Ensure 4-1/2” 11.6# EZGO HTGT x DS-50 crossover is on rig floor and M/U to FOSV. x Ensure all casing has been drifted on the deck prior to running. x Be sure to count the total # of joints on the deck 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. 16.3 Run 4-1/2” production liner x Use API Modified or “Best O Life 2000 AG”thread compound. Dope pin end only w/ paint brush. Wipe off excess. x Utilize a collar clamp until weight is sufficient to keep slips set properly. x Run float shoe on bottom x Shoe track will be 120’, for liner cement job x Fill Liner every 10 joints x 4-1/2” Liner will be centralized, 1/jt free floating x Install liner as per the Running Order (From Completion Engineer post TD). o There will be x13 NCS Sliding Sleeves ran on this liner, 3 per Schrader Bluff Sand Lobe Page 33 Prudhoe Bay West L-240 SB Injector Drilling Procedure o o Completion Engineer to provide placement x If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. x Obtain up and down weights of the liner. Record rotating torque at 10 and 20 rpm 4-1/2” 11.6 # EZGO HT Torque OD Minimum Maximum Yield Torque 4-1/2 4,007 ft-lbs 6,144 ft-lbs 11,537 ft-lbs Page 34 Prudhoe Bay West L-240 SB Injector Drilling Procedure Page 35 Prudhoe Bay West L-240 SB Injector Drilling Procedure Page 36 Prudhoe Bay West L-240 SB Injector Drilling Procedure 16.4. After ~1443’ of 4-1/2” Liner, XO to 7” 26# H563 x Ensure there will be enough room for all completion jewelry x Ensure enough space for upper completion packer will be placed within 200’ of first sliding sleeve, as per AOGCC regulation 20 AAC 25.412 (b) x Ensure correct well control safety joint is ready 16.5. RU 7” running equipment and run 7” 26# H563 Liner x ~5000’ total. TOL ~ 6000’ MD x Centralized ½ joints, bowspring centralizers 16.6. Ensure to run enough liner to provide for sufficient overlap inside 9-5/8” casing for upper completion. Ensure hanger/pkr will not be set in a 9-5/8” connection. x L-240 ~ liner top packer depth 6000’ MD. Confirm with Completion Engineer x AOGCC regulations require a minimum 100’ overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Do not place liner hanger/packer across 9-5/8” connection. 16.7. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.8. M/U Baker SLZXP liner top packer to 7” liner. 16.9. Note: PU, SO, ROT and torque of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.10. RIH with liner no faster than 30 ft/min – this is to prevent buckling the liner and drill string and weight transfer to get liner to bottom with minimal rotation. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. x Ensure 5” DP/HWDP has been drifted x There is no inner string planned to be run, as opposed to previous wells. The DP should auto fill. Monitor FL and if filling is required due to losses/surging. 16.11. Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + SO depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 16.12. Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, & 20 RPM. 16.13. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. Page 37 Prudhoe Bay West L-240 SB Injector Drilling Procedure 16.14. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.15. Rig up to pump down the work string with the rig pumps. 16.16. Break circulation. Begin circulating at ~1 BPM and monitor pump pressures. Do not exceed 1,600 psi while circulating.Pusher tool is set at 2,100 psi with 5% shear screws but it should be discussed before exceeding 1,600 psi. Note all losses. Confirm all pressures with Baker 16.17. While circulating, R/U cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 16.18. Fill surface cement lines with water and pressure test. 16.19. Pump remaining 20 bbls 10.5 ppg tuned spacer. 16.20. Drop bottom dart – HEC rep to witness. Mix and pump cement per below calculations for the cement job, confirm actual cement volumes with cementer after TD is reached. 