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Home My WebLink About208-088Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/31/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240531 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 1/25/2024 AK E-LINE JB/GR/RBP MPI 2-14 50029216390000 186149 5/8/2024 READ CaliperSurvey MPS-17 50029231150000 202173 5/14/2024 READ LeakPointSurvey PBU GNI-03 50029228200000 197189 5/21/2024 READ PressureTemperatureLog PBU GNI-04 50029233670000 207117 5/22/2024 READ CaliperSurvey PBU GNI-04 50029233670000 207117 5/20/2024 READ PressureTemperatureLog TBU K-12RD2 50733201560200 208088 5/17/2024 READ CaliperSurvey TBU K-17 50733202480000 173001 5/16/2024 READ CaliperSurvey Please include current contact information if different from above. T38865 T38866 T38867 T38868 T38869 T38869 T38870 T38871 TBU K-12RD2 50733201560200 208088 5/17/2024 READ CaliperSurvey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.05.31 13:00:13 -08'00' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS RECEIVED By Anne Prysanka ar 2.0 pm, Nov 30, 2022 1. Operations Susp Well Ins{❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing ❑ Operations shutdown ❑ Performed: Install Whipstocl❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Mod Artificial Lit] Perforate New Pool ❑ Repair Well ❑ Coiled Tubing Ops ❑ Other: No -Flow Test ❑� 2. Operator Name 4. Well Class Before Work: 5. Permit to Drill Number: Hilcorp Alaska, LLC Development ❑� Exploratory ❑ Stratigraphic ❑ Service ❑ 208-088 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20156-02-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADLoo18777 Trading Bay Unit K-12RD2 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): N/A McArthur River Field / Hemlock Oil & Middle Kenai G Oil Pools 11. Present Well Condition Summary: Total Depth measured 11,515 feet Plugs measured N/A feet true vertical 9,641 feet Junk measured N/A feet Effective Depth measured 11,465 feet Packer measured See Schematic feet true vertical 9,598 feet true vertical See Schematic feet Casing Length Size MD ND Burst Collapse Conductor 394' 24" 394' 394' Surface 2,510' 13-3/8" 2,510' 2,437' 3,090psi 1,540psi Production 10,747' 9-5/8'. 10,747' 8,982' 6,870psi 4,760psi Liner 386' 7" 10,873' 9,088' 11,640psi 15,1oopsi Liner 408' 7" 10,434' 8,718' 8,160psi 7,020psi Liner 1,031' 4" 11,465' 9,598, Perforation depth Measured depth See schematic feet True Vertical depth See schematic feet Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6#/ L-80 1,264 (MD) 1,261 (TVD) Packers and SSSV (type, measured and true vertical depth) See Schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13a. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf I Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 10 10 10 0 Subsequent to operation: 0 10 10 10 10 13b. Pools active after work: Hemlock Oil & Middle Kenai G Oil Pools 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations ❑� Exploratory ❑ Development Q Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas WDSPL LJ Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: DI9ltally v8netl by Dan MaM1 321-602 Dan Marlowe (ON 67)-Dan Authorized Name and Marlowe (1287). Digital Signature with Date: 267) Dare zozzr,.301052auoem• Contact Name: Ryan Rupert Contact Email: rvan.ruoertCrRhilcoro.com Authorized Title: Operations Manager Contact Phone: 907 777-8503 Sr Pet Eng: ISr Pet Geo: I I Sr Res Eng: Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov Hilcorp Alaska, LLC RKB to MSL = 100' RKB to TBG Head = 33 24" @ 394' B 13 318' @ 2,510' TOc @ Damaged ceg 9,986' 11/19/21 Top of 7" Liner @ 10,026' Bad call 10,328' lu 2 Bottom of 7" / �� Top of 4" Slot Liner@ 10,434' .' I I Top of 7" Liner lof @ 10,48TPG 59 6/8" @ 10,747" G-5ToI I Window in T' Liner I 1 @ 10,873' I I I I I I I 1 I 1 I I 1 3 4" Slotted Liner @ 11,465' I 1 TD = 11,515' MAX HOLE ANGLE = 42' @ 5800' SCHEMATIC McArthur River Field, TBU Well: K-12RD2 PTD: 208-088 API: 50-733-20156-02 Last Completed: 11/22/21 CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24" Conductor Surface 394' 13-3/8" 61 J-55 BTC 12.515" Surface 2,510' 9-5/8" 47 N-80 & S95 BTC/LTC 8.681" Surface 10,747' 7" 38 P-110 LTC 5.920" 10,487' 10,873'(TOW) 7" Liner 29 L-80 HydriI 563 6.184" 10,026' 10,434' 4" Slotted Liner 10.9 L-80 HydriI 521 3.476" 10,434' 11,465' TUBING DETAIL 4-1/2" 12.6 L-80 Supermax 1 3.998 Surf 1,264' JEWELRY DETAIL Depth Depth NO. (MD) (TVD) ID OD Item Tubing hanger: CIW-DCB-ESP, 11" X4 1/2" IBT lift & susp, w/ 4" type H BPV profile, 5 1/4 EN, 33.75' 33.75' 2-3/8 cont control line ports. Prepped f/BIW penetrator w/blank plug installed 1 1,264' 1,261' Kill String 2 10,415' 8,702' 1.92" 6.040" 1" Swell Packer 3 11,355' 9,504' 3.476" 3.476" 4" Swell Packer PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Status Open in'95. G-5 10,826' 10,910' 9,048' 9,119, 84' Reperf'd 1/02 G-5 10,830' 10,860' 9,052' 9,077' 30' Open 08/12/14 Coen Hole Interval G-5 thru HB-7 10,873' 11,515' 9,088, 9,641' 642' Open Open HK-1 11,049' 11,066' 9,239' 9,254' 17' 08/12/14 Open HK-2 11,078' 11,160' 9,264' 9,336' 82' 08/12/14 Open HK-3 11,173' 11,198, 9,347' 9,368' 25' 08/12/14 Updated by: JLL 12/20/21 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MRF K-12RD2 N/A 50-733-20156-02-00 208-088 11/24/22 11/24/22 Daily Operations: 11/24/22 -Thursday No flow test passed on 11/24/22 (non -witnessed). See file for report and meter data. 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Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Ryan Rupert Cc:Juanita Lovett; Josh Allely - (C); Dan Marlowe Subject:RE: K-12RD2(PTD#208-088) Date:Monday, November 28, 2022 2:29:00 PM Ryan, Please submit the NFT activity report and data in a 10-404 referenced to the sundry 321-602. Thank you 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: Ryan Rupert <Ryan.Rupert@hilcorp.com> Sent: Monday, November 28, 2022 9:11 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Josh Allely - (C) <Josh.Allely@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: K-12RD2(PTD#208-088) Bryan- Please see attached for the results of Hilcorp’s in-house no flow test performed on K- 12RD2(PTD#208-088). The test was a pass, and was performed on 11/24/22 in accordance with Sundry #321-602. I believe there is no further actions necessary with regards to this sundry. Please let us know if any further action is required. Thank you, Ryan Rupert CIO Ops Engineer (#13088) 907-301-1736 (Cell) 907-777-8503 (Office) 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. From:McLellan, Bryan J (OGC) To:AOGCC Records (CED sponsored) Subject:TBU K-12RD2 (PTD 208-088) wellfile Date:Monday, November 28, 2022 2:30:18 PM Attachments:RE K-12RD2(PTD#208-088).msg Please add the attached email to the wellfile. 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ůŝŶĞƐͬ͘KŚĂŶĚůŝŶŐĞƋ͘WKK,ůͬĚϮϯͬϴΗǁŬƐƚƌŝŶŐ͕ůͬĚϰΗĐͬŽĂƐƐǇ͕ĐůĞĂƌĨůŽŽƌΘƌͬĚŚĂŶĚůŝŶŐĞƋ͘DͬhƚĞƐƚũŽŝŶƚƐ͕ƉͬƵϯ ϭͬϮΗƚĞƐƚũŽŝŶƚΘŝŶƐƚĂůů͘&ŝůůƐƵƌĨĂĐĞĞƋ͘ƌͬƵƚĞƐƚĞƋ͘dĞƐƚKW͘ůůƚĞƐƚƐϮϱϬůŽǁͬϮ͕ϱϬϬƉƐŝŚŝŐŚ͕ϱŵŝŶ͕ƉĞƌ,<ĂŶĚ K'ƌĞƋƵŝƌĞŵĞŶƚƐ;ǁŝƚŶĞƐƐǁĂŝǀĞĚďǇ:ŝŵZĞŐŐͿ͘dĞƐƚĂŶŶƵůĂƌǁŝƚŚϯϭͬϮΗƚĞƐƚũŽŝŶƚ͕ƚĞƐƚĞĚsZƌĂŵƐŽŶϯϭͬϮΗĂŶĚϰ ϭͬϮΗƚĞƐƚũŽŝŶƚ͘WĞƌĨŽƌŵĐĐƵŵƵůĂƚŽƌĚƌĂǁĚŽǁŶ͕Ϯ͕ϵϱϬƉƐŝďĞŐŝŶŶŝŶŐƉƌĞƐƐƵƌĞϭ͕ϳϱϬƉƐŝĂĨƚĞƌĨƵŶĐƚŝŽŶ͕ϮϬϬƉƐŝŐĂŝŶŝŶ ϮϬƐĞĐŽŶĚƐ͕ƉƵŵƉƐŽĨĨϵϯƐĞĐŽŶĚƐ͕EϮďŽƚƚůĞƐĂǀĞƌĂŐĞϮ͕ϬϬϬƉƐŝ͘EŽĨĂŝůͬƉĂƐƐĚƵƌŝŶŐƚĞƐƚƐ͘dĞƐƚ'ĂƐĂůĂƌŵƐΘWsdŐŽŽĚ͘ ZŝŐĚŽǁŶƚĞƐƚĞƋƵŝƉŵĞŶƚ͕ůĂǇĚŽǁŶƚĞƐƚũŽŝŶƚƐ͕ƉƌĞƉZ/,WhϯϭͬϮΗǁŽƌŬƐƚƌŝŶŐƚŽůĂǇĚŽǁŶ͘tŽƌŬďŽĂƚ͘Z/,ǁŝƚŚϰϯͬϰΗ ƐĂŶĚϯϭͬϮΗǁŽƌŬƐƚƌŝŶŐŽƵƚŽĨĚĞƌƌŝĐŬƚŽϱ͕ϭϱϬΖ͘WK,͕ůĂǇŝŶŐĚŽǁŶϯϭͬϮΗW,ϲǁŽƌŬƐƚƌŝŶŐ͘ƚͬϰ͕ϴϰϬΖ͘ ϭϭͬϮϭͬϮϭͲ^ƵŶĚĂǇ WK,ůĂǇŝŶŐĚŽǁŶϯϭͬϮΗǁŽƌŬƐƚƌŝŶŐĨƌŽŵͬϰ͕ϴϰϬΖƚŽϭϱϱΖ͘ZŝŐƐĞƌǀŝĐĞ͘Z/,ǁŝƚŚϯϭͬϮΗǁŽƌŬƐƚƌŝŶŐĨƌŽŵϭϱϱΖƚŽϲ͕ϭϮϰΖ͘ WK,ůĂǇŝŶŐĚŽǁŶηϯϭͬϮΗǁŽƌŬƐƚƌŝŶŐĨƌŽŵϲ͕ϭϮϰΖƚŽϭϮϬΖ͘>ĂǇĚŽǁŶϰϯͬϰΗƐ͘ŚĂŶŐĞŚĂŶĚůŝŶŐƚŽŽůƐ͕ƉƌĞƉƚŽƉŝĐŬƵƉϰ ϭͬϮΗŬŝůůƐƚƌŝŶŐ͘WŝĐŬƵƉZ/,ǁŝƚŚϰϭͬϮΗ^ƵƉĞƌŵĂǆϭϮ͘ϲη>ϴϬƚƵďŝŶŐƚŽϭ͕ϮϯϬΖ͕ŵĂŬĞƵƉůĂŶĚŝŶŐũŽŝŶƚ͘DĂŬĞƵƉŚĂŶŐĞƌĂŶĚ ůĂŶĚŬŝůůƐƚƌŝŶŐŝŶǁĞůůŚĞĂĚ͘>ĂŶĚĞĚŵƵůĞƐŚŽĞΛϭ͕ϮϲϰΖ;ŽƌŝŐŝŶĂů<ŽĨϯϯ͘ϳϱΖͿZ/>^͕ƐĞƚWs͘>ĂǇĚŽǁŶůĂŶĚŝŶŐũŽŝŶƚ͘ZŝŐ ĚŽǁŶƉƌĞƉƚŽƐĐŽƉĞĚŽǁŶĂŶĚůĂǇŽǀĞƌŵĂƐƚĨŽƌŶŝƉƉůĞĚŽǁŶKW͘ůĞĂƌĨůŽŽƌ͕ƌĞŵŽǀĞǁŝŶĚǁĂůůƐ͘ ϭϭͬϮϮͬϮϭͲDŽŶĚĂǇ >ĂŶĚĞĚŵƵůĞƐŚŽĞΛϭ͕ϮϲϰΖ ƉƌĞƉƚŽƉŝĐŬƵƉϰ ϭͬϮΗŬŝůůƐƚƌŝŶŐ͘WŝĐŬƵƉZ/,ǁŝƚŚϰϭͬϮΗ^ƵƉĞƌŵĂǆϭϮ͘ϲη>ϴϬƚƵďŝŶŐƚŽϭ͕ϮϯϬΖ͕ 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 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): 11,515'N/A Casing Collapse Conductor Surface 1,540psi Production 4,760psi Liner 15,100psi Liner 7,020psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Swell Pkrs (x2) & N/A 10,415 (MD) 8,702 (TVD) / 11,355 (MD) 9,504 (TVD) & N/A 12. Attachments: Proposal Summary Wellbore schematic 13. W ell Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Katherine O'Connor Contact Email:katherine.oconnor@hilcorp.com Contact Phone: (907) 777-8376 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE AOGCC Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 10,826 - 11,515 408' 4" 9,048 - 9,641 In progress 11,465'1,031' N/A 9,598' 386' 10,747' 10,434' Perforation Depth MD (ft): 10,873' 394'24" 13-3/8" 9-5/8" 2,510' 9,088' 2,510' 10,747' 8,718'7" 7" Length Size 394'394' N/A TVD Burst N/A 8,160psi MD 11,640psi 3,090psi 6,870psi 2,437' 8,982' PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018777 208-088 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-733-20156-02-00 Hilcorp Alaska LLC Trading Bay Unit K-12RD2 McArthur River Field / Hemlock Oil & Middle Kenai G Oil Pools N/A Other: Run Kill String Bryan McLellan 11/20/2021 Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Dan Marlowe Operations Manager 9,641' 11,465' 9,598' 2,268 psi N/A ry Statu Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 12:45 pm, Nov 23, 2021 321-602 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.11.23 11:10:09 -09'00' Dan Marlowe (1267) X BJM 11/24/21 DSR-11/23/21 10-404 DLB 11/24/2021 BOP test to 2500 psi, if it becomes due before removing the BOP stack for rig down. Provide 48 hrs notice to AOGCC for witness. X dts 11/30/2021 11/30/21 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.11.30 11:30:07 -09'00' RBDMS HEW 12/1/2021 Well Work Prognosis Well: K-12RD2 VER2 Well Name:King Salmon K-12RD2 API Number:50-733-20156-02-00 Current Status:ESP Producer Leg:Leg #4 NW Corner Estimated Start Date:Nov 22, 2021 Rig:404 Reg. Approval Req’d?10-403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett 777-8332 Permit to Drill Number:208-088 First Call Engineer:Karson Kozub (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8376 (O) (907) 214-7400 (M) Current Bottom Hole Pressure:3,078 psi @ 8,128’ TVD 0.379 psi/ft (7.3 ppg) ESP Gauge (10/13/2020) Maximum Expected BHP:3,078 psi @ 8,128’ TVD 0.379 psi/ft (7.3 ppg) ESP Gauge (10/13/2020) Maximum Potential Surface Pressure:**2,268 psi Using 0.1 psi/ft gradient per 20AAC 25.280(b)(4) **This is a no flow well 08/29/2014 Brief Well Summary: K-12rd2 is an ESP completion that has drastically declined in production over the last couple years due to increased drawdown and believed scaling. The objective of this program is to run a new, smaller ESP and cleanout the liner to increase production. The ESP was pulled and during the cleanout on K-12RD2, the rig found a bad spot in the casing @ ±9800’ MD and was unable to pass by with 9-5/8” tools. The rig was also unable to get by with tools for cleaning out the 7” casing. The rig picked up a cleanout assembly for the 4.5” and made it into the 4.5” slotted liner, they saw some drag when running past the bad spot in the casing. During the cleanout, the work string hit a tight spot at 10349' MD. The work string was unable to move down and when they dropped the ball to close the bypass sub, it would not shift. Eventually we worked free, and the decision has been made to pull the plug on this RWO. The risk in continuing is high, with the damaged casing and being unsure of what hung up the work string. The objective is to run a kill string and leave the well full of KWF. The future utility of this well has not yet been determined. Last Casing Test: 08/05/2014 9,836’ 1,500 psi for 30 minutes on chart Procedure: 1. MIRU HAK 404 2. Circulate well to production x Work over fluid will be FIW 3. Set BPV, ND tree NU BOP and test to 250psi Low/2,500psi High/2,500 psi Annular x Note: Notify AOGCC 24 hours in advance of test to allow them to witness test 4. Monitor well to ensure it is static 5. Unseat hanger and POOH with ESP completion 6. RIH to with cleanout assembly, cleanout to ±11200’ MD, circ bottoms up, POOH 7. PU and RIH with ±1500’ 4.5” kill string. 8. PU and RIH with new ESP assembly. See proposed schematic 9. Set BPV, ND BOP, NU tree and test 10. Turn well over to production 11. Conduct SVS tests per AOGCC regulations Well Work Prognosis Well: K-12RD2 VER2 12. Set BPV, NU tree, test same. 13. RD 404. 14. Leave well shut in. 15. Within 1 year, repair well or place downhole plug above perforations & damaged zone or prove the well is incapable of flowing on its own & has shown no signs of repressurization over the year. Attachments: 1. Well Schematic Proposed 2. Wellhead Diagram Proposed 3. BOP Drawing 4. Fluid Flow Diagrams 5. RWO Sundry Revision Change Form Updated by: JLL 11/20/21 McArthur River Field, TBU Well: K-12RD2 PTD: 208-088 API: 50-733-20156-02 Last Completed: FUTURE PROPOSED TD = 11,515’ MAX HOLE ANGLE = 42q @ 5800’ RKB to MSL = 100’ RKB to TBG Head = 33.80’ 1 Bottom of 7” / Top of 4” Slot Liner@ 10,434’ 9 5/8” @ 10,747’ 13 3/8” @ 2,510’ G-5 24” @ 394’ Bad csg 10,328’ TOC @ 9,300’ 4” Slotted Liner @ 11,465’ Top of Window in 7” Liner @ 10,873’ Top of 7” Liner @ 10,026’ 2 3 Top of 7” Liner @ 10,487’ Damaged csg ± 9,800’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Status G-5 10,826' 10,910' 9,048' 9,119' 84' Open in '95. Reperf'd 1/02 G-5 10,830’ 10,860’ 9,052’ 9,077’ 30’ Open 08/12/14 Open Hole Interval G-5 thru HB-7 10,873' 11,515' 9,088' 9,641' 642' Open HK-1 11,049’ 11,066’ 9,239’ 9,254’ 17’ Open 08/12/14 HK-2 11,078’ 11,160’ 9,264’ 9,336’ 82’ Open 08/12/14 HK-3 11,173’ 11,198’ 9,347’ 9,368’ 25’ Open 08/12/14 JEWELRY DETAIL NO.Depth (MD) Depth (TVD)ID OD Item 1 ±1,200’ ±1,198’ Kill String 2 10,415’ 8,702’ 5.92” 6.040” 7” Swell Packer 3 11,355’ 9,504’ 3.476” 3.476” 4” Swell Packer CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” Conductor Surface 394’ 13-3/8” 61 J-55 BTC 12.515” Surface 2,510’ 9-5/8” 47 N-80 & S95 BTC/LTC 8.681” Surface 10,747’ 7” 38 P-110 LTC 5.920” 10,487’ 10,873’ (TOW) 7” Liner 29 L-80 Hydril 563 6.184” 10,026’ 10,434’ 4” Slotted Liner 10.9 L-80 Hydril 521 3.476” 10,434’ 11,465’ TUBING DETAIL 4-1/2” Surf ±1,200’ King Salmon Platform K-12RD2 Current 07/23/2018 BHTA, B-11-A0, 4 1/16 5M FE Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Master, WKM-M, 4 1/16 5M FE, HWO, EE trim All unihead annular valves, 2 1/16 5M FE OCT-20, HWO Valve, OCT-20, 3 1/8 2M FE, HWOStarting head, OCT, 21 ¼ 2M FE X 24'’ SOW, w/ 1- 3 1/8 2M EFO, full set of lockpins Unihead, OCT type 3, 13 5/8 5M API hub top X 13 3/8 BTC casing bottom, w/ 1- 2 1/16 5M SSO on lower section, 1- 2 1/16 5M SSO on middle section, 3- 2 1/16 5M SSO on upper section , IP internal lockpin assy King Salmon K-12RD2 24 X 13 3/8 X 9 5/8 X 4 ½ 24'’ 13 3/8'’ 9 5/8'’ 4 ½’’ Valve, Wing, AOP, 2 1/16 5M FE, HWO, AA trim Valve, Wing, WKM-M, 4 1/16 5M FE, w/ Safeco oper, EE trim Tubing head, CIW-DCB, 13 5/8 3M X 11 5M, w/ 2- 2 1/16 5M SSO, X- bottom prep, 1 ½ VR profile Adapter, CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE, prepped for 5 ¼ ESP neck, 2- ½ npt continuous control line ports Spool, 13 5/8 5M API hub X 13 5/8 5M FE DSA 13 5/8 5M x 13 5/8 3M Tubing hanger, CIW-DCB- ESP, 11 X 4 ½ IBT lift and susp, w/4'’ type H BPV profile, 5 ¼ EN, 2-3/8 continuous control line ports, prepped for BIW penetrator Void test good 250/3000psi Packed off in 2010 Re-checked 7/16/2018 Void test good 250/5000 7/16/2018 King Salmon Platform Rig 404 BOP K-12 10/15/2021 Shaffer SL 13 5/8 5M 2 7/8-5.5 variables Blinds 2.00' 14.20' Riser 13 5/8 5M FE X 13 5/8 5M FE 4.54' 2.83' Choke and Kill valves 2 1/16 5M Mud Cross 3 1/8 5M EFO 4.30'Hydril GK 13 5/8-5000 DSA 3 X 2DSA 3 X 2CIW-U 2 3/8 rams 2.23' HILCORP ALASKA, LLC SwacoSuperchokeBlooey LineTo Gas BusterInlet Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well K-12RD2 (PTD 208-088)Sundry #: xxx-xxxAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC 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 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date 1 Carlisle, Samantha J (CED) From:McLellan, Bryan J (OGC) Sent:Saturday, November 20, 2021 10:16 PM To:Katherine O'connor Cc:Juanita Lovett Subject:RE: [EXTERNAL] Re: K-12 ESP Swap (PTD: 208-088) Youhaveverbalapprovaltorunthekillstringasyourequestedinyouremailbelow.PleasefollowupwithaSundry submittalfortheChangetoApprovedpermitwithin3daysper20AAC25.507.Pleaseincludethefollowing: 1. Adescriptionoftheworkyou’vecompletedtodateandthereasonforrunningthekillstring. 2. IncludeawrittencommitmentintheSundrytoeitherrepairthewellorplaceadownholeplugabovethe perfs/damagedzonewithin1yearofcompletionofoperations. 3. Submitasingle10Ͳ404tocoverbothSundrieswithin30daysofmovingtherigoffthewell. Regards BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 From:KatherineO'connor<Katherine.Oconnor@hilcorp.com> Sent:Saturday,November20,20213:39PM To:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Cc:JuanitaLovett<jlovett@hilcorp.com> Subject:Re:[EXTERNAL]Re:KͲ12ESPSwap(PTD:208Ͳ088) Itwillbe~1200’of4.5”tubing.SamedealasKͲ17. Thanks Katherine From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Saturday,November20,20211:59PM To:KatherineO'connor<Katherine.Oconnor@hilcorp.com> Cc:JuanitaLovett<jlovett@hilcorp.com> Subject:[EXTERNAL]Re:KͲ12ESPSwap(PTD:208Ͳ088) Katherine,canyousendtheproposeddiagram?Oratleastsenddetailsofthekillstring. Thanks SentfrommyiPhone 2 OnNov20,2021,at9:45AM,KatherineO'connor<Katherine.Oconnor@hilcorp.com>wrote: HelloBryan DuringthecleanoutonKͲ12whilecleaningoutthe9Ͳ5/8"casingweencounteredwhatlooked tobedamagedcasingat~9800'MD.Wewereabletomovepastitwitha4Ͳ1/2"cleanout assembly.Lastnightwhilecleaningoutthe4.5"wehitatightspotat10349'MD.Thework stringwasunabletomovedownandwhentheydroppedtheballtoclosethebypasssub,it wouldnotshift.Eventuallyweworkedfree,andthedecisionhasbeenmadetopulltheplugon thisRWO.Theriskincontinuingishigh,withthedamagedcasingandbeingunsureofwhat hungusupagainlastnight. Wewouldliketoruna4.5"killstring.TheywillbeBOPtestingtoday.Wewillsubmitasundry earlynextweek. Thankyou, Katherine 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. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Reviewed By: P.I. Supry ► 17 ZL�,� BOPE Test Report for: TRADING BAY UNIT K-12RD2 Comm Contractor/Rig No.: Hilcorp 404 - PTD#: 2080880 DATE: 11/13/2021 Inspector Adam Earl - Insp Source Operator: Hilcorp Alaska, LLC Operator Rep: Soule/ Smith Rig Rep: Johnson/ Castagine Inspector Type Operation: WRKOV Sundry No: Test Pressures: Inspection No: bopAGE211117125329 i Rams: Annular. Valves: MASP: - --- - - - Type Test: [NIT 1T 250/2500 - 250/2500- 250/2500. 2268 - Related Insp No: TEST DATA MISC. INSPECTIONS: MUD SYSTEM: P/F ACCUMULATOR SYSTEM: ---_ 1. -- _- P_ P/F 0 - Visual Alarm Ball Type Time/Pressure P/F Location Gen.: P-. Trip Tank NA NA - System Pressure 2975 P Housekeeping: P- Pit Level Indicators _ P P_- Pressure After Closure 1650 - P PTD On Location P_ Flow Indicator NA NA 200 PSI Attained 24 - P _ Standing Order Posted P Meth Gas Detector P P Full Pressure Attained 106 . P Well Sign P H2S Gas Detector -P P Blind Switch Covers: All Stations - P Drl. Rig P MS Misc 0 NA Nitgn. Bottles (avg): -6 (&, 2000 -_ P ` Hazard Sec. P' Choke Ln. Valves 1 ACC Misc 0 NA_ Misc NA HCR Valves 2 21/16 P Inside Reel Valves - 0 FLOOR SAFTY VALVES: BOP STACK: Quantity P/F Upper Kelly ---_ 1. -- _- P_ Lower Kelly 0 - NA Ball Type _ _I P Inside BOP I P FSV Misc 0 NA BOP STACK: CHOKE MANIFOLD: Quantity Size P/F Quantity P/F Stripper 0 NA- No. Valves 11 , P Annular Preventer 1 135/8 P Manual Chokes 1 , P -_ #1 Rams -1 23/8 NT_'/ Hydraulic Chokes 1 P #2 Rams 1 2 7/8 X 5 I/2 P CH Misc 0 NA #3 Rams I -0 Blinds P - #4 Rams P #5 Rams 0 p INSIDE REEL VALVES: #6 Rams 0 P (Valid for Coil Rigs Only) Choke Ln. Valves 1 21/16 FP Quantity P/F HCR Valves 2 21/16 P Inside Reel Valves - 0 NA Kill Line Valves 2 2 1/16 P Check Valve 0 NA BOP Misc 0 NA Number of Failures: I Test Results Test Time 5 Remarks: Inside choke on mud cross had to be cycled and passed retest. Top rams have 2 3/8" hard bodies installed but didn't test. Not to be used until after next BOPE test, these rams will be tested then. Closing times: Annular -25 secs. Rams -7.5 secs and 8 secs. HCRS-1.5 secs 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 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): 11,515'N/A Casing Collapse Conductor Surface 1,540psi Production 4,760psi Liner 15,100psi Liner 7,020psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Swell Pkrs (x2) & N/A 10,415 (MD) 8,702 (TVD) / 11,355 (MD) 9,504 (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: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Karson Kozub Contact Email:kkozub@hilcorp.com Contact Phone: (907) 570-1801 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE AOGCC Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 9,641'11,465'9,598'2,268 psi N/A 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Dan Marlowe Operations Manager Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018777 208-088 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-733-20156-02-00 Hilcorp Alaska LLC Trading Bay Unit K-12RD2 McArthur River Field / Hemlock Oil & Middle Kenai G Oil Pools N/A Other: Replace ESP Length Size 394'394' 12.6# / L-80 TVD Burst 9,595' 8,160psi MD 11,640psi 3,090psi 6,870psi 2,437' 8,982' 9,088' 2,510' 10,747' 8,718'7" 7" 394'24" 13-3/8" 9-5/8" 2,510' 386' 10,747' 10,434' Perforation Depth MD (ft): 10,873' 10,826 - 11,515 408' 4" 9,048 - 9,641 10/25/2021 11,465'1,031' 4-1/2" 9,598' ry Statu Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:06 am, Oct 14, 2021 321-542 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.10.13 09:27:46 -08'00' Dan Marlowe (1267) DSR-10/15/21 BOP test to 2500 psi. X SFD 10/14/2021BJM 10/19/21 See conditions & comments on attached BOP test procedure. dts 10/20/2021 JLC 10/20/2021 10-404 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.20 11:10:18 -08'00' RBDMS HEW 10/22/2021 Well Work Prognosis Well: K-12RD2 Well Name:King Salmon K-12RD2 API Number:50-733-20156-02-00 Current Status:ESP Producer Leg:Leg #4 NW Corner Estimated Start Date:Oct 25, 2021 Rig:404 Reg. Approval Req’d?10-403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett 777-8332 Permit to Drill Number:208-088 First Call Engineer:Karson Kozub (907) 570-1801 (M) Second Call Engineer:Katherine O’Connor (907) 777-8376 (O) (907) 214-7400 (M) Current Bottom Hole Pressure:3,078 psi @ 8,128’ TVD 0.379 psi/ft (7.3 ppg) ESP Gauge (10/13/2020) Maximum Expected BHP:3,078 psi @ 8,128’ TVD 0.379 psi/ft (7.3 ppg) ESP Gauge (10/13/2020) Maximum Potential Surface Pressure:**2,268 psi Using 0.1 psi/ft gradient per 20AAC 25.280(b)(4) **This is a no flow well 08/29/2014 Brief Well Summary: K-12rd2 is an ESP completion that has drastically declined in production over the last couple years due to increased drawdown and believed scaling. The objective of this program is to run a new, smaller ESP and cleanout the liner to increase production. Last Casing Test: 08/05/2014 9,836’ 1,500 psi for 30 minutes on chart Procedure: 1. MIRU HAK 404 2. Circulate well to production x Work over fluid will be FIW 3. Set BPV, ND tree NU BOP and test to 250psi Low/2,500psi High/2,500 psi Annular x Note: Notify AOGCC 24 hours in advance of test to allow them to witness test 4. Monitor well to ensure it is static 5. Unseat hanger and POOH with ESP completion 6. RIH to with cleanout assembly, cleanout to ±11200’ MD, circ bottoms up, POOH 7. PU and RIH with new ESP assembly. See proposed schematic 8. Set BPV, ND BOP, NU tree and test 9. Turn well over to production 10. Conduct SVS tests per AOGCC regulations 11. Conduct a no-flow per AOGCC regulations Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current/Proposed (Same) 4. BOP Drawing 5. Fluid Flow Diagrams 6. Rolling BOP Test Procedures 7. RWO Sundry Revision Change Form 4-1/2" tubing. 