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Home My WebLink About219-057CAUTION: 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: NOT OPERABLE: Injector S-210 (PTD #2190570) will lapse on AOGCC MIT-IA Date:Monday, January 26, 2026 11:33:50 AM From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Monday, January 26, 2026 10:49 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>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: NOT OPERABLE: Injector S-210 (PTD #2190570) will lapse on AOGCC MIT-IA Mr. Wallace, Injector S-210 (PTD #2190570) is due for a 2-year AOGCC MIT-IA in January 2026. The well is currently shut-in and will not be on injection before the end of the month. It will now be classified as NOT OPERABLE for tracking purposes. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307) 399-3816 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: [EXTERNAL] [AOGCC_Public_Notices] Are Injection Order 25A.021 and 25A.022 Amended (Hilcorp) Date:Monday, September 29, 2025 12:02:26 PM Prudhoe Bay Unit S-210 (PTD 2190570), Polaris Oil Pool Prudhoe Bay Unit S-201A (PTD 2190920), Polaris Oil Pool From: Wallace, Chris D (OGC) Sent: Monday, September 29, 2025 11:59 AM To: 'Oliver Sternicki' <oliver.sternicki@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: RE: [EXTERNAL] [AOGCC_Public_Notices] Are Injection Order 25A.021 and 25A.022 Amended (Hilcorp) Oliver, I did carry over the 2 year testing frequency as that is our standard on injectors with high set packer AA’s. WFL schedule sounds fine. For the MIT schedules, for S-201A I itemized the April 2026 MITIA in the AA. I would be OK with both the MITT both being completed in April 2026 rather than the MITT for December 2025 if that is more operationally efficient. You could request a delay for the MITT as it approaches with this email as justification, otherwise keep them on different schedules. Yes – from AOGCC standpoint you are approved for re-start of Polaris water only injection in S-201A and S-210. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Oliver Sternicki <oliver.sternicki@hilcorp.com> Sent: Monday, September 29, 2025 11:21 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: RE: [EXTERNAL] [AOGCC_Public_Notices] Are Injection Order 25A.021 and 25A.022 Amended (Hilcorp) CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Chris, Planning on doing the initial WFLs on S-201A, S-23 and S-24B ~30 days after injection starts back up. Giving it a couple weeks just to make sure that if there are any flow paths they would be established at that point. Other than that the MIT-T and MIT-IA’s are cueing off the preexisting schedules. S-201A MIT-IA due in April 2026, S-201A MIT-T due in December 2025. S-210 MIT-T and MIT-IA due in January 2026. Are we good from an AOGCC perspective on restart of injection into S-201A and S-210? Thanks, Oliver Sternicki Hilcorp Alaska, Hilcorp North Slope LLC Well Integrity Supervisor Office: (907) 564 4891 Cell: (907) 350 0759 Oliver.Sternicki@hilcorp.com From: Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov> Sent: Monday, September 29, 2025 9:00 AM To: AOGCC_Public_Notices <AOGCC_Public_Notices@list.state.ak.us> Subject: [EXTERNAL] [AOGCC_Public_Notices] Are Injection Order 25A.021 and 25A.022 Amended (Hilcorp) Docket Number: AIO-25-021 Request for Administrative Approval to Area Injection Order 25A; Water Injection Prudhoe Bay Unit S-210 (PTD 2190570), Polaris Oil Pool Docket Number: AIO-25-022 Request for Administrative Approval to Area Injection Order 25A; Water Injection Prudhoe Bay Unit S-201A (PTD 2190920), Polaris Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: oliver.sternicki@hilcorp.com Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/oliver.sternicki%40hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, March 7, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC S-210 PRUDHOE BAY UN POL S-210 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 03/07/2024 S-210 50-029-23630-00-00 219-057-0 N SPT 2308 2190570 3100 1118 3587 3418 3377 REQVAR P Kam StJohn 1/18/2024 AOGCC 2 Year MIT-T AIO AA 25A.021 Max anticipated pressure 3100 psi. 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 POL S-210 Inspection Date: Tubing OA Packer Depth 0 0 0 0IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS240119124451 BBL Pumped:0.7 BBL Returned:0.6 Thursday, March 7, 2024 Page 1 of 1          MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, March 4, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC S-210 PRUDHOE BAY UN POL S-210 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 03/04/2024 S-210 50-029-23630-00-00 219-057-0 G SPT 2308 2190570 3410 2663 2667 2667 2667 REQVAR P Sully Sullivan 1/27/2024 S-210 is a Monobore Well. 2 year MIT per AIO 25A.021 Criteria #4 (on Gas) 1.1x MIP est. 3100psi. Related inspection is MIT on water inj. Tested with 80 degree diesel 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 POL S-210 Inspection Date: Tubing OA Packer Depth 503 3724 3570 3522IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS240127131436 BBL Pumped:3.5 BBL Returned:3.7 Monday, March 4, 2024 Page 1 of 1           MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, March 1, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC S-210 PRUDHOE BAY UN POL S-210 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 03/01/2024 S-210 50-029-23630-00-00 219-057-0 W SPT 2308 2190570 2310 1662 1664 1663 1664 REQVAR P Sully Sullivan 1/9/2024 Mono bore well, tested with 118 deg diesel. 2 year MIT per AIO 25A.021@ 1.1 x max inj. Pres. of 2100 =2310 psi 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 POL S-210 Inspection Date: Tubing OA Packer Depth 57 2575 2478 2447IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS240110133715 BBL Pumped:3.7 BBL Returned:3.3 Friday, March 1, 2024 Page 1 of 1             Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: (907) 564-4891 02/09/2024 Mr. Mel Rixse Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Prudhoe Bay Surface Casing by Conductor Annulus Top-offs of Cement, Corrosion Inhibitor through 02/09/2024. Dear Mr. Rixse, Enclosed please find a copy of a spreadsheet with a list of Prudhoe Bay wells that were topped-off with cement, corrosion inhibitor in the surface casing by conductor annulus through 02/09/2024. Cement top-offs are executed as needed to mitigate the void space left at surface by minor cement fallback during the primary surface casing by conductor cement job. The remaining void space between the top of the cement and the top of the conductor is filled with a heavier than water corrosion inhibitor to reduce the risk of external surface casing corrosion. The attached spreadsheets include the well names, API and PTD numbers, treatment dates and volumes. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10-404 Report of Sundry Operations. If you have any additional questions, please contact me at 564-4891 or oliver.sternicki@hilcorp.com. Sincerely, Oliver Sternicki Well Integrity Supervisor Hilcorp North Slope, LLC Digitally signed by Oliver Sternicki DN: cn=Oliver Sternicki, c=US, o=Hilcorp North Slope LLC, ou=PBU, email=oliver.sternicki@hilcorp.com Date: 2024.02.09 11:15:58 -09'00' Oliver Sternicki Hilcorp North Slope LLC. Surface Casing by Conductor Annulus Cement, Corrosion Inhibitor Top-off Report of Sundry Operations (10-404) 02/09/2024 Well Name PTD #API # Initial top of cement (ft) Vol. of cement pumped (gal) Final top of cement (ft) Cement top off date Corrosion inhibitor (gal) Corrosion inhibitor/ sealant date L-293 223020 500292374900 30 8/29/2023 S-09A 214097 500292077101 2 9/19/2023 S-102A 223058 500292297201 2 9/19/2023 S-105A 219032 500292297701 10 9/19/2023 S-109 202245 500292313500 7 9/19/2023 S-110B 213198 500292303002 35 9/19/2023 S-113B 202143 500292309402 10 9/19/2023 S-115 202230 500292313000 4 9/19/2023 S-116A 213139 500292318301 4 9/19/2023 S-117 203012 500292313700 3 9/19/2023 S-118 203200 500292318800 9 9/19/2023 S-122 205081 500292326500 5 9/19/2023 S-125 207083 500292336100 2 9/19/2023 S-126 207097 500292336300 3 9/19/2023 S-134 209083 500292341300 35 9/19/2023 S-200A 217125 500292284601 7 9/19/2023 S-202 219120 500292364700 13 9/19/2023 S-210 219057 500292363000 10 9/19/2023 S-213A 204213 500292299301 4 9/19/2023 S-215 202154 500292310700 3 9/19/2023 S-216 200197 500292298900 4 9/19/2023 S-41A 210101 500292264501 3 9/19/2023 W-16A 203100 500292204501 2 9/23/2023 W-17A 205122 500292185601 3 9/23/2023 S-210 219057 500292363000 10 9/19/2023 Well Name PTD # API # Initial top of cement (ft) Vol. of cement pumped (gal) Final top of cement (ft) Cement top off date Corrosion inhibitor (gal) Corrosion inhibitor/ sealant date W-19B 210065 500292200602 8 9/23/2023 W-21A 201111 500292192901 8 9/23/2023 W-32A 202209 500292197001 4 9/23/2023 W-201 201051 500292300700 44 9/23/2023 W-202 210133 500292343400 6 9/23/2023 W-204 206158 500292333300 3 9/23/2023 W-205 203116 500292316500 3 9/23/2023 W-207 203049 500292314500 3 9/23/2023 W-211 202075 500292308000 8 9/23/2023 W-213 207051 500292335400 3 9/23/2023 W-214 207142 500292337300 10 9/23/2023 W-215 203131 500292317200 2 9/23/2023 W-223 211006 500292344000 7 9/23/2023 Z-69 212076 500292347100 2.0 27 1.5 10/24/2023 S-128 210159 500292343600 11 12/27/2023 S-135 213202 500292350800 16 12/27/2023 V-113 202216 500292312500 24 12/31/2023 V-114A 203185 500292317801 5 12/31/2023 V-122 206147 500292332800 5 12/31/2023 V-205 206180 500292333800 2 12/31/2023 V-207 208066 500292339000 8 12/31/2023 V-214 205134 500292327500 5 12/31/2023 V-215 207041 500292335100 2 12/31/2023 V-218 207040 500292335000 5 12/31/2023 V-224 208154 500292340000 16 12/31/2023 V-225 209118 500292341900 6 12/31/2023 V-01 204090 500292321000 3 1/1/2024 V-02 204077 500292320900 5 1/1/2024 V-04 206134 500292332200 5 1/1/2024 V-102 202033 500292307000 8 1/1/2024 V-104 202142 500292310300 5 1/1/2024 V-220 208020 500292338300 4 1/1/2024 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/14/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230914 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# PBU S-210 (Revision)50029236300000 219057 4/17/2023 READ Injection Profile PBU S-42A 50029226620100 215055 8/8/2023 AK E-LINE Gamma Ray/CCL Revision explanation: PBU S-210: Updated LAS files and Final Report added. Please include current contact information if different from above. T37996 T37727 Revised 9/15/2023 50029236300000 219057 4/17/2023 READ Injection ProfilePBUS-210 (Revision) Kayla Junke Digitally signed by Kayla Junke Date: 2023.09.15 13:32:45 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 06/02/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230416 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPB-15 50029213740000 185121 5/16/2021 READ Caliper Survey MPC-02 50029208660000 182194 4/26/2023 READ Caliper Survey MPE-15 50029225280000 194153 4/17/2023 READ Caliper Survey MPE-15 50029225280000 194153 4/21/2023 READ Caliper Survey MPL-40 50029228550000 198010 4/18/2023 READ Caliper Survey PBU D-03A 50029200570100 200134 5/28/2023 READ MRCBL PBU L-212 50029232520000 205030 4/14/2023 READ Injection Profile PBU S-210 50029236300000 219057 4/17/2023 READ Injection Profile PBU V-212 50029232790000 205150 5/13/2023 READ Injection Profile Please include current contact information if different from above. T37721 T37722 T37723 T37723 T37724 T37725 T37726 T37727 T37728 PBU S-210 50029236300000 219057 4/17/2023 READ Injection Profile Kayla Junke Digitally signed by Kayla Junke Date: 2023.06.12 14:32:41 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, June 15, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Guy Cook P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp North Slope, LLC S-210 PRUDHOE BAY UN POL S-210 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 06/15/2022 S-210 50-029-23630-00-00 219-057-0 G SPT 2308 2190570 3410 1956 1963 1961 1960 REQVAR P Guy Cook 5/28/2022 2 year MITIA to 1.1 times max anticipated header injection pressure (MI header pressure = 3100 psi.) per AA AIO 25A.021. This well is a monobore well. Testing was completed with a Little Red Services pump truck and calibrated gauges. 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 POL S-210 Inspection Date: Tubing OA Packer Depth 2 3768 3524 3462IA 45 Min 60 Min Rel Insp Num: Insp Num:mitGDC220527181848 BBL Pumped:4.5 BBL Returned:4.3 Wednesday, June 15, 2022 Page 1 of 1 9 9 9 9 9 9 9 9 9 9 9 MITIA 1.1 times max anticipated header injection pressure AA AIO 25A.021. James B. Regg Digitally signed by James B. Regg Date: 2022.06.15 14:16:49 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: OPERABLE: WAG Injector S-210 (PTD #2190570) will need AOGCC witnessed MIT-IA Date:Wednesday, May 25, 2022 9:26:03 AM From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Sunday, May 22, 2022 4:06 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com>; Stan Golis <sgolis@hilcorp.com> Subject: OPERABLE: WAG Injector S-210 (PTD #2190570) will need AOGCC witnessed MIT-IA Mr. Wallace, Drilling on M-pad is complete and injection on S-210 (PTD #2190570) is ready to resume. The well is now classified as OPERABLE and an AOGCC witnessed MIT-IA will be scheduled when on stabilized injection. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Thursday, April 28, 2022 1:43 PM To: chris.wallace@alaska.gov Cc: Regg, James B (CED) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: NOT OPERABLE: WAG Injector S-210 (PTD #2190570) will lapse on AOGCC MIT-IA Mr. Wallace, WAG Injector S-210 (PTD # 2190570) is due for its 2-year AOGCC MIT-IA by the end of April. The well is currently shut-in for reservoir management due to drilling on M-pad. It will not be online before it lapses on the required MIT-IA. The well will now be classified as NOT OPERABLE for tracking purposes. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: NOT OPERABLE: WAG Injector S-210 (PTD #2190570) will lapse on AOGCC MIT-IA Date:Thursday, May 5, 2022 12:21:24 PM From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Thursday, April 28, 2022 1:43 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: NOT OPERABLE: WAG Injector S-210 (PTD #2190570) will lapse on AOGCC MIT-IA Mr. Wallace, WAG Injector S-210 (PTD # 2190570) is due for its 2-year AOGCC MIT-IA by the end of April. The well is currently shut-in for reservoir management due to drilling on M-pad. It will not be online before it lapses on the required MIT-IA. The well will now be classified as NOT OPERABLE for tracking purposes. Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity / Compliance andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MEMORANDUM TO: Jim Regg P.I. Supervisor 7 1 FROM: Austin McLeod Petroleum Inspector Zf4(-7�7- NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday, February 3, 2022 SUBJECT: Mechanical Integrity Tests Hilcorp North Slope, LLC S-210 PRUDHOE BAY UN POL S-210 Sre: Inspector Reviewed B P.I. Supry 55/2— Comm Well Name PRUDHOE BAY UN POL S-210 API Well Number 50-029-23630-00-00 Inspector Name: Austin McLeod Permit Number: 219-057-0 Inspection Date: 1/30/2022 Insp Num: mitSAM220131131823 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well S-210 -Type Inj N ,TVD 2308 Tubing 3430 3656 - 3602 3588 PTD 2190570 ' 'Type Test SPT Test psi 3410 IA 1011 1064 1118 - 1132 - BBL Pumped: 0.1 " BBL Returned: 1.7 - OA Interval OTHER P/F P Notes: MITT. 2 year to l.lx MAIP (3100) per email chain w/ Mel Rixse. Test bumped after previous test IA was bled. Packer TVD is TOC Thursday, February 3, 2022 Page I of 1 MEMORANDUM TO: Jim Regg P.I. Supervisor FROM: Austin McLeod Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday, February 3, 2022 SUBJECT: Mechanical Integrity Tests Hilcorp North Slope, LLC S-210 PRUDHOE BAY UN POL S-210 Sre: Inspector Reviewed By:: P.I. Supry Jai` Comm Well Name PRUDHOE BAY UN POL S-210 API Well Number 50-029-23630-00-00 Inspector Name: Austin McLeod Permit Number: 219-057-0 Inspection Date: 1/30/2022 lisp Num: mitSAM220131131348 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well S-210 Type Inj N TVD 2308 Tubing 3522 - 3647 - 3618 3598 3580 - 3565 ' PTD 7 2190570 ' Type Test SPT "Test psi 3410 IA 3402 3633 3585 3559 3538 3521 BBL Pumped: 0.3 ' BBL Returned: 3 OA Interval OTHER P/F P Notes: CMITT/IA. 2 year to l.lx MAIP (3100) per email chain w/ Mel Rixse. Test bumped from previous fail. Packer TVD is TOC Thursday, February 3, 2022 Page 1 of I MEMORANDUM TO: Jim Regg �I 2/-,' zf�-L P.I. Supervisor ' l FROM: Austin McLeod Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday, February 3, 2022 SUBJECT: Mechanical Integrity Tests Hilcorp North Slope, LLC S-210 PRUDHOE BAY UN POL S-210 Sre: Inspector Reviewed By: P.I. Supry V5L_ Comm Well Name PRUDHOE BAY UN POL S-210 API Well Number 50-029-23630-00-00 Inspector Name: Austin McLeod Permit Number: 219-057-0 Inspection Date: 1/30/2022 Insp Num: mitSAM220131130707 Rel lnsp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well S-210 Type Inj N' TVD 2308 Tubing 437 3612 - 3554 - 3522 PTD 2190570 - Type Test sPT Test psi 3410 IA 454 3596 3469 3402 ' BBL Pumped: 4.4 BBL Returned: OA Interval OTHER P/F F Notes: CMITT/IA. 2 year to I.1 x MAIP (3100) per email chain w/ Mel Rixse. No BBL back -test bumped. Packer TVD is TOC Thursday, February 3, 2022 Page I of l David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: Hilcorp North Slope, LLC Date: 06/16/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: FTP Folder Contents: Log Print Files and LAS Data Files: Well API PTD # Log Date Log Type Log Vendor 13-20 500292070500 182009 05/08/2021 RCBL HALLIBURTON E-34A 500292243701 214096 06/06/2021 RCBL READ CH G-18B 500292062002 214071 05/23/2021 RCBL HALLIBURTON S-201A 500292298701 219092 05/29/2021 IPROF-WFL and ANALYSIS HALLIBURTON S-210 500292363000 219057 04/27/2021 IPROF-WFL and ANALYSIS HALLIBURTON V-117 500292315600 203090 05/02/2021 PPROF and ANALYSIS HALLIBURTON V-117 500292315600 203090 05/02/2021 RCBL HALLIBURTON Z-11A 500292205301 205031 05/18/2021 RCBL HALLIBURTON Z-31 500292187100 188112 06/07/2021 RCBL HALLIBURTON Please include current contact information if different from above. Received By: 06/16/2021 37' (6HW By Abby Bell at 10:04 am, Jun 16, 2021 MEMORANDUM TO: Jim Regg --S/, 7.c, P.I. Supervisor Z FROM: Austin McLeod Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, May 13, 2020 SUBJECT: Mechanical Integrity Tests BP Exploration (Alaska) Inc. S-210 PRUDHOE BAY UN POL S-210 Src: Inspector Reviewed By: P.I. Suprv� Comm Well Name PRUDHOE BAY UN POL S-210 API Well Number 50-029-23630-00-00 Inspector Name: Austin McLeod Permit Number: 219-057-0 Inspection Date: 4/21/2020 Insp Num: mitSAM200421152455 Rel Insp Num: Wednesday, May 13, 2020 Page 1 of I Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well S-210 Type In] W ✓TVD - —2308 Tubing1406 - 1407 ' 1407. 1408 PTD 2190570 Type Test' SPT (Test psi 1500 - 'I IA 673 2123 2039 - 2015 BBL Pumped: 1.6 - IBBL Returned: 1.6 '' OA Interval. INITAL IP/F P Notes: Initial after converted to an injector. Monobore. Packer TVD is TOC. Cement packer (500'). Wednesday, May 13, 2020 Page 1 of I 1 Winston, Hugh E (CED) From:Lastufka, Joseph N <Joseph.Lastufka@bp.com> Sent:Monday, April 20, 2020 4:33 PM To:AOGCC Reporting (CED sponsored) Subject:PBU S-210 / PTD # 219-057 Hello, Please reference the following well: Well Name: PBU S-210 Permit #: 219-057 API #: 50-029-23630-00-00 This well began Injection on: 4/14/2020 Method of Operations on this date: Water Injection Date: 4/9/2020 Transmittal Number: 93743-S-210 BPXA WELL DATA TRANSMITTAL Subsurface Information Management 900 E. Benson Blvd. PO Box 196612 Anchorage, AK 99519-6612 Digital zip files for the well log packages listed below are being provided to you via SharePoint. If you have any questions please contact Merion Kendall: 907-564-5216; merion.kendall@bp.com. SW Name Log Date Company Description Format S-210 1/10/2020 Schlumberger SCMT Zip File Please Sign and Return one copy of this transmittal to GANCPDC@bp365.onmicrosoft.com Thank you, Mer Merion Kendall SIM Specialist ----------------------------------------------------------------------------------------------- BP Exploration Alaska|900 E. Benson Blvd.|Room: 716B|Anchorage, AK ----------------------------------------------------------------------------------------------- AOGCC https://bp365.sharepoint.com/sites/BPtoAOGCCElectronicPermittingandReporting/ DNR https://drop.state.ak.us/drop/ Received by the AOGCC on 04/09/2020 PTD: 2190570 E-set: 32475 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23630-00-00Well Name/No. PRUDHOE BAY UN POL S-210Completion StatusWAGINCompletion Date1/14/2020Permit to Drill2190570Operator BP Exploration (Alaska) Inc.MD6050TVD5510Current StatusWAGIN4/6/2020UICYesWell Log Information:DigitalMed/FrmtReceivedStart StopOH /CHCommentsLogMediaRunNoElectr DatasetNumberNameIntervalList of Logs Obtained:MWD/GR/RES, MWD/GR/RES/DEN/NEU, FORM EVAL, CMT EVALNoNoYesMud Log Samples Directional SurveyREQUIRED INFORMATION(from Master Well Data/Logs)DATA INFORMATIONLog/DataTypeLogScaleC1/27/2020 Electronic File: S-210_C1_10JAN2020_SCMT_SCH_MEM_FIELDPRINT.pdf31961EDCement EvaluationC2/11/202070 6050 Electronic Data Set, Filename: S-210_BH_LTK_MEM_Composite_Drilling Depth Data.las32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_LTK_2MD_Memory Drilling Log.cgm32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_LTK_2TVDSS_Memory Drilling Log.cgm32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_LTK_5MD_Memory Drilling Log.cgm32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_LTK_5TVDSS_Memory Drilling Log.cgm32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_LTK_5TVDSS_Memory Drilling Log.cgm.meta32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_OTK-VSS_RLT-MEM_Composite Drilling Dynamics.cgm32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_LTK_MEM_Composite_Drilling Depth Data.dls32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_LTK_2MD_Memory Drilling Log.pdf32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_LTK_2TVDSS_Memory Drilling Log.pdf32031EDDigital DataMonday, April 6, 2020AOGCCPage 1 of 7S-,210_BH_LTK_MEM_Composite_Drilling Depth __Data.las DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23630-00-00Well Name/No. PRUDHOE BAY UN POL S-210Completion StatusWAGINCompletion Date1/14/2020Permit to Drill2190570Operator BP Exploration (Alaska) Inc.MD6050TVD5510Current StatusWAGIN4/6/2020UICYesC2/11/2020 Electronic File: S-210_BH_LTK_5MD_Memory Drilling Log.pdf32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_LTK_5TVDSS_Memory Drilling Log.pdf32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_Final Surveys Report.csv32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_Final Surveys Report.pdf32031EDDigital DataC2/11/2020 Electronic File: S-210_BH_Final Surveys Report.txt32031EDDigital Data0 0 2190570 PRUDHOE BAY UN POL S-210 LOG HEADERS32031LogLog Header ScansC2/11/2020 Electronic File: S-210_BH_Final Surveys Report.csv32031EDDigital DataC2/13/20203 1170 Electronic Data Set, Filename: S-210_RDT_20DEC19_5351FT_MD.las32040EDDigital DataC2/13/20203 882 Electronic Data Set, Filename: S-210_RDT_20DEC19_5355FT_MD.las32040EDDigital DataC2/13/20204 1780 Electronic Data Set, Filename: S-210_RDT_20DEC19_5426FT_MD.las32040EDDigital DataC2/13/20204 3136 Electronic Data Set, Filename: S-210_RDT_20DEC19_5428FT_MD.las32040EDDigital DataC2/13/20204 774 Electronic Data Set, Filename: S-210_RDT_20DEC19_5455FT_MD.las32040EDDigital DataC2/13/20203 1131 Electronic Data Set, Filename: S-210_RDT_20DEC19_5465FT_MD.las32040EDDigital DataC2/13/20203 694 Electronic Data Set, Filename: S-210_RDT_20DEC19_5467FT_MD.las32040EDDigital DataC2/13/20204 1397 Electronic Data Set, Filename: S-210_RDT_20DEC19_5548FT_MD.las32040EDDigital DataC2/13/20204 434 Electronic Data Set, Filename: S-210_RDT_20DEC19_5555FT_MD.las32040EDDigital DataC2/13/20204 894 Electronic Data Set, Filename: S-210_RDT_20DEC19_5557FT_MD.las32040EDDigital DataC2/13/20204 1144 Electronic Data Set, Filename: S-210_RDT_20DEC19_5568FT_MD.las32040EDDigital DataMonday, April 6, 2020AOGCCPage 2 of 7 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23630-00-00Well Name/No. PRUDHOE BAY UN POL S-210Completion StatusWAGINCompletion Date1/14/2020Permit to Drill2190570Operator BP Exploration (Alaska) Inc.MD6050TVD5510Current StatusWAGIN4/6/2020UICYesC2/13/20203 701 Electronic Data Set, Filename: S-210_RDT_20DEC19_5593FT_MD.las32040EDDigital DataC2/13/20204 604 Electronic Data Set, Filename: S-210_RDT_20DEC19_5599FT_MD.las32040EDDigital DataC2/13/20203 410 Electronic Data Set, Filename: S-210_RDT_20DEC19_5617FT_MD.las32040EDDigital DataC2/13/20204 765 Electronic Data Set, Filename: S-210_RDT_20DEC19_5637FT_MD.las32040EDDigital DataC2/13/20204 599 Electronic Data Set, Filename: S-210_RDT_20DEC19_5639FT_MD.las32040EDDigital DataC2/13/20204 856 Electronic Data Set, Filename: S-210_RDT_20DEC19_5643FT_MD.las32040EDDigital DataC2/13/20204 655 Electronic Data Set, Filename: S-210_RDT_20DEC19_5690FT_MD.las32040EDDigital DataC2/13/20204 762 Electronic Data Set, Filename: S-210_RDT_20DEC19_5696FT_MD.las32040EDDigital DataC2/13/20204 1948 Electronic Data Set, Filename: S-210_RDT_20DEC19_5700FT_MD.las32040EDDigital DataC2/13/20205 1709 Electronic Data Set, Filename: S-210_RDT_20DEC19_5749FT_MD.las32040EDDigital DataC2/13/20204 1928 Electronic Data Set, Filename: S-210_RDT_20DEC19_5757FT_MD.las32040EDDigital DataC2/13/20205 1983 Electronic Data Set, Filename: S-210_RDT_20DEC19_5768FT_MD.las32040EDDigital DataC2/13/20204 1003 Electronic Data Set, Filename: S-210_RDT_20DEC19_5810FT_MD.las32040EDDigital DataC2/13/20205 1029 Electronic Data Set, Filename: S-210_RDT_20DEC19_5859FT_MD.las32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5351FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5355FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5426FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5428FT_MD.dlis32040EDDigital DataMonday, April 6, 2020AOGCCPage 3 of 7 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23630-00-00Well Name/No. PRUDHOE BAY UN POL S-210Completion StatusWAGINCompletion Date1/14/2020Permit to Drill2190570Operator BP Exploration (Alaska) Inc.MD6050TVD5510Current StatusWAGIN4/6/2020UICYesC2/13/2020 Electronic File: S-210_RDT_20DEC19_5455FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5465FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5467FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5548FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5555FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5557FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5568FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5593FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5599FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5617FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5637FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5639FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5643FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5690FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5696FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5700FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5749FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5757FT_MD.dlis32040EDDigital DataMonday, April 6, 2020AOGCCPage 4 of 7 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23630-00-00Well Name/No. PRUDHOE BAY UN POL S-210Completion StatusWAGINCompletion Date1/14/2020Permit to Drill2190570Operator BP Exploration (Alaska) Inc.MD6050TVD5510Current StatusWAGIN4/6/2020UICYesC2/13/2020 Electronic File: S-210_RDT_20DEC19_5768FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5810FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5859FT_MD.dlis32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5351FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5355FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5426FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5428FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5455FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5465FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5467FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5548FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5555FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5557FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5568FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5593FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5599FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5617FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5637FT_MD.ver32040EDDigital DataMonday, April 6, 2020AOGCCPage 5 of 7 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23630-00-00Well Name/No. PRUDHOE BAY UN POL S-210Completion StatusWAGINCompletion Date1/14/2020Permit to Drill2190570Operator BP Exploration (Alaska) Inc.MD6050TVD5510Current StatusWAGIN4/6/2020UICYesWell Cores/Samples Information:ReceivedStart Stop CommentsSentSample SetNumberNameIntervalINFORMATION RECEIVEDC2/13/2020 Electronic File: S-210_RDT_20DEC19_5639FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5643FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5690FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5696FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5700FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5749FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5757FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5768FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5810FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_5859FT_MD.ver32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19.pdf32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_SAMPLES-V2.pdf32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_img.tiff32040EDDigital DataC2/13/2020 Electronic File: S-210_RDT_20DEC19_SAMPLES-V2_img.tiff32040EDDigital Data0 0 2190570 PRUDHOE BAY UN POL S-210 LOG HEADERS32040LogLog Header ScansMonday, April 6, 2020AOGCCPage 6 of 7 DATA SUBMITTAL COMPLIANCE REPORTAPI No. 50-029-23630-00-00Well Name/No. PRUDHOE BAY UN POL S-210Completion StatusWAGINCompletion Date1/14/2020Permit to Drill2190570Operator BP Exploration (Alaska) Inc.MD6050TVD5510Current StatusWAGIN4/6/2020UICYesCompletion ReportProduction Test InformationGeologic Markers/TopsY Y / NAYComments:Compliance Reviewed By:Date:Mud Logs, Image Files, Digital DataComposite Logs, Image, Data Files Cuttings SamplesY / NAYY / NADirectional / Inclination DataMechanical Integrity Test InformationDaily Operations SummaryYY / NAYCore ChipsCore PhotographsLaboratory AnalysesY / NAY / NAY / NACOMPLIANCE HISTORYDate CommentsDescriptionCompletion Date: 1/14/2020Release Date:6/10/2019Monday, April 6, 2020AOGCCPage 7 of 7M.Guhl4/6/2020 STATE OF ALASKA REC 'r' IVF r" ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil El Gas ❑ SPLUG ❑ Other ❑ Abandoned El Suspended El1b. 