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Home My WebLink About167-045CAUTION: 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:Josh Allely - (C) To:Regg, James B (OGC);DOA AOGCC Prudhoe Bay;Brooks, Phoebe L (OGC);Wallace, Chris D (OGC) Cc:McLellan, Bryan J (OGC);Chad Helgeson Subject:MIT - KDU-01 - 04/24/22 Date:Monday, April 25, 2022 10:33:49 AM Attachments:KDU 01 - MIT Form 4-24-2022.xlsx Attached is the official report of the successful MIT performed on KDU-01 (KENAI DEEP UNIT 1), tested on 04/24/22. Witness was waived. Thanks Josh Allely Well Integrity Engineer Kenai – Hilcorp Alaska 907-777-8505 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. .HQDL'HHS8QLW 37' Submit to: OOPERATOR: FIEL D / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1670450 Type Inj G Tubing 206 209 210 211 Type Test P Packer TVD 4415 BBL Pump 0.7 IA 97 1906 1905 1905 Interval I Test psi 1500 BBL Return 0.5 OA 141 142 142 141 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska, LLC Kenai Gas Field / Kenai Unit / Pad 14-06 Waived Andrew Tuttle 04/24/22 Notes: Notes: Notes: Notes: KENAI DEEP UNIT 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec hanical Integrity Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)2022-0424_MIT_KDU-1 9 9 9 9 9 9 9 -5HJJ 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. Some people who received this message don't often get email from agraves@hilcorp.com. Learn why this is important From:Regg, James B (OGC) To:Andy Graves Cc:Brooks, Phoebe L (OGC) Subject:RE: Well: Kenai Deep Unit 1 MIT-IA Report Date:Tuesday, April 19, 2022 9:57:00 AM Revised our copy of the test report to show “BBL Pump” as 4.5 instead of 187 (presumably gallons). Please adjust your copy. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Andy Graves <agraves@hilcorp.com> Sent: Monday, April 18, 2022 2:15 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: Well: Kenai Deep Unit 1 MIT-IA Report Jim, Here is the MIT-IA report for Well: KDU-001 Kenai Gas Field / Kenai Unit / Pad 14-06 Thanks Andy Graves Kenai Gas Field Operations Lead Office 1-907-283-1345 Cell 1-907-394-3076 Alternate: Zach Rohr .HQDL'HHS8QLW 37' Revised our copy of the test report to show “BBL Pump” as 4.5 instead of 187 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. Submit to: OOPERATOR: FIEL DD // UNITT // PAD: DATE: OPERATORR REP: AOGCCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 1670450 Type Inj G Tubing 226 225 222 224 221 222 Type Test P Packer TVD 4415 BBL Pump 4.5 IA 160 1668 1637 1622 1617 1592 Interval I Test psi 1500 BBL Return 4.0 OA 185 185 185 185 185 185 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Notes: Hilcorp Alaska, LLC Kenai Gas Field / Kenai Unit / Pad 14-06 Waived by Jim Regg Andy Graves 04/18/22 Notes: Notes: Notes: Notes: KENAI DEEP UNIT 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MMec hanicall Integrityy Tes t jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Notes: Notes: Form 10-426 (Revised 01/2017)2022-0418_MIT_KDU-01 9 9 9 9 9 MEU -5HJJ %%/3XPSHGUHYLVHGWRVKRZEEOVLQVWHDGRIJDOORQVMEU 999 04/18/22 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 1/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KDU 01 (PTD 167-045) Perf 11/27/2021 Please include current contact information if different from above. 37' (6HW Received By: 01/12/2022 By Abby Bell at 12:35 pm, Jan 11, 2022 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 1/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KDU 01 (PTD 167-045) Jet Cut 10/22/2021 Please include current contact information if different from above. 37' (6HW Received By: 01/12/2022 By Abby Bell at 12:35 pm, Jan 11, 2022 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 12/28/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KDU 01 (PTD 167-045) TTBP Cement 11/18/2021 Please include current contact information if different from above. 37' (6HW Received By: 12/29/2021 By Abby Bell at 8:56 am, Dec 29, 2021 2SHUDWLRQV $EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 3XOO7XELQJ 2SHUDWLRQVVKXWGRZQ 3HUIRUPHG 6XVSHQG 3HUIRUDWH 2WKHU6WLPXODWH $OWHU&DVLQJ &KDQJH$SSURYHG3URJUDP 3OXJIRU5HGULOO 3HUIRUDWH1HZ3RRO 5HSDLU:HOO 5HHQWHU6XVS:HOO 2WKHU12SHUDWLRQV 'HYHORSPHQW ([SORUDWRU\ 6WUDWLJUDSKLF 6HUYLFH $3,1XPEHU 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,ĞůĚW:^D͕KƉĞŶǁĞůů;ǁĞůůŽŶǀĂĐƵƵŵͿƉƵŵƉϱďďůƐϴ͘ϰƉƉŐĨůƵŝĚĚŽǁŶƚďŐ͘ŽŶƚŝŶƵĞƉŽŽŚůĂǇŝŶŐĚŽǁŶϮͲϳͬϴΗϲ͘ϱη͕h >ϴϬƚďŐĨͬϮ͕ϬϮϮĨƚ͘ƚŽƐƵƌĨĂĐĞ͕ůĂǇĚŽǁŶƉĂĐŬĞƌΘƚĂŝůƉŝƉĞ͕ZŝŐĚŽǁŶůĂǇĚŽǁŶŵĂĐŚŝŶĞ͘ZŝŐƵƉƐŚŽŽƚŶŝƉƉůĞĨůĂŶŐĞŽŶ ĂŶŶƵůĂƌ͕ƌŝŐƵƉ<ůŝŶĞ͕ƌŝŐƵƉůƵďƌŝĐĂƚŽƌĂŶĚϳΗ/WŽŶƚŽŽůƐ͕WͬƚůƵďƌŝĐĂƚŽƌƚŽϱϬϬƉƐŝ͘Z/,ǁŝƚŚ>ĞŐĂĐǇϱ͘ϲϭϬΗKŝŐŽǇ ƌŝĚŐĞƉůƵŐƐƵŝƚĂďůĞĨŽƌϲͲϱͬϴΗϭϳͲϮϮĂŶĚϳΗϭϳͲϯϱWW&ĐĂƐŝŶŐdĞƐƚĞĚƚŽϭϬ͕ϬϬϬƉƐŝĂƚϯϮϱĚĞŐ&>ŽƚηϴϳϭϵϳƉĂƌƚEŽ͘ϬϬϬͲ ϱϲϭϬͲϬϬϮƚŽϴ͕ϵϲϬĨƚ͘ZƵŶĐŽƌƌĞůĂƚŝŽŶƉĂƐƐƵƉƚŽϴ͕ϯϬϬĨƚ͘ĚƌŽƉďĂĐŬĚŽǁŶƚŽϴ͕ϵϯϬĨƚ͘ƐĞƚ/WƚŽƉĂƚϴ͕ϵϯϬĨƚ͘&ŝůůŚŽůĞ ǁŝƚŚϱϰďďůƐϴ͘ϰƉƉŐǁĂƚĞƌ͕ƉŽŽŚǁŝƚŚŶŽƉƌŽďůĞŵƐ͕ůĂǇĚŽǁŶůƵďƌŝĐĂƚŽƌ͘DĂŬĞƵƉϱΗǆϯϬĨƚ͘ĚƵŵƉďĂŝůĞƌ͕DŝǆĂŶĚĨŝůůďĂŝůĞƌ ǁŝƚŚϮϳ͘ϰϰŐĂůůŽŶƐEĞŽĐŵƚƐůƵƌƌǇŬŝƚDŝǆĞĚĂƚϭϳ͘ϬƉƉŐ͕Z/,ǁŝƚŚƐĂŵĞƚĂŐŐŝŶŐ/WĂƚϴ͕ϵϯϬĨƚ͘>D͕ĚƵŵƉĐŵƚŽŶƚŽƉŽĨ /WĂƚϴ͕ϵϯϬ͕ƉŽŽŚ͕ŵŝǆĂŶĚĨŝůůĂŝůĞƌǁŝƚŚϮϳ͘ϰϰŐĂůůŽŶƐŽĨEĞŽ^ůƵƌƌǇŬŝƚ͕DŝǆĞĚĂƚϭϳ͘ϬƉƉŐ͕Z/,ĚƵŵƉŝŶŐĐŵƚŽŶƚŽƉŽĨ /WĨŽƌdŽƚĂůϱϰ͘ϴϴŐĂůůŽŶƐĐŵƚϯϱĨƚ͘ŽĨĨŝůůƚŽƚĂů^d͘ƚŽƉŽĨĐŵƚϴ͕ϴϵϱĨƚ͘WŽŽŚŶŽƉƌŽďůĞŵƐ͘ZŝŐƵƉĂŶĚƚĞƐƚ/WĂƚϴ͕ϵϯϬ ΖĂŶĚϯϱĨƚ͘ĐŵƚĨŝůů^dƚŽƉŽĨĐŵƚĂƚϴ͕ϴϵϱΖΘϳΗϮϵηůŝŶĞƌĂŶĚϵͲϱͬϴΗϰϬηĐƐŐƚŽϭ͕ϳϬϬƉƐŝĨŽƌϯϬŵŝŶƵƚĞƐŽŶĐŚĂƌƚ;ŐŽŽĚ 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ĂƚϲϯŬ͕ĐŽŶƚŝŶƵĞƉŝĐŬŝŶŐƵƉŽŶ&,,ǇĚƌĂƵůŝĐZĞƚƌŝĞǀĂďůĞƉĂĐŬĞƌ͕ƉĂĐŬĞƌĐĂŵĞĨƌĞĞĂƚϳϱŬ͕ůĞƚƉĂĐŬĞƌƌĞůĂǆ͕ĐŽŶƚŝŶƵĞƉŝĐŬŝŶŐ ƵƉŚĂŶŐĞƌĂďŽǀĞƚŚĞĨůŽŽƌ͕ůĂǇŽƵƚŚĂŶŐĞƌƉƵƉƐĂŶĚůĂŶĚŝŶŐũŽŝŶƚ͘ƵůůŚĞĂĚĞĚϲϬďďůƐϴ͘ϰƉƉŐǁĂƚĞƌĚŽǁŶƚďŐĂƚϮďƉŵ ƉƌĞƐƐƵƌĞƵƉƚŽϮϬϬƉƐŝĂƚϱϯďďůƐƉƵŵƉĞĚ͕ƐŚƵƚĚŽǁŶƉƵŵƉƉƌĞƐƐƵƌĞďůĞĞĚƚŽΗϬΗŝŶϭŵŝŶƵƚĞ͘,ĞůĚW:^DǁŝƚŚĐƌĞǁƐ͕ WŽŽŚůĂǇŝŶŐĚŽǁŶϮͲϳͬϴΗϲ͘ϱη>ͲϴϬ͕hƉƌŽĚƵĐƚŝŽŶƚďŐĂŶĚůŽĂĚŝŶŐŽƵƚŽŶƚƌĂŝůĞƌƐĨƌŽŵϵ͕ϬϯϰĨƚ͘ŽǀĞƌƐŚŽƚĚĞƉƚŚƚŽϲ͕ϰϲϮΖ ƉŝĐŬƵƉǁƚ͘ϰϲŬƐͬŽǁƚ͘ϯϴŬ͘tŽƌŬŝŶŐŽŶtŝƌŝŶŐĨŽƌ,ǇĚƌĂƵůŝĐĐŽŽůŝŶŐĨĂŶŽŶƚŚĞƐŬĂƚĞ͕ĐŚĂŶŐĞŽƵƚ,ǇĚƌĂƵůŝĐŚŽƐĞŽŶƐŬĂƚĞ ƉŝƉĞĨůŝƉĂƌŵĂŶĚƚŚĞƉŽǁĞƌƚŽŶŐƐ͘ŽŶƚŝŶƵĞƉŽŽŚůĂǇŝŶŐĚŽǁŶϮͲ ϳͬϴƉƌŽĚƵĐƚŝŽŶƚďŐĨͬϲ͕ϰϴϮΖƚŽϮ͕ϬϮϮΖ͕^ĞĐƵƌĞǁĞůůĨŽƌ ŶŝŐŚƚ͘ dĞƐƚƵƉƉĞƌϰͲϭͬϮΗǆϳΗsZΖƐǁŝƚŚϱͲϭͬϮΗƚĞƐƚũ ůĂǇĚŽǁŶƉĂĐŬĞƌΘƚĂŝůƉŝƉĞ͕ WŝĐŬƵƉ>ĂŶĚZ/,ƚŽϰ͕ϴϬϬΖƚŽƉŽĨůŝŶĞƌůŽŐŐŝŶŐƵƉĨͬϰ͕ϴϳϬĨƚ͘ƐƵƌĨĂĐĞĨ ^d͘ƚŽƉŽĨĐŵƚϴ͕ϴϵϱĨ WŽŽŚůĂǇŝŶŐĚŽǁŶϮͲϳͬϴΗϲ͘ϱη>ͲϴϬ͕hƉƌŽĚƵĐƚŝŽŶƚďŐ ZŝŐƵƉƐŚŽŽƚŶŝƉƉůĞĨůĂŶŐĞŽŶ ĂŶŶƵůĂƌ͕ƌŝŐƵƉ<ůŝŶĞ͕ƌŝŐƵƉůƵďƌŝĐĂƚŽƌĂ ŽŶƚŝŶƵĞƉŽŽŚůĂǇŝŶŐĚŽǁŶϮͲϳͬϴƉƌŽĚƵĐƚŝŽŶƚďŐĨͬϲ͕ϰϴϮΖƚŽϮ͕ϬϮϮΖ͕^ĞĐƵƌĞǁĞůůĨŽƌ ŶŝŐŚƚ͘ Est TOC at 1190' MD - bjm. 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ƉƵŵƉŝŶƐƵďŽŶtͬ>ĞƋƵŝƉŵĞŶƚ͘DĂŶͲůŝĨƚĂƌƌŝǀĞƐ͕ƌĞŵŽǀĞĚƚƌĞĞĐĂƉ͕ƐƚĂďŽŶůƵď͘ƉͬƚƚŽϮ͕ϬϬϬƉƐŝĨĂŝů͕ĐͬŽKͲZŝŶŐƚĞƐƚ ĂŐĂŝŶ͕ŐŽŽĚƚĞƐƚ͘Z/,ǁͬϮ͘ϴϲΗŐͲƌŝŶŐƚŽϴ͕ϳϯϲΖƐůŵϴ͕ϳϱϭŬďƚĂŐ͕WKK,͘Z/,ǁͬƐƉŝŶŶĞƌΘƉͬƚƐƵƌǀĞǇƚŽŽůƐ͕ϭϬϬĨƉŵƚŽ ϴ͕ϳϬϭΖ͕ƐƚĂƌƚĞĚƉƵŵƉŝŶŐĐŽůĚǁĂƚĞƌĨƌŽŵǁĂƚĞƌǁĞůůĂƚϯWD͕ƚƵďŝŶŐƉƌĞƐƐƵƌĞĚƌŽƉƉĞĚĨƌŽŵϯϲϳƉƐŝƚŽϭϬϬƉƐŝŝŶϭϱŵŝŶ ;ŚŽůĞĨŝůůĂƚΕϰϱďďůƐƉƵŵƉĞĚͿ͕ƉƌĞƐƐƵƌĞĐůŝŵďĞĚƚŽϳϬϬƉƐŝ͕ĚƌŽƉƉĞĚĂŶĚŐƌĂĚƵĂůůǇďƵŝůƚƚŽΕϯϱϬƉƐŝ͘>ŽŐŐĞĚƵƉĂŶĚŵĂĚĞ ϱŵŝŶƐƚŽƉƐĂƚϰϵϳϬ͕ϰϳϲϬ͕ϰϱϰϬǁŚŝůĞƉƵŵƉŝŶŐϭϱϬďďůƐ͘WƵŵƉĞĚĂŶŽƚŚĞƌϲϭ͘ϳďďůƐƚŽĐŽǀĞƌƉƵŵƉŝŶŐǁŚŝůĞĂƚĨŝŶĂů ƐƚŽƉƐ͘ŽŶƚŝŶƵĞĚůŽŐŐŝŶŐƚŽϰ͕ϬϬϬΖ͘&ƌĞĞǌĞƉƌŽƚĞĐƚĞĚƚƵďŝŶŐǁŝƚŚϰďďůƐDĞK,͘ZWƵŵƉƚƌƵĐŬ͘^ůŝĐŬůŝŶĞŵĂĚĞϭϱŵŝŶ ƐƚŽƉĂƚϰϬϬϬΖ͘ůŽŐƚŽϴ͕ϳϬϭΖϯƚŝŵĞƐǁŝƚŚϭŚƌƐƚŽƉƐŽŶďŽƚƚŽŵĂŶĚϯŵŝŶƐƚŽƉƐĂƚϰ͕ϬϬϬΖ͘ ϭϬͬϭϱͬϮϬϮϭͲ&ƌŝĚĂǇ ƌƌŝǀĞΛ<'&͕ŵĞĞƚǁŝƚŚŶĚǇĨŝůůŽƵƚ:^͘WƵ>Ƶď͕^ƚĂďŽŶZŝƐĞƌ͘Z/,ǁϭͲϯͬϴΗK^ǁͬϰ͘ϱΗĞůůŐƵŝĚĞƚŽϰ͕ϴϲϱΖ^>DƐŝƚǁŝƚŚ ƚŽŽůƚĂƉĚŽǁŶϯƚŝŵĞƐ͕WKK,͘Z/,ǁͬ^ĂŵĞƚŽϴ͕ϳϯϮΖ^>D͕^/dǁͬƚŽŽů͕WKK,ϮϬϬηŽǀĞƌƉƵůů͘WKK,ƚŽϲ͕ϵϲϲ^>DŚƵŶŐƵƉ ǁƚŽŽů͘dŽŽůƐĨƌĞĞ͘WKK,ŵĞƚĂůŵĂƌŬƐŽŶďĞůůŐƵŝĚĞ͘Z/,ǁͬƐĂŵĞǁͬϰͬϱΗĐĞŶƚ͘ƚŽϴ͕ϳϯϰΖ^>DǁͬƚŽŽůƚŽϴ͕ϳϯϴΖ^>D͘ WKK,͕ŚƵŶŐƵƉĂƚϴ͕ϲϲϲǁͬƚŽŽůƚŚƌƵΛϴϰϭϯ͕ϴϮϬϰ͕ϳϵϬϵ͕ϳϳϴϰ͕ϳϯϯϲ͕ϳϭϮϳ͕ŝŶŵƵůƚŝƉůĞƐƉŽƚƐ͘WKK,͕>ŽƐƚϰ͘ϱΗďĞůůŐƵŝĚĞ ΛĐŽŶƚƌŽů͘K^ƚŚƌĞĂĚƐĚƵůůĞĚΘŵƵƐŚƌŽŽŵĞĚ͕ƐƚĂŶĚďǇĨŽƌŵĂŐŶĞƚ͘Z/,ǁͬϯ͘ϴΗĐĞŶƚ͘ǁͬϯΖƐƚĞŵ͕ϰ͘ϱĐĞŶƚ͕ϯ͘ϳΗ>/ƚŽϰϰϭϭΖ ^>Dϰ͕ϰϮϲ<͕^/dǁƚŽŽů͕WKK,ŵƉƚǇ͘>ĂǇĚŽǁŶůƵďĨŽƌŶŝŐŚƚ͕ƐĞĐƵƌĞǁĞůů͕ƚƵƌŶŝŶƉĞƌŵŝƚ͘ ϭϬͬϭϲͬϮϬϮϭͲ^ĂƚƵƌĚĂǇ ƌƌŝǀĞŽŶůŽĐĂƚŝŽŶũƐĂƉĞƌŵŝƚ͘ƵƚǁŝƌĞƌĞͲŚĞĂĚĐŚĞĐŬƚŽŽůƐƚƌŝŶŐƉͬƵůϰď͘^ƚĂďŽŶ͕Z/,ǁͬϯ͘ϴϱΖΖĐĞŶƚ͘ϮΖƐƚĞŵϰ͘ϱΖΖĐĞŶƚ͘ ϯ͘ϴϱΖΖůŝďƚŽϰϰϭϭΖƐůŵϰϰϮϲΖŬďŚŝƚϭƚŝŵĞƉŽŽŚǁͬŝŵƉƌĞƐƐŝŽŶŽĨďĞůůŐƵŝĚĞŽŶŝƚƐƐŝĚĞ͘Z/,ǁͬϮΖƐƚĞŵǁͬϰΖΖďůŝŶĚďŽǆƚŽ ϰϰϭϭΖƐůŵďĞĂƚĚŽǁŶϮϬƚŝŵĞƐĚŝĚŶŽƚĨĂůůƉŽŽŚĐŚĞĐŬƚŽŽůƐ͘Z/,ǁͬϰ͘ϱΖΖĐĞŶƚ͘ϮΖƐƚĞŵϰΖΖďďƚŽƐĂŵĞǁͬƚŽŽůϯϬƚŝŵĞƐĨĞůů ƚŚƌƵĐŽŶƚ͘ƚŽϰϰϮϬΖƐůŵƚĂŐƉŽŽŚ͘Z/,ǁͬϰ͘ϱΖΖĐĞŶƚϮΖƐƚĞŵϯ͘ϳΖΖŵĂŐŶĞƚƚŽϰϰϮϬΖƐůŵƐŝƚǁͬƚŽŽůƉŽŽŚĞŵƉƚǇ͘Z/,ǁͬϰ͘ϱΖΖ ĐĞŶƚ͘ϮΖƐƚĞŵϰΖΖďďƚŽƐĂŵĞǁͬƚŽŽůϰϰϮϮΖƐůŵǁͬƚŽŽůǁŽƵůĚŶŽƚĨĂůůƉŽŽŚ͘Z/,ǁͬϯ͘ϴϱΖΖĐĞŶƚ͘ϮΖƐƚĞŵϰ͘ϱΖΖĐĞŶƚ͘ϯ͘ϴϱΖΖůŝďƚŽ ϰϰϮϮŚŝƚϭƚŝŵĞƉŽŽŚǁͬŝŵƉƌĞƐƐŝŽŶŽĨĨůĂƚƚĞŶĞĚďĞůůŐƵŝĚĞǁͬďƌĂƐƐǁŝƌĞƐŝŵďĞĚĚĞĚŝŶůĞĚĐĂůůƐƵƉ͘ĂůůŚĂĚ:ŽŚŶƐŽŶ͘Z/, ǁͬϰ͘ϱΖΖĐĞŶƚ͘ϮΖƐƚĞŵϰΖΖďůŝŶĚďŽǆƚŽϰϰϮϮΖƐůŵϰϰϯϳΖŬďǁͬƚŽŽůĚŝĚŶŽƚĨĂůůƉŽŽŚ͘ZDK͘ ϭϬͬϭϰͬϮϬϮϭͲdŚƵƌƐĚĂǇ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ZŝŐϰϬϭͬ^> ͬ>ϴͬϮϭͬϮϭ ϭϭͬϮϳͬϮϭ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hͲϬϭ ϱϬͲϭϯϯͲϮϬϬϯϱͲϬϬͲϬϬ ϭϲϳͲϬϰϱ ϭϭͬϮϯͬϮϭͲdƵĞƐĚĂǇ Wdt͕:^ǁŝƚŚĐƌĞǁƐ͘D/Zh&ŽǆĞŶĞƌŐǇdhϴǁŝƚŚϭ͘ϳϱΗĐŽŝů͘Ϯϰ,ƌ͘KWƚĞƐƚǁŝƚŶĞƐƐŶŽƚŝĨŝĐĂƚŝŽŶƐĞŶƚƚŽƐƚĂƚĞ͘tŝƚŶĞƐƐ ǁĂŝǀĞĚďǇ:ŝŵZĞŐŐ͘dĞƐƚKWĞƋƵŝƉŵĞŶƚƚŽϮϱϬͬϮϱϬϬƉƐŝ͘ZŝŐƵƉŚŽƚŽŝůƚƌƵĐŬĂŶĚůŽĂĚǁĞůůďŽƌĞǁŝƚŚϲϬďďůƐĨůƵŝĚ͘ ^&E͘ ϭϭͬϮϬͬϮϭͲ^ĂƚƵƌĚĂǇ DĂŬĞŽƵƚƉĞƌŵŝƚƐĂŶĚ:^͘tĂƌŵŝŶŐƵƉĞƋƵŝƉŵĞŶƚWdKǁŝůůŶŽƚƐƚĂǇĞŶŐĂŐĞĚŵŽǀĞŚĞĂƚĞƌΘŚĞĂƚƵŶĚĞƌt>ƚƌƵĐŬ͘ ŽŶƚŝŶƵĞƚŽƌŝŐƵƉƋƵŝƉŵĞŶƚǁŚŝůĞƚƌƵĐŬŚĞĂƚƐƵƉ͘DŝǆŝŶŐĐŵƚĂŶĚůŽĂĚϰΗǆϯϬΖĚƵŵƉďĂŝůĞƌǁŝƚŚϭϱŐĂůůŽŶƐŽĨϭϳƉƉŐŽĨ EĞŽƐƵƉĞƌƐůƵƌƌǇ͕ŽƉĞŶǁĞůů^/dWϲϬϬW^/͘Z/,ǁŝƚŚƌƵŶηϭ͕ůŝŐŚƚůǇƚĂŐƉůƵŐ;ƚŽƉŽĨƚƵďĞͿĂƚϰϲϭϬĨƚ͘ǁŝƚŚϮϬůďƐŽĨǁƚ͘ƉŝĐŬ ƵƉĂŶĚĚƵŵƉĐŵƚ͘ƉŽŽŚǁŝƚŚďĂŝůĞƌ͘ŽŶƚŝŶƵĞƚŽŵĂŬĞ;ϰͿĚƵŵƉďĂŝůĞƌƌƵŶƐǁŝƚŚϭϱŐĂůůŽŶƐĞĂĐŚŽĨEĞŽƐƵƉĞƌƐůƵƌƌǇ ŵŝǆĞĚĂƚϭϳ͘ϬƉƉŐ͕ĚƵŵƉĞĚĂƚŽƚĂůŽĨϴϬŐĂůůŽŶƐŽĨĐŵƚŽŶƚŽƉŽĨƉůƵŐƐĞƚĂƚϰϲϮϬ>D͘ƐƚƚŽƉŽĨĐŵƚϰϱϵϱĨƚ͘>D͘EŽƚĞ ĨůƵŝĚĂƚϮϱϯϴĨƚ͘KK,ƐĞĐƵƌĞǁĞůůĂŶĚƌŝŐĚŽǁŶͲůŝŶĞ͕ŵŽǀĞŽƵƚĞƋƵŝƉŵĞŶƚ͘ &ŝůůŽƵƚƉĞƌŵŝƚƐĂŶĚ:^ĂƚŽĨĨŝĐĞ͕ƐƉŽƚĞƋƵŝƉŵĞŶƚĂƚǁĞůů͘ŽŶƚŝŶƵĞƚŽƌŝŐƵƉůĂƐŬĂͲůŝŶĞĞƋƵŝƉŵĞŶƚĂŶĚůƵďƌŝĐĂƚŽƌ͘DĂŬĞ ƵƉEĞŽdŚƌƵƚďŐďƌŝĚŐĞƉůƵŐǁŝƚŚĂƌƵŶŶŝŶŐĚŝĂŽĨϮΗǆϭϳϲΗ͕ƐƚĂďůƵďƌŝĐĂƚŽƌĂŶĚƚĞƐƚƐĂŵĞƚŽϮϱϬůŽǁĂŶĚϮϱϬϬƉƐŝŚŝŐŚ͘; ŐŽŽĚƚĞƐƚͿ͘KƉĞŶǁĞůůŚĂĚϲϬϬƉƐŝ^/dW͕ZŝŚǁŝƚŚdͲdWƚŽϰϳϱϬĨƚ͘>DƌƵŶĐŽƌƌĞůĂƚŝŽŶƉĂƐƐĨƌŽŵϰϳϱϬĨƚ͘>DƚŽϰϰϳϲĨƚ͘ >DƐĞŶĚůŽŐŝŶĨŽƌĞůĞǀĂƚŝŽŶ͕ƌĞƌƵŶĐŽƌƌĞůĂƚŝŽŶůŽŐĨƌŽŵϰϳϱϬĨƚ͘>DƚŽϰϯϱϲĨƚ͘>DƚŽƚŝĞƚďŐĚĞƚĂŝůŝŶǁŝƚŚĐŽƌƌĞůĂƚŝŽŶ ůŽŐ͘^ĞŶĚůŽŐŝŶĨŽƌůĞǀĂƚŝŽŶ͕;ůŽŐŽŶĚĞƉƚŚͿƐĞƚdͲdWĂƚϰϲϮϬĨƚ͘>D͕ůŽƐƚϴůďƐ͘ǁƚ͘ǁŚĞŶƐĞƚƚŝŶŐdͲdW͕ŚĂĚ;ϯͿϮϱůď͘ ŽǀĞƌƉƵůůǁŚŝůĞƉƵůůŝŶŐŽĨĨdͲdW͕WKK,͘>ĂǇĚŽǁŶdͲdWŚŽƵƐŝŶŐĂŶĚŵĂŬĞƵƉϰΗǆϭϬΖďĂŝůĞƌ͕ůŽĂĚďĂŝůĞƌǁŝƚŚϯŐĂůůŽŶƐŽĨ ĐĞƌĂŵŝĐďƌŝĚŐŝŶŐŵĂƚĞƌŝĂů͕ŽƉĞŶǁĞůů͕ϲϬϬƉƐŝŽŶ^/dW͕Z/,ǁŝƚŚƐĂŵĞƚĂŐŐŝŶŐƉůƵŐ;ƚŽƉŽĨdƵďĞͿĂƚϰϲϬϴĨƚ͘>D͕ĚƵŵƉ ďĂŝůĞƌůŽƐƚϳůďƐ͘ŽĨǁƚ͘ǁŚĞŶĚƵŵƉďƌŝĚŐŝŶŐŵĂƚĞƌŝĂů͕ƉŽŽŚǁŝƚŚďĂŝůĞƌ͕ŶŽƚĞĨůƵŝĚůĞǀĞůĂƚϮϰϯϳĨƚ͘>D͘ZĞĚƌĞƐƐďĂŝůĞƌΘ ůŽĂĚƐĂŵĞǁŝƚŚϱŐĂůůŽŶƐŽĨEĞŽƐƵƉĞƌĐŵƚƐůƵƌƌǇƐǇƐƚĞŵŵŝǆĞĚĂƚϭϳ͘ϬƉƉŐ͘ZŝŚƚŽϰϱϵϮĨƚ͘>D͕ĚŝĚŶŽƚŚĂǀĞĂĐĂƉďƌĞĂŬ͕ ƉŽŽŚĐŵƚĚŝĚŶŽƚĚƵŵƉ͕ůĂǇĚŽǁŶďĂŝůĞƌĂŶĚƚƌŽƵďůĞƐŚŽŽƚƐĂŵĞ͘&ŽƵŶĚƐŚŽƌƚĞĚŽƵƚǁŝƌĞŝŶďĂŝůĞƌ͕ƌĞůŽĂĚďĂŝůĞƌǁŝƚŚϱ 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August 4, 2021 3:45 PM To:Jake Flora - (C) Cc:Taylor Wellman; Aras Worthington; Donna Ambruz; Chmielowski, Jessie L C (CED); Regg, James B (CED); Salazar, Grace (CED); Carlisle, Samantha J (CED) Subject:RE: KDU-01 (10-403 321-307) (PTD 167-045) - Docket OTH-21-028 Jake, This request was assigned AOGCC Docket OTH‐21‐028. Thank you for the supporting documentation in your below email. In response, the AOGCC approves Hilcorp’s request to complete KDU‐01 gas storage injector without a SSSV or injection valve installed, as allowed in 20 AAC 25.265(d)(5). The justification is mainly because of the low reservoir pressure, restricted public access and distance from buildings, roads, coastline, navigable waters, etc… The other points listed in the below email are common to many gas injection wells and did not influence the decision. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Jake Flora ‐ (C) <Jake.Flora@hilcorp.com> Sent: Monday, August 2, 2021 1:45 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Cc: Taylor Wellman <twellman@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com> Subject: KDU‐01 (10‐403 321‐307) (PTD 167‐045) Mr. McLellan, Hilcorp Alaska’s Kenai Onshore Team respectfully requests an additional review of the recent SSSV requirement placed on the KDU‐01 Pool 6 Gas Storage Well. The onshore dry gas fields of the Cook Inlet Basin are different in many ways to the much larger number of AOGCC regulated wells of the North Slope. It is a reasonable view that the language in 20 AAC 25.265(d)(5) requiring subsurface safety valves for gas‐only injection wells is speaking directly to the high pressure and high deliverability wells of Prudhoe Bay (AGI, LGI, WGI) and not the seasonal gas storage wellbores of the low pressure Pool 6 at Kenai Gas Field(KGF) or the limited reservoir gas storage wells at Swanson Gas Field. The final sentence of the rule appears to directly address gas storage wells that cycle between injection and production, allowing a case by case look in this exact scenario. Currently (3) Pool 6 producer/injector wellbores exist at KGF playing a critical role in managing peak demand, providing back‐up production when offshore platforms go down, and during the shoulder months we commonly produce and 2 inject in a single day. Installing a SSSV in a Pool 6 storage well directly impedes the ability (and need) to instantaneously manage the gas flow to and from the reservoir. Operationally, the wellbores have a history of sand production and fill issues that are commonly addressed by slickline bailing as the low BHP will not support a fill cleanout. Sand and slickline operations make operating a TRSSSV problematic, especially given the high frequency it would have to be used. Much worse, after it would eventually malfunction there is no quick fix as our workover rig is run across campaigns, often avoiding the coldest months of the year. We believe the below facts and conditions make a case for a variance: 1. The well will have a tested SSV 2. Passing MITIA 3. Extremely low BHP (current BHP is 170 psi, it was down to 140 psi this spring) a. Max allowable Pool 6 BHP = 400 psi (360 psi surface pressure). b. Easily killed by water 4. Satisfies all buffer requirements as detailed in 20 AAC 25.265(d)(2)(A‐H) 5. Mechanically there is zero difference between a dry gas producer like the majority of our wells and a Pool 6 gas producer/injector 6. No public access, the well pad is gated 7. There are no current Pool 6 wells with subsurface safety valves 8. Recent (2020) KGSF 1A storage well did not require a SSSV 20 AAC 25.265(d)(5) (5) gas-only injection wells must be equipped with either a subsurface safety valve as stated in this subsection, or an injection valve capable of preventing back flow; the commission will address wells cycling between gas storage injection and production on a case-by-case basis. Please advise if there is additional information the AOGCC would like to see regarding this concern. Additionally, we would appreciate the opportunity to discuss Storage Well SSSVs in person should the conversation be warranted. Sincerely, Jake Flora Jake Flora | Kenai Ops Engineer | Hilcorp Alaska | 720‐988‐5375 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. 1Guhl, Meredith D (OGC)From:McLellan, Bryan J (OGC)Sent:Thursday, December 2, 2021 1:02 PMTo:Jacob FloraSubject:RE: KDU-01 (PTD 167-045) MITIA clarificationJake, You don’t need to do the second MITIA until you’ve converted the well to an injector, per Rule 3 of SIO 7A. Thanks for checking. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Thursday, December 2, 2021 9:30 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: KDU‐01 (PTD 167‐045) MITIA clarification Hi Bryan, We plugged back the lower C2 sand that was wet and shot the upper C1 sand and found it to be normal Pool 6 pressure. So far it looks like a good Pool 6 well and is currently producing. In the Sundry there is a 1500 psi MITIA that needs to occur after the well is on stable injection. We did do a 30 minute MITIA after setting the packer that passed. How would you like us to handle the witnessed MITIA in the sundry? We currently have an orifice valve in the GLM above the packer that was put in place to blow water off the well if it ever loaded up. The well won’t be on stable injection till the spring. Thanks in advance for the direction, I’ve added screen shots below of the sundry COA and the Ops summary. 2 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, November 24, 2021 10:00 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: [EXTERNAL] RE: KDU‐01 (PTD 167‐045) Sterling Pool 6 UPDATE & BOP test pressure clarification Jake, Yes, the 2500 psi CT BOP test is acceptable. The CT BOP test pressure to 2500 psi, which I wrote on the Sundry conditions of approval, is the minimum pressure required by the AOGCC. If you want to test higher, that is fine also. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 3 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Wednesday, November 24, 2021 7:54 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: KDU‐01 (PTD 167‐045) Sterling Pool 6 UPDATE & BOP test pressure clarification Hello Bryan, We set the plug over the C2 storage perfs, and now are in the process of getting an MIT on the plug prior to coil tubing jetting the well dry ahead of perforating the C1 sand. We are currently working off of the approved sundry 321‐307 and the below approval in this email to set the plug. Per sundry 2500 psi is written in the COA as the approved test pressure. I had 4000 psi written in the Coil Tubing Contingency language of the sundry which was a cut and paste error. Is the 2500 psi acceptable? The MASP for the C1 is expected less than 200 psi, the C2 we just plugged back was essentially dead (wet). Thanks, Jake From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Thursday, October 21, 2021 12:24 PM To: Jacob Flora <Jake.Flora@hilcorp.com>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Cc: Aras Worthington <Aras.Worthington@hilcorp.com>; Roby, David S (CED) <dave.roby@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Chris Kanyer <ckanyer@hilcorp.com>; Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Subject: [EXTERNAL] RE: KDU‐01 Sterling Pool 6 UPDATE (10/15/21 temp/spinner logs) Jake, You have approval to proceed with your plan below. Be sure to also complete the condition on the approved Sundry 321‐307, which requires an MITA of 1500 psi after stable injection conditions have been established. Provide AOGCC opportunity to witness this MIT. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 4From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Wednesday, October 20, 2021 12:49 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Cc: Aras Worthington <Aras.Worthington@hilcorp.com>; Roby, David S (CED) <dave.roby@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Chris Kanyer <ckanyer@hilcorp.com>; Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Subject: KDU‐01 Sterling Pool 6 UPDATE (10/15/21 temp/spinner logs) Bryan, Attached is an updated log presentation of the spinner and temp logs with the passes labeled. As discussed on the phone yesterday both spinner and temperature indicate all the fluid is entering through the C2 perforations, and no temperature anomaly or indication of a channel below this point. Also as mentioned we have the memory spinner and slickline bell guide lodged in the tubing tail. We request permission to proceed with the following steps: 1. Jet cut the tubing tail 2. Set a through tubing plug over the C2 perforations with 25’ cement on top 3. MIT the plug to 1200 psi after the cement has hardened. I estimate the C2 BHP at 850 psi based on the WHP of 382 psi + the HP with the fluid level at 3642’. 4. RU coil tubing and jet the wellbore dry with Nitrogen (this contingency already exists in the open sundry 321‐307) 5. Perforate and test the C1 within the currently approved interval Let me know if you need more information for this request, Thanks, Jake From: Jacob Flora Sent: Tuesday, October 19, 2021 11:33 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com> Cc: Aras Worthington <Aras.Worthington@hilcorp.com>; Roby, David S (CED) <dave.roby@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov>; Dan Marlowe (dmarlowe@hilcorp.com) <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Chris Kanyer <ckanyer@hilcorp.com> Subject: KDU‐01 Sterling Pool 6 UPDATE Bryan, 5Friday (10/18) we performed a memory LDL with slickline to gain a better understanding of what is happening downhole. Fluid level prior to pumping: 3762’ (380 psi HP + 550 psi WHP = 929 psi BHP) 10/15/2021 Logging Summary: We logged a baseline to TD above the 7” CIBP, pumped 150 bbls of cold water into the well, and logged up while pumping 3 bpm looking for both temperature and spinner response. We then continued pumping at 3bpm, and obtained stop counts above and below the perforations, followed by 1hr and 2hr static warm‐back passes. The data is attached and shows no temperature anomaly below the open Sterling C2 perforations. On the final pass POOH we got to surface and found the spinner assembly to be missing (unthreaded from the Spartek gauge housing). A fishing attempt the next day then lodged the spinner in the tubing tail and then dropped a bell guide on top of it. We now believe we are in communication with the C2 sand and that this log rules out a channel down or upward. A look at the 9‐22‐1967 sonic porosity log shows the zone to be much lower quality (4‐6% sonic porosity) rock that the larger C1 above it with 16%. I think there’s a strong case here that we are in an isolated portion of the C2 and that the logs support this. Our plan forward is to use e‐line to log a CCL off the tubing tail fish, ensure we can get a jet cutter below the packer, and then jet cut and drop the 5‐1/2” tubing tail. Followed by setting a through tubing umbrella plug over the C2 perfs, dump bailing cement on the plug, waiting on cement, then using coil tubing to unload the water prior to perforating the C1. I’ll call you this afternoon to discuss the plan forward, Thanks, Jake Below are the two logging summaries, and subsequent fishing rig ups: Oct 8 2021 ENGINEER: Jake Flora FIELD SUPERVISOR: Cole Bartlewski FW: 0.0 PRESENT OPERATIONS: MIRU YJES, Production profile log. Static log and Log after pumping 170 bbls of 190*F water with hot oil truck. PTW, JSA. Spot Equipment. United Rentals man lift on location.;RIg up E line unit. PT lubricator 250/3000 psi. RIH with 2 x 1 11/16" WB & 1 3/8" CCL/Tempt tool. Logged down to TD for static log. Tagged @ 7863'.;Wait for hot oil truck to finish MIT on KU 24-32. Parked on bottom for 4 hours before logging up.;Rig up hot oil truck and Cruz 170 bbl tanker truck. PT Pump line to Eline valve pump in sub. 250/3500 psi.;Start pumping down tubing at 1.4 bbls/min and heating fluid to 190*F. Waiting for a spike to see when we caught fluid level. No significant indication of catching fluid level. Pumped 170 bbls at 1.4 bbls/min with 365 being the highest pressure seen and 318 after breakover.;Starting Logging OOH from 8730' to surface. Rig down Hot oil truck and release Cruz Tanker truck.;Rig Down E-line unit and prep man lift to return to Beaver Creek for BCU-19 perforating. DAILY JOB COST: $12,183 TOTAL JOB COST: $439,798 6Oct 15 2021 ENGINEER: Jake Flora FIELD SUPERVISOR: Chad Helgeson FW: 0.0 PRESENT OPERATIONS: Slickline & Pumping operations Arrive at KGF meet with Andy, complete JSA/Permit. Rig Up slickline p/u lub., standby for manlift for tree 15ft in air. Hot Oil Truck arrived, RU to water well for pump supply water w/ 3" hose. Rig up pump discharge with 1" hose on truck to pump in sub on W/L equipment.;man-lift arrives, removed tree cap, stab on lub. p/t to 2,000 psi fail, c/o O-Ring test again, good test.;RIH w/ 2.86" g-ring to 8,736' slm 8,751kb tag, POOH;RIH w/ spinner & p/t survey tools, 100 fpm to 8,701', started pumping cold water from water well at 3 BPM, tubing pressure dropped from 367 psi to 100psi in 15 min (hole fill at ~45 bbls pumped), pressure climbed to 700 psi, dropped and gradually built to ~350 psi. Logged up and made 5 min stops at 4970, 4760, 4540 while pumping 150 bbls. Pumped another 61.7 bbls to cover pumping while at final stops.;Continued logging to 4,000'. Freeze protected tubing with 4 bbls MeOH. RD Pump truck. Slickline made 15 min stop at 4000'. log to 8,701' 3 times with 1hr stops on bottom and 3 min stops at 4,000'. OOH lost spinner and centralizer. Half of Gamma CCL in hole. lay down Lub. Secure well for night. DAILY JOB COST: $6,489 TOTAL JOB COST: $446,287 Oct 16 2021 ENGINEER: Jake Flora FIELD SUPERVISOR: Andy Graves FW: 0.0 PRESENT OPERATIONS: Fishing SL Tools Arrive @ KGF, meet with Andy fill out JSA, Pu Lub, Stab on Riser.;RIH w 1-3/8" OS w/ 4.5" Bell guide to 4,865' SLM sit with tool tap down 3 times, POOH. RIH w/ Same to 8,732' SLM, SIT w/ tool, POOH 200# overpull. POOH to 6,966 SLM hungup w tool. Tools free. POOH metal marks on bell guide. RIH w/ same w/ 4/5" cent. to 8,734' SLM w/ tool to 8,738' SLM. POOH, hung up at 8,666 w/ tool thru @ 8413, 8204, 7909, 7784, 7336, 7127, in multiple spots. POOH, Lost 4.5" bell guide @ control.;OS threads dulled & mushroomed, standby for magnet. RIH w/ 3.8" cent. w/ 3' stem, 4.5cent, 3.7" LIB to 4411' SLM 4,426 KB, SIT w tool, POOH Empty. Lay down lub for night, secure well, turn in permit. DAILY JOB COST: $0 TOTAL JOB COST: $446,287 Oct 17 2021 ENGINEER: Jake Flora FIELD SUPERVISOR: Andy Graves FW: 0.0 PRESENT OPERATIONS: Fishing SL Tools Arrive on location jsa permit, Cut wire re-head check tool string p/u l4b. Stab on, RIH w/ 3.85'' cent. 2' stem 4.5'' cent. 3.85'' lib to 4411'slm 4426'kb hit 1 time pooh w/ impression of bell guide on its side. RIH w/ 2' stem w/ 4'' blind box to 4411'slm beat down 20 times did not fall pooh check tools RIH w/ 4.5'' cent. 2' stem 4'' bb to same w/ tool 30 times fell thru cont. to 4420'slm tag pooh;RIH w/ 4.5'' cent 2' stem 3.7'' magnet to 4420'slm sit w/ tool pooh empty RIH w/ 4.5'' cent. 2' stem 4'' bb to same w/ tool 4422'slm w/ tool would not fall pooh RIH w/ 3.85'' cent. 2' stem 4.5'' cent. 3.85'' lib to 4422 hit 1 time pooh w/ impression of flattened bell guide w/ brass wires imbedded in led call sup. Call Chad Johnson RIH w/ 4.5'' cent. 2' stem 4'' blind box to 4422'slm 4437'kb w/ tool did not fall pooh RDMO 7 From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 12, 2021 10:45 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Taylor Wellman <twellman@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>; Roby, David S (CED) <dave.roby@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: [EXTERNAL] KDU‐01 Sterling Pool 6 gas storage Jake, I understood from our phone call yesterday that there is some question about the integrity of the seal in Gas Storage Pool 6 in KDU‐01 and that crossflow is occurring behind casing. Please submit information to the AOGCC explaining what you believe is occurring, supporting evidence, date when you first identified the problem, current status of the well, and your plan to immediately stop the crossflow, as required in SIO 7A rules 4 and 5. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 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. 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. 8 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 notadversely 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. Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KDU 1 (PTD 167-045) CIBP, 35’ of Cement, CBL 08/25/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/09/2021 By Abby Bell at 8:43 am, Nov 09, 2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KDU 1 (PTD 167-045) Temp 10/07/2021 Please include current contact information if different from above. 11/02/2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/26/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KDU 01 (PTD 167-045) Completion Record Perf 08/27/2021 Please include current contact information if different from above. 10/26/2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/20/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KDU-01 (PTD 167-045) Perf 09/20/2021 Please include current contact information if different from above. 37' (6HW Received By: d 10/25/2021 By Abby Bell at 12:27 pm, Oct 25, 2021 From:McLellan, Bryan J (CED) To:Jacob Flora; Josh Allely - (C); Donna Ambruz Cc:Aras Worthington; Roby, David S (CED); Davies, Stephen F (CED); Dan Marlowe; Chad Helgeson; Chris Kanyer; Todd Sidoti - (C) Subject:RE: KDU-01 Sterling Pool 6 UPDATE (10/15/21 temp/spinner logs) Date:Thursday, October 21, 2021 12:24:00 PM Jake, You have approval to proceed with your plan below. Be sure to also complete the condition on the approved Sundry 321-307, which requires an MITA of 1500 psi after stable injection conditions have been established. Provide AOGCC opportunity to witness this MIT. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Wednesday, October 20, 2021 12:49 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>; Josh Allely - (C) <Josh.Allely@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Cc: Aras Worthington <Aras.Worthington@hilcorp.com>; Roby, David S (CED) <dave.roby@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Chris Kanyer <ckanyer@hilcorp.com>; Todd Sidoti - (C) <Todd.Sidoti@hilcorp.com> Subject: KDU-01 Sterling Pool 6 UPDATE (10/15/21 temp/spinner logs) Bryan, Attached is an updated log presentation of the spinner and temp logs with the passes labeled. As discussed on the phone yesterday both spinner and temperature indicate all the fluid is entering through the C2 perforations, and no temperature anomaly or indication of a channel below this point. Also as mentioned we have the memory spinner and slickline bell guide lodged in the tubing tail. We request permission to proceed with the following steps: 1. Jet cut the tubing tail 2. Set a through tubing plug over the C2 perforations with 25’ cement on top 3. MIT the plug to 1200 psi after the cement has hardened. I estimate the C2 BHP at 850 psi based on the WHP of 382 psi + the HP with the fluid level at 3642’. 