2-3/8" workstring used for cleanout. bjm Updated by: JLL 08/21/17 McArthur River Field, TBU Well: K-12RD2 PTD: 208-088 API: 50-733-20156-02 Last Completed: 07/30/17 SCHEMATIC TD = 11,515’ MAX HOLE ANGLE = 42q @ 5800’ RKB to MSL = 100’ RKB to TBG Head = 33.80’ 1 Bottom of 7” / Top of 4” Slot Liner@ 10,434’ 9 5/8” @ 10,747’ 13 3/8” @ 2,510’ G-5 24” @ 394’ Bad csg 10,328’ TOC @ 9,300’ 4” Slotted Liner @ 11,465’ Top of Window in 7” Liner @ 10,873’ Top of 7” Liner @ 10,026’ 2 3 Top of 7” Liner @ 10,487’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Status G-5 10,826' 10,910' 9,048' 9,119' 84' Open in '95. Reperf'd 1/02 G-5 10,830’ 10,860’ 9,052’ 9,077’ 30’ Open 08/12/14 Open Hole Interval G-5 thru HB-7 10,873' 11,515' 9,088' 9,641' 642' Open HK-1 11,049’ 11,066’ 9,239’ 9,254’ 17’ Open 08/12/14 HK-2 11,078’ 11,160’ 9,264’ 9,336’ 82’ Open 08/12/14 HK-3 11,173’ 11,198’ 9,347’ 9,368’ 25’ Open 08/12/14 JEWELRY DETAIL NO.Depth (MD) Depth (TVD)ID OD Item 33.80’ 11” Hanger 1 9,595’ 8,028’ N/A 6.750” Discharge B/O 9,595’ 8,028’ N/A 6.750” Pump (x2) 45 Stg SH16000 9,634’ 8,060’ N/A 6.750” Intake 9,635’ 8,060’ N/A 5.130” Tandem Seals - 513 Series, BPBSL 9,653’ 8,075’ N/A 5.620” Motors (x2) 562, KMSUT & KMSLT 500 HP 9,719’ 8,128’ N/A 5.620” Centralizer Anode 2 10,415’ 8,702’ 5.92” 6.040” 7” Swell Packer 3 11,355’ 9,504’ 3.476” 3.476” 4” Swell Packer CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” Conductor Surface 394’ 13-3/8” 61 J-55 BTC 12.515” Surface 2,510’ 9-5/8” 47 N-80 & S95 BTC/LTC 8.681” Surface 10,747’ 7” 38 P-110 LTC 5.920” 10,487’ 10,873’ (TOW) 7” Liner 29 L-80 Hydril 563 6.184” 10,026’ 10,434’ 4” Slotted Liner 10.9 L-80 Hydril 521 3.476” 10,434’ 11,465’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.998 Surface 9,595’ Updated by: JLL 09/29/20 McArthur River Field, TBU Well: K-12RD2 PTD: 208-088 API: 50-733-20156-02 Last Completed: FUTURE PROPOSED TD = 11,515’ MAX HOLE ANGLE = 42q @ 5800’ RKB to MSL = 100’ RKB to TBG Head = 33.80’ 1 Bottom of 7” / Top of 4” Slot Liner@ 10,434’ 9 5/8” @ 10,747’ 13 3/8” @ 2,510’ G-5 24” @ 394’ Bad csg 10,328’ TOC @ 9,300’ 4” Slotted Liner @ 11,465’ Top of Window in 7” Liner @ 10,873’ Top of 7” Liner @ 10,026’ 2 3 Top of 7” Liner @ 10,487’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Status G-5 10,826' 10,910' 9,048' 9,119' 84' Open in '95. Reperf'd 1/02 G-5 10,830’ 10,860’ 9,052’ 9,077’ 30’ Open 08/12/14 Open Hole Interval G-5 thru HB-7 10,873' 11,515' 9,088' 9,641' 642' Open HK-1 11,049’ 11,066’ 9,239’ 9,254’ 17’ Open 08/12/14 HK-2 11,078’ 11,160’ 9,264’ 9,336’ 82’ Open 08/12/14 HK-3 11,173’ 11,198’ 9,347’ 9,368’ 25’ Open 08/12/14 JEWELRY DETAIL NO.Depth (MD) Depth (TVD)ID OD Item 33.80’ 11” Hanger 1 ±9,595’ ±8,028’ N/A Discharge B/O N/A Pump N/A Intake N/A Seals N/A Motor ±9,720’ ±8,128’ N/A Centralizer Anode 2 10,415’ 8,702’ 5.92” 6.040” 7” Swell Packer 3 11,355’ 9,504’ 3.476” 3.476” 4” Swell Packer CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” Conductor Surface 394’ 13-3/8” 61 J-55 BTC 12.515” Surface 2,510’ 9-5/8” 47 N-80 & S95 BTC/LTC 8.681” Surface 10,747’ 7” 38 P-110 LTC 5.920” 10,487’ 10,873’ (TOW) 7” Liner 29 L-80 Hydril 563 6.184” 10,026’ 10,434’ 4” Slotted Liner 10.9 L-80 Hydril 521 3.476” 10,434’ 11,465’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.998 Surface ±9,595’ King Salmon Platform K-12RD2 Current 07/23/2018 BHTA, B-11-A0, 4 1/16 5M FE Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Master, WKM-M, 4 1/16 5M FE, HWO, EE trim All unihead annular valves, 2 1/16 5M FE OCT-20, HWO Valve, OCT-20, 3 1/8 2M FE, HWOStarting head, OCT, 21 ¼ 2M FE X 24'’ SOW, w/1-3 1/8 2M EFO, full set of lockpins Unihead, OCT type 3, 13 5/8 5M API hub top X 13 3/8 BTC casing bottom, w/ 1- 2 1/16 5M SSO on lower section, 1- 2 1/16 5M SSO on middle section, 3- 2 1/16 5M SSO on upper section , IP internal lockpin assy King Salmon K-12RD2 24 X 13 3/8 X 9 5/8 X 4 ½ 24'’ 13 3/8'’ 9 5/8'’ 4 ½’’ Valve, Wing, AOP, 2 1/16 5M FE, HWO, AA trim Valve, Wing, WKM-M, 4 1/16 5M FE, w/ Safeco oper, EE trim Tubing head, CIW-DCB, 13 5/8 3M X 11 5M, w/ 2- 2 1/16 5M SSO, X- bottom prep, 1 ½ VR profile Adapter, CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE, prepped for 5 ¼ ESP neck, 2- ½ npt continuous control line ports Spool, 13 5/8 5M API hub X 13 5/8 5M FE DSA 13 5/8 5M x 13 5/8 3M Tubing hanger, CIW-DCB- ESP, 11 X 4 ½ IBT lift and susp, w/ 4'’ type H BPV profile, 5 ¼ EN, 2-3/8 continuous control line ports, prepped for BIW penetrator Void test good 250/3000psi Packed off in 2010 Re-checked 7/16/2018 Void test good 250/5000 7/16/2018 King Salmon Platform BOP StackSuperseded HILCORP ALASKA, LLC SwacoSuperchokeBlooey LineTo Gas BusterInlet Rig 404 BOP Test Procedure Attachment #1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Rig 404, WO Program – Oil Producers, Gas Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with kill weight fluid. x Note: Fluid level will fall to a depth that balances with reservoir pressure. x Shoot fluid levels as needed. 3) Confirm that well is static. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV. As approved in the sundry, proceed as follows: a) Fill well with KWF if the fluid is not to surface b) ND tree with no BPV Inspect and prepare BPV profile to accept a 2-way valve, or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand, or MU landing (test) joint to lift-threads d) For ESP wells - Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and / or a penetrator leaks, notify Operations Engineer (Hilcorp), Mr. Bryan McLellan (AOGCC – bryan.mclellan@alaska.gov) and Mr. Jim Regg (AOGCC - jim.regg@alaska.gov) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. Rig up Slickline and Set a plug in the tubing and test to 2300 psi before ND tree. bjm Rig 404 BOP Test Procedure Attachment #1 e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing-head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same- RIH with test plug on joint of tubing. Install a pump-in sub w/ test line plus an open TIW or lower Kelly valve in top of test joint w/ open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump- install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder (test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1 st valve on standpipe manifold (PM1), close valves 8,10 &11 on choke manifold and close the annular preventer, open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer, close safety valve and open IBOP on test joint, close outside valve on kill side of mud cross (K2), open PM1, close valves 5,7 & 9 on choke manifold, open valve 10 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close manual and super choke / open valves 7 & 9 on choke manifold. Bleed pressure from step b or c recording change and stabilization. If passes after 5 minutes, bleed off pressure back to tank. e) Close inside valve (K1) / open outside valve on kill side of mud cross (K2), close valves 2,4 & 6 / open valves 5,7 & 9 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. f) Close valves 1 & 3 / open valves 4 & 6 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. Note that the detailed BOP testing procedures will need to be agreed by the AOGCC inspector if he is witnessing the test. The test procedure is at the discretion of the inspectors. bjm Rig 404 BOP Test Procedure Attachment #1 g) Close HCR (CL2) open valves 2,4 & 6 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Close inside valve (CL1) / open outside valve (HCR) on choke side of mud cross. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Ensure all pressure is bled off- open pipe rams and pull test joint leaving test plug / 2-way check in place. Close blind rams and attach test line to valve 11 on choke manifold, close valve 1,2 & 3 / open valve 11 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. j) Test additional floor valves (TIW or Lower Kelly Valve) and IBOPs as necessary. STANDARD TEST PROCEDURE OF CLOSING UNIT (ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record “Accumulator Pressure”. It should be +/- 3,000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2 nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read “10 bottles at 2,150 psi”). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the electric pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/- 3,000 psi). Note: Make sure the electric pump is turned to “Auto”, not “Manual” so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format. Document both the rolling test and the follow up tests. Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well K-12RD2 (PTD 208-088)Sundry #: xxx-xxxAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC 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 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date .LQJ6DOPRQ3ODWIRUP 5LJ%23. ^ŚĂĨĨĞƌ^> ϭϯϱͬϴϱD ϮϳͬϴͲϱ͘ϱ ǀĂƌŝĂďůĞƐ ůŝŶĚƐ Ϯ͘ϬϬΖ ϭϰ͘ϮϬΖ ZŝƐĞƌ ϭϯϱͬϴϱD&yϭϯϱͬϴϱD& ϰ͘ϱϰΖ Ϯ͘ϴϯΖ ŚŽŬĞĂŶĚ<ŝůůǀĂůǀĞƐ ϮϭͬϭϲϱD 0XG&URVV 0()2 ϰ͘ϯϬΖ,ǇĚƌŝů '<ϭϯϱͬϴͲϱϬϬϬ ^ϯyϮ^ϯyϮ/tͲh Ϯϯͬϴ ƌĂŵƐ Ϯ͘ϮϯΖ 1 Winston, Hugh E (CED) From:Carlisle, Samantha J (CED) Sent:Wednesday, September 8, 2021 4:46 PM To:Winston, Hugh E (CED) Subject:FW: Withdraw Sundry #320-421 - Trading Bay Unit K-12RD2 PTD: 208-088 From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Wednesday, September 8, 2021 4:44 PM To: Carlisle, Samantha J (CED) <samantha.carlisle@alaska.gov> Subject: FW: Withdraw Sundry #320‐421 ‐ Trading Bay Unit K‐12RD2 PTD: 208‐088 Sam, See below. Please withdraw 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: Juanita Lovett <jlovett@hilcorp.com> Sent: Wednesday, September 8, 2021 3:43 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov>; Karson Kozub ‐ (C) <kkozub@hilcorp.com> Subject: Withdraw Sundry #320‐421 ‐ Trading Bay Unit K‐12RD2 PTD: 208‐088 Bryan, Please withdraw the above mentioned sundry. The project will not be completed at this time. Scope of work was to run a new, smaller ESP and cleanout the liner to increase production. Regards, Juanita L Lovett Sr. Operations/Regulatory Tech Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 | Anchorage | AK | 99503 (907) 777-8332 | jlovett@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. 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 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address: 3800 Centerpoint Drive, Suite 1400 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): McArthur River Field / Hemlock Oil & Middle Kenai G Oil Pools 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 11,515'N/A Casing Collapse Conductor Surface 1,540 psi Production 4,760 psi Liner 15,100 psi Liner 7,020 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:Katherine.oconnor@hilcorp.com Contact Phone: (907) 777-8376 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 Other: Replace ESP N/A 9,641' 11,465' 9,598' 2,712 psi 1,031' 4" 8,718'7" 11,465' 9,598' 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. 10/25/2020 4-1/2" Daniel E. Marlowe Swell Pkrs (x2) & N/A 10,434' Perforation Depth MD (ft): 10,837' 10,826 - 11,515 408' 10,415 (MD) 8,702 (TVD) 11,355 (MD) 9,504 (TVD) & N/A Tubing Grade:Tubing MD (ft): 9,048 - 9,641 Perforation Depth TVD (ft): 394' 24" 13-3/8" 9-5/8" 2,510' 7"386' 10,747' 2,437' 8,982' 9,088' 2,510' 10,747' 394' 12.6# / L-80 TVD Burst 9,595' 8,160 psi Tubing Size: MD 3,090 psi 6,870 psi 208-088 50-733-20156-02-00Anchorage, AK 99503 Hilcorp Alaska, LLC Trading Bay Unit K-12RD2 COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018777 Authorized Signature: Operations Manager Katherine O'Connor PRESENT WELL CONDITION SUMMARY Length Size 11,640 psi N/A 394' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:45 am, Oct 06, 2020 320-421 Daniel Marlowe I am approving this document 2020.10.05 16:26:59 -08'00' Daniel Marlowe Replace ESP DSR-10/12/2020 OIL gls 10/13/20 * 3000 psi BOPE test (2500 psi annular ) X X 404 Pull Tubingll Tubing 10-404 * No-flow test required within 30 days of POP. DLB 10/6/2020 Comm. q 10/14/2020 dts 10/14/2020 JLC 10/14/2020 RBDMS HEW 11/3/2020 Well Work Prognosis Well: K-12rd2 Date: 9/25/2020 Well Name:King Salmon K-12rd2 API Number:50-733-20156-02 Current Status:Oil Producer Leg:Leg #4 NW Corner Estimated Start Date:Oct 25, 2020 Rig:404 Reg. Approval Req’d?10-403 Date Reg. Approval Rec’vd:HAK 404 Regulatory Contact:Juanita Lovett 777-8332 Permit to Drill Number:208-088 First Call Engineer:Katherine O’Connor (907) 777-8376 (O) (907) 214-7400 (M) Second Call Engineer:Karson Kozub (907) 777-8434 (O) (907) 570-1801 (M) Current Bottom Hole Pressure:3657 psi @ 9,450’ TVD 0.387 psi/ft (8.61 ppg) ESP Gauge Maximum Expected BHP:3657 psi @ 9,450’ TVD 0.387 psi/ft (8.61 ppg) ESP Gauge Maximum Potential Surface Pressure:**2712 psi Using 0.1 psi/ft gradient per 20AAC 25.280(b)(4) **This is a no flow well 08/29/2014 Brief Well Summary: The K-12rd2 is an ESP completion that has drastically declined production over the last couple years due to increased drawdown and scaling. The objective of this program is to run a new, smaller ESP and cleanout the liner to increase production. Last Casing Test: 08/05/2014 9,836’ 1,500 psi for 30 minutes on chart Procedure: 1. MIRU 404 rig 2. Circulate hydrocarbons off of well. x Work over fluid will be FIW. BOP’s will be closed as needed to circulate the well. 3. Set BPV, ND tree NU BOP 4. BOP and test to 250psi low/3,000psi high. x Note: Notify AOGCC 24 hours in advance of test to allow them to witness test. 5. Monitor well to ensure it is static. 6. Unseat hanger and POOH w/ tubing string and ESP assembly. 7. RIH to with cleanout assembly, cleanout to ±11200’ MD, circ bottoms up, POOH 8. PU and RIH with new ESP assembly. See proposed schematic. 9. ND BOP, NU wellhead and test. 10. Turn well over to production. 11. Conduct SVS tests per AOGCC regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current/Proposed (Same) 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form (KWF is 7.3 ppg) *** NO FLOW test to be performed within 30 days 3000 psi BOPE test gls 10/13/20 See email 10-13-20... BHP 7.3 ppg per ESP gauge Updated by: JLL 08/21/17 McArthur River Field, TBU Well: K-12RD2 PTD: 208-088 API: 50-733-20156-02 Last Completed: 07/30/17 SCHEMATIC TD = 11,515’ MAX HOLE ANGLE = 42q @ 5800’ RKB to MSL = 100’ RKB to TBG Head = 33.80’ 1 Bottom of 7” / Top of 4” Slot Liner@ 10,434’ 9 5/8” @ 10,747’ 13 3/8” @ 2,510’ G-5 24” @ 394’ Bad csg 10,328’ TOC @ 9,300’ 4” Slotted Liner @ 11,465’ Top of Window in 7” Liner @ 10,873’ Top of 7” Liner @ 10,026’ 2 3 Top of 7” Liner @ 10,487’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Status G-5 10,826' 10,910' 9,048' 9,119' 84' Open in '95. Reperf'd 1/02 G-5 10,830’ 10,860’ 9,052’ 9,077’ 30’ Open 08/12/14 Open Hole Interval G-5 thru HB-7 10,873' 11,515' 9,088' 9,641' 642' Open HK-1 11,049’ 11,066’ 9,239’ 9,254’ 17’ Open 08/12/14 HK-2 11,078’ 11,160’ 9,264’ 9,336’ 82’ Open 08/12/14 HK-3 11,173’ 11,198’ 9,347’ 9,368’ 25’ Open 08/12/14 JEWELRY DETAIL NO.Depth (MD) Depth (TVD)ID OD Item 33.80’ 11” Hanger 1 9,595’ 8,028’ N/A 6.750” Discharge B/O 9,595’ 8,028’ N/A 6.750” Pump (x2) 45 Stg SH16000 9,634’ 8,060’ N/A 6.750” Intake 9,635’ 8,060’ N/A 5.130” Tandem Seals - 513 Series, BPBSL 9,653’ 8,075’ N/A 5.620” Motors (x2) 562, KMSUT & KMSLT 500 HP 9,719’ 8,128’ N/A 5.620” Centralizer Anode 2 10,415’ 8,702’ 5.92” 6.040” 7” Swell Packer 3 11,355’ 9,504’ 3.476” 3.476” 4” Swell Packer CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” Conductor Surface 394’ 13-3/8” 61 J-55 BTC 12.515” Surface 2,510’ 9-5/8” 47 N-80 & S95 BTC/LTC 8.681” Surface 10,747’ 7” 38 P-110 LTC 5.920” 10,487’ 10,873’ (TOW) 7” Liner 29 L-80 Hydril 563 6.184” 10,026’ 10,434’ 4” Slotted Liner 10.9 L-80 Hydril 521 3.476” 10,434’ 11,465’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.998 Surface 9,595’ Updated by: JLL 09/29/20 McArthur River Field, TBU Well: K-12RD2 PTD: 208-088 API: 50-733-20156-02 Last Completed: FUTURE PROPOSED TD = 11,515’ MAX HOLE ANGLE = 42q @ 5800’ RKB to MSL = 100’ RKB to TBG Head = 33.80’ 1 Bottom of 7” / Top of 4” Slot Liner@ 10,434’ 9 5/8” @ 10,747’ 13 3/8” @ 2,510’ G-5 24” @ 394’ Bad csg 10,328’ TOC @ 9,300’ 4” Slotted Liner @ 11,465’ Top of Window in 7” Liner @ 10,873’ Top of 7” Liner @ 10,026’ 2 3 Top of 7” Liner @ 10,487’ PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) Ft Status G-5 10,826' 10,910' 9,048' 9,119' 84' Open in '95. Reperf'd 1/02 G-5 10,830’ 10,860’ 9,052’ 9,077’ 30’ Open 08/12/14 Open Hole Interval G-5 thru HB-7 10,873' 11,515' 9,088' 9,641' 642' Open HK-1 11,049’ 11,066’ 9,239’ 9,254’ 17’ Open 08/12/14 HK-2 11,078’ 11,160’ 9,264’ 9,336’ 82’ Open 08/12/14 HK-3 11,173’ 11,198’ 9,347’ 9,368’ 25’ Open 08/12/14 JEWELRY DETAIL NO.Depth (MD) Depth (TVD)ID OD Item 33.80’ 11” Hanger 1 ±9,595’ ±8,028’ N/A Discharge B/O N/A Pump N/A Intake N/A Seals N/A Motor ±9,720’ ±8,128’ N/A Centralizer Anode 2 10,415’ 8,702’ 5.92” 6.040” 7” Swell Packer 3 11,355’ 9,504’ 3.476” 3.476” 4” Swell Packer CASING DETAIL SIZE WT GRADE CONN ID TOP BTM. 24” Conductor Surface 394’ 13-3/8” 61 J-55 BTC 12.515” Surface 2,510’ 9-5/8” 47 N-80 & S95 BTC/LTC 8.681” Surface 10,747’ 7” 38 P-110 LTC 5.920” 10,487’ 10,873’ (TOW) 7” Liner 29 L-80 Hydril 563 6.184” 10,026’ 10,434’ 4” Slotted Liner 10.9 L-80 Hydril 521 3.476” 10,434’ 11,465’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.998 Surface ±9,595’ King Salmon Platform K-12RD2 Current 07/23/2018 BHTA, B-11-A0, 4 1/16 5M FE Valve, Swab, WKM-M, 4 1/16 5M FE, HWO, EE trim Valve, Master, WKM-M, 4 1/16 5M FE, HWO, EE trim All unihead annular valves, 2 1/16 5M FE OCT-20, HWO Valve, OCT-20, 3 1/8 2M FE, HWOStarting head, OCT, 21 ¼ 2M FE X 24'’ SOW, w/1-3 1/8 2M EFO, full set of lockpins Unihead, OCT type 3, 13 5/8 5M API hub top X 13 3/8 BTC casing bottom, w/ 1- 2 1/16 5M SSO on lower section, 1- 2 1/16 5M SSO on middle section, 3- 2 1/16 5M SSO on upper section , IP internal lockpin assy King Salmon K-12RD2 24 X 13 3/8 X 9 5/8 X 4 ½ 24'’ 13 3/8'’ 9 5/8'’ 4 ½’’ Valve, Wing, AOP, 2 1/16 5M FE, HWO, AA trim Valve, Wing, WKM-M, 4 1/16 5M FE, w/ Safeco oper, EE trim Tubing head, CIW-DCB, 13 5/8 3M X 11 5M, w/ 2- 2 1/16 5M SSO, X- bottom prep, 1 ½ VR profile Adapter, CIW-Toadstool, 11 5M Stdd X 4 1/16 5M FE, prepped for 5 ¼ ESP neck, 2- ½ npt continuous control line ports Spool, 13 5/8 5M API hub X 13 5/8 5M FE DSA 13 5/8 5M x 13 5/8 3M Tubing hanger, CIW-DCB- ESP, 11 X 4 ½ IBT lift and susp, w/ 4'’ type H BPV profile, 5 ¼ EN, 2-3/8 continuous control line ports, prepped for BIW penetrator Void test good 250/3000psi Packed off in 2010 Re-checked 7/16/2018 Void test good 250/5000 7/16/2018 King Salmon Platform BOP Stack Valve Position(O/C)Standpipe PumpManifold1(PM1) OManifold PumpManifold2(PM2) OPumpManifold3(PM3) CPumpManifold4(PM4) OPumpManifold5(PM5) CMud KillLine1OCross KillLine2OHCRvalve(ChokeLine1) CChokeLine2OChoke ChokeManifold1(CM1) OManifold ChokeManifold2(CM2) CChokeManifold3(CM3) OChokeManifold4(CM4) CChokeManifold5(CM5) OChokeManifold6(CM6) CChokeManifold7(CM7) OChokeManifold8(CM8) CChokeManifold9(CM9) CChokeManifold10(CM10) OSuperChoke CManualChoke CRigFloor SafetyValve O Valve Position(O/C)Standpipe PumpManifold1(PM1) OManifold PumpManifold2(PM2) CPumpManifold3(PM3) OPumpManifold4(PM4) CPumpManifold5(PM5) OMud KillLine1OCross KillLine2OHCRvalve(ChokeLine1) CChokeLine2OChoke ChokeManifold1(CM1) OManifold ChokeManifold2(CM2) CChokeManifold3(CM3) OChokeManifold4(CM4) CChokeManifold5(CM5) OChokeManifold6(CM6) CChokeManifold7(CM7) OChokeManifold8(CM8) CChokeManifold9(CM9) CChokeManifold10(CM10) OSuperChoke CManualChoke CRigFloor SafetyValve O Rig 404 BOP Test Procedure Attachment #1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Rig 404, WO Program – Oil Producers, Gas Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. x Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. Confirm that well is static. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV. As approved in the sundry, proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2-way valve, or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand, or MU landing (test) joint to lift-threads d) For ESP wells - Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and / or a penetrator leaks, notify Operations Engineer (Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) Rig 404 BOP Test Procedure Attachment #1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing-head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same- RIH with test plug on joint of tubing. Install a pump-in sub w/ test line plus an open TIW or lower Kelly valve in top of test joint w/ open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump- install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder (test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1 st valve on standpipe manifold, close valves 1, 2, 10 on choke manifold and close the annular preventer, open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer, close safety valve and open IBOP on test joint, close outside valve on kill side of mud cross, open 1st valve of standpipe, close valves 3, 4 & 9 on choke manifold, open valves 1 & 2 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve / open outside valve on kill side of mud cross, close valves 5 & 6 / open valves 3 & 4 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke / open valves 5 & 6 on choke manifold. Pressure up to ~ 1200 psi and bleed off 200 – 300 #s recording change and stabilization. If passes after 5 minutes, bleed off pressure back to tank. f) Close HCR (outside valve on choke side of mud cross), open manual & super choke. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. Rig 404 BOP Test Procedure Attachment #1 g) Close inside valve / open outside valve (HCR) on choke side of mud cross. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Ensure all pressure is bled off- open pipe rams and pull test joint leaving test plug / 2-way check in place. Close blind rams and attach test line to valve 10 on choke manifold, close valve 7 & 8 / open valve 10 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Test additional floor valves (TIW or Lower Kelly Valve) and IBOPs as necessary. STANDARD TEST PROCEDURE OF CLOSING UNIT (ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record “Accumulator Pressure”. It should be +/- 3,000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2 nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read “10 bottles at 2,150 psi”). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/- 3,000 psi). Note: Make sure the electric pump is turned to “Auto”, not “Manual” so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format. Document both the rolling test and the follow up tests. Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well K-12RD2 (PTD 208-088)Sundry #: xxx-xxxAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC 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 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date 1 Carlisle, Samantha J (CED) From:Katherine O'connor <Katherine.Oconnor@hilcorp.com> Sent:Tuesday, October 13, 2020 3:04 PM To:Schwartz, Guy L (CED) Cc:Roby, David S (CED); Regg, James B (CED) Subject:RE: [EXTERNAL] K-12RD2 (PTD 208-088) ESP RWO HiGuy, WiththehelpofsomeESPgurus,IwasabletofindthatthegaugeontheESPisstillreadingandsendingdata,whichI didn’tknowuntiltoday.KͲ12hasbeenshutinsince2018,sothebelowdataisa2yearbuildup: Current Bottom Hole Pressure: 3,078 psi @ 8,128’ TVD 0.379 psi/ft (7.3 ppg) ESP Gauge (10/13/2020) Maximum Expected BHP: 3,078 psi @ 8,128’ TVD 0.379 psi/ft (7.3 ppg) ESP Gauge (10/13/2020) Maximum Potential Surface Pressure: **2,268 psi Using 0.1 psi/ft gradient per 20AAC 25.280(b)(4) Thisreservoirpressureismuchmoreaccuratethantheoneonthesubmittedprogram,whichwasacalculatedpressure bythereservoirengineer.SoFIWshouldbesufficient,butwealsohaveoilfieldsaltsatthedockasneededifFIW doesn’tkillthewellwhenwecirculateit. NotedontheNFTneeded. Thanks Katherine KatherineO’Connor CIOOperationsEngineer Katherine.oconnor@hilcorp.com W:(907)777Ͳ8376 C:(214)684Ͳ7400 From:Schwartz,GuyL(CED)<guy.schwartz@alaska.gov> Sent:Tuesday,October13,202011:41AM To:KatherineO'connor<Katherine.Oconnor@hilcorp.com> Cc:Roby,DavidS(CED)<dave.roby@alaska.gov>;Regg,JamesB(CED)<jim.regg@alaska.gov> Subject:[EXTERNAL]KͲ12RD2(PTD208Ͳ088)ESPRWO Katherine, KͲ12RD2hasaBHPof8.61ppg…areyoustillusingFIW(8.4ppg)toKillwellasdescribedintheprocedure?Assume youhaveabackupplantoaddKCLasneeded. Also,thiswellwillrequirea“noflow“testafterthecompletionisrun.Itsbeen6yrssincelaststestandtheFCOmay changethewelldynamics.Youcanwait30daysafterPOPsowellshouldbeinsteadystatebythen. Regards, 2 GuySchwartz Sr.PetroleumEngineer AOGCC 907Ͳ301Ͳ4533cell 907Ͳ793Ͳ1226office 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). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA RECEIVED AL/IL OIL AND GAS CONSERVATION COMARION AUG 2 8 2017 REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon El Plug Perforations 0 Fracture Stimulate 0 Pull TubingEl OperatioAOGn s shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other:Replace ESP 0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development I] Exploratory❑ 208-088 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20156-02 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018777 Trading Bay Unit K-12RD2 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A McArthur River Field/Hemlock Oil&Middle Kenai G Oil Pools 11.Present Well Condition Summary: Total Depth measured 11,515 feet Plugs measured N/A feet true vertical 9,641 feet Junk measured N/A feet Effective Depth measured 11,501 feet Packer measured 10,415&11,355 feet true vertical 9,629 feet true vertical 8,702&9,504 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 394' 24" 394' 393' Surface 2,510' 13-3/8" 2,510' 2,437' 3,090 psi 1,540 psi Production 10,747' 9-5/8" 10,747' 8,981' 6,870 psi 4,760 psi Liner 408' 7" 10,434' 8,723' 11,640 psi 15,140 psi Liner 1,031' 4" 11,465' 9,604' Perforation depth Measured depth 10,826-11,515 feet En True Vertical depth 9,048-9,641 feet SCAN NOV e( Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 9,595'(MD) 8,028'(TVD) 10,415'(MD)8,702'(TVD) Packers and SSSV(type,measured and true vertical depth) Swell Packers(x2) 11,355'(MD)9,504'(TVD SSSV: N/A 12.Stimulation or cement squeeze summary: 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 0 147 143 Subsequent to operation: 216 131 7991 57 72 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations El Exploratory ❑ Development0 Service ❑ Stratigraphic 0 Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ 0 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: 316-631 Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager J Contact Email: dmarlowe(a.hilcorp.com Authorized Signature: t.+...J Date: Oit%I Zet j 11 Contact Phone: (907)283-1329 /e (/‘ ^"c, 2 8 2017 Form 10-404 Revised 4/2017 K ,Y RBDMS Submit Original Only Z =r7 �CArthur River Field, TBU 14 . SCHEMATIC Well: K-12RD2 ' PTD: 208-088 Hilcorp Alaska,LLC API: 50-733-20156-02 Last Completed: 07/30/17 RKB to TBG Head=33.80' CASING DETAIL 24"@394' j i SIZE WT GRADE CONN ID TOP BTM. 0 24" Conductor Surface 394' 13 3/8" 13-3/8" 61 K-55 12.515" Surface 2,510' @ 2,510' 1 9-5/8" 47 N-80&S95 BTC/LTC 8.681" Surface 10,747' 7"Liner 38 P-110 LTC 6.184" 10,026' 10,434' 1 4"Slot. 10.9 L-80 IBTC 3.476" 10,434' 11,465' Liner TUBING DETAIL i 4-1/2" 12.6 L-80 Supermax 3.998 Surface 9,595' IA TOC @ 9,300' JEWELRY DETAIL Depth Depth NO. (MD) (TVD) ID OD Item Top of 7"Liner r, 1 @ 10,026' 9,595' 8,028' N/A 6.750 Discharge B/O 9,595' 8,028' N/A 6.750 Pump(x2)45 Stg 5H16000 Bad csg 4 4A 9,634' 8,060' N/A 6.750 Intake 10,328' i 1 9,635' 8,060' N/A 5.130 Tandem Seals-513 Series,BPBSL ? 9,653' 8,075' N/A 5.620 Motors(x2)562,KMSUT&KMSLT 500 HP Bottom of 7"/ iY 9,719' 8,128' N/A 5.620 Centralizer Anode Top of 4"Slot : " 2 10,415' 8,702' 5.92" 7"Swell Packer Liner@ 10,434' I " 3 11,355' 9,504' 3.476" 4"Swell Packer kifc 9 5/8"@ 10,747'W I ' 2 I I - I I -- G-5 Top of I I Window in 7"Liner I I PERFORATION DETAIL @ 10,873' I I I I Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Ft Status I I Open in'95. I I G-5 10,826' 10,910' 9,048' 9,119' 84' Reperf'd 1/02 I I I I G-5 10,830' 10,860' 9,052' 9,077' 30' en I I08/12/14 I I Open Hole Interval I I I I G-5thru HB-7 10,873' 11,515' 9,088' 9,641' 642' Open Open CO I.E.1 3 HK-1 11,049' 11,066' 9,239' 9,254' 17' 08/12/14 4"Slotted Liner I I Open @ 11,465' I I HK-2 11,078' 11,160' 9,264' 9,336' 82' 08/12/14 Open TD=11,515' HK-3 11,173' 11,198' 9,347' 9,368' 25' 08/12/14 MAX HOLE ANGLE=42° @ 5800' Updated by: JLL 08/21/17 • • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-12RD2 Moncla 404 50-733-20156-02 208-088 7/25/17 7/30/17 Daily Operations .. : . . 07/25/2017-Tuesday Skidded rig North then on West skid seals in one cylinder blew out. Called for 2-cylinders from Grayling. R/U 2" line from Moncla rig pump to tb side on K-12RD2 running returns to production pipeline. 0900 hrs began pumping FIW LW at 2.5 bpm 200 psi- returns at 30 bbls pumped, pressure now at 680 psi 2 bpm (400 psi pipe line pressure). Positioned racking mat beam. 1230 hrs worked M/V Titon receiving skid cylinders and 2- pipe racks. Finished skid over K-12RD2 at 1400 hrs. Moved W/O equipment into position while finishing circulation. Shutdown pump. Monitored well f/10 mins (on vacuum) and set BPV. Assisted production breaking down hookups on tree- N/D tree - N/U BOPE 13 5/8" 5M BOPE using 11" 5M x 13 5/8" 5M adapter flange. Hooked up all Koomey lines to stack, choke hose and kill line hose. Raise and scoped out derrick, securing all guy lines- mounted rig floor- loaded floor w/ handling tools and tongs. Moncla crew change out @ 0500am (1-crew rotation). 07/26/2017-Wednesday M/U 4 1/2" test jt w/pumpin, SV& IBOP on top, LH release sub on btm-shell tested BOPE to 3500 psi.Test all BOPE 250 psi low 3500 psi high as per Sundry in accordance with Hilcorp and AOGCC requirements. Tested w/4 1/2" & 3 1/2" tb- performed successful koomey draw-down test. Witness waived by Mr. Regg by email 10:07 AM 7/25/17. Onboard electrician checked gas alarm system. B/O LH blanked and ported test sub- pulled BPV. M/U landing jt- B/O hold down pins-opened casing valve- pulled hanger to surface (came off tb head at 112k- pulled up hole at 118k). NOS &Summit worked hanger- pumped 76 bbls FIW to fill the hole. R/U Summit to POH. Began POH w/ ESP production string pumping 10 bbls FIW every 20 jts laid down. Held Safety Standdown with both Moncla and crane crews discussing the importance of fall protection and incident at GPP. Lined up to prod pipeline and circulated 65 bbls down tbg flushing oil off backside. Continue POH w/ ESP production string pumping 10 bbls FIW every 20 jts laid down. 140 of 286 jts laid down at report time = EOT @ 5,208'. 07/27/2017-Thursday Finished POH from 5,208' w/Summit ESP assy laying down 3 1/2" 9.2# L-80 SuperMax tb. Discussed procedure for recovery of parted ESP assembly during tour change PJSM. Load boat w/ recovered 3 1/2" 9.2# L-80 SuperMax production tb and unload boat w/ new 4 1/2" SuperMax completion string. B/D ESP assy-found (suspected) broken shaft in lower tandem pump- intake shaft and coupling was stuck in the base of the lower pump (see pictures in 0 drive). Summit reattached the intake assembly over the shaft and triple wrapped it with absorb sheets and plastic wrap to prevent leaks. Found clean mineral oil in the heads of both motors- motors were grounded and balanced. Cleared and cleaned rig floor and well room-filled hole w/65 bbls FIW. Changed out 3 1/2" handling equipment to 4 1/2". Centered rig over hole. M/U pup w/xover on btm of 1st jt- began P/U new 4 1/2" 12.6# L-80 SuperMax tubing, straping then make up to 3200 FPT-stopped to adjust beaver slide and change out tongs (because of leak). 12 jts in hole =403' at report time. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-12RD2 Moncla 404 50-733-20156-02 208-088 7/25/17 7/30/17 Daily Operations: 07/28/2017- Friday Modified rig floor handrail to receive pipe from North side- completed power tong change out. Continued RIH w/ new 4 1/2" 12.6# L-80 Supermax prod string-strapping, P/U and torqueing to specs (total of 290 jts RIH = 9586'). Monitor well 10 mins, POH standing back prod string in derrick. 68 of 144 stands OOH at report time = 5,057'. 07/29/2017-Saturday Finished POH racking back 4 1/2" 12.6# L-80 SuperMax production string from 5,057' (total of 144 stands in derrick). Cleared and cleaned floor- prepped floor to P/U ESP assy. R/U Summit running equipment. P/U lower motor w/ gauge and lowered in hole. M/U upper motor and filled both with oil- picked up and attached anode, discharge and flat pack lines. Filled hole with 21 bbls FIW. Lowered in hole and M/U 2-seal sections and connected motor lead. M/U gas separator/intake and dual pump sections, pressure sub, discharge, X-over sub w/jt of 4 1/2" SuperMax bucked up- performed all checks on cable & lines.Tripped in hole to 5,554' w/ ESP assy on 4 1/2" production tubing drifting and torqueing to specs (3200 FPT)-testing power cable every 1000'. End of cable reel#1-changed out reel, setting 2nd reel in place on spooler-Spliced ESP power cable @ 5,556' (82 stands in hole). Continued RIH w/ ESP assy-89 stands in hole at report time = 6,020'. 07/30/2017-Sunday Finished RIH from 6,020' w/Summit dual 500 HP motor ESP assy on 4 1/2" 12.6# L-80 SuperMax production string to 9,680'. M/U tb hanger w/ landing jt-assisted by NOS rep- plumbed power cable and control lines thru hanger- electrical checked good-SOW 88k PUW est. 118k- landed hanger(EOTs @ 9,719.46') and ran in hold down pins- electrical checked good. B/O L/D landing jt. Set BPV. NOS rep packed off hanger void to 7000 psi. R/D Summit running equipment-cleared rig floor of all tools and tongs- B/D windwalls &floor supports-dismounted rig floor. Scope derrick down and laid over in headache rack. N/D BOPE. N/U production tree and assisted production hands hooking up all valves and lines. NOS hand tested tree void on hanger 500 psi f/5 mins 5000 psi f/ 15 mins.Tested hanger neck seals 500 psi f/5 mins and 5000 psi f/5 mins- Summit hand tested elec penetrator connection. Pull BPV and set 2-way check-shell tested tree t/5000 psi 5 mins all good- pull 2-way check and turned well over to production. Cleaned up well head room. Tit S • \%1///5 w THE STATE Alaska Oil and Gas ti41 of J\ LAsKA Conservation Commission aioritt = y 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ain: 907.279.1433 (4, ;11+-`S�� MFax. 907.276.7542 www.aogcc.alaska.gov Stan W. Golis Operations Manager SCANNED MAR 3 0 2017, Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: McArthur River Field,Hemlock and Middle Kenai G Oil Pools, TBU K-12RD2 Permit to Drill Number: 208-088 Sundry Number: 316-631 Dear Mr. Golis: 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, ° I 2ctt Cathy P oerster Chair DATED this 2lday of December, 2016. RBDMS LL- DEC 2 3 2016 • • RECEIVED STATE OF ALASKA DEC 19 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION ID`S 12.(22 j f f APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing 0 , Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. Replace ESP 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development 0 • 208-088 " 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,AK 99503 50-733-20156-02 , 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A Will planned perforations require a spacing exception? Yes 0 No 0 / Trading Bay Unit!K-12RD2 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018777 McArthur River Field/Hemlock Oil&Middle Kenai G Oil Pools 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): 11,515 9,641 11,501 9,629 3,144 psi NIA N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 394' 24" 394' 393' Surface 2,510' 13-3/8" 2,510' 2,437' 3,090 psi 1,540 psi Production 10,747' 9-5/8" 10,747' 8,981' 6,870 psi 4,760 psi Liner 408' 7" 10,434' 8,723' 11,640 psi 15,140 psi Liner 1,031' 4" 11,465' 9,604' Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 10,826-11,515 9,048-9,641 3-1/2" 9.2#/L-80 9,595 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): Swell Packer(x2)&N/A 10,415'(MD)8,702'(TVD)/11,355'(MD)9.504'(TVD)&N/A 12.Attachments: Proposal Summary El Wellbore schematic El 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic❑ Development 0 4 Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 1/15/2017 OIL 0 ' WINJ ❑ WDSPL ❑ 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 Dan Marlowe(907)283-1329 Email dmarlowe@hilcorp.com Printed Name Stan W.Golis,� Title Operations Manager Signature ►t.�.�; Phone (907)777-8356 Date it f (9 ` i (p COMMISSION USE ONLY Conditions of approval: Notify Co mission so that a representative may witness Sundry Number: ' 31 Le - Ce. Plug Integrity 0 BOP Test 1113 Mechanical Integrity Test ❑ Location Clearance ❑ Other: ,U ,t 35 u /G's:` df /.., . Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Now( Subsequent Form Required: /0" V o RBDMS L DEC 2 3 2016 I / APPROVED BY Approved by: Ag �" (.... .„,v...„.,__ „' COMMISSIONER THE COMMISSION Date: /2 -ZZ —/ b IL . ) 6' .- /2--22--L Submit Form and Form 10-403 Revised 11/2015 0 4rIv lPMi wistid for 12 months from the date approval. Attachments in Duplicate • • Well Work Prognosis Well: K-12rd2 Date: 12/19/16 HiIcorp Alaska,LLC Well Name: King Salmon K-12rd2 API Number: 50-733-20156-02 Current Status: Oil Producer Leg: Leg#4 NW Corner Estimated Start Date: January 15, 2017 Rig: Kuukpik#5 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 208-088 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Stan Golis (907)777-8356 (0) Current Bottom Hole Pressure: 4,049 psi @ 9,048'TVD 0.448 psi/ft(8.61 ppg)ESP Gauge Maximum Expected BHP: 4,049 psi @ 9,048'TVD 0.448 psi/ft(8.61 ppg)ESP Gauge Maximum Potential Surface Pressure: "*3,144 psi Using 0.1 psi/ft gradient per 20AAC 25.280(b)(4) **This is a no flow well 08/29/2014 Brief Well Summary: The K-12rd2 ESP failed on 12/18/16 due to a suspected parted shaft.The purpose of this work over is to replace the failed ESP equipment. f Last Casing Test: 08/05/2014 9,836' 1,500 psig for 30 minutes on chart 1.7 Procedure: 1. MIRU Kuukpik Rig#5. 7 2. Circulate hydrocarbon off of well.Work over fluid will be FIW. BOP's will be closed as needed to circulate the well. 3. ND Wellhead, NU BOP and test to 250psi low/3,500psi high. (Note: Notify AOGCC 24 hours in advance of test to allow them to witness test). 4. Monitor well to ensure it is static. 5. POOH ESP. 6. PU and RIH with new ESP assembly. 7. ND BOP, NU wellhead and test. 8. Turn well over to production. 9. Conduct SVS per AOGCC regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current/Proposed (Same) 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form CArthur River Field, TBU II 0 SCHEMATIC Well: K-12RD2 PTD: 208-088 Hilcarp Alaska,LLC C API: 50-733-20156-02 Last Completed: 08/15/2014 RKB to TBG Head=33.80' CASING DETAIL 24"@39a' SIZE WT GRADE CONN ID TOP BTM. 4 24" Conductor Surface 394' 133nr 13-3/8" 61 K-55 12.515" Surface 2,510' 2,510' 9-5/8" 47 N-80&S95 BTC/LTC 8.681" Surface 10,747' 7"Liner 38 P-110 LTC 6.184" 10,026' 10,434' 4"Slot. 10.9 L-80 IBTC 3.476" 10,434' 11,465' Liner TUBING DETAIL 3-1/2" 9.2 L-80 Supermax 2.992" Surface 9,595' 1 1 2 TOC @9,300' _ 4 JEWELRY DETAIL 5 ..,.) NO. Depth s (MD) Length ID OD Item Top of 7"Liner 6 # 1 9,594' 0.70 X-Over Sub @ 10,026' 4 2 9,595' 0.62 Bolt-On Discharge Bad cs i 511 3 9,596' 43.78 Pump(x2)675 Series 9 4 9,641' 17.84 Tandem Seals:BPBSL 10,328' ;' ';a )2 5 9,659' 60.50 Motor(x2)562 Series 340 HP r 41 6 9,723' 2.02 Centralizer/Anode Bottom of 7"/ A 7 10,415' 19.0' 5.92" 7"Swell Packer Top of 4"Slot ;"` J 8 11,355' 19.7' 3.476" 4"Swell Packer Liner@ 10,434' ; 41 Y 9 5/8"@ 10,747 1 I �ra 7 I I - I I = G-5 Top of I I - Window in 7"Liner I I @1o,s73' I I PERFORATION DETAIL I I Zone Top(MD) Btm(MD) Top(TVD) Btm(ND) Ft Status I I Open in'95. I I G-5 10,826' 10,910' 9,048' 9,119' 84' Reperf'd I I 1/02 en G-5 10,830' 10,860' 9,052' 9,077' 30' 08/12/14 Open Hole Interval I I I I G-5 thru HB-7 10,873' 11,515' 9,088' 9,641' 642' Open CEP CEJ 8 Open HK-1 11,049' 11,066' 9,239' 9,254' 17' 08/12/14 4"Slotted Liner I I Open @ 11,465' I I HK-2 11,078' 11,160' 9,264' 9,336' 82' 08/12/14 Open TD=11,515' HK-3 11,173' 11,198' 9,347' 9,368' 25' 08/12/14 MAX HOLE ANGLE=42° @ 5800' Updated by: .ILL 09/15/14 • cArthur River Field, TBU 11 PROPOSED Well: K-12RD2 PTD: 208-088 Hilcorp Alaska,LLC API: 50-733-20156-02 Last Completed: Future RKB to TBG Head=33.80' ICASING DETAIL 24"@ 394' D SIZE WT GRADE CONN ID TOP BTM. ,:i 24" Conductor Surface 394' i.413 3/8" 13-3/8" 61 K-55 12.515" Surface 2,510' 2,510' 9-5/8" 47 N-80&595 BTC/LTC 8.681" Surface 10,747' 7"Liner 38 P-110 LTC 6.184" 10,026' 10,434' 4"Slot. 10.9 L-80 IBTC 3.476" 10,434' 11,465' Liner TUBING DETAIL 4-1/2" 12.6 L-80 Supermax 3.958" Surface ±9,595' TOC @s,sood ,,, JEWELRY DETAIL NO. Depth Length ID OD Item 111 Top of 7"Liner '� 1 @ 10,026' ;' • 1 ±9,725' Bottom of ESP t Bad csg '- 10,328' i. w,' i 41 Bottom of 7"/ ' 2 10,415' 19.0' 5.92" 7"Swell Packer Top of 4"SlotPc 3 11,355' 19.7' 3.476" 4"Swell Packer Liner@ 10,434' ' I t rim I I 'MZri 2 9 5/8"@ 10,747 L I I - I I - G-5 Top of I I - Window in 7"Liner I I @ 10,873' I I PERFORATION DETAIL I I Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Ft Status I I Open in'95. I I G-5 10,826' 10,910' 9,048' 9,119' 84' Reperf'd 1/02 I I G-5 10,830' 10,860' 9,052' 9,077' 30' en I I08/12/14 I I Open Hole Interval I 1 I I G-5 thru HB-7 10,873' 11,515' ¢ 9,088' 9,641' 642' Open Open CEP Cal 3 HK-1 11,049' 11,066' 9,239' 9,254' 17' 08/12/14 4"Slotted Liner I I Open @ 11,465' I I HK-2 11,078' 11,160' 9,264' 9,336' 82' 08/12/14 Open TD=11,515' HK-3 11,173' 11,198' 9,347' 9,368' 25' 08/12/14 MAX HOLE ANGLE=42° r@ 5800' Updated by: JLL 12/19/16 r • King Salmon Platform K-12RD2 Current H.h'urp:Va.ka.LIR. 06/17/2014 King Salmon Tubing hanger,CIW-DCB- K-12RD2 ESP,11 X 4 h IBT lift and 24X133/8X95/8X4'/. susp,w/4' type H8PV profile,5'/.EN,2-3/8 continuous control line ports,prepped for BIW penetrator BHTA,B-11-A0,4 1/16 5M FE , ,' Valve,Swab,WKM-M, g �D 4 1/16 5M FE,HWO,EE trim �o 1•1111•11.1•1 Valve,Wing,McEvoy-C,4 1/16 5M FE, w/Axelson AM oper,EE trim Valve,Wing,AOP, ft'��TY O 21/165MFE,HWO,AAtrim 11,*- �, O - 11111 Valve,Master,WKM-M, 4 1/16 5M FE,HWO,EE trim riy .. Adapter,CIW-Toadstool,11 5M Stdd X 4 1/16 5M FE,prepped for 5%ESP neck,2-'%npt t 1 continuous control line ports Tubing head,CIVWDCB, --110.1,r 13 5/8 3M X 11 5M,w/ ' 2-2 1/16 5M SSO,X- 0 1%VR profile tom prep, II III ._ ,a '- OSA 13 5/8 5M x 13 5/8 3M Spool,13 5/8 5M API hub X i- 135/85MFE 0 IS .01 1 _4 re.":i 2 'eI1J.1 . ‘.;e!, II 03, .j• fl AIA i.. E All unihead annular valves, 2 1/16 5M FE OCT-20,HWO Unihead,OCT type 3,13 5/8 5M API ' 1 ,' hub top X 13 3/8 BTC casing bottom, . ��' • I IAl. w/1-2 1/16 5M SSO on lower II r 3, l � 1.4 section,1-2 1/16 5M SSO on middle ! , l _ section,3-2 1/16 5M SSO on upper - .a,.'-'' leill' iI 4 section,IP internal lockpin assy gr. J ... .. \ , Valve,OCT-20,3 1/8 2M FE, Starting head,OCT,21'/.2MFEXs` ® �1 f 1 • % HWO 24"SOW,w/1-3 1/8 2M EFO,full �latil� 4I;•' set of lockpins X24" 13 3/8" 9 5/8" • . King Salmon Platform 2016 BOP Stack(Kuukpik) 06/22/2016 Hilrarp AWL..,1,11L Rig Floor 16" Pipe [In Mint I • o 11 lil I11 III III al III iii 3.74' Shaffer 13 5/8 5M si rftl rn-i I I rn- Shaffer SL 2 7/8-5.5 Variables 2.83' - _ 13 5/8 5M 4,—n Blind r 2 1/16 5M manual and HCR valve t� Iii l 11 1511111'1111 1.76 � � I. � 14. `/ I11 !II I.I- Shaffer SL 130 1.44' 13 SSM 10 2 7/8-5.5 Variables /: :� iIII II!I II•iIII Drill deck 13.70' Riser 13 5/8 5M FE X 13 5/8 5M API hub • • Choke Manifold Valves 2 " 1 To Shaker 3" Panic To Gasbuster 3 1/8" O 2 1/6" �O O 2 1/16" fI frali IT I _ O 21/1 + 2 1/16" + io N xi 3 1/8" rn L41,..,1 • CI 2 1/16" e 2 1/16" Manual Choke Automatic Choke 2 1/16" Inlet Pressure Sensor 3" 5,000 PSI Choke Manifold Kuukpik Drilling Rig 5 RED = 3 1/18" 5,000 PSI VALVES AND LINES BLUE = 2 1/16" 5,000 PSI VALVES Kuukpik Drilling Rig 5 Choke Manifold 4 ., :N..' -00 tT 0 10 4t1 C-2 i , \. #6 "'J #9 013 #12 .. 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In a I I I I I I I I 1 r—� r A a• a•aaiaa. a. a.pa4,ll.r at, at) .s.! sl 1010101 I0IVIViCI mi ml mi AmI ml mI mi ml ml q'q•R ,q,q,q.q,q• VIVfol UIU1VIu1Ul U1 al al al al al ai al al ai 40 • il l l 1 1 l l 1D1o101010101010101 «;.4,I�I�I4,I�I�I�Ic Ic I o••o. to NININIMINININININI F4 c 1 1 1 1 1 1 1 1 1 to co r ' fa "INi^i+ini`oir-imiai -+ 1 1 1 1 1 1 I I I .•-, •.• M R-i o w n a 44 i r• m a L. a • Kuukpik 5 BOP Test Procedure • flilcarp Alaska,r.r.c Attachment#1 Attachment #1 Hilcorp Alaska LLC. Rolling BOP Test Procedure: Kuukpik 5 — Oil/Gas Producers, Water/Gas Injectors Initial Test(i.e.Tubing Hanger is in the Wellhead) If BPV profile&lift threads were deemed good, but still unable to get good tests 1) If both set of threads appear to be bad and unable to hold a pressure test and/or a penetrator leaks, notify Operations Engineer(Hilcorp), Guy Schwartz (AOGCC-guy.schwartz@alaska.gov),Jim Regg (AOGCC-jim.regg@alaska.gov) and Michael Quick (AOGCC—Michael.quick@alaska.gov)via email explaining the wellhead situation prior to performing the rolling test. If on Federal land contact BLM representative Amanda Eagle (aeagle@blm.com) and Mutasim Elganzoory(melganzoory@blm.com). AOGCC and BLM may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: 2) With stack out of the test path, test choke manifold per standard procedure 3) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) Kill and choke line valve will also be tested during this time. 4) During these tests the test chart needs to be set to 60 min instead of 12 hours so chart shows a better graph. Need to station hands in cellar going over all connections on the BOPs looking for the slightest leak.Also need a man looking down the hole to confirm that the BOPs are not leaking. Test# 1=Annular, HCR Choke, and HCR Kill. Test#2=Upper Pipe Rams, HCR Choke, and HCR Kill. Test#3=Upper Pipe Rams, Manual Choke, and Manual Kill. Test#4=Lower Pipe Rams. 5) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. 6) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) 7) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/penetrator wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 8) Pull hanger to surface. (Making tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid and sweep off any oil cap that may be present. 9) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE as per Kuukpik's standard test procedure. Or POOH laying down all the tubing and use the normal test plug to finish the tests that were not completed as per regulatory approval. • • Kuukpik 5 BOP Test Procedure Hilcorp Alaska, HA #1 If the tubing hanger won't pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree and test. May have to tap out if scaled up or paraffined up if well is not dead may have to be done w/pressure lubricator (diesel or acid could help) 2) If unsuccessful, or BPV profile is eroded and well is dead. Best practice is to have two barriers a. Fluid column b. Set wire line plug or tag fluid level with slick line to establish static fluid level or shoot fluid level with an echo meter gun. 3) Shoot off tubing very shallow( 300-500' most likely just under SSSV if applicable) 4) Spear hanger w/upside down cup provided by fishing company 5) Proceed to get best test we can achieve against cup and confirm no visual leaks on all flanges of BOPE 6) Notify Hilcorp Anchorage Operations Engineer and AOGCC of situation 7) Pull hanger and cut off stub 8) P/U test plug and set same. 9) Perform complete BOPE test as per Kuukpik's standard procedure • 0 � C 2 R20 / k02 2 & 0 _ 2E CDo ° / / 2 � � cw < a E ® 0 ' a . . : § 2o w7 0mc 3 a < 73 § $ -02 as >,; > = fcOg �.§ C:3. % / M -0 ■ a) 3 ® # 2 U _ 2 c CD 3 .>"Ccn o J Co co k � W o ¥ '0 1- / � @ a = e O N � � _k / 2 a)co c0 c = \ 100 ■ kf CD I) E % ° m 2 2 / .% a / / L. $ co \ 0 g C) .� a -6 F C ' co § � m c ' 0 c w § > ■ 0 0 1-4 0 a. o_ % co � 03 « ° ' 0 Zr)a. Q % / E 0 Q a ¥ a ■ a)« � co o w os ns . co § Q $ g 000 el C .2 2 ° q Ch a t. 20 k F 2 /O 0 / . U co Cl) k 0 Cl) < a 0 • Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. Z O_S - 0 g g Well History File Identifier Organizing (done) ❑ Two -sided 1111111111111111 ❑ Rescan Needed 111 1111111111111 7§CAN DIGITAL DATA OVERSIZED (Scannable) 1 Color Items: ❑ Diskettes, No. ❑ Maps: ❑ Greyscale Items: ❑ Other, No/Type: ❑ Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: me BY: Maria Date: a 3 /s/ Project Proofing III IIIIIII 1 111 BY: del, Date: a ' 1 /s/ 11111 Scanning Preparation 1 x 30 = 30 + 3q = TOTAL PAGES 5- 1 (Count does not include cover sheet) BY: . <aria ) Date: 4 0..3 1 1 /s/ Production Scanning III IIIIIII 11111 Stage 1 Page Count from Scanned File: _ b t ! (Count does include cov heet) Page Count Matches Number in Scanning Preparation: YES NO BY: 411:, Date: 3 a3 J 1 /s/ WI v P Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. III 11111111111111 ReScanned 111 I1IIIIHIIIU BY: Maria Date: /s/ Comments about this file: Quality Checked 111 11111111 IIII 10/6/2005 Well History File Cover Page.doc DATA SUBMITTAL COMPLIANCE REPORT 3/14/2011 Permit to Drill 2080880 Well Name /No. TRADING BAY UNIT K -12RD2 Operator UNION OIL CO OF CALIFORNIA API No. 50- 733 - 20156 -02 -00 MD 11475 TVD 9607 Completion Date 8/14/2008 Completion Status 1 -OIL Current Status 1 -OIL UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Surve( Ye) DATA INFORMATION III Types Electric or Other Logs Run: RST & LWD (data taken from Logs Portion of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Ty Med /Frmt Number /Name Scale Media No Start Stop CH Received Comments D C Las 16916 R eservoir Saturation 7183 8898 Open 9/18/2008 RST og Reservoir Saturation 2 Blu 7200 11456 Open 9/18/2008 RST, Sigma, GR, CCL 11- Aug -2008 QED C Las 17185 Lt uction /Resistivity 10834 11475 Open 11/7/2008 Depth, ROP, GR, RAC, RPC o - In ction /Resistivity 2 Col 10892 11475 Open 11/7/2008 MPR, GR 7- Aug -2008 ED C Las 19806 Induction/Resistivity 10843 11514 Open 6/29/2010 Final and MPR in multiple graphics Well Cores /Samples Information: Sample Interval Set III Name Start Stop Sent Received Number Comments ADDITIONAL INFORMATION r Well Cored? 1/ Daily History Received? N Chips Received? . Y1'td -- Formation Tops -� N Analysis " Received? Comments: DATA SUBMITTAL COMPLIANCE REPORT 3/14/2011 Permit to Drill 2080880 Well Name /No. TRADING BAY UNIT K -12RD2 Operator UNION OIL CO OF CALIFORNIA API No. 50- 733 - 20156 -02 -00 MD 11475 TVD 9607 Completion Date 8/14/2008 Completion Status 1 -OIL Current Status 1 -OIL UIC N • Compliance Reviewed By: Date: t MA N I '7 • • 1 Chevron Francisco Castro Chevron North America Exploration and Production Technical Assistant 3800 Centerpoint Dr. Suite 100 Anchorage, AK 99503 Tele: 907 263 7844 Fax: 907 263 7828 E -mail: fcbn @chevron.com DATE June 28, 2010 . F IP To: AOGCC Mahnken, Christine R 333 W. 7 Ave. Ste #100 Anchorage, AK 99501 Al a ;71. a _ , DATA TRANSMITTAL Transmitted herewith is one DVD containing the following data. • D -48L1 �� • Formation evaluation logs - LAS /` 9 "0 / • Gamma ray logs - LAS • K -12RD2 aoc,- l .46OJ • K- 12RD2_Final_Survey.xls • K- 12RD2_Tops.xlsx 0/5 _W 1'1 IS I) • MPR -Gamma ray logs - LAS, CGM, PDF • K -18RD 00! - / /q /9t6)---4- • K- 18RD_Final_Survey.doc • Density Neutron logs - LAS 064,--/q/ / 9 �d t • K- 18RDPB1 • UBI log - LAS, PDS, DLIS 30°5-664i y .bd • survey.xls • K -24RD2 X63 - /t0 • Density Neutron logs - LAS • Final Mudlog Report - LAS, DOC 'O? " l9 0 /9 $ 1/ • M -06 • Final logs; Depth, Formation Evaluation, Realtime, Time - LAS, PDS, DLIS • M -10 • M- 10Tops.xlsx c9011 -- /(o �jc7 • USIT log - PDS 069 -Q /� �i 3 • Final logs; Depth, Formation Evaluation, Realtime, Time - LAS, PDS, DLIS • M -10PB1 • Final logs; Depth, Formation Evaluation, Realtime, Time - LAS, PDS, DLIS • M -16RD /1‘9 - 6 9L) • M- 16RD_Tops.xlsx • Final logs; Cement Bond Log, Completion Record -PDS • M -17 • M- 17_Tops.xlsx • M17_MWD_Survey.pdf • Final Mudlog Report - LAS, DOC, DBF, MDX, PDF, DAT • Final logs; Depth, Formation Evaluation, Cement Bond, Plug Setting, Perforation - LAS, PDS, DLIS, TIFF Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 263 7828. Received By: Date: log • Chevron Francisco Castro Chevron North America Exploration and Production Technical Assistant 909 W. 9th Avenue Anchorage, AK 99501 %110 Tele: 907 263 7844 Fax: 907 263 7828 E -mail: fcbn @chevron.com DATE November 3, 2008 To: AOGCC Mahnken, Christine R 333 W. 7 Ave. Ste#100 - Anchorage, AK 99501 DATA TRANSMITTA WELL L0 TYPE SCALE LOG DATE INTERUAL NOTES LAS PD5 MULTIPLE GRANITE PT RESISTIVITY GAMMA ST 18742 RAY AZIMUTHAL GAMMA LAS, CGM, XLS, 32RD2 IMAGE 2" 21- Sep -08 1 9070 -15386 PDF, DLIS AZIMUTHAL DENSITY GAMMA RAY BULK GRANITE PT DENSITY NEUTRON ST 18742 POROSITY ACOUSTIC LAS, CGM, XLS, 32RD2 CALIPER 2" 21- Sep -08 1 13020 -15388 PDF, DLIS MULTIPLE GRANITE PT PROPAGATION ST 18742 RESTIVITY GAMMA RAY LAS, CGM, XLS, 32RD2 MAGNEIC RESONANCE 2" 21- Sep -08 1 10120 -13100 PDF, DLIS MULTIPLE PROPAGATION RESISTIVITY GAMMA GRANITE PT RAY BULK DENSITY ST 18742 NEUTRON POROSITY LAS, CGM, XLS, 32RD2 ACOUSTIC CALIPER 2" 21- Sep -08 1 13030 -15388 PDF, DLIS MULTIPLE PROPAGATION RESISTIVITY GAMMA TBU K -12RD2 RAY 2" 7- Aug -08 10834 -11475 CGM, PDF, LAS 0 / 1 / 6 -( 9o I l t s Please acknowledge recei.t by signing and returning one copy of this transmittal or FAX to 907 263 7828. Received By: I Date: 3 • • Chevron Francisco Castro Chevron North America Exploration and Production Technical Assistant 909 W. 9th Avenue ito•-- Anchorage, AK 99501 Tele: 907 263 7844 Fax: 907 263 7828 E-mail: fcbn@chevron.com DATE September 17, 2008 To: AOGCC Mahnken, Christine R 333 W. 7 Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL ,;;,i,'‘r,,:::rkavv.,,„„t,,.,,..,,,,-,,,,,,47,,,,,op,,, ,'‘k4',,;. ' ';' '`,,,'• ' , , rr; V.1 Mr7Mirtffe. . , 4 ‘, ‘ < n, ., 1 : , , ,' ''' 3:44M0i4Zak ,'' 1, ' ::: , , , , ' !,,tli 4,1*,:***::::: it ,? 1 Itt94 '5,1");.„A 4414 oti*0,0 '' , ,*- 4 1 , z •°; - :::ivia L.--::,‘ 1, ii*,:64- :....: ,t,2, 7. ,,,, , ‘,„•„, ,..,,,,,,,, ,,,,„--..,,,, . : ! , 34 1. ; : , ,, ,,,00,1e..4, ,, :k ,, Y:\.jkif jie . 0 4 A '4' 4- EWWW ;4'z ' II RESERVOIR SATURATION TOO SIGMA TBU K-12RD2 MODE GR/CCL 5" 11-Aug-08 7200-11456 1 1 1 PDS, LAS PSP PRESSURE GRANITE PT TEMPERATURE ST 17587 3 LOG GR-CL 5" 17-Jul-08 200-9036 1 1 PDS, LAS OofF u-Te.... /626 - •r'/9/ Please acknowledge receipt by signing and returning one copy oftfriS.TraAM4tt'albr 'FAX.to 907 263 7828. Received By: & 6 ----- Date: so 3 STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la. Well Status: Oil El , Gas ❑ Plugged ❑ Abandoned ❑ Suspended ❑ lb. Well Class: 20AAC 25.105 20AAC 25.110 Development 0 ' Exploratory❑ GINJ ❑ WINJ ❑ WDSPL ❑ WAG ❑ Other❑ No. of Completions: Service ❑ Stratigraphic Test❑ 2. Operator Name: 5. Date Comp., Susp. r 7 P 12. Permit to Drill Number: tre :15 Union Oil Company of California Aband.: 8/008 208 -088 - 3. Address: 6. Date Spudded: 13. API Number: PO Box 196247, Anchorage, AK 99519 i 7/25/2008 • 50- 733 - 20156 -02 , 4a. Location of Well (Government I Section): // ��k 7. Date TD Reached: 14. Well Name and Number: Surface: 735' & 140'�f SE Cr., Sec 17, T9N, R13W SM , 8/5/2008 • King Salmon K -12RD2 , Top of Productive Ho on: � 8. KB (ft above MSL): 100' • 15. Field /Pool(s): 743'& 269'yrof SE Cr, Sec 18, T9N, R13W, SM Ground (ft MSL): N/A McArthur River Field qq Total Depth: ✓ 9. Plug Back Depth(MD +TVD): G -Zone Pool 777''& 596' W of SE Cr. , Sec 18, T9N, R13W SM N/A Hemlock Pool • 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD p+, �/ 16. Property Designation: Surface: x- 213758 ` y- 2511809 . Zone- 4 • 11,475' MD (J510 D ADL0018777 [King Salmon Platform] TPI: x- 208349 y- 2511950 Zone- 4 11. SSSV Depth (MD + TVD : 17. Land Use Permit: Total Depth: x- 208024 - y- 2511994 . Zone- 4 N/A 'P'ib'N /A 18. Directional Survey: Yes ell , No ❑ 19. Water Depth, if Offshore: 20. Thickness of Permafrost (TVD): (Submit electronic and printed information per 20 AAC 25.050) 62' (ft MSL) N/A 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): -77'g /D, 4373 / 7 A RST & LWD / coi54 X 71 , "b f' /t •O$ 22. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD FT PULLED 24" Surface 394' Surface 393' 13 -3/8" 61 J -55 Surface 2,510' Surface 2,437' 18" 1500 sxs class G cement 9 -5/8" 47 N80/S95 Surface 10,747' Surface 8,981' 12 -1/4" 1000 sxs class G cement 7" 29 P -110 10,026' 10,434' 8,382' 8,723' 8 -1/2" N/A 4" 10.9 L -80 10,434' 11,465' 8,723' 9,604' 5 -3/4" N/A 23. Open to production or injection? Yes 0 No❑ If Yes, list each 24. TUBING RECORD interval open (MD +TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD) 4" Slotted Liner from 10,751' - 11,460' MD (9,016' - 9,599' TVD) 4 -1/2" 9,833' N/A G -5 10,826' - 10,910' (9,055' - 9,125' TVD) 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED N/A N/A RECEIVED il 26. PRODUCTION TEST sP Jena Date First Production: Method of Operation (Flowing, gas lift, etc.): Alaska Oil �58Oi7S9fflftllSSiO(t 8/14/2008 ESP Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Cho48 ge Gas -Oil Ratio: 8/16/2008 24 Test Period —4 81 126 7622 N/A N/a Flow Tubing Casing Press: Calculated Oil-Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 930 12psi 24 -Hour Rate —> 81 126 7622 N/A 27. CORE DATA Conventional Core(s) Acquired? Yes ❑ No ig Sidewall Cores Acquired? Yes ❑ No El If Yes to either question, list formations and intervals cored (MD +TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. Iv CU M PLtT10�1 ,v U fPER!} .► t ,./.:. ,./.:. t s d p�( Form 10-407 Revised 2/2007 CONTINUED ON REVERSE 4 .-----7,4 9 � /a ' " • • 28. GEOLOGIC MARKERS (List all formations and markers encountered): 29. FORMATION TESTS NAME 1 MD TVD Well tested? ❑ Yes 0 No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if Permafrost - Top N/A N/A needed, and submit detailed test information per 20 AAC 25.071. Permafrost - Base N/A N/A G -Zone G5LB 10,922' 9,135' G -Zone G6B 10,987' 9,191' G -Zone G7T 10,994' 9,197' Hemlock HKT 11,030' 9,228' Hemlock HK1T 11,037' 9,234' Hemlock HK1B 11,070' 9,262' Hemlock HK2T 11,078' 9,269' Hemlock HK2B 11,177' 9,356' Hemlock HK3T 11,182' 9,360' Hemlock HK3B 11,215' 9,389' Hemlock HK4T 11,215' 9,389' Hemlock HK4B 11,308' 9,469' Hemlock HK5T 11,315' 9,475' Hemlock HK5B 11,363' 9,516' Hemlock HK6T 11,376' 9,526' Hemlock HK6B 11,424' 9,567' Hemlock HK7T 11,428' 9,570' 30. List of Attachments: Directional Survey, Schematic, Daily operational summary 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Steve Tyler 263 -7649 Printed Name: Timothy C. Brandenburg Title: Drilling Manager Signature: l - Phone: (907) 276 -7600 Date: 9/16/2008 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10 -407 well completion report and 10 -404 well sundry report when the downhole well design is changed. Item la: Classification of Service wells: Gas Injection, Water Injection, Water - Alternating -Gas Injection, Salt Water Disposal, Water Supply for / njection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50- 029 - 20123- 00 -00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut -in, or Other (explain). Item 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10 -407 Revised 2/2007 • • Chevron 111 %. Chevron - Alaska Daily Operations Summary Well Name Field Name API /UWI Lease/Serial CHEVNO License No. /Props... Orig KB Elev (ftKB) Water Depth (ft) K -12RD2 MCARTHUR RIVER, 507332015602 ADL0018777 AR4374 2080880 33.8 Job Cat Type AFE No. QC Eng Drill and Complete Drilling - Re -Entry UWDAK- R8042 -E... till "O " ratio ,'t 7/25/2008 00:00 - 7/26/2008 00:00 Operations Summary Tag CIBP (cast iron bridge plug) © 10,886', orient whipstock, set & begin window milling operation w/ 5 -3/4" bit. Mill window from 10,873' to 10,882'. Drill out into formattion to 10,886' 7/26/2008 00:00 - 7/27/2008 00:00 Operations Summary Drill additional formation to 10,892' out of window pump sweep & start out of hollow mill BHA 7/27/2008 00:00 - 7/28/2008 00:00 Operations Summary Recover window milling BHA missing mill blade. RU slickline making runs with magnet. Recover 2 small metal pieces. 7/28/2008 00:00 - 7/29/2008 00:00 Operations Summary Continue slickline runs w/ magnet recover 2 more metal pieces. RD slickline. RIH w/ drilling BHA w/ 5 -3/4" Bit. 7/29/2008 00:00 - 7/30/2008 00:00 Operations Summary Continue in hole w/ BHA. Circ sweep, begin directionally drilling. Drill from 10,892' to 11,067' 7/30/2008 00:00 - 7/31/2008 00:00 Operations Summary Continue directionally drilling from 11,073' to 11,075', Drilling slowed to 0.5 ft/hr. Start out of hole, Blew Cudd seal on manifold. Laid down for repair, circulate while repairing. 7/31/2008 00:00 - 8/1/2008 00:00 Operations Summary Repair CUDD "Husco" unit & continue to POOH to 1590' at report time. Notice given to AOGCC of upcoming BOP test. 8/1/2008 00:00 - 8/2/2008 00:00 Operations Summary POOH to surface. Test BOPE 250 low/ 3000psi high, passed, witness waived by AOGCC Jim Regg. make up new motor & Hycalog 5 -3/4" PDC Bit. RIH to 6018' at report time. (P /U 108K) S /0 =68K 8/2/2008 00:00 - 8/3/2008 00:00 Operations Summary RIH to 11074'. make P /U -S /O check, Pump 30bbl sweep. Directionally drill from 11074' to 11276', ROP stopped, pump slug - start out of hole. 8/3/2008 00:00 - 8/4/2008 00:00 Operations Summary POOH w/ 5 -3/4" Hycalog bit (worn out) make up new PDC (1-10507Z) & RIH to 3110' at time of report. 8/4/2008 00:00 - 8/5/2008 00:00 Operations Summary RIH w/ PDC bit (5 -3/4" HC507Z) Rotate thru window 10817' - 10943'. Wash down from 11198' - 11262' and directionally drill to 11345' 8/5/2008 00:00 - 8/6/2008 00:00 Operations Summary - Continue directionally drilling w/ bit No. 3 to 11515'. Work tight spot t 11515' to 10943'. Pump 30bbl pill & 80b1 fresh mud. 8/6/2008 00:00 - 8/7/2008 00:00 Operations Summary Continue pump bottom mud sweep & start out of hole to 1433' at time of report. 8/7/2008 00:00 - 8/8/2008 00:00 Operations Summary Continue to POOH with drill pipe. LD BHA. Prep for liner run. PU RIH w/ 7" 38# P -110 LTC Liner. Scab w/ 4" 10.9# L -80 IBTC slotted liner. 8/8/2008 00:00 - 8/9/2008 00:00 Operations Summary Continue running Liner. Set liner bottom at 11465' (old RKB). Top of liner @ 10040' (old RKB).Set liner hanger to 2800psi & packer to 3200psi. Pressure test 9 -5/8 "casing to 1000psi, held for 10 min. 8/9/2008 00:00 - 8/10/2008 00:00 Operations Summary Liner hangersetting tool would not release. Backed off drill pipe. POOH. RIH w/ freepoint. Pulled liner hanger setting tool free. POOH at time of report. 8/10/2008 00:00 - 8/11/2008 00:00 Operations Summary Cont. POOH & LD with liner hanger setting tool. RIH. Displace mud with FIW (filtered Inlet water)). 8/11/2008 00:00 - 8/12/2008 00:00 Operations Summary Run RST log from 11,516- 10,570' & 8,750'- 7,185', prep to run ESP pump completion. Equipment change out, blind rams for blind shears to run completion, test to 250 /3000psi. 8/12/2008 00:00 - 8/13/2008 00:00 Operations Summary RIH with ESP completion on 4.5" 12.6# L -80 BTC tubing to 4993' (Jack Rail measurement) at time of report Chevron • Chevron - Alaska Daily Operations Summary Well Name Field Name API /UWI Lease /Serial CHEVNO License No. /Prope... Orig KB Elev (ftKB) Water Depth (ft) K -12RD2 MCARTHUR RIVER, 507332015602 ADL0018777 AR4374 2080880 33.8 i O. Orations .. .. .,, .3• u " . f ` . , . ". `g 8/13/2008 00:00 - 8/14/2008 00:00 Operations Summary Continue running tubing to land ESP pump at 9833' RKB. 8/14/2008 00:00 - 8/15/2008 00:00 Operations Summary • Test tubing hanger to 5000psi for 30 min, held, ND BOP, NU tree. Rig mob to K -01. Chevron 0 0 ft0 Trading Bay Unit King Salmon Well No. K -12RD2 1%0 Actual Schematic RKB to \ TBG Head = 33.80' 1 24" @ 394' i CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 13 3/8" 13 -3/8" 61.0 K -55 12.515" Surface 2,510' @ 2,510' 9 -5/8" 47 N -80 & S95 BTC /LTC 8.681" Surface 10,747' 7" Liner 38 P -1 10 LTC 6.184" 10,026' 10,434' 4" Slot. Liner 10.9 L -80 IBTC 3.476" 10,434' 11,465' Tubing: 4 -1/2" 12.6 L -80 BTC 3.958" 33.8' 9,833' J Q . ° ° ° ° ci Jewelry Detail ■ Item # Depth Length OD ID Description TOC @ 9,300' , .. .$ 1 9,655' 4.05' 4.5" 3.958" Otis Sliding sleeve 2 9,700' 0.84' 4.5" 3.958" XN Profile Nipple 3 9,747' 1.03' 5.55" Crossover Pressure Head Top of 7" Liner '; Upper 4 9 13.12' 6.75" U @ 1o,o2s' pump p g 5 9,761' 13.12' 6.75" Middle pump Bad csy 6 9,773' 13.73' 6.75" Lower pump 10,328' � 7 9,788' 14.85' 7" Tandem Seals 8 9,802' 27.10' 7 -1/4" Motor Bottom of 7" / ' Top of 4" Slot 9 9,830' 1.87' 4.5" Phoenix XT -1 Sensor Gauge Liner@ 10,434' .4 Aluminum Anode w/ bullnose (I 1 {' 10 9,831' 1.80' 7" cntralizer ' 1 11 10,415 19.0' 8.25" 5.92" 7" Swell Packer 12 11,355' 19.7' 5.3" 3.476" 4" Swell Packer 9 5/8" @ 10,747' L i 1 1; 1 1 = G -5 Top of 1 1 Window in 1 1 7" Liner @ 10,873' 1 1 K -I2RD PERFORATION DATA i I Zone Top Btm Amount Condition 1 1 1 1 G-5 10,826' 10,910' 84 Open in '95. Reperfd 1/02 1 1 1 1 1 1 1 1 1 1 1 1 CE3 ICE] 4" Slotted Liner 1 1 @11,465' 1 1 TD = 11,475' MAX HOLE ANGLE = 42° @ 5800' 9/8//08 CVK Actual Wellpath Geo • raphic Report Report Generated 9/9/2008 at 4:14:00 PM Projection System NAD27 / TM Alaska State Plane, Zone 4 (5004), US feet ' Operator Chevron North Reference True - Area Cook Inlet, Alaska (Offshore) Scale 0.999993 Field McArthur River Field Horizontal Reference Point Slot Facility KING SALMON Platform Vertical Reference Point Actual Datum (RKB) Slot slot #4 -29 MD Reference Point Actual Datum (RKB) Well K -12RD2 Field Vertical Reference mean sea level Wellbore K -12RD2 Actual Datum (RKB) to rkb 100.00 ft Wellpath INC ONLY <10908- 11219 >MWD <10252.48 - 11515> Actual Datum (RKB) to mean sea level 100.00 ft Wellbore Last Revised 08/04/2008 rkb to Mud Line (Facility) 0.00 ft Sidetrack from K -12Rd at 10800.00 MD Section Origin X E 0.00 ft User Ulricard Section Ori • in Y N 0.00 ft Calculation method Minimum curvature Section Azimuth 270.72° Local North Local East Grid East Grid North Latitude Longitude [ft] [ft] [USft] (USft] Slot Location 734.56 - 139.64 213758.36 2511809.14 60 °51'56.025 "N 151°36'21.223'W Facility Reference Pt 213879.98 2511071.39 60 °51'48.792 "N 151 °36'18.403 "W Field Reference Pt 213640.71 2500514.08 60 °50'04.803 "N 151°36'18.018'W TVD from MD Inclination Azimuth 1VO Fld Ref North East Grid East Grid North Latitude Longitude DLS Toolface Build Rate Turn Rate Vert Sect Comments [ft] [°] [°] [ft] [ft] [ft] [ft] [ft] [ft] [° /100ft] [°] [° /100ft] [ ° /100ft] [ft] 0.00 0.00 196.52 0.00 - 100.00 0.00 0.00 213758.36 • 2511809.14 r 60 °51'56.025 "N 151°36'21.223'W 0.00 - 163.48 0.00 0.00 0.00 100.00 0.12 196.52 100.00 0.00 -0.10 -0.03 213758.32 2511809.04 60 °51'56.024 "N 151°36'21.223'W 0.12 -62.58 0.12 0.00 0.03 200.00 0.18 170.22 200.00 100.00 -0.36 -0.03 213758.32 2511808.79 60 °51'56.022 "N 151 °36'21.223'W 0.09 52.13 0.06 -26.30 0.03 300.00 0.65 209.72 300.00 200.00 -1.00 -0.29 213758.04 2511808.14 60 °51'56.016 "N 151°36'21.229'W 0.52 10.00 0.47 39.50 0.27 400.00 0.78 211.40 399.99 299.99 -2.08 -0.92 213757.38 2511807.09 60 °51'56.005 "N 151 °36'21.241'W • 154.39 0.13 1.68 0.90 500.00 0.95 345.00 499.98 399.98 -1.86 -1.49 213756.82 2511807.32 60 °51'56.007"N 151 °36'21.253'W 1.59 51.50 0.17 133.60 1.47 600.00 1.58 8.43 599.96 499.96 0.31 -1.50 213756.86 2511809.48 60 °51'56.028 "N 151 °36'21.253'W 0.80 14.67 0.63 23.43 1.51 700.00 1.62 8.80 699.92 599.92 3.07 -1.09 213757.35 2511812.23 60 °51'56.056 "N 151°36'21.245'W 0.04 -25.94 0.04 0.37 1.13 800.00 2.91 356.95 799.84 699.84 7.00 -1.01 213757.52 2511816.16 60 °5156.094 "N 151°36'21.243'W 1.37 -28.45 1.29 -11.85 1.09 900.00 4.60 346.03 899.62 799.62 13.43 -2.11 213756.58 2511822.61 60 °51'56.158 "N 151°36'21.265'W 1.83 -50.57 1.69 -10.92 2.28 1000.00 6.44 328.91 999.16 899.16 22.12 -5.97 213752.93 2511831.40 60 °51'56.243 "N 151 °36'21.343'W 2.45 -85.41 1.84 -17.12 6.25 1100.00 7.13 307.61 1098.48 998.48 30.71 -13.79 213745.33 2511840.18 60 °5156.328 "N 151°36'21.501'W 2.59 -68.56 0.69 -21.30 14.17 1200.00 8.31 291.98 1197.58 1097.58 37.21 -25.41 213733.87 2511846.96 60 °5156.392 "N 151 °36'21.736"W 2.40 -82.51 1.18 -15.63 25.87 1300.00 9.01 275.49 1296.45 1196.45 40.66 -39.90 213719.46 2511850.77 60 °51'56.426 "N 151 °36'22.029'W 2.57 -44.78 0.70 - 16.49 40.41 1400.00 10.08 269.70 1395.07 1295.07 41.36 -56.45 213702.94 2511851.87 60 °5156.433 "N 151 °36'22.363'W 1.44 -8.45 1.07 - 5.79 56.97 1500.00 11.52 268.63 1493.30 1393.30 41.08 -75.19 213684.20 2511852.05 60 °51'56.430 "N 151 °3622.741'W 1.45 17.19 1.44 -1.07 75.70 1600.00 12.45 269.96 1591.12 1491.12 40.83 -95.95 213663.44 2511852.31 60 °5156.428"N 151 °3623.160"W 0.97 20.16 0.93 1.33 96.46 1700.00 13.61 271.76 1688.54 1588.54 41.19 - 118.49 213640.91 2511853.22 60 °51'56.431 "N 151 °36'23.616'W 1.23 25.44 1.16 1.80 119.00 1800.00 14.97 274.24 1785.45 1685.45 42.50 - 143.13 213616.31 2511855.14 60 °51'56.444 "N 151 °36'24.113"W 1.49 17.45 1.36 2.48 143.65 1900.00 16.19 275.61 1881.77 1781.77 44.82 - 169.89 213589.62 2511858.11 60 °5156.467 "N 151 °3624.653'W 1.27 -43.67 1.22 1.37 170.44 2000.00 18.33 269.41 1977.27 1877.27 46.02 - 199.49 213560.06 2511860.03 60 °51'56.479 "N 151°3625.251'W 2.82 -60.90 2.14 -6.20 200.05 2100.00 20.87 258.35 2071.50 1971.50 42.26 - 232.68 213526.79 2511857.09 60 °5156.442 "N 151 °36'25.921'W 4.49 -42.72 2.54 -11.06 233.19 2200.00 23.17 253.15 2164.21 2064.21 32.96 - 268.96 213490.29 2511848.68 60 °51'56.350 "N 151 °36'26.654'W 3.01 -8.19 2.30 -5.20 269.35 2300.00 25.64 252.33 2255.27 2155.27 20.69 -308.41 213450.55 2511837.37 60 °5156.229 "N 151 °36'27.451'W 2.49 8.13 2.47 -0.82 308.64 • 2400.00 29.87 253.54 2343.74 2243.74 7.06 - 352.92 213405.71 2511824.84 60 °5156.095 "N 151°36'28.350'W 4.27 -5.69 4.23 1.21 352.99 2500.00 33.11 252.95 2429.00 2329.00 - 8.01 -402.93 213355.35 2511811.00 60 °51'55.946 "N 151°3629.359'W 3.25 1.75 3.24 -0.59 402.80 2600.00 35.39 253.07 2511.66 2411.66 - 24.45 -456.75 213301.15 2511795.88 60 °5155.785 "N 151 °36'30.446W 2.28 -17.92 2.28 0.12 456.41 2700.00 36.12 252.67 2592.81 2492.81 -41.66 - 512.59 213244.90 2511780.04 60 °51'55.615 "N 151 °36'31.574"W 0.77 67.70 0.73 -0.40 512.02 2800.00 36.38 253.72 2673.45 2573.45 - 58.76 -569.19 213187.90 2511764.34 60 °51'55.447 "N 151 °36'32.717'W 0.67 105.38 0.26 1.05 568.41 2900.00 36.01 256.16 2754.16 2654.16 -74.10 -626.21 213130.53 2511750.39 60 °51'55.296 "N 151 °3633.868'W 1.49 96.89 -0.37 2.44 625.22 3000.00 35.77 260.85 2835.19 2735.19 -85.79 -683.62 213072.85 2511740.12 60 °51'55.180 "N 151 °36'35.027"W 2.76 91.88 -0.24 4.69 682.48 3100.00 35.75 263.89 2916.34 2816.34 -93.54 - 741.52 213014.77 2511733.78 60 °51'55.104 "N 151°36'36.197'W 1.78 30.25 -0.02 3.04 740.28 3200.00 36.32 264.45 2997.21 2897.21 - 99.52 - 800.05 212956.12 2511729.24 60 °51'55.045 "N 151 °36'37.378'W 0.66 34.42 0.57 0.56 798.73 3300.00 36.74 264.93 3077.56 2977.56 - 105.02 - 859.32 212896.74 2511725.19 60 °51'54.991 "N 151 °36'38.575'W 0.51 -93.43 0.42 0.48 857.92 3400.00 36.70 263.61 3157.72 3057.72 - 110.99 - 918.80 212837.12 2511720.68 60 °51'54.932 "N 151 °36'39.777'W 0.79 31.71 -0.04 -1.32 917.33 3500.00 37.33 264.25 3237.57 3137.57 - 117.36 - 978.67 212777.12 2511715.78 60 °51'54.869 "N 151 °36'40.985'W 0.74 138.99 0.63 0.64 977.11 3600.00 36.89 264.89 3317.32 3217.32 - 123.07 - 1038.73 212716.93 2511711.54 60 °51'54.813 "N 151°36'42.198'W 0.59 -24.31 -0.44 0.64 1037.09 3700.00 37.32 264.57 3397.07 3297.07 - 128.61 - 1098.80 212656.74 2511707.47 60 °51'54.758"N 151°36'43.411'W 0.47 21.50 0.43 -0.32 1097.09 3800.00 37.49 264.68 3476.51 3376.51 - 134.30 - 1159.28 212596.15 2511703.26 60 °51'54.702 "N 151 °36'44.633'W 0.18 14.67 0.17 0.11 1157.49 3900.00 37.63 264.74 3555.78 3455.78 - 139.92 - 1219.98 212535.33 2511699.13 60 °51'54.647 "N 151 °3645.858'W 0.14 - 149.79 0.14 0.06 1218.12 4000.00 37.38 264.50 3635.11 3535.11 - 145.63 - 1280.59 212474.59 2511694.91 60°5154.591"N 151°36'47.082'W 0.29 31.75 -0.25 -0.24 1278.65 4100.00 38.45 265.56 3714.00 3614.00 - 150.94 - 1341.81 212413.26 2511691.09 60 °51'54.538 "N 151 °36'48.318'W 1.25 162.74 1.07 1.06 1339.80 4200.00 38.43 265.57 3792.32 3692.32 - 155.75 - 1403.79 212351.18 2511687.80 60 °51'54.491 "N 151 °36'49.570 "W 0.02 -24.38 -0.02 0.01 1401.72 4300.00 38.54 265.49 3870.60 3770.60 - 160.60 - 1465.84 212289.04 2511684.47 60 °51'54.443 "N 151°3650.823'W 0.12 -22.57 0.11 -0.08 1463.69 4400.00 39.01 265.18 3948.56 3848.56 - 165.70 - 1528.25 212226.52 2511680.91 60 °51'54.393 "N 151 °3652.083'W 0.51 -21.87 0.47 -0.31 1526.04 4500.00 39.31 264.99 4026.10 3926.10 - 171.11 - 1591.17 212163.49 2511677.04 60 °51'54.339 "N 151°36'53.354'W 0.32 91.91 0.30 -0.19 1588.88 4600.00 39.29 266.27 4103.49 4003.49 - 175.93 - 1654.32 212100.24 2511673.76 1 60 °51'54.292 "N 151°3654.629'W 0.81 155.09 -0.02 1.28 1651.97 Page 1 of 3 TVD from MD Inclination Azimuth TVD Fld Ref North East Grid East Grid North Latitude Longitude DLS Toolface Build Rate Turn Rate Vert Sect Comments [ft] [1 [1 [ft] [ft] [ft] [tt] [ft] [ft] [ °I100ft] [°] [° /10 0ft) ['PI00ft] [ft] 4700.00 39.10 266.41 4180.99 4080.99 - 179.97 - 1717.39 212037.09 2511671.27 60 °51'54.252 "N 151°36'55.902'W 0.21 -21.35 -0. 