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAG 0 WDSPL 11No. of Completions: One Well ass: Development Eeloratory ❑ Service ® - raAgraphic Test ❑ 2. Operator Name: BP Exploration (Alaska), Inc 6. Date Comp., Susp., or Aband.: 1/14/2020 14. Permit to Drill Number/Sundry 219-057 3. Address: P.O. Box 196612 Anchorage, AK 99519-6612 7. Date Spudded: 12/14/2019 15. API Number: 50-029-23630-00-00 4a. Location of Well (Governmental Section): Surface: 4196' FSL, 4503' FEL, Sec. 35, T12N, R12E, UM Top of Productive Interval: 376' FSL, 5091' FEL, Sec. 26, T12N, R12E, UM Total Depth: 692' FSL, 5265' FEL, Sec. 26, T12N, R12E, UM 8. Date TD Reached: 12/19/2019 16. Well Name and Number: PBU S-210 9 Ref Elevations KB 81.68 GL 35.20 - BF 38.17 17. Field/Pool(s): PRUDHOE BAY, POLARIS OIL ' 10. Plug Back Depth(MD/TVD): 1 5956'/ 5433' " 18. Property Designation: ADL 028257 ' 4b. 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 618930 y- 5980399 Zone - ASP 4 TPI: x- 618316 y- 5981850 Zone - ASP 4 Total Depth: x- 618137 y- 5962163 Zone - ASP 4 11. Total Depth (MD/TVD): 6050' / 5510' 19. DNR Approval Number: 83-47 12, SSSV Depth (MD/TVD): None 20 Thickness of Permafrost MD/TVD: 1923'/ 1916' 5. Directional or Inclination Survey: ' Yes Q (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 113. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary MWD / GR / RES, MWD / GR / RES / DEN / NEU, Formation Evaluation, Cement Evaluation 23' CASING, LINER AND CEMENTING RECORD CASING Wi. PER FT. GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 20" 129.45# x-65 47' 158' 47' 158' 42"/Driven 17 yds Concrete 10-3/4"x9-5/8" 45.5#/47# L-80 46' 2853' 46' 2831' 13-1/2" 1440 sx LiteCrete, 339 sx Class'G' 3-1/2" 9.2# L-80 44' 6042' 44' 5503' B-1/2" 804 sx Class'G', 355 sx Class'G' 24. Open to production or injection? Yes Q No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom, Perforation Size and Number, Date Perfd): Injection Stations 1/14/2020 5429'- 5779' 5002' - 5288' COMPLETION V ,DATEnformation / VERIFIED 25. TUBING RECORD GRADE DEPTH SET (MD) PACKER SET (MD/TVD) 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes El No Q Per 20 AAC 25.283 (i)(2) attach electronic and printed DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 200' 22 Bbls Diesel 27. PRODUCTION TEST Date First Production: Not on Injection Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Hours Tested: Production for Test Period -110. Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size Gas -Oil Ratio: Flow Tubing Press Casing Press: Calculated 24 Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl Oil Gravity - API (corr): Form 10-407 Revised 5/2017 CONTINUED ON PAGE 2 Submit ORIGINAL only RBDMS�' FEB 13 2020 28. CORE DATA Conventional Core(s) Yes ❑ No Q Sidewall Cores Yes ❑ No Q If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Permafrost - Top 38' 38' Well Tested? Yes D No ❑ Permafrost - Base 1961' 1954' If yes, list intervals and formations tested, briefly summarizing test results. Attach Top of Productive Interval 5423' gggg separate sheets to this form, if needed, and submit detailed test information per 20 AAC 25.071. Ugnu 3664' 3585' Schrader Bluff NA 5403' 4981' See Attached y Schrader Bluff NB Schrader Bluff NC 5423' 4998' 5454' 5023' Schrader Bluff NE 5464' 5031' Schrader Bluff NF 5512' 5070' t Schrader Bluff OA 5537' 5090' Schrader Bluff OBa 5592' 5135' Schrader Bluff OBb 5635' 5171' J Schrader Bluff OBc 5685' 5211' Schrader Bluff OBd Bluff OBe 5745' 5260' Schrader Schrader Bluff OBf 5806' 5853' 5310' 5348' Schrader Bluff OBf Base 5898' 5385' n /� Formation at total depth: Schrader Bluff OBf Base 5898' 5385' 31. List of Attachments. LOT / FIT Summary, Summary of Daily Drilling Reports, Summary of Post -Rig Work, Survey, Cement Report, As -Built, Wellbore Schematic Diagram Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Lastufka, Joseph N Contact Name: Nocas, Noel Authorized Title: ecialist Contact Email: Noel.Nocas@bp.com Authorized Signature: Date: 2-11 "v! Contact Phone: +1 9075645027 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1a. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b. Well Class Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disp, Water Supply for Injection, Observation or Other. Item 4b. TPI (Top of Producing Interval). Item 9. The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20. Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 29, Item 22. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other ( explain). Item 28. Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30. Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31. Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only TREE= GE WELLHEAD = FMC ACTUATOR= MACH GE OKB. ELEV = 81.68' BF. ELEV = 38.17' KOP = 10 Max Angle = 38" 4564' Daum MD = 5526' Datum TVD = 5000'SS 20' COND, 158' 129.45#, X-65, ID = TOC PER SLB MEMORY CBL (01/1020) 2318' 10-3/4' CSG, 45.5#, L-80 VAM 21, ID = 9.950' 2349' 9-5/8' CSG, 47#, L-80 VAM 21, ID = 8.681 • 2853' Minimum ID = 2.813" a@ 2008' 3-1/2" HES X NIPPLE INJECTION STATIONS "-2.4' FROM BOTTOM OF GLM" NO DEPTH D GAUGE ADDRESS DATE ZONE 9 5429 2.92' 10 1226/19 Nb 8 5548 2.92' 8 1226/19 OA 7 5569 2.92' 7 1226/19 OA 6 5596 2.92' 6 1226/19 OBa 5 5619 2.92' 5 1226/19 OBa 4 5642 2.92' 4 1226/19 OBb 3 5694 2.92' 3 1226/19 OBc 2 5756 2.92' 2 1226/19 OBd 1 5779 2.92' 1 1226/19 OBd PBTD 6966' 3-12' TBG, 9.2#, L30 VT, .0087 bip, ID = 2.992" 6042' S-210 SAFETY NOTES: MAX DLS: 5.3' Q 1086'. 2008' -�3-12' HES X NIP, ID = 2.813" 2303' 3-12' BOT HP DEFENDER SLD SLV, ID = 2.813' TYPE SLD SLV PERMANENTLY -CLOSED (01/1020) 2349' 103/4' X 9-5/8• XO, ID = 8.681 1' RAKFR Sr1F PnrlCFT MANIIRFI C ST MD TVD DEV TYPE VLV LATCH PORT DATE 9 5424 4999 35 BKR DMY BK 0 01/1720 8 5543 5096 35 BKR RWF BK 5/32' 01/1720 7 5564 5112 35 BKR DMY BK 0 01/1720 6 5591 5134 35 BKR RWF BK 9/32' 01/1720 5 5614 5154 35 BKR DMY BK 0 01/1720 4 5637 5172 35 BKR RWF BK 5/32' 01/1720 3 5689 5215 36 BKR RWF BK 5/32' 01/1720 2 5751 5265 36 BKR RWF BK 5/32' 01/1720 1 5774 5284 36 BKR DMY BK 0 01/1720 5342' —+3-12' 5424' 6481' HES X NIP, ID =2.813' V BKR SIDE POCKET MANDREL w/ GAUGE CLAMP #10 3-12' HES X NP, D = 2.813' 5543' 1' BKR SIDE POCKET MANDREL w/ 1228119 P-272 INITIAL COMPLETION 02/1020 CJWJMD WFR C/O 01/1720 GAUGE CLAMP #8 5564' V BKR SIDE POCKET MANDREL w/ 01/1420 NWJMD FINAL ODE APPROVAL GAUGE CLAMP #7 5591' 1' BKR SIDE POCKETMANDREL W GAUGE CLAMP 06 5614' V BKR SIDE POCKET MANDREL w/ GAUGE CLAMP #5 5637' 1' BKR SIDE POCKET MANDREL w/ GAUGE CLAMP #4 5668' 3-12' HES X NIP, ID = 2.813' 5689' 1' BKR SIDE POCKET MAND RE L w/ GAUGE CLAMP #3 5716' 3-12' HES X NIP, ID = 2.813' 5751' 1' BKR SIDE POCKET MANDREL w/ GAUGE CLAMP #2 5774' 1' BKR SIDE POCKET MANDREL w/ GAUGE CLAMP #1 5801' 3-12' HES X NIP, ID = 2.813' POLARIS UNIT WELL: S-210 PERMIT No: 219-057 API No: 50-029-23630-00 SEC 35, T12N, R12E, 4196' FSL & 4503' FEL DATE REV BY COMMENTS DATE REV BY COMMENTS 1228119 P-272 INITIAL COMPLETION 02/1020 CJWJMD WFR C/O 01/1720 01)09/19 JMD DRLG HO CORRECTIONS 02/1020 AY/JMD ADDED ZONES TO INJECTION TABLE 01/1320 KP/JMD TREE INSTALLED 01/1420 NWJMD CORRECTIONS 01/1420 NWJMD FINAL ODE APPROVAL BP Exploration (Alaska) 01/3020 ICJN/JMDI EDITTO TOC & DEFENDER SLD SLVI T m OO N N N F N N N O F i5 w Q m m(DLOH I` M M O N (N N Cl) co M N LO co Wa 00 00 OO 00 c0 t`06 ti I\ r- I` I` co 00 co I` r- r- N r- r - W W W W W W W W W W W W W W W W W W W W W W W W W W W 7 CLD D D D D D D D D D Z) D D:D :D D D D D (n CO co U) N cn U) U) U) U) N U) U) U)C/) U) U) U)(n U) w U) cn U) m U) U) (n U) U) U) cn(n U) U) U) U) N U) U) U) co(n U) U) U) U) N U) 0 U) N U) U) i£ to W W W W W W W W W W W W W W W W W W W W W W W W W W W a a a a a. o- a d a n. n. a a a a m a. a a a n. a- a a a a 0- N N N N a) i) a ) N ) a y N y N (D a) N N N N N Q) N y N Q) N N N N N 4) 0 a) N N N N N O) N N N N N N Q) N O 0 0) ra =a s a a a a a a a a a a a a a a C O O O OOO O OOO O O O cm 0000000000 O O O O O O O O O O O UE U` CD U F 0 (7 0 0 (7 (7 0 0 0 0 (D (7 (7 0 0 (7 t- F (7 Q I- m N CO N m m fD O M 00 m - LO M LO I- V CO LO (0 (0 (D N CO V E V m m m co � c) O m mc? 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V LO LO m (D I� 1-- r� M V m I- m N m m c0 (D M co co 0) N c0 m I- Lo M m m m O I- O r m m �2 m O m O L() m M N N LO O O V LO LO (D m(m M LDLr) M V W m m V LO (O O LO V� n' CO LO V LO �7 LO V LO V LO V' LO LO LO LO LO LO LO X) LO LO LO Ln LO O LO M LO (D LO (D LO (D LO (D LO r-- LO � LO I` LO 00 LO 00 LO I` LO a Q Q Q Q m m m m m-0 m m Q-0 m m U m U m U m a m a m a m m m m a m 0 m Z co Z Z Z Z o o o o o 0 o 0 o 0 o o 0 o 0 o o o o o yr (D I-- W m O- N M V LO W I- N M C) r- N M V LO (O I- N cM '' 0 C O O O O O N N N N N N N N M M M M M •O LL O O O O O O O O O O O O O O O O O O O O O O O O O O O n o 0 0 0 0 0 0 0 0 0 C) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 C) N M V LO (O I- W m O O r- N M V t0 CD tb N N N N N N 'Q T'N 2 BP AMERICA LOT / FIT Summary Well Name: S-210 Surface Leak Off Test Test Test Depth Test Depth AMW Pressure Pressure EMW Date Type (TMD -Ft) (TVD -Ft) (ppg) (psi) (BHP) (psi) (ppg) 12/18/19 FIT 2,853.00 2,830.64 9.20 570.00 1,922.51 13.08 Page 1 of 1 Printed 1/8/2020 11 26 40AM 'All dephts reported in Drillers Dephts" North America - ALASKA - BP Page 1 of 14 Operation Summary Report Common Well Name: S-210 Event Type: DRL-ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code ! NPT Total Depth Phase Description of Operations hr ( ) (usft) 12/12/2019 09:00 11:00 2.00 RIGD P -0.67 PRE GENERAL RIG DOWN SKID RIG FLOOR PREFORM PRE SKID CHECK LIST LAY DERRICK OVER PREFORM DERRICK INSPECTION SET UP BARRICADES IN FRONT OF RIG LAY MAST OVER = 380K ON RACK DISCONNECT INTERCONNECTS 11.00 1930 8.50 MOB P -0.67 PRE MOVE RIG FROM S-129 TO S-210 WARM HYDRAULICS SPLIT MODULES MOVE MODULES TO S-210 19:30 22:30 3.00 MOB P T -0.67 PRE _ SPOT�MODULES ES-FUNCTION E-STOPS PRIOR TO SPOTTING OVER WELL - RIG UP UTILITY MOD PIPE SHED AND INTER 'CONNECT RIG UP MUD MOD PIPE SHED AND INTER CONNECT 22:30 00:00 1.50 RIGU P -0.67 PRE GENERAL RIG UP RAISE DERRICK, MAX WEIGHT 525 KLBS SKID RIG FLOOR TO DRILLING POSITION SKID HAUNCH RIG UP RIG FLOOR EQUIPMENT HOLD PRESPUD MEETING WITH LYLE BUCKLERS CREW 12/13/2019 00:00 02:00 2.00 RIGU P -0.67 PRE GENERAL RIG UP RIG UP RIG FLOOR EQUIPMENT RECONNECT INTERCONNECTS PERFORM OPERATIONS ON RIG ACCEPTANCE CHECKLIST "'RIG ACCEPTED AT_02:00— 02:00 02:30 0.50 r RIGU P -0.67 PRE HOLD RIG EVAC / DIVERTER / H2S DRILL _ WITH AAR 02:30 11:00 8.50 DIVRTR P -0.67 PRE NIPPLE UP DIVERTER SYSTEM SIMOPS: BRIDLE DOWN CALIBRATE PVT AND TOTCO SYSTEM CHANGE OUT SAVER SUB TEST GAS ALARMS _ HOIST BHA SUBS TO THE RIG FLOOR 11 00 13.00 2.00 DIVRTR N 0.67 PRE RE-STRING BRIDGE CRANES SIMOPS: BUILD STANDS OF 5" DP OFFLINE 13:00 17 00 4.00 DIVRTR P 0.67 PRE NIPPLE UP DIVERTER SYSTEM INSTALL KNIFE VALVE AND 21-1/4" DIVERTER ANNULAR WITH DIVERTER EXTENSION OUT THE BACK OF THE RIG - FUNCTION TEST DIVERTER SYSTEM, 15 SEC FOR KNIFE VALVE TO OPEN AND 33 SEC FOR ANNULAR TO CLOSE, WITNESS WAIVED BY AOGCC REP GUY COOK Printed 1/8/2020 11 26 40AM 'All dephts reported in Drillers Dephts" North America - ALASKA - BP Operation Summary Report Common Well Name S-210 Page 2 of 14 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 17:00 18:00 1.00 DIVRTR P -0.67 PRE HOLD PRESPUD MEETING AND EVAC / H2S / DIVERTER DRILL WITH RUSSEL WOODS CREW - 18:00 20:00 2.00 DIVRTR P -0.67 PRE FILL SURFACE LINES AND CONDUCTOR - PICK UP STAND OF DP, RIH AND TAG ICE PLUG AT 52' MD FILL CONDUCTOR AND CHECK FOR LEAKS PRESSURE TEST SURFACE LINES TO 3500 PSI (VISUAL LEAK TIGHT) MAKE UP STANDS OF HWDP 20:00 22:00 2.00 DRILL P -0.67 SURF MAKE UP 13-1/2" KYMERA BIT, MOTOR AND STAB TO 3T MD PICK UP STAND OF 5" DP CLEAN OUT CONDUCTOR TO 158' MD WITH 420 GPM, 350 PSI, 30 RPM, 1 KFT-LBS - TORQUE 2200 0000 2.00 DRILL P -0.67 SURF RACK BACK STAND AND CONTINUE MAKING UP BHATO 112' MD - PLUG IN AND SURFACE TEST MWD AND GWD 12/14/2019 00:00 02:00 2.00 DIVRTR P -0.67 SURF FINISH TESTING MWD/GWD AND BUILD BHA TO 147' MD 02:00 12:00 10.00 DRILL P 1,037.33 SURF DRILL 13-1/2" SURFACE HOLE FROM THE BOTTOM OF THE CONDUCTOR AT 158' MD TO 1038' MD 880' IN 10 HRS = 88 FPH WITH CONNECTIONS UP TO 300 FPH INSTANTANEOUS ROP 550 GPM, 1350 PSI ON BOTTOM, 1300 PSI OFF BOTTOM - 50 RPM, 3 KFT-LBS TORQUE ON BOTTOM, 2 KFT-LBS TORQUE OFF BOTTOM, 10 KLBS WOB PU 95 KLBS, SO 91 KLBS, ROT 92 KLBS SURVEY EVERY 90' WITH GWD MUD WEIGHT IN/OUT = 8.6 PPG 1200 21:00 9.00 DRILL P 1,986.33 SURF DRILL 13-1/2" SURFACE HOLE FROM 1038' MD TO 1987' MD - 948' IN 9 HRS = 105 FPH WITH CONNECTIONS UP TO 300 FPH INSTANTANEOUS ROP 550 GPM, 1600 PSI ON BOTTOM, 1450 PSI OFF BOTTOM - 50 RPM, 5 KFT-LBS TORQUE ON BOTTOM, 3 KFT-LBS TORQUE OFF BOTTOM, 10 KLBS WOB PU 60 KLBS, SO 60 KLBS, ROT 60 KLBS SURVEY EVERY 90' WITH GWD MUD WEIGHT IN/OUT = 8.6 PPG STARTED GETTING CLEAN MWD SURVEYS AT 1416' MD BIT DEPTH BPRF OBSERVED AT 1954' MD 21:00 21:30 0.50 DRILL P 1,986.33 SURF CIRCULATE BOTTOMS UP 550 GPM, 1500 PSI 30 RPM, 3 KFT-LBS TORQUE RACK BACK 1 STAND TO 1895' MD Printed 1/8/2020 11:26:40AM "All dephts reported in Drillers Dephts" Printed 1/8/2020 11:26:40AM **All dephts reported in Drillers Dephts** North America - ALASKA - BP Page 3 of 14 Operation Summary Report Common Well Name: 5-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 21:30 - 23:00 1.50 DRILL P 1,986.33 SURF PULL OUT OF THE HOLE FOR PLANNED SHORT TRIP FROM 1895MD TO THE TOP OF THE BHAAT 210' MD - MONITOR WELL FOR 10 MIN PRIOR TO PULLING OFF BOTTOM AND AT THE TOP OF THE BHA (STATIC) - OBSERVE TIGHT HOLE AT 11 50'MD, WORK THROUGH TIGHT HOLE WITH 50 KLBS OVERPULL, WIPE TIGHT SPOT WITH NO ISSUES 23:00 00:00 1.00 DRILL P 1,986.33 SURF RUN IN THE HOLE FROM THE TOP OF THE BHAAT 210' MD TO 1500' MD 12/15/2019 00:00 01:00 1.00 DRILL P 1,986.33 SURF RUN IN THE HOLE FROM 1500' MD TO BOTTOM AT 1987' MD 01:00 12:00 11.00 DRILL P 2,859.33 SURF DRILL 13-1/2" SURFACE HOLE FROM 1987' MD 'TO 2860' MD - 873' IN 11 HRS = 79 FPH WITH CONNECTIONS UP TO 300 FPH INSTANTANEOUS ROP 630 GPM, 1840 PSI ON BOTTOM, 1720 PSI OFF BOTTOM - 55 RPM, 5 KFT-LBS TORQUE ON BOTTOM, 4 KFT-LBS TORQUE OFF BOTTOM, 10 KLBS WOB PU 135 KLBS, SO 115 KLBS, ROT 125 KLBS SURVEY EVERY 90' WITH GWD MUD WEIGHT IN/OUT = 9.2 PPG 12:00 14:30 2.50 DRILL P 2,859.33 SURF CIRCULATE HOLE CLEAN WITH 3X BOTTOMS UP 650 GPM, 1812 PSI 55 RPM, 4 KFT-LBS TORQUE RACK BACK STAND EVERY 20 MIN TO 2451' MD 1430 15:00 0.50 DRILL P 2,859.33 SURF PULL OUT OF THE HOLE ON ELEVATORS FROM 2451' MD TO THE LAST TRIP DEPTH AT 1987MD - MONITOR WELL FOR 10 MIN PRIOR TO PULLING OFF BOTTOM (STATIC) - NO ISSUES PULLING THROUGH OPEN HOLE 15:00 15:30 0.50 DRILL P 2,859.33 SURF RUN IN THE HOLE ON ELEVATORS FROM 1987' MD TO BOTTOM AT 2860' MD - NO ISSUES RUNNING THROUGH OPEN HOLE 15:30 17:00 1.50 DRILL P 2,859.33 SURF CIRCULATE HOLE CLEAN WITH 1.5X BOTTOMS UP 650 GPM, 1800 PSI 55 RPM, 3 KFT-LBS TORQUE 17:00 19:00 2.00 DRILL P 2,859.33 SURF PULL OUT OF THE HOLE ON ELEVATORS FROM 2451' MD TO THE TOP OF THE BHAAT 210' MD - MONITOR WELL FOR 10 MIN PRIOR TO PULLING OFF BOTTOM AND AT THE TOP OF THE BHA (STATIC) NO ISSUES PULLING THROUGH OPEN HOLE 19:00 21:30 2.50 DRILL P 2,859.33 SURF LAY DOWN BHA FROM 210' MD TO SURFACE BIT GRADE: 1 -1 -IN GAUGE 21:30 22:00 0.50 DRILL P 2,859.33 SURF CLEAN AND CLEAR RIG FLOOR Printed 1/8/2020 11:26:40AM **All dephts reported in Drillers Dephts** Printed 1/8/2020 11:26:40AM "All dephts reported in Drillers Dephts" North America - ALASKA - BP Page 4 of 14 Operation Summary Report Common Well Name: S-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 22:00 - 00:00 2.00 CASING P 2,859.33 SURF RIG UP TO RUN 10-3/4" X 9-5/8" SURFACE CASING - VOLANT CRT, BAIL EXTENSIONS, ELEVATORS, DOUBLESTACK TONGS WITH TORQUETURN 12/16/2019 00:00 01:00 1.00 CASING P 2,859.33 SURF FINISH RIGGING UP CASING RUNNING EQUIPMENT 01:00 13:00 12.00 CASING P 2,859.33 SURF RUN 10-3/4" X 9-5/8",45.5# X 47#, L-80, VAM21 SURFACE CASING TO PLANNED SET DEPTH AT 2853' MD CHECK FLOATS USE JET LUBE SEAL GUARD PIPE DOPE TORQUE TURN 9-5/8" CONNECTIONS TO 31,550 FT -LBS - TORQUE TURN 10-3/4" CONNECTIONS TO 26,250 FT -LBS - FILL ON THE FLY AND TOP OFF EVERY 10 JOINTS OBTAIN PU/SO WEIGHTS EVERY 10 JOINTS FINAL PU 143K, SO 97K MUD WEIGHT: 9.2 PPG IN, 9.2 PPG OUT 13:00 17:00 4.00 CASING P 2,859.33 SURF CONDITION MUD TO CEMENTING PROPERTIES 10 BPM, 454 PSI RECIPROCATE PIPE 15' Printed 1/8/2020 11:26:40AM "All dephts reported in Drillers Dephts" North America - ALASKA - BP Page 5 of 14 Operation Summary Report Common Well Name: S-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) - - - 17:00 20:30 3.50 CASING P 2,859.33 SURF CEMENT 10-3/4" X 9-5/8" SURFACE CASING AS FOLLOWS: FILL LINES WITH WATER AND PRESSURE TEST TO 3500 PSI FOR 5 MINUTES PUMP 100 BBLS OF 10 PPG MUDPUSH II SPACER @ 5 BPM, 300 PSI RELEASE BOTTOM PLUG KICK OUT PLUG WITH 10 BBL OF FRESH WATER - PUMP 490 BBLS OF 11 PPG LITECRETE LEAD CEMENT @ 5.5 BPM, EXCESS VOLUME 350% ABOVE BPRF AND 40% BELOW BPRF (YIELD 1.91 CU.FT/SK) - PUMP 70 BBLS OF 15.8 PPG CLASS G TAIL @ 5.5 BPM, EXCESS VOLUME 40% (YIELD 1.16 CU-FT/SK) DROP TOP PLUG RECIPROCATED PIPE 15 FT AT SURFACE WHILE PUMPING LEAD CEMENT, LAND CASING TO BATCH UP TAIL, UNABLE TO MOVE PIPE AFTER BATCHING UP TAIL PERFORM DISPLACEMENT WITH RIG PUMPS AND 9.2 PPG MAX-DRIL MUD 180 BBLS DISPLACED AT 10 BPM: ICP 460 PSI, FCP 620 PSI, CATCH CEMENT AT 92 BBL INTO DISPLACEMENT 60 BBLS DISPLACED AT 7 BPM: ICP 400 PSI, FCP 760 PSI 5.6 BBLS DISPLACED AT 3 BPM: ICP 560 PSI, FCP 575 PSI REDUCE RATE TO 3 BPM PRIOR TO PLUG BUMP: FINAL CIRCULATING PRESSURE 575 PSI - BUMP PLUG AND INCREASE PRESSURE TO 1000 PSI, BLEED OFF AND CHECK FLOATS - HOLDING - CEMENT IN PLACE (CIP) @ 20:21 ON 12/16/2019 - TOTAL DISPLACEMENT VOLUME 255.6 BBLS (MEASURED BY STROKES @ 96% PUMP EFFICIENCY) OBSERVE -200 BBL OF CEMENT RETURNS TO SURFACE TOTAL LOSSES: 30 BBLS 2030 2200 1.50 CASING P 2,859.33 SURF CLEAN UP AFTER CEMENT JOB FLUSH DIVERTER RISER AND ANNULAR DUMP AND CLEAN PITS _ -LAY DOWN LANDING JOINT 22:00 00:00 2.00 BOPSUR P 2,859.33 SURF NIPPLE DOWN DIVERTER SYSTEM NIPPLE DOWN 16' DIVERTER LINE FROM BACK OF BOP DECK BREAK BOLTS ON RISER AND DIVERTER !ANNULAR NIPPLE DOWN KNIFE VALVE AND DIVERTER 'ANNULAR MOBILIZE WELLHEAD TO BOP DECK NIPPLE DOWN RISER SIMOPS: CLEAN PITS RIG DOWN VOLANT TOOL Printed 1/8/2020 11:26 40AM **All dephts reported in Drillers Dephts" North America - ALASKA - BP Operation Summary Report Common Well Name: S-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Contractor: PARKER DRILLING CO. Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Rig Release: 2/25/2019 BPUOI: Page 6 of 14 Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations -- --- - (hr) -�-- - - (usft) 12/17/2019 00:00 04:30 4.50 BOPSUR P 2,860.00 SURF CONTINUE TO NIPPLE DOWN THE DIVERTER ISYSTEM 04:30 08:00 3.50 BOPSUR P 2,860.00 SURF NIPPLE UP FMC GEN 5 WELLHEAD PER FMC REPRESENTATIVE CLEAN AND STEAM SPEED HEAD AND CASING SPOOL ORIENT AND INSTALL WELLHEAD -TQ CSG HEAD X TBG SPOOL FLANGE -TQ CSG HEAD TO HANGER INSTALL OA VALVES & DBL BLOCK IA/OA VALVES -TEST VOID TO 1000 PSI 1 08:00 12:00 4.00 BOPSUR P 2,860.00 SURF NIPPLE UP BOP STACK NIPPLE UP HIGH PRESSURE RISER AND SPACER SPOOL NIPPLE UP BOP STACK NIPPLE UP FLOW RISER ATTACH TURNBUCKLES AND HOLE FILL LINES INSTALL MOUSEHOLE NIPPLE UP CHOKE LINE 12:00 13:00 1.00 BOPSUR P 2,860.00 SURF RIG UP TO TEST BOPE SET TEST PLUG BLEED AIR FROM SYSTEM 13:00 18:00 5.00 BOPSUR P 2,860.00 SURF PRESSURE TEST BOPE TO 250 PSI LOW AND 4000 PSI HIGH FOR 5 MIN EACH - TEST ANNULAR TO 3500 PSI ON HIGH SIDE TEST WITH 5" AND 3-1/2" TEST JOINTS TEST PVT AND FLOW ALARMS _ TEST WITNESSED BY AUSTIN MCLEOD 18:00 19:00 1.00 BOPSUR P 2,860.00 SURF RIG DOWN TESTING EQUIPMENT PULL TEST PLUG AND SET WEAR BUSHING .(9" ID) 19:00 21:30 2.50 DRILL P 2,860.00 SURF MAKE UP 8-1/2" PRODUCTION HOLE BHA TO 68' MD PLUG IN TO MWD/LWD PULL BHA OUT OF THE HOLE 21:30 22:30 1.00 CASING P 2,860.00 SURF CLOSE THE BLINDS AND PRESSURE TEST SURFACE CASING TO 4000 PSI FOR 30 MIN (PASS) TEST APPROVED BY WOS (WSUP DOA) SIMOPS: SURFACE TEST THE MWD/LWD/AUTOTRACK 22:30 00:00 1.50 DRILL P 2,860.00 SURF FINISH MAKING UP BHA TO TOTAL LENGTH OF 167' MD 12/18/2019 00 00 0200 200 DRILL P 2,860.00 SURF RUN IN THE HOLE FROM THE TOP OF THE BHAAT 167' MD TO THE TOP OF CEMENT AT 2717' MD - SHALLOW HOLE TEST MWD AT 800' MD: GOOD FILL PIPE EVERY 1500' MD WASH DOWN THE LAST STAND AT 2 BPM, 300 PSI - TAG TOP OF CEMENT AT 2717' MD - MONITOR WELL WITH HOLE FILL AND TRIP TANK WHILE RUNNING IN: GOOD DISPLACEMENT - MUD WEIGHT IN/OUT = 9.3 PPG Printed 1/8/2020 11 26:40AM **All dephts reported in Drillers Dephts" North America - ALASKA - BP Page 7 of 14 Operation Summary Report Common Well Name: 5-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU - Site: S - - Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date I From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr)(usft) 02:00 - 04.30 2.50 DRILL P 2,86000 SURF DRILL CEMENTAND FLOAT COLLAR FROM 2717 MD TO 2843' MD (10' FROM SHOE) 500 GPM, 1500 PSI 60 RPM, 4.5 KFT-LBS TORQUE 04:30 - 05:30 1.00 DRILL P 2,860.00 SURF DISPLACE WELL TO 9.2 PPG LSND 500 GPM, 1200 PSI 60 RPM, 3.5 KFT-LBS TORQUE MONITOR WELL FOR 10 MIN: STATIC 05:30 - 06:00 0.50 DRILL P 2,860.00 SURF CONTINUE TO DRILL OUT SHOE TRACK FROM 2843' MD TO 2860' MD 500 GPM AT 1186 PSI 60 RPM, 4.5 KFT-LBS TORQUE, 10 KLBS WOB MUD WEIGHT IN/OUT = 9.2 PPG MONITOR WELL FOR 10 MIN AFTER DRILLING SHOE: STATIC 06:00 06:30 0.50 DRILL P 2,880.00 SURF DRILL 20' OF NEW HOLE TO 2880' MD AND CIRCULATE HOLE CLEAN 600 GPM, 1208 PSI i MUD WEIGHT IN/OUT = 9.2 PPG 106:30 - 08:00 1.50 DRILL P 2,880.00 SURF RIG UPAND PERFORM FIT 9-5/8" SHOE AT 2853' MD, 2830' TVD MUD WEIGHT IN/OUT = 9.2 PPG PRESSURE UP TO 570 PSI FIT EMW = 13.0 PPG ODE APPROVED FIT 08.00 12:00 4.00 DRILL P t 3,803.00 PROD1 DIRECTIONALLY DRILL 8-1/2" PROD HOLE ROM 2880' MD TO 3083' MD 923 FT IN 4 HRS: 230.8 FT/HR ROP WITH CONNECTIONS 550 GPM, 1445 PSI ON/OFF BOTTOM 120 RPM, 4 KFT-LBS TORQUE ON, 3 KFT-LBS TORQUE OFF, UP TO 12 KLBS WOB PU 124 KLBS, SO 108 KLBS, ROT 115 KLBS SURVEY EVERY 90', NO BACK REAMING AT CONNECTIONS MUD WEIGHT IN/OUT = 9.2 PPG GASWATCH BACKGROUND RANGE = 95 UNITS, MAX AT 531 UNITS 12.00 00:00 12.00 DRILL P 4,450.00 PROD1 DIRECTIONALLY DRILL 8-1/2" PROD HOLE FROM 3083' MD TO 4450' MD, 4215' TVD 1367 FT IN 12 HRS: 113.9 FT/HR ROP WITH CONNECTIONS 550 GPM, 1820 PSI ON/OFF BOTTOM 120 RPM, 6 KFT-LBS TORQUE ON, 5 KFT-LBS TORQUE OFF, UP TO 12 KLBS WOB PU 163 KLBS, SO 121 KLBS, ROT 131 KLBS SURVEY EVERY 90', NO BACK REAMING AT CONNECTIONS MUD WEIGHT IN/OUT = 9.2+ PPG GASWATCH BACKGROUND RANGE = 270 'UNITS, MAX AT 3273 UNITS PUMP 35 BBL HIGH VIS SWEEP AT 3380' MD, 75% INCREASE IN CUTTINGS BACK AT (SHAKERS PUMP 35 BBL HIGH VIS SWEEPAT 3840' MD, 50% INCREASE IN CUTTINGS BACKAT SHAKERS PUMP 35 BBL HIGH VIS SWEEPAT 4320' MD, 100% INCREASE IN CUTTINGS BACKAT SHAKERS Printed 1/8/2020 11 26 40AM **All dephts reported in Drillers Dephts** North America - ALASKA - BP Page 8 of 14 Operation Summary Report Common Well Name: S-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 —-— -- Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM I Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 12/19/2019 00:00 12:00 12.00 DRILL P 5,291.00 PROD1 DIRECTIONALLY DRILL 8-1/2" PROD HOLE FROM 4450' MD TO 5291' MD, 4969' TVD 641 FT IN 12 HRS: 70.1 FT/HR ROP WITH CONNECTIONS 500-550 GPM, 1750-1823 PSI ON/OFF BOTTOM 75-120 RPM, 6-11 KFT-LBS TORQUE ON, 5-8 KFT-LBS TORQUE OFF, UP TO 12 KLBS WOB PU 189 KLBS, SO 125 KLBS, ROT 141 KLBS SURVEY EVERY 90', NO BACK REAMING AT CONNECTIONS MUD WEIGHT IN/OUT = 9.2+ PPG GASWATCH BACKGROUND RANGE = 130 UNITS, MAX AT 667 UNITS 4450'- 4460' MD & 4509'- 4534' MD: PACKING OFF AND TORQUING UP: PICK UP AND WORK FLOW RATE AND RPM BACK TO DRILLING RATE BEFORE RESEATING BIT SIGNIFICANT AMOUNT OF COAL CUTTINGS BACK AT SHAKER i PUMP 35 BBL HIGH VIS SWEEP AT 4972' MD, '50% INCREASE IN CUTTINGS BACKAT SHAKERS 12 00 1900 7.00 DRILL P 6,050.00 PROD1 DIRECTIONALLY DRILL 8-1/2" PROD HOLE FROM 5291' MD TO SECTION TD AT 6050' MD, 5509'TVD 759 FT IN 7 HRS: 108.4 FT/HR ROP WITH CONNECTIONS 550 GPM, 2050 PSI ON/OFF BOTTOM 120 RPM, 11 KFT-LBS TORQUE ON, 9 KFT-LBS TORQUE OFF, UP TO 15 KLBS WOB PU 220 KLBS, SO 127 KLBS, ROT 151 KLBS SURVEY EVERY 90', NO BACK REAMING AT CONNECTIONS MUD WEIGHT IN/OUT = 9.2+ PPG GASWATCH BACKGROUND RANGE = 150 UNITS, MAX AT 669 UNITS PUMP 35 BBL HIGH VIS SWEEP AT 5448' MD, 100% INCREASE IN CUTTINGS BACK AT SHAKERS PUMP 35 BBL HIGH VIS SWEEP AT 6050' MD, 25% INCREASE IN CUTTINGS BACKAT SHAKERS 19:00 2030 1.50 DRILL P 6,050.00 PROD1 CIRCULATE 2x BOTTOMS UP AT TD 550 GPM, 1900 PSI 120 RPM, 10 KFT-LBS TORQUE PU 200 KLBS, SO 127 KLBS MUD WEIGHT IN/OUT = 9.2+ PPG Printed 1/6/2020 11 26:40AM ~*All dephts reported in Drillers Dephts" North America - ALASKA - BP Operation Summary Report Page 9 of 14 Common Well Name: S-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Site: S Project: PBU Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00 OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 20:30 - 21:30 1.00 DRILL --P 6,050.00 PROD1 PLANNED WIPER TRIP: PULL OUT OF THE HOLE ON ELEVATORS FROM 6050' MD TO 4392' M D - MONITOR WELL FOR 15 MIN PRIOR TO PULLING OFF BOTTOM: STATIC PU 175 KLBS, SO 120 KLBS AT 4400' MD MUD WEIGHT IN/OUT = 9.2+ PPG MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE PULLING: GOOD FILL PULL 35 KLBS OVER AT 4392' MD SEVERAL TIMES STAGE UP PUMPS TO 2 BPM AND ATTEMPT 1_ TO PULL THROUGH WITH 30 KLBS OVERPULL 21:30 00:00 2.50 DRILL P 6,050.00 PROD1 'PLANNED WIPER TRIP: BACKREAM OUT OF THE HOLE FROM 4392' MD TO 3650' MD 550 GPM, 1700-2100 PSI 120 RPM, 2-14 KFT-LBS TORQUE VARY BACKREAMING SPEEDS TO MANAGE PACK -OFFS AND TORQUING UP. SIGNIFICANT AMOUNT OF COALAT SHAKERS 12/20/2019 00:00 - 02:30 2.50 DRILL P 6,050.00 PROD1 PLANNED WIPER TRIP: BACKREAM OUT OF THE HOLE FROM 3650' MD TO 2802' MD, INSIDE 9-5/8" CASING SHOE 550 GPM, 1700-2100 PSI 120 RPM, 8-10 KFT-LBS TORQUE VARY BACKREAMING SPEEDS TO MANAGE PACK -OFFS AND TORQUING UP. I SIGNIFICANT AMOUNT OF COALAT SHAKERS SIMOPS: LOAD HALLIBURTON PRIMARY AND -- BACK-UP RDT LOGGING TOOLS IN PIPE SHED 0230 03.00 0.50 DRILL PP 6,050.00 �PROD1 CIRCULATE HOLE CLEAN AT 9-5/8" CASING SHOE WITH 1.5x BOTTOMS UP 600 GPM, 1685 PSI MUD WEIGHT IN/OUT = 9.2+ PPG 03.00 0500 2.00 DRILL P 6,050 00 PROD1 PLANNED WIPER TRIP: RUN IN THE HOLE ON ELEVATORS WITH 8-1/2" DRILLING ASSEMBLY FROM 2850' MD TO TD AT 6050' MD MONITOR WELL FOR 15 MIN: STATIC PU 119 KLBS, SO 106 KLBS AT 2850' MD FILL PIPE EVERY 2000' MD MUD WEIGHT IN/OUT = 9.2+ PPG MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE RUNNING IN: GOOD DISPLACEMENT NO HOLE ISSUES WHILE RUNNING IN SIMOPS: - SPOT HALLIBURTON E -LINE UNIT FOR UPCOMING RDT LOGGING RUNS 05:00 0630 1.50 DRILL P 6,050.00 PROD1 CIRCULATE HOLE CLEAN AT TD WITH 2.5x BOTTOMS UP 550 GPM, 1780 PSI 120 RPM, 10 KFT-LBS TORQUE MUD WEIGHT IN/OUT = 9.2+ PPG Printed 1/8/2020 11 26 40AM **All dephts reported in Drillers Dephts** Printed 1/8/2020 11 26 40A `*All dephts reported in Drillers Dephts" North America - ALASKA - BP Page 10 of 14 Operation Summary Report Common Well Name: S-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 06:30 08:00 1 1.50 DRILL P 6,050.00 PROD1 PULL OUT OF THE HOLE ON ELEVATORS WITH 8-1/2" DRILLING ASSEMBLY FROM 6050' MD TO INSIDE 9-5/8" CASING SHOE AT 2850' MD - MONITOR WELL FOR 10 MIN PRIOR TO PULLING OFF BOTTOM: STATIC PU 185 KLBS, SO 125 KLBS AT 6050' MD MUD WEIGHT IN/OUT = 9.2+ PPG MONITOR WELL WITH HOLE FILL AND TRIP TANK WHILE PULLING: GOOD FILL NO OVERPULLS OR HOLES ISSUES NOTED WHILE PULLING OUT _ 08:00 09:30 1.50 DRILL P 6,050.00 PROD1 PULL OUT OF THE HOLE ON ELEVATORS I WITH 8-1/2" DRILLING ASSEMBLY FROM 2850' MD TO TOP OF THE BHAAT 812' MD - MONITOR WELL FOR 10 MIN AT THE 9-5/8" SHOE: STATIC MUD WEIGHT IN/OUT = 9.2+ PPG MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE PULLING: GOOD FILL MONITOR WELL FOR 10 MIN AT THE TOP OF - THE BHA: STATIC 0930 1200 2.50 DRILL P 6,050.00 PROD1 PULLAND LAY