4. RU coil tubing and jet the wellbore dry with Nitrogen (this contingency already exists in the open sundry 321-307) 5. Perforate and test the C1 within the currently approved interval Let me know if you need more information for this request, Thanks, Jake From: Jacob Flora Sent: Tuesday, October 19, 2021 11:33 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>; Josh Allely - (C) <Josh.Allely@hilcorp.com> Cc: Aras Worthington <Aras.Worthington@hilcorp.com>; Roby, David S (CED) <dave.roby@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov>; Dan Marlowe (dmarlowe@hilcorp.com) <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Chris Kanyer <ckanyer@hilcorp.com> Subject: KDU-01 Sterling Pool 6 UPDATE Bryan, Friday (10/18) we performed a memory LDL with slickline to gain a better understanding of what is happening downhole. Fluid level prior to pumping: 3762’ (380 psi HP + 550 psi WHP = 929 psi BHP) 10/15/2021 Logging Summary: We logged a baseline to TD above the 7” CIBP, pumped 150 bbls of cold water into the well, and logged up while pumping 3 bpm looking for both temperature and spinner response. We then continued pumping at 3bpm, and obtained stop counts above and below the perforations, followed by 1hr and 2hr static warm-back passes. The data is attached and shows no temperature anomaly below the open Sterling C2 perforations. On the final pass POOH we got to surface and found the spinner assembly to be missing (unthreaded from the Spartek gauge housing). A fishing attempt the next day then lodged the spinner in the tubing tail and then dropped a bell guide on top of it. We now believe we are in communication with the C2 sand and that this log rules out a channel down or upward. A look at the 9-22-1967 sonic porosity log shows the zone to be much lower quality (4-6% sonic porosity) rock that the larger C1 above it with 16%. I think there’s a strong case here that we are in an isolated portion of the C2 and that the logs support this. Our plan forward is to use e-line to log a CCL off the tubing tail fish, ensure we can get a jet cutter below the packer, and then jet cut and drop the 5-1/2” tubing tail. Followed by setting a through tubing umbrella plug over the C2 perfs, dump bailing cement on the plug, waiting on cement, then using coil tubing to unload the water prior to perforating the C1. I’ll call you this afternoon to discuss the plan forward, Thanks, Jake Below are the two logging summaries, and subsequent fishing rig ups: Oct 8 2021 ENGINEER:Jake Flora FIELD SUPERVISOR:Cole Bartlewski FW:0.0 PRESENT OPERATIONS:MIRU YJES, Production profile log. Static log and Log after pumping 170 bbls of 190*F water with hot oil truck. PTW, JSA. Spot Equipment. United Rentals man lift on location.;RIg up E line unit. PT lubricator 250/3000 psi. RIH with 2 x 1 11/16" WB & 1 3/8" CCL/Tempt tool. Logged down to TD for static log. Tagged @ 7863'.;Wait for hot oil truck to finish MIT on KU 24-32. Parked on bottom for 4 hours before logging up.;Rig up hot oil truck and Cruz 170 bbl tanker truck. PT Pump line to Eline valve pump in sub. 250/3500psi.;Start pumping down tubing at 1.4 bbls/min and heating fluid to 190*F. Waiting for a spike to see when we caught fluid level. No significant indication of catching fluid level. Pumped 170 bbls at 1.4 bbls/min with 365 being the highest pressure seen and 318 after breakover.;Starting Logging OOH from 8730' to surface. Rig down Hot oil truck and release Cruz Tanker truck.;Rig Down E-line unit and prep man lift to return to Beaver Creek for BCU-19 perforating. DAILY JOB COST:$12,183 TOTAL JOB COST:$439,798 Oct 15 2021 ENGINEER:Jake Flora FIELD SUPERVISOR:Chad Helgeson FW:0.0 PRESENT OPERATIONS:Slickline & Pumping operations Arrive at KGF meet with Andy, complete JSA/Permit. Rig Up slickline p/u lub., standby for manlift for tree 15ft in air. Hot Oil Truck arrived, RU to water well for pump supply water w/ 3" hose. Rig up pump discharge with 1" hose on truck to pump in sub on W/L equipment.;man-lift arrives, removed tree cap, stab on lub. p/t to 2,000 psi fail, c/o O-Ring test again, good test.;RIH w/ 2.86" g-ring to 8,736' slm 8,751kb tag, POOH;RIH w/ spinner & p/t survey tools, 100 fpm to 8,701', started pumping cold water from water well at 3 BPM, tubing pressure dropped from 367 psi to 100psi in 15 min (hole fill at ~45 bbls pumped), pressure climbed to 700 psi, dropped and gradually built to ~350 psi.Logged up and made 5 min stops at 4970, 4760, 4540 while pumping 150 bbls. Pumped another 61.7 bbls to cover pumping while at final stops.;Continued logging to 4,000'. Freeze protected tubing with 4 bbls MeOH. RD Pump truck. Slickline made 15 min stop at 4000'. log to 8,701' 3 times with 1hr stops on bottom and 3 min stops at 4,000'. OOH lost spinner and centralizer. Half of Gamma CCL in hole. lay down Lub. Secure well for night. DAILY JOB COST:$6,489 TOTAL JOB COST:$446,287 Oct 16 2021 ENGINEER:Jake Flora FIELD SUPERVISOR:Andy Graves FW:0.0 PRESENT OPERATIONS:Fishing SL Tools Arrive @ KGF, meet with Andy fill out JSA, Pu Lub, Stab on Riser.;RIH w 1-3/8" OS w/ 4.5" Bell guide to 4,865' SLM sit with tool tap down 3 times, POOH. RIH w/ Same to 8,732' SLM, SIT w/ tool, POOH 200# overpull. POOH to 6,966 SLM hungup w tool. Tools free. POOH metal marks on bell guide. RIH w/ same w/ 4/5" cent. to 8,734' SLM w/ tool to 8,738' SLM. POOH, hung up at 8,666 w/ tool thru @ 8413, 8204, 7909, 7784, 7336, 7127, in multiple spots. POOH, Lost 4.5" bell guide @ control.;OS threads dulled & mushroomed, standby for magnet. RIH w/ 3.8" cent. w/ 3' stem, 4.5cent, 3.7" LIB to 4411' SLM 4,426 KB, SIT w tool, POOH Empty. Lay down lub for night, secure well, turn in permit. DAILY JOB COST:$0 TOTAL JOB COST:$446,287 Oct 17 2021 ENGINEER:Jake Flora FIELD SUPERVISOR:Andy Graves FW:0.0 PRESENT OPERATIONS:Fishing SL Tools Arrive on location jsa permit, Cut wire re-head check tool string p/u l4b. Stab on, RIH w/ 3.85'' cent. 2' stem 4.5'' cent. 3.85'' lib to 4411'slm 4426'kb hit 1 time pooh w/ impression of bell guide on its side.RIH w/ 2' stem w/ 4'' blind box to 4411'slm beat down 20 times did not fall pooh check tools RIH w/ 4.5'' cent. 2' stem 4'' bb to same w/ tool 30 times fell thru cont. to 4420'slm tag pooh;RIH w/ 4.5'' cent 2' stem 3.7'' magnet to 4420'slm sit w/ tool pooh empty RIH w/ 4.5'' cent. 2' stem 4'' bb to same w/ tool 4422'slm w/ tool would not fall poohRIH w/ 3.85'' cent. 2' stem 4.5'' cent. 3.85'' lib to 4422 hit 1 time pooh w/ impression of flattened bell guide w/ brass wires imbedded in led call sup. Call Chad Johnson RIH w/ 4.5'' cent. 2' stem 4'' blind box to 4422'slm 4437'kb w/ tool did not fall pooh RDMO From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 12, 2021 10:45 AM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Taylor Wellman <twellman@hilcorp.com>; Aras Worthington <Aras.Worthington@hilcorp.com>; Roby, David S (CED) <dave.roby@alaska.gov>; Davies, Stephen F (CED) <steve.davies@alaska.gov> Subject: [EXTERNAL] KDU-01 Sterling Pool 6 gas storage Jake, I understood from our phone call yesterday that there is some question about the integrity of the seal in Gas Storage Pool 6 in KDU-01 and that crossflow is occurring behind casing. Please submit information to the AOGCC explaining what you believe is occurring, supporting evidence, date when you first identified the problem, current status of the well, and your plan to immediately stop the crossflow, as required in SIO 7A rules 4 and 5. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 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 responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ________N2________ 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,895'N/A Casing Collapse Structural Conductor Surface 1,540 psi Intermediate 2,570 psi Production Liner 7,020 psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng jake.flora@hilcorp.com 9,531'9,811'9,454'35psi N/A FH Ret Hydraulic Packer; 2 Guiberson Model RH-1 Pkrs 8,925' MD-8,630' TVD; 9,050' MD-8,761' TVD; 9,434'MD-9,109' TVD; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: 8,160 psi Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 167-045 50-133-20035-00-00 Kenai Deep Unit (KDU) 01 Kenai Gas Filed / Sterling 6 Gas, Sterling 6 Gas Storage Length Size CO 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 6.5# / N-80 TVD Burst 9,473' MD 3,950 psi 3,090 psi1,209' 4,984' 1,209'13-3/8" 9-5/8"4,984' 1,209' Perforation Depth MD (ft): 4,984' See Attached Schematic 7" Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: July 20, 2021 9,858'4,870' 2-7/8" 9,497' Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:38 am, Jun 23, 2021 321-307 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.06.23 10:20:14 -08'00' Taylor Wellman (2143) SFD 6/23/2021 BJM 6/30/21 X 10-404 SFD 6/23/2021 CBL log of 9-5/8" casing is required. Discuss results with AOGCC before installing new tubing. Injection valve is required while on gas injection per 20 AAC 25.265(d)(5). DSR-6/23/21 MITIA to 1500 psi required after stable injection conditions have been achieved. Provide 24 hrs notice for AOGCC witness. X BOP Test to 2500 psi, annular test to 2000 psi. dts 7/1/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.07.01 11:19:43 -08'00' RBDMS HEW 7/2/2021 Well Prognosis Well: KDU-01 Date: 06/23/2021 Well Name: KDU-01 API Number: 50-133-20035-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: 07/20/21 Rig: 401 Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 167-045 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number: Current Surface Pressure: 35 psi Maximum Expected BHP: 175 psi @ 4445’ TVD Max. Potential Surface Pressure: ~ 0 psi (Assumed 0.10 psi/ft gas gradient). Current Well Status Shut in gas producer, offline since April 2018. Brief Well Summary KDU-01 was drilled as a grassroots well to target gas sands in the Tyonek formations. In March of 2016 a RWO was conducted to repair a high part in the tubing string. At the time the well was shut-in for the repair, it was making 2.2 MMCF/D @ 135 psi from the Tyonek D-3 and D-4 sands. After the repair, the rate came back at approximately half that rate (1.3 MMCF/D). The start of 2017, the well dropped again to 500 MCF/D. The well eventually stopped flowing and has been offline since April 2018. The Tyonek D4B, D3B and the D2 have produced a total of 105.4 BCF. The purpose of this work/sundry is to perform pull the existing completion, plug back the open perfs, and complete the well as a new Pool 6 storage injector and producer. Once KDU-01 tests out as a successful Pool 6 storage well, existing Pool 6 storage well KU 31-07X will be converted into a Sterling producer. KU 31-07X has a increasing history of sand production and replacing it with KDU-01 will safeguard the ability to produce and inject at high rates as necessary to protect seasonal demand. ***Based on the attached 660’ buffer map a SSSV will not be installed in the completion*** Wellbore Condition 03-13-2016 MITIA to 1500psi PASSED (2016 RWO after setting packer) 05-05-2018 2.25” LIB to 8575, tag fluid, 2-7/8” SS shifting tool to 9087’, couldn’t open sleeve Ran 2” DDB to 9201’, bailed soupy mud 05-17-2021 MITIA to 1500 psi passed Rig Procedure 1. MIRU 401. 2. Notify AOGCC 24hrs in advance of BOP test. 3. Bullhead tubing with water, Set TWC, ND Tree 4. NU BOP and test to 250 psi low & 2,500 psi high, annular to 250 psi low & 2,000 psi high. Record accumulator pre-charge pressures and chart tests. a. Perform Test. b. Test rams on 2-7/8” and 5-1/2” test joints. BOP Stack has 2-7/8” to 5-1/2” variables in second position, Blinds in bottom. Gas-only injection wells must have a SSSV or an injection valve per 20 AAC 25.265(d)(5). SIO 7A authorized area wide storage injection in Pool 6. - DSR 6/23/21 complete the well as a new Pool 6 storage injector and producer. Well Prognosis Well: KDU-01 Date: 06/23/2021 c. Submit completed form 10-424 to AOGCC within 5 days of BOPE test. 5. Pull completion (retrievable packer & overshot from 9,034’), circulate wellbore, LD same. 6. RU E-Line, set 7” CIBP at 9000’ and dump bail 35’ cement top. 7. MIT CIBP to 1500 psi 8. ND BOP, ND tubing head, install new tubing head to accommodate larger tubing hanger, NU BOP and shell test flange connection. 9. Run 5-1/2” tubing & 9-5/8 retrievable packer to ~4425’, land hanger, (log on depth if necessary) RILDS, test packoff, drop B&R, pressure up and set packer 10. MITIA to 1500psi 11. ND BOP, NU tree, PT same, RDMO Slick-Line, E-line Procedure 12. MIRU Slickline, PT Lubricator 13. Pull B&R, RHC plug body 14. Pull dummy valve from GLV, set pocket protector 15. RU Nitrogen to the tubing, depress tubing fluid level while taking returns from the IA 16. Once 100 bbls have been recovered (tubing volume to the GLM), pull pocket protector, re-set dummy GLV 17. Bleed down tubing pressure, RDMO 18. MIRU E-line, PT Lubricator 19. Perforate the following intervals from the bottom up: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Pool 6 (Storage) ±4,445' ±4,681’ ±238' ±4,445' ±4,681’ a. Correlate using correlation log from Geologist. b. Use Gamma/CCL/to correlate. Flow Test 20. Turn Well over to production CONTINGENCY NITROGEN BLOWDOWN WITH COIL TUBING Sundry completion work: 1. NOTIFY AOGCC 24hrs in advance of CTU BOP Test. 2. MIRU Coiled Tubing Unit. 3. PT BOP equipment to 250 psi Low / 4,000 psi High. (Notify AOGCC 24 hrs. in advance on BOP test. 4. MU nozzle, and RIH to TD. 5. RU N2 pumping unit. 6. Blow well dry with N2 taking returns to tanks. 7. Once well is dry, leave N2 pressure on well per OE for the first perforation interval. Tubing and IA must both be displaced to KWF before unseating tubing hanger. Shoot holes in tubing as needed to provide flowpath. bjm 7.a. Run Cement log across 9-5/8" casing and send results to AOGCC for review prior to installing new tubing. bjm Notify AOGCC to witness test. bjm Perform MITIA to 1500 psi after stable injection has been established, per Rule 3 of SIO 7A. Provide 24 hrs notice to AOGCC inspectors to witness test. Install injection valve in the tubing prior to placing the well on injection. Well Prognosis Well: KDU-01 Date: 06/23/2021 8. POOH w/ coil. RDMO CTU. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Current Wellhead Diagram 4. Proposed Wellhead Diagram 5. Rig 401 BOP Schematic 6. Coil BOP Schematic 7. Standard Nitrogen Procedure 8. Area of Review (AOR) ¼ mile radius map 9. Area of Review (AOR) table 10. 660 ft Buffer Map 11. RWO Change Form _____________________________________________________________________________________ Updated by JMF 02-04-2021 Kenai Gas Field Well: KDU 01 Date Last Completed: 11-13-67 PTD: 167-045 API#: 50-133-20035-00 SCHEMATIC PBTD = 9,811’ MD / 9,454’ TVD TD = 9,895’ MD / 9,531’ TVD 1 5 6 7 8 9 10 13-3/8” 7” 9-5/8” Tight spot from 8,941’-8,946’. Possible casing damage at 9,004’ 2 3 4 N X KB to Hanger =15’ X X CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 13-3/8” Surface 61 / J-55/ BTC Surf 1,209’ 9-5/8" Intermediate 40 / J-55/ BTC Surf 4,984' 7” Liner 29 / P110 / BTC 4,870’ 8,210 29 / N-80 / BTC 8,210’ 9,858’ TUBING DETAIL 2-7/8” Tubing 6.5# / L-80 / EUE 2.441” Surf 9,048’ 2-7/8” Tubing 6.5# / N-80 / BTC 9,035’ 9,473’ JEWELRY DETAIL No Depth OD Item 1 15’ Tubing Hanger 2 8,925’ 5.968” FH Hydraulic Retrievable Packer 3 9,001’ “X” Nipple 4 9,034’ 5.5” 6’ Overshot 5 9,050’ 5-3/4” Guiberson “RH-1” Packer 6 9,087’ Otis “X” Sleeve 7 9,122’ 3-3/4” Top of Baker Blast Jts 8 9,244’ 3-3/4” Btm of Baker Blast Jts 9 9,275’ Otis “X” Sleeve 10 9,434’ 5-3/4” Guiberson “RH-1” Packer 11 9,472’ Otis “N” Nipple 12 9,473’ Btm of Guiberson Sheer Nipple PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD)Btm (TVD) FT SPF Date Status D-2 9,155’ 9,175’ 8,856’ 8,874’ 20’ 4 11-09-67 Open 9,210’ 9,230’ 8,906’ 8,924’ 20’ 4 11-08-67 Open D-3 9,535’ 9,555’ 9,201’ 9,219’ 20’ 4 11-06-67 Open D-4 9,670’ 9,720’ 9,325’ 9,370’ 50’ 4 11-06-67 Open _____________________________________________________________________________________ Updated by JMF 05-20-2021 Kenai Gas Field Well: KDU 01 Date Last Completed: 11-13-67 PTD: 167-045 API#: 50-133-20035-00 PROPOSED POOL 6 STORAGE WELL PBTD = 9,811’ MD / 9,454’ TVD TD = 9,895’ MD / 9,531’ TVD 1 5 6 7 8 9 10 13-3/8” 7” 9-5/8” Tight spot from 8,941’-8,946’. Possible casing damage at 9,004’ 9-5/8” TOC CALC @ 3152 with 50% washout 4 7” TOC N X KB to Hanger = 15’ X 5-1/2” GLM ~4370’ 9-5/8” PKR ~4400’ X-Nipple ~4415’ WLEG ~4425’ Sterling C1, C2 4445-4681’ 7” CIBP ~9000 w/ 35’ cmt top CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm Cement 13-3/8” Surface 61 / J-55 / BTC Surf 1,209’ 9-5/8" Intermediate 40 / J-55 / BTC Surf 4,984' 998 sx 7” Liner 29 / P110 / BTC 4,870’ 8,210 29 / N-80 / BTC 8,210’ 9,858’ TUBING DETAIL 5-1/2” Tubing 17# / L-80 / EUE 4.892” Surf 4,415’ JEWELRY DETAIL No Depth OD Item 5 9,050’ 5-3/4” Guiberson “RH-1” Packer 6 9,087’ Otis “X” Sleeve 7 9,122’ 3-3/4” Top of Baker Blast Jts 8 9,244’ 3-3/4” Btm of Baker Blast Jts 9 9,275’ Otis “X” Sleeve 10 9,434’ 5-3/4” Guiberson “RH-1” Packer 11 9,472’ Otis “N” Nipple 12 9,473’ Btm of Guiberson Sheer Nipple PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT SPF Date Status Pool 6 4445’ 4681’ 4445’ 4681’ TBD TBD Planned Planned D-2 9,155’ 9,175’ 8,856’ 8,874’ 20’ 4 11-09-67 Open 9,210’ 9,230’ 8,906’ 8,924’ 20’ 4 11-08-67 Open D-3 9,535’ 9,555’ 9,201’ 9,219’ 20’ 4 11-06-67 Open D-4 9,670’ 9,720’ 9,325’ 9,370’ 50’ 4 11-06-67 Open Injection valve is required for gas injection in tubing. Kenai Gas Field KDU #1 Current 01/19/2016 Tubing head, CIW-AP 13 5/8 3M x 11 5M, w/ 2- 2 1/16 5M EFO, w/ R bottom w/ 1- 2 1/16 5M CIW-FC valve Casing head, Baash Ross type FL w/ FL style packing unit, 13 5/8 3M x 13 3/8 SOW, w/ 2- 2'’ LPO Bloc k, tree, CIW-F, 11 5M FE x 3 1/8 5M double master x 2 1/16 5M wing section, prepped f/ 6 ¼ FBB hanger neck, ½ control line port, AA trim 13 3/8'’ 9 5/8'’ 2 7/8'’ Valve, Swab, CIW-F, 3 1/8 5M FE, HWO, AA trim BHTA, Otis, 3 1/8 5M x 6.5 Otis acme Valve, SSV, WKM-M, 2 1/16 5M FE, w/ 13'’ Safeco oper, DD trim Kenai Gas Field KDU #1 13 3/8 x 9 5/8 x 2 7/8 Tubing hanger, CIW-F-FBB, 11 x 3 ½ EUE 8rd lift x 3 ½ EUE 8rd susp, w/ 3'’ type H BPV profile, 6 ¼ extended neck Kenai Gas Field KDU #1 Proposed 05/19/2021 Casing head, Baash Ross type FL w/ FL style packing unit, 13 5/8 3M x 13 3/8 SOW, w/ 2- 2'’ LPO Kenai Gas Field KDU #1 13 3/8 x 9 5/8 x 5 1/2 Valve, Master, CIW-FC, 5 1/8 5M FE, HWO, EE trim Valve, Upper master, CIW-FC, 5 1/8 5M FE, HWO, EE trim Valve, Swab, CIW-FC 5 1/8 5M FE, HWO, EE trim Valve, Wing, CIW-FC, 4 1/16 5M FE, HWO, EE trim BHTA, Otis, 5 1/8 5M FE x 9.5 Otis quick union top 5 ½’’ Tubing head, Cactus C-29L- HPS, 13 5/8 3M x 11 5M, w/ 2- 2 1/16 5M SSO Casing hanger, CW, 11 x 5 ½ DWC/C box btm x 6.125'’ LH stub acme box top, w/ 7 5/8 od neck, 5'’ type H BPV profile, DD-NL material Valve, Wing, SSV, WKM-M, 4 1/16 5M FE, w/ 15'’operator 13 3/8'’ 9 5/8'’ The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 13-5/8"Spherical Annular Height: 46" Weight: 12,806 13-5/8"LWS Double BOP Height: 37" Width: 93" Weight 9,900 lbs. TOP RAMS 2-7/8" TO 5-1/2" MULTI- RAMS BOTTOM RAMS BLIND RAMS 13-5/8"Mud Cross W/ 4- 1/16" outlets Height:28.5" Width 31" Dual 4-1/16" Manual Gate valves W/ DSA to 2-1/16" 4-1/16" Manual Gate valve & 4-1/16" HCR W/ DSA to 2-1/16" Full Mud Cross Assy. width w/ valves installed Width: 98.5" Weight: 2200 lbs. Kill side Choke side Height Addition for Ring Gaskets: 0" BOP Total Height: 111.5" BOP Total weight: 24,906 lbs. 13-5/8" 5m BOP Package W/ 4-1/16" Valves Coiled Tubing HydraCo 60K Injector Head & Gooseneck Weight = 3500 lbs 3" 500psi ArmorPak Stripper Bowen Type 5K 5.5" Lubricator 5K CJS ArmorPak Guide Bowen Type 5K x 5-1/8" 10K Flange 5-1/8" 10K Quad BOP 1.ArmorPak 1.5" x 1.5" Pipe Ram 2.ArmorPak 1.5" x 1.5" Pipe Ram 3.Shear Ram 4.Blind Ram 5-1/8 10K Spool with 2-1/16" 10K Outlets - Kill Port Manual Valve 1: 2-1/16" 10K Manual Valve 2: 2-1/16" 10K Manual Valve 3: 2" Weco 1502 Adapter Spool 5-1/8" 10K x 7-1/16" 5K Adapter Spool 7-1/16" 5K x 5-1/8" 5K 5-1/8" 5K ArmorPak 1.5" x 1.5" CT Head Wellhead STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. KDU 01 Quarter Mile AOI MapQuarter Mile-4,505 KDU-01 Area of Review 6/3/2021PTD API WELL STATUS Distance, ft Top of Pool 6 (MD / TVD)TOC across Pool 6 sandsNotes MITs205-165 50-133-20556-00 KBU 11-07 Producer 1358 4708' / 4436' 4530' MD 12/22/05 CBL207-149 50-133-20572-00-S1 KBU 14-06Y Producer 262 4462' / 4439' 4030' MD 01/17/21 CBL MITIA Pass (3/15/21)215-044 50-133-20650-00 KBU 22-06Y Producer 1119 4581' / 4425' 3670' MD 04/29/15 CBL MITIA Pass (10/24/20)206-013 50-133-20499-01 KBU 24-06RD Producer 966 4564' / 4403' 3630' MD MITIA Pass (5/26/20)217-041 50-133-20662-00 KU 11-07X Producer 524 4469' / 4425' 2500' MD 04/30/17 CBL181-092 50-133-20342-00 KU 14x-06 (KDU-08)Pool 6 Producer248 4441' / -4346' 3822' MD (calculated w 35% washout) 9-5/8" casing set at 7282' MD cemented with 1450 sx. Active Pool 6 perfs: 4462-4670'. Multiple squeezes across the Sterling A & B sands were performed at 3548-50', 3746-48', 3800-02' behind the 9-5/8" casing.202-252 50-133-20342-01 KU 14-06RD (renamed from KU 14-06)SI Producer 236 4439' / 4428' 3228' MD 7" casing set at 4616' cemented w 775sx. Calculated TOC = 3228'.165-008 50-133-10092-00-00 KU 21-07 SI Producer 791 DNP 3500' MD NA, 06/13/65 CBL NA206-029 50-133-20558-00-00 KU 21-07X SI Producer 1149 4564' / -4332' 2816' MD 05/24/06 CBL220-065 50-133-20692-00-00 KU 44-01B PB1 Pool 6 Producer1344 6964' / -4429' 2070' MD 12/17/20 CBL3/31/06 CBLSFD 6/23/2021SFD 6/23/2021Did not penetrate KU 31-07XKDU 01SEC. 6SEC. 74N11WKENAI UNITKenai Gas FieldPad No. 14-06SALAMATOFNATIVEASSN INCSALAMATOFNATIVEASSN INC151°15'40"W151°15'50"W151°16'0"W151°16'10"W60°27'50"N60°27'50"N60°27'45"N60°27'45"N60°27'40"N60°27'40"N60°27'35"N60°27'35"N60°27'30"N60°27'30"N60°27'25"N60°27'25"NKenaiUnitKGF 14-06 PadWells: KDU-01 and KU 31-07X660 ft Radii0 100 200 300 400FeetLegendSurface Well LocationWell PadsExisting Gas PipelinesKGF 14-06 Pad - 660ft BuffersWells: KDU-01 and KU 31-07XKPB ParcelsCook Inlet Oil and Gas Units1 inch = 200 feet @ 11x17 page sizeMap Date: 5/24/2021 Document Path: O:\Alaska\GIS\cook_inlet\fields\KenaiUnit\mxds\Kenai_Unit_KDU-01_Well_660ftBuffer_11x17_JFlora_v01.mxd Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well KDU-01 (PTD 167-045) Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date 1 Carlisle, Samantha J (CED) From:Jake Flora - (C) <Jake.Flora@hilcorp.com> Sent:Wednesday, June 30, 2021 1:07 PM To:McLellan, Bryan J (CED) Subject:KDU-01 (PTD 167-045) 7 inch cement summary Attachments:KDU-01 7 in cement summary.pdf Bryan, Fromthe1967drillinghistorytheypumped600sxclassGwhilecementingthe7”liner.Goodcementreturnswere noted.IfoundtheCBLfrom11Ͳ5Ͳ1967whichnotesTOCat4800’,howevertheprintoutiscroppedandonlyshows 9000’anddeeperacrossthedeeperpays. Letmeknowifyouneedmoredetailonthisorwouldliketoseethelogheader, Thanks, Jake From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Wednesday,June30,202111:56AM To:JakeFloraͲ(C)<Jake.Flora@hilcorp.com> Subject:RE:[EXTERNAL]KDUͲ01(PTD167Ͳ045)RWOSundry Jake, Whatareyourplansforinjection/productioninthiswell?Isitaseasonalswitchwhereyouwillbeoninjectioninthe warmweatherperiodsandswitchtoproductioninhighͲdemandwinterperiod?Orisitathingwhereyouare constantlyswitchingbackandforth? Thanks BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:JakeFloraͲ(C)<Jake.Flora@hilcorp.com> Sent:Wednesday,June30,202111:14AM To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Subject:RE:[EXTERNAL]KDUͲ01(PTD167Ͳ045)RWOSundry Bryan, 1. Themaxinjectionpressurewecouldseeisthesaleslinepressureof750psi. 2. MASPfromthecurrentperfsiszero.TheyareexhaustedTyonekgasperfsthatquitflowingin2018. 2 3. TheCalculatedTOCbehindthe9Ͳ5/8casingis3152’(using204slurrybbls&50%washout).The204bblsis basedonthewellhistoryofpumping998sxclassG.Iused1.15cf/sackwhichisconservative. Letmeknowifyouneedanythingfurther, Thanks, Jake From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Tuesday,June29,20215:29PM To:JakeFloraͲ(C)<Jake.Flora@hilcorp.com> Subject:[EXTERNAL]KDUͲ01(PTD167Ͳ045)RWOSundry Jake, AcouplequestionsabouttheworkoverSundry: 1. Whatisthemaxinjectionpressurefromthegasinjectionsystem? 2. WhatistheMASPfromtheexistingperfs? 3. Whatdoyouknowaboutthecementjobonthe9Ͳ5/8”Casing?Doyouhavethecementingreportyoucan send? BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 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. 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. • • of Tit THE STATE Alaska Oil and Gas Conservation Commission o fALASKA fifth i 333 West Seventh Avenue .471 -2.471 -2 + , GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572. Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager rt Hilcorp Alaska, LLC NM�� `' 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Kenai Field, Tyonek Gas Pool,KDU 1 Permit to Drill Number: 167-045 Sundry Number: 317-108 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy . Foerster y-�, Chair DATED this /S day of March, 2017. RBD 'MS 3 2617 • • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAR 0 9 2017 APPLICATION FOR SUNDRY APPROVALS D 37/ //? AOG CC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate p• Other Stimulate ❑ Pull Tubing ❑ Change Apped Program 0 Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Coil Turing Clean Out ❑., • 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: + Name- ' Hilcorp Alaska,LLC Exploratory ❑ Development Q• 167-045 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20035-00 • 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 510A Kenai Deep Unit(KDU)01 Will planned perforations require a spacing exception? Yes ❑ No ❑., 9.Property Designation(Lease Number): 10.Field/Pool(s): FEDA028142' Kenai/Tyonek Gas . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 9,895'• 9,531' • 9,811' 9,454' 2,500psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,209' 13-3/8" 1,209' 1,209' 3,090 psi 1,540 psi Intermediate 4,984' 9-5/8" 4,984' 4,984' 3,950 psi 2,570 psi Production Liner 4,870' 7" 9,858' 9,497' 8,160 psi 7,020 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: 2-7/8" Tubing Grade: 9.3#/N-80 Tubing MD(ft): 9,048'; See Attached Schematic See Attached Schematic 2-7/8" 6.5#/N-80 9,473' Packers and SSSV Type: FH Hyd Ret Pkr; Packers and SSSV MD(ft)and TVD(ft): 8,925'MD/8,647'TVD; 2 Guiberson Model RH-1 Pkrs;N/A 9,050'MD-8,761'ND;9,434'MD-9,109'ND;N/A 12.AttachOnts: Proposal Summary Wellbore schematic E 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic❑ Development❑✓ Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: March 23,2017 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS 2 WAG 0 GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown 0 Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved -lett- herein will not be deviated from without prior written approval. Contact Ted Kramer-777-8420 Email tkramer( hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature /; "7 e7Phone 907-777-8405 Date 3 -el / r COMMISSION USE ONLY / 1 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: `� �-r- / 3 l�7- Plug Integrity ❑ BOP Test OI Mechanical Integrity Test ❑ ,Location Clearance ❑ 4•••••r-4=-- '14.SI a Other: 1I`- <66 / S, 00,P 5T_ 1. Post Initial Injection MIT Req'd? Yes 0 No ❑ f RED4A5 G,,V2 l L J Lu: Spacing Exception Required? Yes ❑ No Subsequent Form Required: I 0 ' WoLi APPROVED BY _ 7 Approved by: COMMISSIONER THE COMMISSION Date:3._I S ^ f j NA.� L -om—r Submit and Form 10-403 evised 11i2015 C,:i f p p i valid for�2 months from the date of approval. � Attachments in Duplicate ,�'f h 3'``'- /7 • Well Prognosis Well: KDU-01 Elilcarp Alaska,LU Date:03/8/2017 Well Name: KDU-01 API Number: 50-133-20035-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: 03/23/17 Rig: N/A Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 167-045 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (M) AFE Number: Current Surface Pressure: 32 psi Maximum Expected BHP: —2,250 psi @ 9,370' TVD (Based on 12/17/14 SIBHP survey of offset well KBU 42-06Y in D-3 sand) Max. Potential Surface Pressure: — 1,313 psi (Assumed 0.10 psi/ft gas gradient). 2,500 psi Pressure if N2 is used to push water. Brief Well Summary KDU-01 was drilled as a grassroots well to target gas sands in the Tyonek formations. In March of 2016 a RWO was conducted to repair a high part in the tubing string. At the time the well was shut-in for the repair, it was making 2.2 MMCF/D @ 135 psi from the Tyonek D-3 and D-4 sands. After the repair, the rate came back at approximately half that rate (1.3 MMCF/D). The start of 2017,the well dropped again to 500 MCF/D. The purpose of this work/sundry is to perform a coil cleanout of this well and to re-perforate the D-2, D-3 and D-4 formations. Hilcorp asks for a name change for this well from Kenai Deep Unit (KDU) 1 to Kenai Unit (KU) 1. The three letters typically designating the pool the well was initially completed in KGF sometimes changes in the life of the well and makes the three letter designation confusing, so we would like to work on changing names of the KGF wells as future sundries are submitted to the simple Kenai Unit (KU) designation. • Safety Concerns(if coiled tubing letting is performed) • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter, i.e. near flow-back tank. • Consider tank placement based on wind direction and current weather forecast(venting methane and Nitrogen during this job) • Ensure all crews are aware of stop job authority Coiled Tubing Cleanout Procedure : t)/ ;} rye h 1. Submit 24 hr.witness notification to AOGCC✓ via web base notification. 2. MIRU Coiled Tubing, PT BOPE to 250/4500 psi. 3. Isolate production flow line. Route well production to open top diffuser 400 bbl tank. 4. Pressure test N2 lines to 4,500 psi prior to starting job. 5. RIH w/1.5" coil w/jet nozzle BHA. a. Start pumping N2 at 800 scf at 8,000 ft b. Increase N2 rate as necessary while RIH to 9,811' MD and tag PBTD. Once N2 has reached return tank start pinching in choke (Maintain approximately 200-300 psi on tubing). • Well Prognosis Well: KDU-01 Ilileorp Alaska,LL' Date:03/8/2017 6. PU slowly to 8,000ft monitoring tank for fluid. Cycle between 8,000' and 9,811'one more time pumping N2 to lift well. Strap return tank until estimated volume of fluid recovered. If fluid rate is substantial continue to cycle between intervals. Use LEL monitor to sniff for gas on Return tank. 7. Return to bottom and blow well dry. 8. POOH w/coil. LD jet nozzle BHA. 9. RD Coil. 10. Turn over to operations and test well. E-line Procedure (If production rates do not return to 1-2mmsfd.) 11. MIRU E-line, pressure test lubricator to 3,500 psi High/250 Low. 12. Pressure up with Nitrogen to push water out of well bore. 13. PU 6 JSPF perf guns. 14. RIH and Perforate the following intervals: Sands Top (MD) Bottom (MD) Ft. J�s D-2 9,155 9,175 20 (u;J D-2 9,210 9,230 20 D-3 9,535 9,555 20 D-4 9,670 9,720 50 • a. Proposed Perfs on the proposed schematic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using correlation log from Geologist. d. Use Gamma/CCL/to correlate. e. Install crystal gauges(or verify PT's are open to SCADA) before perforating. Record Tubing pressures before and after each perforating run. f. All perforations in Table above are located in the Tyonek Pool based on Conservation Order • NO. 510A. 15. RD E-line. 16. Turn Well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Wellhead Diagram 4. CT BOPE Schematic 5. CT Schematic forward jetting • , H . Kenai Gas Field SCHEMATIC Datie LaDst Completed: 11-13-67 PTD: 167-045 Hilcory Alaska,LLC API#:50-133-20035-00 KB to Hanger=15' 1 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 13-3/8" Surface _ 61/1-55/BTC Surf 1,209' 9-5/8" Intermediate 40/J-55/BTC Surf 4,984' 7" Liner 29/P110/BTC 4,870' 8,210 29/N-80/BTC 8,210' 9,858' 133/' . TUBING DETAIL 2-7/8" Tubing 6.54/L-80/EUE 2.441" Surf 9,048' 2-7/8" Tubing 6.5#/N-80/BTC 9,035' 9,473' JEWELRY DETAIL No Depth OD Item 1 15' Tubing Hanger 2 8,925' 5.968" FH Hydraulic Retrievable Packer 3 9,001' "X"Nipple 4 9,034' 5.5" 6'Overshot 5 9,050' 5-3/4" Guiberson"RH-1"Packer 6 9,087' Otis"X"Sleeve ¢st8- M. 1� 2 7 9,122' 3-3/4" Top of Baker Blast its 8 9,244' 3-3/4" Btm of Baker Blast its %„/1„ 3 9 9,275' Otis"X"Sleeve TYspo<iom 10 9,434' 5-3/4" Guiberson"RH-1"Packer I I 1.44 11 9,472' Otis"N"Nipple 4 Possiblepyo 12 9,473' Btm of Guiberson Sheer Nipple I, /damp at9pM' /' s PERFORATION DETAIL I Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT SPF Date Status 9,155' 9,175' 8,856' 8,874' 20' 4 11-09-67 Open 7 D-2 . 9,210' 9,230' 8,906' 8,924' 20' 4 11-08-67 Open ,, 5r D-3 9,535' 9,555' 9,201' 9,219' 20' 4 11-06-67 Open .r _5-• D-4 9,670' 9,720' 9,325' 9,370' 50' 4 11-06-67 Open D2 I I w_10 el 11 NE DJ 64 Fi 1 PIDD=9,811'MO/9,454'11/3 TO=9$55 MD/9,531'lVD Updated by DMA 04-19-16 • PROPOSED SCHEMATIC• Kenai Gas Field Well: KU-01 Date Last Completed: 11-13-67 PTD: 167-045 Hilcorp Alaska,LLC API#:50-133-20035-00 KB to Hanger=15' 1 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 13-3/8" Surface 61/J-55/BTC Surf 1,209' 9-5/8" Intermediate 40/J-55/BTC Surf 4,984' 7" Liner 29/P110/BTC 4,870' 8,210 29/N-80/BTC 8,210' 9,858' 13-3/8< > TUBING DETAIL 2-7/8" Tubing 6.5#/L-80/EUE 2.441" surf 9,048' 2-7/8" Tubing 6.5#/N-80/BTC 9,035' 9,473' JEWELRY DETAIL No Depth OD Item 1 15' Tubing Hanger 2 8,925' 5.968" FH Hydraulic Retrievable Packer 3 9,001' "X"Nipple 4 9,034' 5.5" 6'Overshot - 5 9,050' 5-3/4" Guiberson"RH-1"Packer 6 9,087' Otis"X"Sleeve 9-5/82 M K L 2 7 9,122' 3-3/4" Top of Baker Blast Jts 8 9,244' 3-3/4" Btm of Baker Blast its 3 9 9,275' Otis"X"Sleeve II 10 9,434' 5-3/4" Guiberson"RH-1"Packer Tight spot from 11 9,472' Otis"N"Nipple 8,941'-8,946'. • 4 Possible casing 12 9,473' Btm of Guiberson Sheer Nipple damage at 9,004' s PERFORATION DETAIL 6 Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT SPF Date Status 9,155' 9,175' 8,856' 8,874' 20' 4 11-09-67 Open 7 9,155' 9,175' 8,856' 8,874' 20' 4 TBD Proposed ' D-2 9,210' 9,230' 8,906' 8,924' 20' 4 11-08-67 Open 9,210' 9,230' 8,906' 8,924' 20' 4 TBD Proposed ' 9,535' 9,555' 9,201' 9,219' 20' 4 11-06-67 Open D2 0-3 9,535' 9,555' 9,201' 9,219' 20' 4 TBD Proposed 9,670' 9,720' 9,325' 9,370' 50' 4 11-06-67 Open D-4 9,670' 9,720' 9,325' 9,370' 50' 4 TBD Proposed 9 TAIK 10 11 D-3 D4 7'L PBTD=9,811'MD/9,454'TVD TD=9,895'MD/9,531'TVD Updated by DMA 03-08-17 • Kenai Gas Field KDU#1 Current IIilrorp f.f.c 01/19/2016 ths.ha. Kenai Gas Field Tubing hanger,CIW-F-FBB, 11x3'hEUE8rdlift x3%2 KDU#1 EUE8rdsusp,w/3' type H 13 3/8 x 9 5/8 x 2 7/8 BPV profile,6%extended neck BHTA,Otis,3 1/8 5M x 6.5 Otis acme n�■v.iu n ..............:.:......................... Valve,Swab,CIW-F,3 1/8 5M FE,HWO,AA trim 1 � Valve,SSV,WKM-M, 2 1/16 5M FE,w/13"Safeco oper, DD trim Block,tree,CIW-F,11 5M FE x 3 1/8 5M double master x 4.13 2 1/16 5M wing section, prepped f/6'FBB hanger °` 0 neck,%z control line port, AA trim aNCIrel Tubing head,CIW-AP � 13 5/8 3M x 11 5M,w/2- * , 2 1/16 5M EFO,w/R bottom w/1-2 1/16 5M ��'' CIW-FC valve 0- a) 14 Casing head, Baash Ross type FL w/FL style packing unit, o p 13 5/8 3M x 13 3/8 SOW,w/ 2-2"LPO 13 3/8" 9 5/8" 2 7/8" . II0 Kenai Gas Field COIL BOPE KDU-1 3/3/2017 nil,orp v.14:i.I i(. 