19 0.14 1714.98 . 4800.00 39.54 266.14 4258.35 4158.35 - 184.08 - 1780.62 211973.78 2511668.70 60 °51'54.211 "N 151 °36'57.179'W 0.47 -12.88 0.44 -0.27 1778.15 4900.00 39.82 266.04 4335.31 4235.31 - 188.44 - 1844.32 211909.99 2511665.91 60 °51'54.168 "N 151 °36'58.466'W 0.29 43.70 0.28 -0.10 1841.80 5000.00 40.75 267.39 4411.59 4311.59 - 192.14 - 1908.87 211845.37 2511663.79 60 °51'54.132 "N 151 °36'59.769'W 1.28 26.55 0.93 1.35 1906.29 5100.00 40.96 267.55 4487.23 4387.23 - 195.02 - 1974.22 211779.97 2511662.51 60 °51'54.103 "N 151 °37'01.089'W 0.23 21.02 0.21 0.16 1971.60 5200.00 41.46 267.84 4562.46 4462.46 - 197.67 - 2040.05 211714.10 2511661.47 60 °51'54.077 "N 151 °37'02.418'W 0.54 174.35 0.50 0.29 2037.39 5300.00 40.93 267.92 4637.71 4537.71 - 200.11 - 2105.87 211648.24 2511660.65 60 °51'54.053 "N 151 °37'03.747'W 0.53 66.30 -0.53 0.08 2103.17 5400.00 41.09 268.47 4713.17 4613.17 - 202.18 - 2171.45 211582.62 2511660.19 60 °51'54.033 "N 151 °37'05.071'W 0.39 -32.42 0.16 0.55 2168.73 5500.00 41.87 267.73 4788.09 4688.09 - 204.37 - 2237.65 211516.39 2511659.61 60 °51'54.011 "N 151 °3706.408'W 0.92 107.43 0.78 -0.74 2234.89 5600.00 41.82 267.97 4862.58 4762.58 - 206.88 - 2304.32 211449.69 2511658.74 60 °51'53.986 "N 151 °37'07.754'W 0.17 - 151.06 -0.05 0.24 2301.52 5700.00 41.19 267.44 4937.47 4837.47 - 209.53 - 2370.53 211383.43 2511657.71 60 °51'53.960 "N 151 °37'09.091'W 0.72 -0.82 -0.63 -0.53 2367.70 5800.00 42.61 267.41 5011.90 4911.90 - 212.53 - 2437.24 211316.66 2511656.34 60 °51'53.930 "N 151 °37'10.439'W 1.42 - 164.04 1.42 -0.03 2434.37 5900.00 40.94 266.68 5086.48 4986.48 - 215.96 - 2503.77 211250.07 2511654.54 60 °51'53.896 "N 151 °3711.782W 1.74 123.91 -1.67 -0.73 2500.85 6000.00 40.64 267.37 5162.19 5062.19 - 219.35 - 2569.01 211184.77 2511652.75 60 °51'53.863 "N 151 °37'13.099W 0.54 170.19 -0.30 0.69 2566.04 6100.00 39.25 267.75 5238.85 5138.85 - 222.08 - 2633.16 211120.57 2511651.59 60 °51'53.83614 151 °37'14.396W 1.41 18.06 -1.39 0.38 2630.14 6200.00 39.80 268.03 5315.99 5215.99 - 224.43 - 2696.76 211056.94 2511650.80 60 °51'53.812"N 151 °37'15.679'W 0.58 166.34 0.55 0.28 2693.71 6300.00 38.42 268.57 5393.58 5293.58 - 226.30 - 2759.81 210993.86 2511650.47 60 °51'53.794 "N 151 °37'16.952'W 1.42 173.33 -1.38 0.54 2756.73 6400.00 37.08 268.83 5472.64 5372.64 - 227.69 - 2821.01 210932.64 2511650.58 60 °51'53.780 "N 151 °37'18.188'W 1.35 - 114.39 -1.34 0.26 2817.91 6500.00 37.05 268.72 5552.44 5452.44 - 228.98 - 2881.27 210872.37 2511650.76 60 °51'53.767"N 151 °37'19.405'W 0.07 144.04 -0.03 -0.11 2878.15 6600.00 35.81 270.27 5632.90 5532.90 - 229.52 - 2940.65 210813.00 2511651.68 60 °51'53.762"N 151 °3720.604'W 1.54 7.57 -1.24 1.55 2937.51 6700.00 37.08 270.55 5713.34 5613.34 - 229.09 - 3000.05 210753.63 2511653.56 60 °51'53.766 "N 151 °37'21.803'W 1.28 5.83 1.27 0.28 2996.92 6800.00 38.99 270.86 5792.10 5692.10 - 228.33 -3061.65 210692.06 2511655.83 60 °51'53.773 "N 151 °37'23.047W 1.92 31.51 1.91 0.31 3058.53 6900.00 39.85 271.68 5869.35 5769.35 - 226.92 - 3125.14 210628.63 2511658.80 60 °51'53.787 "N 151 °37'24.329'W 1.01 159.29 0.86 0.82 3122.02 • 7000.00 39.10 272.13 5946.54 5846.54 - 224.81 - 3188.68 210565.16 2511662.47 60 °51'53.807 "N 151 °37'25.612'W 0.80 148.59 -0.75 0.45 3185.58 7100.00 38.50 272.72 6024.47 5924.47 - 222.16 - 3251.28 210502.64 2511666.65 60 °51'53.833 "N 151 °37'26.876'W 0.70 117.04 -0.60 0.59 3248.22 7200.00 38.29 273.39 6102.85 6002.85 - 218.85 - 3313.30 210440.72 2511671.47 60 °51'53.866 "N 151°37'28.129'W 0.47 155.12 -0.21 0.67 3310.27 7300.00 37.16 274.26 6181.94 6081.94 - 214.77 - 3374.35 210379.79 2511677.04 60 °51'53.906 "N 151 °37'29.362'W 1.25 - 114.28 -1.13 0.87 3371.37 7400.00 36.93 273.40 6261.76 6161.76 - 210.75 -3434.46 210319.80 2511682.54 60 °51'53.945 "N 151°37'30.575'W 0.57 39.24 -0.23 -0.86 3431.52 7500.00 37.37 273.99 6341.47 6241.47 - 206.85 - 3494.72 210259.65 2511687.90 60 °51'53.983 "N 151 °37'31.792'W 0.57 142.24 0.44 0.59 3491.83 7600.00 36.80 274.73 6421.24 6321.24 - 202.27 - 3554.84 210199.66 2511693.96 60 °51'54.028 "N 151 °37'33.006'W 0.72 126.92 -0.57 0.74 3552.01 7700.00 36.52 275.36 6501.46 6401.46 - 197.02 - 3614.32 210140.33 2511700.66 60 °51'54.080 "N 151 °37'34.207'W 0.47 -10.56 -0.28 0.63 3611.54 7800.00 37.40 275.09 6581.37 6481.37 - 191.55 -3674.19 210080.61 2511707.60 60 °51'54.134 "N 151 °37'35.417'W 0.89 12.43 0.88 -0.27 3671.48 7900.00 38.10 275.34 6660.43 6560.43 - 185.98 - 3735.16 210019.79 2511714.66 60 °51'54.188 "N 151°37'36.648'W 0.72 63.42 0.70 0.25 3732.52 8000.00 38.47 276.51 6738.93 6638.93 - 179.58 - 3796.78 209958.35 2511722.56 60 °51'54.251 "N 151 °37'37.892'W 0.81 55.92 0.37 1.17 3794.22 8100.00 38.58 276.77 6817.16 6717.16 - 172.38 - 3858.65 209896.67 2511731.27 60 °51'54.322"N 151°37'39.141'W 0.20 34.62 0.11 0.26 3856.17 8200.00 39.13 277.37 6895.04 6795.04 - 164.66 -3920.91 209834.63 2511740.52 60 °51'54.398 "N 151 °37'40.399'W 0.67 , - 175.52 0.55 0.60 3918.52 8300.00 38.03 277.23 6973.21 6873.21 - 156.73 - 3982.76 209772.98 2511749.96 60 °51'54.475 "N 151 °37'41.648'W 1.10 4.77 -1.10 -0.14 3980.47 8400.00 39.01 277.36 7051.45 6951.45 - 148.83 - 4044.54 209711.42 2511759.37 60 °51'54.553 "N 151 °37'42.895'W 0.98 - 167.87 0.98 0.13 4042.34 8500.00 37.05 276.66 7130.21 7030.21 - 141.30 -4105.68 209650.48 2511768.40 60 °51'54.627"N 151 °37'44.130'W 2.01 155.51 -1.96 -0.70 4103.57 8600.00 36.07 277.42 7210.53 7110.53 - 134.00 - 4164.80 209591.57 2511777.14 60 °51'54.699 "N 151 °37'45.324'W 1.08 - 159.19 -0.98 0.76 4162.77 8700.00 35.46 277.02 7291.68 7191.68 - 126.66 -4222.78 209533.78 2511785.90 60 °51'54.771 "N 151 °37'46.495'W 0.65 97.17 -0.61 -0.40 4220.84 8800.00 35.36 278.52 7373.18 7273.18 - 118.82 - 4280.18 209476.58 2511795.14 60 °51'54.848 "N 151 °37'47.654'W 0.87 - 138.93 -0.10 1.50 4278.34 8900.00 31.85 272.49 7456.48 7356.48 - 113.39 -4335.19 209421.72 2511801.92 60 °51'54.901 "N 151 °37'48.765W 4.84 -29.74 -3.51 -6.03 4333.42 9000.00 33.00 271.29 7540.89 7440.89 - 111.63 - 4388.78 209368.20 2511804.99 60 °51'54.918 "N 151 °37'49.847'W 1.32 25.09 1.15 - 1.20 4387.02 9100.00 34.13 272.23 7624.21 7524.21 - 109.92 -4444.04 209313.00 2511808.04 60 °51'54.935 "N 151 "37'50.963'W 1.24 5.41 1.13 0.94 4442.30 9200.00 34.61 272.31 7706.75 7606.75 - 107.69 - 4500.45 209256.66 2511811.66 60 °51'54.956 "N 151 °3752.102'W 0.48 73.89 0.48 0.08 4498.73 9300.00 34.95 274.27 7788.89 7688.89 - 104.41 -4557.39 209199.82 2511816.33 60 °51'54.989 "N 151 °37'53.252'W 1.17 42.05 0.34 1.96 4555.71 9400.00 35.52 275.15 7870.57 7770.57 -99.67 - 4614.89 209142.45 2511822.48 60 °51'55.035 "N 151 °37'54.413'W 0.76 -30.56 0.57 0.88 4613.26 9500.00 36.09 274.58 7951.67 7851.67 -94.71 -4673.18 209084.30 2511828.86 60 °51'55.084 "N 151 °3755.590'W 0.66 43.23 0.57 -0.57 4671.61 • 9600.00 36.75 275.61 8032.14 7932.14 -89.43 -4732.31 209025.32 2511835.59 60 °51'55.135 "N 151 °37'56.784'W 0.90 151.09 0.66 1.03 4730.81 9700.00 35.80 276.51 8112.76 8012.76 - 83.19 - 4791.15 208966.65 2511843.26 60 °51'55.197"N 151 °37'57.972'W 1.09 -24.86 -0.95 0.90 4789.71 9800.00 36.56 275.92 8193.47 8093.47 -76.81 -4849.83 208908.14 2511851.09 60 °51'55.259 "N 151 °37'59.157'W 0.84 88.39 0.76 -0.59 4848.47 9900.00 36.62 278.20 8273.77 8173.77 -69.48 - 4908.98 208849.19 2511859.86 60 °51'55.331 "N 151 °38'00.352'W 1.36 - 158.62 0.06 2.28 4907.71 10000.00 34.42 276.67 8355.16 8255.16 -61.94 -4966.58 208791.79 2511868.80 60 °51'55.405 "N 151 °38'01.515'W 2.37 159.23 -2.20 -1.53 4965.40 10100.00 33.59 277.24 8438.06 8338.06 -55.17 -5022.09 208736.46 2511876.93 60 °51'55.472 "N 151 °38'02.636'W 0.89 103.10 -0.83 0.57 5021.00 _ 10200.00 33.40 278.80 8521.45 8421.45 -47.48 - 5076.74 208682.03 2511885.96 60 °51'55.547 "N 151 °38'03.740'W 0.88 - 137.65 -0.19 1.56 5075.73 10300.00 32.85 277.87 8605.20 8505.20 -39.55 -5130.80 208628.17 2511895.21 60 °51'55.625 "N 151 °38'04.831'W 0.75 106.60 -0.55 -0.93 5129.89 10400.00 32.75 278.50 8689.26 8589.26 -31.84 - 5184.42 208574.76 2511904.23 60 °51'55.701 "N 151 °38'05.914'W 0.36 160.08 -0.10 0.63 5183.61 10500.00 31.75 279.19 8773.83 8673.83 -23.64 -5237.15 208522.25 2511913.72 60 °51'55.781 "N 151 °38'06.979'W 1.07 34.65 -1.00 0.69 5236.43 10600.00 32.23 279.81 8858.64 8758.64 -14.89 -5289.40 208470.23 2511923.74 60 °51'55.867 "N 151 °38'08.034'W 0.58 29.82 0.48 0.62 5288.79 10700.00 33.13 280.75 8942.81 8842.81 -5.25 - 5342.52 208417.35 2511934.68 60 °51'55.962 "N 151 °38'09.107'W 1.03 85.66 0.90 0.94 5342.03 10800.00 33.22 282.59 9026.51 8926.51 5.82 -5396.10 208364.06 2511947.06 60 °51'56.070 "N 151 °38'10.189'W 1.01 169.25 0.09 1.84 5395.75 10868.25 32.02 283.02 9084.00 8984.00 13.97 -5431.98 208328.39 2511956.08 60 °51'56.151 "N 151 °38'10.914'W 1.79 -46.11 -1.76 0.63 5431.72 Top of Whipstock - 10892.25 33.17 280.87 9104.22 9004.22 16.64 - 5444.63 208315.82 2511959.06 60 °51'56.177 "N 151 °38'11.169'W 6.80 - 162.94 4.79 - 8.96 5444.40 Interpolated Azimuth 11020.69 28.95 278.18 9214.22 9114.22 27.69 -5509.94 208250.80 2511971.71 60 °51'56.285 "N 151 °38'12.485W 3.46 -45.80 -3.29 -2.09 5509.85 Interpolated Azimuth 11052.57 29.28 277.49 9242.08 9142.08 29.81 -5525.30 208235.49 2511974.20 60 °51'56.306 "N 151 °38'12.798'W 1.48 -74.05 1.04 -2.16 5525.24 Interpolated Azimuth 11084.30 29.38 276.79 9269.74 9169.74 31.74 - 5540.72 208220.12 2511976.51 60 °51'56.325 "N 151 °3513.110'W 1.13 -55.13 0.32 - 2.21 5540.68 Interpolated Azimuth 11116.07 29.63 276.07 9297.39 9197.39 33.49 -5556.27 208204.62 2511978.64 60 °51'56.342 "N 151 °38'13.424'W 1.37 -72.19 0.79 - 2.27 5556.25 Interpolated Azimuth 11148.78 29.75 275.33 9325.80 9225.80 35.10 -5572.39 208188.54 2511980.65 60 °51'56.358 "N 151°38 1.18 -39.82 0.37 - 2.26 5572.39 Interpolated Azimuth 11179.25 30.18 274.62 9352.20 9252.20 36.42 - 5587.55 208173.42 2511982.34 60 °51'56.371 "N 151 °38'14.056'W 1.83 -72.25 1.41 -2.33 5587.57 Interpolated Azimuth 11212.73 30.31 273.83 9381.12 9281.12 37.66 -5604.37 208156.63 2511983.99 60 °51'56.383 "N 151°38'14.395W 1.25 84.86 0.39 - 2.36 5604.40 First Clean Survey 11244.78 30.38 275.21 9408.78 9308.78 38.94 -5620.51 208140.53 2511985.66 60 °51'56.396 "N 151 °38'14.721'W 2.19 25.00 0.22 4.31 5620.56 Page 2 of 3 TVD from MD Inclination Azimuth TVD Fld Ref North East Grid East Grid North Latitude Longitude DLS Toolface Build Rate Turn Rate Vert Sect Comments [ft] [°] [1 [ft] [ft] [ft] [ft] [ft] [ft] [° /100ft] [°] [ ° /100ft] [ ° /100ft] [ft] 11276.17 30.72 275.52 9435.82 9335.82 40.43 - 5636.40 208124.69 2511987.54 60 ° 51'56.410 "N 151 °38'15.042'W 1.19 - 108.08 1.08 0.99 5636.46 - -- 11307.50 30.55 274.47 9462.77 9362.77 41.82 - 5652.30 208108.82 2511989.32 60 °51'56.424 "N 151 °38'15.363'W 1.79 - 106.76 -0.54 - 3.35 5652.38 11339.25 30.40 273.46 9490.14 9390.14 42.93 - 5668.37 208092.79 2511990.83 60 ° 51'56.435 "N 151 °38'15.687'W 1.68 -55.11 -0.47 - 3.18 5668.46 11371.25 30.60 272.90 9517.71 9417.71 43.83 -5684.58 208076.60 2511992.13 60 °51'56.443 "N 151°38'16.015'W 1.09 -80.73 0.63 - 1.75 5684.68 11402.25 30.70 271.76 9544.38 9444.38 44.48 -5700.37 208060.83 2511993.15 60 ° 5156.450 "N 151°38'16.334'W 1.90 -90.86 0.32 -3.68 5700.48 11433.25 30.70 269.77 9571.04 71.04 44.69 -5716.19 208045.02 2511993.75 60 °51'56.452 "N 151°38'16.653'W 3.28 0.00 0.00 -6.42 5716.30 11475.25 30.70 269.77 9607.15 9507.15 44.60 - 5737.64 208023.58 • 2511994.19 • 60 ° 51'56.451 "N 151 °38'17.086'W 0.00 0.00 0.00 0.00 5737.74 Projected Survey l e • Page 3 of 3 AOGCC 10 -407 filing for K - 12402 Page 1 of 2 Kanyer, Christopher V From: Kanyer, Christopher V Sent: Wednesday, September 17, 2008 1:59 PM To: 'Maunder, Thomas E (DOA)' Cc: Bonnett, Nigel ( Nigel.Bonnett) Subject: RE: AOGCC 10-407 filing for K -12RD2 (208 -088) Through researching the old well files, including plotting the old directional survey data, we have determined there have been some inconsistant data submitted for K -12RD API #50- 733 - 20156 -01 in the Governmental Section. The data submitted for this well should be listed as follows: K -12RD Top of Productive Interval 743'N & 269'W of SE Cr, Sec 18, T9N, R13W, SM TD 688'N & 335'W of SE Cr, Sec 17, T9N, R13W, SM Also note that the Top of Productive Horizon will remain the same for K -12RD2 which will be filed today. We appreciate your patience in this matter. Thanks, Chris Kanyer •• Technical Assistant Wellbore Maintenance Team (907) 263 -7831 Chevron North America Exploration and Production Midcontinent/Alaska SBU 909 W. 9th Avenue Anchorage, AK 99501 -3322 From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Friday, September 12, 2008 10:31 AM To: Kanyer, Christopher V Cc: Bonnett, Nigel (Nigel.Bonnett) Subject: RE: AOGCC 10 -407 filing for K -12RD2 (208 -088) Chris, It is acceptable to delay so the correct information is submitted. As we discussed since that section of the welibore was retained the actual x -y should not have changed. Call or message with any questions. Tom Maunder, PE AOGCC From: Kanyer, Christopher V [mailto:Chris.Kanyer @chevron.com] Sent: Friday, September 12, 2008 10:28 AM To: Maunder, Thomas E (DOA) Cc: Bonnett, Nigel (Nigel.Bonnett) 9/17/2008 AOGCC 10 -407 filing for K -12 Page 2 of 2 Subject: AOGCC 10 -407 filing for K -12RD2 Tom, Over concerns that the location of the K- 12RD2's Top of Productive Horizon is incorrect in the governmental section, I would like to request an extension of the due date, per our conversation, of the 10-407 for K- 12RD2. We would appreciate this time to allow our geologist to ensure the correct information is submitted. Please let me know if you have any questions. Thanks, Chris Kanyer •• Technical Assistant Wellbore Maintenance Team (907) 263 -7831 Chevron North America Exploration and Production Midcontinent/Alaska SBU 909 W. 9th Avenue Anchorage, AK 99501 -3322 9/17/2008 AOGCC 10 -407 filing for K -12RD2 Page 1 of A r • Maunder, Thomas E (DOA) From: Kanyer, Christopher V [Chris.Kanyer @chevron.coml Sent: Friday, September 12, 2008 10:44 AM To: Maunder, Thomas E (DOA) Subject: RE: AOGCC 10-407 filing for K -12RD2 (208 -088) Thank you for your understanding. Chris Kanyer •• Technical Assistant Wellbore Maintenance Team (907) 263 -7831 Chevron North America Exploration and Production Midcontinent/Alaska SBU 909 W. 9th Avenue Anchorage, AK 99501 -3322 From: Maunder, Thomas E (DOA) [mailto :tom.maunder @alaska.gov] Sent: Friday, September 12, 2008 10:31 AM To: Kanyer, Christopher V Cc: Bonnett, Nigel ( Nigel.Bonnett) Subject: RE: AOGCC 10 -407 filing for K -12RD2 (208 -088) Chris, It is acceptable to delay so the correct information is submitted. As we discussed since that section of the wellbore was retained the actual x -y should not have changed. Call or message with any questions. Tom Maunder, PE AOGCC From: Kanyer, Christopher V [mailto:Chris.Kanyer @chevron.com] Sent: Friday, September 12, 2008 10:28 AM To: Maunder, Thomas E (DOA) Cc: Bonnett, Nigel (Nigel.Bonnett) Subject: AOGCC 10 -407 filing for K -12RD2 Tom, Over concerns that the location of the K- 12RD2's Top of Productive Horizon is incorrect in the governmental section, I would like to request an extension of the due date, per our conversation, of the 10-407 for K- 12RD2. We would appreciate this time to allow our geologist to ensure the correct information is submitted. Please let me know if ou have any questions. Y Yq Thanks, 9/12/2008 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg (P.I. Supervisor) �� viZb /0 DATE: August 21, 2008 Petroleum Engineer I 1 THRU: SUBJECT: No Flow test TBU K -12RD2 PTD 208 -088 King Salmon Platform FROM: Lou Grimaldi Trading Bay Field Petroleum Inspector I witnessed a No -Flow test on Chevron's well TBU K -12RD2 aboard the King Salmon platform. The test went well with no fluid produced to surface and the gas flow so low as to be immeasurable. A new 60 psi gauge with 1 psi increments and a Erdco flow meter with a span of 180 scf to 1800 scf were used. I ran a shut -in and bleed sequence one time with results noted below. I looked over the downhole pressures (Phoenix gauge) / which showed negligible buildup over the previous 14 hours. I concluded the test at this time. The well appears to meet no -flow criteria. Copies of the Phoenix data are attached. Attachments: K12.jpg; K- 12pic2.jpg Time Pressure (psi) Flow Rate Comments 0845 0 0 Open to atmosphere, no flow present 0900 0 None Shut -in well. 0930 0 0 Shut -in for build up. 1000 0 0 Shut -in for build up. Open to atmosphere, slight puff of gas. Bled to no -flow in less than 1 1130 0 0 Open well to atmosphere Pagel of 1 2008- 0821_No -Flow TBU_K- 12_Ig.xls 8/26/2008 No Flow TeAugust st 21 — TBU K -12 Witnessed by AOGCC Insp, 2008 ector Lou Grimaldi . Snapshot of Operator screen for monitoring ESP performance (downhole pressure gauge) Start: August 19, 2008; 1638 firs August 21, 2008; 1038 hrs K- 1 q ' R V abie.Speed Drive Au 09 A g 20 0t19 20 ; A a r aA 21 gd'y Ixu.ao, 16#88122 08708 22 18; 08122 00109722 70108 Fy 19 • owar Factor 0 E K Va, Drve:I nrormei orb ( eed Demand ,-; . , 16A1 ;� Motor Volts 0 Y � otel urrent . 0 A etor T orque, �u " (� iX srr' ue Curren; Q a - '^w �12gnotizing Current t1 A Q � 1 Uutput Powl I . kW!. l SCI,ut+f 1 rwz � 54 t p Ph lx Dowtlhale.t ' D ech rge Per 64 pc Dlecharge pressure 328 sl - : p t n -u .k ? s ere 17, 7� F' 1 Q.,I a ' -r* n IW 1Vib - 1o0 551 g ��i' � 1o� i r Current Le tr t el0 ; niA, . ' 1 hr�12 � Zaom n I : ; - id " ieh { 1 . <;22oom + . 6 • 4tou kt}aar tui E sg �amvuies` 1 lam es urrece Preesure O'pci r tuttt � tcaIAm M q l2p Mdkrr np ' 7t ohal �ttf 7 RdbK12P Dl itgPsi R2bK1 WU hia e i . elf r A 4°14/11.4'1' K -12 Dr STOPPE 0 H 4 h +SP- iA k 1 1 r r Hi t� Al t 1# i I( p1 e t (.., 70:35;35 W OIIhea U 2 Room flame Bypass Status , i H619218•STAT J DSC FCP_79US21FIameByp Bypassed ACK 09121 A. .0 u i �[i7 r FCP_74US27FIameByp... �: ..t �7 : , 0 1 pg 2 comp rea s ttr -o0m orne : pass .tutus H° 4 1 -.9 r r r °�. , .: 011 `Pipeline 1 9 limn - Re ea opm ame ypass a s r a �fa i mtli r� � c 1 L'i L as • r a.. =� a ttfuar►t� � Lr7i�L aL'l L I C Lt3�3� Su as �rocess �oom Gas =Pass r gas: r C''. _ r p r gas ' 19 Aak Rst E au Alamta Gas A C Flaw Well. E Se OSP Tr eated Gross e1 39.4O A W ■Girder •Tic 4P P Home 1 a �a ep7 Rst Test Water 011 E Girder lk. ; Are 8 G as ' Proceas K 8 P 08 1 1 h . No Flow Test - TBU K -12 Witnessed by AOGCC Inspector Lou Grimaldi August 21, 2008 Snapshot of Operator screen for monitoring ESP performance (downhole pressure gauge) Start: August 20, 2008; 2026 hrs Stop: August 21, 2008; 1037 hrs K Robison Vail Ie Speed,Dflve Aye' 20.; Aug 20 Aug 21 Aye 21 AV ,.27' giv. ho a M°rm.9 A 20 00 36. '23:82:13 0 831 51i 0Tr0423 10:67!06` :. • w °r Fa 0 { Drive Inforittation Sppeed Demenl 7& 0 Motor Volte 0`v r Total Current 0 A '. Motor Torque 0 00 I io rtiue Current (1'1S n MIgn51i ing1 mart i } Y�(A(Q � fSCi, Output Power G k 4 fri.10 Tel kc Phoenix Downhole Information "t' + t 3 ; L.' In t ak e Preseure ,3265 ps1 Dlecharge Pressure 3265 ps In take Temperature 17. T ° F, ` r IuiotorTeinpereture 1724 W ! i l: i f o6 C _ - vibration O 011 9. . 1911 RM •• •,. t Leakage O'' ttiA_ , , i . 2 0 �02 6 ° > ' i '. { zoom in I4H 10m 3bs tZoom Out ,, , ie. 1 46 ` y. 0 Fa I _ _ 4h I 1r'wr 1 ' 1 „ r h � mi t 10 mr 4 �s .,. . 1.. ' . . ,: Rob T ala INnps RobKi 1x AMotmj inp' Rob(12 r or g Cur Su rtaee Tu Pressure 'toil: . . ............... R66K10HX DI,th of s R6bK12PHX Pumpinfak 7 � K -12 Drive, TOP1 E'D 0.0 Hz F y S Sgy}j , � �y y cu I i � i { r Y .2,..1$1,,,"'''.','. 1 ( d K.19 5' f, ., , ,Fl , 1( $ 41Cilit�, 'ryf ,.rn.4 :t 1 10:35:36 Wellhead 2 Room Flame Bypass Status I HS192 -STAT 1 DSC FCP 19U32tFlameByp. Bypassed ACK 08121 A - SI'tu, / a eg? ry ry Ll i i � bWe llh ea drrramrx to rrnaF atus I "1 "IS-ST . 1— � a_ rI :V *T'''� � �:1�_37Y3� V / 9 ft - 2,-- �1'plm;17. d lrmr> :rmrr :m.r. swm :��evuoa• � .. r r O II I ip 153 r *e ea -00m lama pass a us,. �Cel'J6iL16w11yHTidd d+� L Ii ! E IDIOM R • - r r II . . ■.l9\nS:�� IICtMbrt � J • vas •rocese - oom as Bypass r as: p 1 I: a 'e' " ' lift Get; 1319 Eqp AR Alarms Gas '' 2S AC Flow Well ESPY Sep OSP Treated Gross Home 04:At ` W. j Rst Test t(SsaP�+aM Water 011 ti Fire „ Gas Wocess B ' :Girder 11‘,.