DOWN 8-1/2" DRILLING ASSEMBLY FROM 812' MD PER BAKER DD / MWD LAY DOWN ALL COMPONENETS TO PIPE SHED DULL BIT GRADE: 3 - 1 - CT - N - X - I - BT - TD CLEAN AND CLEAR RIG FLOOR 12:00 18:00 6.00 EVAL P 6,050.00 PROD1 RIG UP HALLIBURTON E -LINE MAKE UP AND VERIFY RDT LOGGING TOOL STRING TO 195' 18:00 2000 2-00 EVAL P 6,050.00 PROD1 RUN IN THE HOLE WITH HALLIBURTON RDT LOGGING TOOLS ON E -LINE FROM 195' MD TO 5600' MD 2000 00:00 4.00 EVAL P 6,050.00 PROD1 OPEN HOLE RDT LOGGING WITH HALLIBURTON TIE-IN TO REAL TIME LOG AND PERFORM FORMATION PRESSURE LOGGING PER RDT LOGGING PROGRAM STATIONS #1-4 BETWEEN DEPTHS 5351' MD 5428' MD 12/21/2019 00:00 06:00 6.00 EVAL P 6,050.00 PROD1 OPEN HOLE RDT LOGGING WITH HALLIBURTON PERFORM FORMATION PRESSURE LOGGING PER RDT LOGGING PROGRAM - STATIONS #5-21 BETWEEN DEPTHS 5455'- 5757' 0600 12:00 t 6.00 EVAL N 6,050.00 PROD1 TROUBLESHOOT AND REPAIR POWER ISSUES WITH HALLIBURTON LOGGING EQUIPMENT 12:00 14:00 2.00 EVAL P 6,050.00 PROD1 OPEN HOLE RDT LOGGING WITH HALLIBURTON COMPLETE FORMATION PRESSURE LOGGING PER RDT LOGGING PROGRAM STATIONS #22-24 BETWEEN DEPTHS 5768' MD - 5859' - TOTAL OF 24 SAMPLE LOCATIONS BETWEEN 535V AND 5859' Printed 1/8/2020 11 26 40A `*All dephts reported in Drillers Dephts" Printed 1/8/2020 11:26:40AM "All dephts reported in Drillers Dephts" North America - ALASKA - BP Page 11 of 14 Operation Summary Report Common Well Name: S-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2,00 OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 14:00 00:00 10.00 EVAL P 6,050.00 PROD1 OPEN HOLE RDT LOGGING WITH HALLIBURTON PERFORM FORMATION FLUID SAMPLING PER RDT LOGGING PROGRAM SAMPLE LOCATION #1 IN THE OBd SAND ATTEMPTAT 5762' AND 5748' AND UNABLE TO GET THE SAMPLE - ABLE TO GET REQUIRED SAMPLE ON THIRD ATTEMPT, AT 5750.5' 12/22/2019 00 00 03:00 3.00 EVAL N 6,050.00 PROD1 PULL BACK TO THE 9-5/8" SHOE AND TROUBLESHOOT HALLIBURTON UNIT - EXHAUST SYSTEM REGENERATION REQUIRED RUN BACK IN THE HOLE AND RE- TIE-IN 03.00 13 30 10.50 EVAL P 6,050.00 PROD1 OPEN HOLE RDT LOGGING WITH HALLIBURTON PERFORM FORMATION FLUID SAMPLING PER RDT LOGGING PROGRAM SAMPLE LOCATION #2 IN THE OBc SAND AT 5700' - ATTEMPT SEVERAL TIMES WITH STRADDLE PACKERS, UNABLE TO FULLY INFLATE STRADDLE PACKER DUE TO SEDIMENT CLOGGING MOVE UP TO SAMPLE LOCATION #3 IN THE OBb SAND AT 5643' MD UTILIZE OVAL PAD PROBE AND OBTAIN REQUIRED SAMPLES 1330 21 30 8.00 EVAL N 6,050.00 PROD1 PULL OUT OF THE HOLE WITH RDT LOGGING TOOLS - RECOVER 4 SAMPLE BOTTLES AND REPLACE 2 WITH CLEAN MUD FOR INFLATING STRADDLE PACKER RUN BACK IN THE HOLE WITH RDT LOGGING TOOLS TO 9-5/8" CASING SHOE AND PERFORM A PREVENTATIVE EXHAUST SYTEM REGEN ON LOGGING UNIT CONTINUE IN THE HOLE TO NEXT SAMPLE STATION IN THE OBa SAN AND RE- TIE-IN TO GAMMA LOG 21:30 00:00 2.50 EVAL P 6,050.00 PROD1 OPEN HOLE RDT LOGGING WITH HALLIBURTON PERFORM FORMATION FLUID SAMPLING PER RDT LOGGING PROGRAM - SAMPLE LOCATION #3 IN THE OBa SAND AT 5593' 12/23/2019 00:00 - 04:00 4.00 EVAL P 6,050.00 PROD1 OPEN HOLE RDT LOGGING WITH HALLIBURTON PERFORM FORMATION FLUID SAMPLING PER RDT LOGGING PROGRAM - SAMPLE LOCATION #3 IN THE OBa SAND AT 5593' 04:00 06:30 2.50 EVAL N 6,050.00 PROD1 PULL BACK TO THE 9-5/8" SHOE AND PERFORM EXHAUST SYSTEM REGENERATION ON HALLIBURTON UNIT RUN BACK IN THE HOLE AND RE- TIE-IN Printed 1/8/2020 11:26:40AM "All dephts reported in Drillers Dephts" North America - ALASKA - BP Operation Summary Report Page 12 of 14 Common Well Name: S-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 06:30 - 12:30 6.00 EVAL P 6,050.00 PROD1 OPEN HOLE RDT LOGGING WITH HALLIBURTON PERFORM FORMATION FLUID SAMPLING PER RDT LOGGING PROGRAM 12:30 - 16:30 4.00 16:30 - 00:00 7.50 EVAL N EVAL 12/24/2019 0000 - 01:00 1.00 EVAL P P 01:00 - 11:30 10.50 EVAL N SAMPLE #4 IN THE OA SAND AT 5569.72' - ATTEMPT SEVERAL TIMES WITH OVAL PAD PROBE, UNABLE TO GET SEAL - MOVE DOWN V AND ATTEMPT AGAIN WITHOUT SUCCESS - MOVE TO STATION AT 5455' MD AND ATTEMPT WITHOUT SUCESS 6,050.00 PROD1 PULL BACK TO THE 9-5/8" SHOE AND PERFORM EXHAUST SYSTEM REGENERATION ON HALLIBURTON UNIT RUN BACK IN THE HOLE AND RE- TIE-IN 6,050.00 PROD1 OPEN HOLE RDT LOGGING WITH HALLIBURTON PERFORM FORMATION FLUID SAMPLING PER RDT LOGGING PROGRAM SAMPLE LOCATION #4 IN THE OA SAND AT 5569.42' - ULTILIZE STRADDLE PACKERS TO OBTAIN SAMPLE - CONTAMINATION AT 5% AND BEGIN FILLING BOTTLES AT 23:30 HRS 6,050.00 PROD1 OPEN HOLE RDT LOGGING WITH HALLIBURTON PERFORM FORMATION FLUID SAMPLING PER RDT LOGGING PROGRAM SAMPLE LOCATION #4 IN THE OA SAND AT 5569.42' - FINISH FILLING SAMPLE BOTTLES - COMPLETE PRESSURE BUILD-UP PER PROCEDURE -DEFLATE STRADDLE PACKERS 6,050.00 PROD1 ATTEMPT TO PULL HALLIBURTON RDT TOOLS FREE WITH E -LINE PER HALLIBURTON ENGINEERS - FIRE E -LINE JARS 1x, UNABLE TO RESET JARS VERIFY PACKERS DEFLATED CYCLE PUMPS AND ATTEMPT TO USE OVAL PAD TO FREE RDT TOOL STRING DISCUSS WITH ODE AND NOTIFY SLB FISHING REPRESENTATIVES CONTINUE TO PULL WITH E -LINE WHILE WAITING ON SLB FISHING DISCONNECT E -LINE FROM LOGGING TOOLS PER HALLIBURTON PROCEEDURE AND PULL OUT OF THE HOLE WITH HALLIBURTON E -LINE Printed 1/8/2020 11:26:40AM **All dephts reported in Drillers Dephts** North America - ALASKA - BP Operation Summary Report Page 13 of 14 Common Well Name: S-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) _ 11:30 15:00 3.50 FISH N 6,050.00 PROM MAKE UP AND RUN IN THE HOLE WITH FISHING ASSEMBLY TO FISH RDT LOGGING TOOLS MAKE UP 8-1/8" OVERSHOT DRESSED TO CATCH 3-5/8", OVERSHOT EXTENSIONS, PUMP -OUT SUB AND JARS RUN IN THE HOLE TO 4858' MD ON ELEVATORS MUD WEIGHT IN/OUT = 9.3 PPG MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE RUNNING IN: GOOD DISPLACEMENT SET DOWN 20 KLBS (3X) AT 4858' MD - STAGE UP PUMPS TO WASH DOWN: 4 BPM, 350 PSI, 60 RPM, 5 KFT-LBS TORQUE r 15.00 16 30 1.50 FISH ,050.00 N 6PROD1 WASH DOWN FROM 4858' TO 5414' MD 4 BPM, 400 PSI, 10 RPM, 6 KFT-LBS TORQUE PU 162 KLBS, SO 130 KLBS, ROT 138 KLBS AT 5400' MD TAG TOP OF FISH AT 5414_' MD WITH 20 KLBS_ 1630 1830 2.00 FISH N 6,050.00 PROD1 CHASE DOWN FROM 5414' MD TO 5570' MD AND ENGAGE FISH PUSH FISH DOWN TO 5570' MD ENGAGE FISH WITH 25 KLBS DOWN II PULL 30 KLBS OVER WITH FISH ON WORK FROM 30 KLBS - 58 KLBS IN 5 KLB INCREMENTS TO PULL FISH FREE - ADDITIONAL 9-10 KLBS STRING WEIGHT WITH FISH ON MONITOR WELL FOR 10 MIN: STATIC 18:30 2230 4.00 FISH N 6,050.00 PROD1 PULLOUT OF THE HOLE ON ELEVATORS WITH WITH FISHING ASSEMBLY AND FISH FROM 5570' MD TO 250' MD MUD WEIGHT IN/OUT = 9.3 PPG MONITOR WELL FOR 10 MIN AT 9-5/8" CASING SHOE: STATIC PERFORM WEEKLY BOP FUNCTION TEST 22 30 00 00 1.50 FISH N 6,050.00 PROD1 LAY DOWN FISHING BHAAND RDT LOGGING TOOLS PER SLB FISHING REPAND HALLIBURTON LOGGING REP - LAY DOWN OVERSHOT WITH CABLE HEAD, SWIVEL AND JARS TO PIPE SHED - LAY DOWN ALL OF RDT TOOLS PER - HALLIBURTON 12/25/2019 00:00 01 00 1.00 FISH N 6,050.00 PROD1 CONTINUE TO LAY DOWN RDT LOGGING TOOLS PER HALLIBURTON LOGGING REP 01:00 03:00 200 CLEAN P 6,050.00 PROD1 MAKE UP AND RUN IN THE HOLE WITH 8-1/2" CLEAN OUTASSEMBLY PER BAKER DD TO 765' MD - 8-1/2" MILL -TOOTH BIT, BIT SUB, (4) 8-3/8" OD STABILIZERS ALTERNATED BETWEEN DRILL COLLARS MUD WEIGHT IN/OUT = 9.3 PPG MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE RUNNING IN: GOOD DISPLACEMENT Printed 1/8/2020 11.26:40AM **All dephts reported in Drillers Dephts** Printed 1/8/2020 11:26:40AM **All dephts reported in Drillers Dephts** North America - ALASKA - BP Page 14 of 14 Operation Summary Report Common Well Name: S-210 Event Type: DRL- ONSHORE (DON) Start Date: 2/12/2019 End Date: 2/25/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 03:00 04:00 1.00 CLEAN P 6,050.00 PROD1 RUN IN THE HOLE WITH 8-1/2" CLEAN OUT ASSEMBLY ON 5" DRILL PIPE FROM 765' MD TO 2650' MD FILL PIPE EVERY 2000' MD MUD WEIGHT IN/OUT = 9.3 PPG MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE RUNNING IN: GOOD DISPLACEMENT 0400 0500 1.00 CLEAN P 6,050.00 PROD1 CUTAND SLIP 102' OF DRILLING LINE, CALIBRATE BLOCKS 0500 0700 2.00 CLEAN P 6,050.00 PROD1 RUN IN THE HOLE WITH 8-1/2" CLEAN OUT ASSEMBLY ON 5" DRILL PIPE FROM 2650' MD TO 6050' MD FILL PIPE EVERY 2000' MD MUD WEIGHT IN/OUT = 9.3 PPG MONITOR WELL WITH HOLE FILLAND TRIP TANK WHILE RUNNING IN: GOOD DISPLACEMENT -TAG TIGHT SPOT @ 5568'(25K), ATTEMPT TO WORK PAST WITHOUT SUCCESS. -WASH AND REAM THROUGH AREA WITH 550 GPM 1160 PSI 60 RPM 9K TORQ -20' OF FILL ON BOTTOM, WASH FROM 6030' TO 6050' 07:00 09:00 2.00 CLEAN P 6,050.00 PROD1 CIRCULATE BOTTOMS UP X 4 -PUMP HI VIS SWEEP -550 GPM 1320 SPP 120 RPM 9K TORQ 0900 1330 4.50 CLEAN P 6,050.00 PROD1 POOH ON ELEVATORS FROM 6050' TO 750' -FLOW CHECK ON BTM FOR 10 MIN - STATIC -PU 190K SO 140K -FLOW CHECK @ 750, - STATIC POOH TO 121' 13:30 - 14:00 0.50 CLEAN P 6,050.00 PROD1 POOH AND LAY DOWN BHA Printed 1/8/2020 11:26:40AM **All dephts reported in Drillers Dephts** North America - ALASKA - BP Operation Summary Report Page 1 of 3 Common Well Name: 5-210 Event Type: COM- ONSHORE (CON) Start Date: 12/25/2019 End Date: 12/28/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00 OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 12/25/2019 14:00 15:30 1.50 WHSUR P 6,050.00 RUNCMP CLEAN AND CLEAR RIG FLOOR, BLOW DOWN CHOKE, KILL AND MUD LINES, MU WBRRT, ENGAGE WEAR BUSHING, BACK OUT LDS AND PULL WEAR BUSHING TO SURFACE AND LD 15:30 17:00 1.50 CASING P 6,050.00 RUNCMP RU COMPLETION EQUIPMENT 17:00 17:30 0.50 CASING P 6,050.00 RUNCMP MU SHOE TRACKAND CHECK FLOATS TO 85' 17:30 19:00 1.50 CASING P 6,050.00 RUNCMP WAIT ON BAKER REP TO ARRIVE ON RIG 19:00 23:30 4.50 CASING P 6,050.00 RUNCMP MU & RIH WITH 3 1/2" 9.2 PPF L-80 COMPLETION ASSEMBLY PER TALLY -INSTALL I-WRIE, GAUGES AND CLAMPS PER TALLY (ON GLM'S) FILL EVERY 15 JTS 23:30 00:00 0.50 CASING P 6,050.00 RUNCMP RIG SERVICE 12/26/2019 00:00 22:00 22.00 CASING P 6,050.00 RUNCMP MU & RIH WITH 3 1/2" 9.2 PPF L-80 COMPLETION ASSEMBLY PER TALLY - INSTALL I -WIRE, GAUGES AND CLAMPS PER TALLY FILL EVERY 15 JTS CIRCULATE 2 TUBING VOLUME AT THE SHOE- 5843 TAG BOTTOM ON DEPTH @ 6050' SPACE OUT AND MU HANGER TERMINATE I -WIRE AND SECURE ABOVE HANGER - TEST I -WIRE PACKOFF ON HANGER TO 5000 PSI - RIH WITH HANGER AND LAND IN WELL HEAD (VERIFIED)- SHOE AT 6042 MD - POSITION HANGER 2' ABOVE WELLHEAD FOR CIRCULATING. PU 90K SO 76K 22:00 00:00 2.00 CASING P 6,050.00 RUNCMP BREAK CIRCULATION AND STAGE UP RATE TO 7 BPM SPP 867 PSI MUD WT IN 9.3 PPG OUT 9.3 PPG LUBRICATE RIG 12/27/2019 00:00 01:30 1.50 CASING P 6,050.00 RUNCMP CIRCULATE 3 X BU @ 7 BPM SPP 867 PSI MUD WT IN 9.3 PPG OUT 9.3 PPG OFFLINE, RU UP HOSES FOR CEMENTING AND BEGIN LAYING DOWN DRILL PIPE 01:30 03:30 2.00 CASING P 6,050.00 RUNCMP LAND HANGER IN WELLHEAD SHOE AT 6042 MD PUMP OUT STACK BREAK CIRCULATION TAKING RETURNS THROUGH THE 2" HOSE FROM THE IA (1 BPM 175 PSI - 0 WHP) - DISPLACE STANDPIPE AND KELLY HOSE WITH BRINE MU CEMENTING HEAD TEST CEMENT LINES TO 250/4500 PSI 03:30 04:30 1.00 CEMT P 6,050.00 RUNCMP CEMENTING PJSM - FLUID PACK CEMENT LINES AND PT TO 250/4500 PSI - BLOW DOWN LINES Printed 1/8/2020 11:27:29AM "All depths reported in Drillers Depths" North America - ALASKA - BP Operation Summary Report Page 2 of 3 Common Well Name: S-210 Event Type: COM- ONSHORE (CON) Start Date: 12/25/2019 End Date: 12/28/2019 --- — - - Project: PBU Rig Name/No.: PARKER 272 1 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) - -- (usft) 04:30 07:30 00 CEMT 3. P 6,050.00 RUNCMP CEMENT 3 1/2 TBG AS FOLLOWS: FILL LINES WITH WATER AND PRESSURE TEST TO 250/4500 PSI FOR 5 MINUTES PUMP 42 BBLS OF 11 PPG MUDPUSH 11 SPACER @ 3 BPM, 417-97 PSI- MIX & PUMP ON THE FLY PUMP 214.6 BBLS OF 13 PPG LITECRETE HP GASBLOK LEAD CEMENT @ 5 BPM, EXCESS VOLUME 30% (YIELD 1.5 CU.FT/SK) 518-816 PSI PUMP 79.7 BBLS OF 15 PPG CLASS G ACID SOLUBLE TAIL @ 5 BPM, EXCESS VOLUME 30% (YIELD 1.26 CU.FT/SK) 895-455 PSI - DROP TOP PLUG NO RECIPROCATION PERFORM DISPLACEMENT WITH RIG PUMPS AND 9.8 PPG BRINE 40 BBLS DISPLACED AT 7 BPM: ICP 1075 PSI, FCP 1638 PSI, CATCH CEMENT AT 10 BBL INTO DISPLACEMENT 11.8 BBLS DISPLACED AT 2 BPM: ICP 881 PSI, FCP 1022 PSI REDUCE RATE TO 2 BPM PRIOR TO PLUG BUMP: FINAL CIRCULATING PRESSURE 1022 PSI - BUMP PLUG AND INCREASE PRESSURE TO 1659 PSI, BLEED OFF AND CHECK FLOATS - HOLDING - CEMENT IN PLACE (CIP) @ 0704 HRS ON 12/27/2019 - TOTAL DISPLACEMENT VOLUME 51.8 BBLS (MEASURED BY STROKES @ 96% PUMP EFFICIENCY) NO CEMENT RETURNS TO SURFACE TOTAL LOSSES: 0 BBLS -MAX OBSERVED PRESSURE AT IA GAUGE - 1160 PSI- IA RETURN HOSE FRICTION LOSS. 07 30 0830 1.00 CEMT P 6,050.00 RUNCMP !CIR OUT EXCESS CMT- RETURNS VIA IA _ 1 -PUMP ON TBG OBSERVE DISK BURST AT 3400 PSI -PUMP 50 BBLS 9.8 BRINE FOLLOWED WITH 9.8 BRINE AT 5-7 BPM, 1000 PSI -CIR OUT MUD PUSH AND 70 BBLS CMT AT 5 PBM - 1000 PSI -CIR 1.5 X BU UNTILL CLEAN BRINE AT SURFACE -MAX OBSERVED PRESSURE AT IA GAUGE - 160 PSI- IA RETURN HOSE FRICTION LOSS. - BLOW DOWN LINES, RD CMT HEAD. -PERFORM TOP JOB ON CONDUCTOR X 10 :3/4 ANNULUS- PUMPED 15 BBLS CMT._ 0830 0000 15.50 CEMT P 6,05000 RUNCMP i WAIT ON CMT -RU CIR HEAD ON LANDING JT. -PUMP 10 BBLSAT 2 BPM EVERY HR UNTIL 200 PSI COMPRESSIVE ON LEAD CMT. -LD 5" DP -HOLD PRESPUD MEETING FOR 5-201A WITH CREWA Printed 1/8/2020 11:27:29AM **All depths reported in Drillers Depths*` Printed 1/8/2020 11:27:29AM **All depths reported in Drillers Depths** North America - ALASKA - BP Page 3 of 3 Operation Summary Report Common Well Name: S-210 Event Type: COM- ONSHORE (CON) Start Date: 12/25/2019 End Date: 12/28/2019 Project: PBU Site: S Rig Name/No.: PARKER 272 Spud Date/Time: 12/14/2019 2:00:OOAM Rig Release: 2/25/2019 Rig Contractor: PARKER DRILLING CO. BPUOI: Active datum: ACTUAL KB P272 @81.68usft (above Mean Sea Level) Date From - To Hrs Task Code NPT Total Depth Phase Description of Operations (hr) (usft) 12/28/2019 00:00 - 04:30 4.50 CEMT P 6,050.00 RUNCMP WAIT ON CMT -PUMP 10 BBLS AT 2 BPM EVERY HR UNTIL 200 PSI COMPRESSIVE ON LEAD CMT. -HOLD PRESPUD MEETING FOR S -201A WITH CREW D -LOAD PIPE SHED WITH 3 1/2" TUBING 04:30 - 05:30 1.00 CASING P 6,050.00 WHDTRE FREEZE PROTECT WELL TO 200' -REMOVE LANDING JOINT FROM HANGER -PUMP 22 BBLS OF DIESEL INTO THE IA -ALLOW DIESEL TO U -TUBE INTO TUBING 0530 1600 10.50 CEMT P 6,050.00 RUNCMP WAIT ON CMT 1600 1630 0.50 WHSUR P 6,050.00 RUNCMP PRESSURE TEST TWC FROM BELOW TO 2000 PSI 16:30 20:00 3.50 BOPSUR P 6,050.00 RUNCMP NIPPLE DOWN BOP STACK BLOW DOWN ALL LINES CLEAN OUT FLOW BOX RIG DOWN FLOW LINE AND TURN BUCKLES NIPPLE DOWN STACKAND RISERS 20:00 00:00 4.00 BOPSUR P 6,050.00 RUNCMP NIPPLE UP DRY HOLE TREE -TERMINATE I -WIRE - PRESSURE TEST ADAPTER VOID TO 4500 PSI FOR 15 MIN (TEST APPROVED BY WSUP) - PRESSURE TEST TREE TO 4500 PSI FOR 5 MIN (VISUAL LEAK TIGHT) - SECURE WELLHOUSE SIMOPB: - GENERAL RIG DOWN OPERATIONS ***RIG RELEASED FROM 5-210 @ 23:59 HRS'** Printed 1/8/2020 11:27:29AM **All depths reported in Drillers Depths** Daily Report of Well Operations PBU S-210 T/I/O=TWC/0/0 R/D dryhole tree, R/U production tree, torqued to API specs. R/U lubricator, PT'd 300/low..5000/high.. 5 min. each... pass. see "Field Charted Tests" Pulled 4" CIW "H" TWC #442 through tree. Installed tree cap with new O-ring, pt'd 500. R/D piggybacks off IA & 12/30/2019 OA, installed blinds with jewelry. PT'd 2500 psi against shut valves... pass. FWP's 0/0/0 see T/1/0= 0/25/4. LRS unit 72. CMIT-TxIA to 4000 psi. *ABORTED* OA pressure tracked up with the TxIA. Pumped 2.6 bbls of diesel into the TBG. T/1/0= 673/699/674. Bled TBG back to 1/3/2020 Final T/1/0= 0/27/7. SV, SSV, WV closed. MV open. IA/OA OTG. WFO notified upon T/1/0=0/0/0 temp=S1 LRS unit 46 CMIT-TxIA, Circ Well to diesel. ( NEW WELL POST) Road 1/7/2020 unit to location/ PJSM*** WSR continued on 01/08/20 *** *** WSR continued from 01/07/20*** Heated diesel transport to 50*. CMIT-TxIA PASSED to 4033/4084 psi. Max Applied Pressure=4250 psi Target Pressure= 4000 psi.. Pressured T/IA to 4172/4228 psi with 3.4 bbls 60/40 to test. CMIT-T/IA lost 10T1 05 psi in the first 15 minutes and 37/39 psi in the 2nd 15 minutes for a total loss of 139/144 psi during a 30 minute test. Bled T/IA to 38/43 psi recovering —3 bbls. Pumped 2 bbls 60/40 followed by 273 bbls Diesel down TBG up the IA taking returns to S-43 FL to production to Cic-Out well. Freeze protected S-43 FI with 6 bbls 60/40. SI LV Pressured FL to 1500 psi. FWHP=159/162 **Fluid packed tags hung on IAV/VW** 1/8/2020 **AFE sign hung on MV** ***WELL S/I ON ARRIVAL*** (New well post) PARTIAL RIG UP SWCP 4516, CURRENTLY ON WEATHER HOLD (Low temp). 1/9/2020 ***JOB IN PROGRESS, CONTINUED ON 1/10/20 WSR*** T/1/0=96/96. LRS unit 46 Assist Slickline as directed (NEW WELL POST) MIT T **PASSED** to 4710 psi. Max applied = 4800 psi. Target pressure = 4600 psi. Pumped 2.94 bbls diesel down tbg to reach test pressure. Test # 1 15 min T lost 173 psi. Repressure tbg with .07 bbl diesel (Total dsl = 3.01 bbls) Test # 2 15 min T lost 16 psi 30 min T lost 6 psi. Total loss in 30 mins = 22 psi. Bleed TP back to 1500 psi. Bled back .5 bbls. Maintained 1/10/2020 1500 psi during Log. ***CONTINUED FROM 1/9/20 WSR*** (New well post) RAN 2.70" x 20' DUMMY WHIPSTOCK, S-BLR TO 5,823' SLM (Sample of cement). RAN 2.25" x 5' DD BAILER TO 5,822' SLM, WORK TOOLS TO 5,830' SLM (Recovered H cement). CLOSE 3-1/2" BAKER HP DEFENDER SLIDING SLEEVE AT 2,263' SLM / 2,303' MD. LRS PERFORMED SUCCESSFUL MIT -T TO 4710 PSI. 1/10/2020 CURRENTLY LOGGING SECOND PASS W/ SLB SCMT FROM 5,805' SLM TO SURFACE. T/1/0= 219/75/62. LRS Unit 46 to assist Slickline (NEW WELL POST). Pumped 20 bbls Diesel intoTBG to establish injectivity in first zone. 1/11/2020 ***Job continued to 1/12/2020*** ***Continued from 1/10/2020***. T/1/0=1504/97. LRS unit 46 Assist Slickline as directed (NEW WELL POST) Pumped 1 bbls Diesel, maintaining1500 psi on TBG while SLB conducted log. SLB in control of well 1/11/2020 upon departure. Tag hung. FWHP's = 288/84 Daily Report of Well Operations PBU S-210 ***CONTINUED FROM 1/10/20 WSR*** (New well post) MADE TWO PASSES W/ SLB SCMT FROM 5,805' SLM TO SURFACE (Good data). SET 3-1/2" X -CATCHER SUB IN X -NIPPLE AT 5,759 ' SLM / 5,801' MD. PULL BED -GLV FROM ST #1 (5,774' MD). LRS ESTABLISHED INJECTIVITY W/ DIESEL AT .5 BPM @ 1166 PSI (Seeing PSI response on ST#1 and ST#2 downhole gauges) SET BEK-FLOW SLEEVE AT ST #1 (5,774' SLM). CURRENTLY STANDING BY FOR KCL TO ARRIVE FOR INJECTIVITY TEST (St #1). 1/11/2020 ***JOB IN PROGRESS, CONTINUED ON 1/12/20 WSR*** ***CONTINUED FROM 1/11/20 WSR*** (New well post) INJECTION RATE OF 4 BPM @ 2145 PSI W/ 3% KCL FOR ST #1 (PSI response on DH gauges #1 & #2). PULL BEK-FLOW SLEEVE FROM ST #1 & SET BK-DGLV AT ST #1 (5,774' MD). LRS PERFORMED SUCCESSFUL PRESSURE TEST ON TUBING TO 4000 PSI. PULL BED-DGLV FROM ST #2 (5,751' MD). LRS ESTABLISHED INJECTIVITY W/ DIESEL OF .5 BPM @ 1400 PSI (PSI response on DH gauges #1 & #2). SET BEK-FLOW SLEEVE AT ST #2 (5,751' MD). INJECTION RATE OF 3.7 BPM @ 2453 PSI W/ 3% KCL FOR ST #2 (PSI response on DH gauges #1, 2, 3, 7, 81 & 10). PULL BEK-FLOW SLEEVE FROM ST #2 & SET BK-DGLV AT ST #2 (5,774' MD). LRS PERFORMED SUCCESSFUL PRESSURE TEST ON TUBING TO 4000 PSI. PULL BED-DGLV FROM ST #3 (5,689' MD). LRS ESTABLISHED INJECTIVITY W/ DIESEL OF .5 BPM @ 1350 PSI (PSI response on DH gauges #3 & #4). SET BEK-FLOW SLEEVE AT ST #3 (5,689' MD). INJECTION RATE OF 1 BPM CaD- 1670 PSI W/ DIESEL FOR ST #3 (Only gauge #3 showed pressure gain during test). PULL BEK-FLOW SLEEVE FROM ST #3 & SET BK-DGLV AT ST #3 (5,689' MD). 1/12/2020 ***JOB IN PROGRESS, CONTINUED ON 1/13/20 WSR*** T/I/O = 71/93/79 Temp - SI. LRS Unit 46 Assist SLB (NEW WELL POST) ***Job continued from 1/11/2020*** Station #1 - Pumped 285 bbls KCL into TBG for injection test. Injection Pressure test for last 5 minutes was at 4 bpm at 2145 psi. Pumped 3 bbls 60/40 Meoh and 22 bbls Diesel to FP TBG. Pumped 3 bbls Diesel into TBG to pressure test Dummy GLV to 4000 psi, TBG lost 57 psi in 5 minutes. Bled down pressure to 488 psi, bled back 2.7 bbls. Station #2. Pumped 7 bbls down tbg at .5 bpm to establish injectivity. Slickline to RIH and set flow sleeve. Injectivity test = 2 bbls 60/40, followed by 270 bbl of 3% kcl @ 4 bpm. 5 min test = 15 bbls at 3.7 b m 2453 psi. Freeze protect tbg with 2 bbls 60/40, followed by 22 bbls of 70* dsl. Pumped 5 bbls dsl to pressure up to check set of DGLV in station #2. Pumped .10 bbl dsl to pressure tbg to 4000 psi for 5 min test. Tbg lost 72 psi in 5 mins. Slickline to pull station #3, Pumped 8.25 bbls dsl down tbg at .5 bpm to establish injectivity. Pumped 50 bbls Diesel into TBG for Injection Test. Injection pressure test for last 5 minutes was 1 bpm at 1670 psi. 1/12/2020 1 ***Job continued to 1/13/2020*** Daily Report of Well Operations PBU S-210 ***CONTINUED FROM 1/12/20 WSR*** (New well post) LRS PERFORMED SUCCESSFUL PRESSURE TEST ON TUBING TO 4000 PSI. PULL BED-DGLV FROM ST #4 (5,637' MD). LRS ESTABLISHED INJECTIVITY W/ DIESEL OF .5 BPM @ 1605 PSI (PSI response on DH gauges #4, 5, 6, 7, & 8). SET BEK-FLOW SLEEVE AT ST #4 (5,637' MD). INJECTION RATE OF 1 BPM @ 1895 PSI W/ DIESEL FOR ST #4 (PSI response on DH gauges #4, 5, 6, 7, & 8). PULL BEK-FLOW SLEEVE FROM ST #4 & SET BK-DGLV AT ST #4 (5,537' MD). LRS PERFORMED SUCCESSFUL PRESSURE TEST ON TUBING TO 4000 PSI. PULL BED-DGLV FROM ST #5 (5,614' MD). LRS ESTABLISHED INJECTIVITY W/ DIESEL OF .5 BPM @ 1964 PSI (PSI response on DH au es #4, 5, 6, 7, & 8). SET BEK-FLOW SLEEVE AT ST #5 (5,614' MD). INJECTION RATE OF 1 BPM @ 1691 PSI W/ DIESEL FOR ST #5 (PSI response on DH gauges #4 5 6,-7,_& 8-). PULL BEK-FLOW SLEEVE FROM ST #5 & SET BK-DGLV AT ST #5 (5,614' MD). LRS PERFORMED SUCCESSFUL PRESSURE TEST ON TUBING TO 4000 PSI. PULL BED-DGLV FROM ST #6 (5,591' MD). LRS ESTABLISHED INJECTIVITY W/ DIESEL OF .5 BPM @ 1850 PSI (PSI response on DH gauges #4, 5, 6, 7, & 8). SET BEK-FLOW SLEEVE AT ST #6 (5,591' MD). INJECTION RATE OF 1 BPM @ 1890 PSI W/ DIESEL FOR ST #6 (PSI response on DH gauges #4, 5, 6, 7, & 8). PULL BEK-FLOW SLEEVE FROM ST #6 & SET BK-DGLV AT ST #6 (5,591' MD). 1/13/2020 ***JOB IN PROGRESS, CONTINUED ON 1/14/20 WSR*** T/I/O = 1120/-17/-21 Temp - SI. LRS Unit 46 assist SLB (NEW WELL POST). ***Job continued from 1/12/2020*** Station #3 Pumped .98 bbls Diesel to pressure test Dummy GLV to 4000 psi. TBG lost 24 psi in 5 minute test. Bled back 1.4 bbls. Station #4 Pumped 7 bbls 70* Diesel to establish injection pressure. 10 minute injection test average of 1605 psi at .5 bpm. Pumped 50 bbls 70* Diesel into TBG for injection test. Last 5 minute Injection Test at 1 bpm, TGB average pressure - 1895 psi. Pumped 2.18 bbls dsl down tbg for station #4 DGLV pressure test. TP lost 73 psi in 5 min. Bled TP to 1000 psi. Bled back .5 bbl Station #5 Pumped 6.8 bbls dsl down tbg to verify injectivity. 10 min = 1945 psi @ .5 bpm. Pumped 50 bbls dsl down tbg for injection test. Last 5 mins injectivity average at 1691 psi @ 1 bpm. Pumped 2.5 bbls dsl down tbg to pressure up to 4000 psi. 5 min TP lost 62 psi. Bled TP back to 1000 psi. Bled back .8 bbl. Station #6 Pumped 7 bbls dsl down tbg to verify injectivity. 10 min = 1850 psi @ .5 bpm. Pumped 50 bbls Diesel intoTBG for Injection Test. Last 5 minutes injectivity average of 1890 psi @ 1 bpm. 1/13/2020 ***Job continued to 1/14/2020*** Daily Report of Well Operations PBU S-210 ***CONTINUED FROM 1/13/20 WSR*** (New well post) LRS PERFORMED SUCCESSFUL PRESSURE TEST ON TUBING TO 4000 PSI. PULL BED-DGLV FROM ST #7 (5,564' MD). LRS ESTABLISHED INJECTIVITY W/ DIESEL OF .5 BPM @ 1623 PSI (PSI response on DH gauge #6, 7, & 8). SET BEK-FLOW SLEEVE IN ST #7 (5,564' MD) INJECTION RATE OF 1 BPM @ 1623 PSI W/ DIESEL FOR ST #7 (PSI response on DH gauges #6, 7, & 8). PULL BEK-FLOW SLEEVE FROM ST #7 & SET BK-DGLV AT ST #7 (5,564' MD). LRS PERFORMED SUCCESSFUL PRESSURE TEST ON TUBING TO 4000 PSI. PULL BED-DGLV FROM ST #8 (5,543' MD). LRS ESTABLISHED INJECTIVITY W/ DIESEL OF .5 BPM @ 1365 PSI (PSI response on DH gauge #6, 7, & 8). SET BEK-FLOW SLEEVE IN ST #8 (5,543' MD). INJECTION RATE OF 1 BPM @ 1505 PSI W/ DIESEL FOR ST #8 (PSI response on DH gauges #6, 7, & 8). PULL BEK-FLOW SLEEVE FROM ST #8 & SET BK-DGLV AT ST #8 (5,543' MD). LRS PERFORMED SUCCESSFUL PRESSURE TEST ON TUBING TO 4000 PSI. PULL BED-DGLV FROM ST #9 (5,424' MD). ****NOTE: GAUGE #10 IS IN GLM - r LRS ESTABLISHED INJECTIVITY W/ DIESEL OF .5 BPM @ 1627 PSI (Only gauge #10 , /net / showed psi response).. SET BEK-FLOW SLEEVE IN ST #9 (5,424' MD). INJECTION RATE OF 1 BPM @ 1939 PSI W/ DIESEL FOR ST #9 (Only gauge #10 showed psi response). PULL BEK-FLOW SLEEVE FROM ST #9 & SET BK-DGLV AT ST #9 (5,424' MD). 1/14/2020 LRS PERFORMED SUCCESSFUL PRESSURE TEST ON TUBING TO 4000 PSI. T/I/O = 747/-16/-18 Temp - SI. LRS Unit 46 assist SLB (NEW WELL POST) ***Job continued from 1/13/2020*** Station Pumpe 1.13 bbls Diesel into TBG to pressure test Dummy GLV to 4000 psi. TBG lost 39 psi in 5 minutes. Bled back .9 bbls. Station #7 Pumped 7.8 bbls Diesel into TBG to establish injection rate at .5 bpm. 10 minute injection test at .5 bpm averaged at 1623 psi. Pumped 50 bbls 70* Diesel into TBG for Injection Test. 5 min inject test = 1761 psi 1 bpm. Pumped 2.08 bbls dsl down tbg to test DGLV set @ 4000 psi. TP lost 54 psi in 5 mins. Bled TP back to 980 psi. Bled back .7 bbl Station#8 Pumpe bbls dsl down tbg to verify injectivity. 10 min = 1365 psi @,.5 bpm. Pumped 50 bbls down tbg for injection test. Final 5 mins = 1505 psi @ 1 bpm. Pumped 2.5 bbls dsl down tbg to test DGLV set to 4000 psi. TP lost 48 psi in 5 mins. Bled TP back to 1000 psi. Bled back .8 bbl Station #9 Pumped 7 bbls dsl down tbg to verify injectivity. 10 min = 1627 psi @ .5 bpm. Pumped 50 bbls 70* Diesel @ 1 bpm down TBG for Injection Test -Last minute Injection test resulted in average TBG pressure at 1939 psi. Pumped 1 bbl Diesel into TBGto pressure test Dummy 1/14/2020 GLV. TBG lost 77 psi in 5 minutes. Bled back 1.7 bbls. Daily Report of Well Operations PBU S-210 T/I/O = 444/-2/-18 Temp - SI. LRS Unit 46 Assist SLB (NEW WELL POST). Job continued from 1/14/2020 WFR Station #2 (First test) Pumped 15.4 bbls 70* Diesel into TBG for Step Rate Test of WFR Station #2. At 800 psi - 5 minutes @ .04 bpm, 10 minutes @ .06 bpm with a average of .05 bpm. At 1600 psi - 5 minutes @ .22 bpm, 10 minutes @ .18 bpm; average of .2 bpm. 2500 psi - 5 minute @.24 bpm, 10 minutes @.26 bpm; average of .25 bpm. at 3000 psi - 5 minutes @ .24 bpm, 10 minutes @ .28. Slickline to swap out valves. WFR Station #2 (Second test) Pumped a total of 16.4 bbls Diesel down TBG for SRT station #2. 1600 psi = 5 min @ .20 bpm / 10 min @.22 bpm. 2500 psi = 5 min @.22 bpm / 10 min @.24 bpm. 3000 psi = 5 min @ .22 bpm / 10 min @ .24 bpm. Slickline to swap out valves. WFR Station #2 (Third test) Pumped a total of 15.46 bbls Diesel down TBG for SRT station #2. 1600 psi = 5 min @ .20 bpm / 10 min @ .20 bpm. 2500 psi = 5 min @ .26 bpm / 10 min @ .32 bpm. 3000 psi = 5 min @.32 bpm/10 min =.30 bpm. WFR Station #2 (Fourth test) Pumped a total of 12.44 bbls Diesel down TBG for SRT station #2. 1200 psi = 5 min @ .14 bpm / 10 min @.12 bpm. 1600 psi = 5 min @.22 bpm / 10 min @.18 bpm. 1800 psi = 5 min @.22 bpm/10 min @.24 bpm. WFR Station #2 and #3 Pumped a total of 22.3 bbls Diesel into TBG for SRT of Station #2 and #3. 1200 psi = 5 min @ .2 bpm / 10 min @ .18 bpm. 1600 psi = 5 min @ .42 bpm / 10 min @ .42 bpm. 1800 psi = 5 min @.44 bpm / 10 min @.46bpm. 2000 psi = 5 min @.44 bpm / 10 min @.46bpm. 1/15/2020 **** Job continued to 1/16/2020 **** ***CONTINUED FROM 1/14/20 WSR*** (New well post) PULL BK-DGLV FROM ST #2 (5,751' MD) & SET BK-BKR-RFR (202 bwpd, 5/32" port, 0 spacers). LRS PERFORMED STEP RATE TEST ON ST #2 (Injection rate high for valve design). PULL BK-BKR RFR FROM ST #2 (5,751' MD) & SET BK-BKR-RFR (202 bwpd, 5/32" port, 0 spacers). LRS PERFORMED STEP RATE TEST ON ST #2 (Same results - Injection rate high for valve design). PULL BK-BKR RFR FROM ST #2 (5,751' MD) & SET BK-BKR-RFR (202 bwpd, 5/32" port, 2 spacers). LRS PERFORMED STEP RATE TEST ON ST #2 (Injection rate even higher for valve design w/ spacers). PULL BK-BKR RFR FROM ST #2 (5,751' MD) & SET BK-BKR-RFR (202 bwpd, 5/32" port, 0 spacers). LRS PERFORMED STEP RATE TEST ON ST #2 (Injection rate high for valve design, OK'd to move on). PULL BK-DGLV FROM ST #3 (5,689' MD) & SET BK-BKR-RFR (202 bwpd, 5/32" port, 0 spacers). LRS PERFORMED STEP RATE TEST ON ST #2 & #3 (Injection rate high but stable, OK'd to move on). 