16.21. Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, with top of tail slurry to be the 7” x 4-1/2” xo at ~11,000’ MD and TOC brought to liner hanger. 16.22. Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation and continue with the cement job. Cement Slurry Design: 16.23. Section Calculation Vol (bbl) Vol (ft3) Vol (sks) 9-5/8" Casing x 7" Liner (6,200-6,000') x 0.0282 bpf x 1 5.6 31.4 8.5" OH x 7" Liner (12,443 - 6,200-1443) x .0226 bpf x 1.3 141.0 791.1 Total Lead 146.6 822.5 350.0 8.5" OH x 4-1/2" Liner 1443' x 0.0505 bpf x 1.3 = 94.7 531.3 4-1/2" Shoetrack 120' x 0.0155 bpf = 1.9 10.7 Total Tail 96.6 541.9 467.2LeadTail Lead Slurry Tail Slurry Density 12.0 lb/gal 15.8 lb/gal Yield 2.35 ft3/sk 1.16 ft3/sk Mix Water 13.92 gal/sk 4.98 gal/sk Page 38 Prudhoe Bay West L-240 SB Injector Drilling Procedure 16.23. Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 16.24. Shut down pumps. Drop top dart (down the workstring and pump slowly (1-2 BPM). 16.25. Displace rig rig pumps: x (6000’ x .0177 bpf) + (5000’ x .0383 bpf) + (1323’ x .0155 bpf) = x 106.2 + 191.5 + 20.5 = 318.2 bbl 16.26. Slow pump before the dart lands. Do not allow dart to slam into landing collar 16.27. Continue pressuring up to 2,700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the SZXP liner hanger/packer to ensure the HRDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4,500 psi to release the HRDE running tool. 16.28. Bleed DP pressure to 0 psi. Pick up to expose rotating dog sub and set down 50K without pulling sleeve packoff. Pick back up without pulling sleeve packoff, begin rotating at 10-20 RPM and set down 50K again. 16.29. PU to neutral weight, close BOP and test annulus to 1,500 psi for 10 minutes charted. 16.30. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.31. PU pulling running tool free of the packer and displace with at max rate to wash the liner top. Pump sweeps as needed. Circulate multiple bottoms up to remove any ccement from around the drillpipe. Have black water ready 16.32. POOH. LD and inspect running tools. If setting of liner hanger/packer proceeded as planned, LD DP on the TOOH. Note: Once running tool is LD, swap to the completion AFE. Page 39 Prudhoe Bay West L-240 SB Injector Drilling Procedure 17.0 Run 7” Tieback 17.1 RU and pull wear bushing. Get an accurate measurement of RKB to tubing hanger load shoulder to be used for tie-back space out calculation. Install 7” solid body casing rams in the upper ram cavity. RU testing equipment. PT to 250/3,000 psi with 7” test joint. RD testing equipment. 17.2 RU 7” casing handling equipment. x Ensure XO to DP made up to FOSV and ready on rig floor. x Rig up computer torque monitoring service. x String should stay full while running, RU fill up line and check as appropriate. 17.3 PU 7” tieback seal assembly and set in rotary table. Ensure 7” seal assembly has (4) 1” holes above the first seal. These holes will be used to spot diesel freeze protect in the 9-5/8” x 7” annulus. 17.4 MU first joint of 7” to seal assy. 17.6 Run 7”, 26#, L-80 BTC tieback to position seal assembly two joints above tieback sleeve. Record PU and SO weights. 7”, 26#, L-80, BTC Confirm Torques with casing hand = 17.7 MU 7” to DP crossover. 17.8 MU stand of DP to string, and MU top drive. 17.9 Break circulation at 1 BPM and begin lowering string. 17.10 Note seal assembly entering tieback sleeve with a pressure increase, stop pumping and bleed off pressure. Leave standpipe bleed off valve open. 17.11 Continue lowering string and land out on no-go. Set down 5 – 10K and mark the pipe as “NO- GO DEPTH”. 17.12 PU string & remove unnecessary 7” joints. 17.13 Space out with pups as needed to leave the no-go 1 ft above fully no-go position when the casing hanger is landed. Ensure one full joint is below the casing hanger. Casing OD Torque (Min) Torque (Opt)Torque (Max) 7”13,280 ft-lbs 14,750 ft-lbs 16,230 ft-lbs Page 40 Prudhoe Bay West L-240 SB Injector Drilling Procedure 17.14 PU and MU the 7” casing hanger. 