20 X 13 3/8 X 9 5/8 X 7 X 4-1/2 Coil Tubing BOP Lubricator to injection head 0 ii 1.75"Tandem Stripper 1 1 0.1111 Blind/Shear -4 1/16 10M!:Bh /5 hear ,','■- aM -mum isime- ammo mm, 1111111 Blind/Shear 111. --Blind/Shear l,l,'■1 € — — _ Slip • Slip 1.1.1 Hilt Pipe —_mom Mud Cross EllMIL •I1I'7 i/16 10M X 4 1/16 10M simor Outlet w/2-2 1/16 10M full opening FMC valves 7. i .. 8 _ ■ Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M '' 2 1/16 10M 2 1/16 10M Crossover spool 4 1/16 10M X 4 1/16 5M . . . 8] Q j U F F- m Q Y ] U z Q mo c ,3 � i t '3 L9Zpi1 -p w k Z -+-' r a a N v' E O e Y 2 N V q • g H VN • t ►64 00 U- b,, E V v A 0 d O H 1111, 11 I� 1 1 1m .hill0 1in ini IN in11!1100;a til 0 U 3 Z C O H n 0 1 c • A • A 0 I o i a € I 6 ., i8 c 1 13 c 17 D ° N0 Z0 O a1 ¢ w8 O E tl i S STANDARD WELL PROCEDURE HileorpAlaska,IAA: NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well} to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 • • Schwartz, Guy L (DOA) From: Ted Kramer <tkramer@hilcorp.com> Sent: Tuesday, March 14, 2017 4:22 PM To: Schwartz, Guy L(DOA) Cc: Donna Ambruz Subject: RE: KDU -1 FCO/Perforate(PTD 167-045) Attachments: STANDARD WELL PROCEDURE - NITROGEN OPERATIONS FINAL 12-08-15.pdf Guy, Thanks for the note. Sorry about missing the Safety Bulletin. I have made a note of that. Can I bring over two copies in the morning to attach? I am talking to our perforation vendors about the D-2 now.The blast joints are a problem, I am waiting on their reply for options. If it turns out that we cannot feel good about shooting through the blast joints,we will drop the D-2 perfs from the perforating schedule. I have discussed with the managers here and let them know that the D-2 perfs are not a sure thing. Ultimately, I included them in the Sundry on the off chance that we find a way to shoot them. The other option that I am pursuing is that we just run in with some primer cord across from where the D-2 perfs are shot behind and rattling the pipe with the sleeves open to dislodge any fill back there. The feeling here is that if there is a chance that we may perf them,we better sundry them. Please let me know if there are any additional questions or concerns. If you would like to discuss further, please let me know. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Tuesday, March 14,2017 3:18 PM To:Ted Kramer<tkramer@hilcorp.com> Subject:KDU -1 FCO/Perforate (PTD 167-045) Ted, Looking at the sundry to CT FCO and perforate. All Nitrogen work sundries should have the Hilcorp N2 safety bulletin attached . Also,you are re-perforating the D2 sands through tubing and blast joints. This may make any kind of work- over in the future very difficult(shattering blast jts) and not sure how much effective the perforations will be after going 1 • • thru tubing and approx. 1"of carbide. No regulation against this but just curious if vendors have modeled or experience with this type of perfing. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). 2 c (o—/- offs II ith Nolan Hilcorp Alaska, LLC `2.-(2..._-'14-- GeoTech 3800 Centerpoint Drive Z.�ZQG Anchorage, AK 99503 Tele: 907 777-8308 itik ir,, U:,+k:,.1.i.t Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATE 06/09/16 `SUN 1 0 2016 DoT tD 3f2o1 vl.K. BENDER 41-)r,":-• To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 SAMPLE TRANSMITTAL SCA"ED JAN 0 4 2Uf KDU 1 Production data Prints: Production Profile Log Production Log Interpretation Report CD1: DLIS Data 611/20169:08 AM File folder LAS Data 61//2016 9:08 AM File folder Log 6.11/20169;08 AM File folder CD2: LAS 5/31/2016 5:15 PM File folder PDF 5/31/2016 5:15 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 17)Received By:iM�� Date: RECEIVED vol- 045 JUN 1 0 2016 Company HILCORP ALASKA, LLC AOG CC Ililrorp Alaska,LU: Well Name KDU 1 Field Name KENAI DEEP UNIT State ALASKA 111 Location 411' FSL & 931' FWL Schlumberger Logged by C. Bowler Logging Date 11-May-2016 Report Date 12-May-2016 SCANNED JAN 0 5 2017 Prepared By Peter Lywood Trip Number Run Number 1 Production Services Platform 1 Production Log Interpretation Report ' SIS I 1 INTERPRETATION SUMMARY 3 I 1.1 INTRODUCTION 3 1.2 OBJECTIVES 3 1.3 TECHNIQUE 3 I 2 DATA QUALITY AND INTERPRETATION COMMENTS 3 3 TABLE 1:PRODUCTION AT STANDARD CONDITIONS 4 4 TABLE 2:PRODUCTION AT RESERVOIR CONDITIONS 4 I 5 INTERPRETATION PROFILE 5 6 BASIC SENSORS AND MATCH DATA 6 I 7 DEFT DATA 7 8 TABLE OF ABBREVIATIONS 8 9 WELL AND JOB DATA 9 I 9.1 WELL SCHEMATIC 9 9.2 SPINNER CALIBRATION 10 9.3 TOOL STRING 11 I 10 APPENDIX Z:ZONE COLOR CODE 12 I I I I I I I I I I I I I tDISCLAIMER ANY INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES, OR I RECOMMENDATION FURNISHED WITH THE SERVICES OR OTHERWISE COMMUNICATED BY SCHLUMBERGER TO CUSTOMER AT ANY TIME IN CONNECTION WITH THE SERVICES ARE OPINIONS BASED ON INFERENCES FROM MEASUREMENTS, EMPIRICAL RELATIONSHIPS AND/OR ASSUMPTIONS, WHICH INFERENCES, EMPIRICAL I RELATIONSHIPS AND/OR ASSUMPTIONS ARE NOT INFALLIBLE, AND WITH RESPECT TO WHICH PROFESSIONALS IN THE INDUSTRY MAY DIFFER. ACCORDINGLY, SCHLUMBERGER CANNOT AND DOES NOT WARRANT THE ACCURACY, CORRECTNESS I OR COMPLETENESS OF ANY SUCH INTERPRETATION, RESEARCH, ANALYSIS, DATA, RESULTS, ESTIMATES OR RECOMMENDATION. CUSTOMER ACKNOWLEDGES THAT IT IS ACCEPTING THE SERVICES "AS IS", THAT SCHLUMBERGER MAKES NO I REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, OF ANY KIND OR DESCRIPTION IN RESPECT THERETO. SPECIFICALLY, CUSTOMER ACKNOWLEDGES THAT SCHLUMBERGER DOES NOT WARRANT THAT ANY INTERPRETATION, RESEARCH, I ANALYSIS, DATA, RESULTS, ESTIMATES, OR RECOMMENDATION IS FIT FOR A PARTICULAR PURPOSE, INCLUDING BUT NOT LIMITED TO COMPLIANCE WITH ANY GOVERNMENT REQUEST OR REGULATORY REQUIREMENT. CUSTOMER FURTHER ACKNOWLEDGES THAT SUCH SERVICES ARE DELIVERED WITH THE EXPLICIT I UNDERSTANDING AND AGREEMENT THAT ANY ACTION TAKEN BASED ON THE SERVICES RECEIVED SHALL BE AT ITS OWN RISK AND RESPONSIBILITY AND NO CLAIM SHALL BE MADE AGAINST SCHLUMBERGER AS A CONSEQUENCE THEREOF. I I I 1 I I I I I I I I 1 Interpretation Summary 1.1 Introduction I A production log was run in the Kenai Deep Unit 1 well on 11-May-2016 using PSP (Production ' Services Platform). 1.2 Objectives I Production log was recorded in the KDU 1 with following objective: 1. Obtain a production profile to identify gas and water entries from the sliding sleeve and from I the open D3 and D4 sands. 1.3 Technique A 1 11/16" surface read out production logging tool was deployed on wireline. This is a deviated I wellbore, no inclination or azimuth provided by the client. The sensors present are Casing Collar Locator, Pressure, Temperature, Gamma-Ray, DEFT, PILS spinner, PFCS spinner and Gradiomanometer. There are four up and four down passes logged at 40, 80 and 120 ft/min along I with 21 station stops. 2 Data Quality and Interpretation Comments I The majority of hydrocarbon (62%) is produced from the D-2 sands through sliding sleeve #6 and #9 (from well sketch), followed by 38% from the D-3 sand. No production is observed from the D-4 I sand. Qualitatively water is observed rising in the wellbore from the D-3 sand but mainly disappears at the top sliding sleeve entry, a small amount of water is making it to surface but it is too small to quantify. The reported water rate was manually added and is likely produced from the I D-3 sand. Any water production is likely recirculating along the low side of the borehole. A slight increase in spinner and change in temperature over the sliding sleeve#9 suggest this sleeve may be leaking or partially open. The logged interval is approximately 8900 to 9622 ft. In general the data quality was good. The I full-bore spinner clearly identifies the wellbore inflows but appeared wavy and undulating. This response does not correlate with tension and is more pronounced on the full bore spinner down I passes. It is observed on both up and down passes on the inline spinner. It may be related to the completion, deviation and tool rotation. The DEFT data is of good quality and clearly identifies the transition from water in the wellbore I sump to hydrocarbon at 9555 ft. The DEFT indicates very little water is making its way to surface and therefor it is difficult to quantify any water. The DEFT also produces a wavy undulating I response and repeats from pass to pass indicating this is not caused by random slugging in the wellbore but likely mechanically related to the completion and tool rotation. The combined calipers (C1C2) read 2.5" in the tubing and 6.5" in the casing; the nominal ID 2.44" I in tubing and 6.456" in casing was used as input to the interpretation. The caliper data does appear to show the wavy undulating response which may provide evidence that the completion is responsible for the DEFT and Spinner wavy response. I Measured Production at Standard Conditions Gas = 1.34 MMscf/Day I I KDU 1 3 of 12 16/05/2016 I I 3 Table 1: Production at Standard Conditions I Zones Water Oil Gas I ft STBID STBID Mscf/D SLV#6(9087.1-9090.0) 0.00 0.00 770.61 I SLV#9(9275.0-9278.0) 0.00 0.00 48.79 D-3(9535.0-9555.0) 18.46 0.00 519.38 ITotal (inc. Bottom) 18.46 0.00 1338.78 1 4 Table 2: Production at Reservoir Conditions Zones Ot res. Production Ift B/D % SLV#6(9087.1-9090.0) 6011.96 58.44 SLV#9(9275.0-9278.0) 373.82 3.63 ID-3(9535.0-9555.0) 3901.60 37.93 IContributions by phase Zones Ow res. Oo res Og res. ft B/D B/D BID I w•O U G SLV#6(9087.1-9090.0) 0.00 0.00 601196 -„'- SLV#9(9275.0-9278.0) 0.00 0.00 373.82 , I D-3(9535.0-9555.0) 18.73 0.00 3882.87 111111.1111.111 I I II I t I I IKDU 1 4 of 12 16/05/2016 INTERPRETATION PROFILE KDU 1 I Schlumberger Company: HILCORP ALASKA, LLC Test: PRODUCTION Field: KENAI DEEP UNIT Date: 11-MAY-2016 Well: KENAI DEEP UNIT 1 Survey: Survey# 1 GR C1C2 )eptl Z WTEP WPRE WFDE DN 80 SPIN QZT QZI 0 GAPI 150 -2 in 8 (ft) 132 °F 158 330 psia 440 -0.2 g/cc 1.2 0 iv 1 1 -20 rps 110 -500 B/D11500 -100 B/D6500 8900 I If I� I I I� 9000 tl — — 01 ". iti I 91001 SLV ii I r► - 0 I 9200 I r Ic I IF _ ,1 I -1 : SLV '� 9300 0 - o 1 41110 1 _ _ I 1I 19400 _ Ii3 _ - II 2.EN 1/ C �-� ...; — �,., "r"` 1, I ) P A 0 Ir/ - r 0) { 9600 1 — )f. (- 1 fli I I. — — ale - I I I. 2 KDU 1 5 of 12 16/05/2016 I 1 Basic PSP Sensors and Match Data KDU 1 1 Schlumberger Company: HILCORP ALASKA, LLC Test: PRODUCTION Field: KENAI DEEP UNIT Date: 11-MAY-2016 Well: KENAI DEEP UNIT 1 Survey: Survey# 1 1 GR SCVL CCLD Dept!'Z WPRE WTEP WFDE SPIN SPI1 _er holdup ma'elocity matcl 0 GAPI150 -200ft/min 200 -8 8 (ft) 330psia440 132 °F 158 -0.2g/cc 1.2 -20 rps 110 -20 rps 70 -0.2 1.2 W_FLV S1,VASPIN S1,I I J_FLVZ-> S\SPINZ-> S1 0 0 0 0 1 z. 0 1> _ _ I Y 1 i Station Data I - i, \ .1, I - 51' " I 411.� o 1 F 9100 1 ' 1, I O 0 11 G IP 1 1 - -I ! _ ft , 4� 1 I �4 0 - o CD 1 I � 0 �i vvvv - 0 CO 0 ❑ 1, iti BM r „ 1ri11 9500 1p i ) 4 62 ft. _ , I W ,.., ------- f II_< j \ I �{ 9600 e iii I I � KDU 1 6 of 12 16/05/2016 DEFT Data KDU 1 I Schlumberger Company: HILCORP ALASKA, LLC Test: PRODUCTION I Field: KENAI DEEP UNIT Date: 11-MAY-2016 Well: KENAI DEEP UNIT 1 Survey: Survey# 1 DFH1 DFH2 DFH3 DFH4 rept D1RB DN 120 DN 40 DN 80 -0.2 1.2 -0.2 1.2 -0.2 1.2 -0.2 1.2 (ft) il 0 0 360 011=1E- 111 0=1=11111 0 p 1 I IIUUUIIIIIIIIIIIIIII! 7/ III ITTIlIP ({) z r 1 it) ) JMI • -__ IS .. -L tier riper, MI -- e r - _ = mm-- — _ I 0- 0 II. - teri; - y. - rte.. ,,s .r.. •f " - _ `-- +r. — at W d 11 Illi I slv d ii C i, _ I_ - ...1111111111111111111.1111.11111 KDU 1 7 of 12 16/05/2016 111 I 8 Table of Abbreviations I Tool Mnemonic Channel Description Units: Description CVEL Cable velocity I CCLD/ B/D Barrels per Day CCLC Casing Collar Locator Discriminated/Calibrated DFB112/3/ scf/bbl Standard Cubic Feet per Barrel 4 DEFT bubble count per probe I DFH1/2/3/ cp Viscosity centipoises 4 DEFT water holdup per probe ft/m Feet per minute SCV1 Depth corrected cable speed to in-line spinner I g/cc Grams per cubic centimeter SCVL Depth corrected cable speed to spinner MMSCF/D Million Standard Cubic Feet per Day GHHM2 Field calculated combined gas holdup MSCF/D Thousand Standard Cubic Feet per Day DFHM Field calculated combined water holdup Res. To denote reservoir conditions(downhole) MWFD Field pressure derived density I rps Revolutions per second GR Gamma Ray GHB1/2/3/ S.C. To denote surface conditions(uphole) 4 GHOST gas bubble count per probe I GHH1/2/3/ SCF Standard Cubic Feet 4 GHOST gas holdup per probe STB/D Stock Tank Barrels per Day SPI1 In-line spinner WPRE Pressure I PVT: Pressure Volume Temperature DPHZ Pressure derived density(from Emeraude) Bo Oil volume factor PFC1/PFC2 PSP Caliper 1 and Caliper 2 Bw Water volume factor Q Rate I Bg Gas volume factor D1 RB2 Relative bearing for probe 1 of second tool (GHOST) FVF Fluid volume factor D1 RB Relative bearing of probe 1 GOR Gas Oil Ratio SPIN Spinner(fullbore or turbine) I Holduput Ratio of produced water to total fluids WTEP Temperature Holdup Fraction of fluid present in an interval of pipe TENS Tension Uncorrected Fluid Density(from I Interpretation: UWFD gradiomanometer) WFDE Well fluid density(from gradiomanometer) Correlation Model L-G:Liquid Gas W-H:Water Correl. Hydrocarbon;O-W Oil-Water I ID Q Internal Diameter PSP Production Services Platform Cumulate Rate with continuous solution DEFT Digital First Entry Tool(Water holdup) QZI Incremental rate per zone GHOST Gas Holdup Optical Sensor Tool(Gas holdup) I QZT Cumulative Rate track with zonal contribution Regime Modeled Spinner Calibration: Slope of rps/(ft/m). Defines conversion of YG Gas Holdup Slope spinner to velocity. IYO Oil Holdup Int Intercept of line of slope(defines velocity) Difference between up/down passes. This is the YW Water Holdup Threshold velocity required to initiate rotation of the spinner. IYW FLV Water Holdup from DEFT Z Zone: Yellow-spinner calibration I Red-Perforation White-Inflow Zones Gray:Calculation(stable)zone I I IKDU 1 8 of 12 16/05/2016 I 9 Well and Job Data I 9.1 Well Schematic • - = CASING DETAIL I Size Type Wt/Grade/Conn ID Top Btm 13-3/8" Surface 61/1-55/BTC Surf 1,209' 9-5/8" Intermediate 40/J-55/6–C Surf 4,984' I r � 29/P11C STC 4,870' 8,210 Lin 29/N-80/ETC 8,210' 9,858' TUBING DETAIL 2-7/8" Tubing 6.9#4-80/ 2.441' Surf 9,048' I 2-7/8" Tubing 6.50 N-80/BTC 9,035' 9.473' JEWELRY DETAIL No Depth OD Item I 1 _5 Tubing Hanger 2 8.925 5.355" FH Hydraulic Retrievable Packer I 3 9,001 "X"Nipple 4 9,03-' 5.5" 6'Overshot — — 5 9,050' 5-5/4" I!tMJt,Ikel5on"RH-1•`Packer 6 9,087' Oris"8'Sleeve e` a 2 7 9,122' 3-3/4" Top of Baker Blast!t> I 8 9,244' 3-3/4" film of Baker Blast J El - 9 9,275' Otis''!!'Sleeve 10 9,434' 5-3/4' ..rioe'son"RH-1'Packer 11 9,472' Cas N"FI p of e 4 12 9,473' e.r cf Gu b"rc❑Sneer Nipple I PERFORATION DETAIL I EI i Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT SPF Date Status D 2 9.155' 9,175' 8;856' 8,874' 20' 4 11-09-67 Open 9;22.0 9.232' 8,906' 8,924' 20' 4 11-08-67 Open D-3 9;535` 9.515 9.201 9.219' 20' 4 11-06-67 Open I D-4 9,670' 9.720' 9.325' S.370' 50' 4 11-C6-67 Open C-2 1 El 9 g' I G: GA I TL`, MD=9811 W/9,454'T10 I 1D=9,815'KV 9,531`TMD I I KDU 1 9 of 12 16/05/2016 I I 9.2 Spinner Calibration Il Zone:-2-.-. from:9127.26ft To: 9229.311 J ,Mire zone _.. __. ( Sipe(d 0.055msApm 110 Int() -608.01ftAm Sbpe(-) N/A Ino I WOO WA 0r" l WO-„H Oftkdn 00 I User Porn a R2 0.9& 00 —' TodI _. . _. Tfneeh(r) ( 01i/min 50 Thresh(-) I orrA„e, 40 n I ac 20 ._.,.--. Tg c P_ :00 -400 ��' 1. m-TE,_ -10 I / -20 I I I I I I I IKDU 1 10 of 12 16/05/2016 I 9.3 Tool String Equip name Length MP name Offset I MH-22 34.54 ') k AH 38 32.96 II 111 EQF43[2] 32.68 I I EQF43[1] 26,68 II I I PSTP-A:80 20.68 GR 16.98 2 iii PSTC 16.68 I PSC-A:802 i:. PSTC Too 0.00 PSTC-A813 rfJ�I String B PBMS-k802 %!I ottom Sapphire 10 7 !Tempera 13.89 kPS3 /ture / Sapphire 13.78 r Pressure 1 ,CCL 13.17 PBMS 642 I Inline Sp 6..04 inner PGI4C-B.:72 12.42 4Accelero 10.91 I KWIC-B:724f meter Acceleio:72 ----Grad ioma 10.91 4 no meter PSOI_Gredi 0:3?91 I ,I___----PGMFC 7.67 PILS-A:98 7.67 9 r I PIL4A;999 Spinner 6.04 I-_-_---PILS-A 5.14 PFCS-A:80 5.14 I 7 PFQ-A 807 EPROBE[4] EPRBE[2J /Spinner er 1.87 I EPROBE[1] );1).:-//..-Caliper 1.87 TURBINE , iii Probes 1.45JPFCC-A 0.00$ ;Relative 0.00 - Bearing I 'i701 ZER9 I KDU 1 11 of 12 16/05/2016 I 10 APPENDIX Z: Zone Color Code APPLNDLX : Z TRACK COLOUR CODING Depth Z (m) I I I I Spinner calibrations zones are shown in yellow. -470. r Linear inflow zones shown Perforations = in white. are shown in red. 4801 Stable rate MOM= "11"--•‘,,,,, zones shown in -4900 grey. I KDU 1 12 of 12 16/05/2016 s • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg 1 ,1 -77-) DATE: February 22, 2016 P. I. Supervisor H FROM: Lou Grimaldi Brian Bixby SUBJECT: Use of Casing Jacks Petroleum Inspectors KDU-1 Hilcorp Alaska LLC PTD 1670450; Sundry 316-055 Sunday, February 21,2016: Brian Bixby and I went to Hilcorp's Kenai Deep Unit#1 to observe the use of casing jacks. This well has parted tubing near surface and is undergoing a workover to restore its mechanical integrity using Moncla Rig 401. Hilcorp previously attempted to unseat the tubing hanger, but were unable to get it free. Efforts were suspended over concerns that additional tension would be unsafe. Hilcorp was granted approval by AOGCC to bolt up a hydraulic casing jack unit on top of the BOPE to unseat the tubing hanger [refer to 2/20/2016 email from AOGCC Drilling Engineer Guy Schwartz]. This is the first application of casing jacks for a well wokover in Alaska (that we are aware of).Hilcorp has plans for use of casing jack for tubing workovers later this year at Endicott and Northstar but those are still under discussion. Inspection Supervisor Jim Regg requested we observe the equipment rig-up and use. Brian and I looked the casing jack over this morning. The tubing hanger was apparently freed up while Hilcorp continued last evening to work on the well with heat and pulling with the rig so the casing jack was never used. They were going to pull I the tubing hanger with the rig after getting the casing jack out of the way. Attachments: Photos (4) SCANNED SEP 2 32016 2016-0221_CasingJack_KDU-1_lg.docx Page 1 of 3 • • i 'stiwr.. 3 • ,t sr r ikii1,14- , —.4. :1,4.4 .4.,..„..-,..„.. „..i . ,,,,,,,../..,...... .:,,,ii,,141,,, w ,,,,.., , ..r . -., r '.:1. /- ...--& — ,i, :„-, I...J....- 44 1,...t. ' 4.',. .ii#— ... - . ,,,, - 1 • N''•,, .., 4.1111 ,-.,....d �;k e t ,.. , -,\~ s 4, est a" X M 0 tz 03 to a ,ISO O U a b 'i o .5 at .I — a c., ,s4 °? = . Cl. a: N S N 0 s ti NO N 03 U 111P11.11,_ 1 inE + L to J i O a � ' 1r ivii-,.. a. 0U Y C9 cz >,to CO co C C 0 CN Ol!!!!ftill ' '' U a N .13 ► • I w.w- *if'4:1114'''''''''':' ' t ii 0411111114 11'' xx f , 111 ' o O .b tb --'I s., ,) O bA" CL 4a O 2 M ~ 7-1bA 0IM 09 an.5 3 A 0-, amict I. o as � 'E °- � � U o `" a3 - -. N o t O w N O p N L .,:rNC x Jr 110114111101r"114* - 1 Y ' '''.." ,ftr...... . :Is:. 11146,:lipi - 1 - I ,:::,,,,. •. xi d fi ,° • • Moncla#401 Casing Jack Tubing Hanger Pull Procedure Sundry#316-055 014C't KDU-01 (,,1 I Notes/Well Condition: • Tubing is parted 3ft below hanger • Pulled to 10,000 lbs with tubing elevators and did not come free (do not want to exceed and have a sling shot effect if the hanger were to release) • Heat tubing hanger with multiple heater trunks Safety Note, When pulling hanger free ensure that floor is clear of people and personnel are positioned away from any line of fire. Read page 4 of the CasingJac Basic Operations brochure for additional precautions. KDU-1 Tubing Hanger Pulling Procedure with CasingJacs 1. RU hydraulic panel, warm hydraulic fluid, ensure and run unit, circulate fluids and set pressure relief on panel at 1,500 psi. 2. RU Casing Jac on top of BOP Stack(see photos below), bolt up jacks to annular and chained back to the BOP stack. 3. Cycle Jacks up and down to ensure proper function (dry run without connected to hanger) with only 2 cylinders activated. 4. Ensure well is dead (no gas on surface) circulate from tubing to casing. 5. Latch landing joint in tubing hanger, using elevators. Leave elevators attached, but not in tension. 6. Set casing jacks slips on 2-7/8" 6.5# L-80 Landing joint. 7. Set pump rate to minimum, start increasing hydraulic pressure. 8. Slowly stroke the CasingJac to 500 psi (38,480 lbs), hold for 5 min. If hanger isn't free increase pressure in 250 psi increments, holding 5 min at each increment. DO NOT EXCEED a maximum of 1,500 psi of hydraulic pressure (115,440 lbs) 80%of landing joint yield. a. If hanger does not come free, relax pressure, wait 30 min with additional heat and repeat 2 more times. b. If not free after 3 tries, notify engineer and Ops Manager to develop a new fishing plan. 9. Once hanger is free, pull tension with elevators and release casing jack slips. Pull hanger above CasingJacs and lay down. 10. RD CasingJacs and proceed with rest of the procedure. See Following pages with photos of Casinglac and descriptions Same) MAY 1 8 2016 1 • • iir Ili i - w , ) CasingJacs iii P glikir, ... , , , , ps 1 , , 1 F 1 13" spacer spool to annular r A t 13" spacer spool to annular •,•, •,.., • fi p 4 r r ig5 N"F Backup support '4X1". chains ----..• - --- r.. ''.. r , ... •- _ s-. 0 • c I 1 (i i 0 0 I 8 I . I ‘ i i ‘ l \ ti s * 4‘ \ t III 1...k. allift • • lipa r , r" i c ' ''" 4, i Valve to isolate cylinder, when both •.1 . valves closed, only 2 cylinders n,< r --fli:rt.,... .444'1Fot , 4 IC , -'''A_ • Illir 4iiik I 2"d Valve to isolate cylinder, when �`,�' 4 - both valves closed, only 2 cylinders J j,, activated )4 te O" i • rt Bottom slips always holding pipe ..' '1,, .i ' $ * -- 1, �k . mss. :: . . 14 z ' Bottom plate � � r Top slips looking from below that Y jack the pipe up. (aka jacking elevators) NI • • • Top (Jacking) plate looking from below 111 l' . • • 1 of 4 CASINUJAC MODEL 385-60-10.75 BASIC OPERATIONS The following information is limited in scope and can be subject to interpretation. All situations and jobs are different; and Casinjac Inc. provides this information as a general guide for operation of our casing jacks. Specific questions or concerns about operation should be directed to Casinjac Inc. at(405) 942-0995. 385-60-10.75 PSI LIFT CAPACITY(TONS) A NO.CYLINDERS 250 19.24 i NDIA.OF CYLINDER(IN) - 500 38.48 DIA.OF ROD SHAFT(IN) 5 750 57.73alLCYLINDER ROD DIA.(IN) 1000 76.97 °"siommulosa''" SURFACE AREA PER ROD(IN^2) 38.48 1250 96.21 RL ' SURFACE AREA IF USING(2)CYLINDERS(IN^2) 76.97 1500 115.45 1750 134.70 THE FOLLOWING ARE FOR ENTIRE UNIT 2000 153.94 or TOTAL SURFACE AREA PER UNIT(INA2) 153.94 2250 173.18 • 2500 192.42 STROKE OF UNIT(IN) 60.00 2750 211.66 VOLUME NEEDED FOR UP STROKE(INA3) 9236.28 3000 230.91 VOLUME NEEDED FOR UP STROKE(GAL.) 39.98 3250 250.15 VOLUME USED BY ROD SHAFT(INA3) 4712.39 3500 269.39 F°. VOLUME USED BY ROD SHAFT(GAL) 20.40 3750 288.63 "" ', VOLUME NEEDED FOR DOWN STROKE(INA3) 4523.89 4000 307.881 VOLUME NEEDED FOR DOWN STROKE(GE L.) 19.58 4250 327.12 « TOTAL VOLUME NEEDED FOR(1)COMPLETE STROKE(INA3) 13760.18 4500 346.36 «;lett TOTAL VOLUME NEEDED FOR(11 COMPLETE STROKE(GJ L.) 59.57 4750 365.60 hwI, MAXIMUM OPERATING PRESSURE(PSI) 5000 5000 384.85 FLOW RATE AT MAX PRESSURE(GPM) 50 Jack Nomenclature (385-60-10.75) is as follows: • 385 is maximum lift force operating on all 4 cylinders with a Hydraulic Power Unit providing 5000 psi. • 60 designates maximum stroke length, 60"or 5' • 10.75 jack is designed for 10 3/4"collared pipe and has a 12.25"ID bore through bottom bowl and top bowl. o 10.75"jack has one reducing busing for a standard 8 5/8"rotary opening. o 10.75 wellhead adaptor plate is drilled and tapped for 11", 3M, 5M, 10M flange as well as 13 5/8" 3M, 5M or 10M Flange • • 2 of 4 Basic Hydraulics — Personnel that operate and/or supervise workers that operate Casinjacs should be familiar with the basics of fluid power systems and components. • The Casinjac Model 385 —60— 10.75 is a hydraulic jack specifically designed to: o Raise and lower strings of pipe in an oil or gas well. o Stretch pipe string for various purposes. • Ithasa (1) Top bowl with insert bowls ► If a I(2) Cylinder assembly consisting of four hydraulic cylinders with a cylinder top plate and a cylinder mounting plate and two hydraulic manifolds i .. PL . I (3) Bottom bowl with insert bowls (4) Wellhead adapter plate • The top and bottom bowls have a 4/12 (API)taper and handle pipe ranges from 8.625" (8 3/8")to 10.75" (10 3/4") (See Jack Nomenclature) • The insert bowls have a 4/12 (API)taper inside and outside. They fit inside the top and bottom bowls for pipe ranges from 2.375" (2 3/8")to 8.625 (8 3/8"). • The four hydraulic cylinders have 7/000"+.005, 0.000 bore, the stroke length is 60"and the rod diameter is 5.000". • The top manifold connects the four cylinders,has a 1A" quick disconnect for use in bleeding air and pressure testing, a 11/4"quick disconnect to connect hose from hydraulic power unit to retract cylinder rods, and a connection for a '/4"hydraulic hose to pilot the counterbalance valve on the bottom manifold. • The bottom manifold connects the four cylinders,has a '/4"quick disconnect for use in bleeding air and pressure testing, a counterbalance (load holding)valve, a 1/4"connection to attach the pilot line from the top manifold, and a 1 1/4" quick disconnect to connect line from hydraulic power unit. • All 385 ton wellhead adapter plates have bolt holes drilled and tapped. (see Jack Nomenclature) • • 3 of 4 • Lift Capacity—Up to 385 tons(about 770,000 lbs.) o Each cylinder has a nominal bore area of 38.48 sq. inches x 4 cylinders= 153.92 sq. inches • Force=Pressure x Area o 153.94 x 5,000psi= 769,700 lbs. (maximum lift force using 4 cylinders) o If you choose to prescribe the lifting force, divide the desired lifting force by the area of the cylinders being used to determine the required hydraulic pressure. For example: 200,000/153.92 = 1299 psi. It is difficult to interpolate the gauge indicator needles position between graduation marks therefore it is good practice to select the nearest graduation mark. For an example if the gauge is graduated in 50 lb. increments select 1300 psi so that the indicator needle can be aligned with the graduation mark selected. Most people prefer to dial the pressure upwards to desired psi while having the joy stick in the up position as not to shock load any components, spears, drill pipe, etc. • Fluid volume to extend rods 60" o 4—Cylinders o 153.94 x 60 =9236 cubic inches or 39.98 gallons • Fluid volume to retract rods 60" o 4—Cylinders o 5" dia. Rod volume=((5/2)A2*3.1416*60*4)=4.712 cubic inches/231=20.39 gallons 39.98 gallons—20.39 gallons= 19.59 gallons • Fluid volume to extend and retract 60" o 4—Cylinders=39.98 gal+ 19.59 gal=59.57 gal o ALL 385-60 jack models can be operated on 2 cylinders by closing the two valves 180 degrees apart and unpinning the top plate from the two CLOSED cylinders. This will reduce jacking tonnage by 50%but increase jack speed by 100%. After you are finished operating the jack on 2 cylinders, re-pin the cylinders to the top plate and OPEN THE TWO CLOSED VALVES. Failure to do this will make the jack continue to run on a reduced maximum tonnage while appearing to be operating on all four cylinders and cause additional wear on the jack and its components. • Jacking Speed o The speed of jacking pipe is a function of the gallons per minute supplied by the hydraulic power unit. o At 45 gallons per minute using four cylinders this model jacks pipe at a rate of 5 ft. per 75 seconds or roughly 290 feet per hour. Time and footage can be doubled in 2 cylinder operations. • Hydraulic Oil Temperature o Pressure drops occur when oil passes over a counterbalance valve or over a relief valve. The amount of heat generated increases with the increase in pressure drop and flow rate. Attention should be given to maintaining oil temperature to proper limits. The tube carrying relieved fluid from the valve on the intensifier can become hot to touch. • • • 4 of 4 • Operation Notes: o Ensure all quick disconnects are securely made up. o Jack should never be operated without the well head adapter plate secured to jack. o As a safety precaution, Casinjac recommends having the Workover Rig elevator attached to the pull sub during jacking operations. o It is better practice to stop short of full up and down strokes (just short of full rod extension or retraction) to prevent unnecessary metal to metal contact between stop tube and head gland of cylinder. o To avoid slip lock extend jack approximately 2 feet prior to inserting slips. o To keep slips in place, Casinjac recommends tying your slip handles together in top bowl. o Ensure the insert bowls are properly/symmetrically seated in the top and/or bottom bowl assemblies and the slips are properly seated within the insert bowls to reduce the risk of crushing, warping,rp g, or parting the pipe. RECEIVED STATE OF ALASKA ALL OIL AND GAS CONSERVATION COM SION APR 2 9 2016 REPORT OF SUNDRY WELL OPERATIONS =. 1.Operations Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing U Operations shutdown H Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ 8rforate New Pool ❑ Repair Well ❑✓ Re-enter Susp Well❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development E Exploratory ❑ 167-045 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20035-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028142 Kenai Deep Unit(KDU)01 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Kenai/Tyonek Gas 11. Present Well Condition Summary: r `- L ' 1) Total Depth measured 9,895 feet Plugs measured N/A feet nA fkc true vertical 9,531 feet Junk measured N/A feet j' it'''3.a'' Effective Depth measured 9,811 feet Packer measured 9,050;9,434 feet true vertical 9,454 feet true vertical 8,761;9,109 feet Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,209' 13-3/8" 1,209' 1,209' 3,090 psi 1,540 psi Intermediate 4,984' 9-5/8" 4,984' 4,984' 3,950 psi 2,570 psi Production Liner 4,988' 7" 9,858' 9,497' 8,160 psi 7,020 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic SCAtitIE® MAY 0 9 209E 2-7/8" 9.3#/L-80 9,048'MD 8,759'TVD Tubing(size,grade,measured and true vertical depth) 2-7/8" 6.5#/N-80 9,473'MD 9,144'TVD 2 Guiberson Model RH-1 Pkr 9,050';9,434'MD 8,761';9,109'TVD Packers and SSSV(type,measured and true vertical depth) FH Hyd Ret Pkr;N/A 8,925'MD 8,647'TVD N/A; N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 540 530 Subsequent to operation: 0 1,042 75 30 71 14.Attachments(required per 20 AAC 25.070.25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations Ei] Exploratory LI Development❑✓ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas El WDSPL H Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-055 Contact Taylor Nasse-777-8354 Email tnasse(a�hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature f'fjfl�J t Phone 907-777-8405 Date y77ct 'I L eliii,_ s--3-11-, Ae- --,,,, * Form 10-404 Revised 5/2015 RBDMS ti.- MAY 0 2 2016 Submit Original Only i Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KDU-01 Moncla 401 50-133-20035-00 167-045 2/17/16 3/21/16 Daily Operations: 02/17/2016-Wednesday Held PJSM, discussed daily activities and spill prevention with Moncla Crew. Barricaded part of the pad entrance off with safety cones. Secured equip/trucks with duck ponds. Laid a 100'x75" containment. Off loaded weaver bro trailers. Accepted Moncla 401 and assoicated equipment into well. Sealed in containment. Started RU winterization for equipment. Spotted 500bbls Rain for Rent tank and filtration unit. Plan for am well kill ops. Secured location. Night watch on tower. 