1/15/2020 ***JOB IN PROGRESS, CONTINUED ON 1/16/20 WSR*** Daily Report of Well Operations PBU S-210 T/I/O = 507/3/-20 Temp - SI. LRS Unit 46 assist SLB (NEW WELL POST). **** Job continued from 1/15/2020*** Station #2, 3 & 4 WFR Step Rate Test Pumped a total of 28.3 bbls Diesel into TBG for SRT. 1200 psi = 5 min @ .24 bpm / 10 min @ .22 bpm. 1600 psi = 5 min @ .6 bpm / 10 min @ .62 bpm. 1800 psi = 5 min @ .66 bpm / 10 min @.68 bpm. 2000 psi = 5 min @.68 bpm / 10 min @.66 bpm. Station #2,3,4,8 WFR SRT Pumped a total of of 41.55 bbls dsl down tbg for SRT. 1200 psi 5 min =.36 bpm/10 min =.36 bpm. 1600 psi 5 min =.80 bpm/10 min =.82 bpm. 1800 psi 5 min =.92 bpm/10 min =.92 bpm. 2000 psi 5 min = 1 bpm/10 min = .96 bpm. Station #2,3,4,6,8 WFR SRT Pumped a total of 100 bbls dsl down tbg for SRT. 1200 psi= 5 min @ .40 bpm/10 min @ .38 bpm. 1600 psi 5 min @ 1.08 bpm/10 min @ 1.04 bpm. 1800 psi 5 min @ 1.36 bpm/10 min @ 1.34 bpm. 2000 psi 5 min @ 1.72 bpm/10 min 1.70 bpm. 2500 psi 5 min @ 2.14 bpm/10 min @ 2.16 bpm. Station #6,8 WFR ( with D&D test tool installed) Pumped a total of 38 bbls dsl down tbg for SRT. 1200 psi = 5 min@ .20 bpm/10 min @.20 bpm. 1600 psi = 5 min @.52 bpm/10 min @.50 bpm. 1800 psi = 5 min @72 bpm/10 min @ .72 bpm. 2000 psi = 5 min @.98 bpm/10 min @.98 bpm. Station #8 WFR SRT with D&D test tool set below Station #8. Pumped at total of 12.5 bbls Diesel into TBG for SRT. 1200 psi = 5 min @ .08 bpm / 10 min @.08 bpm. 1600 psi = 5 min @.22 bpm / 10 min @.22 bpm. 1800 psi = 5 min @.28 bpm / 10 min @.20 bpm. 2000 psi = 5 min @.28 bpm / 10 min @.24 bpm. 1/16/2020 *** Job continued to 1/17/2020 *** ***CONTINUED FROM 1/15/20 WSR*** (New well post) PULL BK-DGLV FROM ST #4 (5,637' MD) & SET BK-BKR-RFR (202 bwpd, 5/32" port, 0 spacers). LRS PERFORMED STEP RATE TEST ON ST #2, 3, & 4 (Injection rate high but stable, OK'd to move on). PULL BK-DGLV FROM ST #8 (5,543' MD) & SET BK-BKR-RFR (202 bwpd, 5/32" port, 0 spacers). LRS PERFORMED STEP RATE TEST ON ST #2, 3, 4, & 8 (Injection rates a little high w/ pressure increase) PULL BK-DGLV FROM ST #6 (5,591' MD) & SET BK-BKR-RFR (694 bwpd, 5/16" port, 0 spacers). LRS PERFORMED STEP RATE TEST ON #2, 3, 4, 6, & 8 (Injection rates increased w/ increased pressure) SET D&D @ 5,568' SLM, LRS PERFORM FAILING SRT'S ON STA'S #8 & #6 (rates not linear, incresing w/ pressure) PULL D&D FROM 5568' AND SET AT 5,520' SLM, SRT'S ON STA #8 (Rates are a little high but valve is regulating ok) 1/16/2020 ***CONT WSR ON 1/17/19*** ***CONT WSR FROM 1/16/20*** (new well post) SET BK-BKR-RFR (9/32" port, no spacer, 585 bwpd, 9/32" port, 0 spacers) IN ST#6 (5,591' MD) LRS PERFORMED STEP RATE TEST (rates are higher than expected but appear valves are regulating) 1/17/2020 R/D, ENGINEER TO REVIEW DATA Daily Report of Well Operations PBU S-210 T/I/O = 277/-2/-19 Temp - SI. LRS Unit 46 assist SLB (NEW WELL POST).**** Job continued from 1/16/2020 **** Pumped 29 bbls Diesel into TBG to assist SLB to set Station #6 WFR. 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N N U) Q L O O O C co N N N O m Z a (n (n (n ch O w M V w O w O O O N M I� o O m O m m r- m O ^ O N N O o O t- (n N m Cl) 1� m V M V w r N m m �.L E c roi rn co o w w m 'n v o m ro m o u o v 6 ui ` m Cl) m m N N V O In N N V M M V N u) m (� O co m m m m o O_ O o - N 04 M M N u) m O N O W _ p cn C d LL LL O V O C m O (D No ERV O Q N a a) m U) LL _ m f- N m m M m m m m M M m M O V O m N f- r- m m 01 O Cl m I, m m V m m N I, V M N O V m m m m I- m O O O N M m M O N V f- M M M I, m V N N 1- m m m m m 0 M O N V M I� m O M m m N m O M O M .- .- N N N N N N M M M M V V M M m m f- a m N O n O m M N M m r V N M 0 O Cl) M r m m m O M m m f- M U N .- O r- O r N M M r O O O r N N N M M N N N z > > Q 00 m m m m 0 d 7 J o0 m m 0 N NN N N l6 N a Z M M M O r V m , M N M m r I- M m O M N O m O N M m m m M m M fD M m m O m N m V O N m N M V 1: m M m m 3 a m O_ Y Y m M N M M I- I� m m m � � V M m � m Cl? m m I - V m mm m www m M r mOm r V Cl) M m Nm r OR O Y Q Q M V mmm M N O 00 O 00 m I m m m m m mm Cl) r? < 3 m m m m m m m m m m m m m m m m m m m m m m m m m m j m m m m m m m m m m m m m m m m m m m m m m m m m m m Q Q H ILLI W m N M M V V N m m m m M m M m m M m N M m MV m m V m I, m O m r O N m m V M m V N I� M r m V V f� V V N.M V M d N O O N mO ` V M O N m M N M M M I- M V V .� C p) C m I� V V CO V m V O M O M M N M M M V M m M m M O m N m V m M m m m _ V fI t- r m M m m m V m m m V m O O p O O O O O O O O O O O O O O O O O O O O O O O O 41 w N m m m m m m m m m m m m m m- m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m Z M M d C O M M M M M M M M M M M M M M M M M M M M M M M M M 20, C U d C fi d d C V M f� O M r N m V V V V •- M m V M m V I- M m m m m M N m N V V m 4 i w N m M m m m V N N O N V m M M N N V OD m N N C6 m p w d (,1 I� 01 m O O N N M M M N N N N M M m m N p 3 z M 0 7 f� m m V m M V m V I- m M V m m r m m N m m m M N m m M O O M m V O O N V M N r OR m m m M m M r� m m M ui Cl) Cl) v LO Oi ori v v 00 v m 00 v vi co v ori M co W o 0 v 0 W m f� m m O O N M V m m O N N N Vm N N m N M V M I- M V M V O M V M m M V m m m Z, I- m N N M m m M m M m I� m M V m M M M V m M V N m V m V O O O O m M h M M m m V M M m f- M f- Cl) m V N m m M m m m m m r� m O O n m O M M M M O N m I� m O m m m M O N m O N m N f- N N r- M N m V N m M N V m N O N N m N N V m N M m N M O M NO . M N M m N M m M M m V M V M co N m M O m N r M Cl) d 7 M m r- r M N m V N m N m M O O m OR m V N Cl) O V m N m m M CO N M f� O m O m O N N m m M I� n M N O m f� n m m m m I� O _ � m N m M M V V M V m M I� m n 1- m N m N O _ O N m N f- co m V V M N m O m m m N N N N N N N N N N N CO M M M M M Cl) CO CO Cl) CO V m m N N m N O O m V M O f- M m M m m f- O M N _ m V f- V O m O m V M M m N m V f- M m m V m m O I- m m m m M N N m m M M N M N M N M M M N M M M V M M Cl) M M U7; M Cl) V Cl) V Cl) V M M M a m m 5 Q E Q L O O O O in z a m cn 6 c C .. a a rn m E Q m m C63, L O _ M O O V m V O m N m V O O m V N N N N V m m M V V m m V V 1- m9 O N N m m O M m M O M co In r- m w f- r- P- m r� m V MM M m f: m NN V N mN mN M riM I'- M � M � � � � � M M 0 I- m M M m N N I- M m M M V m V O m M V m O M m m V m M m V M f -N w m O O_ V M m M O M m M m M In O O m m m N m f4 r m m M M m M V V V M N N O� N O m O N CO V M m f� m m m O .- N M V M m P,- m m m N N N N N N N N N N N N M M M M M M M M M M M rL N N N tf O Q CL a m z U) LL m Lf) m M r- m m M OD N m M O O M mr-:V m U? N N Cl) M O m Irl N O r- V m u) N m m ` In O V M M r- M m O m r M m V O m m M O O N N M V In In m ccr- r-1 m c m m d rq N C d (4O C T O Q w d N 7 U a i 6 O rn � r`V n m V m m M V v m m u) V r- V V M V V Nm (n M . M V M M M m V V0 In (n m r- CO m r- r- r- r- r- r- r- r- r r- r- r- r-- (ri w) w) o w) vi v v v v M Cl) M M M co co M M M Cl) M M M M M M M M Cl) Cl) M M F O CD O M Lo N n m N m m N N N M r- m N M N m O n V O � V V N 7 m U m O V N r m M r- r- r- m O C m o m V m m r N r- r- N m m m V m O m m m rl (O m rn V V M M N N O O m m m In O — N M V u) m r m m O N M V m m r- r- m m O O V In vi v) vi (n (n n (D (D ID m m '0 0 m m O O CO U) Qq U CV CV O O IS m m O 1` O m m N M N M N .- M M V M O N m V O V r- m N Lo r: m V O m V m n m N M N O N O U O O O O O O O O O O r O O O O O O O O x Z 7 Q cp N mD (m0 J o 0 r n N N (0 a s O m r- m m N r- m O m M N m M N O V N M M m M O V m m t` m M �l M O m V M m m M M V m Q M m 3 V O r- m In V Lr) Lr) O m m" n Cl) m M m O Y Y U m V m (!1 m N Cl) M N N N M to r, , LO m M N m m Y N (n C O r' -m m In m M m O m r Ln m M N m V m V M V O V r- M M M m N m N M N N m � In r V M r � Q Q 3 (� Z) Z) a' C3 - �' co W ao co co co m m co m m co co ao m m oo co a_o oo m co (o v m m m m m m m m m m m m m m m m m m m m m m (O Q Q H O W N �_ N O m V N M m r` N m N m m .- M m N m c0 m m O M N M to m M M m t` o N V N m OD O m m m m r M m N m O m n O N O m N m M r� t` M O OD d m m O M M M N O m m m n m M N O r V O m N O C O iT C V m m N O M to M O V N V O o m o O m V m m m V r m r1 V cc m cc V m m m Mm O O M r V m r r r t N N Z m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m N m m m m m m m m m m m m m m m m c In u) vi vi ui ui Lri vi (n vi Ln (n (n (n In Lo In LO m ui to vi d o So c ci � is y d C O 'O n N O N O 1` V V m m N •- N0 (D V NN u) m O m C O O C (D r V m m (n r- m m m Lo n m M m M O m m m m m d _ R :! m d m M m M m V O m m r-� t` m V N m V O m N co m m V O w d d U () d 4- M T W O N M N (n N N N O M M M m M m M V V V f� V O to M iD m m V m m V o m p co J F 2 N 0 V N m N M M m M m M M r- M M m m M m N N M n N co M M m m M In m V m04 m N m N N N r, m V (D r- m O O O O m m m m m m m M N O 1` V m (17 f� O m Lo m O m lD m O m O m O N In N O M ifl M O V m V O ir) to LQ O m m m m m V r- m r� h - — — — — — — — — — — - — r- e - Z; N m m N V m N m m m m o h m m m N N V O M m m m O rl O M m O m m r-� N m M In In O M lo O m NIn (() M O m m N M r, O N m 1- N V M _ m m m N V m m m V f- M m O N N m co m co O V O V V N V M V M V V V (() V m V m V � V cc V m V m V O ID r (r) N lD N Ir) M iD V V O r- r- O o N n M m V M m M o m r- m r- O CO N m N M V m CO r� V N O N m r- Cl) m m m M m V N N m 1- N r- N r- N rl N m M m M m In N m 1- V m m N m Mm m O O m M N M m M m V M Lr)m m m m r- M m m m m m O V N N O M f� M (n V m O V M ^ co V V V V V V V V V V V V V V (n ID LO m to m N N (D V IA r- m m V N r, O n M Cl) V m V N m N m N O r� m m V V O V m m M m N m V �) m V M Cl) r- V Cl) V M Mm m m m O O O N N O m O O O Cl) Cl) Cl) Cl) Cl) Cl) CO Cl) CO Cl) Cl) M M M N Cl) N Cl) N Cl) N M M M M M M M M M M Cl) M Cl) M M M Cl) N Cl) CO M M Cl) Cl) Cl) C d (4O C T O Q w d N 7 U a i 6 O rn � r`V n m V m m M V v m m u) V r- V V M V V Nm (n M . M V M M M m V V0 In (n m r- CO m r- r- r- r- r- r- r- r- r r- r- r- r-- (ri w) w) o w) vi v v v v M Cl) M M M co co M M M Cl) M M M M M M M M Cl) Cl) M M F O CD O M Lo N n m N m m N N N M r- m N M N m O n V O � V V N 7 m U m O V N r m M r- r- r- m O C m o m V m m r N r- r- N m m m V m O m m m rl (O m rn V V M M N N O O m m m In O — N M V u) m r m m O N M V m m r- r- m m O O V In vi v) vi (n (n n (D (D ID m m '0 0 m m O O CO U) Qq U CV CV O O IS E U z o Q � m m m 0 O of � a co co r r w a a Z m Q o Y Y V Y J J N Q Q D Z) N E ❑w V- a 0 t2 N Q[D a (D m m z Y (n V L O U) 3 ❑ a o L o E U E N O O U a m rn v m U) W j m � c v ^ O o O U o 0 r U m O � p. -f C Z N r } a 0 M N O R a Q[D m Y (n V L O 3 r y Lo a Lo � � Q o � o L o L o o o_ o m N N N Lo N y o z a w ch 6 6 � a❑ -' m ^ o i o p. C .. C Q V 9 m d E d d y N .d+ a 0 M N O R I Northing (450 usft/in) CN a W 10 W co W co 0) 0) 0) 0) 0) a) cv 0 co co 0) CD m (0 ID 0 (D (D (ui/4sn 090 bulqlJON North America - ALASKA - BP PBU S S-210 S-210 S-210 500292363000 AOGCC Offset Well Report 02 January, 2020 ClIft. Baker c&% Hughes- BP Hughes 8 Obp Anticollision Report Baker Company: North America - ALASKA - BP Project: PBU Reference Site: S Site Error: 0.00usft Reference Well: S-210 Well Error: 0.00usft Reference Wellbore S-210 Reference Design: S-210 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well S-210 ACTUAL KB P272 @ 81.68usft ACTUAL KB P272 @ 81.68usft True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum Reference S-210 Filter type: NO GLOBAL FILTER: Using user defined selection & filtering criteria Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: Unlimited Scan Method: Tray. Cylinder North Results Limited by: Maximum centre distance of 500 Error Surface: Pedal Curve Survey Program Date 1/2/2020 From To (usft) (usft) Survey (Wellbore) Tool Name Description 100.00 1,275.16 Survey #1 (S-210) GYRO -WD -SS Gyro while drilling single shots 1,330.28 2,750.01 Survey #2 (S-210) MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal 2,810.73 2,810.73 Survey #3 (S-210) GYRO -WD -SS Gyro while drilling single shots 2,894.04 6,050.00 Survey #4 (S-210) MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal 1/212020 2:41:25PM Page 2 of 4 COMPASS 5000.15 Build 90 bBP Baker s pAnticollision Report Hughes Company: North America - ALASKA - BP Local Co-ordinate Reference: Well S-210 Project: PBU ND Reference: ACTUAL KB P272 @ 81.68usft Reference Site: S MD Reference: ACTUAL KB P272 @ 81.68usft Site Error: 0.00usft North Reference: True Reference Well: S-210 Survey Calculation Method: Minimum Curvature Well Error: 0.00usft Output errors are at 1.00 sigma Reference Wellbore S-210 Database: EDM R5K-Alaska PROD -ANCP1 Reference Design: S-210 Offset TVD Reference: Offset Datum Summary Reference Offset Centre to Measured Measured Centre Site Name Depth Depth Distance Offset Well - Wellbore - Design (usft) (usft) (usft) EX NKUPST HURLST Plans: Gwydyr Development (SHL) S S-100 - S-100 - S-100 341.72 325.00 242.84 S-101 - S-101 - S-101 1,398.45 1,375.00 162.57 S-101 - S-101 PB1 - S-101 PB1 1,398.45 1,375.00 162.57 S-102 - S-102 - S-102 1,100.97 1,075.00 256.09 S-102 - S-1021-1 - S-1021-1 1,100.97 1,075.00 256.09 S-102 - S-1021-1 13131 - S-1021-1 PB1 1,100.97 1,075.00 256.09 S-102 - S-102PI31 - S-102PB1 1,100.97 1,075.00 256.09 S-103 - S-103 - S-103 1,437.02 1,400.00 354.07 S-104 - S-104 - S-104 341.61 325.00 451.82 S-105 - S-105 - S-105 1,261.43 1,225.00 412.72 S-105 - S -105A - S -105A 1,261.43 1,225.00 412.72 S-106 - S-106 - S-106 285.96 275.00 407.68 S-106 - S-106PB1 - S-106PB1 285.96 275.00 407.68 S-107 - S-107 - S-107 436.28 425.00 362.90 S-108 - S-108 - S-108 3,123.57 3,075.00 188.47 S-108 - S-1 08A* - S-1 08A 46.48 45.38 316.57 S-109 - S-109 - S-109 978.16 950.00 259.18 S-109 - S-109PB1 - S-109PB1 978.16 950.00 259.18 S-110 - S-110 - S-110 665.73 650.00 284.11 S-110 - S -110A - S -110A 665.09 650.00 284.10 S-110 - S -110B - S -110B 652.42 650.00 283.95 S-111 - S-111 - S-111 266.80 250.00 333.67 S-111 - S-111 PB1 - S-111 PB1 266.80 250.00 333.67 S-111 - S-111 PB2 - S-111 PB2 266.80 250.00 333.67 S-112 - S-112 - S-112 486.53 475.00 133.84 S-112 - S-1121-1 - S-1121-1 486.53 475.00 133.84 S-112 - S-1121-1 P61 - S-1121-1 PB1 486.53 475.00 133.84 S-112 - S-1121-1 PB2 - S -112L1 PB2 486.53 475.00 133.84 S-113 - S-113 - S-113 996.04 950.00 336.61 S-113 - S -113A - S -113A 996.04 950.00 336.61 S-113 - S -113B - S-1138 996.04 950.00 336.61 S-113 - S-113BL1 - S-11381-1 996.04 950.00 336.61 S-114 - S-114 - S-114 621.00 600.00 426.89 S-114 - S -114A - S -114A 621.00 600.00 426.89 S-115 - S-115 - S-115 1,078.62 1,050.00 178.80 S -116 -S -116-S-116 1,121.89 1,100.00 54.12 S-116 - S -116A - S -116A 1,121.89 1,100.00 54.12 S-116 - S-116APB1 - S-116APB1 1,121.89 1,100.00 54.12 S-116 - S-116APB2 - S-116APB2 1,121.89 1,100.00 54.12 S-117 - S-117 - S-117 1,822.30 1,800.00 94.12 S-118 - S-118 - S-118 964.08 950.00 83.35 S-119 - S-119 - S-119 369.38 350.00 302.95 S-120 - S-120 - S-120 670.75 650.00 165.03 S-121 - S-121 - S-121 342.34 325.00 61.63 S-121 - S-121 P81 - S-121 PB1 342.34 325.00 61.63 S-122 - S-122 - S-122 1,746.40 1,725.00 139.47 S-122 - S-122PB1 - S-122PB1 1,746.40 1,725.00 139.47 S-122 - S-122PB2 - S-122PB2 1,746.40 1,725.00 139.47 1/2/2020 2.41:25PM Page 3 of 4 COMPASS 5000.15 Build 90 Summary Reference BP Centre to Measured Measured Centre Z°t Anticollision Report Distance Offset Well - Wellbore - Design (usft) (usft) (usft) Company: North America - ALASKA - BP Local Co-ordinate Reference: Well S-210 Project: PBU ND Reference: ACTUAL KB P272 @ 81.68usft Reference Site: S MD Reference: ACTUAL KB P272 @ 81.68usft Site Error: 0.00usft North Reference: True Reference Well: S-210 Survey Calculation Method: Minimum Curvature Well Error: 0.00usft Output errors are at 1.00 sigma Reference Wellbore S-210 Database: EDM R5K - Alaska PROD - ANCP1 Reference Design: S-210 Offset ND Reference: Offset Datum Summary Baker Hughes 1/2/2020 2:41:25PM Page 4 of 4 COMPASS 5000.15 Build 90 Reference Offset Centre to Measured Measured Centre Site Name Depth Depth Distance Offset Well - Wellbore - Design (usft) (usft) (usft) S S-122 - S-122PB3 - S-122PB3 1,746.40 1,725.00 139.47 S-125 - S-125 - S-125 292.72 275.00 32.33 S-125 - S-125PB1 - S-125PB1 292.72 275.00 32.33 S-200 - S-200 - S-200 2,629.79 2,600.00 60.13 S-200 - S -200A - S -200A 2,639.00 2,625.00 60.15 S-200 - S-200PB1 - S-200PB1 2,629.79 2,600.00 60.13 S-201 - S-201 - S-201 1,714.18 1,675.00 383.87 S-201 - S-201 A- S-201 A 1,721.65 1,700.00 383.97 S-201 - S-201 A - S-201 A WP06 1,721.20 1,700.00 383.96 S-201 - S-201 PB1 - S-201PB11,714.18 1,675.00 383.87 S-213 - S-213 - S-213 2,537.94 2,525.00 81.15 S-213 - S -213A- S -213A 2,541.73 2,525.00 81.16 S-213 - S-213ALl - S-213ALl 2,541.73 2,525.00 81.16 S-213 - S-213ALl-01 - S-213ALl-01 2,541.73 2,525.00 81.16 S-213 - S-213AL2 - S-213AL2 2,541.73 2,525.00 81.16 S-213 - S-213AL3 - S-213AL3 2,541.73 2,525.00 81.16 S-216 - S-216 - S-216 1,190.63 1,175.00 50.52 S-23 - S-23 - S-23 6,027.29 6,550.00 413.78 S-31 - S-31 - S-31 4,526.33 5,075.00 494.81 S-31 - S-31 A - S-31 A 4,526.33 5,075.00 494.81 S-400 - S-400 - S-400 442.06 425.00 72.08 S-400 - S -400A - S -400A 442.26 425.00 72.08 S-401 - S-401 - S-401 566.44 550.00 29.96 S-401 - S-401 PB1 -S-401P131 566.44 550.00 29.96 S-41 - S-41 - S-41 609.37 600.00 42.71 S-41 - S-41 A- S-41 A 615.52 600.00 42.82 S-41 - S-41ALl - S-41ALl 615.52 600.00 42.82 S -41-S-41 L1 -S-41 L1 609.37 600.00 42.71 S-41 - S-41 PB1 - S-41 PB1 609.37 600.00 42.71 S-42 - S-42 - S-42 459.84 450.00 15.34 S-42 - S -42A - S -42A 448.95 450.00 15.20 S-42 - S-42PB1 - S-42PB1 459.84 450.00 15.34 S-43 - S-43 - S-43 889.44 875.00 17.98 S-43 - S-4311 - S-4311 889.44 875.00 17.98 S-44 - S-44 - S-44 1,016.52 1,000.00 35.98 S-44 - S -44A- S -44A 1,002.41 1,000.00 35.81 S-44 - S -44L1 - S -44L1 1,016.52 1,000.00 35.98 S-44 - S -44L1 PB1 - S -44L1 PB1 1,016.52 1,000.00 35.98 S-504 - S-504 - S-504 132.60 125.00 103.59 Baker Hughes 1/2/2020 2:41:25PM Page 4 of 4 COMPASS 5000.15 Build 90 Remarks: WELL NAME S -210i CEMENT REPORT Date : 12/16/2019 Shoe 2853' MD Hole Size: FC A : 13-1/2 2764' MD Casing Size: Top Csq A : 10-3/4" X 9-5/8" GL / Surface Preflush (Spacer) Type: Mud Push II Density (ppg) : 10 Volume pumped (BBLs) : 100 Lead Slurry Type : LiteCRETE Sacks : 1440 Yield: 1.91 Density (ppg) : 11 Volume (BBLs) : 490 Mixing / Pumping Rate (bpm) : 5.5 Tail Slurry Type : GasBlock D500 Sacks : 339 Yield : 1.16 w a Density (ppg) : 15.8 Volume (BBLs) : 70 Mixing / Pumping Rate (bpm) : 6 U) Post Flush (Spacer) U) Type : Fresh Water Density (ppg) : 8.5 Rate (bpm) : 6 Volume: 10 bbl Displacement: Type : Max-Dril Density (ppg) : 9.2 Rate (bpm) : 10.00 Volume (actual / calculated) : 245.5/247.4 FCP (psi) : 575 Pump used for disp : Rig Plug Bumped? x Yes No Bump press : 1000 Casing Rotated? Yes X No Reciprocated? X Yes No % Returns during job : 96% Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Sur : —200 bbl Cement In Place At: 20:21 Date : 12/16/2019 Estimated TOC : Surface Method Used To Determine TOC: Cement to surface Remarks: Remarks: WELL NAME S-210i CEMENT REPORT Completion Date : 27-Dec-19 Shoe A 6042 MD Hole Size: 8.5 FC A : 5999 MD Casing Size: 3.5 Top Liner A : TBG TO SURFACE Preflush (Spacer) Type: MUDPUSH II Density (ppg) : 11 Volume pumped (bbls) : 41.9 BBLS Lead Slurry Type : LITECRETE HP GASBLOK Volume (bbls): 214.7 Density (ppg) : 13 Yield : 1.5 Sacks : 803.6221 Mixing / Pumping Rate (bpm) : 5 Tail Slurry Type : 15.0 ACID SOLUABLE Volume (bbls) : 79.7 Density (ppg) : 15 Yield : 1.26 Sacks : 355.1394048 Mixing / Pumping Rate (bpm) : 5 a Post Flush (Spacer) Type : N/A Density (ppg) : Rate (bpm) : Volume: Displacement: Type : BRINE Density (ppg) : 9.8 Rate (bpm) : 7 Volume (actual / calculated) : 51.8 ACTUAL FCP (psi) : 1022 Pump used for disp : RIG Plug Bumped? X Yes No Bump press : 1659 Casing Rotated? Yes X No Reciprocated? Yes X No % Returns during job : 100% Cement returns to surface? Yes X No Spacer returns? Yes X No Vol to Sur: N/A Cement In Place At: 0704 HRS Date : 12/27/2019 Estimated TOC: 2,303 Method Used To Determine TOC: CIR OUT 70 BBLS LEAD CMT FROM SLIDING SLEEVE AT 2303 AFTER PLUG BUMPED. Volume lost during displacement (bbls) : 0 BBLS Remarks: LVV � 1 118 ■ 116 ■ 121 ■ 44 ■- 125 ■ S—PAD M PAD MON. S-1 GRAPHIC SCALE 0 50 100 200 ( IN FEET ) 1 inch = 100 ft. NOTES: LEGEND: AS -BUILT CONDUCTOR EXISTING CONDUCTOR OPERATOR MONUMENT 1. ALASKA STATE PLANE COORDINATES ARE ZONE 4, NAD27. (EPSG:26734) 2. BASIS OF VERTICAL CONTROL IS S -PAD MONUMENT S-4, REFERENCE 2018 WELL BORE SUBSIDENCE STUDY HOLDING MON. S-4 (ELEV. 38.64') 3. VERTICAL DATUM IS BPXA M.S.L. 4. GEODETIC POSITIONS ARE NAD27. (EPSG:4267) 5. BEARINGS AND DISTANCES SHOWN ARE ALASKA STATE PLANE GRID 5. S -PAD AVERAGE SCALE FACTOR IS: 0.9999165. 6. DATE OF SURVEY: JULY 17. 2019. 7. REFERENCE FIELD BOO{: NS19-17 PP. 22-27. 8. COMPUTED RELATIVE ACCURACY (THIRD ORDER} BASELINE DISTANCE 1:27,440 BASELINE AZIMUTH: N/A ALLOWABLE VERTICAL CLOSURE ±0.01': FOUND: 0.002' 9. NAD27 COORDINATES DERIVED USING TRIMBLE BUSINESS CENTER-HCE. VER 3.92 TM PROJECT ............. . VICINITY MAP NTS SURVEYOR'S CERTIFICATE I HEREBY CERTIFY THAT 1 AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS AS -BUILT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF JULY 17, 2019. BASIS OF COORDINATES: HELD COORDINATES OF RECORD S -PAD MONUMENT S-1 Y- 5,979,431.54 N- 1,400.72 X= 619,321.07 E= 1,423.66 NAD27, ASP, ZONE 4 S -PAD PLANT DESCRIPTION: OPERATOR MONUMENT, PUNCH MARK ON EAST END OF PIPE SUPPORT FOR RELIEF UNE LOCATED WITHIN PROTRACTED SEC. 35, T. 12 N., R. 12 E., UMIAT MERIDIAN, ALASKA WELL NO. A.S.P. COORDINATES PLANT COORDINATES GEODETIC POSITION(DMS) GEODETIC POSITION(D.DD) SECTION OFFSETS PAD ELEVATION CELLAR BOX EL. BASE FLANGE EL. S-210 Y= 5,980,398.73 X= 618,930.02 N= 1,010.01 E= 456.24 70'21'18.363" 149'02'03.028" 70.3551008' 149.0341744' 4,196' FSL 4,503' FEL 35.2' 35.2' N/A ..yam. '^`��' 's_ e AWN: JACOBS y� ArAmw p CHECKED,DRAPER DATE 7/22/19 DRAWING: FRe19 wos 02 S—PAD AS—BUILT CONDUCTOR LOCATION WELL S-210 SHEET.WOA 1 OF 1 cCA4 AECC582 SM r.�srFtuu+c scA�E: 1•Q10D• W 22 1 ML$ED FOR WFaRwAT1Ri JJ am NO. DATE RVASION BY CNN Rixse, Melvin G (CED) From: Rixse, Melvin G (CED) Sent: Monday, March 16, 2020 4:19 PM To: Sternicki, Oliver R Cc: AK, GWO SUPT Well Integrity; Daniel, Ryan Subject: RE: S-210 PTD 219-057 Oliver, Looking back at the reports I find a passing CMIT-TXIA to 4000 psi, a passing MIT -T to 4710 psi, a CBL showing good cement. BPXA is good to go. Please be aware of the AIO 25A, Rule 6, for additional MITs after injection stabilization. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.RixseLbalaska.aqv). From: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Sent: Monday, March 16, 2020 2:16 PM To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Cc: AK, GWO SUPT Well Integrity<AKDCWellintegrityCoordinator@bp.com>; Daniel, Ryan <Ryan.Daniel@bp.com> Subject: RE: S-210 PTD 219-149 Mel, I wanted to check with you to see if the AOGCC was waiting on anything prior to BPXA bringing S-210 on initial injection. I wanted to make sure we had everything lined out before the slope team has the tie in work completed. Regards, Oliver Sternicki Ranbat wet" drR�:ntr�iwn Sr. Well Integrity Engineer BP Exploration Alaska Office: 1 (907) 564 4301 Cell: 1 (907) 350 0759 Oliver. sternickiCa)bp.com From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Sent: Tuesday, March 10, 2020 3:30 PM To: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Cc: AK, GWO SUPT Well Integrity <AKDCWellintegrityCoordinator@bp.com>; Bjork, David <David.Biork@bp.com>; Daniel, Ryan <Ryan.Daniel@bp.com> Subject: RE: S-210 PTD 219-149 Oliver, This is all I need at the moment. I will pass along to auditors here and let you know if AOGCC requires anything more. I will get back to you. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Sent: Tuesday, March 10, 2020 2:59 PM To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Cc: AK, GWO SUPT Well Integrity <AKDCWellintegrityCoordinator@bp.com>; Bjork, David <David.Biork@bp.com>; Daniel, Ryan <Ryan.Daniel@bp.com> Subject: RE: S-210 PTD 219-149 Mel, Rixse, Melvin G (CED) To: Youngmun, Alex Cc: Schwartz, Guy L (CED); David Bjork Subject: RE: S-210 PTD 219-149 Alex, AOGCC auditors reviewed the completion report for S-210. They were concerned that in the permitting for S-210, AOGCC had not provided ample assurance for injection integrity. Auditors had the following 2 concerns: (Can you answer their questions below?) 1. AOGCC did not require periodic MIT -Ts with a plug set in the X nipple at 5342'MD (uppermost X nipple) to assure longterm integrity in the 3-1/2" tubing/casing above the upper most injection zone at 5424'MD. Does BPXA have plans, other than the first annual water flow log to assure no injectivity above 5424'MD? AOGCC auditors suggested quadrennial MIT -T utilizing a plug set at 5342'MD. 2. The approved Permit to Drill allows this well for a 'Service - WAG injector', operating under AIO 25A, which, in addition to water, authorizes injection of enriched hydrocarbon gas for enhanced oil recovery. As it appears currently (from previous emails), BPXA plans to limit injection pressures to 1900 psi. Does this imply the well will be water injection and not WAG? The current injection order requires MIT -IA every 4 years to 1500 psi. If BPXA were to inject at pressures higher than 1900 psi, say enriched gas, would the quadrennial MIT -IA be performed to a higher pressure to assure containment in the IA in the event of a tubing failure? Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (MeIvin.Rixse@alaska.gov). From: Bjork, David <David.Bjork@bp.com> Sent: Friday, February 21, 2020 11:58 AM To: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov>; Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Youngmun, Alex <younak@BP.com> Subject: RE: S-210 PTD 219-149 Mel, Guy, Please see below for answers to your questions. Also attached is the completion report (Joe should have also sent it in, let me know if it did not come thru), post rig work starts at pg 22. Overall I think we are pretty happy with the completion design so far and look forward to getting it on injection. Happy to discuss whenever, I know we have played phone tag a bit. Thanks, Dave From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Sent: Tuesday, February 18, 2020 2:15 PM To: Youngmun, Alex <younak@BP.com>; Bjork, David <David.Biork@bp.com> Cc: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Subject: S-210 PTD 219-149 David, Alex, AOGCC is reviewing well S-210 (PTD219-149); We just want to assure we understand BPXA's plans for initial injectivity, maximum steady state injection pressure, future water flow monitoring, and integrity testing. Can you answer the following questions? 1. What initial pressures do expect to need to break down the cement barriers in the completions? Actual breakdown pressures were in the 1,200-1,600 range 0.5bpm for around 5bbls. a. How long would you sustain these pressures? I don't have the actual pressure charts, but it seemed to breakdown fairly easy. 2. What is BPXA's expected maximum steady state injection pressures after cement barrier breakdown? a. 1900 psi 3. Will there be continuous IA monitoring when this well is POI? Yes a. Will there be notification to AOGCC if IA shows communication to tubing pressure? We intend to follow standard well integrity practice for injectors. 4. The approved PTD requires a water flow log after one year of injection. How does BPXA flag this AOGCC requirement? Will this log be provided to AOGCC? a. These are currently being tracked using AKIMS (Alaska Integrity Management System). b. BP plans to provide the WFL to AOGCC. 5. A10 26 requires a Commission -witnessed mechanical integrity test after injection is commenced when injection conditions have stabilized. Subsequent tests must be performed at least once every four years thereafter. Is this in BPXA plans and how is this tracked? a. Tracked using AKIMS (Alaska Integrity Management System). Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.RixseCWalaska.Lov). cc. Guy '•loftanent Evaluation GL 1 6543' -1• BKRSDE POCKET MANDREL., .. _._. GAUGE CLAMP .0 5554'-1'BKRSDFPOCKETMANDREL.I .- -_.... GAUGE CLAMP .7 - .TREE.` MLUFAD- FMC SAFE 1 TYNOTEs. 770"'770"' 010"'. POLARS UM ACTUATOR = MACH GE S 2 O V&XL S-210 OKB ELEV 8168 ■ PERMR N. 219051 Dr u[v- aev KOP- 20•COND, 16? 6 5588 29r 8 128&19-.6974' AP`N SOOM7363000 M.. Arq* = 38' @.564': 129.L. X85. 2006' . -'}1/2' MES JI NP. o.7 e1r TFF SEC 15 T12N 812E .1N'F6L 1.30r FEL D.MO MO' 552f'�� ,D-— 5842 2 9r . 1286,19 D.m TVD - 5007 SS' 3 5694 2B2' 3 12rMn9 BP E.Pbr.�K11At.a.1 TOC---; 2393' Y 2303' --11? W OEFENDER SLD SLV, D-2860' 10AR'CSG.4359.L80VAM21.1D-§9S(P 2349' 2349'-ro-&WX*4V'XO,o-6Mr• 1 5779 29Y 1 1288139 - _ 1'.AKERS0E_P_OCKE7 WPdDRELS _ MD TVD TYPE VLV LATCH.PORI DAH __ �iB'c6G,.N,L80VAM21,D-6Y1• �` ,ST . .DEV. - -- __ - - 9 5.3. .989 35 BGLO EOOMY BK.? - t78EVt9 55.7 5096 35 BGLO EOOMY! BK -2 - 12!18'19 7 SSM 5712 35 " Bf101EODA/Y: RK .2 - 128819 65591 S. SS .0I EODMYRK -2 - 1?M19 55511 5154 35 WXO'�EODMY BX,2 - 1NM119 . 5637 5172 35 BOLO f EODMY RX -2 - IWW'19 3 5889 5215 36 9MO EODMV BK -2 - 1286119 _ 2 5751 5205 36 ROLO EODMY BK2 - 12M Minimum IO = 7 -sir e P1 w 1 577.. 52" 36 _ SCLOEOOW. 09-2 - ;'21M19 3412" HES XNIPPLE 5342'-31rrESXNP.D-281r 542r -1'SKR SDE POCKET MANDREL GAUGE CLAMP.10 ....6451• .'-34r HESX P.D-2813• NJECTIONSTATIONS F" BOTTOM OF GLM-_ 1 6543' -1• BKRSDE POCKET MANDREL., .. _._. GAUGE CLAMP .0 5554'-1'BKRSDFPOCKETMANDREL.I .- -_.... GAUGE CLAMP .7 - OEP1H. D GAUGE ADDRESSj_DAlE .NO _1• 9� 5128 292• 10 1286719 POLARS UM 5591'-BKR SIDE POCKET MANDREL VK 8 55.6 .292' 3 1286119 V&XL S-210 GAUGE CLAMP .6 7 5569 2 92' 7 12lm PERMR N. 219051 01133/10 KPUMD TREE RSTALLED 6 5588 29r 8 128&19-.6974' AP`N SOOM7363000 -'1'BKRSDF POCKETMANORELM --_-- 5 5619 29r 5 1286,19 SEC 15 T12N 812E .1N'F6L 1.30r FEL GAUGE CLAW.5 5842 2 9r . 1286,19 3 5694 2B2' 3 12rMn9 BP E.Pbr.�K11At.a.1 _. 5qT - 1'SKR SDE POCKET MANDREL.., __ j 2 5756 '29r 2 1286/15 GAUGE CLAMP.. 1 5779 29Y 1 1288139 599P-3-rHEs XNP.D-2.1r 5{55'-1'BKR SOF. POCKET MANORS, -w, GAUGE CLAW 63 5719'- -s1r HESX W. 9)-201r 5751' - V RKR SDE POCKET MANDRF I..1 ... .. -.. CAUDE CLAW .1 5774' -V SK" SDE POCKS I MANURI 1..1 GAUGE CLAMP .1 $661• ^3-1r1ESXNP. 4D-7613• ]'t TBc.92ttd vro 'b%'D-2,1.,- - 6042' • The 3-1/2" tubing was cemented in place on 12/27/2019 by pumping 42 bbls of spacer, followed by 215 bbls of 13 ppg Litecrete, followed by 80 bbls of 15 ppg Class G cement, followed by 52 bbls of 9.8 ppg brine. • No cement returns were observed at surface and no losses were measured. • The plug was successfully bumped and the floats held. • Excess cement and spacer was circulated out of the IA to surface from the sliding sleeve located at 2303' MD. • A memory cement bond log was performed on January 10, 2020 with the following results: • No cement is present in the IA from the sliding sleeve at 2303' MD to surface. • Excellent bond from cement to tubing and cement to formation is present from 2303'-4100' MD providing isolation between the topmost DPZ (OA sand at 5532' MD) and surface. • Cement exhibiting good bond to formation and lower bond to the casing is present from 4100'-4800' MD. • Cement exhibiting lower bond to formation and casing is present from 4800' to the first reading of the CBL tool at 5822' MD. Formation arrivals however are present throughout this interval demonstrating that there is cement in place. 