17.15 Ensure circulation is possible through 7” string. 17.16 RU and circulation corrosion inhibited brine in the 9-5/8” x 7” annulus. 17.17 With seals stabbed into tieback sleeve, spot diesel freeze protection from 2,500’ TVD to surface in 9-5/8” x 7” annulus by reverse circulating through the holes in the seal assembly. Ensure annular pressure are limited to prevent collapse of the 7” casing (verify collapse pressure of 7” tieback seal assembly). 17.18 SO and land hanger. Confirm hanger has seated properly in wellhead. Make note of actual weight on hanger on morning report. 17.19 Back out the landing joint. MU packoff running tool and install packoff on bottom of landing joint. Set casing hanger packoff and RILDS. PT void to 3,000 psi for 10 minutes. 17.20 RD casing running tools. 17.21 PT 9-5/8” x 7” annulus to 1,500 psi for 30 minutes charted. 17.22 AOGCC to require cement bond log prior to running upper completion. Page 41 Prudhoe Bay West L-240 SB Injector Drilling Procedure 18.0 Run Upper Completion/ Post Rig Work 18.1 RU to run 4-1/2”, 12.6#, L-80 VAMTOP tubing. x Ensure wear bushing is pulled. x Ensure 4-1/2”, L-80, 13.5#, VAMTOP x XT-39 crossover is on rig floor and M/U to FOSV. x Ensure all tubing has been drifted in the pipe shed prior to running. x Be sure to count the total # of joints in the pipe shed before running. x Keep hole covered while RU casing tools. x Record OD’s, ID’s, lengths, SN’s of all components with vendor & model info. x Monitor displacement from wellbore while RIH. 18.2 PU, MU and RH with the following 4-1/2” GL completion jewelry (tally to be provided by Operations Engineer): x Torque Turn All Connections x Tubing Jewelry to include: x 2x ‘X’ Nipple x 1x Production Packer x 1x X Nipple x 1x WLEG x XXX joints, 4-1/2”, 12.6#, L-80, VAMTOP 18.3 PU and MU the 4-1/2” tubing hanger. Make final splice of any TEC wire used and ensure any unsued control line ports are dummied off. 18.4 Record PU and SO weights before landing hanger. Note PU and SO weights on tally along with band/clamp summary. 18.5 Land the tubing hanger and RILDS. Lay down the landing joint. 18.6 Install 4” HP BPV. ND BOP. Install the plug off tool. 18.7 NU the tubing head adapter and NU the tree. 18.8 PT the tubing hanger void to 500/5,000 psi. PT the tree to 250/5,000 psi. 18.9 Pull the plug off tool and BPV. 18.10 Reverse circulate the well over to corrosion inhibited source water follow by 85 bbls of diesel freeze protect for both tubing and IA to 2,500’ MD. 18.11 Drop the ball & rod and complete loading tubing and hydraulically set the packer as per Halliburton’s setting procedure Page 42 Prudhoe Bay West L-240 SB Injector Drilling Procedure 18.12 Pressure up and test the tubing to 3500 psi for MIT-T with 1000 psi on the IA. Bleed off the tubing to 2000psi. Test the IA to 3500 psi for MIT-IA. Bleed off the tubing and observe DCK shear. Confirm circulation in both directions thru the sheared valve. Record and notate all pressure tests (30 minutes) on chart. 18.13 Bleed both the IA and tubing to 0 psi. 18.14 Rig up jumper from IA to tubing to allow freeze protect to swap. 18.15 Prepare to hand over well to production. Ensure necessary forms filled out and well handed over with valve alignment as per operations personnel. 