02/18/2016-Thursday Held PJSM, discussed daily activities and spill prevention. Hooked up flow line. MU Kelly hose from csg to rig pump. SITP/SICP 540psi - opened well to sales. Mixed 500 bbls of 3% KCL in mixing tank at G&I and filled rig pit with same. With FTP at 75psi, rolled pump over @ 2bpm, pumping 3% KCL down annulus while flowing out of the tbg. Monitored well at 150bbls, pumped away well when on a vacuum. Pumped total of 170bbls of 3% KCL. Set the BPV(2-1/2" profile threads. Disconnected flowline, ND production tree and inspected Lift treads. Hanger seals did not test so nipple the production tree back up to secure well over night. Will ND PT and NU BOP's next AM. Installed winterization for associated rig equipment. SDFN. Night man on tower. 02/19/2016- Friday Held PJSM, discussed daily activities. Well static, ND production tree and send to the well head shop for inspection. MU 2-7/8" blanking sub into lifting threads. NU 13-5/8" x 11" 5M DSA, 13-5/8" mud cross (with kill and choke valved), 13- 5/8" double gate blinds and pipe rams and 13-5/8" annulur preventer. RU rig floor, handrails, stairs and BOP skirting. Connected hydraulic lines from Koomey to stack. MU kill and choke lines. Function tested BOP. MU test jt. Filled and circulated BOPE. Shell test BOP's to 250-2,500psi. Performed BOPE test as following: valves 250-2,500psi (charted 5mins), rams 250-2,500psi (charted 5mins), annular 250-2,500psi (charted 5mins). Gas detection and Koomey drawdown. 1 F/P was record, body stem leaked, screwed in packing and retested good. AOGCC witness waived by Jim Regg. Secured well and SDFN. Night watch on tower. 02/20/2016-Saturday Held PJSM and discussed daily operations. SICP 500psi. Bled off pressure to gas buster, lined up manifold and pumped 20 bbls of 3% KCL down csg, monitored well on vacuum. Prep rig to pull pipe. Pulled blanking sub and BPV out. MU landing jt and BO lock down screws. PU 10K over,could not unseat hanger. Tried dumping diesel on top of the hanger and hitting it with hammers. Called engineer and discussed using a hydraulic csg jack to free hanger. Call OSK dock, loaded Hilcorp owned csg jack and trucked over to KDU-01 location. RU casing jack and associated equipment._ Waiting for AOGCC approval. Made 1 more attemp to pull the hanger with elevators at 10K and was unsuccessful. Secured well and SDFN. Night watch on tower. i'.')vwv J • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KDU-01 Moncla 401 50-133-20035-00 167-045 2/17/16 3/21/16 Daily Operations: 02/21/2016-Sunday Held PJSM, discussed daily activities. SICP 500psi. Bled off pressure to gas buster. Lined up manifold and pumped 30bbls of 3% KCL down the csg. Monitored well and vac with State Inspector we were swapping out the landing jt and the tbg hangerpulled free. RD casing jack and associated equipment. Spotted SL on location. MU/PU 2-7/8" fishing BHA and tallied 8" over size guide, 5-3/4" bowl, 5-3/4" upper ext and XO sub, spaced out with 10', 4', 4' 2-7/8" EUE 8RD pup jts. Worked over TOF and latched. Pulled to 40K and well stated gasing. Stabbed TIW and Kelly hose pumped 80 bbls down the tbg. Monitored tbg on vac. BO/LD Kelly hose, latched elevators and PU to find neutral weight, at 70K tubing parted 1 jt. LD joint and tallied. Tally show to be a 2-7/8" EU8RD x 3-1/2" IBT XO looking up. Discussed plan with engineer. MU OS dressed to latch 3-1/2" (4-1/4" grapple) BTC collar. TIH and could not catch fish. TOH and LD OS. MU OS dressed to latch 2-7/8"EUE collar(3-21/32" grapple). TIH and could not catch fish. TOH, LD OS inspected and found marks that measure 3-3/16". Secured well and SDFN. Night watch on tower. 02/22/2016- Monday Held PJSM and discussed daily activities SICP 500psi, Bled down csg and pumped 30bbls down well-Monitored well static. PU MU OS dessed with 2-7/8 hollow guide mill and TIH w/same. Dressed off 2-7/8" stub looking up and TOH. LD Mill and PU 2-7/8"grapple. TIH and worked cut lip guide over fish, latched on fish. PU 6K over and set in slips spaced out with pup jt at rig floor. Well started gassing. MU,TIW and Kelly hose. Pumped 60 bbls down tbg monitored well on vacuum. MIRU SL. Tested lubricator 2,500psi, test ok. MU 2.30" swedge and TIH and set down 9,066', worked down to 9,166' and POOH with drag from 9,166' to 8,997'. POOH. PU 2-7/8" tbg brush. TIH w/same and brushed tbg from 8,997'- 9,150'. POOH. PU 2.31" dummy plug and TIH to 9,180' with no drag. POOH. PU 2.31" PX plug and TIH w/same, set px plug in Otis X sleeve @ 9,076'SLM. POOH. PU px prong and RIH set in px plug @ 9,075'. POOH. PU 51" catcher sub and RIH, set on top of prong @ 9,072'. POOH. RDMO SL. Filled tbg up with 63bbls of 3% KCL, MIRU EL, MU 2" radial torch cutter to 600'. Logged up and made cut 510' (middle of a jt). POOH. RD EL. Circulated full returns for 1 hr and monitored,tbg and csg has gas still migrating up. Prep rig floor to TOH in the AM. Secured well, SDFN to let well swap. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KDU-01 Moncla 401 50-133-20035-00 167-045 2/17/16 3/21/16 Daily Operations: 02/23/2016-Tuesday Held PJSM and discussed daily activities. SICP/SITP 50psi. Bled of pressure and circulated well for 15 mins. SD pump and monitored well, static. LD Kelly hose and TIW. TOH and LD 2-7/8" workstring OS and 14-1/2"jts of 3-1/2" IBT. Calipered cut jt to 3-1/2". Inspected 3-1/2" tbg, in good condition. MU OS dressed to catch 3-1/2". Cut jt looking up. TIH w/same and latched fish at 509'. PU to 82K and set pipe in the slips. RU Pollard EL, RIH with 2-7/8" chemical cutter and tagged at 9,072'. PU and made correlation pass to 8,950'. Identified XO sub (8,990'), X sleeve (9,021') and packer at 9,055'. Set cutter on depth at 9,038' and made the cut. POOH. RD EL. Latched on pipe and PU to 90K, cycled pipe for 70K to 90K 4 times. Pipe is not free. PU to 90K and set pipe in the slips. RU EL and MU 2-7/8" chemical cutter. RIH and tagged at 9,072'. PU and made correlation pass to 8,950'. Identified XO sub(8,990'), X sleeve (9,021') and packer at 9,055'. Set cutter on depth at 9,039' (1' below 1st cut) and made cut. Tools stuck at cut depth. Worked tools free and POOH. RD EL. PU on pipe to 95K no movement, MU Kelly hose and circulated well at 4 bpm. PU on pipe to 105K, pipe started traveling up hole. Continued working pipe up hole at 115K. Made 32'. Set slips with pipe in tension. MU TIW and inside gray. Closed BOP's. SDFN. Night watch on tower. 02/24/2016-Wednesday Held PJSM and discussed daily activities, SITP Opsi. Rev circulated bottoms up and returns clean fluid. PU pipe of slips at neutral (77K). Continued working tbg from 60K to 115K made 30' in 3.5hrs. LD 1 jt and set slips. MIRU power swivel, PU sting out of slips @ 80K, continued PU at 105K, started traveling at 114K, tbg parted. Set slips. LD power swivel and TOH with 4 jts and 1 jt parted at 11'. Parted jt was bottle necked down to 2" ID. Call Anchorage and discussed plan to fish. Plan to pick up outside tbg cutter and cut 5'+/-of the TOF. Waited on Knight shop to prep tbg cutter. SDFN, night watch on tower. 02/25/2016-Thursday Held PJSM and discussed daily activities. Waited on outside tbg cutter from Knight. Adding inserts to the cutter to center the cutter over fish. Rig maintenance and cleanup. PU/MU 5-3/4" outside tbg cutter dressed for 2-7/8" tbg. Worked on power swivel. With the rig floor height they had to modify stiff arm to PU pipe. PU 5 jts and tagged TOF @ 127.5'. Set PS at 78 rpm and torque at 900psi. Worked cut lip guide over fish and swallowed 12.5'. Started rotating on pipe.Torque up on fish at 1,200psi. Rotated on fish for 80mins. With torque at 900psi. Racked back PS, POOH. LD cutter and a 10-1/2" 2-7/8" cut piece. Cut piece calipered full OD and ID. PU/MU 5-3/4" OS loaded with 2-7/8" OS. TIH latched TOF at 137'. PU 54k and set the pipe slips. MIRU EL RIH w/6-1/2' x 2" weight bars and set down at 126' ELM. Made several attemps to go thru with no luck. POOH. MU 1-11/16" CCL and RRIH to 550'. POOH. MU 2' x 2" weight bar and RIH to 550'. POOH. LD weight bar. Waited on Pollard EL to bring out anchor for RTC. MU 2" RTC with a tbg anchor. RIH to 4,760 CCL measurement. Set anchor and cut tbg at 4,772'. POOH. RDMO EL. PU on pipe, pipe is free weighing 34K. Secured well and SDFN. Night watch on tower. • S Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KDU-01 Moncla 401 50-133-20035-00 167-045 2/17/16 3/21/16 Daily Operations: 02/26/2016- Friday Held PJSM and discussed daily activities. MO power pack for PS, set cat walk and pipe racks in place. Prepped floor to trip pipe. TOH L/D 5 jts of 2-7/8" 6.5# EUE 8RD tbg, OS, 11 jts of 2-7/8" 6.5# EUE 8RD, OS and of 137 3-1/2" 9.3# IBT. Tallied pipe OOH. Inspected cut joint, no dressing required PU 2-7/8" test jt with a 11" test plug, circulated BOP stack full. Shell test BOPE 250psi-2,500psi. Tested BOPE, performed BOPE test as follows: valves 250-2,500psi (charted 5mins), rams 250-2,500psi (charted 5mins), annular 250-2,500psi (charted 5mins). Gas detection and Koomey drawdown. 1 F/P recorded on the HCR kill valve. Greased and retested good. Witnessed waived by Jim Regg. 02/27/2016-Saturday Held PJSM, discussed daily activities and spill prevention. MU/PU fishing BHA and tallied as follows: 8" oversize cut lip guide, 5-3/4" bowl dressed 3-1/2" grapple, 5-3/4" top sub,4-3/4" bumper jars,4-3/4" oil jar, 5 4-5/8" DC,4-3/4" acc.jar and 3-1/2" IF box x 2-7/8" PH6 pin. PU YT elevators dressed for 2-7/8". TIH with BHA and 151 jts of 2-7/8" 7.9# PH6. Tagged TOF @ 4,720', worked guide over TOF and latched fish. PU on pipe and pulled 130K (55K over string weight) and pulled free. Stood back 1 stand. MU Kelly hose and rev cir 1.75bpm @ 1,000psi. Circulated 100bbIs (63 bottoms up). Monitored circulation, returns dirty fluid no solids. SD pump. RD Kelly hose and racked back 1 stand. Pulled string weight 67K with no drag. Secure well, SDFN. Night watch on tower. 02/28/2016-Sunday Held PJSM and discussed daily activities. RU trash pump to the rig pit. TOH racking back 75 stands 2-7/8" PH6 workstring. LD BHA 5 drill collars,jars and OS. Swapped elevators and and slip to pull 3-1/2" IBT. TOH, LD 134 jts of 3- 1/2" 9.3# IBT at 5,066'. The jts were covered with drilling mud consistent all the way to bottom. LD XO and 1 jt of 2- 7/8" EUE 8RD, 1 2-7/8" sliding sleeve and a 14' 2-7/8" cut joint. Left 1' 2-7/8" cut piece on bottom. MIRU SL, RIH with 3" drivedown bailer and tag at 8,882'. POOH w/sample of mud and mule shoe shows tagging metal. PU 4-1/2" magnet. RIH and tagged @ 8,885', worked magnet, POOH. Recovered piece of metal. RIH with same tagged at 8,888'. Worked magnet and had over pull coming off bottom. POOH. Magnet clean. RDMO SL. 02/29/2016- Monday Held PJSM and discussed daily activities. Pumped 26bbls down the csg and pressured up to 1,100psi. SI and charted lost 90psi in 30mins. Bled off pressure. Waited on orders. Cleaned drilling mud off containment and sent to G&I MU milling BHA, 6" bit and sud, 6" string mill, oil jars and 2 4-5/8' DC tallied. TIH w/ BHA, 75 stands and 142 singles of 2-7/8" PH6. Tagged up at 8,940' (19' above 2-7/8" stab). Set down 10K and confirmed tag. Racked back 1 stand. Secured well and SDFN. Night watch on tower. s • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KDU-01 Moncla 401 50-133-20035-00 167-045 2/17/16 3/21/16 Daily Operations: 03/01/2016-Tuesday Held PJSM and discussed daily activities. Rev circulated well, bottoms up dirty water. SD pump and PU power swivel. Closed hydrill and could not circulate while rotating thru bag. NU 13-5/8" x 7-1/16" spool on top of annular. NU 7-1/16" halls head. PU power swivel and rotated on pipe. Rolled over pump, rev circulating at 1.5bpm 1,100psi. Slacked off and tagged 8,940' drilled off down to 8,944'. Pump pressure increased to 1,200psi with no returns. SD pump. Swap valves and pumped down tbg 3.5bpm @ 300psi. Continued rotating pipe down and tagged at 8,962'. SD PS and confirmed tag on top of 2-7/8" stub. Lined valves to rev circulate. Rolled pump over and could not circulate. SD pump. RD PS and TOH racking back 146 stand and 4 DC. LD string mill and bit. MIRU SL, RIH w/4-1/2" LIB and tagged 8,994'. POOH. RIH w/4-1/2" magnet and tagged at 8,988'. POOH, pulled heavy for the first 50' recover metal shavings. RIH with same and tag 8,994'. POOH, drag first 50' magnet clean. RDMO SL. Secured well. Night watch on tower. 03/02/2016-Wednesday Held PJSM and discussed daily activities. Waited on orders. PU/MU BHA, OS dressed to catch 2-7/8" (7" short catch), jars, 2 4-5/8" DC. TIH w/same and 146 stands and 1 single of 2-7/8" PH6 to 8,958' (4' above stub). MU Kelly hose to tbg. Rolled pump over at 2.5bpm/900psi, rev cir 25bbls returns mud and pressure increased to 1,000psi/.7 bpm. Continued circulating pressure, climbed to 1,100psi and lost returns. Pumping in well at .6bpm/1,100psi, lost 10bbls. SD pump. Total returns 110bbIs 90 of heavy mud. Swapped valves and pumped 20bbls down the tbg @ 2.5 bpm/1,000psi. Returns 1/1 up csg. SD pump. Discussed plan with Anchorage. RD Kelly hose. Pick up weight 57' and stack off 52'K. Stacked off of pipe and tagged TOF @ 8,964' (2' Deeper than previous tag). Continued working OS to latch fish. Never saw any over pull after working grapple of fish. TOH standing back workstring and DC. L/D OS. No fish. Inspected OS metal marks 8" deep inside cut lip. Secured well and SDFN. Night watch on tower. 03/03/2016-Thursday Held PJSM. Discussed plan with Anchorage. Knight building a series 70 short catch OS to run on pipe. MIRU SL, RIH w/6" LIB, had to work down from 5,000' to TOF at 8,994' SLM. Tap LIB on top of fish with the jar. POOH. LIB showed picture of junk just of center. PU 4-1/2" magnet and RIH tagged TOF @ 8,994' SLM. POOH, slow at 100fpm. Recovered metal shavings. PU EOT locator to catch 1" 2-7/8" stub and TIH tagged 8,994'SLM. Worked to latch pipe with no luck. POOH. PU a GS/PR spear(2.441" grapple tags) and RIH tag 8,994'SLM. Could not latch up. POOH. RIH with same, tagged at 8,994'. Worked and did not latch up. POOH . Metal marks show grapple may be to inside pipe. RIH w/same and added a centralizer. Worked grapple. POOH, more metal marks of pipe on tool. Added spearable knuckle joint and RIH w/same. Tagged at 8,994', worked grapple, had 500#over pull, POOH, no fish. RD SL. Secured well, SDFN. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KDU-01 Moncla 401 50-133-20035-00 167-045 2/17/16 3/21/16 Daily Operations: 03/04/2016- Friday Held PJSM, discussed daily activities. MU test plug and 2-7/8" test jt. Circulated stack. Pressured up test pump and blow a fuse on the pump. Repaired test pump. Cleanup work areas. Pressured up on stack and could not get a shell test. Troubleshoot and found test plug was not holding. Continued pressuring up and finally got the test plug to seat. Performed a good shell test. Notified inspector, performed BOPE test as follows: annular 250-1,500psi,valves 250- 2,500psi, rams 250-2,SOOpsi. Performed Koomey drawdawn and gas detection rest. 1 F/P recorded HCR kill valve, replaced packing and retested good. AOGCC State inspector Lou Grimaldi witnessed BOPE Test. LD Test Jt. Prep rig floor to TIH am. Secured well and SDFN, night watch on tower. 03/05/2016-Saturday Held PJSM and discussed daily operations. MU BHA tallied as follows: 5-7/8" OS (2-7/8"grapple), 5-3/4" top sub,4- 3/4" bumper jars,4-3/4" oil jar, 2 4-5/8" DC and XO 2-7/8" PH6 box x 3-1/2" IF box. TIH w/BHA and 146 stands of 2-7/8" PH6 to TOF at 8,960'. RU Kelly hose and circulated 20bbls down tbg up csg to clean fish top off. Stacked off and tagged fish @ 8,966' (2" deeper that previous tag with pipe). Worked and rotated OS over fish. PU 3K over and slipped off. Made several attemps to catch fish. Pulled 1 jt and tbg flowing, opened tbg and csg to balance well with mud in the hole. TOH standing back workstring, LD BHA did not recover fish. Cut lip on OS, was rolled in with pipe marks indicating that the fish and stub are side by side. Discussed plan with Anchorage, PU a mill AM. Secured well and SDFN. Night watch on tower. 03/06/2016-Sunday Held PJSM, discussed spill prevention and daily activities. MU/PU BHA as follows: 6" concaved mill, 2 boot baskets, bit sub,jars, 2 4-5/8" DC,TIH w/BHA and 2-7/8" PH6 workstring and tagged 4K down on TOF @ 8,967' . NU halls head to 13-5/8" annular, PU/MU power swivel and Kelly hose. Rolled pump over @ 2.5bpm/650psi circulating the long way. Started rotating pipe, slacked off and tagged TOF @ 8,967' pushing fish down hole 4'. Stopped rotating SD pump and PU 10' off fish. Worked back down, tagged and pushed fish down to 8,988' (total of 19') and started taking weight. Started rotating and pumping 2bpm/650psi. Milled off 1' and SD pump to break connection and PU 1 single. PU single and started rotating and milled off 2' (3'total) circulations 1/1 @ 2.75bpm/650psi. Returns heavy mud and could not filter it from pit to the Rain for Rent tank. SD pump due to high pit level. Called for vac truck support. Mixed 400bbls of KCL in mixing plant, hauled 170 bbls of heavy mud from rig pit to G&I. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KDU-01 Moncla 401 50-133-20035-00 167-045 2/17/16 3/21/16 Daily Operations: 03/07/2016- Monday Held PJSM, discussed daily activities and housekeeping. Filled Rain 4 Rent tank with 3% KCL. Finished cleaning mud out of rig pit. Waited on orders. Opened well, rolled pump over and broke circulation the long way @ 1.75bpm/400psi. Started rotating pipe and slacked off pipe. Tagged TOF at 8,988'. Milled 6" and chased fish down 1'. Continued milling on fish, returns 9.2# mud with metal shavings. Hauling pits to G&I. SD pump due to halls head rubber leaking. Replaced halls head rubber. Started back circulating and rotating pipe, slacked off and milled down to 8,993' (total of 5' off 2-7/8" stub). SD power swivel. Returns clean fluid and metal shavings. Circulated bottoms up at 4bpm/1,250psi. SD pump returns clean fluid with metal shavings. RD power swivel and Kelly hose,TOH standing back 2-7/8" workstring and DC, LD Jars, 2 boot basket(full of metal shavings) and mill. Inspected mill,took pictures and sent to Anchorage. Night watch on tower. 03/08/2016-Tuesday Held PJSM, MIRU SL, RIH w/5-1/2" LIB tagged at 9,008' SLM. POOH. LD LIB. Impression of junk. PU 3" pump bailer and RIH to TOF @ 9,010. Bailed down 2' to 9,010'. POOH, bailer bottom impression of stub looking up. Recovered 2 gals of sand, no metal. RIH w/same and tag at 9,010', bailed and POOH. 2 gals of sand recovered. RIH w/same and tag at 9,010', bailed and POOH. 2 gals of sand recovered. RIH w/same, no centralizer and tagged at 9,006'. Bailed, POOH. Metal marks on bottom, possible csg collar. Recovered 2 gals of sand. No metal. PU and RIH w/4-1/2" LIB tag at 9,006'. POOH, no impression. PU 3" drivedown bailer. RIH and tagged @ 9,004'. Could not make hole. Lost jar action. POOH, recovered 2 gals of sand. 2 metal marks on bottom of muleshoe show possible csg. Discussed plan with engineer. Pumped 26bbls of KCL down tbg and pressured up with 4bbls to 1,250psi charted for 30 mins, good test. PU/MU 2-1/4" drivedown bailer, RIH and tagged at 9,004'. Worked down to 9,006'. POOH. Bailer was empty due to flapper valve hung open. RIH w/same tagged @ 9,003', bailed down to 9,004'. POOH. Bailer full of sand no metal marks. PU 6" GR and RIH, tagged at 9,001'. POOH. RDMO SL. Secured well. SDFN. Night watch on tower. 03/09/2016-Wednesday Held JSA. MU and tallied BHA as follows: shoe wave bottom, 8' washpipe ext, top bushing, XO 3-1/2" IF x 2-7/8" EUE, 1 Jt of 2-7/8" EUE, XO 2-7/8 EUE x 3-1/2" IF, bumper jars, oil jars, 2 drill collars and XO 3-1/2" IF x 2-7/8" PH6. TIH with BHA and 290 jts of 2-7/8" PH6. Tagged up at 8,941'. Set down 4K and confirmed tag PU 10' and set slips. MU halls head, power swivel and Kelly hose. Repaired power swivel (rig time). PU 1 single and and MU PS. PU on pipe and slacked off 10', tag 8,941'. Started rotating and worked down 3', PU 6K over and pulled free. Rolled pump over rev cir @ 2 bpm/500psi, broke cir and continued rotating. Slacked off and worked washpipe down thru 8,941'to 8,946' tight spot. Continued downhole to 8,961'. Set slips and cir bottoms up, returns trace of sand. SD power swivel and pump, PU 1 single and continued rotating downhole pumping 2bpm/600psi, washed down to 8,991'. Returns heavy sand. Continued circulating until returns cleaned up. SD pump and power swivel, PU 1 single and continued rotating and rev circulating 2bpm/600psi. Slacked off washed over 2-7/8" stub down to 9,001'. Bottomed out on stub and pump pressure increased with lost circulation. PU 2' and pump pressure decreased with full returns. Rev circulated 2 bottoms up at 3 bpm/700psi. Monitored, returns sand after 1st bottom ups and clean after 2nd bottoms up. Hung back power swivel in the goose neck. Stood back 3 stands. Secured well and SDFN. Night watch on tower. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KDU-01 Moncla 401 50-133-20035-00 167-045 2/17/16 3/21/16 Daily Operations: 03/10/2016-Thursday Held PJSM discussed. Cleaned work area. TIH w/3-stands of 2-7/8" PH6 and 16' of pups from spaceout, worked washpipe over 2-7/8" stub @ 8,993', bottom of the shoe @ 9,001'. Worked over without rotating or pumping. MU Kelly hose and rev circulated 100bIs returns 8.4 ppg dirty fluid no solids. SD pump stacked off 3K down on stub. Set slips. MIRU SL, MU 2" bailer and RIH tagged up at 9,024'. No issues running thru the 2-7/8" stub. POOH, RDMO SL. Spotted pipe racks, ND halls head, MU stripping rubber. TOH LD 292 jts of 2-7/8" PH6 and BHA. Metal marks on the outside of washpipe. 03/11/2016- Friday Held PJSM and discuss daily activities. PU/MU 2-7/8" test jt and 11" test plug. Circulated stack full. Pressured up on test plug to 3,000psi to seat plug. Make several attempts. With plug seated performed the shell test, good test. 0()P Performed BOPE test as follows: annular 250-1,500psi,valves 250-2,SOOpsi, rams 250-2,500psi. Performed Koomey ,r; - drawdown and gas detection test. No failures recorded. AOGCC witness waived by Jim Regg. Tallied 2-7/8" 6.5 EUE 8RD tbg, PU/MU 5-1/2" tubing overshot for 2-7/8" tbg, 1 joint of 2-7/8" 6.5 EUE 8RD, 2-7/8" X-nipple, 2 joints of 2-7/8" 6.5 EUE 8RD, 7" FH hydraulic packer and 2-7/8" 6.5 EUE 8RD to liner top @ 4,870'. Worked thru, slow trip due to every 2- 7/8" collar tagging the liner top. Continued TIH to 5,576'. Set slips and secured well. SDFN. 03/12/2016-Saturday Held PJSM and discussed daily activities. Continued TIH with completion to 8,993' pipe measurements. Stripped over halls head and PU 1 jts. MU TIW and Kelly hose. Rolled over pump @ 1.5bpm/Opsi rev circulating. Broke circulation, slacked off and did not locate stub. SD pump. PU 1 jts and slacked off tagging 2' in on jt @ 9,026' pipe measurements. LD 1 jt and PU 10' pup jt, rolled pump over 1.5bpm/Opsi to establish circulation. Slacked off and tagged stub with no increase in pump psi. Set down 2K trying to fall over stub. Continue working pipe and could not get over stub. Rev circulated 100bbIs returns dirty fluid no solids. SD pump. MU tbg swivel and Kelly hose. Rolled pump over and rotated pipe, slacked pump pressure increased, worked OS 5' over 2-7/8" stub. Marked pipe. MIRU SL, RIH w/2.3" GR and tagged 9,024' slm. POOH. PU 2.25" pump bailer, RIH, tagged @ 9,024' slm. Bailed and POOH, recover 2 pieces of metal shavings and a half 0-ring. PU 2.31" PX plug, RIH, set plug in X-nipple @ 8,918'. RD SL. Marked pipe, ND halls head. LD pups and 1 jt. PU 10', 8' ,6' pup jt. MU, hung and landed completion with OS 4' over stub. String weight 42K up/38K down. RILDS. RU SL, RIH 2-1/2" GS pulling and latched px-plug @ 8,918'. RD slickline. MIRU EL, MU 1-11/16" CCL. RIH at 9,032'ELM, could not get inside stub. POOH. RD EL. Secured well, SDFN. S Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KDU-01 Moncla 401 50-133-20035-00 167-045 2/17/16 3/21/16 Daily Operations: 03/13/2016-Sunday Held PJSM. Lined up pump to csg, opened tbg side to rig pit. Rolled pump over and pressured up on csg to 500psi. Held to confirm OS is swallowing 2-7/8" stub. Bled off pressure. RU SL, RIH w/1.75" drive down bailer and tagged at 9,031' slm. Bailed, could not make hole. POOH, metal marks on mule shoe. No solids recovered. PU a 2.24" LIB. RIH, tagged 9,029'. POOH 300psi over pull coming off bottom. Impression might be LIB going inside stub. PU 2.31" px-plug. RIH, set plug @ 8,988' slm. POOH. PU px prong and set in plug at 8,987' slm. POOH. RD SL. MU Kelly hose to csg and tbg. Opened csg and pressured up to 3,700psi to set pkr, charted for 30 mins, good test. Bled off pressure. Opened tbg and pressured up on csg to 1,500psi charted for 30 mins,good test. Bled off pressure. LD landing jt and set BPV. NU 13-5/8" BOP stack/NU production tree, test 5,000psi, good test. Pulled BPV. RD Moncla 401 Lnd associated equipment. Night watch on tower. moi;' 03/14/2016- Monday Held PJSM, RDMO Moncla 401 and associated equipment, Mobe to Moncla's Yard. 03/16/2016-Wednesday Pollard arrive at KGF and meet with Dave K. and did safety meeting and JSA. Pressure tested lubricator and made sure WLV's are good. RIH with 2.25" pump bailer to 9,034'. RIH with 1.75" hydrostatic bailer with 2" fill tube to 9,037'. Ran baited on RB pulling tool. RIH with 2" pump bailer to 9,037'. RIH with 1.75" hydrostatic bailer with 2" fill tube to 9,039'. Ran baited on RB pulling tool. RIH with 2" pump bailer to 9,040'. RIH with 1.75" hydrostatic bailer with 2" fill tube to 9,041'. Ran baited on RB pulling tool. RIH with 2" pump bailer to 9,041'. RIH with 1.75" hydrostatic bailer with 2" fill tube to 9,043'. Ran baited on RB pulling tool. RIH with 2" pump bailer to 9,044'. RIH with 1.75" hydrostatic bailer with 2" fill tube to 9,046'. Ran baited on RB pulling tool. Lay down lubricator and pull wire. Re-head to 1.25" tool string. Secure well for the night and sign off on the permit. 03/17/2016-Thursday PJSM. Rig up. PT Lub and WLV. RIH W 1.31" gauge ring to 9,046' KB. Beat down. Fill is solid. POOH. Make 10 bailer runs. Alternated BTW. 1.75" hydro-static and 2" pump bailers. Started at,9046' ended at 9,056'. Laid down equipment for the night. Pulled wire and re-headed TS to 1.75"tools. Ready to start swabbing 2-7/8" tubing tomorrow. 03/18/2016- Friday Arrive at KGF and have a TGSM, and fill out JSA and PTW. RIH with 2-7/8" swab mandrel and swab cups. Tag fluid at 99'. Make 19 runs swabbing fluid to tank. Swabbed to a depth of 5,180" unloading 26.34 bbl's to the tank. Lay down lubricator, cut wire, and re-head. Secure well for the night. Turn in PTW and sign out. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date • • KDU-01 Moncla 401 50-133-20035-00 167-045 2/17/16 3/21/16 Daily Operations: 03/19/2016-Saturday Arrive at KGF, do a TGSM, sign in, and do a JSA. Rig up slick line, PT lubricator, WLV are good. RIH with swab cups and start swabbing at 5,080'. Make 13 swab runs to a depth of 6,080'. Total fluid swabbed from tubing is 32.7 bbl's. Reached target fluid level. RIH with 2.25" pump bailer to 9,038' and work to 9,047'. Full fluid. RIH with 2" pump bailer to 9,055'. Work tools and POOH, full of thick slurry. RIH with 2" DD bailer to 9,056' and work to 9,058'. POOH with full bailer of slick slurry. RIH with hydrostatic bailer to 9,061' and POOH with full bailer. RIH with 2" DD bailer and POOH with full bailer. Lay down lubricator and secure well for the night. Turn in PTW and sign out. 03/20/2016-Sunday PJSM, work permit. Pick up lubricator. RIH with 2" drive down bailer to 9,060' KB RIH with 1.75" hydro-static bailer to 9,061' Made 10 runs with a 2" pump bailer. Starting depth was 9,062'. Ending depth was 9,076'. RIH with 1.75" pump bailer.Trying to clear fishing neck on catcher sub. No indication of metal to metal contact on bailer bottom. RIH with 2.25" D.D. bailer to 9,076'. Made 4 small file marks on bottom of 2.25"bailer. If we set down on catcher sub fishing neck we hope to flatten bailer bottom enough to indicate a metal to metal contact. POOH No indication of metal to metal contact. Lay down lubricator. Cut wire. Re-head and put new packing in stuffing box. 03/21/2016- Monday PJSM and work permit. Rig up slick line and PT lubricator. RIH w 2-1/2" GR pulling tool. Did not make it to fishing neck on catcher sub. Made 5 runs with a 2" by 14' drive down bailer. Started at 9,078' and ended at 9,086'. RIH w 1.75" pump bailer.Attempted to get bailer inside of catcher sub fishing neck. Needed several jar licks to get free. RIH with 2- 1/2" GS pulling._tool to pull catcher sub. RII1 with 2"JDC pulling tool, couldn't latch prong. RIH with 2" pump bailer to 9,090' KB. Came back with 3 cups of course sand. RIH with 2"JDC latched prong at 9,090'. Had to get tough with it. Oil jar and spang licks for 15 minutes before at came free. POOH with prong. RIH with 5' of stem btw. spangs and 2-1/2" GS pulling tool. Latched PX plug at 9,092' and pulled plug. Lay down lubricator and secure well for the night. Pressure already building at the surface. t ,ll • SCHEMATIC • Kenai Gas Field Well:KDU 01 Date Last Completed: 1143-67 PTD: 167-045 11,1..0,, el:,L t.ii( API#:50-133-20035-00 KB to Hanger=15' 1 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 13-3/8" Surface 61/J-55/BTC Surf 1,209' 9-5/8" Intermediate 40/J-55/BTC _ Surf 4,984' 7" Liner 29/P110/BTC 4,870' 8,210 29/N-80/BTC 8,210' 9,858' 13-3/ - TUBING DETAIL 2-7/8" Tubing 6.5#/L-80/EUE 2.441" Surf 9,048' 2-7/8" Tubing 6.5#/N-80/BTC 9,035' 9,473' JEWELRY DETAIL No Depth OD Item 1 15' Tubing Hanger 2 8,925' 5.968" FH Hydraulic Retrievable Packer 3 9,001' "X"Nipple 4 9,034' 5.5" 6'Overshot - 5 9,050' 5-3/4" Guiberson"RH-1"Packer 6 9,087' Otis"X"Sleeve 9-5/8'2 tt / 2 7 9,122' 3-3/4" Top of Baker Blast Jts 8 9,244' 3-3/4" Btm of Baker Blast Jts 3 9 9,275' Otis"X"Sleeve 10 9,434' 5-3/4" Guiberson"RH-1"Packer T ' 11 9,472' Otis"N"Nipple 8,94r-8,946'. � ! 44Possiblecasing 12 9,473' Btm of Guiberson Sheer Nipple I Mk /damage at 9,004' 1 N. V 5 PERFORATION DETAIL 6 Sands Top(MD) Btm(MD) Top(ND) Btm(ND) FT SPF Date Status D-2 9,155' _ 9,175' 8,856' 8,874' 20' 4 11-09-67 - Open 9,210' 9,230' 8,906' 8,924' 20' 4 11-08-67 Open D-3 9,535' 9,555' 9,201' 9,219' 20' 4 11-06-67 Open 0-4 9,670' 9,720' 9,325' 9,370' 50' 4 11-06-67 Open - 62 _}. 8 9 10 m. 11 IN D3 = 64 sltr 1�t 7L PBTD=9,811'MD/9,454'ND TD=9,895'ND/9,531'ND Updated by DMA 04-19-16 Pti • \CO1d45 OF To_ sA THE STAT Alaska Oil and Gas 0AT cKA Conservation Commission gra = " 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 g ain: 907,279.1433 of ALA`91- MFax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson C EE EE 6 6 Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 t ( ©tt`r Anchorage,AK 99503 Re: Kenai Field, Tyonek Gas Pool, KDU 01 Permit to Drill Number: 167-045 Sundry Number: 316-055 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P Foerster Chair DATED this 3 day of February, 2016. RBDMS FEB 0 4 2016 • • RECEIVED STATE OF ALASKA JAN 2 6 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION OTS 2./3// APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 ., 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ (-°,.Repair Well Q' Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing Q • Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: N2 Jetting ❑� • 2.Operator Name: Hilcorp Alaska, LLC 4.Current Well Class: 5. Permit to Drill Number: Exploratory ❑ Development ❑✓ • 167-045 3.Address. 3800 Centerpoint Drive,Suite 1400 Stratigraphic El Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20035-00 7. If perforating: 8.Well Name and Number: {e4 T-4.)