1 1 DATE REV BY COMMENTS DATE REV BY COMMENTS POLARS UM 12R.D9 P-272 MmALCONPLEnOR _ V&XL S-210 Otg9n9 JAD DrRG110 CORREC tONs PERMR N. 219051 01133/10 KPUMD TREE RSTALLED _ AP`N SOOM7363000 0114?0 NNVMD COr6tECTONS ---- _-- •. SEC 15 T12N 812E .1N'F6L 1.30r FEL 0"41 N -0M NALOM APPRDYN. -...... ____-_-_..... BP E.Pbr.�K11At.a.1 • The 3-1/2" tubing was cemented in place on 12/27/2019 by pumping 42 bbls of spacer, followed by 215 bbls of 13 ppg Litecrete, followed by 80 bbls of 15 ppg Class G cement, followed by 52 bbls of 9.8 ppg brine. • No cement returns were observed at surface and no losses were measured. • The plug was successfully bumped and the floats held. • Excess cement and spacer was circulated out of the IA to surface from the sliding sleeve located at 2303' MD. • A memory cement bond log was performed on January 10, 2020 with the following results: • No cement is present in the IA from the sliding sleeve at 2303' MD to surface. • Excellent bond from cement to tubing and cement to formation is present from 2303'-4100' MD providing isolation between the topmost DPZ (OA sand at 5532' MD) and surface. • Cement exhibiting good bond to formation and lower bond to the casing is present from 4100'-4800' MD. • Cement exhibiting lower bond to formation and casing is present from 4800' to the first reading of the CBL tool at 5822' MD. Formation arrivals however are present throughout this interval demonstrating that there is cement in place. 1 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Gorham, Bradley M <Bradley.Gorham@bp.com> Sent: Tuesday, April 16, 2019 12:06 PM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Mel, This well is the first of the new Schrader Bluff injector design that Dave Bjork discussed with Guy and yourself back in December of last year. If you would like to discuss further we'd be happy to set up a conference call to ensure we have answered all your questions. Let me know what times work best for you and we will try to accommodate as best as we can. Thanks, Brad Gorham BP Exploration (Alaska), Inc. Drilling Engineer W: (907)564-4649 C: (907)223-9529 Bradley.Gorham@bp.com From: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Sent: Tuesday, April 16, 2019 11:06 AM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Subject: PTD Request 219-057, PBU S-210 Variance Request Brad, On page 8 under 'Variance Requests' for the BPXA PTD request for S-210, there is no discussion for a request for variance to: 20AAC25.412. Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage which states: (b) A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. Please provide written justification why a cemented 3-1/2" tubing string would provide an equally effective means of accomplishing 20 AAC 25.412 (b) Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231) or (Melvin.Rixse@alaska.gov). Rixse, Melvin G (CED) From: Bjork, David <David.Bjork@bp.com> Sent: Thursday, May 16, 2019 1:54 PM To: Rixse, Melvin G (CED); Schwartz, Guy L (CED) Cc: Gorham, Bradley M Subject: FW: PTD Request 219-057, PBU 5-210 Variance Request Mel, Guy, Please review the below discussion of injection pressures, confinement monitoring and explanation for variance request. Thank you for your consideration and assistance working through the new completion design. Please don't hesitate to call if you would like to discuss. Regards, Dave Bjork (907) 564-5683 (907) 440-0331 Schrader Bluff Injection will be managed in within the parameters set forth in Area Injection Order 26A May 1, 2006. Injection Confining Intervals: The upper contact between the N Sands and the overlying Prince Creek formation is generally an abrupt transition from sandstone to mudstone forming the upper confinement. The Lower Prince Creek formation (Ma -Mc sands) typically contains over 30 feet of laterally continuous shales and mudstones. Mudstones and muddy siltstones up to 1000 feet thick provide the basal confinement of the Schrader sandstones. Fracture Information The Commission originally ordered that injection pressures be maintained below 0.67 psi/ft to ensure that Orion injected water does not fracture or migrate out of zone, and based its decision upon BPXA's estimate of a 0.66 - 0.67 psi/ft fracture pressure for the confining mudstone using data from stress tests and dipole sonic log. Several tests conducted with the Commission's approval support BPXA's conclusion that increased injection pressures will not result in migration out of zone. A zonal isolation test was completed in Orion well L- 210 in April 2005. Sand -face pressure gauges were installed adjacent to discrete zones both above and below an isolated injection interval in order to record pressure response and reveal whether injection was breaching the confining barriers. The two perforated zones were separated by around 28 feet TVD of unperforated OA interval comprised of silty mudstone. Injection rates of up to 4200 BWPD with an injection gradient of up to 0.82 psi/ft were achieved while injecting into the lower zone. No pressure response in the adjacent zone was seen; hence, the water did not breach out of zone. Additional step rate and pulse tests in Polaris and Milne Point Schrader formations showed similar results. On December 13, 2005 the Commission administratively approved elimination of the injection pressure limitation. However, injection pressure must be maintained such that injected fluids do not fracture the confining zones or migrate out of the approved injection stratum. BPXA will monitor each injection well and if any significant change in injectivity indicates injection out of zone, surveillance will be conducted to determine the cause of the injection anomaly. Planned cement tops for this completion style is in excess of 2,000ft of cement above injection zone. Confinement Monitoring will be performed on a two year MIT -T and MIT testing cycle. A waterflow log will also be performed at the testing anniversary. Daily tubing and Annulus pressure will be noted, and any anomalies communicated to the Well Integrity Team for evaluation. From: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Sent: Thursday, April 18, 2019 1:14 PM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Cc: Schwartz, Guy L (DOA) <guy.schwa rtz@alaska.gov> Subject: FW: PTD Request 219-057, PBU S-210 Variance Request Brad, AOGCC does not consider 'volume of cement' sufficient justification to provide a variance to: 20AAC25.412. Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage (b) A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. The proposed well design no longer provides an additional cemented casing shoe as an additional barrier to isolate injection from permeable zones above the targeted zone. AOGCC will require BPXA to provide "an equally effective means of accomplishing the requirement set out in the commission's regulation". In addition to cement volume, I would encourage BPXA to provide a thorough discussion of: 1. Production practices (injection pressures etc.) 2. Confinement monitoring for the life -of -well. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin Rixs 0alaska.gov). cc. Guy Schwartz From: Gorham, Bradley M <Bradley.Gorham@bp.com> Sent: Wednesday, April 17, 2019 1:41 PM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Cc: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Mel, Please see below for the written variance request. Let me know if there is any other information you need or if you have any questions. The new injector design involves the use of a significant volume of cement to provide zonal isolation to the Schrader Bluff reservoir as well as to provide mechanical integrity on the inner annulus. Due to the volume of cement being placed in the well, it is requested that the utilization of a production packer is unnecessary. This is a variance from 20 AAC 25.412. Thanks, Brad Gorham BP Exploration (Alaska), Inc. Drilling Engineer W: (907)564-4649 C: (907)223-9529 Bradley.Gorham@bp.com From: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Sent: Tuesday, April 16, 2019 1:14 PM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Cc: Schwartz, Guy L (DOA) <guy.schwa rtz@aIaska.gov> Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Brad, Please provide a written variance request to 20 AAC 25.412 as noted in the attached email. As discussed with David Bjork, it is expected that AOGCC commissioners will approve this PTD request. A complete discussion of confinement and scheduled confinement monitoring in the BPXA variance request will be required. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin. Rixse a alaskav). cc. Guy Schwartz From: Rixse, Melvin G (DOA) Sent: Tuesday, April 16, 2019 12:14 PM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Brad, Agreed. I expect we (commissioners) will still want a written variance request. I will get back to you. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell Rixse, Melvin G (CED) From: Bjork, David <David.Bjork@bp.com> Sent: Friday, February 21, 2020 11:58 AM To: Rixse, Melvin G (CED); Schwartz, Guy L (CED) Cc: Youngmun, Alex Subject: RE: S-210 PTD 219-149 Attachments: S-210 10-407 Completion Report.pdf Mel, Guy, Please see below for answers to your questions. Also attached is the completion report (Joe should have also sent it in, let me know if it did not come thru), post rig work starts at pg 22. Overall I think we are pretty happy with the completion design so far and look forward to getting it on injection. Happy to discuss whenever, I know we have played phone tag a bit. Thanks, �� V Dave From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> `,(\ Sent: Tuesday, February 18, 2020 2:15 PM To: Youngmun, Alex <younak@BP.com>; Bjork, David <David.Biork@bp.com> Cc: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> L� Subject: S-210 PTD 219-149 David, Alex, AOGCC is reviewing well S-210 (PTD219-149); We just want to assure we understand BPXA's plans for initial injectivity, maximum st ady state injection pressure, future water flow monitoring, and integrity testing. Can you answer the following questions? 1. What initial pressures do expect to need to break down the cement barriers in the completions? Actual breakdown pressures were in the 1,200-1,600 range 0.5bpm for around 5bbls. // a. How long would you sustain these pressures? I dont have the actual pressure charts, but it seemed to breakd wn fairly easy. 2. What is BPXA's expected maximum steady state injection pressures after cement barrier breakdown? a. 1900 psi 3. Will there be continuous IA monitoring when this well is POI? Yes a. Will there be notification to AOGCC if IA shows communication to tubing pressure? We intend to follow standard well integrity practice for injectors. 6vc- (L c tJ�}� Si:rti2 rc�l kv- 4. The approved PTD requires a water flow log after one year of injection. How does BPXA flag this AOGCC requirement? Will this log be provided to AOGCC? These are currently being tracked using AKIMS (Alaska Integrity Management System). BP plans to provide the WFL to AOGCC. 5. AIO 26 requires a Commission -witnessed mechanical integrity test after injection is commenced when injection conditions have stabilized. Subsequent tests must be performed at least once every four years thereafter' Is this in BPXA plans and how is this tracked? a. Tracked using AKIMS (Alaska Integrity Management System). \ / Mel Rixsez1- Senior Petroleum Engineer (PE) co l r — Alaska Oil and Gas Conservation Commission 907-793-1231 Office r 907-223-3605 Cell W CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil nd 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 i ch 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 Ylou, contact Mel Rixse at (907-793-1231) or (Melvin. Rixse@alaska.Rov). CC. Guy �\ / r {� s� Lam- Vtk co Y TREE = GE WELLHEAD = FMC ACTUATOR = MACH GE OKB. ELEV = 81.68' BF. ELEV = —38.17' KOP = 10 Max Angle = 38' @ 4564' Dahsn MD = 5526' Dahm TVD = _ 5000' SS r " COND,9.45#, X-05,= " TOC PER SLB MEMORY CBL (01/10/20) 2318- 110-3/4- CSG, 45.5#, L-80 VAM 21, ID = 9.950" 2349' 9x18" CSG, 47#, L-80 VAM 21, ID = 8.681" 2853" Minimum ID = 2.813"@ 2008' 3-112" HES X NIPPLE S-210 SAFETY NOTES: MAX DLS: 5.3" @ 1086'. i ' e-yJ yFs 7,010 g /✓ d sr Irl�L Q 5 wr A-,. ¢� 1 rz� 4/sav -Y- Z Z6z = /TsX s S�, IN E�T TATIONS '4) 2_ ' ROMIiOTTOM OF GI M" 7 NO DEPTH D GAUGE ADDRESS DATE ZONE 9 5429 2.92" 10 12/26/19 Nb 8 5548 2.92" 8 1226/19 OA 7 5569 2.92" 7 1226/19 OA 6 5596 2.92" 6 1226/19 OBa 5 5619 2.92" 5 1226/19 OBa 4 5642 2.92" 4 1226/19 OBb 3 5694 2.92" 3 1226/19 OBc 2 5756 2.92" 2 1226/19 OBd 1 5779 2.92" 1 1226/19 OBd 9 S 2008' --13-12" HES X NIP, ID = 2.813" 2303' 3-12" BOT HP DEFENDER SLD SLV, ID = 2.813" SLD SLV PERMANENTLYCLOSED (01/10/20) 2349' 10-0/4" X 9-5/8" XO, ID = 8.681" 1" RAKFR Cf1F PCY:KFT MANn Pr -1 C ST MD TVD DEV TYPE VLV LATCH PORT DATE 9 5424 4999 35 BKR DMY BK 0 01/17/20 8 5543 5096 35 BKR RWF BK 5/32" 01/17/20 7 5564 5112 35 BKR DMY BK 0 01/17/20 6 5591 5134 35 BKR RWF BK 9/32" 01/17/20 5 5614 5154 35 BKR DMY BK 0 01/17/20 4 5637 5172 35 BKR RWF BK 5/32" 01/17/20 3 5689 5215 36 BKR RWF BK 5/32" 01/17/20 2 5751 5265 36 BKR RWF BK 5/32" 01/17/20 1 5774 5284 36 BKR DMY BK 0 01/17/20 5342' -� 3-12" HES X NIP, ID = 2.813" 5424'1' BKR SIDE POC KET MAND RE L w/ GAUGE CLAMP #10 ,C, 6481' 3-12- HES X NIP, D = 2.813' ` 5543' —11" BKR SIDE POCKET MANDREL w/ GAUGE CLAMP #8 5564' 1- BKR SIDEPOCKET MANDREL w/ GAUGE C LAMP #7 5591' 1" BKR SIDE POCKETMANDREL w/ GAUGE CLAMP #6 5614' 1" BKR SIDE POCKET MANDREL w/ GAUGE CLAMP #5 5637' 1" BKR SIDE POCKET MANDREL w/ GAUGE CLAM P #4 5668' 3-12" HES X NIP, ID = 2.813" 5689' 1' BKR SIDE POCKET MANDREL w/ GAUGE CLAMP #3 5716' 3-12" HES X NIP, ID 5751' 1' BKR SIDE POCKET MAND REL w/ GAUGE CLAMP #2 1"BKR SIDE POCKET MANDREL w/ / GAUGE CLAMP #1 5801' 3-12" HES X NIP, ID = 2.813" PBTD 6966' 3-12" TBG, 9.2#, L-80 VT, .0087 bfp, ID = 2.992"6--i POLARIS UNIT WELL: S-210 PERMIT No: 219-057 API No: 50-029-23630-00 SEC 35, T12N, R12E, 4196' FSL 8 4503' FEL DATE REV BY COMMENTS DATE REV BY COMMENTS 1228/19 P-272 INITIAL COMPLETION 02/1020 CJWJMD WFR C/O (01/1720) 01/09/19 JMD DRLG HO CORRECTIONS 02/1020 AY/JMD ADDED ZONES TO INJECTION TABLE 01/1320 KP/JMD TREE INSTALLED 01/1420 NN/JMD CORRECTIONS 01/1420 NN/JMD FINAL ODE APPROVAL BP Exploration (Alaska) 01/3020 ICJNIJMDI EDITTO TOC & DEFENDER SLD SLVI STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7`h Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF BP ) Area Injection Order No. 25A EXPLORATION (ALASKA) INC. for ) modification of Area Injection ) Prudhoe Bay Field Order 25 to authorize underground ) Polaris Oil Pool injection of enriched hydrocarbon ) gas for enhanced oil recovery in ) Polaris Oil Pool, Prudhoe Bay Field, ) November 28, 2005 North Slope, Alaska; and THE PROPOSAL initiated by the Commission to amend underground injection orders to incorporate consistent language addressing the mechanical integrity of wells IT APPEARING THAT: 1. By application dated August 23, 2005 BP Exploration (Alaska) Inc. (`BPXA") in its capacity as Polaris Operator and Unit Operator of the Prudhoe Bay Unit ("PBU") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") modifying Area Injection Order 25 ("AIO 25") to authorize the injection of enriched hydrocarbon gas for enhanced oil recovery purposes in the Polaris Oil Pool within the PBU. 2. The Commission published notice of opportunity for public hearing on BPXA's application in the Anchorage Daily News on September 6, 2005. 3. The Commission received no comments or protests regarding BPXA's application. 4. The Commission held a public hearing October 13, 2005 at the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. 5. On its own motion the Commission proposed to amend the rules addressing mechanical integrity in all existing orders authorizing underground injection. The Commission published notice of opportunity for public hearing on the proposal in the Anchorage Daily News on October 3, 2004. 6. By e-mail dated October 15, 2004, BPXA suggested edits to the Commission's proposed language addressing the mechanical integrity of injection wells. 7. No protests to the Commission's proposal or requests for hearing were received, and the hearing was vacated. Area Injection Order 25A November 28, 2005 FINDINGS: 1. Operator: 0 Page 2 BPXA is Operator of the Polaris Oil Pool in the Prudhoe Bay Field, North Slope, Alaska. 2. Formations Authorized for Enhanced Recovery: The currently approved strata for enhanced recovery injection are a subset of the Polaris Oil Pool defined in Conservation Order 484 and correlated with the N- and 0 - Sand interval between 5,603 feet and 6,012 feet measured depths ("MD") in Prudhoe Bay Unit well S-200PB 1. BPXA has not requested changes to the approved strata for injection. 3. Proposed Injection Area: BPXA requested authorization to inject fluids for the purpose of enhanced recovery on portions of lands within Umiat Meridian T11N-R12E, T11N-R13E, T12N-Rl2E, and T12N-R13E in the Prudhoe Bay Unit. The application for the AIO 25 modification provides information surrounding three injection wells. These proposed injectors are wells S -215i, W -209i, and W-2151. 4. Operators/Surface Owners Notification: BPXA provided operators and surface owners within one-quarter mile of the proposed area with a copy of the application for injection. The only affected operator is BPXA, Operator of the Prudhoe Bay Unit. The State of Alaska, Department of Natural Resources is the only affected surface owner. 5. Description of Operation: The contemplated operation is an enhanced oil recovery ("EOR") project using enriched gas from the Prudhoe Bay Central Gas Facility. The project involves the cyclical injection of water alternating with injection of hydrocarbon gas enriched with intermediate hydrocarbons, principally ethane and propane. Implementation of the Polaris EOR project will involve connection of Polaris injection wells to existing or new miscible gas injection distribution systems on M, S, and W Pads. Enriched hydrocarbon gas injection is expected to occur in late 2005. 6. Hydrocarbon Recovery: The Polaris Oil Pool is estimated to contain 350 to 750 million barrels of original oil in place ("OOIP") based on exploratory drilling and seismic mapping. Combined primary and secondary recovery is estimated at 15-30% of the OOIP. Preliminary evaluations suggest that the EOR project could yield an incremental recovery of up to 6% where implemented. These recovery estimates were obtained using an Equation of State ("EOS") developed for the Polaris reservoir fluid. Area Injection Order 25A November 28, 2005 Page 3 Laboratory swell, multiple contact, and slimtube experiments were conducted using Polaris oil and the PBU enriched gas and were used to develop a new Polaris EOS. Fully compositional, mechanistic type pattern model simulations were conducted using the Polaris EOS for a W Pad reservoir description. In part of the project area where the reservoir oil has sufficient concentration of C7 -C13, the enriched gas forms a miscible bank with the reservoir oil through exchange of hydrocarbon components, and displaces nearly all of the contacted oil. In areas where the oil lacks sufficient concentration of C7 -C13 components to be miscible with the Prudhoe enriched gas at reservoir conditions, miscibility may not occur. Rather, a multiple contact condensing/vaporizing mass transfer mechanism between reservoir oil and the CO2 and C2-C4 in the Prudhoe enriched gas causes a significant reduction in reservoir oil viscosity. BPXA states that the magnitude of tertiary oil recovery by this "viscosity reducing, immiscible enriched gas flood" is very close to that recovered with miscible gas injection. A fifty -fold reduction in viscosity of a 40 cp Polaris oil was found by contacting the PBU enriched gas in a single cell multiple -contact laboratory experiment conducted at reservoir conditions. Gross utilization of Prudhoe enriched gas was estimated to be around 5.3 thousand cubic feet ("MCF") of enriched gas injected for every barrel of EOR oil. This is similar to the efficiency at other satellite Prudhoe projects and compares to an efficiency of about 15-20 MCF/barrel for enriched gas injection in the mature IPA EOR project area, which justifies the preferential injection of Prudhoe enriched gas into the Polaris Oil Pool. 7. Geologic Information: a. Stratigraphy: The Polaris Oil Pool encompasses reservoirs assigned to the Late Cretaceous -age Schrader Bluff Formation ("Schrader Bluff') and the Early Tertiary -age Ugnu Formation ("Ugnu"). The approved injection interval is only the Schrader Bluff Formation. AIO 25 dated February 3, 2003 provides a full geologic description of the Polaris Oil Pool. b. Confining Intervals: Lower confinement for the Polaris Oil Pool is provided by the non -reservoir, laminated muddy siltstone that constitutes the base of the OBf interval and 1,100 feet of mudstone and silty mudstone assigned to the upper Colville Group. The basal portion of the Schrader Bluff N -Sands interval consists of non -reservoir mudstone and siltstone that forms a regionally extensive hydraulic barrier. This barrier separates lighter, higher quality oil in the O -Sands from the heavier oil accumulations in the overlying N- and M -Sand intervals. The MC -Sand is separated from the underlying N -Sands by a silty mudstone that ranges in thickness from 15 to 25 feet. Upper confinement is provided by a 14- to 25 -foot thick mudstone that lies at the base of the M132 interval and forms a regionally continuous hydraulic barrier. This mudstone layer separates oil-bearing MC -Sand from overlying, water -bearing M132 -Sand within the pool. A 9- to 15 -foot thick silty mudstone overlies the Area Injection Order 25A November 28, 2005 uppermost MA -Sand and provides a regionally extensive barrier. 8. Well Logs: The logs of existing injection wells are on file with the Commission. 9. Mechanical Integrity of Injection Wells and Wells within'/4 mile of injector: Page 4 Wells recently drilled into the Polaris Oil Pool have been constructed in conformance with Commission regulations. Three wells are currently proposed for enhanced gas injection service: Wells S -215i, W -209i, and W-2151. Mechanical integrity has previously been established for the subject wells and all wells within '/4 mile of these injectors have been reviewed. The Commission approved these wells for water injection. Changes proposed by the Commission in the rules governing demonstration of mechanical integrity, well integrity failure and confinement, and administrative actions will improve clarity, reduce the potential for confusion, and better protect mechanical integrity of injection wells. 10. Type of Fluid / Source: In addition to water for injection supplied from Gathering Center 2 and from the Seawater Treatment Plant, enriched hydrocarbon gas from the Prudhoe Bay Central Gas Facility will be injected. In addition, tracer survey fluids and well stimulation fluids will be injected periodically to ensure efficient operation of the water flood. Non -hazardous filtered water collected from Polaris Oil Pool well house cellars and well pads may also be injected. 11. Enriched Gas Composition and Compatibility with Formation: The enriched gas proposed for injection is a hydrocarbon with similar composition to reservoir fluids in the Polaris Oil Pool and therefore no compatibility issues are anticipated. The compatibility of the injection waters was addressed in AIO 25 dated February 3, 2003. 12. Injection Rates and Pressures. Fracture Information: The anticipated maximum gas injection requirements are 15,000 MCF per day. The requested maximum water injection rate is 50,000 barrels of water per day ("BWPD") in the project area. The individual well injection rates will range from 1000 to 5000 BWPD. The surface injection pressure for the enriched gas will be around 3400 psi, with a maximum surface injection pressure of 4500 psi. Miscible gas and water injection operations are expected to be above the Schrader Bluff Formation parting pressure to enhance injectivity and improve recovery of oil. Miscible gas injection is not anticipated to cause fracture propagation through the confining intervals. Fracture propagation models and operations involving injection of highly viscous fluids at high rates have not created net pressures sufficient to exceed the integrity of the confining layers. Area Injection Order 25A November 28, 2005 13. Rule 10 — W-17 Surveillance: ) Page 5 In the original AIO 25 the Commission ordered that temperature logs be run in W-17. This surveillance was required because well W-17 is within 255 feet of proposed injector W-2121 and there was insufficient information at the time to demonstrate cement confinement across the Polaris Oil Pool in well W-17. The required temperature surveys indicate that the Polaris Oil Pool is isolated within W-17 and no further action is needed at this time. CONCLUSIONS: 1. The application requirements of 20 AAC 25.402 have been met. 2. Enriched gas injection will significantly improve recovery. 5. The proposed injection operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 6. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 7. Reservoir and well surveillance, coupled with regularly scheduled mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 8. The findings and conclusions of AI0 25 dated February 3, 2003, are incorporated by reference to the extent not inconsistent with this order. 9. Revisions as proposed by the Commission are appropriate concerning the rules governing demonstration of mechanical integrity, well integrity failure and confinement, and administrative actions. 10. Rule 10 concerning surveillance requirements in W-17 is no longer necessary because BPXA has satisfied those requirements. NOW, THEREFORE, IT IS ORDERED that: 1. Within the affected area, this order supersedes and replaces Area Injection Order 25 dated February 3, 2003. 2. The underground injection of fluids for enhanced oil recovery as described in BPXA's application is authorized, as modified by and subject to the following rules and the statewide requirements under 20 AAC 25 (to the extent not superseded by these rules) in the following affected area. Area Injection Order 25A November 28, 2005 Umiat Meridian Page 6 Township / Range Lease Sections T12N-R12E ADL 28256 Sec 22 S/2 S/2 and NE/4 SE/4 ADL 47448 Sec 23 S/2 NW/4 and SW/4 ADL 28257 Sec 25 SW/4 NW/4 and SW/4 and SW/4 SE/4, 26, 35, 36 ADL 28258 Sec 27, 33 SE/4 SE/4, 34 E/2 W/2 and SW/4 S W/4 and E/2 T12N-R13E ADL 28279 Sec 31 SW/4 NW/4 and SW/4 T11N-R13E ADL 28282 Sec 6 W/2 and SE/4 and S/2 NE/4 and NW/4 NE/4, Sec 7 N/2 and N/2 SW/4 and SE/4 SWA and SE/4, Sec 8 W/2 SW/4 T11N-R12E ADL 28260 Sec 1, 2, 11 W/2 and NW/4 NE/4, 12 N/2 N/2 and SE/4 NE/4 ADL 28261 Sec 3, 4 E/2 E/2, 9 NE/4 NE/4 and S/2 NE/4 and SE/4, 10 ADL 28263-1 Sec 15, 16 E/2 ADL 28263-2 Sec 21 NE/4 NW/4 and NE/4 SE/4 and NE/4, 22 N/2 and N/2 SW/4 and SEA SW/4 and SE/4 ADL 47451 Sec 14 W/2 and W/2 SE/4, 23 W/2 and W/2 E/2 and SE/4 SE/4 and SE/4 NE/4 ADL 28264 Sec 26 N/2 N/2 ADL 47452 Sec 27 NEA NE/4 Area Injection Order 25A Page 7 November 28, 2005 Rule 1 Authorized Injection Strata for Enhanced Recovery (AIO 25) Authorized fluids may be injected for purposes of pressure maintenance and enhanced oil recovery into strata that are common to, and correlate with the N- and O -Sand interval between 5,603 feet and 6,012 feet MD in Prudhoe Bay Unit well S-200PB 1. Rule 2 Fluid Infection Wells (Revised this Order — AIO 25A) The underground injection of enriched gas for enhanced oil recovery is authorized only in the following wells: S-2151, W -209i, and W -215i. Upon proper application, the Commission may approve additional wells for injection of enriched gas within the Polaris Oil Pool. The application to drill or convert a well for injection must include a report on the cementing records, cement quality log or formation integrity test records of each well that has penetrated the injection zone within a one-quarter mile radius of the proposed injection well. Rule 3 Authorized Fluids for Enhanced Recovery (Revised by this Order — AIO 25A Fluids authorized for injection are: a. produced water from the Polaris Oil Pool or Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; b. tracer survey fluid to monitor reservoir performance; c. enriched hydrocarbon gas from the Prudhoe Central Gas Facility; d. source water from a sea water treatment plant; e. non -hazardous filtered water collected from Polaris Oil Pool well house cellars and well pads; and f. enriched hydrocarbon gas from the Prudhoe Bay Unit processing facilities. Rule 4 Authorized Injection Pressure for Enhanced Recovery (AIO 25.003) a. Injection pressure must be maintained so that injected fluids do not fracture the confining zone or migrate out of the approved injection stratum. b. Within three months of start of injection in a new or converted injector, a step rate test and surveillance log must be run for detection of fluids moving out of the approved injection stratum. Results must be submitted to the commission. c. If fluids are found to be fracturing the confining zone or migrating out of the approved injection stratum, the Operator must immediately shut in the injector(s). Injection may not be restarted unless approved by the Commission. Area Injection Order 25A Page 8 November 28, 2005 Rule 5 Monitoring Tubing -Casing Annulus Pressure (Revised by this Order AIO 25A) The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by extreme weather condition, emergency situations, or similar unavoidable circumstances. Monitoring results shall be documented and made available for Commission inspection. Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Revised by this Order AIO 25A) A Commission -witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter (except at least once every two years in the case of a slurry injection well). The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. Results of mechanical integrity tests must be readily available for Commission inspection. Rule 7 Multiple Completion of Water Iniection Wells a. Water injectors may be completed to allow for injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the Commission. b. Prior to initiation of commingled injection, the Commission must approve methods for allocation of injection to the separate pools. c. Results of logs or surveys used for determining the allocation of water injection between pools, if applicable, must be supplied in the annual reservoir surveillance report. d. An approved injection order is required prior to commencement of injection in each pool. Rule 8 Well Integrity Failure and Confinement (Revised by this Order AI025A) Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall notify the Commission by the next business day and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection. Area Injection Order 25A Page 9 November 28, 2005 Rule 9 Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 2 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the Commission, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 10 W-17 Surveillance (Revoked by this Order - AIO 25A) Rule 11 Plugging and Abandonment of Fluid Injection Wells (AIO 25) An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25. Rule 12 Other conditions (AIO 25) a. It is a condition of this authorization that the operator complies with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 13 Administrative Actions (Revised by this Order - AIO 25A) Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. a chor , Alaska e' �JJtf' ,st 1 o an Chairman Cathy. Foerster Comm ssioner AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10 -day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30 -day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). WELL LOG TRANSMITTAL # To: Alaska Oil and Gas Conservation Comm. February 11, 2020 Attn.: Natural Resource Technician 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 R6" RE: Reservoir Description (RDT) Log: 5-210 FEB 13 2020�®� �� Run Date: 12/20/2019 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of. Fanny Sari, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 S-210 Digital Data (LAS), Digital Log file 50-029-23630-00 1 CD Rom PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline & Perforating Attn: Fanny Sari 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-275-2605 FRS_ANC@halliburton.com and GANCPDC@USAANC.hou.xwh.BP.com Date: Signed: 2 190 57 32 04 0 Baker Hughes PRINT DISTRIBUTION LIST COMPANY BP Exploration Alaska Inc. WELL NAME S-210 FIELD Prudhoe Bay Unit COUNTY PRUDHOE BAY BHI DISTRICT Alaska AUTHORIZED BY Paul Canizares EMAIL Paul.CanlZares bakerhugheS.COm STATUS Final Replacement COMPANY ADDRESS (FEDEX WILL NOT DELIVER To P.O. BOX) PERSON ATTENTION V BP Nortb Slope. EOA, PBOC, PRB-20 (Office 109) D&C Wells Project Aides :Attn: Benda Glassmaker & Peggy O'Neil :900 E. Benson Blvd. ;Anchorage, Alaska 99508 ------------------------------------------------------------- - -----------------....------......----------------------...- ------ ----- ----- ----- 2 --- 2 ConocoPhillips Alaska Inc. :Attn: Ricky Elgarico :ATO 3-344 700 G Street :Anchorage, AK 99510 ----_------------------------------.........--------........ ---- - ------------- ----------------------------- .... 3 ExxonMobil Upstream Oil & Gas, US Conventional C/o ExxonMobil Upstream Integrated Solutions Company ;Attn: Technical Data Center (TDC) 22777 Springwoods Village Parkway : N2.2A.332 ;Spring, Texas 77389 .......................................... - — ------------------------- ------------ -- 4iState of Alaska - AOGCC Attn: Natural Resources Technitian :333 W. 7th Ave, Suite 100 !Anchorage, Alaska 99501 ----- ---- ----- - - - -- - 5DNR- Division of Oil & Gas *** :Attn: Rersource Evaluation Section ;550 West 7th Avenue, Suite 1100 '.Anchorage, Alaska 99501 *** Stamp "confidential" on all material deliver 21 9057 32 03 1 Please sign and return one copy of this transmittal form to: BP Exploration (Alaska) Inc. Petrotechnical Data Center, L132-1 900 E. Benson Blvd. Anchorage, Alaska 99508 or GANCPDC@bp365.onmicrosoft.com Ito acknowledge receipt of this data. LOG TYPE GR-RES-DEN-NEU LOG DATE December 19, 2019 TODAYS DATE February 7, 2020 Revision No Details: Requested by: FIELD / FINAL CD/DVD FINAL PRELIM LOGS (las, dlis, PDF, META, SURVEY REPORT LOGS CGM, Final Surveys) (Compass) # OF PRINTS # OF COPIES J# OF COPIES J# OF COPIES 4 4 JV-2019-USONSHOR-288 6:BP Exploration (Alaska) Inc. Petrotechnical Data Center, LR2-1 !900 E. Benson Blvd. 'Anchorage, Alaska 99508 Attn: Nancy Landi ............... TOTALS FOR THIS PAGE: 0 0 4 0 0 THE STATE 'ALASKA GOVERNOR MIKE DUNLEAVY Kenneth Allen Engineering Team Lead BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 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 Re: Prudhoe Bay Field, Polaris Oil Pool, PBU S-210 BP Exploration (Alaska), Inc. Permit to Drill Number: 219-057 Surface Location: 4196' FSL, 4503' FEL, SEC. 35, T12N, R12E, UM Bottomhole Location: 692' FSL, 5256' FEL, SEC. 26, T12N, R12E, UM Dear Mr. Allen: Enclosed is the approved application for the permit to drill the above referenced service 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. 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, w V,si,11. Chmielowski Commissioner DATED this 10 day of June, 2019. STATE OF ALASKA 4SKA OIL AND GAS CONSERVATION COMMISS PERMIT TO DRILL 20 AAC 25.005 ■ ■IllVL.I V L.LJ APR 01 2019 la. Type of Work: 1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG 0 - Service - Disp❑ 1c. Spec' s-* p d for: Drill D ' Lateral ❑ Strati ra hic Test ❑ 9 P Development -Oil ❑ Service - Winj ❑ Single Zone gJ ` Coalbed Gas El Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory Oil ❑ Development - Gas ❑ Service - Supply ❑ Multi FeZonerb P ry- P PP Y P Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond Blanket 0 . Single Well ❑ 11 Well Name and Number: BP Exploration (Alaska), Inc Bond No. 29S105380 PBU S-210 . 3 Address: 6. Proposed Depth: 12. Field/Pool(s): P.O. Box 196612 Anchorage, AK 99519-6612 MD: 6045' . TVD: 5508' PRUDHOE BAY, POLARIS OIL 4a. Location of Well Governmental Section): ( ) 7. Property Designation (Lease Number): ADL 028257„$.02$258 'Z % g DNR Approval Number: 13. Approximate spud date: Surface: 4196 FSL, 4503' FEL, Sec. 35, T12N, R12E, UM 294' FSL, 5138' FEL, Sec. 26, T12N, R12E, UM 83-47 January 10, 2020 Top of Productive Horizon: 9. Acres in Property: 2560 14. Distance to Nearest Property: Total Depth: 692' FSL, 5256' FEL, Sec. 26, T12N, R12E, UM 8000 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 86.00 feet 15. Distance to Nearest Well Open to Same Pool: Surface: x- 618930 y- 5980400 ^ Zone - ASP 4 GL Elevation above MSL: 34.85 feet. 1500 16. Deviated wells: Kickoff Depth: 700 • feet 17. Maximum Anticipated Pressures in prig (see 20 AAC 25.035) Maximum Hole Angle: 37 degrees Downhole: 2368 Surface: 1839 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 42" 20" x 34" 215.5# A-53 80' Surface Surface 80' 90' 260 sx Arctic Set (Aoorox.) 12-1/4" 0-3/4'x9-5/8" 45.5#/47# Vam21 3000' Surface Surface 3000' 2972' 922 sx DeepCrete, 217 sx Class'G' 8-1/2" 3-1/2" 9.2# L-80 VamTo 6045' Surface Surface 6045' 5508' 681 sx LiteCrete, 356 sx Class'G' 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Hydraulic Fracture planned? Yes ❑ No ^ jc( 20. Attachments Property Plat ❑ BOP Sketch 0 Drilling Program D Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch 0 Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements 0 21' Verbal Approval: Commission Representative: Date hereby certify a e toregoing is true and the procedure approved herein will not be deviated Contact Name Gorham, Bradley M from without prior written approval. Authorized Name Allen, Kenneth W Contact Email Bradley, Gorham@bp.com Authorized Title Engineering Team Lead Contact Phone 907-564-4649 Authorized Signature ` ("^ Date '/ Commissio Use ly Permit to Drill!i'�) ? ? / �� = Permit Approval / l See cover letter for other Number: API: 50- L� Date: ''�/ requirements: 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: [� Mud log req'd: Yes ❑ No 09' Other: gem' -Qgg W)OP5 , Samples req'd: Yes El No 10/ Mud rm+e4- YQ �V�� pts�ad , 35dD�5 H2S measures Yes R( No ❑ Directional svy req'd: Yes Gds No El Spacing exception req'd: Yes ❑ No Gd/ Inclination -only svy req'd: Yes ❑ No 12 low, Post initial injection MIT req'd: Yes � No ❑ Ad GCC geFOit � C L_pG Tp 1 ; Vttle�4Va7416 Qr1,k14 $ZOO-- A&C1CL3&}Scm 2S �?o FtE Co%eK ` a pcyp �r e'er �� eC'A PROVED BY `t"- ova q r y I"` d•� IVI THE COMMISSION Date: l� Approved b : CO MISSIONER 7 r r--, ORIG Form 10-401 Revised 5/2017 This permit is valid for 24 months from the dale iSf.pp• rLI (20 AAC 25.005(g)) Submit Form and Attachments in Duplicate PBU S-210 (PTD 219-057) )K Additional Conditions of Approval: Variance to 20 AAC 25.412 (b) is granted by the utilization of a cement packer of —500' in length and an approved cement evaluation log demonstrating that injection will be limited to the injection interval with the following stipulations: a. BPXA will provide a cement job summary reports to AOGCC when they become available BPXA will provide a written cement bond log evaluation/interpretation to the AOGCC along with the cement bond log as soon as it becomes available. The evaluation is to include/highlight the intervals of competent cement (and lengths) that BPXA is using to meet the objective requirements for annular isolation, reservoir isolation, or confining zone isolation etc. Providing the log without an evaluation/interpretation is not acceptable. To: Alaska Oil & Gas Conservation Commission From: Brad Gorham, ODE Date: April 1, 2019 RE: S-210 Permit to Drill The S-210 well is scheduled to be drilled by Parker 272 in January 2020. This grassroots well is a slant injector targeting the Schrader Bluff Sands. The planned well is a two -string design using 10-3/4" x 9-5/8" surface casing with a 3-1/2" monobore completion. The surface casing will be set in the SV2 shale. The production interval will be completed with a 3-1/2" monobore string with cement through mandrels. The maximum anticipated surface pressure from the Schrader Bluff with a full column of gas from TD to surface is 1,839 psi (assumes 8.6 ppg EMW most likely pore pressure and a 0.1 psi/ft gas gradient). The well will be drilled by Parker 272 using their 5,000 psi four preventer BOP stack (3 rams and an annular). The BOP rams will be tested to 4,000 psi and the annular will be tested to 3,500 psi. A detailed operations summary is included with the permit application. If there are any questions concerning information on S-210, please do not hesitate to use the contact information below. Brad Gorham Office: (907) 564-4649 Cell: (907) 223-9529 Email: Bradley. Gorham(aD_bp com Attachments: Well Bore Schematic Area Review Map Directional Package Well Head Schematic BOPE Schematic Tree Schematic Diverter Line Layout Diagram S-210 PTD 1 4/1/2019 Planned Well Summary Well S-210 Well Injector Target Schrader Type I Objective Bluff Current Status Grass Roots Well Estimated Start Date: 1 01/10/ 1 Time to Complete: 1 12.07 Days Surface Northing Easting Offsets TRS Location 5,980,400.25 618,929.69 , 4196.6' 4502.7' 12N 12E Sec 35 T t 2 5,982,044 618,036 5,161 FELFSL/ 12N 12E Sec 27 Northing Easting TVDss Offsets TRS T t 1 5,981,767 618,271 4,904 294' FSL / 5137.8' FEL 12N 12E Sec 26 T t 2 5,982,044 618,036 5,161 575' FSL / 88.5' FEL 12N 12E Sec 27 BHL 5,982,163 618,146 5,422 692' FSL / 5256' FEL 12N 12E Sec 26 Planned KOP: 700' MD Planned TD: 6,045' MD / 5,508' TVD Rig: I I GL -RT: 51.15 1 RTE (ref MSL): 1 86.0-0-7- Directional 6.00 - Directional - Baker WP05 KOP: 700' MD Maximum Hole Angle: -15' in the surface section -37 in the production section Close Approach Wells: None. All offset wells pass BP Anti -collision Scan Criteria. ' Survey Program: Reference attached directional program Nearest Property Line: 8,000' Nearest Well within Pool: 1,500' . S-210 PTD 2 4/1/2019 Formation Tops and Pore Pressure Estimate (SOR) Formation Depth (TVDss) MLPP (ppg) Fluid Type (For Sands) G1 335 8.4 Fluvial gravels SV6 1540 8.4 Fluvial gravels BPRF 1867 8.6 Fluvial gravels EOCU 2080 8.4 N/A SV5 2180 8.4 Gas Associated with Coals SW 2354 8.6 Gas Associated with Coals SV3 2691 8.6 Gas Associated with Coals SV2 2832 8.7 Gas Associated with Coals SV1 3167 8.7 Gas Associated with Coals UG4 3505 8.85 Gas Associated with Coals UG4A 3546 8.85 Gas Hydrates UG3 3866 8.85 Gas Hydrates UG1 4382 8.7 Gas Hydrates UG—Ma 4670 8.7 N/A UG Mbl — 4725 g 7 Possible Gas / Heavy Oil UG Mb2 4750 8.7 N/A UG Mc 4760 8.7 Heavy Oil SB Na 4885 8.7 Heavy Oil SB Nb 4903 8.7 Water/Heavy Oil SB OA 5001 7.7 Viscous Oil SB OBa 5041 7.7 Viscous Oil / Water SB OBb 5079 7.7 Viscous Oil SB OBc 5123 7.7 Viscous oil SB OBd 5171 7.7 Viscous oil SB OBe 5221 8.6 Viscous Oil SB OBf 5258 8.6 Viscous oil SB OBf—B ase 5297 8.6 N/A S-210 PTD 3 4/1/2019 Casing/Tubing Program Hole Size Liner / WVFt Grade Conn Length Top Bottom MBT Tbg O.D. (ppg)y PV (cp) (Ib/1 0ft2) API FL MD / TVDss MD / TVD 42" 20" x 34" 215.5# A-53 - 80' Surface 94'/ 80' 12-1/4" 10-3/4" x 9- 45.5# / L-80 VAM 21 3,000' Surface 3,000'/ 2,972' 5/8" 47# 8-1/2" 3-1/2" Liner 9.2# L-80 VamTop 6045' Surface 6,045'/ 5,508' / Tubing Mud Program Surface Mud Properties: MMH 12-1/4" Hole Section Depth Interval Density PV (cp) YP AN FL LSR-YP MBT Depth Interval (ppg)y PV (cp) (Ib/1 0ft2) API FL (2x3 — 6) pH <4 8.5-9.5 rpm Surface - 3,000' MD 8.7 — 9.2 6-20 35-80 <15 25-60 10 - 11 Production Mud Properties: Water Based Polymer Fluid 8-1/2" Hole Section Depth Interval Density PV (cp) Ib/9YOOftZ AN FL HTHP FL MBT pH 3,000' MD - TD 9.2-9.8 <8 12-20 <12 1 NA <4 8.5-9.5 Logging Program 12-1/4" Surface I Sample Catchers - not required for surface hole Drilling: GR/RES Oen Hole: None Cased Hole: None 8-1/2" Production Sample Catchers — as required by Geology Drilling: Dir/GR/RES/DEN/NEU Oen Hole: RDT — GR Formation Evaluation Cased Hole: CBL -GR — Planned for post rig S-210 PTD 4 4/1/2019 Cement Program Casing Size 10-3/4" x 9-5/8" 45.6#147# L-80 Vam 21 Surface Casing Lead Oen hole volume + 350%o excess in permafrost and 40% excess below permafrost Lead TOC Target surface Basis Tail Oen hole volume + 40% excess + 80 ft shoe track Tail TOC 500 ft MD above casing shoe Spacer -100 bbls of Viscosified Spacer weighted to -10.5 Mud Push II Total Cement Lead 313.7 bbls, 1760 cuft, 921.5 sks of 11.0 ppg Dee CRETE, Yield: 1.91 cuft/sk Volume Tail 44.9 bbls, 252 cuft, 217 sks 15.8 lb/gal Class G - 1.16 cuft/sk Temp BHST 54° F Casing Size 3-1/2" 9.2# L-80 VamTop Production tubing Lead Oen hole volume + 40% excess Lead TOC Target 500 ft MD above surface casing shoe Basis Tail Oen hole volume + 40% excess + 80 ft shoe track Tail TOC 5000' MD Spacer -40 bbls of Vi cosified Spacer weighted to -11.0 Mud Push II Total Cement Lead 182.2.0 bbls, 1022 cult, 681.4 sks of 13 ppg LiteCRETE, Yield: 1.50 cufUsk Volume Tail 80 bbls, 448.6 cuft, 356 sks 15.0 lb/gal Class G - 1.26 cuft/sk Temp BHST 92° F Surface and Anti -Collision Issues Surface Close Proximity: No wells will be affected by the Parker 272 rig shadow. Sub -Surface Pressure Management: No pressure management plan is necessary. Anti -Collision: None. All offset wells pass BP Anti -collision Scan Criteria. Offset well ownership information All offset wells identified within 200 ft of the proposed wellbore are operated by BP. S-210 PTD 5 4/1/2019 Hydrogen Sulfide S -Pad is considered an 1-12S site. Recent 1-12S data from the pad is as follows: Faults Formation Where Fault Encountered Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level S-43 25 ppm 1/3/17 #2 Closest SHL Well H2S Level S -42A 22 ppm 3/26/18 #1 Closest BHL Well H2S Level S-201 180 ppm 3/9/12 Max Recorded H2S on Pad/Facility S-201 500 ppm 6/2/05 Faults Formation Where Fault Encountered MD Intersect TVDss Intersect Throw Direction and Magnitude Uncertainty Lost Circ Potential Flt #1 (SV4) 2599' 2580' 80' DTSW Med: <300' Low: <25% & >200' Flt #2 (Ugnu) 4926' 4520' 20' DTNE Med: <300' Low: <25% & >200' Drilling Waste Disposal • There is no annular injection in this well. • Cuttings Handling: Cuttings generated from drilling operations will be hauled to grind and inject at DS -04. Any metal cuttings will be sent to the North Slope Borough. • Fluid Handling: Haul all drilling and completion fluids and other Class II wastes to DS -04 for injection. Haul Class I waste to DS -04 and/or Pad 3 for disposal. Contact the GPB Environmental Advisors (659-5893) for guidance. S-210 PTD 6 4/1/2019 Well Control The 12-1/4" surface hole will be drilled with a diverter (see attached diverter layout). The 8-1/2" hole sections will be drilled with well control equipment consisting of 5,000 psi working pressure rams (2), blind/shear rams, and annular preventer capable of handling the maximum potential surface pressures. Due to the fact this well is an injector, the BOP equipment will be tested to 4,000 psi. BOP test frequency for S-210 will be 14 days with function test every 7 days. Except in the event of a significant operational issue that may affect well integrity or pose safety concerns, an extension to the 14 day BOP test period should not be requested. 8-1/2" Intermediate Interval Maximum anticipated BHP 2,368 psi at the Schrader Bluff at 5,297' TVDss 8.6 ppg EMW Maximum surface pressure 1,839 psi at the Schrader Bluff (0.10 psi/ft gas gradient to ✓ surface 25 bbls with 11.90 ppg frac gradient. Kick tolerance Assumes 8.6 ppg pore pressure in the Schrader Bluff + 0.5 ppg kick intensity and 9.2 ppg MW. Planned BOP test pressure Rams test to 4,000 psi / 250 psi. Annular test to 3,500 psi / 250 psi Integrity Test — 12-1/4" hole FIT after drilling 20'-50' of new hole 10-3/4" x 9-5/8" Casing Test 4,000 psi surface pressure S-210 PTD 7 4/1/2019 Variance Requests — Make sure is still necessary / Valid 16-14C 1. To avoid the risk of plugging the flow line with large rocks and wood encountered while drilling surface hole, it is requested to drill without a flow paddle for the first portion of the surface hole. After drilling past the larger rocks and wood sections, the flow paddle will be put back in the flow line (<1000 ft). This is a variance from 20 AAC 25.033. Procedures/Safeguards with paddle removed: • Fluid levels will be monitored in the pits for both gains and losses while drilling. Alarms will be set to indicate if gain or loss of more than 10 bbls has occurred. • The well will be monitored for flow when the pumps are off at each connection. • The planned 8.7 - 8.8 ppg fluid will provide over balance to formation fluid. S-210 PTD S-210 Drill and Complete Operations Summary Pre -Rig Operations 1. Install and survey 20" conductor and cellar box. 2. Weld on landing ring. Rig Operations 1. MIRU Parker 272. - 1 �] 2. Nipple up diverter system and function test. '��jJovrAo�-«-e 7a /r �6ZC-- 3. MU 12-1/4" surface motor drilling assembly (GR) and drill to TD at 3,000' MD. POOH and LD drilling assembly. GbWI. 1a GeMew_I r� F' T �v 4Q4 -(_c 4. Run 10-3/4" x 9-5/8" casing to TD and cement. {/aluw�.CS� ��laC,..u,�,nw`1�j ��'��t-� 11•re.y atfT'S� °L 1. Nipple down diverter system. Nipple up 11" wellhead system and nipple up BOPE and test to 1 4,000 psi. (Configured from top to bottom: 13-5/8" annular preventer 2-7/8" x 5" VBRs in the upper cavity, blind/shear rams, mud cross and 2-7/8" x 5" VBRs in the lower cavity). a. Notify AOGCC 24 hrs in advance of full test. 5. Test surface casing to 4,000 psi. L 3j �, „t, C_�-O.r'� 6. MU 8-1/2" intermediate drilling assembly and drill shoe track and 20'-50' formation. 7. Perform FIT. f,:a.S�wc� �� iT QC.► rA-e,.26'A--ro 8. Drill to 8-1/2" section to TD at 6,045' MD,droughly 250' MD below the OBe sand marker. POOH and LD drilling assembly. 9. Pick up and run RDT logs and obtain samples. 10. Run and land 3-1/2" tubing to TD. 11. After mandrel placement is confirmed, cement tubing, bringing cement 500' inside surface casing. A Ce v e►�i a. CBL and integrity testing to be conducted post rig. Volo WL&5 12. Reverse circulate completion brine with corrosion inhibitor through shear valve. 13. Circulate diesel freeze protect. Set TWC and test . 14. Nipple down BOPE. Nipple up adapter and dry hole tree and test to 4500 psi. 15. RDMO Parker 272. Post -Rig Operations 1. V: Tree work/pull TWC 2. E: RU and run CBL to confirm TOC. 3. S: CMIT-TxIA to 3,800 psi. Pull she valve. Set dummy. MIT -T to 3,800 psi. WFRV� work/breakdown cement to allow for reservoir communication 4. F: Assist SL with WFRV work and breaking down cement S-210 PTD 9 4/1/2019 S-210 Drilling Critical Issues POST THIS NOTICE IN THE DOGHOUSE I. Well Control / Reservoir Pressures A. Production Hole: The UG4 is expected to be a 8.85 ppg EMW. Formation pressures will be controlled with a 9.2 — 9.8 ppg mud to drill the interval to TD. II. Lost Circulation/Breathing A. Surface Hole 1: There are is one expected fault crossing in the surface hole. However, the risk of breathing and lost circulation are low based on historical wells drilled from S Pad. B. Production Hole: There is one expected faulrcrossing in the production hole. There is low potential of breathing or lost circulation as the fault crossing occurs in the Ugnu. III. Fault Locations Formation Where MD TVDss Throw Direction #1 Closest SHL Well H2S Level Lost Circ Fault Encountered Intersect Intersect and Magnitude Uncertainty Potential Flt #1 (SV4) 2599' 2580' 80' DTSW Med: <300' S-201 500 ppm 6/2/05 & >200' Low Fit #2 (Ugnu) 4926' 4520' 20' DTNE Med: <300' & >200' Low V. Hydrogen Sulfide S -Pad is considered an H2S site. Recent HSS data from the Dad is as follows: VI. Anti -Collision Issues ➢ None. All offset wells pass BP Anti -collision Scan Criteria. CONSULT THE S -PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION. S-210 PTD 10 4/1/2019 Well Name H2S Level Date of Reading #1 Closest SHL Well H2S Level S-43 25 ppm 1/3/17 #2 Closest SHL Well H2S Level S -42A 22 ppm 3/26/18 #1 Closest BHL Well H2S Level S-201 180 ppm 3/9/12 Max Recorded H2S on Pad/Facility S-201 500 ppm 6/2/05 VI. Anti -Collision Issues ➢ None. All offset wells pass BP Anti -collision Scan Criteria. CONSULT THE S -PAD DATA SHEET AND THE WELL PLAN FOR ADDITIONAL INFORMATION. S-210 PTD 10 4/1/2019 WELLHEAD = ACTUATOR = OKB. ELEV = BF. E LEV = KOP= Max Angle Datum MD = _ Datum TVD = 5000' SS PROPOSLD 20" GOND I-1 108' TOC 2600' 9-5/8" CSG, 47#, L-80 VA M 21, ID = 8.861" 3000' Minimum ID = " @ ' '3-1/2" TBG, 9.2#, L-80 TCB, .0087 bfp, ID = 2.992" I 6044' S-210 _21O SAFETY NOTES: 3-1/2" HES X NIP. ID = 2.813" 110-3/4" CSG, 45.5#, L-80 VAM 21, ID = 9.950" 1 GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 5 WATER KJFCTION MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 4 3 2 1 3-1/2" HES X MP. ID = 2.813" I SURESENS SPIV GAVAGE MA NDREL, ID = 2.875" 3-1/2" HES X NIP, ID = 2.813" SURESENS SPIVGAVAGE MANDREL, D = 2.875" 3-1/2" HES X NIP, ID = 2.813" SURESENS SPIV GAVAGE MANDREL, ID= 2.875" 1 3-1/2" FES X NIP. ID= 2.813" ISURESENS SPIV GAUAGE MANDREL, ID= 2.875" 1 3-1/2" HES X NIP, ID = 2.813" POLARIS LHT WELL: S-210 PERMIT No: AR No: 50-029- -00 SEC _, TN, R E ' FNL & F1JVL BP Exploration (Alaska) MMM�09701%-Vejmgja -- POLARIS LHT WELL: S-210 PERMIT No: AR No: 50-029- -00 SEC _, TN, R E ' FNL & F1JVL BP Exploration (Alaska) N N t �a W) N Q � J � Q � L Ln ♦^ v/ CV N U) U) O Z a m N J E M acncna a N t �a W) N E p E r y V d C N y O W c N N O N = d y N c v Q p a Y Y d Q Q 7 co N N co d N n d m o v cD CL z O O N r r w M O z z m E ci O y 0 N d C O O. ` m 0 2 a d N W W d U Z Q m m c c O 0 g m O 'C'U- m t/1 N 7 Y J 3 y (0 O O Z Q 2! 3 C) 00 U Y N Ud Ud E )r) n J J 3 0� .E Z a- d co (n d (n Q H W � ai G1 a C O d L w d 4) C d O m ' C d U N a d U y 75 C V a U 1 a V a Z a+ 00m J Z y a 0 O Q oC, a)) d Z m c ns d a>) i E p E r y V d C N y O W c N N O N = d y N c v Q p a Y Y d Q Q 7 co N N co d N n d m o v cD CL z O O N r r w M O z z m E ci O y 0 N d C O O. ` m 0 2 a IL co Y U7 Q Q 0 O C O N a- E vh �: < r o Z o o N g N O Z a- d co (n d (n Q � Z A � E • d & y U a N 9: 9: O E p E r y V d C N y O W c N N O N = d y N c v Q p a Y Y d Q Q 7 co N N co d N n d m o v cD CL z O O N r r w M O z z m E ci O y 0 N d C O O. ` m 0 2 a 0 Z a Z 00m oC, Cl) rn ri N M N N N O co O � Cn U m d a J U a C m N O d > d 7 O a . 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LA M O V O O O O O O O O O O O O O „„ rn OD CO rn m w w w rn ao G ao rn m a� w a ao m m m m m Oo m Oo m m m m m ao 5 Oo c Z N In M LO LO m (n 0 (O LO N LO 10 0 LO LO U' LO LO LO LO M « 0 O R U t6 'p U 0 y O co N N N LO O m m m O n V O DD (0 N oO wN 00 O m O co m v m V M m N m n Mn m m� co N O N m m O N m V Oo Om wOy m M LO LO (D m OMLO(O coOMO co U d >, m N N N N N M M M M t N d w >> J F Z m 0 W N O O M N m V N m N V m m m m n CO LO LO M LO o M n LO n LO r m (0 m N LO (0 m V n O V n O') m (h N 0 LO n LO V m LO M m n M n N m M n n O N O M LO m m M m V Cl) m 00 V N O CO LO _ N N Cl) Cl) M M V V LO LO LO LO (0 m m n n n 00 m m O Z � O O V M m m �- V O M O nM LO O N LO O n m O N to V N M m O m N O W n n M0 O Ln V N OD n n n O n V (D V LO M LO O m N (O V N n n M m M n M LO co m M M N N m N n N LO to N m N m N O M M r M N M M M M LO m N Cl) LO Cl) m Cl) m Cl) O m n M m M m M a M O O r V N CA a >O a F` O O a MCR m_ V o M O n LO O N M Ln O n O O Ln (D V N M m O m Mn O n n Cl) o O LO O O co m Cl) m Cl) LO n LO O LO O V m N m tO N M co m Cl) co m n m LO m M N LO m tD m CO n OD N m M O O N N M V LO LO m O O n n aD m m O O N M 0 M i Cl) M M M M M cn Cl) M M M M M M M M M V 00 W M V M m LO .- ? 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O Cl? m m (n (O N v rn N O O m rn Ir) rn M v M rn In rl� 0)0 (O N 0) 01 N M N OR V m N N m O v n Cl) m n O (C) OD M m m (O rn in m N n m N N v n m O N M Cl) M (r) c t c = x v_ v_ (n cc cc cc n n n n cc m aD aD m Oct w d r N m m m m m m m m m m m OD m m m m m 00 0_ rn (D rn 0)rn rn CD G) CD (D CD G) a) CP CD 0) a) O 0 (n (n In (O )O (O (O (n 10 IO In (O N (n Ir) In WO (O 4.1 _ C d _0 U O C 7 C U i U m O O N M O O O t� 0 v m m O m m O 0) Cl) v m N (O m m v n N N m P N . m O N U N N m N m M v m rn m N N6 N M v (n N m n m rn n O rn Cl) (3)rn m m rn In 0 O U D � T t0 � � v V' C (O In In V) N (n (n In In In N N (O y v ❑❑ ❑ Z 0 J f `t z N O W O Q (1) Cl) 00N O n 0) .-- O CD M n v m �. M O m rn N N M (O r- v 0) O O rn N ? v T LO to 0) rn a) M n m N N m (O 0) N Cl) m Cl) (D in m I- O m N m M N m rn v V m O O N N N Cl) Cl) Cl) M M V v v v v v ca Z)3 to u C (6 m M O O N N m O v rn m (O m (n v n m m m v Cl) O m m n v M O N O O m v m M N NN_ N O (O O v 00 In • M N M I- M M m M v rnn (n N m n m N n Cl) n m n CD n m m m m 03O m CD O 0) N 0) N 's v v v v v v v v IT v V v y — CO O N 00 v (O to v O m v O O m m Cl) O N O rn m m v m rn CO m n M N O v M m m m m n n m�_ f- m O v m M v m V a) v n (O cr m M I� (n n m m v m m m 0) 0) m Cl) (3)rn n N n rn m CD m m O ❑ �" v v v v v v v i7 v v v v v v v v v v v O O O O O O O v v v v v v v v v v v M O O O O O O v v v v v v v v v v v v v It v IT v v co Cl) M Cl) M M M M M M M M Cl) Cl) Cl) M Cl) Cl) M Cl) Cl) M Cl) Cl) Cl) M M M Cl) Cl) Cl) M M M M Cl) N — IL m (no 0 0 0 0 0 0 o O o O to 0 o O o ❑ o O g O O O O O O O O O O O M O ❑ O O O O O Q n m ui (ri Ln )r) )r) In M Cl)M Cl)M Cl)M Cl)M Cl)M M M M M M OD N M M a M Cl) Cl) r co O Cl) U (0 N a E(p Cl) a O is z o z o _V C g N O m N O 0 m z d (n (n O_ CO O m O O O O O O CO m p ai O v L O O v a m '4 v O 7 O O O O m N O m v N O n o v O n (O r.- >1 T O N O O O O Cl) N O m m J O 10�j 0 O O " N (V d O m O O O O N rn O N M N n N m O M v M OD m M O v a M v v v ❑'. v v v v (O (O (n (n cn (O (O m t0 (() m m C (n N m N .. n rL N N z fq z z N 0 bi o U pC E d y_ •Nlo N c .N�.. N 0 U d U) ❑ d N 00 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o a 3 u cc m FL o o O S > 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (cn w w a o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o 0 a U o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Q N C (a m 2)LM O ❑ O O a 7 7 N O O OJ l0 O O Z O Cl) m M N Cl) M 1O N to m O in h I) m U) Cl) 0 O m m m (n m Cl) N N m (O m O m m U ' Y a O 0 W m (n ai (n O � m m o m V 1� OD m O rn N v c`'i n tD o N N E U) O C$ M m N m N n N n Cl! m N m N to N (n N v N v N Cl) N Cl) N N N N N (n J J J J E m N O) m m m m m m m m m m m mm m m O 7 m m m m m m m m m m m m m m m m >— > H W W ED I- n O to m O It N m Cl) Cl) N O n IT N CD (O N It m N m I,, m (D N 0) h O N m m co 1l m m M m to h N O m m m (o Ci 07 0 v 0 co OJ tD iO m (D (D 1` m (D U C O m (() C m m m m m O m m N m co m v m v m m m h m m m m m O O Cl) O M O d L �� _ m Z_ m m m m m m m m m m m m m m m co m coN m C In to (o to lO (n (n Ln ui Yi to 1f) (n N (O In N O W N U m V U y O C u m O m N m N m N m m M (l v v O Cl) N m m m (n Un M m M v v m `y m m m v m Cl) m O m M m O m N O w N U N U d LL' T N O 19 co (O N (O Cl) N M tO v (O v (O (n fO (n (O m (O m (D N (O n (O m (O m (O m L m a m ❑o > J F 2 N ❑ W 7 O 0- (D r. O N N r M (O M m M OR m v m O N (() m O M N O m M m O Ln m m n m V) r- T 0) m m M m v m O m N (O M 0 v O O m N 1- 1- m 1` m N O N v v co v v In to to In to (O Ln u'1 (O m m (o C (O d (O M m m N m N m m 1� CO O r lO N m � O (n m m m O O N N In m N N m m Cl) m (D v 1� M m 1- m n m O O N O v O (n O I- O 1` O m O r r .