18.16 RDMO Innovation i. POST RIG WELL WORK 1. CTU a. Pull ball and rod in 4-1/2” production packer Per 20 AAC 25.410 (e) 24 hours notice for state to witness. Page 43 Prudhoe Bay West L-240 SB Injector Drilling Procedure 19.0 Innovation Rig Diverter Schematic Page 44 Prudhoe Bay West L-240 SB Injector Drilling Procedure 20.0 Innovation Rig BOP Schematic Page 45 Prudhoe Bay West L-240 SB Injector Drilling Procedure 21.0 Wellhead Schematic Page 46 Prudhoe Bay West L-240 SB Injector Drilling Procedure 22.0 Days Vs Depth Page 47 Prudhoe Bay West L-240 SB Injector Drilling Procedure 23.0 Formation Tops & Information Gradients = ~ 8.5 ppg EMW SFD 10/13/2021 Page 48 Prudhoe Bay West L-240 SB Injector Drilling Procedure Page 49 Prudhoe Bay West L-240 SB Injector Drilling Procedure 24.0 Anticipated Drilling Hazards 12-1/4” Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates/Free Gas Gas hydrates have been seen on PBU L Pad. They were reported between 1660’ and 2740’ TVD. MW has been chosen based upon successful trouble free penetrations of offset wells. x PBU L-206 (2021) saw gas hydrates from the base of permafrost to top of Ugnu 4, with the highest levels in the SV3 & 2. o Keep mud temperature as cool as possible, Target 60-70*F o Dump and dilute as necessary to maintain temp, utilize cold water on the rig as well as cold premade mud on trucks ready o Drill through hydrate sands and quickly as possible, do not backream. Remember that hydrate gas behaves differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECD’s to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPM’s when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are no known wells with a clearance factory <1.0. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Well Specific A/C: x There are no wells with a clearance factor of <1.0 Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH Page 50 Prudhoe Bay West L-240 SB Injector Drilling Procedure speeds can aggravate fragile shale/coal formations due to the pressure variations between surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion Pool. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 51 Prudhoe Bay West L-240 SB Injector Drilling Procedure 8-1/2” Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 300 gpm Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: Crossing faults, known or unknown, can result in drilling into unstable formations that may impact future drilling and liner runs. Talk with Geologist to ensure all known faults are identified and prepared for accordingly. H2S: Treat every hole section as though it has the potential for H2S. PBU L-pad has a history of H2S on wells in all reservoirs. Below are the most recent H2S values of monitored wells in the Shrader / Orion Pool. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic H2S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 52 Prudhoe Bay West L-240 SB Injector Drilling Procedure Abnormal Pressures and Temperatures: Reservoir pressures are expected to be normal. Utilize MPD to mitigate any abnormal pressure seen. Anti-Collision Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Reference A/C report in directional plan. Well Specific AC: x There are no wells with a CF <1.0 in this hole section Page 53 Prudhoe Bay West L-240 SB Injector Drilling Procedure 25.0 Innovation Rig Layout Page 54 Prudhoe Bay West L-240 SB Injector Drilling Procedure 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 55 Prudhoe Bay West L-240 SB Injector Drilling Procedure 27.0 Innovation Rig Choke Manifold Schematic Page 56 Prudhoe Bay West L-240 SB Injector Drilling Procedure 28.0 Casing Design Page 57 Prudhoe Bay West L-240 SB Injector Drilling Procedure 29.0 8-1/2” Hole Section MASP Page 58 Prudhoe Bay West L-240 SB Injector Drilling Procedure 30.0 Spider Plot (NAD 27) (Governmental Sections) Page 59 Prudhoe Bay West L-240 SB Injector Drilling Procedure 31.0 Surface Plat (As Built) (NAD 27) Page 60 Prudhoe Bay West L-240 SB Injector Drilling Procedure 32.0 Offset Wells TVD MW MD TVD MW MD TVD MW MD TVD MW MD TVD MW 800 791.5 8.9 108 108.0 8.8 1000 998.47 9 1560 1514.07 9.3 1600 1498.3 9.2 2631 2187.4 9.4 3130 2616.42 9.7 3310 2630.56 9.7 3000 2228.4 9.7 4005 2762.5 9.2 4836 3567.24 9.6 4776 3494.73 9.2 3900 2686.6 9.5 6647 3879.0 9.1 6195 