• What Regulation or Conservation Order governs well spacing in this pool? CO 510A �` Kenai Deep Unit(KDU)01 ❑ Will planned perforations require a spacing exception? Yes ❑ No R 9.Property Designation(Lease Number): 10. Field/Pool(s): FEDA028142 Kenai I Tyonek Gas 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 9,895' • 9,531' • 9,811' 9,454' 1,313psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor Surface 1,209' 13-3/8" 1,209' 1,209' 3,090 psi 1,540 psi Intermediate 4,984' 9-5/8" 4,984' 4,984' 3,950 psi 2,570 psi Production Liner 4,870' 7" 9,858' 9,497' 8,160 psi 7,020 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: 3-1/2" Tubing Grade: 9.3#/N-80 Tubing MD(ft): 8,984'; See Attached Schematic See Attached Schematic 2-7/8" 6.5#/N-80 9,473' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): 2 Guiberson Model RH-1 Pkrs;N/A 9,050'MD-8,761'TVD:9,434'MD-9,109'TVD; N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑� Exploratory ❑ Stratigraphic ❑ Development❑✓ Service ❑ 14. Estimated Date for 15.Well Status after proposed work: CommencingOperations: February 8,2016 OIL WINJ WDSPL p ❑ ❑ El Suspended ❑ 16.Verbal Approval: Date: GAS [ • WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse-777-8354 Email tnasse@hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature (. �/ff, Phone 907-777-8405 Date //Z(`i//6 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Lt.- 0G5 Plug Integrity ❑ BOP Test [irt Mechanical Integrity Test ❑ Location Clearance�j ❑ -7—' j Other: if 2 J ( (3,_, 5)f -- 4j t ( r .,:,-. 66) r s.., /4-ei. ( 'e l-/ Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No V Subsequent Form Required: i , - y C Y /� / APPROVED BY Approved by: 4 /}n� �j , `/._ COMMISSIONER THE COMMISSION Date: 2.. • 3- /‘ ./7-ai`�j�7--��"�� Submit Form and Form 10-4r•Revised 11/2015 090,1ALNIAluc,for 12 months from the date of aAttachments in Duplicate RBDMS c' ppFEB 0 4 2016 Z z.7.4, 0 • Well Prognosis Well: KDU-01 IIiI,"'"'t!a,.La.I.L Date:01/25/2016 Well Name: KDU-01 API Number: 50-133-20035-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: 02/08/16 Rig: N/AHio,,,,L,_ -j o I Reg.Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 167-045 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907)903-0341 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(M) AFE Number: Current Surface Pressure: 530 psi Maximum Expected BHP: —2,250 psi @ 9,370' TVD (Based on 12/17/14 SIBHP survey of offset well KBU 42-06Y in D-3 sand) Max. Potential Surface Pressure: 1,313 psi (Assumed 0.10 psi/ft gas gradient) Brief Well Summary KDU-01 was drilled as a grassroots well to target gas sands in the Tyonek formations. Sometime during the life of the well the tubing parted at around 4' below the tubing hanger, and production was halted in May 2015. At the time the well was shut-in it was making 2.2 MMCF/D @ 135 psi from the Tyonek D-3 and D-4 sands. " The purpose of this work/sundry is to run a new completion to reestablish tubing/inner annulus isolation. Notes Regarding Wellbore Condition • Tubing and casing will be filled full of produced fluid before the tubing is cut. • Safety Concerns(if coiled tubing letting is performed) C c,, ,,t s ••e,�r,7 / • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter, i.e. near flow-back tank. • Consider tank placement based on wind direction and current weather forecast (venting methane and Nitrogen during this job) • Ensure all crews are aware of stop job authority WO Rig Procedure: 1. MIRU Moncla #40`.W.0 Rig. ib 2. Kill well with 8.4 ppg 3% KCI inhibited fluid down tubing. ��L 1>Z�� 3. Set BPV. ND Tree. 4-- 4. NU 13-5/8" BOPE. Test to 250 psi Low/2,500 psi High, annular to 250 psi Low/1,500 psi High (hold each valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Test VBR rams on 2-7/8" test joint and 3-1/2" test joint. 5. Bleed any pressure off tubing. Pull BPV. a. Kill well with 8.4 ppg 3% KCI (if necessary). 6. MU landing joint. 7. POOH. Lay down 2-7/8" tubing hanger and tubing (Length approx. 4-6 ft.). 8. PU overshot. 9. RIH w/2-7/8" tubing to top of parted tubing at+/-26'. 10. MIRU slickline. • • Well Prognosis Well: KDU-01 Hacorp Alaska,LL Date:01/25/2016 11. Make gauge ring run to 9,472'. POOH. 12. RIH and set plug in Otis"N" nipple at 9,472' (to minimize amount of fluid on zone). 13. Dump bail sand on top of plug and prong. i.4.4---- ; 5�J--e..,,e. . 14. RD slickline. 15. RU e-line, PT lubricator to 2,500 psi Hi 250 Low. 16. MU chemical cutter/radial torch. a. Have backup cutters on location if tubing does not part. 17. RIH to ±9,035' and make cut approx. 15' above existing packer. POOH. 18. RD e-line. 19. POOH with the 2-7/8" and 3-1/2" tubing and laydown tubing. Inspect cut tubing to determine if tubing stub needs to be dressed off. 20. MU bit/mill and casing scraper for 7" and RIH to top of tubing stub w/new 2-7/8" 8RD EUE tubing. 21. Circulate bottoms up x 2 with 8.4 ppg 3% KCI. 22. SOOH. Lay down mill and scraper. Rack back 2-7/8"tubing. 23. MU completion per the proposed schematic, consisting of: a. 2-7/8" tubing overshot guide ,. /I-- --,:, .1- ,! b. 2-7/8" tubing joint c. 2-7/8" "X" nipple w/RHCP ball catcher d. 2-7/8" tubing joint e. 7" FH hydraulic retrievable packer " f. 2-7/8" pup joint g. 2-7/8" tubing to surface 24. RIH with 2-7/8" completion to just above tubing stub. 25. Obtain accurate pick-up and slack-off weights and record same. 26. Slowly lower overshot guide over stub. Monitor weight indicator. 27. Slack off until you begin to take weight and stop. i 28. Pick up to "pick-up" weight and stop. 29. Rig up pump in sub, close annular preventer and apply annulus pressure. Pressure should build and possibly leak off indicating a seal or partial seal over tubing stub. 30. Release pressure on preventer and mark tubing. Pick up and space out to position overshot and packer in neutral (pump/circulate corrosion inhibitor down annulus). 31. Slack off and engage tubing stub. Land tubing in hanger. 32. Rig up slickline above pump in sub. 33. Make gauge ring run through overshot and tubing stub to access lower portion of completion BHA. POOH. 34. Pick up RHCP ball and RIH. 35. Set plug in X nipple just below FH packer. 36. Pressure the tubing to 2,500 PSI and hold for ten minutes to set packer. 37. Release pressure. 38. Test tubing to 2,500 psi for 30 min. 39. RD wireline. 40. Close preventer and test packer/tubing annulus to 1,500 psi for ten minutes. 41. Release annulus pressure and open preventer. 42. Set BPV. ND BOPE. NU tree. Pull BPV. 43. Set TWC.Test tubing hanger and tree to 250/5,000 psi. Pull TWC. 44. RD Moncla #401 WO Rig. 45. Replace IA x OA pressure gauge if removed (9-5/8" x 13-3/8"). • • Well Prognosis Well: KDU-01 Iliicor)Alaska,LL, Date:01/25/2016 Slickline Procedure: 46. MIRU Slickline, PT Lubricator to 2,500 psi Hi 250 Low. 47. Make gauge ring run to 9,001'. 48. RIH and pull RHCP at 9,001'. 49. Bail sand/debris off of x-plug at 9,472'. 50. RIH and pull plug in Otis "N" nipple at 9,472'. 51. RIH with bailer and tag bottom. 52. Swab well as deep as possible. 53. RD Slickline. 54. Turn over to production. Coiled Tubing Procedure (if unable to swab well on): �' 4 -' 55. Submit 24 hr. witness notification to AOGCC via web base notification. 56. MIRU Coiled Tubing, PT BOPE to 250/4500 psi. 57. Isolate production flow line. Route well production to open top diffuser 400 bbl tank. 58. Pressure test N2 lines to 4,500 psi prior to starting job. 59. RIH w/ 1.5" coil w/2"jet nozzle BHA. a. Start pumping N2 at 800 scf at 8,000 ft b. Increase N2 rate as necessary while RIH to 9,811' MD and tag PBTD. Once N2 has reached return tank start pinching in choke (Maintain approximately 200-300 psi). 60. PU slowly to 8,000ft monitoring tank for fluid. Cycle between 8,000' and 9,811'one more time pumping N2 to lift well. Strap return tank until estimated volume of fluid recovered. If fluid rate is substantial continue to cycle between intervals. Use LEL monitor to sniff for gas on Return tank. 61. POOH w/coil. LD 2"jet nozzle BHA. 62. Bleed N2 off well and put well into production. 63. If well does not flow as predicted, SI overnight and repeat. 64. If well rates are acceptable RD Coiled Tubing. 65. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Wellhead Diagram 4. Moncla 401 BOPE Schematic 5. CT BOPE Schematic 6. CT Schematic(forward and reverse jetting) • 41) Kenai Gas Field Well: KDU 01 SCHEMATIC Date Last Completed: 11-13-67 PTD: 167-045 liilcorp Alaska,LLC API#:50-133-20035-00 KB to Hanger=15' 1 fCASING DETAIL fileluting 8 2 � Size Type Wt/Grade/Conn ID Top Btm 13-3/8" Surface 61/1-55/BTC Surf 1,209' 9-5/8" Intermediate 40/1-55/BTC Surf 4,984' 29/P110/BTC 4,870' 8,210 7" Liner 29/N-80/BTC 8,210' 9,858' 13-3/8k > TUBING DETAIL 3-1/2" 9.3#/N-80/BTC Surf 8,984' 2-7/8" 6.5#/N-80/BTC 8,984' 9,473' JEWELRY DETAIL No Depth OD Item 1 15' Tubing Hanger 2 51' 2-7/8"x 3-1/2"Cross Over 3 8,984' 3-1/2"x 2-7/8"Cross Over 4 9,015' Otis"X"Sleeve - s - 5 9,050' 5-3/4" Guiberson"RH-1"Packer 6 9,087' Otis"X"Sleeve )'- pro 44,- 9-5/8'4 . . t9-5/8 7 9,122' 3-3/4" Top of Baker Blast its 8 9,244' 3-3/4" Btm of Baker Blast its 9 9,275' Otis"X"Sleeve R 10 9,434' 5-3/4" Guiberson"RH-1"Packer -- 11 9,472' Otis"N"Nipple 12 9,473' Btm of Guiberson Sheer Nipple 3 4 C 50t)11 s PPERFORATION DETAIL 6 Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) FT SPF Date Status GJ�`w 9,155' 9,175' 8,856' 8,874' 20' 4 11-09-67 Open 7 D-2 9,210' 9,230' 8,906' 8,924' , 20' 4 11-08-67 Open D-3 _ 9,535' 9,555' 9,201' 9,219' 20' 4 11-06-67 Open 0-4 9,670' 9,720' 9,325' 9,370' 50' 4 11-06-67 Open D-2 5 sr 89 g/ 10 4 11 12 D3 = D4 7'G .a PBTD=9,811'MD/9,454'ND TD=9,895'MD/9,531'TVD Updated by DMA 03-25-15 • PROPOSED • Kenai Gas Field Well: KDU 01 Date Last Completed: 11-13-67 SCHEMATIC PTD: 167-045 i5,;,.;,:, \H,,, , I I t API#:50-133-20035-00 KB to Hanger=15' 1 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 13-3/8" Surface 61/J-55/BTC Surf 1,209' 9-5/8" Intermediate 40/1-55/BTC Surf 4,984' 29/P110/BTC 4,870' 8,210 7" Liner 29/N-80/BTC 8,210' 9,858' 133/8k TUBING DETAIL 2-7/8" Tubing 6.5#/L-80/EUE 2.441" Surf 9,035' 2-7/8" Tubing 6.5#/N-80/BTC 9,035' 9,473' JEWELRY DETAIL No Depth OD Item 1 15' Tubing Hanger 2 8,965' 5.968" FH Hydraulic Retrievable Packer 3 9,001' "X"Nipple 4 9,015' 5.5" 6'Overshot `'.. IV c 56,41--5 r 5 9,050' 5-3/4" Guiberson"RH-1"Packer =J i'''' 6 _ 9,087' Otis"X"Sleeve 95/8' / t . . 2 r 7 9,122' 3-3/4" Top of Baker Blast Jts '^-- R,t- 8 9,244' 3-3/4" Btm of Baker Blast its 3 9 9,275' Otis"X"Sleeve 10 9,434' 5-3/4" Guiberson"RH-1"Packer 11 9,472' Otis"N"Nipple P 4 5� 12 9,473' Btm of Guiberson Sheer Nipple OV L it 5 PERFORATION DETAIL Li 6 Sands Top(MD) Btm(MD) Top(ND) Btm(TVD) FT SPF Date Status 9,155' 9,175' 8,856' 8,874' 20' 4 11-09-67 _ Open D-2 9,210' 9,230' _ 8,906' 8,924' 20' 4 11-08-67 _ Open D-3 9,535' 9,555' 9,201' 9,219' 20' 4 11-06-67 Open D-4 9,670' 9,720' 9,325' 9,370' 50' 4 11-06-67 Open D-2 8 IN 9 'x io uN 11 D3 i D4 s 7G PBTD=9,811'MD/9,454'ND TD=9,895'MD/9,531'TVD Updated by TWN 01-22-16 • • Kenai Gas Field KDU #1 Current 01/19/2016 1.11 Tubing hanger,CIW-F-FBB, Kenai Gas Field 11 x 3'A EUE 8rd lift x3%S KDU#1 EUE 8rd susp,w/3"type H 13 3/8 x 9 5/8 x 2 7/8 BPV profile,61/.extended neck BHTA,Otis,3 1/8 5M x 6.5 Otis acme al jai um Valve,Swab,CIW-F,3 1/8 5M FE,HWO,AA trim �i moi OP, 0 0, Valve,SSV,WKM-M, 2 1/16 5M FE,w/13"Safeco oper, DD trim • Block,tree,CIW-F, 11 5M FE x 3 1/8 5M double master x 711.11111 2 1/16 5M wing section, prepped f/61/4 FBB hanger f4$210 neck,'A control line port, AA trim ;4re:A 111 Mail r ■Ilio Tubing head,CIW-AP 13 5/8 3M x 11 5M,w/2- 2 1/16 5M EFO,w/R bottomy w/1-21/165M ( _ - • �• �Y CIW-FC valve �.�,Oo ri P �r i Et rims Casing head, Baash Ross type FL w/FL style packing unit, p1 p 13 5/8 3M x 13 3/8 SOW,w/ 2-2" LPO 13 3/8" Li 9 5/8" 2 7/8" S Kenai Gas Field Moncla 401 BOPE 01/21/2016 Hilrarp,ilaMkn.I.IS. Ili lit hi lit IS, WA„ U i' 4.54' ' 111Hydril GK 13 5/8-5000 111 111 11'1 111111 • lilt lIII111III .,..-._.. 2 2 7/8-5 variables C6-U4.67' `� !Mr�� —° ows .MMS _ Blinds tt,, rtfirtfirtfi tt 2 1/16 5M Choke and Kill 2.00' I1 valves } 13" 5M {` } ! ! rriErn-irrfainL 6 it-91: LLIJUTV Crossover spool 13 5/8 5M FE X 11 5M FE f I in t rffitrft 1 • ! Kenai Gas Field KDU-01 01/22/2016 ��,�f.,., ‘11.k.. KDU-01 Coil Tubing BOP Lubricator to injection head 3 0 pi J 1.75" Tandem Stripper 1 1 t= Blind/Shear 4 1/16 lOM Blind/Shear =J —_ _ C _ - /- f= Blind/Shear Blind/Shear _A] __ ® amu` : — Slip Slip liii. sr IIIIIIIIIIIIII . _— _— G= Pipe Pipe =1 Mud Cross f — - . / ---- 4 1/16 10M X 4 1/16 10M ( Outlet irtYLii w/2- 2 1/16 10M full opening FMC valves Cla _ 111111[ R I It _� a �I, rt'r. 1 Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M U 2 1/16 10M 2 1/16 10M Crossover spool �] f'l 4 1/16 10M X 3 1/8 5M • 0 c8j " 13 ! 1I U F 7 @ 1] D Q = 1 1] U O N 1 Z Q m O i 1] JoZU f 1 1 0 W C inl - - O i ES�§ 11; it A U tle • k a t' 1111111. t_ , , N = z �i ►•il I 0 c o C J 0 O d O H 111110 mg in in ii, j. 'milli 0 '11!11■1! !I®II.,11, IIII,.., II ill — if, IP ' 1 o, o k V•U 3 A Z C O H O. O F- t C i 0 I V • A •I' I D ., 0) . . 8 it go, rn . J ili c ., ~ Oj ( U0 0 tl 0 g S k a tl • • i $I t b ] �� ! i { c l U I C a I � 3 U l Z N ' ' 070 ! . 3 °' LeZ ° 1 O o 41 K U C-) 1=1 Z 1511 Q N A. Datt IRI t s_ D Y C N l L �i 1104 N Z N (no C L a) Vv IZ o o H IIII In IIII III t 1 II,Iiil '11.11.11 Siy litMI ill lIIl MI " w 19 Y c 12 L 0.12 Iv • O- 11 II' I O I E !E a f i a 51 c 111 rn = c n s c 12 0 n w a U N O 0 Z 0 1 E . k i ,, OF Ty w*I t/1 74' THE STATE Alaska Oil and Gas mwjtk sKAConservation Commission 333 West Seventh Avenue �� ,`, GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 "•� Main: 907.279.1433 OFALAS�� Fax: 907.276.7542 www.aogcc.alaska.gov December 14, 2015 Mr. David Wilkins Senior Vice President Hilcorp Alaska LLC 3800 Centerpoint Drive, Suite 1400 srAt4u8DJuiv 16i) Anchorage, AK 99503 RE: Closeout- Docket Number: OTH-15-017 Operating well with Parted Tubing Kenai Deep Unit#1 (KDU-1) PTD 167-045 Dear Mr. Wilkins: The Alaska Oil and Gas Conservation Commission (AOGCC) issued a notice of violation dated April 22, 2015 for operating KDU-1 with parted tubing. Hilcorp Alaska LLC (Hilcorp) responded with a letter dated May 6, 2015 which outlined the history of KDU-1 tubing x production casing leak. Hilcorp again requested that KDU-1 be allowed to operate with sustained casing pressure as allowed by CO523. The AOGCC responded with a letter dated September 3, 2015 denying Hilcorp permission to flow KDU-1 until the well came into compliance with 20 AAC 25.200(d). The AOGCC also requested that tests be conducted on other Hilcorp gas wells covered under CO 523 to determine tubing by casing leak rates. The leak rates would help determine if any wells were being operated with major mechanical failures such as parted tubing. The AOGCC is satisfied with Hilcorp's response and requested leak data provided on October 16, 2015. The data provided by Hilcorp showed that no other wells tested had major mechanical failure. The AOGCC closes its review and action regarding the April 22, 2015 notice of violation. However, KDU-1 is to remain shut- in until the tubing is repaired. Sincerely, Cathy . Foerster Chair, Commissioner cc: Jim Regg AOGCC Inspectors Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Friday, November 20,2015 9:22 AM To: 'Larry Greenstein' Subject: RE: LETTER FROM AOGCC - KDU#1 and follow-up data request Larry, Received the data last month regarding the other CO 523 area well leak rates. AOGCC agrees there are likely no other wells in that group that have major or catastrophic failures. No other follow-up work on this matter is required by Hilcorp other than the repair of KDU#1 in order to restart production. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at(907-793- 1226)or(Guy.schwartz@alaska.gov). Original Message From: Larry Greenstein [mailto:lgreenstein@hilcorp.com] Sent:Tuesday,September 29,2015 1:50 PM To:Schwartz,Guy L(DOA) Subject: RE: LETTER FROM AOGCC-KDU#1 REQUEST DENIED Excellent Guy...thank you. We are finding out some interesting stuff. Most comforting to know that we don't believe we have any other parted tubing wells in the field(ie instantaneous pressure communication),although we are still performing tests some of the wells. We haven't been managing our casing pressures by the use of bleed downs,so it looks like we won't have any of those to report(except the ones we are doing for testing). The complete report of all the wells tested will be incorporated in our response before the 16th of October. Larry Original Message From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Tuesday,September 29,2015 11:07 AM To: Larry Greenstein Subject: RE: LETTER FROM AOGCC-KDU#1 REQUEST DENIED 1 Larry, You have approval to move deadline for requested leak rate tests until October 16th. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at(907-793- 1226)or(Guy.schwartz@alaska.gov). Original Message From: Larry Greenstein [mailto:lgreenstein@hilcorp.com] Sent:Thursday,September 24,2015 2:59 PM To:Schwartz,Guy L(DOA) Subject: RE: LETTER FROM AOGCC-KDU#1 REQUEST DENIED Thank you,Guy...appreciate it. Just didn't want to wait until the last minute to make this request. Larry Original Message From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Thursday,September 24,2015 2:40 PM To: Larry Greenstein Subject: RE: LETTER FROM AOGCC-KDU#1 REQUEST DENIED Larry, I will need to discuss with commissioners first. They are out of town till Monday. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at(907-793- 1226)or(Guy.schwartz@alaska.gov). 2 Original Message From:Larry Greenstein [mailto:lgreenstein@hilcorp.com] Sent:Thursday,September 24,2015 12:35 PM To:Schwartz,Guy L(DOA) Subject: LETTER FROM AOGCC-KDU#1 REQUEST DENIED Importance: High Hi Guy, Left you a voice message about getting an extension to the deadline for the KDU-1 response. CO 523 sure does cover a lot of wells in KGF and we're sifting through them all. There are a small number we're doing some bleed downs on to see if communication exists plus we're reviewing all of the data entry and operator records looking for any past bleed downs. It just takes a long time and maybe some additional pressure testing to satisfy the review on this many wells. That is why I had asked for a delay in the deadline. Figuring out who's been gone hunting/vacation and getting questions answered about well activities for the last six months means we're still gathering info. Would it be possible to give us some more time to complete the field review of the CO 523 wells?? We'd be looking at a couple of extra weeks, maybe move the deadline to the 16th?? We want to make sure we can answer the leak rate question with authority and it takes time to confirm. A deadline of October 16th would be work out great. Thank you for considering this request. Larry 3 RECEIVED Hilcorp Alaska, LLC 7 n q David S. Wilkins OCT 1 6 201 Post Office Box 244027 Anchorage,AK 99524-4027 ✓to 3800 Centerpo i nt Drive Suite 100 Anchorage,AK 99503 October 16, 2015 Cathy P. Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, AK 99501-3572 Re: Docket No. OTH-15-017 Operating well with Parted Tubing Kenai Deep Unit#1 (KDU-1) PTD 167-045 Dear Chair Foerster: We respond to the AOGCC's September 3, 2015, request for a list of Hilcorp Alaska, LLC (Hilcorp Alaska) wells subject to CO 523 with a summary of leak rates. AOGCC Request: "A list within 30 days of all Cook Inlet wells under CO 523 that show annulus pressures that appear to be tracking the tubing pressure and a summary of leak rates for each well." Hilcorp Alaska Response: There are 70 wells subject to CO 523. Of these, it appears that 16 wells which may be responsive to the AOGCC request. The list of wells and the pressures in these wells are shown in plots in Attachment 1 (CD). The leak rates for these wells are shown in Attachment 2 (CD). Hilcorp Alaska field crews then subjected these wells to testing by adjusting the pressure in the inner or outer annuli. Other than KDU-1, none of the wells demonstrated pressure changes which would show parted tubing. Of the 16 wells which were tested, four wells (including KDU-1) initially appeared to have communication. As previously discussed, KDU-1 has parted tubing. KBU 31-7RD has communication between the production tubing and the inner annulus, but the leak rate test data show that it is not parted tubing. KTU 13-5, a dual string gas producing well, has communication between the two tubing strings, and between the inner and outer annuli, but does not show tubing by IA communication. (KTU 13-5 has been shut in pending our request to return it to production.) The fourth well, KBU 14-6Y, initially appeared to have pressure communication between the IA and OA. The attached leak rate test data show that in fact there is no communication. The other 12 wells show no indication of pressure communication or leakage. Cathy P.Foerster Docket Number:OTH-15-017 October 16,2015 Page 2 of 4 Should you have any additional questions, please contact Larry Greenstein (777-8322 or lgreenstein@hilcorp.com). Sincerely, HILCORP ALASKA, LLC ‘ 8.# or Dav< ilk: r�s David S. Wilkins Sr. Vice President Attachments as described above cc: Luke Saugier(w/attachments) Chad Helgeson(w/attachments) Chris Walgenbach (w/attachments) Pete Iverson(w/attachments) Larry Greenstein (w/attachments) Cathy P.Foerster Docket Number: OTH-15-017 October 16,2015 Page 3 of 4 Kenai Deep Unit#1 (KDU-1) PTD 167-045 Docket No. OTH-15-017 Hilcorp Alaska Response Attachment 1 List of Wells and Pressure Plots [See attached CD] +.. Cathy P.Foerster Docket Number: OTH-15-017 October 16,2015 Page 4 of 4 Kenai Deep Unit#1 (KDU-1) PTD 167-045 Docket No. OTH-15-017 Hilcorp Alaska Response Attachment 2 Leak Rate Tests for KBU 14-6Y, KBU 31-7RD, and KTU 13-5 [See attached CD] AMMO• w��\I%%�sKA. � THE STATE Alaska Oil and Gas ��, -, ofT �� Conservation Commission -= 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 of ��- September 3, 2015 Main: 907.279.1433 ALAS p Fax: 907.276.7542 www.aogcc.alaska.gov CERTIFIED MAIL— RETURN RECEIPT REQUESTED 7015 0640 0006 0779 5579 Mr. David Wilkins Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket No. OTH-15-017 Operating well with Parted Tubing Kenai Deep Unit#1 (KDU -1) PTD 167-045 Dear Mr. Wilkins: Your request to recommence production in KDU #1 (PTD 167-045) as stated in your letter dated May 6, 2015 is DENIED until the well has come into compliance with regulation 20 AAC 25.200(d). Hilcorp's argument that the well should be waivered based on CO 523 does not have merit and is misinterpreted. The intent of CO 523 was to allow wells to stay on production with manageable leaks to the annulus and not direct, uncontrollable communication to the annulus. Hilcorp's request to define production with parted tubing as annular flow is inconsistent with actual operation of the well. This is clearly a case of requesting to operate a "broken well" and not permission to flow a well up the annulus. Additionally, in the initial notification letter dated April 22, 2015 the Alaska Oil and Gas Conservation Commission (AOGCC) requested an explanation of how this type of violation would be prevented in the future. This was not addressed in your response letter. Therefore the AOGCC is requesting a list within 30 days of all Cook Inlet wells under CO 523 that show annulus pressures that appear to be tracking the tubing pressure and a summary of leak rates for each well. Failure to comply with this request may be an additional violation per 20 AAC 25.300. Sincerely, Cathy P. Foerster Chair, Commissioner cc: Jim Regg AOGCC Inspectors RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a),within 20 days after written notice of the entry of this order or decision,or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed,then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration,upon denial,this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction,in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration,this order or decision does not become final. Rather,theorder or decision on reconsideration will be the FINAL order or decision of the AOGCC,and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails,OR 30 days if the AOGCC otherwise distributes,the order or decision on reconsideration. In computing a period of time above,the date of the event or default after which the designated period begins to run is not included in the period;the last day of the period is included,unless it falls on a weekend or state holiday,in which event the period runs until 5:00 p.m.on the next day that does not fall on a weekend or state holiday. • U.S. Postal Service CERTIFIED MAIL`"' RECEIPT cr Domestic Mail Only V"1 For delivery information,visit our website at www.usps.cam'. lT' OFFICIAL n- Certified Mail Fee F`- $ Extra Services&Fees(check box,add fee as appropriate) ❑Return Receipt(hardcopy) $ — ❑Return Receipt(electronic) $ —. Postmark lin 0 Certified Mail Restricted Delivery $ Here 0 ❑Adult Signature Required $ 0 Adult Signature Restricted Delivery$ O Postage ci Total Postage and Fees Mr. David Wilkins SentTo Senior Vice President r-q - HilcorpAlaska, LLC 0 'S4reet endApt.No.,or�Box IPti. r- 3800 Centerpoint Dr.,Ste. 1400- cm 3Yare,lfia+di Anchorage,AK 99503 �97.77P1�1:I4�1�..�1�lili••� �•�clmureeirnaitr�i�-a..-...-.....��.�...-..�- SENDER: COMPLETE THIS SECTION COMPLETE THIS SECTION ON DELIVERY • Complete items 1,2,and 3. A. Sig • Print your name and address on the reverse X J ./ ; 0 Agent so that we can return the card to you. 0 Addressee ■ Attach this card to the back of the mailpiece, ei d by(Printed Name C. D eyelly.eryor on the front if space permits. / 1V79 delivery address different from item 1. ❑ t1 iv address below: El No Mr. David Wilkins 4� Senior Vice President S_ iP 1 U 2015 Hilcorp Alaska, LLC 3800 Centerpoint Dr.,Ste. 1400 GV Anchorage,AK 99503 V 3. Service Type 0 Priority Mail Express® I�I I I III 111111111111111 11111 IIII I I II 11 ❑Adult Signature ❑Registered Mail. ❑Adult Signature Restricted Delivery ❑Registered Mail Restricted MCertified Mail® Delivery 9590 9401 0057 5071 0131 85 0 Certified Mail Restricted Delivery VReturn Receipt for 0 Collect on Delivery Merchandise ❑Collect on Delivery Restricted Delivery 0 Signature ConfirmationT. 2. Article Number(Transfer from service label) '-;sures Mail ❑Signature Confirmation 7 015 0 6 4 0 0 0 0 6 0 7 7 9 5 57 9 ver sured Mail Restricted Delivery Restricted Delivery • PS Form 3811,April 2015 PSN 7530-02-000-9053 Domestic Return Receipt RECEIVEL ,n Hilcorp Alaska,LLC MAY 0 6 2015 ® Post Office Box 244027 Anchorage,AK 99524-4027 (� 3800 Centerpoint Drive 0®�.A�� Suite 100 A chorage,AK 99503 Phone: 907/777-8378 May 6, 2015 Fax: 907/777-8510 �' Isaugier@hilcorp.com Cathy P. Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission State of Alaska 333 West Seventh Avenue Anchorage. Alaska 99501-3572 Re: Docket No. OTH-15-017 Operating Well with Parted Tubing Kenai Deep Unit#1 (KDU-1) PTD 167-045 Dear Chair Foerster: We respond to your letter dated April 22, 2015, concerning KDU-1. We detail the history of KDU-1 and its current state. We request a waiver approving production through the inner annulus, and approval to recommence operation of the well in its current condition. History of KDU-1 As the original operator of the Kenai Gas Field, Union Oil Company of California (Unocal) drilled KDU-1 in 1967 into what is now defined as Kenai Gas Field, Tyonek Gas Pool 1. Unocal completed KDU-1 and put it on production. The initial bottom hole pressure on December 30, 1967, was 4,230 psi. In reviewing the well file, we have found a report from North State Engineering, Inc., which provides pressures as of July 5, 1973, with the tubing pressure at 2,641 psi, and the casing pressure at 2,121 psi, perhaps an early indication of communication between the tubing and the inner annulus. In a report of transient testing dated April 27, 1979, the tubing pressure is stated as 1,560 psi and the casing pressure is 1,575 psi. Unocal and Marathon Oil Company (Marathon) rationalized their property interests in the Cook Inlet effective December 1, 1994. Unocal assigned its interest in the Kenai Gas Field to Marathon, and Marathon assumed operatorship of the KGF on that date. In notes dated May 6, 1999, Marathon reported that a slick line operation tagged an obstruction at 4,908' MD, indicating damage to the tubing from which possible communication to the casing could be inferred. The well file contains a printout of an email dated February 11, 2002, from Wayne Cissell, a Marathon Well Work Over Supervisor, to several other Marathon employees. The email Cathy P.Foerster • Docket OTH-15-017 May 6,2015 Page 2 of 6 describes an attempt to run a camera down by wire line, probably to investigate a tagged restriction in the well. The crew was able to run the camera only down to 5,132' MD but the camera computer chip burned out and no pictures were made. At the end of the email, Mr. Cissell states the following: One thing that I should mention: I had put a new pressure gauge on the annulus when the well was producing, the flowing pressure was at 320 psiq, the annulus had 320 psig. When the well was shut in, the tubing pressure was at 640 psiq, the annulus had 640 psiq it would seem that there is communication between both the tubing and the backside. (Emphasis in original.) The well file does not record any further Marathon work on the well after the February 2002 wire line effort. In 2013, Marathon transferred its interest in the Kenai Gas Field to Hilcorp Alaska, and Hilcorp Alaska became operator on February 1, 2013. On February 18, 2013, Hilcorp Alaska ran a slick line survey to check access for potential additional perforations in gas producing zones. We ran the tools to 5,115' MD at which point the tool tagged an obstruction. The crew notes indicate some question as to whether the slick line was in the production tubing or had exited the tubing and was in the inner annulus. The team decided to run a lead impression block (LIB), which indicated the tubing had parted at 25' MD. This result reflected what the 1973, 1979, 1999, and 2002, work notes indicate: The production tubing was damaged or parted decades ago, allowing full communication between the production tubing and the production casing. This condition appears to have been present since at least 1979. There has never been any indication of lack of production casing integrity. In early 2015, Hilcorp Alaska submitted a permit to drill for the KBU 22-06Y grassroots well. As part of the permit process, the Commission requested that Hilcorp Alaska perform a directional survey of the KDU-1 well path. On March 23, 2015, after reviewing the well records and consulting with field personnel, Hilcorp Alaska reported to Commission staff that a directional survey of KDU-1 could not be performed because of the parted tubing. On March 24, Commission staff replied making inquiry regarding Hilcorp Alaska's intentions for KDU-1 and asking if Hilcorp Alaska is monitoring the pressure in the outer annulus. On March 24, we shut KDU-1 in at 10:46pm. As part of our investigation of the matter, we reviewed Conservation Order 523. CO 523 authorizes sustained casing pressures in the Kenai Gas Fields. Finding Number 4 states: "Annulus pressure is common in development wells. Pressures may be purposely imposed, thermally induced or the result of leaks in tubing, casing, packer or other well components." Hilcorp Alaska sent an email to Commission staff noting CO 523 and asking for confirmation that the CO applied to the long-time condition of KDU-1. Hilcorp Alaska put the well back on production on March 25 at 6:00pm. • Cathy P .Foerster Docket OTH-15-017 May 6,2015 Page 3 of 6 On April 23, 2015, Hilcorp Alaska received your letter dated April 22. After internal review of the letter and CO 523, Hilcorp Alaska took KDU-1 off production on May 4 at 2:36pm pending resolution of this matter. Over its 48-year life, KDU-1 has been a prolific well with cumulative production of over 110 Bcf with no work–no workover, no gravel packing, no fracking ... no work of any kind since its completion. At the point when the well was shut in on March 25, 2015, the well was producing approximately 2 mmcfd. At the point of shut-in, the wellhead producing pressure was 158 psi. The current shut-in wellhead pressure is 580 psi (both production tubing and production casing). As previously noted, we have no indication that the production casing is compromised. Hilcorp Alaska Requests a Waiver to Continue Operating KDU-1 Applicable Regulations and Conservation Order 523 20 AAC 25.200(d) provides: "All producing wells capable of unassisted flow must be completed with downhole production equipment consisting of suitable tubing and a packer that effectively isolate the tubing-casing annulus from fluids being produced, unless the commission specifically approves production through the annulus to increase flow rate without jeopardizing ultimate recovery from the well." In October of 2003, "[o]n its own motion, the Alaska Oil and Gas Conservation Commission (`Commission' or `AOGCC') proposed to adopt rules regulating sustained annulus pressures in Kenai Field development wells." After receiving comments from Marathon, the Commission acknowledged that frequent and common communication between production tubing and production casing existed in the Kenai Gas Field. This resulted in CO 523, which found: "It is not essential to adopt rules regulating sustained casing pressures for Kenai Field development wells at this time." Request for Waiver We request an order waiving the requirement of 20 AAC 25.200(d) with respect to KDU-1 to allow continued operation of KDU-1 through the inner annulus. This request is based on several factors. First, the well has successfully and safely operated for 48 years. From the well records, it is apparent that there was significant—and likely complete—communication between the production tubing and the inner annulus as early as 1973, and certainly by 1979. The pressures in the production tubing and the production casing have been effectively the same, whether during production or after being shut-in. There have been and currently are no indications that the mechanical integrity of the production casing is in question. Second, the static and producing pressure of in KDU-1 is substantially less than the pressure at initial production. The casing has shown continued ability to contain pressures as high as 2,121 psi as shown in the 1973 report. The current producing pressure of 158 psi is substantially • • Cathy P.Foerster , Docket OTH-15-017 May 6,2015 Page 4 of 6 lower. There is little risk of overpressuring the annulus. We attach a P/z curve for KDU-1 showing steadily declining pressure over time. Third, in order to work over KDU-1, the well will need to be killed with appropriate weight drilling fluids. We have significant concern that killing this well will in fact "kill the well," i.e., that KDU-1 will not come back on production at all after a workover. Fourth, Hilcorp Alaska will continue to monitor the pressures on KDU-1 on a daily basis. Over time, we anticipate those pressures will follow the P/z curve provided with this letter, and if there is a substantial departure, we will address the well as appropriate at that time. We understand the Commission takes the position that CO 523 is not directly applicable to this situation. However, there are solid reasons—applicable to KDU-1—that CO 523 concludes that "It is not essential to adopt rules regulating sustained casing pressures for Kenai Field development wells at this time." The CO discusses a number of factors which can result in annulus pressure, and makes findings that are applicable to KDU-1: 4. Annulus pressure is common in development wells. Pressures may be purposely imposed, thermally induced or the result of leaks in tubing, casing, packer or other well components. 