- r N N v v (n N (O (o (O 10 (n to (O tO (O In Ln 2 F>O w ` ID m N m N m Cl) (O m In m N_ O M m m h O _ N Vn O m m O m (n 1` ri m (n v m v N I- O M N O Ln O m O m O N_ v (O m m O Cl! N N M N (O N O M O M >❑ (n I- 7 In N (n LO Lo N 16 N m (n (o LO u) N io O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O v Cl) Cl) v M Cl) v M M v M M v M M v co M IT Cl) M v M Cl) v Cl) M v M co v M M v Cl) Cl) v co co v M Cl) v M M v co M IL co Y U) J O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O ❑ Q v) M vi Cl) vi M vi M vi M vi M LO M In M (n M vi M vi M in M N M Ln M vi M (n M N N U O O O N n. Q m L O ZQ O_ 'O O mN J N L Z d m m LL In 1` m O N It m o N co v O Ln m M m N v N O m n M O v I� M Ln O v N m N AQ. T I1- O CO y o Oo N 1` O N O o m H O) h N O N Q 0) Z �n v m v O (n Cl) (n m (O m LL LO O m m LL 1 N (O Ln m LL m I m O I� O N LL I M 1` m I, LLm 11` N -Q v) O in Ln Lo LO u) Q vi m .n Q m Lom (ri m m in m U L m ui U vi C3 L6 ❑ L N W LL z z Q O Q O O O O OO m O m O m O (n it O a V C N m a m o o :: a d d c R o c)ain0 (L (i c�, 0 o O O o 0 0 0 Oo O O O o 0 0 0 0 0 0 0 0 0 0 p F LO (n u) U') L ch0 OO O o O O O O O O W W d O O O O O O O O U Q o a 0 0 0 0 0 0 0 M m Cl)m Cl) co M M m M M Cl) M Cl) M Cl) M co Cl) m m c c 0 y 12 J o o N CD O .2) C p O O a a. (0 N N J Y 3 N (0 ^ O O 3 Q o_ m m U Y m D) o m o m m rn N Il m O O m V O co N (^O (D M v v N E Ln C N N r r r r U)E J J m m06 N m 00 m m J LU LU O O m N O Ln O N N LO m >J It 2 w LU M M Cl) Cl) Cl) Cl) M M m m c�LO 0 I -r- m m N M N M d co m Ln D) O N M V .a C O d 0 Cl) C O Cl) O m O m O m O m m L d L v 7 NO .0 ONO m Nm 00 00 .0 Vy O Z.... O) W O) (A W W W O) L O_ Z O_ N m V') N m Ln N d O m N g N VV d t0 7 O Z d U) U) d U) C O M O m Cl) V m m W (n O O Cl) C d w N Cl) O M V m M Ln (!) O O ii m m D) O .- V Ln Ln a) CO o m m O o r v m P3 Q Z OD m 7 Co o) o c J Z U) p W p N Lri Lri m Ln p Lri m ml Ln m m 0 O A ?! O 0 0 O M H a 2RN.. (' rn c Q tm N a a m � m .n M v rn N � rn O R (P O) Cl) I- 0 O N V (n N U a V) N r r in Z U 7 c fB CL jm m m Cl) r- co O N N m N I -m CA N O V O H N Ln N LO N N Cl! m M Ln m M to N N V 10 N til) >O F co m m rn Cl) 00 (0 n m m O Cl) r-� O Cl) v v co Cl) m Cl) 00 m M o r- V (D 0 O m N p F LO (n u) U') L ch0 d E CO Z 0 O O 7 Q N O O W d co m rn O N L" 04M O O O O O O O O O O O O O O O O V V V V V M m Cl)m Cl) co M M m M M Cl) M Cl) M Cl) M co Cl) N a. Q07 Y U) Q O O O O J O O m N O Ln O N N LO m M M Cl) Cl) Cl) Cl) M M {Q U O o V E N Q Q U) L O_ Z O_ m N g N O Z d U) U) d U) W O O M V (o O O O O m o o v a) CO o m m O o r v m P3 Q Z OD m Co o) o c p N Lri Lri m Ln p Lri m ml Ln m m 0 O A ?! O O O M H a 2RN.. (' rn c tm a a U a m 3 p a U d E CO Z 0 O O 7 Q N O O W d co m rn O N L" 04M N 0- U) m J (¢p U OU) E (: O i n ¢ C L O Z O 7 N g N o a z(n (n m (b N C O Q R T J C .. ` CO { O C GO d d d y 6 U d (n O N Ov O co o O U) C', o CR v n N O p U) w" n O UI o Li n °' w n vM ° v O N o nU)) U O f0 O U O N V V LL a O F- o O o O O O O O L O U) o O L L O r- 04 O UJ P7 v C6 L v N O U) n U) N U01 J M J m J O v m p m m .;- O v o v o,w,m N U) N U (n (n (n (n (n (n (n (n (n (n (n F O n U) v O M r w m NO O U) M v U) OD r' N v OD U) M o N M o t0 O m N m o N o o o m m n m m �n N W 7 d } R C U o o U O m m N v O O U) m jp O N N v UJ 7 7 v O U) n v J (1 O N ! r N UJ CI IT v Cv0 n O U) M M m O O v U) O O U) O m v m 0 (n M n O o m U a O m m0 O CO OO CO O O O N (O n m N O n oD () m M U) N N M M v v v U) U7 O O O O v O N W v v W O 'p O O O O U) O O v n n N O L O O O O U) m O co U) O U) U) a+ O O O U) n N oo n v m y y) - y U) to o '- N O OD NM v n O W zN N cu M m U) m o U) U) m a m 0 O g 04 N U) (V m O 04 N M North America - ALASKA - BP PBU S S-210 PLAN S-210 S-210 WP05 Anticollision Summary Report 25 March, 2019 by Company: North America - ALASKA - BP Project: PBU Reference Site: S Site Error: 0.00usft Reference Well: 5-210 Well Error: 0.00usft Reference Wellbore PLAN S-210 Reference Design: S-210 WPO5 BP Anticollision Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well S-210 WELL @ 86.00usft (Original Well Elev) WELL @ 86.00usft (Original Well Elev) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum Reference S-210 WPO5 Filter type: NO GLOBAL FILTER: Using user defined selection & filtering criteria WARNING: There is hidden tight data in this project Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: Unlimited Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 799.48usft Error Surface: Elliptical Conic Survey Tool Program Date 3/25/2019 From To (usft) (usft) Survey (Wellbore) 50.20 1,700.00 S-210 WP05 (PLAN S-210) 1,700.00 3,000.00 S-210 WP05 (PLAN S-210) 1,700.00 3,000.00 S-210 WP05 (PLAN S-210) 3,000.00 6,045.00 5-210 WP05 (PLAN 5-210) 3,000.00 6,045.00 5-210 WP05 (PLAN S-210) Tool Name Description GYD-GC-SS Gyrodata gyro single shots MWD MWD - Standard MWD+IFR+MS-WOCA MWD +IFR + Multi Station W/O Crustal MWD MWD - Standard MWD+IFR+MS-WOCA MWD + IFR + Multi Station W/O Crustal 3/25/2019 2:55.00PM Page 2 of 5 COMPASS 5000.1 Build 81D Company: North America - ALASKA - BP Project: PBU Reference Site: S Site Error: O.00usft Reference Well: S-210 Well Error: O.00usft Reference Wellbore PLAN S-210 Reference Design: S-210 WPO5 BP Anticollision Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well S-210 WELL @ 86.00usft (Original Well Elev) WELL @ 86.00usft (Original Well Elev) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) S S-03 - S-03 - S-03 3,340.87 3,600.00 508.07 57.56 452.90 Pass - Major Risk S-100 - S-100 - S-100 371.34 350.00 241.62 5.77 235.86 Pass - Major Risk S-101 - S-101 - S-101 1,454.08 1,425.00 175.89 26.82 149.30 Pass - Major Risk 5-101 - S-101 PB1 - 5-101 PB1 1,454.08 1,425.00 175.89 26.82 149.30 Pass - Major Risk 5-102 - 5-102 - S-102 1,160.82 1,125.00 267.62 18.61 249.03 Pass - Major Risk 5-102 - 5-1021-1 - S-1021-1 1,160.82 1,125.00 267.62 18.99 248.64 Pass - Major Risk 5-102-5-1021-1P131-S-1021-1PBI 1,160.82 1,125.00 267.62 18.61 249.03 Pass - Major Risk S-1 02 - S-1 02PB1 - S-1 02PB1 1,160.82 1,125.00 267.62 18.99 248.64 Pass - Major Risk S-108 - S-108 - S-108 3,102.84 3,050.00 173.92 42.16 131.80 Pass - Major Risk S-109 - S-109 - S-109 925.16 900.00 265.62 16.35 249.27 Pass - Major Risk S-109 - S-109PB1 - S-109PB1 925.16 900.00 265.62 16.35 249.27 Pass - Major Risk S-112 - S-112 - S-112 516.17 500.00 132.41 9.83 122.59 Pass - Major Risk S-112 - S-1121_1 - 5-1121_1 516.17 500.00 132.41 9.83 122.59 Pass - Major Risk S-112 - S-1121-1 PB1 - 5-1121-1 PB1 516.17 500.00 132.41 9.83 122.59 Pass - Major Risk S-112 - S-1121_1 P132 - S-1121_1 PB2 516.17 500.00 132.41 9.83 122.59 Pass - Major Risk 5-115 - S-115 - S-115 1,083.72 1,050.00 193.30 16.82 176.49 Pass - Major Risk 5-116 - 5-116 - S-116 1,126.50 1,100.00 71.10 19.39 51.76 Pass - Major Risk 5 -116 -5 -116A -S -116A 1,126.50 1,100.00 71.10 19.38 51.76 Pass - Major Risk 5-116-5-116APB1-S-116APB1 1,126.50 1,100.00 71.10 19.38 51.76 Pass - Major Risk S-116 - S-116AP62 - S-116APB2 1,126.50 1,100.00 71.10 19.38 51.76 Pass - Major Risk S-117 - S-117 - S-117 1,775.17 1,750.00 101.09 30.71 70.51 Pass - Major Risk S-118 - S-118 - S-118 1,064.48 1,050.00 85.06 17.73 67.42 Pass - Major Risk S-120 - S-120 - S-120 621.69 600.00 163.96 11.74 152.23 Pass - Major Risk S-121 - S-121 - S-121 371.71 350.00 60.41 6.38 54.03 Pass - Major Risk S-121 - 5-121 PB1 - S-121 PB1 371.71 350.00 60.41 6.38 54.03 Pass - Major Risk S-122 - 5-122 - 5-122 1,749.31 1,725.00 143.68 26.84 116.89 Pass - Major Risk S-122 - 5-122PB1 - S-122PB1 1,749.31 1,725.00 143.68 26.84 116.89 Pass - Major Risk 5-122 - S-122PB2 - 5-122PB2 1,749.31 1,725.00 143.68 26.84 116.89 Pass - Major Risk 5-122 - S-122PB3 - 5-122PB3 1,749.31 1,725.00 143.68 26.84 116.89 Pass - Major Risk 5-125 - S-125 - S-125 297.08 275.00 30.79 5.21 25.58 Pass - Major Risk S-125 - S-125PB1 - 5-125PB1 297.08 275.00 30.79 5.21 25.58 Pass - Major Risk S-200 - S-200 - S-200 2,612.94 2,575.00 66.73 42.20 28.13 Pass - Major Risk S-200 - S -200A - S -200A 2,621.87 2,600.00 66.80 42.52 28.17 Pass - Major Risk S-200 - S-200PB1 - S-200PB1 2,612.94 2,575.00 66.73 42.20 28.13 Pass - Major Risk S-213 - S-213 - S-213 2,542.45 2,525.00 63.30 36.31 27.82 Pass - Major Risk S-213 - S -213A - 5-213A 2,546.10 2,525.00 63.45 36.37 27.92 Pass - Major Risk S-213 - 5-213ALl - 5-213ALl 2,546.10 2,525.00 63.45 36.37 27.92 Pass - Major Risk S-213 - S-213ALl-01 - 5-213ALl-01 2,546.10 2,525.00 63.45 36.37 27.92 Pass - Major Risk S-213 - S-213AL2 - S-213AL2 2,546.10 2,525.00 63.45 36.37 27.92 Pass - Major Risk S-213 - S-213AL3 - 5-213AL3 2,546.10 2,525.00 63.45 36.37 27.92 Pass - Major Risk S-216 - 5-216 - 5-216 1,219.49 1,200.00 64.61 20.97 43.94 Pass - Major Risk S-23 - 5-23 - S-23 5,999.99 6,525.00 421.28 163.93 322.00 Pass - Major Risk S-24 - S -24A - S -24A 3,819.04 4,275.00 604.46 87.47 537.90 Pass - Major Risk S-24 - S -24B - S -24B 3,819.04 4,275.00 604.46 87.47 537.89 Pass - Major Risk 5-31 - S-31 - S-31 4,701.88 5,250.00 483.33 120.96 388.08 Pass - Major Risk S-31 - S -31A - S-31 A 4,701.88 5,250.00 483.33 120.80 388.24 Pass - Major Risk S-400 - S-400 - S-400 471.27 450.00 74.13 7.91 66.23 Pass - Major Risk S-400 - S -400A - S -400A 471.47 450.00 74.14 7.91 66.23 Pass - Major Risk S-401 - S-401 - S-401 570.88 550.00 31.87 9.78 22.12 Pass - Major Risk S-401 - S-401 PB1 - S-401 PB1 570.88 550.00 31.87 9.78 22.12 Pass - Major Risk S-41 - S-41 - S-41 788.06 775.00 44.26 12.81 31.46 Pass - Major Risk S-41 - S -41A - S -41A 794.20 775.00 44.39 12.93 31.47 Pass - Major Risk S-41 - S-41 AL1 - S-41 AL1 794.20 775.00 44.39 12.93 31.47 Pass - Major Risk 3/25/2019 2.55:OOPM Page 3 of 5 COMPASS 5000.1 Build 81D nby Company: North America - ALASKA - BP Project: PBU Reference Site: S Site Error: 0.00usft Reference Well: S-210 Well Error: O.00usft Reference Wellbore PLAN 5-210 Reference Design: S-210 WP05 BP Anticollision Report Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset ND Reference: Well S-210 WELL @ 86.00usft (Original Well Elev) WELL @ 86.00usft (Original Well Elev) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) S S-41 - 5-41 1_1 - S-41 L1 788.06 775.00 44.26 12.81 31.46 Pass - Major Risk S-41 - S-41 P B 1 - S-41 P B 1 788.06 775.00 44.26 12.81 31.46 Pass - Major Risk S-42 - S-42 - S-42 489.11 475.00 17.48 8.32 9.18 Pass - Major Risk S-42 - S -42A - S -42A 478.23 475.00 17.28 8.13 9.17 Pass - Major Risk S-42 - S-42PB1 - S-42PB1 489.11 475.00 17.48 8.32 9.18 Pass - Major Risk S-43 - S-43 - S-43 943.29 925.00 21.86 15.03 6.87 Pass - Major Risk S-43 - S-431_1 - S -431L1 943.29 925.00 21.86 15.03 6.87 Pass - Major Risk S-44 - S-44 - S-44 1,120.45 1,100.00 42.90 17.25 25.68 Pass - Major Risk S-44 - S -44A- S -44A 1,130.97 1,125.00 43.05 17.41 25.66 Pass - Major Risk 5-44 - 5-441_1 - S-441_1 1,120.45 1,100.00 42.90 17.25 25.68 Pass - Major Risk S-44 - S-441_1 P131 - S-441_1 PB1 1,120.45 1,100.00 42.90 17.25 25.68 Pass - Major Risk S-504 - S-504 - S-504 137.00 125.00 105.03 3.72 101.31 Pass - Major Risk 3/25/2019 2:55.00PM Page 4 of 5 COMPASS 5000.1 Build 81D 1 by Company: North America - ALASKA - BP Project: PBU Reference Site: S Site Error: O.00usft Reference Well: S-210 Well Error: O.00usft Reference Wellbore PLAN S-210 Reference Design: S-210 WP05 BP Anticollision Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well S-210 WELL @ 86.00usft (Original Well Elev) WELL @ 86.00usft (Original Well Elev) True Minimum Curvature 1.00 sigma EDM R5K - Alaska PROD - ANCP1 Offset Datum Reference Depths are relative to WELL @ 86.00usft (Original Well Coordinates are relative to: S-210 Offset Depths are relative to Offset Datum Coordinate System is Alaska NAD27 State Plane Zones, NAD27 ' OGP-Usa AK Central Meridian is 150° 0'0.000 W ° Grid Convergence at Surface is: 0.91° ,_ Ladder Plot $ S-101,S-101PB1,S-101PB1 V10 1 0(1000 us�n) -$- S-116,S-116APB1,S-116APB1 VO 1��e $ S-101, S-101, S-101 V5- S-31, S-31, S-31 1i -X- S-116, S-116, S-116 V6 S-102, S -1021-1,S-1021-1 V5 $ S43, S-43, S-43 V3 -t- S-116, S -116A, S -116A VO S-102,S-102PB1,S-102PB1 V14 $ S-44, S-441-1, S-441-1 VO $ S-120,S-120,S-12OV4 - S -102,S -102,S -102V11 - S-44, S-441-1 PB1, S-441-1 P131 V3 $ S -118,S -118,S -118V5 $ S-216, S-216, S-216 V2 S-44, S -44A, S -44A VO $ S -112,S -112,S -112V20 $ S-213, S-213AL3, S-213AL3 V7 -9- S-44, S-44, S-44 V1 0 $ S-112, S-1121-1, S-1121-1 VO $ S-213,S-213AL1,S-213AL1 V9 $ S-125,S-125PB1,S-125PB1 V7 $ S-112,S-1121-1P132,S-1121-1PB2VO - - S-213, S-213AL2, S-213AL2 V5 $ S -125,S -125,S -125V11 S-112,S-112L1PB1,S-112L1PB1 VO �- S-213, S-213, S-213 V9 -$- 5.400, S400, S-400 V4 $ S-115, S-115, S-115 V7 -I- S-213,S-213AL1-01,S-213AL1-01 V7 -X- S-400,S-400A,S-400AV6 $ S -109,S -109,S -109V9 3/25/2019 2.55:OOPM Page 5 of 5 COMPASS 5000.1 Build 81D L C) `11 0 Ch Z Q N p � 500 0 W ❑ y LUF 2400 O O O O o O n O O O O O O O O O O O 00 O o O O 2100_' 1800 m ❑ w � ❑ _ - — — — (ui/ljsn 001) (+)gl-Iow(-)glnoS '1sJI � F - 900 M -F O - 300 y 300 Z v o 4 oe o m0 W n x -300 F toO 90 �-,6 O M'2 w 200 to ❑ CLz v m'�ovo�o��n R'2 100 om ¢` m rn <n w w cn <n <n h �0000�rnomurir�o 0 o �a pj o rn a �2 �o �N� °off.6 'l 10 ch3 rn�no `nr wn�ivvvu"-�� 0 Z. lii ai �c s deo o�ZZ�'M P!.on obi °od �a@i - 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JGS 1-2-2016 Air Heaters Rig Boilers Air Heater 20' Exclusion Zone Loader Parking Prohibited T7 � ♦ ` IX Utility Modul �♦ Drill Mo ule Rig Cedar 75' (Dummy Well Hous ' Rig Floor Cantilever 11' ' New ' Diverter Vent Line Cellar, BOP Deck &\ X50' Rig Floor Are All / Classified Areas (No Ignition Sources) 4.0 ud Module Vac Trucks Note 1 -All ignition sources are outside the 75' radius from the end of the diverter vent line. Boilers are located on a deck 2 levels below the air heaters on the rig. Note 2 - An exclusion zone will be used to keep the loader from parking in the 75' radius around the diverter vent. 1970' ► 230' 260' ► t04 Parker 272 on Well S-210 I i I- -114 106 1 07 103 I 111 113 122 u7 119 108 I I� 109 102 110 100 101 115 i 22 120 213 ti 75' Radius Ignition Sources 12 j z0. 216 s —I— I 504 4 / � 504 4— I ® ------------------------ �I I I I o — II 01 d i y 100 I i. LO I �/ I 1 130' 30' ► — tOI I I I ----«----- r--------1 J 130' I 1 1 11 115 I I 61_ 126 I �1134 1 1 t6 n ,zs I II I I j 1 I 18 1 I I I i I I I I 1 1_! 40 Mcg=____�_ j 1175'ILD / / I Enter/E�ik\ ! WELL WELL INJECTOR DATE: 5/1/2018 SCALE: 1" = 300' MAP DATE :2017 PBU - S PAD For current Well and Service information please see One Map AK (https://onemap-alaska.bpweb.bp.com) bs14495. mxd Area of Review — S-210 D/ vt?,19 Distance From Top of Pool Well Name Planned Well (ft) Annulus Integrity (TVDss) TOC s S -200P81 650 P&A'd -4860 Estimated at -3,159' MD. 148 bbls of 15.8 Class G cement was pumped and there were no notable losses during the execution of the job. This estimate places the top of cement at the 9-5/8" casing shoe since injection was established after pumping the cement and the 7" x 9-5/8" annulus was freeze protected. Estimated at `3,159' MD. 48 bbls of 15.8 Class G cement was S-200 900 P&A'd -Rotary sidetracked to S -200A 4839 pumped and there were no notable losses during the execution of the job. This estimate places the top of cement at the 9-5/8" casing shoe since injection was established after pumping the cement and the 7" x 9-5/8" annulus was freeze protected. S-03 is an operable gas lifted producer. S-03 was recompleted to a Kuparuk only producer in 2005. 7/20/06: MIT -IA tested to 4000 psi. Lost 60 psi followed by 40 psi passing to 3900 psi. T/IA had 2500 psi differential during test. TOC is estimated at the 7" liner top packer as "409 bbls of 15.8 IA/OA had 3900 psi differential during test (T/I/O - 1400/3900/0 Class G cement was pumped. Records are very limited but the 503 1020 psi). This test proves up the integrity of the tubing and PC strings -0860 volume pump is more than double the liner length assuming down to the production packer at time of test. A574 % 40%excess. . V5747" B �/� - ZOQ Sr Sl st4J s Cep The OA started showing re -pressurization in late 2016 and has 6119,5 required 3 bleeds since 7/9/17. OA re -pressurization is currently �Q✓ K}.(r .�r�.rn manageable by bleeds. IA/OA have -750 psi differential in Nov. J/wi 2018. S-31 is an operable WAG injector currently on MI. S-31 has been a Kuparuk only injector since Aug. 2014. 6/7/15: MIT -IA tested to 2538 psi. Lost 75 psi followed by 19 psi passing to 2444 psi. T/IA had 1021 psi differential during test. Pumped 375 bbls of 13.5 ppg lead slurry followed by an S-31 630 IA/OA had 2389 psi differential during test (T/I/O - 1423/2444/55 -4880 additional 40 bbols of 15.8 Class G cement. Estimated TOC is psi). This test proves up the integrity of the tubing and PC strings -4,922' MD.( 4 1,5p 7•'N(O 659; down to the production packer at time of test. The T/I/O plots look good for a WAG injector. No history o requiring frequent bleeds. Pumped 239 bbls of 10.7 ppg lead followed by 29 bbls of 15.8 5-108 1230 P&A'd 4917 ppg Class G cement. Signs of cement and dye noted at sur** -,e Estimated TOC is 3,180' MD. i V S-105 is an operable gas lifted producer. 12/30/17: MIT -T tested to 2747 psi. Lost 27 psi followed by 15 psi passing to 2705 psi. T/IA had 2712 psi differential during test (T/I/O - 2705/8/212 psi). This test proves up the integrity of the tubing string to the production packer as TTP was set below the Total of 170 bbls of cement were pumped (115 bbls of 11.5 ppg packer. lead, 55 bb's of 15.8 ppg tail). No losses were noted during the 5305 1320 -4939 cementjob. Assuming 305A washout the TOC would be `3,300' 12/30/17: CMIT-TxIA tested to 2704/2731 psi. Tubing gained 6 psi / IA lost 97 psi followed by 21/27 psi passing to 2689/2607 psi. h I MD. ` 3CZ V ` L- IA/OA had 2372 psi differential during test (T/I/O - 2689/2607/235 psi). This test proves up the integrity of the PC down to the production packer. l The T/I/O plots look good for a gas lifted well. No history o requiring frequent bleeds. D/ vt?,19 0 254 500 750 1000 1250RUS 1 7000 Distance from planned well (Feet) Top of oil pool TVDss 650 -4860 900 -4839 1020 4860 630 -4880 1230 -4917 1320 -4939 i f T o1 0 11 C, Vii ➢1 CV v Vim' 7C -V o V.^,C, AC 7 -=R VAT' AND CONFIDENTIAL -, ,o2 V^, J- jv O O fMCreI -'SSV e. V-'��. v scssv_x Cl) \ O — O VCl 2'.", �. �7 O O O a O O J --V- �,A3- \.VS_a 3 3C0 030.. –� VA\S CC ?—\0 7 38377 OCCS /8 AS \3-A\C--2 azo -o S_ 4 oa8 9 CAS VC -AJ ASS -V3 - 0 2CAS VC —AAC-3 - - — 2C CJ CASVC b 7 'AC<0-- ASS -V-, g ' So9o5 3\,", - A\C-C ASS_V3_ 9 OS C 0 5 -_3 V;; =AJ 47AI-13 ASS=_V3L" 2319J Sid 2 --AS VC -AAG C, .AS VC 2 .2 09< -7 CAS \C _AVC -3 __ G-) LAS \C oc -JV �'9�98 Rixse, Melvin G (CED) From: Bjork, David <David.Bjork@bp.com> Sent: Thursday, May 16, 2019 1:54 PM To: Rixse, Melvin G (CED); Schwartz, Guy L (CED) Cc: Gorham, Bradley M Subject: FW: PTD Request 219-057, PBU S-210 Variance Request Mel, Guy, Please review the below discussion of injection pressures, confinement monitoring and explanation for variance request. Thank you for your consideration and assistance working through the new completion design. Please don't hesitate to call if you would like to discuss. Regards, Dave Bjork (907) 564-5683 (907)440-0331 Schrader Bluff Injection will be managed in within the parameters set forth in Area Injection Order 26A May 1, 2006. Injection Confining Intervals: The upper contact between the N Sands and the overlying Prince Creek formation is generally an abrupt transition from sandstone to mudstone forming the upper confinement. The Lower Prince Creek formation (Ma -Mc sands) typically contains over 30 feet of laterally continuous shales and mudstones. Mudstones and muddy siltstones up to 1000 feet thick provide the basal confinement of the Schrader sandstones. Fracture Information The Commission originally ordered that injection pressures be maintained below 0.67 psi/ft to ensure that Orion injected water does not fracture or migrate out of zone, and based its decision upon BPXA's estimate of a 0.66 - 0.67 psi/ft fracture pressure for the confining mudstone using data from stress tests and dipole sonic log. Several tests conducted with the Commission's approval support BPXA's conclusion that increased injection pressures will not result in migration out of zone. A zonal isolation test was completed in Orion well L-210 in April 2005. Sand -face pressure gauges were installed adjacent to discrete zones both above and below an isolated injection interval in order to record pressure response and reveal whether injection was breaching the confining barriers. The two perforated zones were separated by around 28 feet TVD of unperforated OA interval comprised of silty mudstone. Injection rates of up to 4200 BWPD with an injection gradient of up to 0.82 psi/ft were achieved while injecting into the lower zone. No pressure response in the adjacent zone was seen; hence, the water did not breach out of zone. Additional step rate and pulse tests in Polaris and Milne Point Schrader formations showed similar results. On December 13, 2005 the Commission administratively approved elimination of the injection pressure limitation. However, injection pressure must be maintained such that injected fluids do not fracture the confining zones or migrate out of the approved injection stratum. BPXA will monitor each injection well and if any significant change in injectivity indicates injection out of zone, surveillance will be conducted to determine the cause of the injection anomaly. Planned cement tops for this completion style is in excess of 2,000ft of cement above injection zone. Confinement Monitoring will be performed on a two year MIT -T and MIT testing cycle. A waterflow log will also be performed at the testing anniversary. Daily tubing and Annulus pressure will be noted, and any anomalies communicated to the Well Integrity Team for evaluation. From: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Sent: Thursday, April 18, 2019 1:14 PM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Cc: Schwartz, Guy L (DOA) <Ruy.schwartz@alaska.gov> Subject: FW: PTD Request 219-057, PBU S-210 Variance Request Brad, AOGCC does not consider 'volume of cement' sufficient justification to provide a variance to: 20 AAC 25.412. Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage (b) A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. The proposed well design no longer provides an additional cemented casing shoe as an additional barrier to isolate injection from permeable zones above the targeted zone. AOGCC will require BPXA to provide "an equally effective means of accomplishing the requirement set out in the commission's regulation". In addition to cement volume, I would encourage BPXA to provide a thorough discussion of: 1. Production practices (injection pressures etc.) 2. Confinement monitoring for the life -of -well. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.Kov). cc. Guy Schwartz STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF BP ) Area Injection Order No. 26A EXPLORATION (ALASKA) INC. for } modification of Area Injection Order 26 to ) Prudhoe Bay Field authorize underground injection of ) Schrader Bluff Oil Pool enriched hydrocarbon gas for enhanced oil ) Orion Development Area recovery in Orion Oil Pool, Prudhoe Bay May I, 2006 Field, North Slope, Alaska; and THE PROPOSAL initiated by the Commission to amend underground injection orders to incorporate consistent language addressing mechanical integrity of wells. IT APPEARING THAT: By application dated February 23, 2006 BP Exploration (Alaska) Inc. ("BPXA"), operator of the Prudhoe Bay Unit ("PBU"), requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") modifying Area Injection Order 26 ("AIO 26") and Conservation Order 505 to authorize the injection of enriched hydrocarbon gas for enhanced oil recovery ("EOR") purposes in the Orion Oil Pool within the PBU. 2. The Commission published notice of opportunity for public hearing on BPXA's application in the Anchorage Daily News on March 2, 2006. 3. The Commission received no requests for a public hearing. 4. The Commission received no protests or comments. 5 On its own motion, the Commission proposed to amend the rules addressing well mechanical integrity in all existing orders authorizing underground injection. The Commission published notice of opportunity for public hearing on the proposal in the Anchorage Daily News on October 3, 2004. 6 By e-mail dated October 15, 2004 BPXA suggested edits to the Commission's proposed language addressing the mechanical integrity of injection wells. 7. The Commission received no requests for a public hearing. 8. The Commission received no protests or comments. Area Injection Order 26A Page 2 May 1, 2006 9. No hearing was held. FINDINGS: 1. Operator BPXA is Operator of the Orion Development Area of the Schrader Bluff Oil Pool in the Prudhoe Bay Field, North Slope, Alaska. 2. Formations Authorized for Enhanced Recovery Enhanced recovery injection for the Orion Development Area is proposed within the Schrader Bluff Oil Pool. The target injection zones are correlative to Prudhoe Bay Unit well V-201 between the measured depths ("MD") of 4,549 feet and 5,106 feet (Schrader Bluff formation). 3. Proposed Injection Area BPXA requested authorization to inject fluids for the purpose of enhanced recovery operations on lands within Umiat Meridian T12N-R10E, T12N-RIIE, T11N-R11E, and TI IN -RI 2E in the Prudhoe Bay Unit. 4. Operators/Surface Owners Notification BPXA provided operators and surface owners within one-quarter mile of the proposed area with a copy of the application for injection. The only affected operator is BPXA, operator of Prudhoe Bay Unit and the Milne Point Unit. The State of Alaska, Department of Natural Resources is the only affected surface owner. 5. Description of Operation The contemplated operation is an EOR project using enriched gas from the Prudhoe Bay Central Gas Facility. The project involves the cyclical injection of water alternating with injection of hydrocarbon gas enriched with intermediate hydrocarbons, principally ethane and propane. Implementation of the Orion EOR project will involve connection of Orion injection wells to existing or new miscible gas injection distribution systems on L, V, and Z Pads. Enriched hydrocarbon gas injection is expected to begin in 2nd quarter 2006. 6. Hydrocarbon Recovery The Schrader Bluff Oil Pool is estimated to contain 1,070 - 1,785 million stock tank barrels ("STB") of original oil in place ("OOIP") within the Orion Development Area, based on exploratory drilling and seismic mapping. Computer simulation indicates primary recovery within the major sands of the development area is expected to be 5% - 10% of the OOIP, and waterflood may increase recovery to 20% - 25% of the OOIP where implemented. Preliminary evaluations suggest that the EOR project could yield an incremental recovery to waterflood of up to 6% where implemented. These recovery estimates were obtained using an Equation of State ("EOS") developed for the nearby Polaris Oil Pool, a close analog of Area Injection Order 26A May 1, 2006 Page 3 the Orion Development Area. Oil from the Polaris Oil Pool has essentially identical composition and quality as that of the Orion accumulation and both accumulations have similar reservoir temperature, pressure and depth. Laboratory swell, multiple contact, and slimtube experiments were conducted using Polaris oil from W-203 and the PBU enriched gas and were used to develop a new Polaris EOS. Fully compositional, mechanistic type pattern model simulations were conducted using the Polaris EOS for a W Pad reservoir description. In part of the project area where the reservoir oil has sufficient concentration of C7 - C13, the enriched gas forms a miscible bank with the reservoir oil through exchange of hydrocarbon components, and displaces nearly all of the contacted oil. In areas where the oil lacks sufficient concentration of C7 - C 13 components to be miscible with the Prudhoe enriched gas at reservoir conditions, miscibility may not occur. Rather, a multiple contact condensing/vaporizing mass transfer mechanism between reservoir oil and the CO2 and C2 - C4 in the Prudhoe enriched gas causes a significant reduction in reservoir oil viscosity. BPXA states that the magnitude of tertiary oil recovery by this "viscosity reducing, immiscible enriched gas flood" is very close to that with miscible gas injection. A fifty -fold reduction in viscosity of a 40 cp Polaris oil was found by contacting the PBU enriched gas in a single cell multiple -contact laboratory experiment conducted at reservoir conditions. Gross utilization of Prudhoe enriched gas was estimated to be around 5.3 thousand cubic feet ("MCF") of enriched gas injected for every barrel of EOR oil. This is similar to the efficiency at other satellite Prudhoe projects and compares to an efficiency of about 15 - 20 MCF/barrel for enriched gas injection in the mature IPA EOR project area, which justifies the preferential injection of Prudhoe enriched gas into the Orion accumulation. Approval was granted for enriched gas injection within the Polaris Oil Pool on November 28, 2005. 