4417.2 9.6 6175 4366.7 9.2 5000 3253.8 9.2 8793 4843.0 9.2 7458 5419.14 9.6 7686 5500.14 9.2 6500 4028.8 9.2 7800 4488.0 9.3 Source IADC reports Drilling reports Drilling Reports Drilling reports Comments No daily reports 3130' TD 3310 surf td No MW issues noted on drilling summary report L-117 L-118 Hydrates from 1950' to TD 4005 Hydrates breaking out at bell nipple at 4005 td at 4005, reduced MW from 9.5 to 9.2ppg L-200 L-217 6WDQGDUG3URSRVDO5HSRUW 6HSWHPEHU 3ODQ/ZS +LOFRUS$ODVND//& 3UXGKRH%D\ / 3ODQ/ / -1200-6000600120018002400300036004200480054006000True Vertical Depth (1200 usft/in)0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400Vertical Section at 326.49° (1200 usft/in)L-240 wp01 tgt1L-240 wp01 tgt29 5/8" x 12 1/4"6 5/8" x 8 1/2"500100015002000250030003500400045005000550060006500700075008000850090009500100001050011000115001200012443L-240 wp03Start Dir 3º/100' : 300' MD, 300'TVDStart Dir 4º/100' : 600' MD, 598.77'TVDEnd Dir : 2306.77' MD, 1808.04' TVDStart Dir 3º/100' : 10459.34' MD, 3958.94'TVDStart Dir 2º/100' : 11126.96' MD, 4137.3'TVDEnd Dir : 11294.4' MD, 4186.37' TVDStart Dir 2º/100' : 11780.27' MD, 4342.3'TVDTotal Depth : 12443.43' MD, 4625.6' TVDBPRFSV1Ugnu 4AUgnu LANAOAOBaObbOBdColville SandHilcorp Alaska, LLCCalculation Method:Minimum CurvatureError System:ISCWSAScan Method: Closest Approach 3DError Surface: Ellipsoid SeparationWarning Method: Error RatioWELL DETAILS: Plan: L-24045.80+N/-S +E/-WNorthingEastingLatitudeLongitude0.000.005978055.42 583030.3370° 21' 0.0755 N149° 19' 33.2191 WSURVEY PROGRAMDate: 2021-09-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool26.50 700.00 L-240 wp03 (L-240) 3_Gyro-MWD90+Sag700.00 6200.00 L-240 wp03 (L-240) 3_MWD+IFR2+MS+Sag6200.00 12443.43 L-240 wp03 (L-240) 3_MWD+IFR2+MS+SagFORMATION TOP DETAILSTVDPath TVDssPath MDPath Formation1749.60 1677.30 2125.88 BPRF2557.60 2485.30 5147.83 SV12859.60 2787.30 6292.51 Ugnu 4A3625.60 3553.30 9195.89 Ugnu LA3994.60 3922.30 10593.73 NA4139.60 4067.30 11135.59 OA4194.60 4122.30 11320.03 OBa4241.60 4169.30 11466.49 Obb4342.60 4270.30 11781.20 OBd4555.60 4483.30 12305.93 Colville SandREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-240, True NorthVertical (TVD) Reference:L-240 as-built RKB @ 72.30usftMeasured Depth Reference:L-240 as-built RKB @ 72.30usftCalculation Method: Minimum CurvatureProject:Prudhoe BaySite:LWell:Plan: L-240Wellbore:L-240Design:L-240 wp03CASING DETAILSTVD TVDSS MD SizeName2835.19 2762.89 6200.00 9-5/8 9 5/8" x 12 1/4"4625.60 4553.30 12443.43 6-5/8 6 5/8" x 8 1/2"SECTION DETAILSSec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation1 26.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.002 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 Start Dir 3º/100' : 300' MD, 300'TVD3 600.00 9.00 300.00 598.77 11.76 -20.36 3.00 300.00 21.04 Start Dir 4º/100' : 600' MD, 598.77'TVD4 800.00 17.00 300.00 793.48 34.23 -59.29 4.00 0.00 61.285 2306.77 74.70 330.26 1808.04 852.17 -667.76 4.00 34.03 1079.19 End Dir : 2306.77' MD, 1808.04' TVD6 10459.34 74.70 330.26 3958.94 7679.82 -4569.20 0.00 0.00 8925.93 Start Dir 3º/100' : 10459.34' MD, 3958.94'TVD7 11126.96 74.63 309.48 4137.30 8169.02 -4981.58 3.00 -92.98 9561.49 L-240 wp01 tgt1 Start Dir 2º/100' : 11126.96' MD, 4137.3'TVD8 11294.40 71.28 309.48 4186.37 8270.79 -5105.13 2.00 179.95 9714.55 End Dir : 11294.4' MD, 4186.37' TVD9 11780.27 71.28 309.48 4342.30 8563.39 -5460.29 0.00 0.00 10154.60 L-240 wp01 tgt2 Start Dir 2º/100' : 11780.27' MD, 4342.3'TVD10 12443.43 58.02 309.48 4625.60 8943.61 -5921.81 2.00 180.00 10726.41 Total Depth : 12443.43' MD, 4625.6' TVD -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 South(-)/North(+) (1500 usft/in)-8250 -7500 -6750 -6000 -5250 -4500 -3750 -3000 -2250 -1500 -750 0 750 1500 2250 West(-)/East(+) (1500 usft/in) L-240 wp01 tgt2 L-240 wp01 tgt1 9 5/8" x 12 1/4" 6 5/8" x 8 1/2"10001500 