„: 2 King Salmon BOP test • Page 1 of 2 • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, July 25, 2008 10:19 AM To: Newell, Jack R [FEP] Subject: FW: King Salmon BOP test - K12RD2 (208 -088) Jack, Here is the note Jim Regg sent to Nick Eaton regarding the 14 day BOP test. Call or message with any questions. Tom Maunder, PE AOGCC From: Regg, James B (DOA) ( ) Sent: Friday, July 25, 2008 10:17 AM To: Maunder, Thomas E (DOA) Subject: FW: King Salmon BOP test Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 From: Regg, James B (DOA) Sent: Friday, July 11, 2008 11:18 AM To: EATON, NICK G Cc: DOA AOGCC Prudhoe Bay Subject: RE: King Salmon BOP test Follow -up to phone conversation with Joe Bothner this morning I understand Chevron will be testing BOPE early (today) while waiting on fishing tools. I waived AOGCC witness of the BOPE test; send report per normal procedure. Also for clarity, you may begin testing BOPE at intervals not exceeding 14 days once you have milled the window for the sidetrack of K -12RD. Thank you for the notice. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 From: EATON, NICK G [mailto:NICK.EATON @chevron.com) Sent: Friday, July 11, 2008 8:19 AM To: jim.regg @alaksa.gov Subject: King Salmon BOP test 7/25/2008 King Salmon BOP test Page 2 of 2 Jim, We have contacted Jeff Jones about our BOP test that is due on the 13th. We have run into problems and left a whipstock in the hole that we are attempting to fish and would like to test the BOP soon as we are waiting on fishing tools. Please give us (Joe Bothner or I) a call here on the King Salmon at 907 - 776 -6698. Nick Eaton • • Drilling and Completions Anchorage, AK 7/25/2008 IP • Z AT] iF SARAH PALIN, GOVERNOR AsEn ALASKA. OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Timothy Brandenburg Drilling Manager UNOCAL PO Box 196247 Anchorage, AK 99519 Re: McArthur River Field, Hemlock /G Oil Pool, K -12RD2 UNOCAL Permit No: 208 -088 Surface Location: 735' N & 140' W of SE Cr, SEC. 17, T9N, R13W, SM Bottomhole Location: 780' N & 604' W of SE Cr, SEC. 18, T9N R13W, SM Dear Mr. Brandenburg: Enclosed is the approved application for permit to redrill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). incerely, Daniel T. Seamount, Jr. Chair DATED this , day of July, 2008 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. II rL.e. lad 1..:1 V Li STATE OF ALASKA - 1( MAY 2 9 2008 ALA OIL AND GAS CONSERVATION CO M ION PERMIT TO DRILL Alaska Oil & Gas Cons. Commisv. 20 AAC 25.005 Anchorage ! la. Type of Work: i 1b. Current Well Class: Exploratory ❑ Development Oil . 0 1c. Specify if well is proposed for: Drill ❑ Redrill 01 Stratigraphic Test ❑ Service ❑ Development Gas ❑ Coalbed Methane ❑ Gas Hydrates ❑ Re -entry ❑ Multiple Zone ❑ Single Zone ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket 0 Single Well ❑ 11. Well Name and Number: Union Oil Company of California Bond No. 5534278 King Salmon K -12RD2 3. Address: 6. Proposed Depth: 12. Field /Pool(s): P.O. Box 196247, Anchorage, AK 99519 MD: 11448' TVD: 9571' McArthur River Field 4a. Location of Well (Govemmental Section): 7. Property Designation: Hemlock Pool Surface: 735' N & 140' W of SE Cr, Sec. 17, T9N, R13W SM ADL- 18777, Cook Inlet Basin Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 532' N & 392' W of SE Cr, Sec 18, T9N, R13W SM N/A 7/20/2008 Total Depth: 9. Acres in Property: 14. Distance to Nearest 780' N & 604' W of SE Cr, Sec 18, T9N, R13W SM 1902 Property: 10090' 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation D s � 15. Distance to Nearest Well Surface: x- 213758 y- 2511809.1 Zoi ASP4 (Height above GL): Al. Within Pool: 2200' K -18 16. Deviated wells: Kickoff depth: 11000' feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 43 degrees Downhole: 3400 ' Surface: 2443 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 8 -1/2" 7" Liner 29# L -80 IBTC 300' 10100' 8438' 10400' 8689' 5 -3/4" 4" Liner 9.5# L -80 IBTC 1045' 10400' 8689' 11445' 9570' 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 11,775' 9867' 10' 11,419 9606' N/A Casing Length Size Cement Volume MD TVD 1 Conductor /Structural 393' 24" 393' 393' Surface 2510' 13 -3/8" 1500 sxs 2510' 2436' Intermediate Production 10747' 9 -5/8" 1000 sxs 10747' 8973' Liner 1278' 7" 350 sxs 11765' 9859' Perforation Depth MD (ft): 10826' - 11,400' Perforation Depth TVD (ft): 20. Attachments: Filing Fee ❑ BOP Sketch el Drilling Program 0 Time v. Depth Plot ❑ Shallow Hazard Analysis 0 Property Plat a Diverter Sketch El Seabed Report ❑ Drilling Fluid Program el 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Steve Alexander Printed Name 'I othy C. Brandenburg Title Drilling Manager Signat - ! A Er i r E „,A ,,,,L J r - Phone (907) 276 -7600 Date 5/28/2008 Commission Use Only Permit to Drill API Number: / Permit Approval See cover letter for other Number: 227 - e:)58 50- 733 - Z4/ s —o ate: r] • / 1 . 0 R requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:' Other: \-2710 Samples req'd: Yes❑ ' No E r Mud log req'd: Yes Nog -v- ">- H measures: YesE No ❑ Directional svy req'd: Yes E✓ No // APPROVED BY THE COMMISSION 7/ AK DATE: - / , COMMISSIONER Form 10-401 Revised 12/2 OR1 G1NAL f ubmit in Duplicate G I NA L ,,,e 7.7 7-/. c.)8. �IMM. • • Chevron Timothy C Brandenburg Union Oil Company of California 14011 Drilling Manager P.O. Box 196427 Anchorage, AK 99519 -6247 %. Tel 907 263 7657 Fax 907 263 7884 Email brandenburgt @chevron.com ■ May 19, 2008 RECEIVED Commissioner MAY 2 7 2008 Alaska Oil & Gas Conservation Commission Alaska • 333 W. 7 Avenue 011 & Gas c s y Anchorage, Alaska 99501 Anchorage 0mmission Re: Application for Permit to Drill (Form 10 -401) McArthur River Field King Salmon Platform, Well K -12RD2 Dear Commissioner, Enclosed is an Application to Drill (Form 10 -401) for King Salmon Well # K- 12RD2. The objective is a short 450' side track within the productive 7" liner just above a stuck clean out assembly. K -12RD2 will consist of approximately 450' of 5 -5/8" hole drilled with Oil base mud and completed with an un- cemented 4" slotted liner. The OBM liquid waste and ground cuttings will be disposed of at our Bruce Platform G &I well 3 -87. Upon completion the well will be returned to production with ESP lift equipment as in the past. The expected spud date for K -12RD2 is July 15, 2008. Please review and approve the Application for Sundry Approvals at your earliest convenience. Please contact Steve Alexander at 907 - 263 -7880 if you have any questions Sincerely, ,),_ 2 r C ` Timothy C. Brandenburg Drilling Manager Attachments Union Oil Company of California / A Chevron Company Page 1 of 1 _/ Chevron • King Salmon Platform 11110 K -12RD2 %.1 Side track Revision #0 5/14/08 OBJECTIVE: • Set Whip stock at 11,000', side track drill with OBM to 11,445' run slotted 4" liner from 10800' to TD • Return well to production from G -5 to Hemlock B -6 intervals. PROCEDURE SUMMARY: • Continue on from K -12RD Abandonment Pro ra with BOPS Equipment in Place and tested to 3000/250 psi. + rc d�c . iyvl / c • Displace hole to 9.2 ppg Mud and Mill wi dow off 7" Whipstock at 11,000' + - . • POOH and M/U 5 -3/4" BHA. RIH and drill 20' of new 5 -3/4" Hole off. Pull up inside casing and conduct a LOT. Note: We will not exceed a 9.7 ppg FIT. • Continue to drill 5 -3/4" hole to TD at — 11,445' with 9.2 +/- oil base mud. • At TD, 11,445' condition the hole for running the liner, and spot base oil if hole conditions good for completion liner ESP • Redress BOP's and test 250/3500 for ESP run. • Pick up 700' pre slotted 4" 10.9 # L -80 BTC liner RIH landing at 10,800' + - (noting option for upper 7" liner if not prey. ran) Note: if upper casing above 10132' (pits from Caliper log 7/07) tests at an acceptable FIT, a 300' 7" liner section with swell packer hanger and the 4" slotted liner will be ran together in one run. • Release liner change well over to completion fluid, POOH laying down DP • RIH w/ replacement ESP assembly similar to the current failed completion with new 4'/2" Tbg. • Install BPV. R/D CUDD HWOU. N/D BOPE. N/U & test tree. • Install flow line and surface facilities & turn well over to Production. Turn platform cathodic protection back on. • Startup ESP as per separate startup procedure and confirm that ESP is functioning properly. K -12RD2 Side track (deep) REVISED BY: SLA 5/14/08 Chevron III • Trading Bay Unit K ing Salmon Well No. K -12RD %. Proposed Abandonment CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. RKB to TBG Head = 33.80' 24" Surf 394' Tree connection: 13 -3/8" 61.0 K -55 12.515 38' 2,510' 9 -5/8" 47 N -80 & S95 BTC /LTC 8.681 38' 10,747' 24" @ 394' 7" Liner 38 P -110 LTC 5.920 10,487' 11,765' . Tubing: 13 3/8" @ 2,510' TOC @9300' y' Fish Details Bad csg Item OD ID Length 1 0,328' Junk Mill 5 3 /" 1 -1/4" 2.75 7 " Liner Junk Basket 4 –'/8" 1 –'h" 3.64 @ 1 0,487' Junk Basket 4?/8" 1 -1/4" 3.63 9 5/8" @ 10,747' A y Bit sub 4 3 /" 1 -1/4" 2.81 Double Pin Sub 4 3 /" 1 -1/4" 0.86 ElE G - String mill 5 3 /" 2" 5.53 r Casing Whipstock @ Bumper Sub 4 3 /" 2" 7.86 .iir - 11,000' Oil Jar 4 3 /" 2" 11.05 Bridge ; Plug _ rill Collars 4 5/8 2 –%" 30.64 — B -1 Drill Collars 4 5/8 2 –' /2" 30.82 Drill Collars 4 3/4 2 –' /" 31.01 B -2 Drill Collars 4 5/8 2 –'h" 30.98 F 1s077' Screw -in sub 4 - 2- 11/16" 3.36 To JIMEL 11,241' _ B - 3 PERFORATION DATA Zone Top Btm Amount Condition G -5 10,826' 10,910' 84 Open in '95. Reperfd 1/02 = B -4 HB -1 11,037' 11,057' 20 Open in '78. Reperfd 1/02 HB -2 11,070' 11,175' 105 Open in '78. Reperfd 1/02 HB -3 11,175' 11,200' 25 Open in '78. Reperfd 1/02 HB -4 11,216' 11,236' 20 Open in '78. Reperfd 1/02 = B HB -5 11,310' 11,330' 20 Open in '78. Reperfd 1/02 HB -6 11,372' 11,402' 30 Open in '78. Reperfd 1/02 HB -6 11,424' 11,444' 20 Open in '78. = B Attempt isolation 1/02 ?os�Set Plug @ 11,429' Rotating Hours: .v/ TOC 11,419' ,'l'51,''' "'?';'i;''s;ii i ii; f ' „,'i @ 24” Casing – 17.5 hrs 13 -3/8" Casing – 755 hrs 9 -5/8" Casing – 126 hrs 7" Casing – 19 hrs PBTD = 11,641' TD = 11,775' MAX HOLE ANGLE = 42° @ 5800' 09/13/07 CRW Chevron • • Trading Bay Unit King Salmon Well No. K -12RD2 %. Proposed Completion CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. RKB to TBG Head = 33.80' 13 -3/8" 61.0 K -55 12.515 38' 2,510' Tree connection: 9 -5/8" 47 N -80 & S95 BTC /LTC 8.681 38' 10,747' 1 7" Liner 38 P -110 LTC 5.920 10,100' 10,487' D 4" Slot. Liner 10.9 L -80 IBTC 10,487' 11,445 Tubing: D 4 -1/2" 12.6 N -80 BTC 3.958 35 9,985' 2,51� I D D D 1l D 0 D TOC 9300' D D 2 1 1 r 3 : I 10,100' - Csg pits 10132- 10328 Swell Pkr 10,487' - \ A 10,747' ma a G-5 1 1 1 \\\\- PERFORATION DATA \ \\ \\ Zone Top Btm Amount Condition CIBP \ G -5 10,826' 10,910' 84 Open in '95. Reperfd 1/02 11,010'Md ••■ HB -1 11,037' 11,057' 20 4" Liner slotted 3/16" x 2" B -1 HB -2 11,070' 11,175' 105 4" Liner slotted 3/16" x 2" HB -3 11,175' 11,200' 25 4" Liner slotted 3/16" x 2" B -2 1 1 HB -4 11,216' 11,236' 20 4" Liner slotted 3/16" x 2" B -3 HB -5 11,310' 11,330' 20 4" Liner slotted 3/16" x 2" B -4 HB -6 11,372' 11,402' 30 4" Liner slotted 3/16" x 2" HB -6 11,424' 11,444' 20 4" Liner slotted 3/16" x 2" B -5 B °osi-Set Plug @ 11,4 ,F-y w/ TOC @ 11,419' �S 11,445' PBTD = 12,170' TD = 12,250' MAX HOLE ANGLE = 42° @ 5800' K12RD2 Proposed.doc8 BY: LWB • • s Kin g Salmon K12RD BOP Stack To of Rota Table • Btm of Trolly beam f 13 5/8" Hydril 5M 3.9' — 16.00' / 13 5/8" Shaffer 5m DBL Gate Upper Pipe Rams 2.8' J / 1 Blind Rams Studded Connections J _ 1 L 13 5/8" 5M T — F .1.1 cXT Mud.Cross 1 Silo) E 1 Top of drill deck y A 2 1/16" 5M HCR Valve 13 5/8" 5M B 2 1/16" 5M Manual gate valve Riser C 2 1/16" 5M Manual gate Kill line D 2 1/16" 5M Manual gate Kill line E 3 1/8" 5M Target Tee — 12.50' F 2 1/16" 5M Target Tee G 13 5/8" 5M x 11" 5M DSA G H 11" 5M x 13 5/8" 3M CIW DCB TH 1 H 1 13 5/8 3M x 13 5/8 5M DSA I I J 135/8" 5M x 13 5/8" 5M # 13 Hub / \ Top of CIW DBS \ \anc909ntdfs2\ share \IQ�aVA013154db Ra\ Depts \Drilli�q \Users\Alexande�lKinq saTatbifigifitiglAillaobaBoP TEST INFO\ inq BOP Stack 5/21/2008 xis JAR • • Ch� 207000 208500 210000 211500 213000 N N o _ 0 500 1000 Oft 'v 0 g yry o cv 1:14000 N - _ .,::K -26 N fT S K 6RD b Lo - N , ,K -22PB \ \., \ T r a ding Bay Unit Boundary $ o l 1 K -22 N r o Ina \ 1 N- N t • 7itki2 K-12 44 King .0.K-18R DP 1 / $ 0 0 / N �— / / D / / - m $ o ,n , K / - 0 o K 01 R D A ,--•".-- G -1 RD -03 _ -03RD / N N / i K -08 0 c 1 e -15 ° N 208500 210000 211500 213000 207000 l . .. • 1 Chevron Planned Wellpath Report BA KER E 1%10. K -12RD2 Version #2 N1�GH Page 1 of 5 TNTEQ REFERENCE WELLPATH IDENTIFICATION Operator'Chevron Slot slot #4 -29 Area jCook Inlet, Alaska (Offshore) Well K -12RD2 Field McArthur River Field Wellbore K -12RD2 {Facility ;KING SALMON Platform Sidetrack fromK -12Rd at 11000.00 MD REPORT SETUP INFORMATION ;Projection System INAD27 / TM Alaska State Plane, Zone 4 (5004), US feet [Software System WellArchitect® 2.0 North Reference True User Ulricard Scale 10.999993 _Report Generated 15/13/2008 at 12:08:06 PM 1 Convergence at slot f 1.40° West ;Database /Source file WA_Anchorage/K -12RD2 .xml WELLPATH LOCATION Local coordinates ! Grid coordinates 1 Geographic coordinates North[ft] i East[ft] i Easting[USft] Northing[USft] Latitude r Longitude 1 Slot Location ; 734.56 - 139.64 1 213758.36 2511809.14 , 60 °51'56.025 "N T 151 °36'21.223 "W Facility Reference Pt s 213879 98 251107139 j 60°51'48.792"N ' 151 °36'18.403 "W Field Reference Pt ; 1 213640.71 2500514.08 3 60 °50'04.803 "N I 151 °36'18.018 "W WELLPATH DATUM ;Calculation method Minimum curvature 'Actual Datum (RKB) to rkb 100.00ft Horizontal Reference Pt SE Corner of Sec. 17, T9N, R13W SM 'Actual Datum (RKB) to mean sea level 1100.00ft {Vertical Reference Pt Actual Datum (RKB) rkb to Mud Line (Facility) '0.00ft {MD Reference Pt Actual Datum (RKB) Section Origin N 734.56, E - 139.64 ft 'Field Vertical Reference mean sea level Section Azimuth 270.45° • • Chevron Planned Wellpath Report BA KER K -12RD2 Version #2 HU Page 2 of 5 INTEQ REFERENCE WELLPATH IDENTIFICATION Operator 'Chevron 'Slot slot #4 -29 Area Cook Inlet, Alaska (Offshore) Well K -12RD2 Field ,McArthur River Field Wellbore K -12RD2 Facility KING SALMON Platform Sidetrack from K -12Rd at 11000.00 MD WELLPATH DATA (118 stations) MD Inclination Azimuth TVD TVD from Vert Sect North East Grid East 1 Grid North DLS [ft] [ 1 [ft] Fld Vert Ref [ft] 1 [ft] ( [f] [sry 8] 1 [sry ft] [ ° /100ft] [a] 7 4. 0.00 0.000 196.520 0.00 - 100.00 0.00 734.56 - 139.64 213758.36 2511809.14 0.00 100.00. 0.120 196.520 100.00 0.00 0.03 734.46 - 139.67 213758.32 2511809.04 0.12 200.00 T 0.180 170.220 200.00 100.00 0.03 73420 - 139.67 213758.32 251180839 ' 0.09 300.00 ' 0.650 209.720 300.00 200.00 0.28 733.56 - 139.93 213758.04 r 2511808.14 0.52 400.00 0.780 211.400 399.99 299.99 0.91 732.48 , r; t 0 . 213757.38 2511807.04, t 500.00 0.950 345.000 499.98 399.98 1.48 732.70 - 141.13 1 213756.82 2511807.32 1.59 600.00 1.580 8.430 599.96 499.96 1.51 734.87 - 141.14 ' 213756.86 2511809.48 0.80 700.00 1.620 8.800 699.92 599.92 1.11 737.63 - 140.73 213757.35 2511812.23 0.04 800.00 2.910 356.950 799.84 699.84 1.06 741.56 - 140.65 213757.52 2511816.16 1.37 900.00 4.600 346.030 899.62 799.62 2.21 747.99 - 141.75 213756.58 2511822.61 1.83 1000.00 6.440 328.910 999.16 899.16 6.15 756.68 - 145.61 213752.93 , 2511831.40 , 2.45 1100.00 I 7.130 307.610 1098.48 998.48 14.03 76527 I - 153.43 1 213745.33 2511840.18 2.59 1200.00 8.310 291.980 1197.58 1097.58 25.70 771.771 - 165.05 213733.87 2511846.96 2.40 1300.00 9.010 275.490 1296.45 1196.45 40.22 775.22 179.54 213719.46 2511850.77 2.57 1400.00 10.080 269.700 1395.07 1295.07 56.78 775.93 - 196.09 21371 " , ., 2511851,8' 144 1500.00 11.520 268.630 1493.30 _ 1393.30 75.51 775.64 - 214.82 213684.20 r 2511852.05 1.45 1 1600.00 12.450 269.960 1591.12 1491.12 96.27 775.39 - 235.59 213663.44 251185231 0.97 1700.00 13.610 271.760 1688.54 1588.54 118.81 775.75 -258.13 213640.91 1 2511853.22' 1.23 1800.00 14.970 274.240 1785.45 1685.45 143.46 777.07 - 282.77 213616.31 2511855.14 1.49 1900.00 16.190 275.610 1881.77 1781.77 17023 779.38 - 309.52 213589.62_. 2000.00 ' 18.3301 269.410; 1977.27 1877.27 199.85 780.59 - 339.13 ' 213560.06 2511860.03 2.82 2100.00 1 20 8701 258 3501 2071.50 1971.50 233.00 776.83 -372.31 213526.79 2511857.09 4.49 2200.00 23.170 253.150 2164.21 2064.21 269.21 767.52 - 408.60 213490.29 2511848.68 3.01 2300.00 25.640 252.330 2255.27 2155.27 308.56 755.25 - 448.05 213450.55 2511837.37 2.49 2400.00 29.870 253.540 2343.74 2243.74 352.97 741.62 -492.56 213405.71 2511824.84 4,27 2500.00 33.110 252.950 2429.00 2329.00 402.85 726.56 - 542.57 213355.35 2511811.00 3.25 2600.00 35.390' 253.0701 2511.66 2411.66 456.54 710.11 - 596.39 213301.15 ' 2511795.88 2.28 2700.00 36.120, 252.670 2592.81 2492.81 512.24 692.90 -652.23 , 213244.90 2511780.04 0.77 2800.00 36.380 253.720 2673.45 2573.45 568.71 675.81 - 708.84 7 213187.90 2511764.34 7' 0.67 2900.00 36.010 256.160 2754.16 2654.16 625.60 660.46 - 765.85 ., 213130.53 ° 251175634' 1.49 3000.00 35.770 260.850 2835.19 2735.19 682.92 648.78 - 823.26 213072.85 , 2511740.12 2.76 3100.00 35.750 263.890 2916.34 2816.34 740.76 641.03 - 881.16 213014.77 2511733.78 178 3200.00 36.320 264.450 2997.21 2897.21 799.23 635.05 - 939.69 212956.12 2511729.24 0.66 3300.00 36.740 264.930 3077.56 2977.56 858.46 629.55 - 998.96 212896.74 2511725.19 0.51 3400.00 36.700 263.610 3157.72 3057.72 917.90 623.58 - 1058.45 t 212837.1 2511720.6 0.79' 3500.00 37.330 264.250 3237.57 3137.57 977.71 617.22 - 1118.31 212777.12 2511715.78 1 0.74 3600.00 36.890' 264.890 3317.32 3217.32 1037.72 611.51 - 1178.37 ; 212716.93 2511711.54 r 0.59 3700.00 37.320 264.570 3397.07 3297.07 1097.75 605.96 , - 1238.44 j 212656.74 2511707.47 0.47 3800.00 37.490 264.680 3476.51 3376.51 1158.18 600.28 -1298.92 1 212596.15 251170326 0.18 3900.00 37.631c 264340 3555.78 3455.78 1218.83 594.66 - 1359.62 ' '- 212535 '. 251 f7 ' . 0. ' 4000.00 37.380 264.500 3635.11 3535.11 1279.40 588.95 -1420.24 i 212474.59 2511694 91 0.29 4100.00 38.450 265.560 3714.00 3614.00 1340.57 583.63 - 1481.45 212413.26 2511691.09 1 1.25 4200.00 38.430 265.570 3792.32 3692.32 I 1402.52 578.83 - 1543.44 212351.18 2511687.80 0.02 4300.00 38.540 265.490 3870.60 3770.60 1464.52 573.98 - 1605.48 `'` 212289.04 2511684.47 0.12 4400.00 39.010 265.180 3948.56 3848.56 1526.90 568.88 - 1667.90 212226.52 2, 68d` • • Chevron Planned Wellpath Report BA K -12RD2 Version #2 HUGHES Page 3 of INTEQ REFERENCE WELLPATH IDENTIFICATION Operator Chevron Slot ,slot #4 - Area Cook Inlet, Alaska (Offshore) Well ! K -12RD2 Field McArthur River Field Wellbore K -12RD2 Facility KING SALMON Platform Sidetrack from K - 12Rd at 11000.00 MD WELLPATH DATA (118 stations) MD Inclination Azimuth TVD TVD from Vert Sect North East Grid East Grid North DLS [ft] 11 11 [ft] Fld Vert Ref [ft] [ft] [ft] [sry ft] [sry ft] [ °/100ft] [ft] 4500.00 39.310 264.990 4026.10 3926.10 1589.77 563.47 - 1730.81 212163.49 I 2511677.04 0.32 P 4600.00 39.290 266.270 4103.49 4003.49 1652.88 558.65 - 1793.96 212100.24 ' 2511673.76 0.81 4700.00 39.100 266.410 4180.99 4080.99 1715.91 554.61 - 1857.03 212037.09 2511671.27 0.21 4800.00 39.540 266.140 4258.35 4158.35 1779.11 550.50 - 1920.26 211973.78 2511668.70 0.47 4900.00 39.820 266.040 4335.31 4235.31 1842.77 546.14 - 1983.96 211909.99 L , 2511665.91 029 5000.00 40.7501 267.390 4411.59 4311.59 1907.29 542.45 - 2048.51 211845.37 2511663.79 1.28` I 5100.00 40.960 267.550 4487.23 4387.23 1972.62 539.561- 2113.86 211779.97 2511662.51 0.23 5200.00 41.460 267.840 4562.46 4462.46 2038.42 536.91 - 2179.69 211714.10 I 2511661.47 0.54 5300.00 40.930 267.920 4637.71 4537.71 2104.22 534.48 - 2245.51 211648.24 2511660.65 0.53 5400.00 41.090 268.470 4713.17 4613.17 2169.79 532.41 - 2311.10 211582.62 W1660.19 0.39 5500.00 41.870 267.730 4788.09 4688.09 2235.96 530.21 - 2377.29 211516.39 2511659.61 0.92 5600.00 41.820 267.970 4862.58 4762.58 2302.61 527.71 - 2443.96 211449.69 2511658.74 - 0.17 5700.00 41.190 267.440 4937.47 4837.47 2368.80 525.06 - 2510.17 211383.43 2511657.71 0.72 5800.00 42.610 267.410 5011.90 4911.90 2435.49 522.06 - 2576.89 211316.66 2511656.34 1.42 5900.00 40.940 266.680 5086.48 4986.48 2501.99 518.63 - 2643.42 211250.07 2511654.54 1.74 6000.00 40.640 267.370 5162.19 5062.19 2567.20 515.24 - 2708.66 211184.77 2511652.75 1 0.54 6100.00 39.250 267.750, 5238.85 5138.85 2631.32 512.51 - 2772.80 211120.57 2511651.59 1.41 6200.00 39.8001 268.0301 5315.99 � 5215.99 2694.90 510.17 - 2836.40 211056.94 2511650.80 0.58 6300.00 38.420 268.570 5393.58 5293.58 2757.93 508.29 - 2899.45 210993.86 2511650.47 1.42 6400.00 37.080 268.830 5472.64 5372.64 2819.12 506.90 - 2960.65 210932.64 2511650.58 1.35 6500.00 37.050 268.720 5552.44 5452.44 2879.37 505.61 - 3020.91 210872.37 L 2511650.76 0.07 6600.00 35.810 270.270 5632.90 5532.90 2938.74 505.08 - 3080.29 210813.00 I 2511651.68 1.54 6700.00 37.080 270.550 5713.34 5613.34 2998.14 505.51 - 3139.69 , 210753.63 2511653.56 1.28 6800.00 38.990 270.860 5792.10 5692.10 3059.75 506.27 - 3201.30 210692.06 2511655.83 1.92 w. 6900.00 39.850 271.680 5869.35 5769.35 3123.24 507.68 - 3264.78 ,; 210628.63 2511658.80 1.01 I 7000.00 39.100 272.130 5946.54 5846.54 3186.80 509.79 - 3328.32 210565 2511662.47 0.80 E 7100.00 38.5001 272.720 6024.47 5924.47 3249.42 512.44 - 3390.92 , 210502.64 2511666.65 0.70 7200.00 38.2901 273.390 6102.85 6002.85 3311.46 515.75 - 3452.94 210440.721 2511671.47 0.47 ..... -.... 7300.00 37.160 274.260 6181.94 6081.94 3372.54 519.83 - 3513.99 210379.79 2511677.04 1.25 7400.00 36.930 273.400 6261.76 6161.76 3432.68 523.86 - 3574.10 210319.80 2511682.54 0.57 7500.00 37.370 273.990 6341.47 6241.47 3492.97 527.75 - 3634 210259.65 2511687.90 0.57 7600.00 36.800 274.730 6421.24 6321.24 3553.13 532.33 - 3694.49 1 210199.66 1 2511693.96 0.72 7700.00 36.520 275.360 6501.46 6401.46 3612.65 537.58 - 3753.96 210140.33 2511700.66 0.47 7800.00 37.400 275.090 6581.37 6481.37 3672.56 543.06 - 3813.84 210080.61 2511707.60 0.89 7900.00 38.100 275.340 6660.43 6560.43 3733.57 548.62 - 3874.80 ,,,- 210019.79 „ 2511714.66 0.72 8000.00 38.470 276.510 6738.93 6638.93 3795.25 555.02 - 3936.43 209958.35 2511722.56 0.81 sM 8100.00 38.580 276.770' 681716 6717.16 3857.17 562.23 - 3998.29 209896.67 2511731.27 0.20 i 8200.00 39.130 277.370 6895.04 6795.04 3919.48 569.95 ' -4060.55 ; 209834.63 ! 2511740.52 0.67 1. 8300.00 38.030 277.230 6973.21 6873.21 3981.40 577.87 4122.41 209772.98 ( 2511749.96 1.10 8400.00 39.010 277.360 7051.45 6951.45 404323 585.78 41, ? • - 0,„..... W -, 51175937 0.98 8500.00 37.050 276.660 7130.21 7030.21 4104.43 593.31 -4245.321 209650.48 2511768.40 2.01 8600.00 36.070 277.420 7210.53 7110.53 4163.61 600.61 4304.44 1 209591.57 2511777.14 1.08 8700.00 35.460 277.020 7291.68 7191.68 4221.64 607.96 4362.42 209533.78 2511785.90 0.65 8800.00 35.360 278.520 7373.18 7273.18 4279.11 615.79 - 4419.83 209476.58 1 2511795.14 0.87 ' i 8900.00 31,850 272.490 7456 7356.48 4334.16_ 62123 4474$4 < 20. 4 251180 4 84 Chevron Planned Wellpath Report BA R 11000 K -12RD2 Version #2 HUGHES Page 4 of 5 INTEQ REFERENCE WELLPATH IDENTIFICATION !Operator Chevron Slot slot #4 -29 Area Cook Inlet, Alaska (Offshore) Well K -12RD2 Field McArthur River Field rWellbore 'K -12RD2 Facility KING SALMON Platform Sidetrack from K -12Rd at 11000.00 MD WELLPATH DATA (118 stations) �' = interpolated /extrapolated station MD Inclination Azimuth TVD TVD from Vert Sect North East Grid East Grid North DLS [ft] [ °1 [ °1 [ft] Fld Vert Ref [ft] [ft] I [ft] [sry ft] [sry ft] [ °/100ft] - 9000.00 33.000 [ 271.2907540.89 7440.89 4387.76 622.99 - 4528.42 209368.20 2511804.99 1.32 9100.00 34.130, 272.230 7624.21 7524.21 4443.03 624.69 ! - 4583.68 209313.00 2511808.04 1.24 9200.00 34.610 272.310 7706.75 7606.75 4499.46 626.93 ' -4640.09 ' 209256.66 2511811.66 0.48 - 9300.00 34.950 274.270 7788.89 7688.89 4556.42 630.21 - 4697.03 209199.82 2511816.33 1.17 9400.00 35.520 275.150 7870.57 7770.57 4613.95 634.95 - 4754.53 209142.45 511822.48 0.76 W 9500.00 36.090 274.580 7951.67 7851.67 4672.28 639.91 j 4812.82 209084.30 i 2511828.86 0.66 1 9600.00 36.750 275.610,, 8032.14 7932.14 4731.46 645.18 1 - 4 871.95 209025.32 2511835.59 0.90 9700.00 35.800 276.5101 8112.76 8012.76 4790.34 651.43 - - 4930.79 208966.65 2511843.26 1.09 9800.00 36.560 275.920 8193.47 8093.47 4849.07 657.82 - 4989.47 208908.14 2511851.09 0.84 a '1 lat 36.620 278.200 8273.77 8173.77 4908.27 665.14 - 5048.62 208849.19.. 