7. Geologic Information a. Stratigraphy: The Schrader Bluff Oil Pool encompasses reservoirs assigned to the Late Cretaceous -aged Schrader Bluff formation ("Schrader Bluff'). The Schrader Bluff is divided into two stratigraphic intervals that are designated, from deepest to shallowest, the "O sands" and the "N sands." The O and N sand intervals were deposited in marine shoreface and shallow shelf environments. The Schrader Bluff O sands are divided into seven separate reservoir intervals that are named, from deepest to shallowest, OBf, OBe, Obd, OBc, OBb, OBa, and OA. Each of these intervals coarsens upward from non -reservoir, laminated muddy siltstone at the base to reservoir -quality sandstone at the top. The lower portion of the Schrader Bluff N sands is dominated by mudstone and siltstone. However, the sediments coarsen upward, and fine- to medium -grained sandstone is prevalent in the upper part of the N sands. Three reservoir intervals are recognized within the N sands. They are, from oldest to youngest, Nc, Nb, and Na. b. Structure Overview: The structural dip ranges from 1 to 4 degrees to the east and northeast, and is broken by three sets of normal faults from Northwest to Southeast, North to South, and East to West. The Northwest to Southeast fault trend has throws up Area Injection Order 26A May 1, 2006 Page 4 to 200 feet. The North to South striking faults, downthrown to the west and east, have throws of up to 100 feet. East to West faults are less common, and form the reservoir trap on the southwestern side of the Orion Development Area. c. Confining Intervals: The upper contact between the N Sands and the overlying Prince Creek formation is generally an abrupt transition from sandstone to mudstone forming the upper confinement. The Lower Prince Creek formation (Ma -Mc sands) typically contains over 30 feet of laterally continuous shales and mudstones. Mudstones and muddy siltstones up to 1000 feet thick provide the basal confinement of the Schrader sandstones. 8. Well Logs The logs of existing injection wells are on file with the Commission. 9. Mechanical Integrity of Wells The Commission has approved injection operations for all currently drilled Orion injectors. Mechanical integrity has been established for all injectors and wells within one-quarter mile of the Orion injectors. Cement tops are at an adequate height above the injection zone to prevent fluid from migrating out of the Orion injection zone. 10. Type of Fluid / Source Fluids requested for injection are: a. enriched gas from Prudhoe Bay Unit processing facilities; b. produced water from Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; c. source water from the Prince Creek formation (also known as the Ugnu formation); d. tracer survey fluid to monitor reservoir performance; e. fluids injected for purposes of stimulation per 20 AAC 25.280(a)(2); f. source water from the Seawater Treatment Plant; and g. non -hazardous water collected from well -house cellars and standing ponds. 11. Enriched Gas Composition and Compatibility with Formation The enriched gas proposed for injection is a hydrocarbon with similar composition to reservoir fluids in the Orion Oil Pool and therefore no compatibility issues are anticipated. The compatibility of the injection waters was addressed in AIO 26 dated February 3, 2003. 12. Injection Rates and Pressures Maximum miscible gas injection requirements are about 60,000 MSCFD. Maximum water injection is projected at 125,000 bwpd. The average manifold injection pressure for the enriched gas will be 3000 psi, with a maximum of about 3300 psi. The average surface water injection pressure will be about 1100 psi, with a maximum of about 2000 psi. This will result in a maximum bottom hole pressure of about 4000 psi. Area Injection Order 26A May 1, 2006 13. Fracture Information Page 5 The Commission originally ordered that injection pressures be maintained below 0.67 psi/ft to ensure that Orion injected water does not fracture or migrate out of zone, and based its decision upon BPXA's estimate of a 0.66 - 0.67 psi/ft fracture pressure for the confining mudstone using data from stress tests and dipole sonic log. Several tests conducted with the Commission's approval support BPXA's conclusion that increased injection pressures will not result in migration out of zone. A zonal isolation test was completed in Orion well L-210 in April 2005. Sand -face pressure gauges were installed adjacent to discrete zones both above and below an isolated injection interval in order to record pressure response and reveal whether injection was breaching the confining barriers. The two perforated zones were separated by around 28 feet TVD of unperforated OA interval comprised of silty mudstone. Injection rates of up to 4200 BWPD with an injection gradient of up to 0.82 psi/ft were achieved while injecting into the lower zone. No pressure response in the adjacent zone was seen; hence, the water did not breach out of zone. Additional step rate and pulse tests in Polaris and Milne Point Schrader formations showed similar results. On December 13, 2005 the Commission administratively approved elimination of the injection pressure limitation. However, injection pressure must be maintained such that injected fluids do not fracture the confining zones or migrate out of the approved injection stratum. BPXA will monitor each injection well and if any significant change in injectivity indicates injection out of zone, surveillance will be conducted to determine the cause of the injection anomaly. 14. Freshwater exemption Aquifer Exemption Order #1, dated July 11, 1986 exempts all portions of aquifers beneath the Western Operating Area of the Prudhoe Bay Unit, including the area designated for the proposed waterflood pilot project. 15. Mechanical Condition of Adjacent Wells All wells within one-quarter mile of existing proposed water -alternating -gas injectors have been reviewed for mechanical isolation. The records of cement jobs and cement bond logs were reviewed. All wells appear to have mechanical isolation between the Schrader Bluff and all other intervals. 16. Amendments to Rules The Commission proposed amendments to Rules 4 and 5 and the addition of Rule 7 in order to incorporate consistent language addressing the mechanical integrity of injection wells. Various wording used in different rules creates confusion and inconsistent implementation of well integrity requirements for injection wells. CONCLUSIONS: 1. The application requirements of 20 AAC 25.402 have been met. Area Injection Order 26A May 1, 2006 2. Enriched gas injection will significantly improve recovery. Page 6 3. The proposed injection operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 4. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 5. Reservoir and well surveillance, coupled with regularly scheduled mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 6. Amendments to Rules 4 and 5 and the addition of Rule 7 will provide for consistent implementation of well integrity requirements for injection wells. NOW, THEREFORE, IT IS ORDERED THAT: In addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), the following rules govern the underground injection of fluids for enhanced oil recovery in the Schrader Bluff Oil Pool within the affected area described below, referred to herein as the Orion Development Area, and supersede and replace the rules adopted in AIO 26 dated January 5, 2004 and AIO 26.001 dated December 13, 2005. Umiat Meridian Township Range, UM Lease Sections T12N-R10E ADL 025637 13 and 24 N/2 T12N-RI1E ADL 047446 17, 18, 19, and 20 ADL 047447 16 S/2 and NW/4 and S/2 NEA, 21, and 22 ADL 028238 25 SWA, 26, 35, and 36 ADL 028239 27, 28, 33 E/2 and N/2 NW/4, and 34 ADL 047449 29 N/2 and SEA, and 30 N/2 NE/4 Tl IN-Rl lE ADL 028240 1, 2, 11 E/2 and E/2 NW/4, and 12 ADL 028241 3 N/2 and N/2 S/2, and 4 NEA N/2 SEA ADL 028245 13 N/2 and SEA, 14 E/2 NEA, and 24 E/2 l - /A Area Injection Order 26A May 1, 2006 NE/4 T11N-R12E ADL 047450 7, and 8 S/2 and NW/4 Rule 1: Authorized Injection Strata for Enhanced Recovery (AIO 26) Page 7 Fluids appropriate for enhanced oil recovery may be injected for purposes of pressure maintenance and enhanced recovery within the Orion Development Area into strata that are common to, and correlate with, the interval between measured depths 4,549 feet MD and 5,106 feet MD in the PBU V-201 well and between the measured depths of 4,174 feet and 4,800 feet in Milne Point Unit well A-1. Rule 2: Fluid Injection Wells (AIO 26) The underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280 and 20 AAC 25.412 (e). Rule 3: Authorized Fluids for Enhanced Recovery (Revised by this Order AIO 26A) Fluids authorized for injection include: a. enriched gas from the Prudhoe Bay Unit processing facilities; b. produced water from Prudhoe Bay Unit production facilities for the purposes of pressure maintenance and enhanced recovery; c. tracer survey fluid to monitor reservoir performance; d. source water from a sea water treatment plant; e. source water from the Prince Creek (Ugnu) formation; and f. non -hazardous filtered water collected from Schrader Bluff Oil Pool well house cellars and well pads in the Orion Development Area. Rule 4: Monitoring Tubing -Casing Annulus Pressure (Revised by this Order AIO 26A) The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by extreme weather condition, emergency situations, or similar unavoidable circumstances. Monitoring results shall be documented and made available for Commission inspection. Rule 5: Demonstration of Tubing/Casing Annulus Mechanical Integrity (Revised by this Order AIO 26A) The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. A Commission -witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus Area Injection Order 26A Page 8 May 1, 2006 pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. Results of mechanical integrity tests must be readily available for Commission inspection. Rule 6: Multiple Completion of Water Injection Wells (AIO 26) a. Water injectors may be completed to allow for injection in multiple pools within the same wellbore so long as mechanical isolation between pools is demonstrated and approved by the Commission. b. Prior to initiation of commingled injection, the Commission must approve methods for allocation of injection to the separate pools. c. Results of logs or surveys used for determining the allocation of water injection between pools, if applicable, must be supplied in the annual reservoir surveillance report. d. An approved injection order is required prior to commencement of injection in each pool. Rule 7: Well Integrity Failure and Confinement (Added this Order AI026A) Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall notify the Commission by the next business day and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8: Notification of Improper Class II Injection (AIO 26) Injection of fluids other than those listed in Rule 3 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the Commission, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 9: Plugging and Abandonment of Fluid Injection Wells (AIO 26) An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25. Rule 10: Other conditions (AIO 26) It is a condition of this authorization that the operator complies with all applicable Commission regulations. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Area Injection Order 26A Page 9 May 1, 2006 Rule 11: Administrative Actions (AIO 26) Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. DONE at Anchorage, Alaska and dated May 1, 2006. John K. Norman, Chairman Alaska Oil and Gas Conservation Commission Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission Cathy P. Foerster, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23d day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10 -day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30 day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10'" day after the application for rehearing was filed). From: Gorham, Bradley M <Bradley.Gorham2bp.com> Sent: Wednesday, April 17, 2019 1:41 PM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Cc: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Mel, Please see below for the written variance request. Let me know if there is any other information you need or if you have any questions. The new injector design involves the use of a significant volume of cement to provide zonal isolation to the Schrader Bluff reservoir as well as to provide mechanical integrity on the inner annulus. Due to the volume of cement being placed in the well, it is requested that the utilization of a production packer is unnecessary. This is a variance from 20 AAC 25.412. Thanks, Brad Gorham BP Exploration (Alaska), Inc. Drilling Engineer W: (907)564-4649 C: (907)223-9529 Bradley.Gorham@bp.com From: Rixse, Melvin G (DOA) <rnelvin.rixse@alaska.gov> Sent: Tuesday, April 16, 2019 1:14 PM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Cc: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Brad, Please provide a written variance request to 20 AAC 25.412 as noted in the attached email. As discussed with David Bjork, it is expected that AOGCC commissioners will approve this PTD request. A complete discussion of confinement and scheduled confinement monitoring in the BPXA variance request will be required. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (M(,lvin Rixse.Li? laska.gov). cc. Guy Schwartz From: Rixse, Melvin G (DOA) Sent: Tuesday, April 16, 2019 12:14 PM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Brad, Agreed. I expect we (commissioners) will still want a written variance request. I will get back to you. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.Rov). From: Gorham, Bradley M <Bradley.Gorham@bp.com> Sent: Tuesday, April 16, 2019 12:06 PM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.Bov> Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Mel, This well is the first of the new Schrader Bluff injector design that Dave Bjork discussed with Guy and yourself back in December of last year. If you would like to discuss further we'd be happy to set up a conference call to ensure we have answered all your questions. Let me know what times work best for you and we will try to accommodate as best as we can. Thanks, Brad Gorham BP Exploration (Alaska), Inc. Drilling Engineer W: (907)564-4649 C: (907)223-9529 Bradley.Gorham@bp.com From: Rixse, Melvin G (DOA) <melvin.rixsePalaska.Bov> Sent: Tuesday, April 16, 2019 11:06 AM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Subject: PTD Request 219-057, PBU S-210 Variance Request Brad, On page 8 under 'Variance Requests' for the BPXA PTD request for S-210, there is no discussion for a request for variance to: 20 AAC 25.412. Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage which states: (b) A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. Please provide written justification why a cemented 3-1/2" tubing string would provide an equally effective means of accomplishing 20 AAC 25.412 (b) Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (ME Ivin Rixse�??alaska_ ov). Davies, Stephen F (DOA) From: Gorham, Bradley M <Bradley.Gorham@bp.com> Sent: Thursday, May 16, 2019 11:04 AM To: Davies, Stephen F (CED) Subject: RE: PBU S-210 (PTD 219-057) - Questions Steve, Just wanted to follow up with your questions on the S-210 PTD. 1. BP does not plan to frac S-210. The plan is to breakdown the cement to establish communication with the reservoir before starting injection. BP does not plan to pre -produce or flowback the S-210 well. After discussing this with Bill Isaacson, it sounds like an agreement was reached and that the information BP originally provided is adequate. Please let me know if that is not the case and we can discuss. Let me know if you have any further questions and I will be happy to address them. Thanks, Brad Gorham BP Exploration (Alaska), Inc. Drilling Engineer W: (907)564-4649 C: (907)223-9529 Bradley.Gorham@bp.com From: Davies, Stephen F (DOA) <steve.davies@alaska.gov> Sent: Monday, April 15, 2019 4:35 PM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Subject: FW: PBU S-210 (PTD 219-057) - Questions Brad, I'm reviewing BP's Permit to Drill for the proposed injection well PBU S-210, and I have a few questions: 1. On the Permit to Drill form, neither of the boxes labeled "Yes" or "No" associated with the question "Hydraulic Fracture planned?" is checked. Is BP planning to frac this well? 2. Does BP plan to pre -produce this injection well for an extended period of time (1 month or longer) or will it be flowed back briefly for clean up? 3. Could BP please check, update, and re -submit the table showing the mechanical condition of all wells within the -mile radius Area of Review? Regulation 20 AAC 402(c)(15) requires: "a report on the mechanical condition of each well that has penetrated the injection zone within a one-quarter mile radius of a proposed injection well." [Emphasis is mine.] BP's application presents information only on the mechanical condition of each well that penetrates the injection zone within a one-quarter mile radius of the proposed injection interval within the reservoir. According to my map, there are more penetrations of the injection zone by wells and plugged -back wellbores that lie within a %-mile radius of the proposed PBU S-210 injection well than are shown on the table submitted in support of the PBU S-210 application. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. z z z z J U (D U' J 3 J J odQ+S0 oo�<oo CL ix CAm c � �Cp+ r ty r o r+ oo b u� � ONtC�pV [cpp ttr��1 Ot(Ny1)� t�upp� Otf[V� Popo G�fN� QO�(N'iNNup stip u�S�fNpg�p� Gb0u 6 b Z O O r rmm"' � f[rNp�) C tryrNp7 U N g pN st r O! f+ t+ t0 O) ted' Q1 M G1 1+ t0 M � u' M M IM'- i �Q(pp1 �O�pp) A r M �Q(pp1 A �Q�pp1 A �p�Cp A A AIA tCG� A �Cpp A [ C+ti7 M Cr) C tl~9 O th 00 N 00 4= a O1 O1 �) M N N o o r r b ch C 6 6 [n 'A � i� (!1 rh � ( 6 fh J, fh Ch Z Z Z Z 0 0 0 0 0 w O w O ui O W O aO> 0 0 0 o a 4 Q 4 Q 1 a a a a a s a s CL IM iX CLlajCL am 0 0 cl m m a m m m m m m a n. a m m m m m m m m m m m m m m m m m ac C) b- C b 0 C O b b b Co -W C C b C C C I; 4) 0 f+ r 1+ �7' 00 m M) w) m M N N C O 0 m O C tV fV C, O N r r N b d co 00 allo oP �+) c0 oQ rn eC6 ai O� o o a o � r r r r r r r r r r N N N N N— C) ) CS C) 6 6 C) C) C) C, b C) Co C] r 0 6 uJ00 C`J CS m 6 Q) 0 Ch 6 n? 6 C,) C? O) C] N O tp O 1'- 6 6 M 6 CO n F- yrn c6 t+ (1) CO 1.f) r N C) Cti V r (14 b CO h�- f+ C) c0 C) 00 O Ch C� r r C T N oo CV ci) c14 [ri O n7 r c l a) CtVV 3 fV N N N N CV N r4 cJ N N N N N fV O) C) Q) b Q) 0) 6 a] Q) Cn O) m b O) Q) N N N N N N N N N N N N N N N G b C7 C) 6 C] 6 U C) U O S O 6 C7 6 O 2 O U O CS 6 6 d co C) C -D C� 6 Ul U) Ui UL,U/ U-,IXi Ui 17J U) U! U) Ul U1 U1 Rixse, Melvin G (DOA) From: Rixse, Melvin G (DOA) Sent: Tuesday, April 16, 2019 1:14 PM To: Gorham, Bradley M Cc: Guy L Schwartz (DOA) (guy.schwartz@alaska.gov) Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Attachments: RE: Schrader Injector Concept Brad, Please provide a written variance request to 20 AAC 25.412 as noted in the attached email. As discussed with David Bjork, it is expected that AOGCC commissioners will approve this PTD request. A complete discussion of confinement and scheduled confinement monitoring in the BPXA variance request will be required. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Me.I in.Rixspaalaska._ov_). cc. Guy Schwartz From: Rixse, Melvin G (DOA) Sent: Tuesday, April 16, 2019 12:14 PM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Brad, Agreed. I expect we (commissioners) will still want a written variance request. I will get back to you. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse a alaska.Rav). From: Gorham, Bradley M <Bradley.Gorham@bp.com> Sent: Tuesday, April 16, 2019 12:06 PM To: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Subject: RE: PTD Request 219-057, PBU S-210 Variance Request Mel, This well is the first of the new Schrader Bluff injector design that Dave Bjork discussed with Guy and yourself back in December of last year. If you would like to discuss further we'd be happy to set up a conference call to ensure we have answered all your questions. Let me know what times work best for you and we will try to accommodate as best as we can. Thanks, Brad Gorham BP Exploration (Alaska), Inc. Drilling Engineer W: (907)564-4649 C: (907)223-9529 Bradley.Gorham@bp.com From: Rixse, Melvin G (DOA) <melvin.rixse@alaska.gov> Sent: Tuesday, April 16, 2019 11:06 AM To: Gorham, Bradley M <Bradley.Gorham@bp.com> Subject: PTD Request 219-0S7, PBU S-210 Variance Request Brad, On page 8 under 'Variance Requests' for the BPXA PTD request for S-210, there is no discussion for a request for variance to: 20 AAC 25.412. Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage which states: (b) A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent. The packer must be placed within 200 feet measured depth above the top of the perforations, unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. Please provide written justification why a cemented 3-1/2" tubing string would provide an equally effective means of accomplishing 20 AAC 25.412 (b) Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.Rov). Rixse, Melvin G (DOA) Subject: PTD Request 219-057, PBU S-210 Variance Request Brad, On page 8 under 'Variance Requests' for the BPXA PTD request for S-210, there is no discussion for a request for variance to: 20 AAC 25.412. Casing, cementing, and tubing of injection wells for enhanced recovery, disposal, and storage which states: (b) A well used for injection must be equipped with tubing and a packer, or with other equipment that isolates pressure to the injection interval, unless the commission approves the operator's use of alternate means to ensure that injection of fluid is limited to the injection zone. The minimum burst pressure of the tubing must exceed the maximum surface injection pressure by at least 25 percent The packer must be placed within 200 feet measured depth above the top of the perforations unless the commission approves a different placement depth as the commission considers appropriate given the thickness and depth of the confining zone. Please provide written justification why a cemented 3-1/2" tubing string would provide an equally effective means of accomplishing 20 AAC 25.412 (b) Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell 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 Mel Rixse at (907-793-1231 ) or (Mels ui Rixs�(��I�sk.gav). Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Monday, April 15, 2019 4:35 PM To: 'bradley.gorham@bp.com' Subject: FW: PBU S-210 (PTD 219-057) - Questions Brad, I'm reviewing BP's Permit to Drill for the proposed injection well PBU S-210, and I have a few questions: 1. On the Permit to Drill form, neither of the boxes labeled "Yes" or "No" associated with the question "Hydraulic Fracture planned?" is checked. Is BP planning to frac this well? 2. Does BP plan to pre -produce this injection well for an extended period of time (1 month or longer) or will it be flowed back briefly for clean up? 3. Could BP please check, update, and re -submit the table showing the mechanical condition of all wells within the -mile radius Area of Review? Regulation 20 AAC 402(c)(15) requires: "a report on the mechanical condition of each well that has penetrated the injection zone within a one-quarter mile radius of a proposed injection well." [Emphasis is mine.] BP's application presents information only on the mechanical condition of each well that penetrates the injection zone within a one-quarter mile radius of the proposed injection interval within the reservoir. According to my map, there are more penetrations of the injection zone by wells and plugged -back wellbores that lie within a %-mile radius of the proposed PBU S-210 injection well than are shown on the table submitted in support of the PBU S-210 application. Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. TRANSMITTAL LETTER CHECKLIST WELL NAME: ':5 — PTD: �C` —(—)S7 Development Y/ 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 The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69 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 Pilot Hole name ( PH) and API number (50- - - -) from records, data and logs acquired for well name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 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 (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements ✓ Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Poo - l PRUDHOE BAY, POLARIS OIL 640160 _ Well Name: PRUDHOE BAY UN POL S-210 Program SERWell bore seg ❑ PTD#: 2190570 Company BP EXPLORATION (ALASKA) INC. Initial Class/Type SER / PEND GeoArea 890 - Unit 11650 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate_ - - - - - - - - Yes - Entire- well in ADL 028257, 3 Unique well -name and number Yes _ - - --- 4 Well located in_a_defined _pool _ Yes PRUDHOE BAY, PO_LARIS_OIL - 640160, governed by CO 484 5 Well located proper distance_ from_ drilling unit -boundary Yes Rule 1: Spacing units within the pool shall be a minimum of 20 acres. The Polaris Oil Pool shall_ not be 6 Well located proper distance from other wells_ Yes es._ - - - opened_ in any well closer than 500' to an external boundarywhere ownershiP changes. 7 Sufficient acreage -available in -drilling unit_ Yes 8 If deviated, is -wellbore plat -included Yes - - - - - - - 9 Operator only affected party_ Yes 10 Operator has -appropriate _ bond in force _ _ _ _ Yes - 11 Permit can be issued without conservation order_ Yes Appr Date 12 Permit can be issued without administrative _approval - - - - - .. Yes 13 Can permit be approved before 15 -day wait_ - - - - . - - - - - - Yes SFD 5/16!2019 - 14 Well located within area and -strata authorized by Injection Order # (put 10# in_comments)_ (For- Yes 15 All wells within 1/4_mile-area.of review identified (For service well only) Yes - - - - Wells -within -1/4 mile -of inj. interval are S-03, S-105, S -105A, S -108,_S-20.0, S-200 PB1_, and -S-31. 16 Pre -produced injector; duration -of pre production less than 3 months_ (For service well only) N_o_ - - - - - - Operator -does not plan to_pre-produce or_flowback the S-210 well. 17 N_onconve_n. gas conforms to AS31.05.030 '.1_.A),(12.A-D) � NA - - - - - - - - - - - 118 Conductor string -provided _ - - . - - - Yes - - - 20" x 34" -set- to 90' RKB_ - - - - - Engineering 119 Surface casing -protects all -known USDWs - - - - Yes----- 120 CMT -vol adequate to circulate -on conductor _& surf _csg - - - ----------- Yes - 35-0%- excess across_the permafrost ------------------------------ 21 CMT -vol adequate -to tie -in -long string to surf csg_ Yes . - - Cemented 3-1/2" production liner fully cemented into surface casing_ 22 _C_MT will coverall known productive horizons _ - - - - Yes - _ - - - - - - All zones_ fully cemented --- ------ -- ----------- 23 Casing designs adequate for C, T, B &_ permafrost _ - - - - - Yes 24 Adequate -tankage- or reserve pit - - - - - Yes - - Parker 272 will be ongoing operations . 25 If, a re -drill, has -a 1-0-403 for abandonment been approved NA- - - - Grassroots well. No abandonment required 26 Adequate wellbore separation_proposed_ - - - - Yes . - Planned wellpath meets all BP separation criteria_ 27 If diverter required, does it meet_ regulations_ Yes Appr Date I28 Drilling fluid- program schematic-&- equip -list-adequate - - - Yes - - - - - All fluids will be overbalanced to reservoir - - - - - - - - - - - _ MGR 6/5/2019 I29 BOPEs,_do they meet regulation - - - - - - - - - Yes _ 3 ram stack plus annular - - - - - - I30 BOPE_press rating appropriate; test to -(put psig in comments)_ Yes - - - - 5M rated BOP_E_tested _to 4000 -psi- 31 Choke manifold complies w/API_RP-53 (May 84)_ - - - Yes - - - - - 32 Work will occur without operation shutdown. Yes Parker 272 will be ongoing operations_ 33 Is presence_ of H2S gas_ probable - - _ - - Yes S -Pad is considered an H2S pad. -BP-H2S-management systems will be in_ place 34 Mechanical -condition of wells within AOR verified (For service well only) - Yes - 35 Permit- can be issued w/o hydrogen- sulfide measures - - - - - No an - - - - - S -Pad is an H2S site. H2S measures are required- - - - - - - - - - - - - - - Geology 36 Data presented onpressure _ potential over p zones Yes Planned weights -hts ppearde q y pore pressures. - - - - a _auate to control theoperator's forecast of -most like) - Appr Date 37 Seismic analysis_ of shallow gas -zones- - - - - NA_ - - - - - - S -Pad wells may encounter_shallow gas and hydrates from SV5 to_UG1. - - - - - - - - SFD 4/12/2019 38 Seabed condition survey -(if off_ -shore) - - _ . NA_ - - - - No abnormally geo-pressured strata are an_ticipated_- - - - - - - - - - 39 Contact name/phone for weekly -progress reports [exploratory only] _ _ _ _ _ _ NA_ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - Geologic Engineering Public S -Pad wells may encounter shallow gas and hydrates from SV5 to UG1. SFD Commissioner: Date: Commissioner: Date Commissioner Date