1 7 5 0 2 0 0 0 2 2 5 0 2 5 0 0 2 7 5 0 3 0 0 0 3 2 5 0 3 5 0 0 3 7 5 0 4 0 0 042504626L-240 wp03Start Dir 3º/100' : 300' MD, 300'TVD Start Dir 4º/100' : 600' MD, 598.77'TVD End Dir : 2306.77' MD, 1808.04' TVD Start Dir 3º/100' : 10459.34' MD, 3958.94'TVD Start Dir 2º/100' : 11126.96' MD, 4137.3'TVD End Dir : 11294.4' MD, 4186.37' TVD Start Dir 2º/100' : 11780.27' MD, 4342.3'TVD Total Depth : 12443.43' MD, 4625.6' TVD CASING DETAILS TVD TVDSS MD Size Name 2835.19 2762.89 6200.00 9-5/8 9 5/8" x 12 1/4" 4625.60 4553.30 12443.43 6-5/8 6 5/8" x 8 1/2" Project: Prudhoe Bay Site: L Well: Plan: L-240 Wellbore: L-240 Plan: L-240 wp03 WELL DETAILS: Plan: L-240 45.80 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 5978055.42 583030.33 70° 21' 0.0755 N 149° 19' 33.2191 W REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: L-240, True North Vertical (TVD) Reference: L-240 as-built RKB @ 72.30usft Measured Depth Reference:L-240 as-built RKB @ 72.30usft Calculation Method:Minimum Curvature 3URMHFW &RPSDQ\ /RFDO&RRUGLQDWH5HIHUHQFH 79'5HIHUHQFH 6LWH +LOFRUS$ODVND//& 3UXGKRH%D\ / 6WDQGDUG3URSRVDO5HSRUW :HOO :HOOERUH 3ODQ/ / 6XUYH\&DOFXODWLRQ0HWKRG0LQLPXP&XUYDWXUH 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eparation Factor0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175Measured Depth (650 usft/in)L-211PB1L-211L-123L-111No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: L-240 NAD 1927 (NADCON CONUS)Alaska Zone 0445.80+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005978055.42 583030.3370° 21' 0.0755 N 149° 19' 33.2191 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-240, True NorthVertical (TVD) Reference: L-240 as-built RKB @ 72.30usftMeasured Depth Reference:L-240 as-built RKB @ 72.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2021-09-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 700.00 L-240 wp03 (L-240) 3_Gyro-MWD90+Sag700.00 6200.00 L-240 wp03 (L-240) 3_MWD+IFR2+MS+Sag6200.00 12443.43 L-240 wp03 (L-240) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)0 325 650 975 1300 1625 1950 2275 2600 2925 3250 3575 3900 4225 4550 4875 5200 5525 5850 6175Measured Depth (650 usft/in)L-110L-109L-50L-100NWE1-01L-121L-205L-114L-123L-123PB1L-207 wp05L-116L-111L-220L-51GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 12443.43Project: Prudhoe BaySite: LWell: Plan: L-240Wellbore: L-240Plan: L-240 wp03Ladder / S.F. Plots1 of 2CASING DETAILSTVD TVDSS MD Size Name2835.19 2762.89 6200.00 9-5/8 9 5/8" x 12 1/4"4625.60 4553.30 12443.43 6-5/8 6 5/8" x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eparation Factor6300 6650 7000 7350 7700 8050 8400 8750 9100 9450 9800 10150 10500 10850 11200 11550 11900 12250 12600 12950Measured Depth (700 usft/in)L-206 wp06L-211PB1L-207 wp05L-200L-200L1L-200A wp03L-200L2No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.WELL DETAILS:Plan: L-240 NAD 1927 (NADCON CONUS)Alaska Zone 0445.80+N/-S +E/-W Northing EastingLatitudeLongitude0.000.005978055.42583030.3370° 21' 0.0755 N149° 19' 33.2191 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: L-240, True NorthVertical (TVD) Reference: L-240 as-built RKB @ 72.30usftMeasured Depth Reference:L-240 as-built RKB @ 72.30usftCalculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2021-09-03T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool26.50 700.00 L-240 wp03 (L-240) 3_Gyro-MWD90+Sag700.00 6200.00 L-240 wp03 (L-240) 3_MWD+IFR2+MS+Sag6200.00 12443.43 L-240 wp03 (L-240) 3_MWD+IFR2+MS+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)6300 6650 7000 7350 7700 8050 8400 8750 9100 9450 9800 10150 10500 10850 11200 11550 11900 12250 12600 12950Measured Depth (700 usft/in)GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference26.50 To 12443.43Project: Prudhoe BaySite: LWell: Plan: L-240Wellbore: L-240Plan: L-240 wp03Ladder / S.F. Plots2 of 2CASING DETAILSTVD TVDSS MD Size