7. The Kenai Field is a mature gas field in which reservoir pressures have declined substantially since production commenced. Well pressures in the Kenai Field are now low relative to other Alaska fields, ranging from a minimum surface pressure of approximately 100 psi to a maximum surface pressure of approximately 1000 psi. 8. Low pressure in the inner annulus of Kenai Field development wells means that there is little risk of overpressuring the outer annulus. 9. Kenai Field wells produce primarily natural gas. Annular pressure increases due to thermally induced fluid expansion are thus expected to be substantially less than thermally induced annular pressure increases in wells of oil-producing fields, due to the compressibility of gas and its generally lower temperature. 10. Well tubulars in Kenai Field development wells are of sufficient burst pressure rating to contain the full range of reasonably anticipated well pressures. Given the long history of successful and safe production, the prolific nature of KDU-1, the low operating and static pressures present in the wellbore, and the potential for causing total cessation of production from KDU-1 by a workover kill fluid, we respectfully request that the Commission issue an order providing a waiver from the requirements of 20 AAC 25.200(d) for KDU-1 and allowing recommencement and continuation of production. Cathy P.Foerster ,Docket OTH-15-017 . May 6,2015 • Page 5 of 6 CO 523 contemplates the continued operation of Kenai Gas Field development wells with annulus pressure, and does not require special reports to the Commission related to such conditions. Nevertheless, we will review KGF well files to determine whether there are other wells which have or may have communication between the production tubing and the annulus, and we will report any such wells to the Commission. If you have any additional questions, please contact Larry Greenstein or by email at lgreenstein@hilcorp.com. Sincerely, HILCORP ALASKA, LLC els; -t - Luke Saugier Kenai Asset Team Leader Enclosure: KDU-1 Piz Curve cc: Jim Regg Cathy P.Foerster • • - .Docket OTH-15-017 May 6,2015 Page 6 of 6 KDU-1 P/z Curve KOU 01 Ph 5000 • 4500 • 4000 • 3500 • 3000 2500 ■Actual P/t —Hypothetical►/t 2000 • • 1500 • 1000 500 0 0 20,000,000 40,000,000 60,000,000 80,000,000 100,000,000 120,000,000 140,000,000 OF TtJ w`"\ I i/7;,,,. THE STATE Alaska Oil and Gas m -��=� oA AS /� Conservation Commission 't it>i_—___ 333 West Seventh Avenue t =�_' Anchorage, Alaska 99501-3572 �" � :�,,r�„ GOVERNOR BILL WALKER g Main: 907.279.1433 OF ALASY'� Fax: 907.276.7542 www.aogcc.alaska.gov April 22, 2015 CERTIFIED MAIL— RETURN RECEIPT REQUESTED 7012 3050 0001 4812 7096 Mr. John Barnes Senior Vice President Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket No. OTH-15-017 Operating well with Parted Tubing Kenai Deep Unit#1 (KDU -1) PTD 167-045 Dear Mr. Barnes: On March 22, 2015 during routine review of a Permit to Drill (PTD) application for KBU 22- 06Y anti-collision warnings were noted with regard to KDU-1 (PTD 167-045). Further investigation into KDU -1 indicated that the well lacked a full directional survey causing a large uncertainty in the well path. A full gyro survey was requested by the Alaska Oil and Gas Conservation Commission (AOGCC) to verify the actual well path of KDU -1. Hilcorp Alaska, LLC (Hilcorp) reported that a gyro survey was not possible because well work records indicated that KDU-1 had parted tubing at 25'md and could not be drifted. The parted tubing was identified by a Hilcorp operated slickine unit in February 2013. The AOGCC was not notified of this catastrophic tubing failure and the well has remained in continuous production until the AOGCC learned of the well's condition and Hilcorp shut-in KDU-1 on March 25, 2015. Hilcorp is reminded that all producing wells capable of unassisted flow must be equipped with suitable tubing and packer to isolate the annulus from the formation as per 20 AAC 25.200(d). Hilcorp did not request or obtain the prior approval of AOGCC to operate DKU-1 in this condition. Conservation Order (CO) 523 is not a blanket waiver allowing any type of annulus communication (i.e. sustained casing pressure) without notification to the AOGCC. Under "Findings" in CO 523, number 4 states that annulus pressure is common due to thermal effects or leaking tubing/packers. This statement however, does not imply that catastrophic failures of critical completion components are "common" or"expected" in operating a well. Within 14 days of receipt of this letter, you are requested to provide the AOGCC with an explanation of how this event happened and what has been or will be done in the future to • • Docket No. OTH-15-017 • • April 22,2015 Page 2 of 2 prevent it's recurrence in other wells at Hilcorp-operated fields in Alaska. Failure to comply with this request will be an additional violation per 20 AAC 25.300. Operating wells with known major component failures without AOGCC approval will not be tolerated. The AOGCC reserves the right to pursue additional enforcement action in connection with KDU -1. Questions regarding this letter should be directed to Guy Schwartz at (907) 793- 1226. Sincerely, (//47Cathy P. oerster Chair, Commissioner cc: Jim Regg AOGCC Inspectors RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a),within 20 days after written notice of the entry of this order or decision,or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed,then the period of time shall be 23 days, An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration,upon denial,this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction,in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration,this order or decision does not become final. Rather,the order or decision on reconsideration will be the FINAL order or decision of the AOGCC,and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails,OR 30 days if the AOGCC otherwise distributes,the order or decision on reconsideration. In computing a period of time above,the date of the event or default after which the designated period begins to run is not included in the period;the last day of the period is included,unless it falls on a weekend or state holiday,in which event the period runs until 5:00 p.m.on the next day that does not fall on a weekend or state holiday. U.S. Postal Service. CERTIFIED MAILTM RECEI 'T Only;Mail(Domestic a- No Insurance Coverage Provided) Y' I�- ▪ For delivery information visit our website at www.usps.come e-1 Postage $ Certified Fee ® Postmark Return Receipt Fee Here ® (Endorsement Required) Restricted Delivery Fee ® (Endorsement Required) Lf) O Total Postage&Fees Mr.John Barnes ru Sent To Senior Vice President I= Street,Apt.No.; Hilcorp Alaska, LLC or P0 Rox No. 3800 Centerpoint Dr.,Ste. 1400 - city,State,ZIP+4 Anchorage,AK 99503 SENDER: COMPLETE THIS SECTION COMPLETE THIS SECTION ON DELIVERY • Complete items 1,2,and 3.Also complete A. Sign, e ■ Agent item 4 if Restricted Delivery is desired. X , / ti',, • Print your name and address on the reverse �r� 1 0 Addressee so that we can return the card to you. B. Received by(Printed Na ; . Date of Delivery ■ Attach this card to the back of the mailpiece, or on the front if space permits. ❑Yes D. Is delivery address different from item 1? 1. Article Addressed to: If YES,enter delivery address below: 0 No Mr.John Barnes I _ Senior Vice President 3. Service Type Hilcorp Alaska, LLC cif Certified Mail® 0 Priority Mail Express'" 3800 Centerpoint Dr.,Ste. 1400 0 Registered 0 Return Receipt for Merchandise Anchorage,AK 99503 0 Insured Mail 0 Collect on Delivery 4. Restricted Delivery?(Extra Fee) 0 Yes 2. Article Number 7012 3050 0001 4812 7096 (Transfer from service label) PS Form 3811,July 2013 Domestic Return Receipt • • • • Schwartz, Guy L (DOA) From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Wednesday, March 25, 2015 2:36 PM To: Schwartz, Guy L (DOA); Monty Myers Cc: Regg, James B (DOA); Luke Saugier; Larry Greenstein; Stan Porhola; Pete Iverson Subject: RE: Gyro on KDU-1 (PTD 167-045 ) Attachments: CO 523 (KGF Sustained Csg Press).pdf Guy/Jim, We shut the well in while we gathered the info you requested as some of this history on this wells integrity is legacy Marathon. We found the attached CO that seems to apply to our situation here and for other wells in the Kenai Gas Field. Would this Conservation Order apply to this well? It states that "4. Annulus pressure is common in development wells. Pressures may be purposely imposed, thermally induced or the result of leaks in tubing, casing, packer or other well components." Yes, Hilcorp has been monitoring the OA on all KGF wells weekly, including this one. I am currently on vacation, but will have someone pull the pressures on this well and we will send them to you. Chad From: Schwartz, Guy L(DOA) [mailto:guy.schwartz©alaska.gov] Sent: Tuesday, March 24, 2015 9:56 AM To: Monty Myers Cc: Regg, James B (DOA); Chad Helgeson Subject: RE: Gyro on KDU-1 (PTD 167-045 ) Monty, Thanks for looking into the gyro for KDU -1 . PTD for 22-06Y is approved without having to run the gyro but this brings up a question regarding KDU -1 and it's integrity. Per 20 AAC25.200(d)all wells that can flow unassisted must have a suitable packer and tubing unless otherwise approved by the Commission. I don't see any communication regarding the well's condition in our well files or data base. Is this well on your short list for a tubing workover? Are you actively monitoring the OA(9 5/8" x 13 3/8" ) to verify the 9 5/8" casing integrity? Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). 1 . • From: Monty Myers [mailto:mmyers@hilcorp.com] Sent: Monday, March 23, 2015 9:39 PM To: Schwartz, Guy L (DOA) Subject: Gyro on KDU-1 for KBU 22-06Y Guy, I was planning on running the gyro on KDU 1 to get some good AC on it for drilling the KBU 22-06Y. Unfortunately talking to the production folks and according to the attached WSR,we will be unable to run gyro because the tubing is parted at 25'.The well is still producing very good, so I don't think there is a plan to fix it before we get there. Let me know if this is acceptable with you. We have run our AC at this point,very conservative and should not have any issues with missing it. Thanks! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 2 Alaska Oil and Gas Conservation liknisssion-Conservation Order No.523.000 • Page 1 of 2 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue, Suite 100 Anchorage Alaska 99501 Re: Proposed Rules Regulating Sustained ) Conservation Order No. 523.000 Casing Pressures in Development Wells ) Within the Kenai Field. ) Kenai Field: All Pools )July 20, 2004 IT APPEARING THAT: 1. On its own motion, the Alaska Oil and Gas Conservation Commission ("Commission" or"AOGCC")proposed to adopt rules regulating sustained annulus pressures in Kenai Field development wells. 2. Notice of opportunity for a public hearing on the proposal was published in the Anchorage Daily News on October 30, 2003. 3. No request for a hearing was received. 4. The Commission received written comments on the proposal from Kenai Field operator, Marathon Oil Company ("MOC"). FINDINGS: 1. In considering proposed rules regulating sustained casing pressures in Kenai Field development wells, the Commission reviewed: the Halliburton Cementing Tables; Commission files for Kenai Field wells; information on well pressures provided by the operator; written comments by MOC in response to the October 30, 2003 notice of opportunity for public hearing; and the records of annular pressure rules for other fields in the state. 2. Unless otherwise specifically authorized by the Commission, AOGCC regulations require all producing wells capable of unassisted flow to be completed with suitable tubing and packer that effectively isolate the tubing- casing annulus from fluids being produced. 3. No current regulation or Commission order for the Kenai Field establishes annular pressure management requirements for producing wells. However, the Commission established such requirements for producing wells in other Alaska fields. 4. Annulus pressure is common in development wells. Pressures may be purposely imposed, thermally induced or the result ofleaks i n tubi casing, packer or other well components. 5. Excessive annular pressure can develop in wells as a result of thermal effects. Well startup can involve significant annular pressure increases due to fluid expansion as a well heats above ambient temperature. Changing produced fluid characteristics and production mechanisms can also create thermal conditions that affect annular pressures. 6. Pertinent characteristics of well construction in the Kenai Field are similar to those in other Alaska fields. 7. The Kenai Field is a mature gas field in which reservoir pressures have declined substantially since production commenced. Well pressures in the Kenai Field are now low relative to other Alaska fields, ranging from a minimum surface pressure of approximately 100 psi to a maximum surface pressure of approximately 1000 psi. http://doa.alaska.gov/ogc/orders/co/co500_599/co523.htm 3/25/2015 Alaska Oil and Gas Conservation emisssion-Conservation Order No. 523.000 • Page 2 of 2 8. Low pressure in the inner annulus of Kenai Field development wells means that there is little risk of overpressuring the outer annulus. 9. Kenai Field wells produce primarily natural gas. Annular pressure increases due to thermally induced fluid expansion are thus expected to be substantially less than thermally induced annular pressure increases in wells of oil-producing fields, due to the compressibility of gas and its generally lower temperature. 10.Well tubulars in Kenai Field development wells are of sufficient burst pressure rating to contain the full range of reasonably anticipated well pressures. 11. The wellheads of many Kenai Field development wells were installed in below-ground cellars, making access to the outer annulus difficult and somewhat hazardous. CONCLUSIONS: 1. It is not essential to adopt rules regulating sustained casing pressures for Kenai Field development wells at this time. NOW, THEREFORE, IT IS ORDERED that this proceeding is concluded without amending the Kenai Field pool rules. By Order of the Commission at Anchorage,Alaska,this 20th day July 2004. John K. Norman, Chair Alaska Oil and Gas Conservation Commission Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission Conservation Order Index Home Webmaster http://doa.alaska.gov/ogc/orders/co/co500_599/co523.htm 3/25/2015 • IoLCORP • F-c- ._ WELL SERVDCE REPORT 1 ,69 ° S Date: ,)- /S--/•3 Well Number: -KzL„-i I Work being done: 71-1t-47(111 ? Location: ku4' (,,tea .,,kld ite- Supervisor: ,m',kr -i.„,iii,m _ AFE#I Charge Code: R; 5? Wireline Unit Number: ,,ii.e. Pollard Wireline Crew: "`C.►rcc��;r.., • �14'41�- Tree Connection Size/Type ;kph Total Wireline Miles: Tree condition 06,4 Wire Test: ,aC Fluid Level if Identified ;► , Max Depth (KB):j5.iSK/•3 Zero Wireline at: I,,03 i4N.,jirr,,t Well KB: jam-- Minimum Tubing ID: ) Max Tool OD: 4,r)-5- Start Tbg. & Csg. PSI V .0sc% EndingTbg 9& Cs PSI -- 9�� . ,.` SL Time Operation Details W/L valve A)3 0 LJR24it. I '3hcy-4.tef _Es -j drzp C-gc,.,) (1 t 5S aopl,2-4- -t% y7;4() E -73.0,1,:e- KCS *b-,,,x- 7---' 7i/.)1.4 fed2}1a:+ 7, 4t&-/`i6.(c:c�u'tilLt-J if:1 O .A /C Srtn - Pawl!it- :0 -'LkZu' LI -' lay /Mkt ti�GrL-51,' 6a,) `3:S0 -07-. `�.1,,-L.I, ;c.tv -7 I 5 b�,r) s-1 q:CY RTITI•141 - ' /lS'i.tLv t. I-+u 75- Ito fl) 34,0 34o M3r 5'- - Ci z. Yir SrL-) q.7a q - /A.!, ,3 0 t SAHs iScic) i i o JO7& nn /510 riz: 3/S'3 4?-411.P.-3o 5 , ,1rx1 j Vt°'g ,9Y33 -7!r 5o .•;477? ?37 CIL4 X040 3Y 66 st'fl-3 4/4/yo 5' - &j`7 I0 1-1 1r767 4 4 c7R. 1/4'SS oD�c1 661.0.14:0 /%4c o k71ltl.:,4•14%.) /!1?3 d t.Zd1 /kcir- IND') kit-1Lti Vfri ti+i3 76 Vis' K1 ,-v4D5t:s;=-Put)H Cht.c..L L13 '.,,-*,kst:ice '4k4-er'i iah II' IAO1 rt---/fir3 ,-4 3 is ,S' 43 6,4 v -! `'/7-rleN - 0L:4'3 I70,.J5 /942.1e4 T 6 J I :ZD rz'o rbc ICD u-i-k 1 ma lv - .7' KO Lz. - /3-- r- u-e ,5W(2.5 rsc la 1 ElNivr.! `'tj/P4 Tide /0 p PlyAmac(Iua•Lr /:3.Sot° 6*n")`.'° s-' rick /Xd. 15 cc/cc / 0.44,k ��r CVc) A.131.i8 9'/' Work String Detail: IZ ; ,,,_ r Ig- oT J,55-5 Size and Length /150 Description of any tools or debris left in the hole: Brief Summary of R.L.. C t2c -2." fj'/%'S/4 S-s i .4.c.s,.,' A Me a 2 k1 gzt �::..- iii-t-'_ Total Work r��.'S k`3 11C 4 L.Jchkti !-J k 'kr fQg u.6.--- c> 31Zl �cr.d b. Completed Total Hours Worked Total Tool Cost ,,S'e°`;' Total Hour Cost /550OC Ticket#:F._ / Day# : / Daily Cost: o�L - “.. i _ - Cumulative Cost: Well Downtime Hr. Shut in • H2S PPM Approved by: ,), Code: SIGO0oO�,� �l J Peter Iverson Production Foreman 5 0000 C? South Kenal Unit • 111, WELL KDU # 1 II CASING & ABANDONMENT DETAIL 1 I. Elevation of Kelly Bushing at 0.0' II. Tubing Hanger at 15.00' III III. 13-3/8', 61*, J-55, Casing at 1,209' IV. Top of 7' Liner at 4,870' 0 , V. 9-5/8'. 40#, J-55 Casing at 4,984' 2 � ��, V1. Bottom Tagged at 9,700' (2/1/85) .(�/6' VII. Cement Plug at 9,809' `41'1 VIII. 7', 29#, P-110 & 26#, N-80 Casing at 9,858' 1 TUBING DETAIL 3-1/2', 9.2# & 2-7/8r 6.4# N-80 TUBING 1. 2-7/8' x 3-1/2' x-over at 51.31' 2. 3-1/2' x 2-7/8' x-over at 8,983.80' 3. Otis 'X' Sleeve at 9,014.85' 4. Guiberson Model `RH-1' Packer at 9,049.81' 5. Otis •X' Sleeve at 9,087.22' 6. Baker Blast Joints From 9,122.16' to 9,244.17' - 7. Otis 'X' Sleeve at 9,275.65' I V r 8. Guiberson Model "RH-1' Packer at 9,434.24' J 9. Otis 'N' Nipple at 9,471.89' V ► 10. Bottom of Guiberson Shear Nipple at 9,473.32' PERFORATION RECORD DATE INTERVAL CONDITION 2 11/6/67 9,720'-9,670' D-4 Sd. Production 3 Rii 11/7/67 9,555'-9,535' D-3 Sd. Production 4 11/8/67 9,230'-9,210' D-2 Sd. Production 5 © 11/9/67 9,175'-9,155' D-2 Sd. 6 7 8 A. 9 ICI 10 RECEIVEDD-3Sd. _ - 0-4 Sd. v1= SEP 141989 VIII A'' ;'•ioska 0 &Gas Cons.Com(nissial, Anchorage '.ATE ---� WELL KDU # 1 TAC RAWN.13-A.111_cKD. SCALE NONE DATE 419/81 WELL SCHEMATIC UNION OIL COMPANY OF CALIFORNIA ANCHORAGE.ALASKA r � OF Tye wP�� ,, THE STATE Alaska Oil and Gas 5 \I//r_s, 7 o Conservation Commission fALAs A 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 LAS*P* Fax: 907.276.7542 www.aogcc.alaska.gov April 22, 2015 CERTIFIED MAIL— RETURN RECEIPT REQUESTED 7012 3050 0001 4812 7096 Mr. John Barnes Senior Vice President Hilcorp Alaska, LLC 2953800 Centerpoint Drive, Suite 1400 ��.p►HN�p APR 3 Anchorage, AK 99503 Re: Docket No. OTH-15-017 Operating well with Parted Tubing Kenai Deep Unit#1 (KDU -1) PTD 167-045 Dear Mr. Barnes: On March 22, 2015 during routine review of a Permit to Drill (PTD) application for KBU 22- 06Y anti-collision warnings were noted with regard to KDU-1 (PTD 167-045). Further investigation into KDU -1 indicated that the well lacked a full directional survey causing a large uncertainty in the well path. A full gyro survey was requested by the Alaska Oil and Gas Conservation Commission (AOGCC) to verify the actual well path of KDU -1. Hilcorp Alaska, LLC (Hilcorp) reported that a gyro survey was not possible because well work records indicated that KDU-1 had parted tubing at 25'md and could not be drifted. The parted tubing was identified by a Hilcorp operated slickine unit in February 2013. The AOGCC was not notified of this catastrophic tubing failure and the well has remained in continuous production until the AOGCC learned of the well's condition and Hilcorp shut-in KDU-1 on March 25, 2015. Hilcorp is reminded that all producing wells capable of unassisted flow must be equipped with suitable tubing and packer to isolate the annulus from the formation as per 20 AAC 25.200(d). Hilcorp did not request or obtain the prior approval of AOGCC to operate DKU-1 in this condition. Conservation Order (CO) 523 is not a blanket waiver allowing any type of annulus communication (i.e. sustained casing pressure) without notification to the AOGCC. Under "Findings" in CO 523, number 4 states that annulus pressure is common due to thermal effects or leaking tubing/packers. This statement however, does not imply that catastrophic failures of critical completion components are "common" or "expected" in operating a well. Within 14 days of receipt of this letter, you are requested to provide the AOGCC with an explanation of how this event happened and what has been or will be done in the future to Docket No. OTH-15-017 April 22,2015 Page 2 of 2 prevent it's recurrence in other wells at Hilcorp-operated fields in Alaska. Failure to comply with this request will be an additional violation per 20 AAC 25.300. Operating wells with known major component failures without AOGCC approval will not be tolerated. The AOGCC reserves the right to pursue additional enforcement action in connection with KDU -1. Questions regarding this letter should be directed to Guy Schwartz at (907) 793- 1226. Sincerely, Cathy P. oerster Chair, Commissioner cc: Jim Regg AOGCC Inspectors RECONSIDERATION AND APPEAL NOTICE As provided in AS 31 05.080(a),within 20 days after written notice of the entry of this order or decision,or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. lithe notice was mailed,then the period of time shall be 23 days An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration If the AOGCC denies reconsideration,upon denial,this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction,in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration,this order or decision does not become final Rather,the order or decision on reconsideration will be the FINAL order or decision of the AOGCC,and it may be appealed to superior court That appeal MUST be filed within 33 days after the date on which the AOGCC mails,OR 30 days if the AOGCC otherwise distributes,the order or decision on reconsideration In computing a period of time above,the date of the event or default after which the designated period begins to run is not included in the period,the last day of the period is included,unless it falls on a weekend or state holiday,in which event the period runs until 5 00 p m.on the next day that does not fall on a weekend or state holiday. Letter of Transmittal MARATHON OIL COMPANY 3201 C Street, Suite 800 P.O. Box 196168 Anchorage, Alaska 99519-6168 Telephone: (907) 561-5311 Fax: (907 564-6435 October 17, 1995 TO: Howard Okland Alaska Oil & Gas Conservation Commission 3001 POrcupine Drive Anchorage, AK 99501 FROM: Chick Underwood Exploitation Department Description Beaver Creek #1-A _.Kenai Unit 21-6L TDT-P b~ ~.~enai Unit 34-31 TDT-P ~Kenai Beluga Unit 33-7L TDT-P ~/.Kenai Deep Unit #1 TDT-P Production Log TOTAL Print Film The data is considered confidential until the normal release date. (Marathon Oil) (Date) ~~(Rece~ved Bv~~ (Date) Please Return I Copy by Either FAX or Mail to Marathon RFCF!VED OCT 1 7 1 95 A~k~ ~I~ ~ %~ ~,,~' Commission · STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISb'ION 0 [~ I REPORT OF SUNDRY WELL OPERATIONS GINA 1. Operations performed: Operation shutdown ~ Stimulate__ Plugging __ Puil tUbing __ Alter casing w Repair well w 2. Name of Operator ] 5. Type of Well: / Development x TT'n'; ~'r', ~'~ 1 ct.~rn~=~,, ,-,¢ ~=1 ~ ~r_~_i_= /UNO~.AL) Exploratory__ 3' Address ",'Anch, Ak. r 9951~ [ Stratigraphic __ P.O. BOX 190247 -Q2 7 Service-- 4. Location of Well at surface 411' N & 931' E f/SW cor., Sec. 6, T4N, RllW, S.M. At top of productive interval 623' N & 1405' At effective depth E of surface Attotaldepth 749' N & 1653' E of 12. Present well condition sUmmary Total depth: measured true vertical surface 9895' feet 9515' feet Perforate ~ Other .._Z_Z 6. Datum elevation (DF or KB) 7R 7. Unit or Property name Kenai Deed Unit 8. Well number feet Effec!ive depth: measured 9 811' feet true vertical 9 4 4 3 ' feet Casing Length Size Structural Conductor Surface 1209' 13-3 / 8" Intermediate 4984 · 9- 5 / 8" 4968' 7" Production Liner Perforation depth: measured See attached true vertical Tubing (size. grade, and measured depth) Packers and SSSV (type and measured depth) 9. Permit number/approval number 67-45/9-8]9 10. APl number 50-- 11. Field/Pool Kenai Gas Field Plugs (measured) Junk(measured) None Cemented 3-1/2", 9.2#, 2-7/8", 6.4#, Two Guiberson 13. Stimulation or cement squeeze summary Intervals treated (measured) See Treatment description including volumes used and final pressure Prior to well operation 14. Subsequent to operation N-80: N-80: model 15. Attachments Copies of Logs and Surveys run Daily Report of Well Operations 1200sxs 9985xs 600SXS Measured depth 1209' 4984' 9858' surf-8984' 8984'-9473' RH-1 packers-9050' & 9434' 1209 ' 4984' 9500' RECEIVED OCT 1 91989 Ala*.ka,.Oil.& ~as Cons..Comr~is,lon AnChorage ,, ' - . Tubing Pressure Date 10/18/89 SUBMIT IN DUPLICATE 390 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Title Environmental Enqineer Form 10-404 Rev 06/15/88 Roy D. Roberts 16. Status of well classification as: Oil ~ Gas ~ Suspended __ 0 4,000 2 0 0 2,600 2 0 Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Attached History True vertical depth Service LEASE KENAI DEEP UNIT ~NOCAL DRILLING RECORD ALASKA REGION PAGE NO. WELL NO. KDU-1 FIELD KENAI UNIT DATE E.T.D. DETAILS OF OPERATION, DESCRIPTIONS & RESULTS 10/01/89 9809' ETD DPM 9774' ETD CTM MIRU coiled tubing and Nitrogen Equipment. Test BOPE to 5000 psi-OK. RIH with 1-1/4" coiled tubing with 1.70" wash nozzle to 7178' CTM. Circ with foam and N2 and RIH to fill at 9605' CTM. Circ out fill to 9774' CTM ETD (9808' DPM). Circ with foam and N2 and switched to N~ only. POH blowing well dry. Returned well to Production. Released all equipment at 2000 hrs. STATE OF ALASKA AEASKA OIL AND GAS CONSERVATION COMMISSION ~'~ APPLICATION FOR SUNDRY APPROVAL 1. Type of Request: Abandon __ Suspend __ Alter Casing __ Repair well __ Change approved program __ Pull tubing __ Variance __ Operation shutdown __ Re-enter suspended well __ Plugging __ Time extension __ Stimulate __ Perforate __ Other 2. Name of Operator ! 5. Type of Well: Union Oil Company of California (UNOCAL) Development_~ ! Exploratory __ 3. Address [ Stratigraphic P.O. Box 190247, Anch, Ak., 99519-0~47 Service 6. Datum elevation (DF or KB) 78 GR 7. Unit or Property name Kenai Deep Unit 4. Location of well at surface 411' N & 931' At top of productive interval 623' N & 1405' At effective depth At total depth 749' N & 1653' E f/SW cor., Sec. E of surface E of surface 12. Present well condition summary Total depth: measured true vertical 6, T4N, RllW, S.M. 8. Well number 1 9. Permit number 67-45 10. APl number 50-- 11. Field/Pool Kenai Gas Field 9 89 5 ' feet 9 515 ' feet Plugs (measured) feet Effective depth: measured true vertical 9811' feet 9443' feet Junk(measured) Top of fi11-9573' Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: Length Size Cemented Measured depth True vertical depth 1209' 13-3/8" 1200sxs 1209' 1209' 4984' 9-5/8" 998sxs 4984' 4984' 4968' 7" 600sxs 9858' 9500' measured See true vertical Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) attached RECE%VErO 19 3-1/2", 9.2~, N-80: surf-89¢~ 2-7/8", 6.4~, N-80: 8984'-9473' Two Guiberson model RH-1 packers-9050' & 9434' 13. Attachments Description summary of proposal 2:_ Detailed operations program __ BOP sketch 14. Estimated date for commencing operation After Sept. 20th 16. If proposal was verbally approved Name of approver Date approved 15. Status of well classification as: Oil __ Gas ~ Suspended __ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed,~z'~_.,~/~~_~a.a'Z ~.