2511859.86 1.36 10000.00 34.420 276.670 8355.16 8255.16 4965.93 672.68 - 5106.22 208791.79 2511868.80 2.37 10100.00 33.590 277.240 8438.06 8338.06 5021.50 679.45 - 5161.73 208736.46 2511876.93 j 0.89 10200.00 33.400 278.800 8521.45 8421.45 5076.20 687.15 - 5216.38 208682.03 1 2511885.96 r 0.88 10300.00 32.850 277.870' 8605.20 8505.20 5130.33 695.07 - 5270.44 208628.17 ! 2511895.21' 0.75 00.00 32.750 278.500 8689.26 858926 5184.01 702.79 - 5324.06 208574.76 2511904.23 0.36 10500.00 31.7501 279.190; 8773.83 8673.83 5236.80 710.99 - 5376.79 208522.25 2511913.72 1.07 L 10600.00 32.230 279.810 8858.64 8758.64 5289.11 719.73 5429.04 208470.23 2511923.74 0.58 ----1--- T 208417.35 2511934.68 1.03 10700.00 33.130 280.750• 8942.81 8842.81 5342.31 729.37 5482.16 10800.00 33.220 282.590 9026.51 8926.51 5395.98 740.44 - 5535.75 208364.06 2511947.06 1.01 10900.00 31.460 283.230 9111.00 9011.00 5448.22 752.39 - 5587.89 208312.23 2511960.27 1.79 11000.00 31.700 285.850 9196.20 9096.20 5499.00 765.54 - 5638.57 208261.88 2511974.66 0.00 11020.00 33.573 282.543 9213.04 9113.04 5509.47 768.17 - 5649.02 208251.50 2511977.55 12.93 11100.001 33.373 278.206 9279.78 ' 9179.78 5552.91 776.12 - 5692.40 208208.33 2511986.55 3.00 i 11200.001 33.338 272.748 9363.33 9263.33 5607.63 781.36 - 5747.08 208153.79 2511993.14 3.00 M 1127023 33.455 268.926 9421.96 9321.96 5646.27 781.93 - 5785.71 208115.18 2511994.64 3. 11300.001 33.4551 268.926 9446.80 9346.80 5662.68 781.62 - 5802.12 208098,77 2511994.74 0.00 - 11400.0011 33.455' 268.926 9530.24 9430.24 5717.79 780.59 - 5857.24 208043.64 2511995.06 0.00 11448.86 ' 33.455- 268.926 9571.00 9471.00 5744.71 780.08 - 5884.17 208016.71 2511995.21 0.001 HOLE & CASING SECTIONS Ref Wellbore: K - 12RD2 Ref Wellpath: K - 12RD2 Version #2 String/Diameter Start MD End MD Interval Start TVD End TVD ' Start N/S Start E/W End N/S End E/W [ft] j [ft] [ft] [ft] [ft] [ft] [ft] i [ft] - [ft] �24in Conductor 0.00 394.00 394.00 0.00 393.99 734.56 - 139.64 732.551 -140.52 13.375in Casing Surface 0.00! 2510.00 2510.00 0.00 2437.37 734.56 -139.641 724.951 - 547.81 9.625in Casing Intermediate 0.00 10699.91! 10699.91 0.00 8942.74 734.56 - 139.64 7 9.37 - 5482.11 5.75in Open Hole 11000.00 11448.86, 448.86 9196.20 9571.00E 765.54, - 5638.571 780.08 - 5884.17 • • Chevron Planned Wellpath Report BA 1 %100 K -12RD2 Version #2 HUGHES Page 5 of 5 INTEQ REFERENCE WELLPATH IDENTIFICATION ,Operator Chevron Slot slot #4 -29 Area Cook Inlet, Alaska (Offshore) Well K -12RD2 Field ;McArthur River Field 1 Wellbore K -12RD2 Facility KING SALMON Platform Sidetrack from!K -12Rd at 11000.00 MD TARGETS Name MD ! TVD North East Grid East Grid North I Latitude Longitude I Shape [ft] ! [ft] [ft] [ft] ; [sry ft] [sry ft] L 1 K -12RD2 Target TD 12 May j 11448 86 i, 'FY., _ - . FP :2008) !SURVEY PROGRAM RefWellbore: K -12RD2 Ref Wellpath: K -12RD2 Version #2 Start MD End MD Positional Uncertainty Model i Log Name /Comment Wellbore [ft] [ft] 0.00 11000.00 Level Rotor Gyro (Standard) 1K - 12Rd 11000.001 11448.86NaviTrak (Magcorrl) 1K Chevron Mill 11 1110 1 C h evron BAKER Location: Cook Inlet, Alaska (Offshore Slot: slot #4-29 HUGHES 1111110 Field: McArthur River Field Well: K -12RD2 INTEQ F acility: KING SALMON Platform Wellbore: K -12RD2 Plot reference wellpath is K -12RD2 Version #2 Well Profile Data True vertical depths are referenced to Actual Datum (RKB) Grid System: NA027 / TM Alaska State Plane, Zone 4 (5004), US feet Design Comment MD (ft) Inc (°) Az ( °) TVD (ft) Local N (ft) Local E (ft) DLS (° /1000) VS (ft) Measured depths are referenced to Actual Datum (RKB) North Reference: True north Tie On 11000.00 31.700 285.850 9196.20 30.91 - 5498.93 0.00 5499.00 Actual Datum (RKB) to mean sea level 100 feet Scale: True distance End of 3D Arc 11020.00 33.573 282.543 9213.04 33.55 - 5509.38 12.93 5509.47 mean sea level to Mud line (Facility, KING SALMON Platform): 0 feet Depths are in feet End of 3D Arc 11270.23 33.455 268.926 9421.96 47.30 - 5646.07 3.00 5646.27 i Coordinates are in feet referenced to Slot Created by ulricard on 5/1312008 End of Tangent 11448.86 33.455 268.926 9571.00 45.45 - 5744.53 0.00 5744.71 III Sales inch =3WM1 Easting (ft) C3 - 6300 -6000 -5700 -5400 -5100 S CP ti V 96 300 CZ 9000 in 03 0 ,(`�\>� p p ',. K - 12Rd u C i co t 9300 - c \ 30 OCN P� 3 0P \ 'i's K -12RD2 p� o z IT m a 0E X30 �,p �� ao 0 III 1 2 �� O 9600 K -12RD2 Target TD (12 May 2008) , K -12RD2 f- -300 J- 9900 '1-- .-600 a 5100 5400 5700 6000 6300 Vertical Section (ft) soak inch =3001t Azimuth 270.45° with reference 0.00 N, 0.00 E • • 1%. Chevron Maximum Anticipated Surface Pressure Calculation King Salmon platform Well K -12RD2 Cook Inlet, Alaska Assumptions: 1. Based on offset well test data, the pore pressure gradient is predicted to be a 0.355 psi /ft gradient from surface to planned total depth at 9571' TVD RKB. 2. The M.A.S.P. during drilling operations will be governed by the 7" shoe frac gradient, and is calculated based on a full column of gas between the TD and the surface. M.A.S.P. While Drilling 5 -5/8" hole at 9,571' TVD: Max. pore pressure at T.D. = 9,571 ft. x 0.355 psi /ft = 3400 psi Max. Est. Frac pressure at KOP = 9196 ft. x 0.810 psi /ft = 7449 psi M.A.S.P. during drilling = 3400 psi - (0.1 psi /ft x 9571 ft.) = = 2443 psi Page 1 of 3 • • Maunder, Thomas E (DOA) From: Alexander, Steve [TVVT] [Steve.Alexander @ chevron.com] Sent: Friday, June 27, 2008 3:23 PM To: Maunder, Thomas E (DOA) Cc: Harness, Evan; Hammons, Darrell; Buster, Larry W Subject: RE: K -12RD (178 -057) Attachments: K12RD2 ST Water Base Mud 6 -21 -08 v2 (2).doc Tom, we are going to have to make a change on K12RD2 mud system from our proposed Oil Base Mud system to the attached Water Base Mud system. We have started the rig up on K12RD for the permitted abandonment of the lower section of the hole and will be preparing the well for the drilling operations once permitted. The Air permit is anticipated by July 8th and I would like to inquire as to the status of the Permit to drill application Dated 5/28/08. Would we not receive this until we receive our Drilling permit, or was there any questions on this application. I have returned Steve Davies call, but have not been able to catch him this week. Please let us know if you need anything else and I will follow up this email with a call to you. Regards Steve Alexander 907 - 263 -7880 From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Thursday, May 29, 2008 11:43 AM To: Buster, Larry W Cc: Alexander, Steve ETWl']; Walsh, Chantal [ Petrotechnical]; Hammons, Darrell Subject: RE: K -12RD (178 -057) Larry, et al, Thanks much. Tom Maunder, PE AOGCC From: Buster, Larry W [mailto:LBuster @chevron.com] Sent: Thursday, May 29, 2008 11:38 AM To: Maunder, Thomas E (DOA) Cc: Alexander, Steve [TWT]; Walsh, Chantal [Petrotechnical]; Hammons, Darrell Subject: RE: K -12RD (178 -057) Tom, Thanks. Also, on the current King Salmon work, we are running 2 -7/8" x 5 -1/2" VBR's in the top and blind /shears in the bottom of our double gate. Regards, Larry Larry W. Buster Drilling Engineering Manager 7/1/2008 • • Halliburton BAROID Chevron Mud rogram n IjAP,010 Chevron K12RD2 i Platform Baroid Mud Program Halliburton Baroid Name (Printed) Signature Date Originator Dave Higbie Reviewed by Dave Higbie Customer Approval Steve Alexander Version No: Date: 2.0 June 21,2008 K12RD2 1 6/21/08 • • Halliburton BAROID Chevron Mud Program K12RD2 Introduction: The following mud program was prepared for a sidetrack of the K12RD2 well on the King Salmon platform. The 2 7/8' kill string with gas lift valves are to be pulled and laid out. Due to the limitations of the CUDD HWU a deep whip stock is to be set within the Hemlock producing intervals. The objective is to side track around the stuck clean out assembly from 11,077' to 11,241 placing a new 4" slotted line in the open hole from the window at 11,000' to a TD of 11,449'. Seawater will be used to kill and decomplete the well. Prior to milling the window in the 7" liner, the 9 5/8" casing above the TOL of the 7" liner will be pressure tested, and possibly scabbed with an inner 7" liner from the TOL (10487' to 10,100'). The well will be displaced to a new Clayseal /KCI /GEM, 9.0 ppg fluid and a 449' sidetrack section will be drilled with a steerable BHA assembly in a 5 3 /4" hole. A pre slotted 4" liner will be run and landed to 11,449' MD with in the Hemlock B -2 through the B -6 intervals. Primary Drilling Obiectives: • Zero fluid related HSE incidents • Maintain well control at all times • Achieve wellbore stability • Achieve good hole cleaning considering hole angle, geometry and anticipated ROP rates • Lost circulation mitigation /control • Achieve good Zonal Isolation as per plan • Achieve minimal formation damage • Minimize fluids related NPT • Minimize drilling wastes Critical Fluid Issues: • Maintain well control • Eliminating /controlling losses. • Maintaining a low ECD in the production zone to reduce risk of lost returns. • Maintaining a stable wellbore through coal seams. Well Specifics: Casing Program MD ND Footage 9 5/8" casing 10487 10487 7" liner (KOP @ 11,000" MD) 11,000' 9196 513 5 3/4" hole (4" liner sloted liner) 11,449' 9571 449 K12RD2 2 6/21/08 • • Halliburton BAROID Chevron Mud Program Production Interval: (5 3 /4" hole, 4" Liner) to 11,449' MD Mud Type: 2% KCI, Clayseal, GEM Mud Properties Density Viscosity PV YP API FL pH Milling 9.0 55 -65 12 -22 25 -30 <5 8.5 -9.5 11,000' — 9.0 — 9.1 45 -60 12 -22 13 - <5 8.5 -9.5 11,449'TD 21 • Additional mud weight may be required for effective coal or shale stabilization. System Formulation: 2% KCI, Clayseal, GEM Product Concentration Water 0.905 bbl KCI 7 ppb (9K chlorides) Caustic 0.2 ppb (9 pH) Barazan D 1.0 ppb (as required 18 YP) Dextrid 1 -2 ppb PAC L 1 ppb Clayseal 4 ppb (initial 1 ppb) Aldacide G 0.1 ppb GEM GP 1.5% by volume Baroid /Baracarbs 1:1 ratio as needed for 9.0 ppg Special Mixing Instructions: • Mix in order as listed • Add polymers slowly to minimize fisheyes. • If possible use fresh water for initial mix and maintenance. This allows lubricants to be added without deleterious reactions. Production Interval (5 3 /4" hole, 4" liner to 11,449' MD) Mud Type: 9.0 ppg KCl/ Clayseal/ GEM System. 1. Mud weight: Maintain the density at 9.0 ppg or as needed; use solids control and whole mud dilution. Increase density as required for hole stability /coal sloughing. Maximize solids control usage. 2. Rheology: While milling maintain a 25 -30 YP then allow the YP to drift back to between 13 and 21. Pump high viscosity or Barolift sweeps throughout the interval as needed, particularly prior to POH for casing. Optimized mud rheology and flow rate will be the primary mechanisms for achieving hole cleaning in this deviated wellbore. Maximize pipe rotation (ideally > 60 RPM). 3. Other issues: The use of good drilling practices to minimize excessive swab and surge pressure should be employed to minimize the chances for losses and differential sticking. Operations Summary: It is recommended to use magnets at the shakers /flowline while milling. Barolift sweeps have proven very effective with metal shavings and are recommended. Sweeps with .25 ppb of Barolift can be pumped after milling operations are completed to help ensure a clean wellbore. K12RD2 3 6/21/08 • i Halliburton BAROID Chevron Mud Program After milling is completed, begin drilling with the KCI based fluid. Baracarb 5, 25 and /or 50 should be strung into the system at 4 -8 sx/hr for wellbore strengthening. The Clayseal concentration should be 1 ppb in the initial mix. As the mud shears, slowly raise the Clayseal concentration to its full 4 ppb concentration. BARAZAN -D should be used to maintain rheological parameters. Maintain the mud as clean as possible while drilling. Should sweeps be required a high viscosity sweep is recommended. Sweep Formulation: 25 bbl of mud with -1 ppb of Barazan D added. Dextrid and PAC L should be used for filtrate control ( <5cc range). If required, 2 ppb Barotrol should be added to help control coals and shales. While drilling, monitor the torque and drag to determine if liquid lubricant is required. If so, approval from town will be required prior to additions of lubricants. Additions of Condet are recommended to reduce the incidence of bit balling and shaker blinding when penetrating high -clay content sections. Maintain the pH in the 8.5 - 9.5 range with caustic soda. Daily additions of Aldacide G / X -Cide 207 should be made to control bacterial action. GEM GP should be maintained at 1.5% by volume. Do not exceed 3% Or of GEM GP. Maintain Cl- in the 8 -9K range with KCI. Reduce system YP as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Consider spotting a Steelseal /Baracarb LCM pill prior to running the casing if losses have been seen in this interval. Suggested Drilling Parameters Pump rate and drill string rotation should be optimized through the real -time use of the DFG software for the actual ROP while drilling. The table below highlights the maximum ROP recommendations above which hole cleaning will become an issue. Maximum Acceptable ROP in fph at Specified GPM and RPM GPM---> 150 200 250 40 RPM 97 123 149 60 rpm 145 162 175 Baroid recommends a flowrate in the 250 -300 gpm range to maximize solids - control efficiency while still maintaining good hole cleaning capabilities at elevated penetration rates. Pump rates above 300 gpm cause a sharp increase in ECD and should be avoided. ROP rates above these levels or with no (sliding) or low rpm will require an increased frequency of the following remedial hole cleaning practices: • wiper trips • back reaming • extended periods of circulation (with maximum pipe rpm, targeting > 60 rpm) • hole cleaning sweeps (change flow regime of base mud by using fibers, density or rheology for carrying capacity) • connection practices - employing extended gpm, rpm and back reaming during the connection Sweeps Two alternate types of hole cleaning sweeps can be used: • Increase the sweep density with barite to 2 ppg over system density. • To reduce the density /viscosity build up in the system, sweeps can be built by adding 0.25 ppb BAROLIFT. The fibrous BAROLIFT will be removed at the shakers. Check with MWD personnel to ensure no plugging of tools will occur. Note: Properly size all sweeps for 300 - 400 ft of annular coverage K12RD2 4 6/21/08 • • Halliburton BAROID Chevron Mud Program Supplement the hole cleaning of the drilling fluid as dictated by hole cleaning indications. Monitor all sweeps pumped and report on their effectiveness. Maximize drill pipe rotation at high rates on a frequent basis (particularly during connections) to assist in disturbing any potential cuttings accumulations down - hole. The objective of the sweep is to change the flow characteristics / carrying capacity that are inherent with the mud system. Select sweep type accordingly. Coal Drilling The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The hole stability risks when drilling coal seams are often high, and the fluid design and drilling operations have been optimized to combine reduced risk with reduced costs. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. • Increase fluid density as required to control the running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL /AK 70 pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss (based on ECD values using the DFG software). System density increases can also be employed in increments of 0.5 ppg. Solids Control Equipment Maximize the use of all solids control equipment to ensure that the solids content of the system is kept to a minimum during this interval. 1. Run the shale shakers with as fine a screen size as possible. • Size shakers screens with coarse mesh initially • Adjust screen size as solids loading, mud rheology and flowrates allow • Inspect the shakers frequently, taking time to repair / replace damaged screens Running Casing / Cementing Preparation Monitor hole fill /returns closely while running the liner to insure losses haven't occurred. Refer to Baroid's DFG+ program if calculated surge /swab values are needed. Production Hole - Hazards / Concerns: • Optimize solids control equipment to minimize colloidal solids build up and dilution requirements. • Maintain flow profile based on PV, YP and tau flow parameters. • Pump sweeps as required to enhance hole - cleaning efforts. Monitor the effectiveness of any sweeps pumped. No sweeps have been needed in this hole section to date. • Follow the hole cleaning guidelines to assist in drilling parameter selection. Use connections for high RPM and pump rate support when these parameters are limited during drilling operations. • Follow the coal drilling guidelines. Estimated Fluid Costs: P10 P50 P90 Decomplete 1,000 4,000 8,000 5 3 /4" Production 68,000 100,000 240,000 Total $69,000 $104,000 $248,000 K12RD2 5 6/21/08 • • Halliburton BAROID Chevron Mud Program Losses Chevron Lost Circulation Decision Tree fl Payzone Mud Systems + + + Partial Seepage 2040 bbllhr Severe Total 5.20 bbllhr Static Static 60 -200 bbllhr Static > 200 bbllhr Static V V Treat Active System Treat Active System + + • with 5 sxlhr Baracarb with 10 sx/hr Baracarb 160 -150 bbl/hr Static 1 150 -200 bbl/hr Static' I Drill Across Fault 50/150 150 4, + + Drill Across Fault I I Drill Across Fault Pump reverse gunk squeeze pill to allow i nami Dynamic 100 ppb L + IMud Pill: + POH (Volume to be Losses < 15 Yes determined based bbllhr Losses < 15 Y 1 20 ppb Baroseal f P ump reverse l bbl/hr 20 ppb Baracarb 50 gunk squeeze pill upon losses 30 ppb Barofibre to allow POH V Drill Ahead Drill Ahead 20 ppb SteelSeal (Volume to be Contact Drilling No 10 ppb Baracarb 150 i No determined based Engineer or Engineer Increase Treatment to v • upon losses) on call 10 sxlhr Baracarb 50/ 50 ppb LCMIMud Pill: Contact Drilling Engineer or r---- 150 Engineer "On Call" i 20 bbls Base mud • 10 ppb Baracarb 25 Contact Drilling Engineer 20 ppb Baracarb 50 or Engineer on call Dynamic y 20 ppb Baracarb 150 • Losses < 15 Yes Plan to pump a second bbllhr 50-80 bbl reverse gunk Drill Ahead • squeeze pill if massive No losses continue. Pump reverse Consider cement I I 20 ppb LCMIMud Pill: namic gunk squeeze pill plugback contingency Losses < 20 Yes (Volume to be 20 bbls base mud bbllhr 4, determined based 10 ppb Baracarb 50 Drill Ahead upon losses 10 ppb Baracarb 150 No , ■ i Contact the Engineer 1)Chevron must approve any steps past PARTIAL losses. , on call to determine if 2) Drill across fault or loss zone 1.5 - 2.0 times the length of the additional LCM throw before spotting reverse gunk squeeze pills. Dynamic additional PBL sub should be run in BHA to spot pills if 'Partial Loss' cases or Losses < 15 Yes treatments are to be j above are anticipated prior to drilling to allow the spotting of LCM bbllhr made or to proceed to pills. reverse gunk squeeze a) LCM pill volume = 30O-600' column based upon actual hole Drill Ahead pill diameter. 5)PRIOR TO ANY LCM PILL, APPROPRIATE DISCUSSIONS AT No I THE RIG MUST BE MADE TO MINIMIZE THE POTENTIAL FOR V PLUGGING THE DRILL STRING. Proceed to 'Partial Losses' Pill K12RD2 6 6/21/08 • Halliburton BAROID Chevron Mud Program Gunks (WBM) Description The basic system forms a fairly soft plug. The addition of cement produces a firmer set which can withstand differential pressure and has a longer lifetime — this is known as DOB2C. Essentially the gunk treatment involves mixing bentonite, bentonite /polymer, or bentonite /cement powder blends into an oil such as diesel. This mixture is pumped down the drill pipe whilst water based mud is pumped down the annulus. When the two streams meet, a thick gunk (gel) is formed as the bentonite or other additives hydrate. This is then squeezed into the formation. The hardness of the gunk depends on the relative pump rates and the concentration of the pill (as well as the pill type). Typically the mud and pill would be pumped at similar rates and the pill would contain around 200- 400ppb bentonite. In some situations environmental regulations may preclude the use of diesel oil. Low toxicity oils such as synthetic oils may be used in place of diesel but should be tested in the laboratory first. A cement unit is used for displacing the gunk squeeze. The pumping unit displaces the mixture down the drill string and the mud pump pumps fluid down the annulus. The slurry reacts with water so that precautions to keep water from prematurely contacting the slurry are needed. An oil spacer is pumped in front of and behind the pill. Benefits: • Temperature is not very important • Soft set avoids sidetracking problems (easy to wash /drill out) • Slurry will pass through most BHAs • Procedures are well established • Suited to large fractures /voids Limitations: • Placement — need to generate gunk in the right place • Flow rate and mix is important to achieve suitable consistency • Suitable experience required • Avoid premature mud contamination • Possible environmental restrictions dealing with oily returns • Effect can be short-lived due to softness of the plug (simple gunk) • May not work with high salt muds ( >50,000 mg /I chlorides) Gel Gunk Squeeze Procedure Formulation —1 barrel • 0.7 bbl Diesel • 400 lbs bentonite (density is approx. 10 lb /gal) Mixing Procedure Mix in a cementing batch tank, not in the pits 0 Ensure the cement unit, batch tank and all associated pipework is completely drained and then flushed through with diesel 0 Add the bentonite to the diesel. Preferably add the bentonite through a mixing jet (not directly into the tank) to avoid lumps. 0 If the mixture becomes too thick to add the required quantity of bentonite, stop mixing and use the slurry as it is. 0 Test the gunk by mixing a sample of it 50/50 with the mud. Check the quality - it should be a consistency similar to chewing gum within 30 seconds. NOTE: If a highly inhibitive Mud does K12RD2 7 6/21/08 • S Halliburton BAROID Chevron Mud Program not allow the Gunk Squeeze to hydrate, then Freshwater, not the Mud, should be used to pump down the annulus AND to displace the Diesel Spacer - Gunk Squeeze- Diesel Spacer combination in the drill pipe. See below procedure. Suggested Procedure 1. Place the bit about 50 -60' above the loss zone. 2. Line up mud pumps to pump simultaneously down the drillpipe and annulus. 3. Line up cement unit to pump down the drillpipe. 4. With the cement unit pump 10 bbls diesel followed by 40 +/- bbls gunk and a further 10 bbls diesel, down the drillpipe. 5. Displace with the mud pump until diesel at the bit. Close annular. 