Name2835.19 2762.89 6200.00 9-5/8 9 5/8" x 12 1/4"4625.60 4553.30 12443.43 6-5/8 6 5/8" x 8 1/2" 1 Guhl, Meredith D (CED) From:Davies, Stephen F (CED) Sent:Thursday, October 14, 2021 4:08 PM To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] PBU L-240 (PTD 221-086) - Question and Notice Please file. Thanks, Steve From: Joseph Engel <jengel@hilcorp.com> Sent: Thursday, October 14, 2021 4:01 PM To: Davies, Stephen F (CED) <steve.davies@alaska.gov>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Cc: Carlisle, Samantha J (CED) <samantha.carlisle@alaska.gov>; Guhl, Meredith D (CED) <meredith.guhl@alaska.gov>; Boyer, David L (CED) <david.boyer2@alaska.gov>; Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] PBU L‐240 (PTD 221‐086) ‐ Question and Notice Thank you, Steve. We will update our records. L‐240 will not be pre‐produced. Joe Engel | Drilling Engineer | Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 | Anchorage | AK | 99503 Office: 907.777.8395 | Cell: 805.235.6265 From: Davies, Stephen F (CED) <steve.davies@alaska.gov> Sent: Thursday, October 14, 2021 1:59 PM To: Joseph Engel <jengel@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com> Cc: Carlisle, Samantha J (CED) <samantha.carlisle@alaska.gov>; Guhl, Meredith D (CED) <meredith.guhl@alaska.gov>; Boyer, David L (CED) <david.boyer2@alaska.gov>; Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Subject: [EXTERNAL] PBU L‐240 (PTD 221‐086) ‐ Question and Notice Joe and Joe: I may have missed this in the Permit to Drill (PTD) application, but will this planned injector be pre‐produced for a length of time (regular production must be reported), or will it be simply flowed back for clean up? Please note that to simplify records management, the AOGCC has decided that whenever a PTD application is rejected:  the history file for that application will be closed,  the suffix “XX” will be appended to the well name/number in AOGCC’s databases,  the record for that application will be classified in our databases as “Not Approved”,  the PTD and API Numbers will not be re‐used, and  a “Note to File” will be placed in each history file to provide a link between the two affected files. In this instance, the original application is now labeled PBU L‐240XX, PTD 221‐079, API 50‐029‐23701‐00‐00, status “NTAPV”. 2 Hilcorp’s revised application submitted on 10/13/2021 will be labeled PBU L‐240, PTD 221‐086, API 50‐029‐23703‐00‐00. Please update Hilcorp’s records accordingly and let me know if you have any questions. Thanks and stay safe, Steve Davies Alaska Oil and Gas Conservation Commission (AOGCC) CONFIDENTIALITY NOTICE: This e‐mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e‐mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907‐793‐1224 or steve.davies@alaska.gov. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Revised 2/2015 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: ____________________________ POOL: ______________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit No. _____________, API No. 50-_______________________. Production should continue to be reported as a function of the original API number stated above. Pilot Hole In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name (_______________________PH) and API number (50-_____________________) from records, data and logs acquired for well (name on permit). Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. (_____________________________) as Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for well ( ) until after ( ) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (________________________) must contact the AOGCC to obtain advance approval of such water well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (_______________________________) in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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