~(~'Title Environmental Engineer ~' ROy ~J. Roberts () FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity __ BOP Test __ Location clearance __ Mechanical Integrity Test __ Subsequent form required 10- Approved by order of the Commission ORIGINAL SIGNED BY LONNIE C. SMITH [Approval No. ~._ 2/~' / A. pproved CoPY Returned -" ~C-~mmissioner Date 9 -'/¢ '-L~¢ Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE KDU-1 PERFORATIONS: 9155'-9175' 20' 4-HPF D-2 sd 9210'-9230' 20' " D-2 sd 9535'-9555' 20' " D-3 sd 9670'-9720' 50' " D-4 sd Ail depths measured. Top of D Zone sand 9003' MD, 8715' TVD. Note: Anticipated static bottom hole pressure: 850 psi. KDU-1 PROCEDURE le · · · · · · MIRU Coiled tubing unit (1-1/2"). Test BOPE to 5000 psi. Run coiled tubing to tubing tail at 9473' MD. Tubing=2-7/8" 6 4# N-80 buttress 3-1/2", 9.2#, N-80 buttress· 3-1/2" x 2-7/8" XO at 8984'. Circ. and RIH to top of fill at ± 9573'. Circulate out fill using water and nitrogen as necessary. ETD is at 9809'. Circ until returns are clean. (A small mud motor may be necessary to assist in breaking up the fill). Make a wiper trip to the tubing tail. Check for additional fill. Clean out same as necessary. Rig down coiled tubing equipment. Return well to production. III D-2 IV WELL KDU 4 CASING & ABANDONMENT DETAIL I. Elevation of Kelly Bushing at 0.0' II. Tubing Hanger at 15.00' III..13-3/8', 61~, J-55, Casing at 1,209' IV. Top of 7' Liner at 4,870' V. 9-5/8', 40~,, J-55 Casing at 4,984' VI. Bottom Tagged at 9,700' (2/1/85) VII. Cement Plug at 9,809' VIII. 7', 29~, P--110 & 26~, N-80 Casing 'at 9,858' TUBING DETAIL 3-1/2', 9.2-f/, & 2-7/8" 6.4'//' N-80 TUBING 3. 4. 5. 6. 7. 8. 9. .10. 2-7/8' x 3-1/2' x-over at 51.31' 3-1/2' x 2-7/8' x-over at 8,983.80' Otis 'X' Sleeve at 9,014.85' Guiberson Model 'RH-I' Packer at 9,049.81' Otis 'X' Sleeve at 9,087.22' Baker Blast Joints From 9,122.16' to 9,244.17° Otis 'X' Sleeve at 9,275.65' Guiberson Model 'RH-I' Packer at 9,434.24' Otis 'N' Nipple at '9,471.69' Bottom of Guiberson Shear Nipple at 9,473.32' PERFORATION. RECORD DA TE INTERVAL- CONDITION 11/6/67 9,720'-9,670' D-4 Sd. Production 11/7/67 9,555'-9,535' D-3 Sd. Production 11/8/67 9,230'-9,210' D-2 Sd. Production 11/9/67 9,175'-9,155' D-3 Sd. Sd..'v, VII VIII · P:-V. I WELL KDU WELL SCHEMATIC UNION OIL COMPANY OF CALIFORNIA ANCHORAGE, ALASKA DRAWN _.B.A.W CKD. APP'D. SCALE: NQNE DATE: 4/9186 IiECEiVED Is P 1989 I & [~as Cons. ComiTIlSSlO.~, Anchorage · KENA I o-R O-R "'IRECEJVED Union Oil Company ?'-'~-qfornia union January 29, 1968 Mr. Thomas R. Marshall, Jr. State Petroleum.Supervisor Division o£ Mines and Minerals 5001 Porcupine Drive Anchorage, Alaska Dear Mr. Marshall: Enclosed for your information is the 4-Point Test for Kenai Deep Unit #1. Should you require further information, please advise. R. C. Hartmann Area Production Superintendent RCH:mgl Enclosure RECEIVED JP, N 3 0 1,~ JJ~/_ ~1~ OF MINES & MINEIJAL~ UNION OIL COMPANY OF CALIFORNIA ALASKA DISTRICT - GAS PRODUCTION & DISPOSITION December' 19-67 ,11, , i i ~ , il il , ' . ""'. '..' ..· :/' . 'N6. Appa~en{ , Lease!. Blown Rental' Gas ' , ' '": .'Total' ..... · · COMPANY OPERATED LEASES . Well Prod. Production' Use :" ~"~ ."~" ' ' Status Days Mcf MMcf 'Air . , ' - ' ' ' , ii . , ii ' ' ......................... ' ..... i,1111 ' 11' 1' '' ~ '~' Kenai..: Deep Unit'#1. (*) 8 Mmcf 8 Mmc'f , . · . Anchorage-028142 .. . ,:' i , , ,l~, ,1, i l'~ il , , , , , ,1 i , ~, , . . ,l,, , [ i i il [ ' ' [ i il Il I I ' I I I I I I I ' L I I I I I '' ' ' :' ' I ' ' r i.ii i i i J ' i · : (*) Approximately 8Mmcf blown to air ana produced during 4 point potential tests. (~ . . District O~erations Prepared by:~/a/-/~/~.-~ ~.~/~_-.;_ - ~ . FORM 369 4-63 PRINTED IN U.S.A. ~ION OI~gN/'-~tY OF CALIFORNIA · Docur~,en~ £ren~rnittal TO Mr. T. R. Marshall Division of Mines & Minerals _3001 Porcupine Dr~ve Anchorage FROM Don Wm. R~.ynnlds TRANSMITTING THE FOLLOWING: KENAI DEEP UNIT NO. 1: 2" IES 1 Sepia and 1 Blueline (FinaL) Mud log, 1 Sepia and 1 Blueltne (Final) \ \ ..... ."-' _ / ,~ . %%:,%\'q . . ..... .... UNITED STATES DEPARTMENT OF THE INTERIOR GEOLOGICAL SURVEY Form approved. Budget Bureau No. 42-R356.5. LAND OFFICE LEASE NUMBER UNIT ........................................... LESSEE'S MONTHLY REPORT OF OPERATIONS T~e followin~ is a correct report of operation, s a~d prod~etior& (ir~cl~dir~ drillin~ and prod~cin~ ~ells) ~ tke ~o.~ o/__~~r ....................... , 19._~.~_, Company ~~~.~ ~~ ~--C;~;~i' ~e~t'~ ~es~ _~O~__}_,-.~2~J~--~J~Ji---~jyj-' ............. ~-: - :.: ........... : :- :- ....... :. ' ....... . ~o:e ......... ~_:::~! ................ : ......................................... ~e:t'~ t~~~:~ ~Jl~'i!~~~~j SEC. AND (~RA¥ITY. Cu. FT. or (]as (In thousands) I(~ALLONS Or (}ASOLINE ~ECOVERED 1895 TO, 9~11 ED. ledrtlled from 9784 Sidewall S~aple. ?" liner 4~70-9858 ~-80 and 2~# N-80 :ement. DST #1 ~ packer at Flow rate ~acker at Flow rate DST #3 92 iFlow rate DST 84 91: Ran 3 1/2" Ctemmd up Production facilities '0-9720' 1624' wit '500 MCF/ ~500' wi' i300 NC:F/ LO-30', 9180 ' ;000 MCF BARRELS OF WA~z~ iN none, so state) -Ran I , 29# P- e~ented 3 1/2" d .h tail t D 1/2" dp h. tail t, D et bp at D REMARKS ii! drillinz, depth; if shut down, cause; date and result O! test for gasoline content o! gas) ~$, Sonic, Density, LlO LT~C 8 Rd. 29# ~tth 600 sacks 1100' water cushion ~ 9636'. 1000' water cushion ~ 9514'. 9421', packer at 9167 ;5-75', ~ [ckers set at 9434 and 9050'. 2500 MC[ ID tubing ~ Lth pack ~rs at 9050 & 9434. well - ~',ig released 11/13/67. L .': t' <: g ['?'E i A. u %~}~tion of productioz NOTE.--There were .............. ~_0__ ................... runs or sales of off; N0 M cu. ft. of gas sold; ................ ]~[0 ......................... runs or sales of gasoline during the month. (Write "no" where applicable.) NoTz.--Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the supervisor by the 6th of the succeeding month, unless otherwise directed by the supervisor. Form 9-~29 16--25766-9 u.s. GOVERNM£NT PRINTIN¢ 0~'FIC~ (January 1950) I 9-330 · 5~s) Ui .red STATES ~ ~ (See otnmAn- ~ DEPARTMENT OF THE INTERIOR struction'son :: reverse side) i ~ GeOLOGICaL SU~EY WELL COMPLETION OR RECOMPLETION R~O. RT AND LOG * la. TYPE.,_OF. WELL: OIL ~ GAS ~] b. TYPE OF COMPLE~ON: NEW ~OvERWOnK ~ DEEP-EN ~BAcKPLUG ~ DIF~* ~nES~ WELL 2, ~AME OF OPERATOR ~ Union Oil Company of California 3, ADDRESS OF OPERATOR ~ '~_ i 507 W. Northern Lights Blvd., Anchorage~ Alaska~:995,03 4t~u~ee 411.4' lq 6 931' E from S~ coz,,er of~.S~c. 6,-'T4N, R11W, Form approved. ~.. Budget Bureau No..42-R355,5 · 5. LEASE DESIGNATION AND' S]~I{iAL NO, A-f12~i &2 . - K~ai ~ep(,UnitL . .. . . . =- ~ ~'o! ~l~cat~Ke~ai Field 1I;. SE~".,-~.; a., ~;, Og e~OC~.'~O'~SUaWX t toSp%rod, interval reported below 623' N & 14.~ '~ o s~rfaCe location - '-. :. ~t totaldepth 749' N & 1653' E of surfac~loca~on ~' ; Sec. 6,::T4N, ' ' ' I 67-45 ~ I' 8-28-67 Ke~a~ Peninsula: ..Alaska ~: 9720-9535 MD f9360-919~VD] ~ ~ = : : / : 9230-9155 ND (8919-885~;ND) a ' ' Yes: -' -- 26,L ~PE ELECTRIC AND OTHER LOGS RUN ~ ~- / ..... : -- :. ~; . 28f ~ CASING RECORD (Report alt ~tri~s ~et i~~ well) ": 31. P~arORiYION RECORD (Inierva~, size and ~mber~ .~ ,: I 82.:~ J' ACID, SHOT, FRACTURE,· ~gN~ S~uEEZE, I pumpi~g--~ze an~ ty~e et pump) ~h~$-S~). - ':' - DA~R ':FIRST PRODUCTION PRODUCTION ~THOD (.~'[~g~ g~ .. 34. DiSPOSI~ION O~ qAs__(.~.oh~,.use~l ~or/~.e/,~v.e._~.t_ed,.et.c_,) ...... "": ' ' I TEST';-WIT~ESSRD B~[ ..... ; O LiST OB' ATTACHMENTS , I;hereb~ eert~z that th~ ~ore~oin .... he~ f~rm~tion Is ~mplete ~-~ correct g~ getermfne~ Zrom ~11. H. ~. *(See Instructions and S~ces ~or Additf~n61 Datd~n Reverse Side) DIVISIOIN OF MINES & Mil', CZ,. INSTRUCTIONS __. GenerQl: This form is designed for submitting a complete and correct well completion report and log on all types of landsLand leases to eitii~r a Federal agency or a or both, pursuant to applicable Federal and/or State laws and regulations. Any necessary special instructions concerning the use of this:.form and the number of submitted, particularly with regard to local, area, or regional procedures and pz'act ices, either are sho. wn belo~v or will be issued by, or may be obtain~:d from, the and/qr.State office. See instructions on items 22 and 24, and 33,~below regarding separate reports for separate completions. ~ ~ .- If not flied prior to the time this summary record is submitted, copies of all currently available logs ('drillers, geologists, sample-and core an'alysis, all ty~oes electric, et~... tion and pressure tests, and directional surveys, should be attached hereto, to the extent 9equired by applicable Federal 'and/or State l~tws and reg..ul, ations. All should be listed on this form, sc(: item 35 .... I~em 4: If there are no al)Iff,cable State requirements, h)cations on Federal or Indian land should be described in accordance With Federal recLuirem~, hts. Consult or Federal office for specific instructions. -' - I$¢m-]~: Indicate which elevation is 'hsed as reference (where -~o~ Otherwise shown) for depth measurements given in o~her si~aces on this form and in any attachme ~:". ~¢m$ ~2 ~d 24: If this well is completed for separate production from more than one interval zone (multiple'completion)wso state in item.22, and in item 24 show the interval, or intervals, top(s), bottom(s) and name(s) (if any) for only the intery.al~reported in item 33. Submit a separate report (page.) on this fSfrm, adequately for each additional interval to be separately produced, showing the. additional data pertinent to such interval:" - ' i$¢ra 29: "Sacks Cement": Attached supplemental records for this Well should show ttie details of any multiple sta~e cem~nting.:and the location of the cementing tool· I$¢m :l]: Submit a separate completion report on this form for each interval to be separately produced. · (See instrttction"for items 22 and'24 above.) 37. SUMMARY OF POI{OUS ZONES: SII()~V Al,I, IMPORTANT ZONES OF POROSITY AND CONTENTS THEREOF ; 'CORED INTERVALS;AND ALL DRILL-ISlTEM TESTS, INCLUDING I)EPT[! INTERVAl, TESTED, CIISIlION USED, TIME TOOl, OPEN, FI,OWING AND SIIIIT-IN PRESSIII~ES, AND RECOVERIES '9'OIt.MATION TOI' BOTTOM DI!I;SCItlI'TION, CONTENTS, ETC. Kenai "D" Zone '., ... "D" Zone "D" Zone 9155 9210 9535 9670 9175 9230 9555 9720 .ps:i · .. .. 1000' W..C. 12,500 MCF/D @ 1/2*' choke, 2350 .... psi ... 1000' W.C. 10,000 MCF/D @ 1/2" choke~ 2250 psi · 1000' W.C. 6300 MCF/D @ 3/8" choke, opened 4 hours 1'000' W:.C. 7400 MCF/D @ 3/8'' ch~ke,.'2550 Opened 2 hours. ~ ... -' ... .. "D" Zone .. U.S, GOVERNMENT PRINTING OFFICE: 1963--0'683636 NAME (;EOLOGIC MARKERS ... MEAS. DEPTH Top. Kenai Gas Zone ...... ""-Top, "D". Zone" ~-' Sand .- .. 3544 9003 . ... TOP TRUE '. ' UNi~~ q OIL CO. Of CALIFC~ .NIA SHEET C WELL RECORD PAGE NO. I LEASE Kenai Deep Unit WELL NO. l ii FIELD Kenai Gas CASING & TUBING RECORD SiZE ! WEIGHT I THREAD GRADS DEPTH REMARKS ---i~i O~ I 8'R~ J 55 1209 ICemented with 1150 sacks Class G with 2% CaC!~ , , ~ - 9 5/sI 40 I Bultress i... J 55'..'. 4984 '"C?mented'with 998 sacks Class G .. 7" ~v9 ~ 2'6 18RD ~ Butt- i i tess P-110,N-80 9858 Top of h~nger 4870'. Cement plug 9809 PERFORATING RECORD ~ ' ~ ~~OL E.T.D. REASON pRESENT CONDITION i±-o-o/t 9720-9o/0 Prod. test Open 7 t 9555"29555 " " Open -" 8 1 9230-9210 '" " " Open 9 I 9175-9155 . " " Open I t --., INITIAL PRODUCTION - --'l D = ~ E IINTERVAL NET OIL CUT' IGRAV, iC.P, T,P. CHOKE MCF GOR ?¢6'71 ' 7 ,, 9555-9535 3/8 6.36 Press. 2200# 9 9230-9210 3/8 5.15 Press. 1800# ., i0 ~ 9175-9155 , 1/2 12.5 Press. 2550# ,. ,,, __ . ~ , I I WELL HEAD ASSEMBLY TV ~PE:, CASING HEAD:.Baash-Ross 12" $000# x 13 5/8" Type FL with slips and packing (Is s/S,, x 9 s/8") CASING HANGER: CASING SPOOL: TUBING IqEAD: Cameron 12" 3000# X 10" 5000# AP Tubing SpOol ,~~ HANGER: Single Cameron AP Hanger with 2 7/8" x 5 1/2" ~wage T'~fBiNG HEAD TOP- VALVES: CIW 5000# 10" Bottom Flange Dual Type F. Ci~RiSTMAS TREE TOP CONN.:.. 3 1/2,i!,' 8 RD. Di4-12 CODE 50-133-20035 _.~l~lease D&te 12-13-69_ i Ji State of Alaska Department of Natural Resources DIVISION OF MINES AND MINERALS Petroleum Branch INDIVIDUAL WELL RECORD Sec.= 6 ....... T. 4N R. lin 'T Permit No. 67-45 Issued 8-28,--67 ......... Operator~ Union Oil Co. of Calif. Location (Surface)411,,4 FSL.,,.& 931.0!. FWL Sec. 6 Lease No. A-028142 or Owner ,Ken3! peep Unit .... Loc. (Bottom)1000' FSL & 2640' FWL Sec. 6 Well No. __ 1 Spud Date 9,~3-67 Area Drilling ceased TOtal Depth Suspended Abandoned Elevation 90.' RT. .... Completed (F~ I 1 - 1 ~.67 ...... IP B/D. Gray (S) 22500MCF/D 32/64 Gas. (L)13_70~0~_~ M~F/D, Bean ~4/64 CP psi, Casingl Size :.Depth Sx Cmt Perf= 9720'-9670'~ · 9555'35'; 9230'-10'; t1. I _' . , , , 13 3/8_. 61# ..... _1209 .1200 9175',55' 9 5/$"-40# /+984 ~ 998 API Cut % TI> 2300 psi On test - TP 2550. PSithen S'.I. 7" lnr. 4890-9858 600 Comb. (2 ~ """ . ., o - ab~,,... 9D~0=9~4~50- ...... String (3 1/2" tbg. 0.9050~ GEOLOGIC FORMATIONS Surface ~est Tested. N~e PRODUCTIVE HORIZONS Depth Contents Year Jan Feb Mar Apr WELL STATUS May June July Aug Sept Oct Nov Dec __ Fish, in ho.!e.: Bit, DOS,,& d.p. 9917-9130'..iPg. 9130.' .-9030'. _w,.[,92 sx. & S,.T. Remarks: _ Co_gtrac'tor~, coastal Drilling. DRILLING RECORD -~AC _. Lp, o~. Kenai Deep Unit FIELD Kenai Gas WELL NO. 1 LOCATION Ka!ifonsky Beach 360 N and 900 E of the SW corner Sec. 6, T4N, R i 1W, SM PERMIT NO SERIAL NO. T.D T.V.D. DEVIATION (B.H.L.) COMPANY ENGINEER John Dakin SPUD DATE CONTRACTOR TYPE UNIT. DRILL PIPE DESCi~.!PTiON. I ! [ BIT RECORD MUD VEL.'~ DEpTv'Z BIT' JET DEPTH I VhTLTTC-:~. L D3.TE I DEPTH NO. SIZE I~.~.KE TYPE SIZE OUT FEET HOURS ANN. ]JET · . ~-~-~71 t!i~ !/4 ~ood YT~T ,0~ ~0 ~0 l~ .... !5 { H0 2 ~ 17 1/2 SEC PICOT Open 1215 1215 15 1/4 ~s ,~ ~0} s~ ~2 ~/~ ~wc X-ZA ~ ~/Z ~oT,,~zg7~ ~/~.... . ,,, 17 ~ 2607] 4 { !2 I/4 Reed XTSA Z 9/16 S774 1167 23 .. 20 3774 3RRI 12 ~/4 HTC X3A 3 9/16 4880 924 18 1/4 28 48~0 4nn~ ~ ~/4 ~ Reed XT3A 3 9/16 5000 150 S .. '"' 29 ~ 5100~ 6 [ S 5/8 SEC S4TJ Open 5218: 118 7 1/4 .. _ 29 { S2lS~SRR~ S 5/8 HTC X3A 3 5/16 -- 50 ~ 52!S~6RR~ 8 5/.8 ~ SEC S4T~ .Open. 5700 482 16 ~0 ~ 87~00~7 ~ s ~/s, ~,c x~ ...... 2-~ ~ ~ ~ ~ 1-9 6087 340 [,.,SOST' s ~ ~ ~ t 1-9 6216 129 5 3/4 .. 2 ~ 6216~ 9 ~ 8 5/8 HTC' ..XlG'. 2-9 I [ { /1-11 .... 6626 410 !8 1'/2 ' '~ ~ 6626{10 i 8 5)'8 ttTC XlG 2-9 ' i, I '~-~!, 7o~ 4ss i8'~/2 4 } 706!{11 ~ 8 5/8 Globe SST3 3 5/16 7392 331 16 1/2 S ~ 73.92~!2 ! 8 5/8 ttTC X3 3 5/16 7682 290 16 3/4 .. 6 .~ 7~82~13 ~ 8 5/8 HTC X3 3 5/16 8004 322 18 1/2 7 ~ 8004~14 ~ 8 5/8 Reed ST1AJ 3 5/16 8366 362 17 .8 } 8366~15~ 8.5/8 Reed ST1AJ 2-10 ._ ~ ~ . ~ /1-11 8659 293 15 9 } 8659116) 8 5/8 HTC Xlg '3-11. 8924 265 .16 __~ { 892.4~!7 J' 8 S/8 '{ HTC X!G .3-1.! 9090...' 166 11 3/4 _ i0 } 9090~ !8 [ 8 5/8 Reed ST1AG 3-11 9125 35 3 1/4 II I 9125~19 ~ ~ 5/8 ~ HTC XV 2-11 · ' ' ' ~1_12 9252 127 11 3/4 ..... ~'"!2 i 9252i20 S .s/a HTC XV 2-11 '" I ! ~ t il-12 9323 71 11 1/2 .... ~, ~ 9323~21 { 8 5/8 HTC ..... X1G..2_11 .... I ~ { I1-12 9485 160 15 i/21 - I 9483 22 8 5/8 Reed ST1AG. J 2-11 " ! J I I 1-12 9575 92 12 1/4 160 375 94-g3'224"-1/4©'N70E ,,~4 I 9~7~12m i 8 5/s HTC X~G 2-~ - ,. ~ . , f 1-12 9711 136 12 165 400 Missed survey _ 15 I 97111241 8 S/8 Reed STiAG, I 2-11 I , .... 'l i i { / 1-12 9797 86 7 1/4] i65 4o0{ :x~.:~o~ Survey _ ~S .... ! 9797125 { 8 5/8i HTC "XIG' 2-111, ..... ~ ~ ...... ~~ { .... I" 1-12 9877 80 6 !65'[ t"'c',~- · ~ . . 400t.,~77'-23 1/~'b N72E !6 ~ 9877~,26 [ 8 5/8 [ HTC X1G 2-11 .. t [ ! I I1-12 9952 75 10 ii4 165 400t .... _17 ~ 9917{27 { 8 5/8{ SEC S4TG 3-12 Lost .... :~.=~ left 5n hole ~9917 ~,9 ~ 9~50}28 ] 8 5/8' SEC S4TG open ~ 9130 Fish tnz Clean out bit ' ~22 [ ' 903028RR 8 .S/8 SEC . S4TG Open . 9072' 42 OEienting & D,/:naDrill _ . 23 'i 9072)29~ 8 s/g HTC XIG 3-13 9111 39 6 180 550 9111-26 5/4 _24 ~ 9i1!{30. I .S 5/8 Reed ST1AG 3-13 9142 Sl 6 3/4 147 310 25 t 91.42i31 I 8 5/8 HTC X1G 3-13 9262 120 10 1/4 147 3i0 9262-27?"5~ N65~/ ' ~.26 9262~32. ~ .8 5/8 HTC X1G 3 3/4 9315 53 10 210 380 9315-26745: Nf7E' ~7 9~ {35. { 8 5/8 Reed ST1AG 3 3/4 9417 102 16 1/.2 210 380 94!7-55745~ ~,~64E -- _ 2g ~ 941ff~54 ~ 8 5/8 IITC X1G 1/2 9555 129 14 3/4 ,,:> ~ 8 5/8 Reed ST!AG 1/2 9602 .47 6 ~ 9575-25 '57E ~j, { o~n~[36 f 8..S/8 SEC , c~T.. ' ~ < .... , , ...... ,,,g'.. 1./2 9714 112 8 j ..... ~ ~.,. ~ X~G ~! {~ u7~"i~7 ~ 8 5/8 . tIT.C 1/2 9819 105 12 3/4 2;_~1-67 i 9~,~:,{ 58. [ 8 .5/8 Reedi ' s~'iAGI 1/2 9895 76 11 1/2 ; Z .., i 52~225,.5~ 39 { ...S 5/8 'SEC i S4TO 1/2 Condition Hs!e 6...--~ ' 40 6 }ITC i OWC Reg. t Dri{Ied o i UNION OIL CO. OF CALIFORNIA DRILLING RECORD SHEET D PAGE NO. i LEASE Kenai Deep Unit VFELL NO. 1 FIELD. Kenai Gas DATE 9-14-67 15 16 17 18 24 24 !0-12-6~ 15 through 16 17 18 19 20 21 22. 23 24 25 26 E.T. D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 221 1220 5000 9952 9956' Top of fish' 9497' 9956' Top of fish 9150' PBD 8880 PBD 9050 9111 9211 9300 9377 Spudded 12 1/4" hole at 3:00 PM 9/15/67. Drilled 12 1/4" hole. Drilled 12 1/4" hole. to 1220', opened 12 1/4" hole to 17 1/2" to 1215'. Made wiper run. .Ran 61 jts. 13 3/8" 61# J-SS 8 RD Casing, set at 1209' with Baker flexiflow shoe at 1209' and Baker flexiflow collar at 1165'. Centralizers at 1187' 1152' 1095' 1058' 1018' and 975' Cemented with 1150 sacks , , ' ' , · Ideal Class "G" Cement with 2% CaC12 mixed with fresh water. Displaced with 1047 cu.ft, cement to surface. Cement in place 9:10 AM 9/16/67. Float held OK. Waited on cement and nipple up. Tested B.O.E's Okay. Drilled out float and shoe. Drilled 12 1/4" hole to SO00'. Ran Schlumberger IES and Sonic to 4953'. Ran 122 its. 9 S/8" 40# J Buttress Thread blank casing to 4984' where casing froze. Cemented casing with 998 sacks Class "G" Cement. Displaced with 2180 cu.ft, mud. Cement in place at 5:40 AM. Bumped plugs on baffle at 4959' with 2000# Shoe at 4984'. Waited on cement Drilled cement and shoe, drilled 8 5/8" hole from 5000' to 9483'. Dyna- Drilled from 5100' to 5185'. Drilled and surveyed 8 5/8" hole from 9483' to 9819'. Stuck pipe in coal. Worked pipe unitl free. Continued drilling from 9819' to 9952'. Pulled out of hole to change bits. Ran back in hole with bit #26. Circulated and reamed hole. Drilled from 9952' to 9956'. Pipe stuck while making a connection. Ran free point indicator and back off shot.. Pipe stuck at 9917'. Leaving 12 spiral drill collars, 2 monels, 4 stabilizers and a bit in the hole. Backed pipe off at 9497'. Recovered a bumper sub, X-over sub,' Stabilizer and 2 spiral steel drill collars. . Ran in hole with fishing string,(ll drill collars, jars and bumper sub) Screwed into top of fish. Unable to jar fish out of hole. Ran dialog back' off shot, pipe stuck while running dialalog. Circulated and worked pipe. No movement in jars or bumper sub. Backed fishing string off 1 single above drill collars at 9130;. Chained drill pipe out of hole. Made bit run to top of fish at 9130; picked up wash over pipe.and washed top collar. Pulled and laid down wash pipe. Ran in hole with open end drill pipe hung at 9130'. Pumped 8 bbls. water followed by 92 sacks Class G Cement mixed with fresh water and 20% blasting sand. Displaced with' -- 2 bbls. water and 123 bbls. mud. Cement in place at' 0400 hours., 10/21/67. Pulled 5 stands, circulated, pulled out of hole. Ran back in hole with bit. Touched top of plug at 9000'. Dressed off plug to 9030', Circulated and conditioned mud. Pulled out of hole. Ran in hole with DynaDrill. Dyna-Drilled 8 5/8" hole from 9030' to 9071'. Drilled and surveyed 8 S/8" hole from 9072' to 9111. Drilled 8 S/8" hole from 9111'-9211'. Drilled 8 5/8" hole from 9211' - 9300'. ~ ; Drilled 8 5/8" hole from 9500 to 9577'. UNION OIL CO. OF CALIFORNIA DRILLING RECORD SHEET D Page NO. 2 LEASE Kenai Deep Unit WELL NO. 1 FIELD Kenai Gas DATE F_.T.D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 10-27-67 9427' 28 29 30 31 11-1-67 10 9555 9602 9714 9831 9895TD 9895TD 9895TD 9895TD 9895TD Plug 9809' 9895TD 9895TD Plug 4809 9895 TD 9895TD 9895'TD Drilled 8 5/8" hole from 9377' - 9427'. , Drilled 8 5/8" hole from 9427' - 9555'. Drilled 8 5/8" hole from 9555' - 9602'. Drilled 8 5/8" hole from 9602' - 9714'. Drilled 8 5/8" hole from 9714' - 9831'. Drilled 8 5/8" hole from 9831' - 9895'. Conditioned hole for logs. Ran Schlumberger IES Log, Sonic Caliper Log, FDC Log, SWS gun. Conditioned hole for 7" liner. Ran 7" 29# & 26#, P-110 & N-80, 8 RD and buttress casing to 9858, top of hanger at 4870'. Cemented through Baker shoe at 9858' with 600 sacks "G" Cement. Displaced with 1453 cu.ft, of mud. Cement in place at 8:00 PM. Had good cement returns. Laid down 4 1/2." Drill pipe. Make up 3 1/2" Drill pipe. Made up 3 1/2" drill pipe. Checked top of cement at 9809'. Ran Schlumber GammaRay Bond Log. , ~an Schlumber scallop jet gun, perforated 4 3/8" holes per foot 9720-9670'. Ran tlalliburton tester on 5 1/2',, 15.30, drill pipe with 1000' of water cushion and 5/8" bean in tester. Set packer at 9624', tail to 9636'. Gas to surface in 3 minutes, cushion in 6 minutes. Closed tool 10:05 AM for 1 hour initial shut in, opened tool 11:05 AM for 2 hour flow test. Surface pressure through 5/8" ~ean 2550# rate 7.0 MMCF. Closed tool and took 1 hour final shut in test. Ran Schlumberger scallop jet gun, per. 4 3/8" holes per foot 9555-9555'. Ran HOWCO Retrievable bridgeplug on tester with 5/8" bean and 1000' of water cushion. Set bridge.plug at 9575'. Set tester at 9500', tail to 9514'. Opened tester at 5:48. AM, had weak blow for 15 minutes. Closed tool at 6:02 AM for 1 hour initial shut in. Opened tool at 7:02 AM for flow test.' Surface pressure 2000# through 3/8" bean, estimated rate 6.~6'b~CF. Closed tester at 11:50 AM for 1 hour final shut in test. (Note: had some mud through out test-.) Circulated and conditioned gas cut mud. Ran Schlumberger scallop jet gun shot 4 5/8" holes per foot 9250'-9210'. Ran ttOWCO Retrievable Bridge plug on tester with 5/8" bean and 1000' of water cusion. Set bridge plug at 9421' Set tester 9167' tail to 9180' Opened tester at 5:30 PM for 11 minutes initial flow test. Gas to surface in 5 minu%es, cushion in 6 minutes Closed tester at 5:41 PM for initial shut in test. Opened tester at 6:36 PM for flow test. Took well 6 hours to clean up. Closed tester at 3:55 AM. Surface pressure 1800# through 5/8" bean, estimated rate 5.15 MMCF, took 2 hour final shut in test. Retrieved bridge plug and back scuttled hole clean. Ran Schlumberger scallop jet gun shot 4 3/8" holes per foot 9175' - 9155'. Ran HOWC0 Retrievable bridge plug on tester with 5/8" bean and i000' of water cushion. Set bridge plug at 9191'. Set tester 9106', tail to 9119'. Opened tester at 2:35 AM for initial flow test. Gas and cusion to surface in 5 minutes. Closed tester at 2:50 AM for initial shut in test. Opened tester at 3:50 AM for flow test. Final surface pressure 2350# through 1/2" bean. Estimate 12.5 MMCF. Closed well in 9:25 AM for 2 hour final shut in test. UNION OiL CO. OF CALIFORNIA DRILLING RECORD SHEET PAGE NO. LEASE Kenai Deep Unit VvqZLL NO.. 1 _ FIELD Kenai Gas DATE 11-10-67 (Cont.) 11 12 13 E.T.D. DETAILS OF OPERATIONS. DESCriPTIONS & RESULTS 9895TD Plug 9809' 9895TD Retrieved bridge plug and pulled out tester. Ran to 9809' and conditioned mud. Conditioned mud. Laid down 5 1/2" drill pipe. Ran 2 7/8" and 3 1/2" tubing to 6250', well started to flow through tubing. Built up mud weight to 90#' and circulated 4 hours. Ran 2 7/8" and 3 1/2" tubing to 9473'. Installed and tested X-Mas tree. Cleaned up location. Contractor released at 4 PM 11/15/67. TUBING DETAIL Guiberson Shear Nipple Otis N-Nipple jr. 2 7/8" 6.5# N-80, F. U8 Tubing Guiberson R.H. 1 Pkr. 5 3/4" OD jts. 2 7/8" 6.5# N-80, EU8 Tubing Otis X-Sleeve jr. 2 7/8" 6.5# N-80 EU8 Tubing jts. Baker Blast Tubing 2 7/8" EU8 .69 .94 31.86 5.59 155.07 3.52 31.48 OD 3 3/4 122.01 1 jr. 6.5# N-80 BU8 Tubing Otis X Sleeve 1 jr. 6.5# N-80 EU8 Tubing Guiberson R.H. 1Pkr. S 3/4 OD 1 jr. 2.7/8" 6.S# N-80 EU8 Tubing Otis X Sleeve 1 jr. 2 7/8" 6.S# N-80 EU8 TFbing X-Over 2 7/8" EU8 to 3 1/2 Buttress 286 its. 3 1/2" 9.2# N-80 Buttress X-Over 3 1/2" Buttress to 2 7/8" EU8 Tubing 1 it. 2 7/8" 6.S# N-80 EU8 Tubing Fatique Nipple 2 7/8" EU8 Donut Landed below Zero 31.42 3.52 31.82 5.59 31.44 3.52 30.05 1.00 8931'.49 1.00 31.71 3.80 .80 15.00 9473.32-9472.63 9472.63-9471.69 9471.69-9439.83 9439.83-9434.24 9434.24-9279.17 9279.17-9275.65 9275.65-9244.17 9244.17-9122.16 9122.16-9090.74 9090.74-9087.22 9087.22-9055.40 9055.40-9049.81 9049.81-9018.37 9018.37-9014.85 9014.85-8984.80 8984.80-8983.80 8983.80- 52.31 52.51- 51.51 51.51- 19.60 19.60- 15.80 15.80- 1S.00 1S.00- 00.00 ×// / / UNION OIL CO. OF CALIFORNIA DRILLING RECORD ~,-, EE'£ PAGE NO LEASE Kenai Deep Unit ~VELL NO. 1 FIELD Kenai Gas DATE E.T.D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 9 5/8" Casing · Itowco Shoe 2.00 Joint #1 41.53 Howco Float Collar 2.00 121 joints 9 5/8" 40# J CSG 4920.47 R.T. to Mat 18.00 4984.00 4984.00 - 4982.00 4982.00 - 4940.47 4940.47 - 4938.47 4938.47 - 18.00 18.00 - 00.00 7" Liner Baker Shoe Joint #1 Baker Float Collar 7" 29# Pll0 Csg. 7" 29# N-80 7" 29# N-80 T1W- 7" Liner Hanger Top Liner to Well Head R.T. to Mat (0) 2.37 41.55 1.76 1602.64 1659.47 1662.99 ,117.22 (Mat)4852.00 18.00 9858.00 9858.00 - 9855.63 9855.63 - 9814.08 9814:08 - 9812.32 981.2.32 - 8209.68 8209.68 - 6550.21 6550.21 - 4887.22 4887.22 - 4870.00 4870.00 - 18.00 18.00 - 00.00 LEASE Deep ~'~:' TVO~. Fres}: wa=er LiRnosolohonatc ! t DEPTi~ 9-!4 -67 955 16 i220 17 i986 18 19 2670 20 3515 o~ 587~ 21 4850 22 4900 22 4900 23 . 5000 73. 48 , NiDo~in 73 5.4 77 51 5.2 79 5.8 79 78 78 i 42 WOCl 24 es wocl 26 5~° , _ u~0 77 i 4? 5.8 26 S020 6.0 27 5215 28 5420 28 5769 S.9 6.0 5.9 77 14o 77 i39 78 54 ,,, 78 i 54 29 6000, 77 j 59 5.6 29 6000 77 I 45 5.8 5O 10-i-67 3 4 6250 79 i 60 6760 I 81 50 7050 7300 7600 7800 7998 6 8327 6 8375 7 8615 8 8740 9 9002 !0 9122 !0 9161 9270 9330 9490 9575 9722 1i 9872 9952 i2 !3 _ i5 !7 9952 8!.s! <42 82 j45 82 is'o 80 i '46 77,5! 48 5.6 _ 18 -- ig _ 20 __ 23 __ 24 9130 8880 5.2 4.8 5.4 5.2 4.8 4.6 79 46 5.8 77 !52 4.6 79 65 4.0 84 [ 45 3.6 87 46' 3.8 90 48 3.2 '90 49 2.8 90 46 3.0 90 50 3,0 89 48 3.4 90 52 3,4 90 50 3 ~6 90 46 3,4 90 S! 90 55 ~. ,, 3,2 90 J 55 3,2 90 ii 3,.0 90 58 . 3,0 90 . 3,0 90 52 5.4 90 ~a 3 2 WELL NO. ], SALT 20 " 20 " 25 " 30 2O .20 15 2O 35 40 45 55 3O 30 55 65 6O 7O O0 O0 O0 0 O0 o.o 0.0 ~100 0.0 ~100 0,0 ~100 9111 9211 i ,8 1800 ,8 1600 ,8 L400 ,6 !500 5OO 1500 D ,6 600 ~ ~6 1600 t~.,o ooo 10,6 ~000 I._Q, 6 000 6 6, 4 4 ' 4. 4 , ! i 4 ?7 s I i 11 1./4 1 · 1 3.4 3/4 3/4 3/4 3/4 '3/4 3/4 3/4 2/4 Ke,~-~ i Gas FIELD - -~'~ DISTRIBUTOR ! MC SOLIDS L/ElvlAI-~ZZS Dri!iine 1.2 i/4" hole 13 14 18 1.9 14 13 15 12 12 I0 12 14 14 13 13 14 12 15 13 14 Ran 125 Cond. for ~oxs,, Dulled a~lied bit ' Ran logs~ conditioned, for casing Ran 9 S/8" 40# csg. Installed BOP Drilled out of casing 13 15 14 15 17 17 20 20 - 19 20 18 20 19 1.9 19 19 19 19 19 19 !9 !9 100 units background gas 110 units background gas 90 " " " Fishing FishSng Fishing i8 19 Drilling Fishing-add Free pioe-mud lube !fhinstock Reports 1.~/3!~22 -pit checks only Re~o:rts !6/2::~,'75=~pit checks onl~ 13/26 - Pit c;:eCl::s only _ ' i ' I !00 [050 !.9 . Cond. for !o. gs 19 ~Cond, for bond ]_ogs 19 for ~'~roductS_on test - ~' ~1 . . ' . .. PROOUCTIOil $ERY.i-CE LABORATORY - BRE~_ RESEARCH CEtiTER SOURCE $A}IPLE PRE~S. LB. GA.¥TEHP. °F. ~ANPLE ~FTER ~[ATi~. LB.~. °F. COL. ~0 A~ALY~iS GAS- DATA 6t~$0. 21. VOLUHE % CO:4TE~T REID V.P, OAS (HOL) LIQUID GALI~ICF. LIQ. ~ · AT~E VAPOr' H20 AIR A-~ CA~BO~ DIOXIDE CO2 __L~]_ .... .~.~ . - N - HEX~ C6H%~ ?OT~L ~.~ .... t).~AVIT¥ OF RESI~-UE °A.P.I. CALC, LB. REID H~S, CRAIH$/tO0 CUBIC FEET SPECIFIC G~A¥1~' (ED:'fARDS) SPECIFIC GRAVITY (CALCULATED) GROSS B.T.U,/CU. FT. (CALCULATED) LBXsOLiHE ¢OHTEXT, GAL,/NCF: ....~P,F-_IL~C_O...._ CHARCOAL TEST, $0# - CHARCOAL TEST~ RECTIFIED EQ~ I V . P.E¢I' .CHAR. CA LC . F~.. AIIALY$ I S DOCTOR CORPOSIOa .... COLOR SP. GR. (CALC)__ __LB. I GAL (CALC).' CU. FT./GAL.~, 76C'r. mi A)!D 607F: OF THE TOTAL SA~iPLE (CALCULATED) 'ISO~PEHTAT~.E A HEAV.(USEO) (~£T) ...... o... , OF TltE iSO-~UTA~E & HEAY.' OF THE ,q-BUTA~.E & liEAV, CO.~TEAT: CO)4PUTED PE)~TA)IE & !;EAV. OF TitE ISO-BUTA~E & HEA¥. OP THE X-~UTA~E & HEAY. OF lliE EQUIV. RECT. CHAP, COAL OF THE LB. ISO-PE~.TA;~E S HEA.',Y REID Y,,P. PRESS. AC'PJAL I~ALC. ' C~_RV_E . COHPUTED SLOP~, LB. REID +PER CE~T C~A~GE ~N PENTA~ES & ~EAYIER CONCE~TRATIO~ DUE TO T~E AODITIO~ OF: MORTAL BUTANE COPIES !._ _ FOR FURTHER DATA, SEE .~EPORi' SHEET )~O .... ;.~,~?_.~ __~?~-.-~ ..... ~,~t ~~-:: " 5. APPROVED r~;- ~:,_ _J~ / , ~,c~} .... :,,,,~ STATE OF ALASKA . .. AND GAS CONSERVATION COMMI'I-rE GAS WELL OPEN FLOW POTENTIAL TEST REPORT Test In,iai E] Annual r-1 specm Field Kenai Gas Field Operator Union Oil Company Test Date 7-30-75 Well No. KDU # 1 (~0tn~ty Kena i l~r°ducingl Thru j Re~errolr Ti30. I CSG. Temperature X 148 .r TIIG. Size J V~'t/Ft. J , ,, Pipeline Connection APL Wellhead I CSG. Size Temperature 68 '~ 7- I 3 I/2 Completion Date !1-13-67 lSet @ tReservoir Tyonek JLease A-028142 ILocation 411.4' N & 931 'E from SW Corner, Sec. 6, T4N, .Rl lW J ~Vt/Ft. J I.D. 26 & 29 · (,~parator) 2. 992 9457 0.555 IType Taps Flanqe Avg. Prod. Leni~ (L) ..9190 J989~,l,tD J T/Pay 9515 TVD 98.~8 5140 Gam-Liqt,id H) drocarbcn R'~lio )ICF per Bbl. 0 9155'--9175' 9210'-9230' Gra~ib' of Liquid ,Apl) 0 ' Multiple Completion (Dual or Triple) ,, _ Sing,lc with 2 Packers Type production from each zone Gas OBSERVED DA.T.& Flow Data Time of Flow Hours (Prover) (Line) Size 3.438 3.43~ 3.438 ~.4~8 Coem- ! ---~/h~ cient (24 Hr.) (Choke) (Orifice) Size 2.250 2 ,_.,0 Press. Diff. psig Tubing Press. psig Casing 2216 Press. pslg Flow( ng Temp. "F 2186 63o 2!47 2.250 , 2.2~0 Pressure psta 2201 2162 h 3.90 ~ 9.84 24.80 35-79 FLOW CALCULATIONS Flow Temp. j Gravity Factor. tF [ . FactOrFg 68© 71° · ; . 72© Compress. Factor ' Rate of Flow F 1,1387 . .1.13.37 1.1;314 1.146O { 3963 { 6128 · ; 27.696 { 92.649 27.696 I 145.856 27.696 t 226.957 '. 27,696 I . 269.012 207,71 ,, 2022 O.'. 9971 0.9924 I 0. 999.6 i o.~887J. PRESSURE CALCULATIONS 1.3423 1.3423 1.3423.. 1.>42> .2062 2007 ~562 11187. m ~ (psi.-,) 1r': F Q (F q)' (F Q): X 1-e-s P: p, -- P~ , Cal. ~.* p :t c c w e w P t c w P · , 1. · , Absolute Potential 11 27,800 .~,cr.,n · 5259 CERTI¥ICATE: I, the unaersi~ea, state mat I am lh~ cng i neer o~ m~ Union 0~1~ C,9~Pg~Y (company), ~d ~at I am nu~or~ed by said comply to make ~ls report: ~nd ~at this repot[ wa~ ~r~d ~der my supervision and dlree~on and ~al ~ lae~ ~tated.jhere~ are l~e, correct ~d complete ~'. r~ - , ,,.~---Gar~ Ejm carlson G_~Ar"~ELL OPEN FLOW POTENTIAL TEST P"~gRT . PRESSURE CALCULAT IONS (Supplement to Alaska'O & GCC Form No. G-I) Field Reservol. r Tesl Date ,,Ken, ai.,Gas Field ...... Tyonek 7-30-75, Operator Lease ~,~ll ;~o Union Oil Company of California ,,, A,-02814~ ..... KDU 1 __ .,, , Test (I) (2) (3) (4'i Ps pf (ps2_ pt2) 0 No, nsia _bsi~ X I04 !...~CF/D 1 2229' 2201 12.40 3963 ,, 2 2230 2162 29.87 6128 , 3 2231 2077 66.34 9562 4 2233 2022 89.78 11187 ,., Sub-Surface Test Data Subsurface pressuPes measured. Subsurface pressures computed: Cullender-Smith Y, ethod of I'¢ (I) (2) (3) (4) Test Pws 0 ' (Pws2-pw~2) Q No. psia psia X I0-4 -- ... , .. -- ...... Nomenclature- Ps = Static surface pressure -i~f~= Flowing surface pressure Pws ='Static bottom-hole pressure (mid-point of perforations) Pwf = Flowing bottom-hole pressure (mid-point of perforations) Q = Flow rate, MCF per day at 60°F and 14.65 psia aena~ oas r~e~a Back P~,-%sure Tests Well: .~ #1 Pool: Deep Survey Date: 7-30-75 1.O ' .05 ~ . 02 . O1 · --f-i:;--- .I ,i,., .... ~..~. , ."'i" '.; '. : ' :; "' :!!: -.;" : ~:: .... ~ ~ : i.; :. 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"[t'~ _ I ,~ / ': : ':::":" ':' ' : ~ ' '' ~' : : ' ' ' '~' ' ' ''' ' ; : ':: ; ; ; l; ':' ;': '; .... ::.i:~:~ h~-:i ~.,:;-=~;-}~i'~;~:~:; ~:~;h;:. : .~: :~:! '; ; iii: : ~: :::-'~i:~.F!~ i~:~J;ii~ :i:~Y:L:.i--~! :iiii'i~'~ ~ .: ~: :~:~: '.:h: ;t:: ~ ;'t ~t: :::.;.x .::: ;:,, ;:: ::!: ~. , _c.~. ~.~-. ~,,*r~ ~-,, ~. .... ,' ',', ''I · .-t '-~; ' ,,i' ~ , . ~_ ~._,.. t ..... ; ............ ~ ..... ~']Yq:~-'i" ['L'Z~":~:':~i ;'i~ i~ ~';;fi'~:i ' :~ '.--~i ~'.:1 iii; :~ .::X L?J ;:'_i ';i~:':~; ~t~.:~tn:l';:~ ~7;~::'! ~l :~: : ;~:;~ ~:~; : ~.; p:.{ t:';: ;:.'..,. : .... '' ;' ':.: 'i:' : - 'J*'-'-' '1-]~* a" 'ti~'~[~i~i! Ti;~I ~1 i?71 :~:J [l~.i ::l :/.. 1,:. L~_~ ~.! i: ~ .-. ; ~4 ;*~-~-hi · ~i.~ : i~.;.,l,~1. .~.~:h, ,..' .... ~ ,.,. t ......... : ...... 1 "it : : '~ :-l~ ': J~:i-':'-:':'7'~ ill~i ~;4-'-:i ,~: : i: t~ ~ ,~ ~ ':~- * ~-; '~;'~'~'~; '' f-''~'! J't''~ t ~t: .... 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[:::'1::.: .';~: -~i :~.: -:i-?-yt;L~:$:~-;: ::-.:~:{~ ~L}:tz;~; ~:: :,:~[ ';: ..-t~. :. ;:f -";~:: : -- ; ............ I --:7;[i'.-;"',';. ::':'";;:": ........ [ ':I~: ?'., ' : . :.~:~"~-~-~--,~.~:: '~':~ ~:~ ~:~l ~:~ .,:: ~ ~: :: :-: :.: :~-~:.: ::::. :-:?~-~ :.; :.~ :~:~,:::::::~::~:: :'.:::~:~':-'.:,':.: ::':' :',: ':"~:: ~:'. ': :~:' ' . -~7;'~'~' ~': '~ ~ -~: t' , , ~::,: ~ : ~::: ::.:'.t :.;.:.. ~:~:: : :: _._2 ....... i-;: : '. ~ . .:. : ~; ~:: .~t:: ~ ' :' : ": '1 .... ~' ';:; '~:; -" :~:~:-~:'$~4:~' ~:;~'~:?~:l; ;~;,~?:' /: :. ;: ~:';~:, .... ! ..... ~,-: ~-~ ~:: ........ H-:-".-.r~ ,~,~,"::: ::.;~" ::::::x~: '~'.[~:~:~ - t : :.::.': .......... -I--LL~-[-~-~t- -~-~' -:-~ ~-~t~ : '~.'':'~h .... ~'' ~: '' ~ ':[':' '~'tt :~t;I "' :''~ -,'~-~-t-~-~" tiC'i. : ..... ,,~.'~ ...... ~, ~. .~...: ............... ~ ......... -'- ~ ~ $--'-~-t-r~ ' ~ -1-::;~' ' "~ "~ ~'~ ' ' ~' ' ' :: ~i'[ P~"' '" f4~ '~ , ' ': d_ ! ; i ~ ' , ~- f; · * ; .. :~ . . :- ' ...... ; -~-~:~',-:i:'--::: ::':: ::::::::::::::::::::::::: ~:~: -~ :1 ': : ::':: :.:':'.::: ~.'::.::::',~'-: "-:: ~: ::'::::::'::.:':: ::".:~:.:: ':: '::' ::~..' .... ~ ' ~ -'~- · : ........ . "r~ ........ :' ....~ ' ., .. . ~- ::-- - - - ': : '"~ .... ,~ : ; . "' ~' ' ' ' ~ ' .~ ~. ~ ........ ~ ..................t ! ~: ...... · ..... ~ .... ,''~t''' :' ":~' ': .... : ....... ' : :: ...... -~-~ .... :-~t ~?,~':']:~'-?i",":,',-~:'x:'~ ::~: .:~::::~:-.:.:;: ~ ....... ~ .... r ,,--~ ..................... ,, ~i .... ~i , ..... · ........ : .... I', ...... -;-~. F'-~*, ~,,~"::~':"F[~ ~ i:'-: : :;1::~;: ~'-:: ........... ": : .... ~-:~-~,: ', ~ ........ ~' "~ ....... ~"~'~ ............ :'I .... 1 '" _:.:~:.;:.: :.~.: ; .::'::~..~ :': ~ t ;:t :.' .~:; . ::t ~ .L:;. ;':. :.:.' .... .-..~ ........... ' '' :' ;. :: ' : ''.:il: ;.::; ,', ' , '.: ;: ................... ':~:+-i-:--;:-.t:~::: ~::;:. i ff~.~ ~.[ [~ [::~: ~ii~ .::: :::: >:::'~-'::1:::: .::: 4:-;-:.;.::.: :;:;';:;;: ::~:~:E i!~ ~:[': ~''l'~'r'~' ] ============== ========= ':'' ~:~-:~':~,:_./~:~ ~: :: :::: :, :.. : :: ~ .~ :~,:~:~. :,~::::::::.:i:::~ ::::: :-:;-.~:-:::.~:t~.,-;:~: :~:.:::;:::::::::::.~ ~,,; ...... , .... , .................... - -~- 'L~ ~-'-: ~-: .... ~'' ;':'': .... ;" ....... t''" '~1 .......... : ..... ~:'; '~"'. 2~: ...... : _L': Fi: ~:. : ~' :'tt;;~:;: ;: :~ :: ':;~:: ~: ti: ,,2. ~.. .,. ............~ ..~ ...... ~--~-~$ -~-~ ',--~ ..... : ...... : ...... ~ .... '', ' ............. : .... ~ ....... ~ ...... · ...... ~ ~:,~, .~ ..... ,,,: ........... ~i .~,: .... ; .................... ~-'*'" :?:~:~'~T~, :=~;;::~::-: :-::: :::.: ~:~:-~:~',,,: '4:: ::::::::::::::::::::::::: :~::: ::'::::~ ......... ~,-,;,,-~ ....... ,-: ....... ~:-:,: ,:~:: :: t:: :: ~::: :.::: :::~:= :: ..... ~..~-~:.i::...I.-::,.~ .... ; f .... ~ ,.'[, .: ~ ..... :---,- .:'-I .... :': '.'~ ..... : ~'. ;::.~'::'t~ :.: . ,; ........ ' ...... ~ ............... ~ . : .... -,_~:.:~:,.~-, L' ~..~t.;'.::!.'.':::;:: ...... ' ...... ~.t,'.,. :'l: .......... , ;"~'I ........... ~-'-l!t'';t~; ..... ' ........... :'',' ': ''" :!:: ..... :' '':' '']'~:,':.'", '-iL~',/i'::_~;i''':; ~::x;:t~-:~':::~'~:~F.:::.:~;':~:~ ~. -~: .~'-';'1~ : ~,;;~;,,:,:;::~.,: :~:;[,!~:,:., .... : .... :~- .:-.:,: i-~-.' ~ i ;~ ~ i i ' ~ ' , . ~ , ~. . : : , ..... ~_..~ .f . i ,. , i ~ .... ~ U'' ,.~ . ~ ....... t" :' ,.t' , ~:t '/i , ~. ~..~.~ ~ . .' .' '1: ..... ' ,,., .+ -:. , ~,-, ....... , ........... : .... , ......... :"'," ..... i'-~ ~', :~'I ' 't~".~'~ ""'~ ' ' '' ''' '''' ' '~ I : ['' ~,' ,,i,' , l~, ': '-t i~ ~ , . ; ....... ;.,.~ ..... , ......... l~ .... --L-~-,-:- ,] ,.~-. i, . .~f.~...~.-? ~.~ I ........... * ......... t '~' "' .... * .... :I'''~''' ~ 'f I': '.' ' I "', ' '" ......... ',~ ',"" !.0 2 ii 10 20 50 i0~ OAS FLOW RATE ~C?/D ' : TBG. Size ,~rt/F,t. . . O.D. . - I.D. I. Set ~ . Oas. Gra~lty Avg. Prod.- - ~ '~:/2TM ::': :l' Ratio ,ICF ~r Bbl. "Gra~ty or 9.2* 3 1/2 2.992 J94S7 (~a~t0r) Leng~ :(L)' Liquid(Apl) Pipeline Connection [ T~pe Taps Multiple Completion (Dual or Trlple) J ~y~e produetto'n from ~ ~one , Single ~ith 2 Pa~ers OBSErvED Flow Data Time (Prover) (Choke) Press. '- ... :: Diff. · Tubing - 'Casing- . Flowing No. of Flow (Line) (Orifice) h Press. Press. TemP. Hours Size Size psig w pslg ": :-: .-'!. pslg ~ ' ' °F · sT_ ....... , 3i _c, 1R 1. 3)4 - _ ........ ~.' . · 6.06S ~. - 3/4 ..... ,. Z/2., FLO%V CALCULATIONS Coeffi- Flow Temp. Gravity ComPress. NO. eient -~-~/h p Pressure Factor Factor Factor--------~ateofFloW (24 Hr.)Vw m psia F F F Q ~CF/D t g pv- . ~.,:.,.84007,68 36,74 '672 0.9786 ''.' 2. 85598k08 70.86 669 0.971S '{'~'~'~'-' l.'.:0~ ' 5;.9!9 ~, 86093.52 , 89.96 674 1.0019 1.336~ 1.oaRn PRESSURE CALCULATIONS (See Attached) P P w pi Cal. w 'p_ (psla) 1~ F Q (F Q)*- (F Q)-~ X 1-e-~ Ps -- p~ p :t e c c W c . :W W i t e ,, ~ I. . :: . .: '.' . ~.. ,~; . .:.. . . ....... . :,.... ..: . , , Absolute Potential [ n 73; 000 - -: i~ICF/D[ ' ' _1~_- =: 0: 87a ' ' ' '- ' CERTIFICATE: I, the undersigned, state' that ! am th;Pr0d"'$upi oi the' 'Uni'/~n Oil Co (company), and that I am authorized by said company to make pared under my supervision and direction and that the facts · . the best of my knowledge. RECEIVED JAN 3 0 1968 ' [I¥1,~ION OF MINES & ,NiJNERAL~ ks re.ri; and that this report was pr~ / ~er/~n ar.e true. correct ,nd comp~e~ ~ Alaska 011 and Gas Conservation Commission .~. Gas Well Open Flow Potential Test Report (4-Point Test) Form No. G-1 Authorized by Order No. I Effective October 1, 1958 .~' . .... -"- GAS ¥: ..... ~ OPEN FLOW~ POTENT[A!.. ?~T ~, ....... ,P,,T Pese.:2 el' Initial. ~ Annual, [ .':Res~'rVoir- ii.,' '- -_- ' -:. I' Lease ~ A~0~8'14~ · . . I 'F I 7" I 26 i Set (~) I ' (]ns .Gravity [ Avg. Prod. · - · (Separator) Length (L) · g4S7 .S60' · 9190 I Type Taps '"" - '"" '" ' ' IType production Crom-e~eh zone OBSERVED DATA Flow Data operator .... , Union'0il. Co. (90unty { Location · ~e__,~_i ' Produclnl~ Thru [ Reservoir TBG. / CSG.[ ?emperatm'e 'TX / '- 'F TBG. Size : .....O.D, .... - - I.D. · .'~ 1/2"-[ :,'.~:~yt/Ft.,: .... ~lpeline Connection APL "~:"~;'-;'-: " Multiple Completion (Dual or Triple) Single with 2 Packers Time (Prover) (Oheke~ .. . Press. : .- -. Diff. ' Tubing..: 1' ; Casing, , .., Flowing i,~o. of Flow (Line) (Orifice) h Press. Press. Temp. · Hours Size · Size psig w ": r :psig SI . : .... :, :. ;... ., . .., ~ . _ ~nn ....... --- -- , . 2. 114 6 0~ ~_qoo ~K ~ n,, Y~-~'c . ~.~e j~ ~..":,. ' .. :;., . ~: ./..;. ~. ;.. ;:::_ ./L : .-.' .' . I 4. . ~ ., FLO%V CALCULATIONS Coeffi. Flow Temp. Gravity Compress. cient ' ----~/h p Pressure Factor Factor Factor Rate of Flow (24 Hr.)V w m psia F F F Q MCF/D · t g '.,'- pv. '~;'-, . ... " ~ 86179.44 :150,83 689 l..nn~o '1 ~A~ 1 ngl~ PRESSURE CALCULATIONS P P Cal. w w (psla) 1~ F Q (F Q): (F Q)-' X 1-e-~ P~ p~ -- 1~ p p :t c c c w , · e ,' W 'w P t c . 2. ., ! Absolute Potential I n . . . .~- :,. . MCF/D] ; . . , :. . :. CERTIFICATE: I, the undersigned, state that I am' the ' of the (company), and that I am authorized by said company to make this report; and that this report was pre- . pared under my supervision and direction and that the facts stated therein are true, correct and complete to the best of my knowledge. Signature RE'CEIVED JAN 3 0 1968 DIVISION OF MINES & MINERAL~ ANCHORAGE Alaska Off and Gas Conservation Commission Gas Well Open Flow Potential Test Report (4-Point Test) Form No. G-1 Authorized by Order No. I Effective October 1, 1958 7 a it i al ~.:.j A'nz: u~d {~.~.i S~ T~,,:;,::~ ~..',. ..... Kenai Gas"F~eld I- "i Kenni ',n', Lease Union 0il Co, A-'028142 . - . ,~ u~. R~e,olr [ Wdlhead } CSG. S~ 1~ %Vt/F{;' l-~:' I.D. .......... ....... ISet~ Temperat~e ' Tem~rat~ '~ 'F 6~ t 29~ '9858 Test Date %Yell Xo. KDU NO, 1 [ T/PaY "]'Producing Lower | Inte~al _.~.:,' 9670u9720 · i~i~perator "~'Producing Thru I 'iJ os . I 3 9.2. 3.s,, .992 ' I- Set @ I.-c,sCra~it~_, I .- /,,. Prod- ] 'GL "/ "94571. 560r' (S~,ara,or)' -/)6251LenC"h (I~)I 5390 Oa.~-Llquid H}'dr0carbon ,. ] Gravity of Ratio MeF:per Bbl." : Liquid (Apl) No IJiquid .... ' -- ~::- Pipeline Connection :l ! . / APL Type Taps .... Flange Muhiple.Completion (Dual or Triple) Type production from ea~h~one '~' Sinele with 2 oackers .Gas -- · " OBSERVED DATA '" Flow Data .Time (Prover) (Choke) ' Press, . 'Diff. , Tubing · .Casing Flowing No. of Flow (Line) (Orifice) h Press. Press. Temp. Hours Size Size psig w psfg . :-: ". ' pstg ". °F , ,. st ........ , ..-,. - :~. 3/4 6.065 s.sO0 ...... , : ~;0,~ 6:0,, * ~. m mm !/2.... 6.065 3.500 600 12.0" ,. 1.' ...... , ?;6'j06~ ..... '~:500" ~:''' '60'0~ ' 1~;0" ."g2.35 ' "-- "'~ ~'~ 4. 3/4. t '6.065 5.500.. 610 28,0" --',':'2920 .~,- .,_..- .t 47e FLOW CALCULATIONS · Coeffi- ' Flow Temp. Gravity compress. LIo. eient ----%/h p Pressure Factor Factor Factor Rate 0f Flow (24 Hr.)VTM m psia F F . F Q MCF/D t g - pM ~; 84634.52 t 60.72 614 O_OS~9 ~ *l_x~,'~ ~ n~.~ c , ~a , .. '.'.: ~ 7..-'. .- ' ;'"~"; -?.~"" ' ", -- ' '~'"" 2. ,,, -84007,68 85.86 614 .0,9786 ! ,x~6_x '!.0_~5_~ 7.2!5 3. 85681.44 105.16 614 0.99R1 1.-~XR~ ~ ndxn 9, ~nn 4. .86934.96 : 132.22 62,4 1.0127 1.31,6~ ' '::~":"~,~'-~" ".::'. '.-~"l 1:1 a'~;' ' PRESSURE CALCULATIONS (See Attached) · _..--. _v ........ ; .: , . P Cal. w (psla) 1~ F Q (F Q): (p Q)-" X 1-e-s p: pi -- I~ p 'p :t e c c %v c w t 2. ,~, ..:._:- ~ ._ . . ..~- . -..: , . 4. ~ i Absolute Potential ] n '49, 000 ~WF/D] O_ 7R CERTIFICATE: I, the undersigned, state that I am the Prod Sup! et the Union 0il' Co. (company), and that I am authorized by said company to make~M rel~drt; and that this report was pre- pared under my supervision and. direction:, and. that the facts~.~~ ~ther/~in-- __._a~.~tru_ e,~ co.rrect and complete to RECEIVED JAN 3 0 DIVISION OF flAINES & MINERAL~ Alaska Off and Gas Conservation Commission Gas Well Open Flow Potential Test Report (4-Point Test) Form No. G-1 Authorized'by Order No. I Effective October 1, 1958 (v) . ~J ~ tO' c. A. wHrr~: gales and Service SUB-SURFACE SURVEY STATIC · UNION OILCOMPANY . KENAI UNIT - Company ............ 0F...C..AL..~.OI~IA .......... Field ............... KF_2~AI..GAS ....................... Lease and Well ..... I~'i..DEEP...TF~ST...#. 1 County ..................~.N.A...!. ....................... : .... State ................ A~K..A ............................ Date .............. D..0..9 e.m.b.e..r.....].~5.,....1..~..6..~ ......... T.D ........................................................................ Formation ..................................................... · Elevation ........... Casing ..... 0%is "X" Sletrve @ 9087.22' ....................................................... 0~.'l~'"":X¥,'"g'l~'//i/~"¢.'"9~'"/~';'65, ' Tubh~ set: 9/*73 Size: 3..1./2" ' Pgrforafion ........ C~e'i~S(~i~."~h~'S~iL'"~'p~']~'"(~'l~'"~d) e 9/*72.63' Datum Point...9632..' .................... 0.,.lil~...!~N" Nipple @ 9/,71.69' (midpoint) DEPTH (FT) FD[TENSION (IN) PRESSURE (PSI) CR^DIEN7 (#/FT) O .......... 1./,35 ..... · .... 3620 1OOO ......... 1.g?O ..... . .... 3710 2000 ......... 1.505 .......... 3800 3000 ......... 1. S&0 .......... 3889 4000 ......... 1.572 · · · · ...... 3972 5ooo · 1 605 4057 · · . · . · · · · . · · · · · · · · · 6000 ......... 1.635 .......... 413/* 7000 ......... 1.666 .......... 4213 8000 ......... 1.695 .......... /*288 ' 9000 ......... 1.722 .......... 4357 9632 ......... 1.739 .......... h&01 = .......... 090 .......... 090 · · . · · . j · . .08~ .......... 083 . ......... 085 .......... 077 .......... 079 ·075 .069 .069 RECEIVED JAN DIVISION Oi= MINES & MINERA~ ANCHORAGE Sales and Service ~- . - Eng. Dept; SUB-SURFACE SURVEY UNION OIL COMPANY KENAI UNIT Company ...... .O.,F..C.A.L!F0,..I~..{!A. .............. Field ...... IfENAI.GAS .................... Lease and Well. N~'.~..DEEI~ .IES.T. ~.. 1 Countyl ............... ..Kt~!AI ...................... State ALASKA .......................... Date...Dec em~ .e.r....K0,.....1.~.6.7. ................ T,D,. ' Formation .................... Elevation ....................................................... Casing .......................................................... perforation ............................................... ' .... Tubin§ Ps .i. ~. :.. ,'.3. ~3.0. .......... .s..e...%..:....?..~. ?..~.,. 1 2 " & , 6 " 8 " l0 Datum Point .... .963..2. ?. ........................ .. DEPTH (FT) EXTENSION (IN) P?ZSSUP, J~ (PSI) FLOW 0 .......... 1.179 ......... 3527 9632 .......... 1.4&6 ......... /,338 ....... $ 9632 .......... 1./.27 ......... /+280 = Ps1 .... $ 5~C~ 9632 .......... 1./,0/, ......... /.21(}. = ps2 .... 7 9632 1 38& &149- .................... = PS$ .... 9 9632 .......... 1.3&7 ......... /,036 = PS4 .... 11 9632 .......... 1.25& ......... 3755 ....... (not explained) BUILDUP DATA 0 hr .......... 1.25/~ ......... 3755 1~/+36 ......... ~308 , 1.£36 ....... ... /,308 1./.36 ........ 1·/.35 ........ ........ ........ ...... · &308 · &305 · /,305 · /*305 · RECEIVED JAN 3 0 ~ " ' I /+3/, ~302 DIVISION OF MINES MINEP, AL~ · · · · · · .· · · · · · · · · · · · · ~ · - ·- · · l.&3/, ......... &302 - Re~rks: 1, ' Test of lower zone ~th all sleeves ~ closed ~si%ion. L. OGARITHM lC 46 7403, CYCLES MADE IN U.S.A. · KEUF[*4~L & E$$ER CO. TIME (HOURS) '~ C. A. WHITE Sales' and Service En~. Dept. SUB-SURFACE SURVEY 18 HOUR BUILDUP Fx~DW RATE DATA ' UNION OIL 00~ANY C, omPany.. - OF CALIFORNIA ' Field ...................... ~A.!...C/.A.S .................. Lease and Well ...... K..E.N..A.!,...UN.!.T. ............. .................................................... N~,~' DF, EP TEST # 2 County ........ KENAI ..State ALASKA - , ......... Date. 12-29 thru 12-30-6~.. T.D ........................................................................ Formation ....................................................... 1 If 18 " Elevation. ' · ..Casing ................................................................. Perforation ........................................................... Tubing ..... Psis.:...3515. ....... S.et.=...9/,7.3 ....... Size.' 3 1/2" Datum Point ..................... .9..1...9..2. .................. CHOKE (6iths) EXT~SION (IN) PRESSURE (PSI) FLOW RATE O ........... 1.667 ......... A226.O ....... Shut in 6/6& ........... 1.650 ......... A182.8 ....... 3.08 MMCF--Psi 12/6A .......... 1.625 ......... Al19.3 ....... 5~.91 ~CF_- Ps2 l&/6i .......... 1.6o9 ......... &OTC.7 ....... 7.7A MMCF-- Ps$ 16/6& 1 590 A030 i 9 78 MMCF= Ps4 . · · · · · · · · · . · · · · . · · · · · · · · · · · · · . 19/6& ....... . . . 1.567 ......... 3971.9 ...... 11.73 ~MCF= p .......... ......... ...... q HOURS BUILDUP DATA 0 1 5~5 - 3915 8 5 m~n. (approx.)...- . . 1.659 ......... ~205.7 1/2 hr .......... 1.660 ......... 4208.2 .......... 1·661 ......... 4210.8 .......... 1.662 ......... 2213.3 .......... 1.665 ......... 2220.9 1 666 2223 5 · · · · · · · · · · · · · · · · · · · · · .......... 1. 668 ......... f1228e 6 1 669 ~231 1 · · · · · · · · · · · . · · · · · · · · · .......... 1.671 ......... 4236.2 .......... 1.671 ......... A236.2 = P£ Remarks: 1. Test of top zone with XX Plug set at 9275' 2. Sleeve @ 9087' in open position. 'RECEIVED JAN 3 0 1968 DIVISION OF MINES & MINERALS ANCHORAGE "inter. Department Route Slip '- ATTN.: I-~ Approval E] signature [-] Comment r-] contact Me [~] Prepare Reply r-~ For Your File [-] Note & Return [] Initial · Return [~] Return As Requested [~] Return For Approval r~ Necessary Action [~] Your Information Remarks: UNION OIL COMPANY OF CALIFORNIA KENAI DEEP UNIT :~ I KENA~ BOROUGH, ALASKA 9895' M.D. 9519.,~s' V.D. N. 749,20' E. 1652.99' ~ ; ~;0~ Z~t~tzA- Santa Ana, Callforn,a 92701 00~~ ":967' COMPANY X~ION OIL 0 .~ . ADDress ....................... ~ 'w~u~NAI DSEP U~T ~1_ bOCAT,OU ........ ~ COU~*~ ~NAI,BOROUGH .... *T * * ~ __m ~AS~A .... '- ~-" ......... t"-: .... ' ...... I ......... t i r , / j I ' Jj' ' lt I, oo~ ' 0'~ ' 6 ~ 29i30,,N . E , m ) i 730~ 53t ;i 16h8 2~ _[_ _ ~L tYPE OF' SURVEY:.. CALCULATED BY _CHECKED BY ....... " :::"~ -"= ' ALACAL DIRECT NAL DRILLING:...CORP. "~ 5, 888 No. ' Main Street Santa Ana, califOrnia 92701 DDR'Ess: COMPANY____~ 0IL C0MPANM 0F CALTFO~'IA .A WELL ~NAI DEEP ~TIT ~1 .LOCATION- -KENAI GAS FIELD COUNTY.._~1~~_BORC)',['),O.H_ _STATE JOB NO SHEET NO_ OCTOBER 19'07 ALASKA MIAIIURIID jCOURSE'] D'EVIATION 't VERTICAL DEPTH COU.SE DIRECTION ......................... C)F" OI~PTH j L IENGTH' ', ANGLE ii COURSE ' TOTAL DEVIATION DEVIATION /3366 22 8129, 06 :t39i99 _~ 67. E! ~6 3 9 ,~2/'~_._ ' COURSE,_ TOTAL L~ ~ ~ ~ , 5 t~ 5 ...... ~' .... It_ ~ ~ .... ].. 606 85t , ~3o8, 55[ 622 25~1 9___262 ~3~.5_ 9/,17 .... _975]L ....... :,L.2__5 ; 9228' 28; 66; _7_7_i N 67 i_-,~ '9,~95 ', ; ' ..~._0~ .....: 9519 /~8:132! 70!~ N. ............. t.._ ............................ II ............ ~I 8993i21 23186~,N, 67 ~E ; J :' I l! ": 660 ~7:, ! 1~'26 + ' ~ tin~ ' ~, 679! 90! 1&66 06j %9 20i i ! 1652 99 i i - .. , o os Z! '.a, !s ol - TYPE Of SURVEY' CALCULATED BY _CHECKED BY ~.r~' ~' ALACAL DIRECTIONAL DRILLING CORP. Jo, .o.. 1/"3 ..... ~_. '~. 888 No. Main Street · Santa AAa, California 92701 $#~IT I~O .......... ' OCTOBER 1967 COMPANY UNION 0IL COMiPANY OF C AL~0R.NIA ............. ADDRESS ............................................. i W~LL~NAI DEeP UNIT ~1, ,,L~ATION ~NAI GAS ~ELD COUNTY ~NAI BOR~GH _,, STATE ALAS,~ ..... ......" ~o....~..v,..,o.~l VERT,CA~ o~H ~ ~ou.. ~ o,.~/,o. ~ ~A~'~.'~. c°~"s%..*'.~u.~ ~... .~,~... .TOTAL. ~....., ..' · ~PTH LENGTH ANGLE ; ..... cOuRsE ~ TOTAL ~ GEV ATION I DEVIATION '1 "O"'" -'~~ - ~*'' , ....... W... :4 ...... "O"~. ~ 'GU'. ' ~*.~'r~'""~W%~ 5099 j~ 0 30~ 5099i00 0[ 871 N 38 W~ ~ ~ , ~ 0 69 ~ 0 5~ 5~3o ~' 2 ooil ~ ~ 5z29~98 ~o8 ~ 25 i~ · ~ ~ ' 1~6~ o o9 ~ 5192 ,[ 5 ~{ ~ , 5191,80:2 70 N L& E [ ~, ' , 5 26 2 70 i~ 6~ ~ '~ ~20 5~ 657 6~ i7270 25 ~0~i 7~301~0i1~~ , : . · , ~J7795 22 2~83~iN 66 E I :: ~ A50 l& ~..939 35. _ ....... ,.. ~... . ..... ,,,, , ·, , ~' ,, ,,.... , ....... TYPE OF:SUR'VEY: ,,, CALCULATED BY CHECKED BY, U'/~%ED STATES SUBMIT IN '~ (Other inutructio. ~ re- DEPARTME, OF THE INTERIOR ,-erse GEOLOGICAL SURVEY SUNDRY NOTICES AND REPORTS ON WELLS ida not use this form for proposals to drill or to deepen or plug back to a different reservoir. Use "APPLICATION FOR PERMIT~" for such proposals.) LEASE DESIGNATION AND SERIAL NO. 2. NAME OF OPERATOR Union Oil Company of California A-028'142 6. IF INDIAN, ALLOTTEE OR TRIBE NAME 1. 7. UNIT AOIIEEMENT NAME oI~w=L E~ ,~,,Sw~,,,,, ~ OTHER Kenai Deep Unit 8. FARM OR I,EAS~ NAME ' 3. ADDRESS OP OPE, RATOR 507 iq. Northern Lights Blvd., Anchorage, Alaska 99503 4. LOCATION OF WELL (Report location clearly and itl accordance with any State requirements.* See also space 17 below.) At surface 411.4'N· 931.0'E from the Siq corner of Sec. 6, T4N, Rll~, SM l§. E~VATIONS (Show whether DF, BT, OR, e~.) RT 90 14. PERMIT NO. 67-45 9. WELL NO. 1 I0. FIEl,l) AND l'OOI,, OR WII,DCAT · 11. SEC., T., n., ~i., OR ELK. AND SURVEY OR AREA ;ec. 6, T4N, RllW, SM 12. COUNTY O.R PARIStI/13. STATE ienai Peninsula. · Alaska 16. Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO: TEST WATER S~IUT-OFP PULL OR ALTER CASINO FRACTURE TREAT MULTIPLE COMPI,ETE · . SHOOT OR ACIDIZE ABANDON* REPAIR WELL CItANOE PLANS (Other) Test "D" Sands SUBSEQUENT REPORT OF: FRACTURE TREATMENT ALTERING CASINO SHOOTING on ACIDIZlNO ABANDONMENT* (Other) (NOTE: Report results of multiple completion on Well C(,mpletlon or lleconH)letlon It(,l)ort and Log f. rm.) 17. DI. iSCRIBE I'ROI'OSgD OR CO.~[I'LETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including esthnated date of starthlg any proposed work~ If well is directionally drilled, give subsurface locations and meaN, red and true rertieal depths for all markers aad zones perti- nent to this work.) * ,. PRESENT STATUS OF iqELL: TD 9895' ED 9811' 13 3/8" C 1209 in 17 1/2"-hole with 1200 sacks cement 9 5/8" C 4984 in 12 1/4" hole with 998 sacks cement 7" liner in 8 5/8" hole 4870-9858' cemented with 600 sacks cement· PROPOSED: Perforate 9720=9670' 9555-9535' 9230-9210' ~ 9175-9155' · · · · Evaluate tests, if productive· complete dually with Module #3 C"A" Sands) .from 3720-3550' at selected intervals. ,: · Should any aY the "D" sands prove to be wet, the intervals will be squeezed and eliminated from proposed completion. · Bottom hole location 7492~' N ~ 1652.99' E of surface location. ' "- Above program approved ver,bally by Mr. William C. Wunnicke. "'...,';: ~,' .::..' ,' .. - . ~ . 18. I hereby certify that the foregoing is t~)le and correct SiOSED .~'[25... ~~~?/C<~>... TITLE/Lts~O~ill/~g2Supc~J~tenden~ATE ' 1J~-15_-62 (Thl~ space for ~ederal or State office use) " APPROVED BY CONDITIONS OF APPROVAL, IF ANY: TITLE *See Instructions on Reverse Side DATE R 'E: C' E.I, V [ O NOV 1 5 1967 DIVISION OF MINE5 & MINERAL8 UNITED STATES DEPARTMENT OF THE INTERIOR GEOLOGICAL SURVEY LESSEE'S MONTHLY REPORT OF OPERATIONS State Alaska Co~ty Kenai Peninsula Field Kenai Gas Field ' Tl~e followin6~ is a correct· report'of oPeratlo~s a~d prod~otio~ (inel~dln~ drilliz~ and prod~ein,~ wells) for ti~e montI~ of ....... _OcKo. b_~_:[ .................... , 19_.0._7__, ............................................................................ .~l~e~'s address 507 ~T. Northern Lights Blvd Union Oil Company of California ........................................................... '_ ....... Co~pan, y ........, ........... : .................. '. ................... ............................................................................................. ......... ........ : PAone .......... 27_7._-_1_401 ......................................................... dZent's title __D_!__s__~.,__.p. Li_l._!!_n.g_._S_.u_p.e..r..i_.n__t_.e__n..d.p. nt ~ ~ Budget Bureau No. 42-R356.5. ,, ' Approval expires 12-31-60. · ,..,dO OFFICE .................................... ,"'~]/,~/, L£A~£ NUMBER ................................. UNIT ........................................... Cu. FT. OF GAs (In thousands) Drilled fz bit at 992 x 50' dril 8 5/8" sta hole. Bot Plugged fx cement mi~ from 9050. ~ALLO~S o~ ~ASOLINE ~m 6216-I 6'. Lef' 1 collar: bilizers tom fish om 91S0' ed with 9784'. BARREL8 OF WAT~ (If no_~no ,_.s_o state2 ~956. P 8 5/8" -2,6 - j ars RE,IA R KS (If drilllnE, depth: if ~hut down. oau~; date and result of t~t for ~olln~ Content of g~) pe stuck bit - 23, 6 1/4" 1/4" x 20' monels-4, .nd bumper sub in at 9917~ top at 9130'. to 9030]with 92 sacks ZO% sand], Redrilled qow re-d~illing. NoT~.--There were ..................... ~.O ............. runs or sales of oil; ............... ~P ........................... M cu.' ft, of gas sold; ........... ~.O_. ........................... runs or sales of gasoline during the month. (Write "no" where applicable.) No~.--P. cpor~ an this form is required for each calendar month, regardless of the status of operations, and must bo filed in duplicate with the supervisor by the 6th of the succeeding month, unless otherwise directed b~ tho aupervisor. R E C F I V ~'or~x 9-329 (January 1950) 16--2~766,-$ U. ~s, ~OVS~RNMS~N? PRIN?INO OrFIC~ .NOV D DIVISION OF MINES & MINEP. AI~ (Do not use this form for proposals to drill or to deepen or plug back to a different reservoir. Use "APPLICATION FOR PERMIT--" for such proposals.) O~L h_~ CAS ~-] WELL WELL OTtIER 2. NAME OF OPERATOR Union Oil Company of California INDIAN, ALLOTTEE OR TRIBE NA.ME ?. UNIT AGREI'].M~NT NAM~ Kenai Deep Unit 8. FARM OR LEASE NA~E 3. ADDRESS OF OPERATOR 9. WELL NO. 507 W. Northern Lights Blvd., Anchorage, Alaska 99503 1 4. 10. ~'I'I~I.D AND POOL,, 0i{ WILDCAT LOCATION OF '~\'EL-L (Report location clearly and in accordance with any State requirements.* See also space 17 below.) At surface 411.4'N, 931.0~E from the SW corner of Sec. 6, T4N, RllW, SM 14. pERSII,]r NO. 67-45 15. ELEVATIONS (Show whether DF, RT, RT 90 ~.,1. SEC., T., i~.., ~7., Oil LfAf. AND Sec 6 12. COUNTZ on r,:,~]~-(-'i3..STATE Kena~ 2eninsu :: Alaska 16. Check Appropric~¢ Box To ~; ' ~ .... ' NOTICE OF INTENTION TO: TEST WATER SHUT-OFF ! I PULL OR ALTER CASING FRACTURE TREAT MULTIPLE CO.MPLETE S,q0oT OR ACn)IZ~ ARANDON* REPAIR WELL CHANGE PLANS (Other) Test "D" g~nds SUBSEQU?-NT i:~?ORT OF: WATER SHUT-0FL~ __~ REPAIRING WELL FRACTURE TREATMENT ALTERING CA~iNG S~OOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report resultz of multiple completion on Well Completion or Recompletlon Report and Lo~ form.) lT. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly stateall pertinent details, and give pertinent dates, including estimated date of starting any proposed work. If well is dimetion~y driIl~, give subsurface lo~tions and measured and true vertical depths for all markers and zones perti- nent ~ this work.) * J' . . · PRESENT STATUS OF WELL' " . TD 9895' ED 9811' · i: .. . . 13 3/8" C 1209 in 17 1/2" hole with 1200 sacks cement '" -'. ' ' 9 5/8" C 4984 in 12 1/4" hole with 998 sacks cement " · :. 7" liner in 8 5/8" hole 4870-9858' cemented with 600 sacks cement.- PROPOSED' . Perforate 9720-9670' 9555-9535' 9230-9210' & 9175-9155' Evaluate tests, if productive, complete dually with Module #3'~{~" Sands) from 5720-3550' at selected intervals. · Should any of the "D" sands prove to be wet, the intervals will be squeezed and eliminated from proposed completion. -. ' '.. . Above program approved verbally by Mr. Karl L. VonderAhe. · 18. ! hereby cert~y that thc forezoin~f is true and correct , .. S!G~W2D TITLE __ I !-,5. - 7 (Thi~ space for Federal or State office use) APPROVED ]BY TITLE ATE R[/FIV[D . -NOV 7 1967 OIVI$1ON OF MINES & MINERAL8 Form No. P--4 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Effective: July 1, 1964 LAND I'~ F F' I E; E LEASE NUMBER LEASE I-1R IJNIT NAME ir- LESSEE'S MONTHLY REPORT OF OPERATIONS State T~e f°llowir~ is a oorreot report of oPeratior~s arid prod~otior~ (ir~ol~dir~ drilli~l arid prod~zoir~ff wells) for the mo~tl~ of ___:_S__e_p_~_e__m_.b_.e__r_ .................... , 19_.5.7_._, ............................................................................ · .,i~e~t's address .... ~g~___bl___:~_~_?_r._t__h__e_.r__n____L__i_gh__t_.s_.:_B_..l_v.__d_,_ ...... · Company ___.U__n._i__o_.~__([i._J:___C_.o.::___o__f..J~__a__l_.i_~.: .......... Phone ............ 2__7--7___-_~_0_! ........................................................ ./lffe~t'.s title _I)JJi£~__DrJL~.__Sjapt: .................... SEC. AND D.rs. CU. FT. or GAS GALLONS or BAREEI.~ olr RE1VIARKS ~ OF ~ TwP. RANGE WELL BARRE~ OF O~ GRA~TY GASO~E WATER (~ (If ~g, d~th; If shut down, oa~; NO. Pao~c~ (~' tho~) RECOVERED none, so s~te) ~te ~d r~ult of ~t for g~o~e Kenai Deep Un:Lt Nc. 1: Spudde~ at 3:00 pm Sept~mber 13, 1967. Drille~ 17-1/2" hole to 1220'. ~n and ~ cemented 13-3/8" 61~ J-~5 casing at 1209' ~ with 1~00 sacks cement. Drilled 12-1/4" hole tc 5000'. Ran ele,..tric logs. ~n and ceu~ented 9-5/8" 40~ J-55 casing at 4984 wi:th 998 s.~cks cema:nC. Drilled 8-5/ directJ.onal hol~ from 5{~00' to 6216'. Now drJ.lling. ............ 'NOTE.--There were ........................... BP ............... runs or sales of oil; .................. XI.O. ........................ M cu. ft. of gas sold; ............................... · .....~...O. .................... runs or sales of gasoline during the month. (Write "no" where applicable.) NOTE.--Report on this form is required fOr each calendar month, regardless of the status of operations, and must be filed in duplicate with the Division o£ Mines & Minerals by the 6th of the succeeding mo~,th, un~e~ o, th, ei[wmisee~' directed. g I: IVt'U OCT 6 1 87 ~I¥1110N OF ~ & ~ Jr, FORM FG- 74/.REV. 2-67) MEMORANDUM TO: ~-Thomas R. Marshall, Jr. Petroleum Supervisor Division of Mines and Minerals 3001 Porcupine Drive, Anchorage FROM: PO!il A. Le ROUX /~/] Water Projects Biologist ~ Division of Commercial Fisheries Anchorage State of Alaska DEPARTM]!iNT OF FISH AND GAME FILE NO: DATE : August 30, 1967 SUBJECT: Kenai Deep Unit Union Oil Company of California, operator. The Alaska Department of Fish and Game requests the following fish and wildlife stipulations be attached to the pemit t° drill. (1) Prior to drilling the operator will construct a sump of sufficient size to contain all waste fluids. (2) Prior to drilling the operator must construct a low ring dike around the drilling area to contain any spills that might occur. (3) Upon completion or abandonment of the well, the sump must be cleaned of oil and filled, and the general contours of the drilling area restored. cc: Huizer Meacham Rearden Stefanich Croxton RECEIVED AUG 3 1 1967 DIVISION OF MINES & MINERAL~ ANC~gAGE 1067 BE: ~07 u. Borehern ~s Blvd. Form P 1 SUBMIT I1~ . ~ CATE* sIATE_'OE' ALASKA >' '~' · (Other instruct,ohs on ...... reverse side.) . OIL AND GAS:'::J~0N~EJiVATION'CO~Is~ION .... APPLICATION ~FOR :PERMIT-' TO~ DR'ii:L, 'DEEPEN; OR PLUG.'BACK' APl 50-133-20035 Effective: July 1, 1964 ., ~." LEAHE DESIGNATION AND SERIAL NO. A-0281~2 b. T~Pa O~WELL, ;' ~ ' '- ' ~" ..... '~ ' .... ....... ~';'~: ' Kena~- ~Deep Unit 2. NAMB "," ' ?'A~R:' "" Union Oil Company of California · - ' ;--, ~ '~ ,-'- ~ .~-- ,~ ~ ''~ '-;~;,->J~.- ~ -, -~ ;-':: ~, -,i~- i~.~,i~ ~. ~'' - - ' -'i' ,, ADDRESS OF OPERATOR , : ~--,~':: ~'c ;-' ,L,' .' ,' ",,'" .... . , ~%:-,:%: ' -' · '.-:" -, ' 507 W. Northern Lights Blvd. ;'-Anchorage ;'~A'laSk~'99503 ' "' 4. LOCATiON-OF -WELL (Report location clearly-andin accordance with anyState requirements.*) At surface 411.4 ' N; 931,0' E-' from the SW"co~ ,: Of SEC';:; 6, -T~-N'," RltW,' SM At proposed prod. zone 1000'N, 2640'E of SW cot. Sec. 6, T4N, RllW, SM 14. DISTANCE IN MILES AND DIRECTION FROM NEAREST TOWN OR POST OFFICEs 6.5 miles from Kenai INDIAN, ALLOTT~ OR TRIBE NAME .., "b. w.£t, so. 1~): ~IEt,D'~lJ~ POOr;, OR WILDCAT 'Nei~ pool' Wildcat 11. SEC., T., S., M., os. BLK. Sec. 6, T4N, RllW, SM 12. BOROUGH sHJ 13. STATE Kenai Penin. ] Alaska 1§. DISTANCE ,ROM PROPOSED* 16. NO. OF ACRES IN LEASE 17. NO. OF ACMS ASSIGNED ~ao,,a,, oa ~.*s. ~,.., ,,. 1000' 2560 640 (~so to nearest drlg. unit l~e~ if any) IS. VlS~Sc~ ~ao~ ~ao~os~v ~ocx~os* N 155~ ,E 33 ~ ~9. ~ao~os~o .v~a 20. ao~ 'oR cts~ ~oo~s TO NEAREST WELL, DRILLING, COMPLETED, os ~,~ ~s, o~ ,ms ~, ~. from KU 14-6 9700' Rotary 21. EmVA~0NS (Show whe~er DF, ET, GR, e~.) 22[ ~PROx. Oi~ woa~ Wlb~ RT 90 August 15, 1967 SIZE OF HOLE 17-1/2" 12-1/4" SIZE OF CASING WEIGHT PER FOOT 13-3/8" 61 9-5/8" 40 SETTING DEPTH l~OO 5000' 1000 sks. ? ;.,',; 500 sks. Drill 17-1/2" hole to 1200'. Run and cement~13-3/8" 61# casing to surface. Install and test 12" 3000# double hydraulic gate and "GK" Hydril. Drill 12-1/4" hole to 5000'. Run electric logs. Ruacand cement 9-5/8" 40# casing. Install 10" 5000# double hydraulic gate and "GK" Hydril. Drill 8-5/8" directional hole to total depth. Log and evaluate for completion. A 5-1/2" liner will be run if deep zone is completed. IN ABOVE SPACE DESCRIBE PROPOSED PROGRAM: If proposal is to deepen or plug back, give data on present productive zone and proposed new productive zone. If proposal is to drill or deepen directionally, give pertinent data on subsurface locations and measured and true vertical depths. Give blowout preventer program, ff any. 24. I herebyl ~rtify that the Fo g is True and Correct. (This space for Federal or state office use) PERMIT NO. ' -' /:2: · .-<" /~-/ . ,, ../ CONDITION8 OP APPROVAL, IF ANY : AP1 50-133-20035 o LD T Executive Secretary TITLE Alu~ku Gl; & ~n~o~ation Committee *See Instructions On Reverse Side DATE RECEIVED Aua 1967 DIVISION OF MINES & MINERAL3 $ C A L E I":20 w i '7"7 9.8 6 T4N ~ !...'6~ S W COR, 12 7 SECTION EAST - 992.00 SURFACE LOCATIONS K U 14-6 (Existing) No. I IWEST- '1' :'~ K U 21 - 7 (Existing) C, Top Grovel Fill Elev. _'4. o! LEGEND ond NOTES' · Found U.S.G.I.O. brass cap monument, All bearings refer to the G.L.O. datum of North for the West boundary of Section ?, Elevations refer to Mean L-ow Tide as being o. oft. determined from the U.S.C. ond G.S. tide datum for the Kenai River entrance, RECEIVED 28 1967 DIVI~ION OF MINES & MINE#AtJS UNION OIL COMPANY OF CALIE OPERATOR KENAI DEEP UNIT NUMBER SURFACE LOCATION LOCATED 411.4 FT. NORTH AND 931.0 FT. EAST FROM THE SW CORNER OF SECTION 6,T4N~ RliW~ S.M., ALASKA. · SURVEYED BY: Stanley S, McLane, R.L.S. Date: July Z4~1967