6. Pump at 5 bpm down the drillpipe and 10 bpm down the annulus (use freshwater, if mud is too inhibitive) simultaneously until half of the gunk is out of the bit. 7. Pump at 5 bpm simultaneously down both the drillpipe and annulus until the gunk has been over displaced from the drillpipe by 5 bbls. 8. Squeeze gunk into the loss zone. Leave at least 5 bbls gunk inside the wellbore to prevent over - displacement. Try to establish a shut -in pressure at the end. 9. If successful, leave the gunk to firm up for 30 minutes prior to washing out. Comments The gunk pill is inert until it is mixed with water or water based mud. IT MUST ONLY CONTACT WATER BASED FLUIDS AS IT EXITS THE BIT. The purpose of initially pumping down the annulus at twice the rate down the pipe is to initially produce a slower reacting product that can penetrate the formation more easily. The last part of the gunk is mixed 50/50 and plugs the loss zone quickly. These flow rates are designed to get the gunk to the loss zone quickly after the gunk has been mixed with the mud (or fresh water). The progress of the job should be determined and monitored by the volume of displacement mud pumped down the drillpipe. DOB2C (DIESEL OIL BENTONITE 2 CEMENT) PRODUCT INFORMATION AND APPLICATION DOB2C is a gel cement slurry that is mixed in diesel oil. It is typically used to cure severe loss circulation situations. DOB2C when contacted by water or a water base mud, will react, releasing the diesel and hydrating the cement. This reaction begins - 1 min after mixing. The degree and rate of reaction depends on how much water mixes with the DOB2C. SAFETY PRECAUTIONS Diesel Oil Slurries should be mixed w/ adequate ventilation. The equipment used to mix the slurry must meet requirements to handle combustible materials. Review the MSDS for the slurry components and wear the proper PPE. Variations on this system which use alternative oils to diesel are possible but would require pilot testing. MIXING PROCEDURE 1. Mixing on location in a cement batch mixer. 2. Blend the required Cement and Bentonite at the bulk plant, if possible. Load this blend into a cement bulk truck. 3. To assure fluid integrity and avoid potential incompatibility situations all mixing and pumping equipment must be free of water. Circulate the batch mixer with warm diesel and isolate that material for use ahead and behind the DOB2C. 4. Measure the required volume of diesel fuel into the mixer. K12RD2 8 6/21/08 • • Halliburton BAROID Chevron Mud Program 5. Begin weighting up the diesel with the Bentonite cement blend. 6. One barrel of DOB2C is made up as follows: • 0.7 bbls Diesel Fuel (Arctic Diesel, #4 Diesel Oil (Mapco) or Mineral Oil) • 150 - 200 lbs of Bentonite • 150 - 200 lbs of Class G cement 7. Confirm the final density with a pressurized mud balance. 8. Allow the slurry to mix for 15 minutes prior to pumping. DOB2C (DIESEL OIL BENTONITE 2 CEMENT) PUMPING PROCEDURE It is important to the success of this operation to have a clear understanding of the loss rate. Both dynamic and static rates should be reviewed just prior to doing this job and incorporated into the final design. Various mixtures of drilling mud and DOB2C result in various degrees of a set product. Annular and drill string injection rates will be based on what the loss rate is at the time of the job. Treatment volume will be based a review of all available wellbore /loss data with a typical minimum recommended volume to be 40 bbls, however, depending upon tubular and annular clearances alternative volumes may be utilized. 1. Go in hole with BHA suitable for pumping Loss Circulation material(s). When a bit is needed, remove the jets. If necessary, a PBL circulating sub in the drilling BHA is suitable for placement. RIH to - 60' above the loss zone. A minimum of 2 bbl hole volume above the loss zone. 2. Establish injection down the drill string. Monitor and record losses. The cement van will pump down the drill pipe. The rig will do any pumping down the backside. 3. Batch mix the DOB2C slurry. Additional warm diesel should be made available on location for equipment cleanup. The system will be effective when mixed with arctic diesel, #4 Mapco or mineral oil, as the base fluid. 4. All surface equipment used to mix and pump the slurry will be free of water. Any diesel required to accomplish this will be isolated and used in the spacer behind the DOB2C. 5. "Typical" Pumping Procedure. Pump the treatment via dp at the maximum rate allowed as follows (The hydril is open): • Pump 10 -15 bbls diesel oil pre -flush spacer • Pump DOB2C slurry • Pump 10 -15 bbls diesel oil post -flush spacer • For maximum hydration ability, displace the squeeze to the bit with freshwater (40 -50 bbls). Follow this with mud as needed. 6. When the diesel oil preflush is at the end of the BHA, close hydrill and begin pumping down annulus with rig pumps. Match injection rates if possible to effectively mix the DOB2C with the annulus fluids. Too much dilution will soften the set product while too little water contact w /the DOB2C will not release the diesel. The best reactions occur at a mixture of 1:2 and 1:3 water based mud:DOB 2C. K12RD2 9 6/21/08 • • Halliburton BAROID Chevron Mud Program Production Hole Cleaning Modeling Operator Chevron Block. Country: INVERHUL .870 % Cutting Total ell: K:12 RD 2 Number User. Flow Rate = 200 gal /min ROP = 50 ft/ln .872 % Cutting Eff Cuttings Transport Average Hole ECD Mud Weight = 9.1 Ib /gal Cutting Dia. =15 in Load, % EH avg % V, ftlmin Angle Iblgal R.1 s@ 50 ft /hr60 rpm / HC. 60 rpm•3m / C =5m / 36 ' ' �w /o Cut 8.681 in � t 500.0�� — 64 /Cut �:: 1000 9.380 / 9.425 Iblgal 8.681 in 2000 87 2100.0 (2072,0) ft — 9.383 / 9.455 Ib /gal 3000 R� 4000 8.681 n 5000 fi 5000.0 (4412.0) ft ={ 4 x 3.34 x 10089.0 ft 95 9,417 / 9.509 Ib /gal 6000 ! 7000 . 1 8000 8.681 8.681 in 8400.0 (7051.0) ft — 9000 89 ill II 11 9.433 / 9.535 Ib /gal 10000 1 ill -- 8.fi81 in 1.18 X875 x 2.151 x 1200.0 ft 1.54 5.625 i i id-'• 1 11000 1.26 .00 `I 5 in ' 3.5 x 1,5 x 180,O ft 37 T _ i J 11 fi59 9.493 / 9.803 Ib/gal . 0 1 (9571.0) ft r H 5 1015 20 25 0 50 100 0 126 253 30 60 90 9.00 9.50 10.00 3.9 hr CUT time Baroid recommends a flowrate in the 250 -300 gpm range to maintain good hole cleaning capabilities at reduced ECD levels. Pump rates above 300gpm cause an increase in ECD and should be avoided. This modeling is based on 60 RPM's If RPM's drop below this level, hole cleaning deteriorates RAPIDLY. ROP's above 100' /hr are discouraged due to ECD build up. K12RD2 6/21 /08 • • King Salmon Mud Mixing Pit 10 " suction Mixing 10" Pump Overboard PI O 140 Bbls 248 Bbls 16 bbls/ft 31 bbls /ft — 1.4 bbls/iinch 2.6 bbls/inch opromtm • J 1 IC I 10" Equalizer 10" Equalizer Y 74 bbls 1 9 bbls/ft ■ 10" Equalizer .8 bblslmch ��' �' Mixing C Pump 172 Bbls 248 Bbls 10" Equalizer 19 bbls/ft 31 bbls/ft 1.6 bblslnch 2.6 bbls(nch 11,0 C esande p a Dump Da . E 10" Equalizer g+ tee. • M I Drilling Fluids L.L.C. 721 West First Avenue DRILLING Anchorage, Alaska 99501 FLUIDS (907) 274 -5564 (907) 279 -6729 Fax • Halliburton BAROID Chevron Mud Program HAROI o UN Cs 4 9 Chevron K12RD2 A - ��a Platform Baroid d Program Hallibu on Baroid Name (Printed) Signature Date Originator Dave Higbie Reviewed by Dave Higbie Customer Approval Steve Alexander Version No: Date: 1.1 May, 13,2008 K12RD2 1 5/14/08 • Halliburton BAROID,. Chevron Mud Program K12RD2 Introduction: The following mud program wa prepared for a sidetrack of the K12RD2 well on the King Salmon platform. The 2 7/8' kill string with • as lift valves are to be pulled and layed out. Due to the limitations of the CUDD HWU a deep whip stock . to be set within the Hemlock producing intervals. The objective is to side track around the stuck clean ou - ssembly from 11,077' to 11,241 placing a new 4" slotted line in the open hole from the window at 11,000' • a TD of 11,445'. Seawater will be used to kill and decom• -te the well. Prior to milling the window in the 7" liner, the 9 5/8" casing above the TOL of the 7" liner will , e pressure tested, and possibly scabbed with an inner 7" liner from the TOL (10487' to 10,100'). The ell will be displaced to a recycled OBM 9.0 ppg from Anna 32RD2 and a 445' sidetrack section will be illed with a steerable BHA assembly in a 5 5/8" hole. A pre slotted 4" liner will run and landed to 11,445' 'D within the Hemlock B -2 through the B -6 intervals. Primary Drilling Objectives: SUPERSEDt7C • Zero fluid related HSE incidents f • Maintain well control at all times • Achieve wellbore stability • Achieve good hole cleaning considering hole an• e, geometry and anticipated ROP rates • Lost circulation mitigation /control • Achieve good Zonal Isolation as per plan • Achieve minimal formation damage • Minimize fluids related NPT • Minimize drilling wastes Critical Fluid Issues: • Maintain well control • Eliminating /controlling losses. • Maintaining a low ECD in the production zone to reduce ri of lost returns. • Maintaining a stable wellbore through coal seams. Well Specifics: Casing Program MD TVD ootag 7" liner (KOP @ 11,000" MD) 11,000' 9196 0' 5 5/8" hole (4" liner slotted liner) 11,445' 9571 145' K12RD2 2 5/14/08 ♦ • Halliburton BAR ■ D Chevron Mud Program Production Interval: ( .18" hole, 4" Liner) to 11,445' MD K- 12R -L1 Mud Type: Inv: mul System Mud Properties Density Viscosity PV YP ES HTHP FL WPS O/W 11,000' — 9.0 — 9.3 , 55 - 80 18 -29 9 - 18 1000- <6 270 to 290K 80/20 11,445'TD 1100 • Additional mud weight may be requ -d for effective coal or shale stabilization. System Formulation: Product I Concentration Base Oil 0.696 bbl t r EZ MUL NT 4 ppb INVERMUL NT 4 ppb GELTONE V 4 ppb Lime 5 ppb DURATONE 4 ppb RM 63 1 ppb Water 0.178 bbl CaCl2 24.6 ppb AK -70 4 ppb BAROID to a 9.0 ppg Mud Type: INVERMUL System. 1. Mud weight: Begin with an initial mud weight o 9.0 ppg. If abnormal pressures exist or the well bore exhibits instability, increase the mud eight accordingly. Maximize solids control equipment. 2. Rheology: Maintain a YP between 9 and 18. P, p high viscosity or Barolift sweeps throughout the interval as needed, particularly prior to • • H for liner. Optimized mud rheology and flow rate will be the primary mechanisms for a• ieving hole cleaning in this deviated wellbore. Maximize pipe rotation. Sweeps will be equired while milling and at the completion of milling. 3. Other issues: The use of good drilling practices to minimize • cessive swab and surge pressure should be employed to minimize the chances for losses an differential sticking. Operations Summary: Seawater will be used to kill and decomplete the well. Prior to milling the wi 'ow in the 9 -5/8" casing, the well will be displaced to a 9.0 ppg INVERMUL oil -based system. Approximately 900 bbl o •il mud will be required to displace the well and fill the pits. Prepare the pit system for the INVERMUL as follows: • Clean pits, solids control equipment, all lines and pumps. • Flush all lines with a small volume of oil and discard. • Disconnect all water lines to the pit area and rig floor. • Check all steam fittings in pit room for leaks and repair as needed. Prior to milling, displace the well to the INVERMUL system designated for this interv- of the well. Pump a 25 bbl spacer ahead of the oil mud as follows: Spacer Formulation: • 20 barrels of the OBM treated with GELTONE to a YP > 30 (app. 4 -6 sx). - ight this pill to 2 ppg over the OBM weight. • Follow with INVERMUL mud system. K12RD2 3 5/14/08 RE: Chevron K12RD2 Permit to drill Page 1 of 2 • • Davies, Stephen F (DOA) From: Martin, Shannon W [SMartin c@chevron.com] Sent: Monday, June 30, 2008 3:45 PM To: Davies, Stephen F (DOA) Cc: Alexander, Steve [TWT] Subject: RE: Chevron K12RD2 Permit to drill Steve, Union and Pacific Energy are the only two working interest owners in the oil WIPAs in TBU. The parties interests in the oil WIPAs are aligned, with Union owning 53.2% and Pacific owning 46.8 %. Please let me know what other information you require. Regards, Shannon W. Martin, CPL Land Representative MidContinent /Alaska Chevron North America Exploration and Production 909 West 9th Ave., Anchorage, AK 99501 Tel 907 - 263 -7872 Fax 907 -263 -7698 smartin @chevron.com From: Alexander, Steve [TWr] Sent: Monday, June 30, 2008 3:35 PM To: 'steve.davies@alaska.gov' Cc: Martin, Shannon W Subject Chevron K12RD2 Permit to drill Steve from your questions today 6/30/08 on K12RD2. The answer to your question on the H2S level is: the gas stream was last measured on 11/23/16 prior to ESP failure, with an H2S content of 1150 ppm. I have spoken to Shannon Martin in our Land department, and he will respond to your 2nd question about the assigned interest of the unit as far as being equalized and uniform with the royalty owners. I have copied him on this note and he will send you a response directly due to the timing of this project. We are hopeful to begin drilling this short side track K12RD2 next week if possible, and have started on the permitted abandonment of K12RD. Regards Steve Alexander 6/30/2008 RE: Chevron K 12RD2 Permit to drill Page 2 of 2 Completions Engineer • Chevron Mid - Continent /Alaska The Wells Team, LLC 909 W. 9th Avenue Anchorage, Alaska 99501 Phone: (907) 263 -7880 Fax: 1- 866 - 914 -4472 steve.alexander @chevron.com 6/30/2008 RE: Chevron K12RD2 Permit to drill Page 1 of 1 • Davies, Stephen F (DOA) From: Alexander, Steve [TWT] [Steve.Alexander ©chevron.com] Sent: Monday, June 30, 2008 3:51 PM To: Alexander, Steve [TWT]; Davies, Stephen F (DOA) Cc: Martin, Shannon W Subject: RE: Chevron K12RD2 Permit to drill Steve, Correction on the date of H2S test: That is an 06 on the year date of the test, Highlighted below. Steve From: Alexander, Steve CTV1/11 Sent: Monday, June 30, 2008 3:35 PM To 'steve.davies@alaska.gov' Cc: Martin, Shannon W Subject: Chevron K12RD2 Permit to drill Steve from your questions today 6/30/08 on K12RD2. The answer to your question on the H2S level is: the gas stream was last measured on 11/23/06 prior to ESP failure, with an H2S content of 1150 ppm. I have spoken to Shannon Martin in our Land department, and he will respond to your 2nd question about the assigned interest of the unit as far as being equalized and uniform with the royalty owners. I have copied him on this note and he will send you a response directly due to the timing of this project. We are hopeful to begin drilling this short side track K12RD2 next week if possible, and have started on the permitted abandonment of K12RD. Regards Steve Alexander Completions Engineer Chevron Mid - Continent /Alaska The Wells Team, LLC 909 W. 9th Avenue Anchorage, Alaska 99501 Phone: (907) 263 -7880 Fax: 1 -866- 914 -4472 steve.alexander@chevron.com 6/30/2008 Page 1 of 3 • Maunder, Thomas E (DOA) From: Alexander, Steve [TWT] [Steve.Alexander @chevron.com] Sent: Friday, June 27, 2008 3:23 PM To: Maunder, Thomas E (DOA) Cc: Harness, Evan; Hammons, Darrell; Buster, Larry W Subject: RE: K -12RD (178 -057) Attachments: K12RD2 ST Water Base Mud 6 -21 -08 v2 (2).doc Tom, we are going to have to make a change on K12RD2 mud system from our proposed Oil Base Mud system to the attached Water Base Mud system. We have started the rig up on K12RD for the permitted abandonment of the lower section of the hole and will be preparing the well for the drilling operations once permitted. The Air permit is anticipated by July 8th and I would like to inquire as to the status of the Permit to drill application Dated 5/28/08. Would we not receive this until we receive our Drilling permit, or was there any questions on this application. I have returned Steve Davies call, but have not been able to catch him this week. Please let us know if you need anything else and I will follow up this email with a call to you. Regards Steve Alexander 907- 263 -7880 From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Thursday, May 29, 2008 11:43 AM To: Buster, Larry W Cc: Alexander, Steve [TVTfl; Walsh, Chantal [ Petrotechnical]; Hammons, Darrell Subject: RE: K -12RD (178 -057) Larry, et al, Thanks much. Tom Maunder, PE AOGCC From: Buster, Larry W [mailto:LBuster @chevron.com] Sent: Thursday, May 29, 2008 11:38 AM To: Maunder, Thomas E (DOA) Cc: Alexander, Steve [IWT]; Walsh, Chantal [Petrotechnical]; Hammons, Darrell Subject: RE: K -12RD (178 -057) Tom, Thanks. Also, on the current King Salmon work, we are running 2 -7/8" x 5 -1/2" VBR's in the top and blind /shears in the bottom of our double gate. Regards, Larry Larry W. Buster Drilling Engineering Manager 7/1/2008 Page 2 of 3 • MidContinent /Alaska Business Unit Chevron North America Exploration and Production 909 West 9th Avenue Anchorage, AK 99501 -3322 Tel: (907) 263 -7853 Cell: (907) 250 -0374 Fax: (907) 263 -7884 Ibuster @chevron.com From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Wednesday, May 28, 2008 5:04 PM To: Buster, Larry W Cc: Alexander, Steve [TWT]; Walsh, Chantal [Petrotechnical]; Hammons, Darrell Subject: RE: K -12RD (178 -057) Larry, et al, Thanks much for the reply. There is no need to resubmit the sundry. When it is returned, the hand changes will be evident. In this case so of the information listed is from K -12, not K -12RD. As this exchange has shown, it is important to keep the paperwork consistent workover to workover on a given platform. On platforms where the rig cannot or will not actually be employed, it is probably best to state upfront if the CUDD unit or some other piece of equipment is being employed. One last question, are you employing VBRs? Call or message with any questions. I will plan to place a copy of your reply in the respective well files. Tom Maunder, PE AOGCC From: Buster, Larry W [mailto:LBuster @chevron.com] Sent: Wednesday, May 28, 2008 4:51 PM To: Maunder, Thomas E (DOA) Cc: Alexander, Steve [TWT]; Walsh, Chantal [Petrotechnical]; Hammons, Darrell Subject: RE: K -12RD (178 -057) Tom, We are planning to do the abandonment work on the K -12RD with the CUDD 340 unit currently on the King Salmon Platform. Please advise if we need to re- submit the proposed program for the 10 -403? Also, we are submitting a 10 -401 for the proposed K -12RD2 today. Lastly, We are using the 3K (double gate and annular) on all of the King Salmon Wells using the CUDD 340 unit. Thanks and Regards, Larry W. Buster Drilling Engineering Manager MidContinent /Alaska Business Unit Chevron North America Exploration and Production 909 West 9th Avenue Anchorage, AK 99501 -3322 Tel: (907) 263 -7853 7/1/2008 Page 3 of 3 • Cell: (907) 250 -0374 Fax: (907) 263 -7884 (buster @chevron.com From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Wednesday, May 28, 2008 3:37 PM To: Walsh, Chantal [Petrotechnical] Subject: K -12RD (178 -057) Chantal, Would you please forward to Steve Alexander. I don't have his email. Steve, I left you a message. The Commission has received the sundry application to plug this well. Will this work be done using the Cudd HWO unit presently on the platform? If so, then the plan should state this. It is also noted in your letter that you will submit the proposed redrill for sundry approval. The redrill will require a new permit to drill. Also, a question for both of you. Which BOP stack arrangement is being used on King? This latest sundry has a 2 ram stack with annular which does meet the 3K requirements. I checked back on the 3 sundries recently approved for other wells and 2 have 3 ram stacks ( K -22RD and K -01 RD2) and 1 the 2 ram stack (K -19). I probably should have caught the difference when they came through, but as I remember they got split up due to questions. Thanks in advance. Tom Maunder, PE AOGCC 7/1/2008 .............. .......... . • I TRANSMITTAL LETTER ( C � HECKLIST WELL NAME PTD# Development, Service Exploratory Stratigraphic Test Non - Conventional Well FIELD: KC.as . \'\ - \Z ■∎VE C POOL: \ I G 0 A V 4to Circle Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK ADD -ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. , API No. 50- - - API number are between 60 -69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals thr target zones. Non - Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: I /112008 WELL PERMIT CHECKLIST Field & Pool MCARTHUR RIVER, HEMLOCK OIL - 520120 Well Name: TRADING BAY UNIT K -12RD2 Program DEV Well bore seg ❑ PTD#: 2080880 Company UNION OIL CO OF CALIFORNIA Initial Class/Type DEV / PEND GeoArea 820 Unit 12070 On /Off Shore Off Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate _ Yes 3 Unique well name and number Yes 4 Well_located in a defined pool Yes MCARTHUR RIVER, HEMLOCK OIL - 520120 governed by CO 80. 5 Well located proper distance from drilling unit boundary Yes Statewide spacing rules apply since CO 80 contains no rule regarding well spacing. K -12RD2 6 Well located proper distance from other wells Yes will conform to 20 AAC 25.055: >2000' from exterior unit boundary, >1500' from 7 Sufficient acreage_available in drilling unit Yes nearest offset well, and only oil_prodsrcer in Section 18. AII_working interests are aligned 8 If_deviated, is wellbore plat included Yes (per Shanon_Martin, Unocal, 6 /3Q /08), so there are no correlative rights issues. SFD 9 Operator only affected party Yes 10 Operator has_appropriate bond inform Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permitcan be issued without administrativ_e_approval Yes SFD 7/1/2008 13 Can permit be approved before 15-day wait Yes 14 _Well located within area and_strata authorized by Injection Order # (put_ 1O# in_comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre- produced injector; duration of pre - production less than 3 months (For service well only) _ _ _NA_ 17 Nonconven. gas conforms to AS31,05.030(j,1.A),(j,2.A -D) NA Engineering 18 Conductor string_provided NA 19 Surface casing_protects all known USDWs NA All aquifers exempted, 40 CFR147.102 (bX2)(ii). 20 CMT vol adequate to circulate on conductor & surf csg NA 21 CMT_v_ol adequate to tie-in long string to surf csg NA 22 CMT will coverall known_ productive horizons No pre - perforated liner planned. 23 Casing designs adequate for C,_T, B & permafrost NA Original wells met design specifications. NA for pre - perforated liner. 24 Adequate tankage_ or reserve pit Yes Rig located on offshore platform. Ali wastes will behauled to approved disposal_well. 25 Its_ re- drill, has_ a_ 10-403 for abandonment been approved Yes 308 -190 26 Adequate wellbore separationproposed NA Penetration is_planned_to be near existing well. Segment will replace section plugged with junk. 27 If diverter required, does it meet regulations NA BOP stack will already_be in place. Appr Date 28 Drilling fluid_ program schematic & equip list adequate Yes Maximum expected formation pressure 6.8 EMW. MW planned 9.0 9.1 ppg. TEM 7/1/2008 29 BOPEs,_do they meet regulation Yes icic, '71\ 30 BOPE_press rating appropriate; test to_(put psig in comments) Yes MASP calculated at 2443 psi. 3500_psi_BOP_ test planned. 31 Choke manifold complies w/API RP -53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 is presence of H25 gas probable Yes H2S is present in TBU oil production. Mud should preclude on rig._ Rig has sensors and alarms. 34 _Mechanical_condition of wells within AOR verified (For service well only) NA Geology 35 Perrnitcan be issued w/o hydrogen_ sulfide measures No Gas stream in K -12 RD measured 1150 ppm H2S in Nov 06. Mitigation measures required. 36 Data_presented on potential overpressure zones Yes Expected pressuregradientis 6.8 ppg EMW_based_on test data from offsetwells. Will be Appr Date 37 Seismic analysis of shallow gas zones NA drilled with 9.0 - 9.3 ppg mud, SFD 7/1/2008 38 Seabed condition survey (if off- shore) NA 39 Contact name /phone for weekly_ progress reports [exploratory only] NA Geologic Engineering P . lic Commissioner: Date: Commissionn / er: Date ' er Date r e— _./.....0.69 i