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Home My WebLink About169-058Nolan 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: 11/07/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251107 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-26 50283201820000 220058 9/20/2025 AK E-LINE Perf BRU 212-35 50283100270000 162018 10/12/2025 AK E-LINE TubingPuncher BRU 234-27 50283202070000 225065 7/17/1905 AK E-LINE CBL-02-October BRU 234-27 50283202070000 225065 10/6/2025 AK E-LINE CIBP/Perf GP 42-23RD 50733201140100 195145 10/26/2025 AK E-LINE TubingPunch GP ST 42-23RD 50733201140100 195145 10/9/2025 AK E-LINE JetCut MPL-54 50029236070000 218066 10/16/2025 READ CaliperSurvey MPL-57 50029236090000 218072 10/27/2025 READ CaliperSurvey MPU B-21 50029215350000 186023 10/25/2025 AK E-LINE RBP NCIU A-07 50883200270000 169058 10/10/2025 AK E-LINE JetCut NCIU A-17A 50883201880100 225089 10/10/2025 AK E-LINE Perf NCIU A-17A 50883201880100 225089 10/14/2025 AK E-LINE Perf PBU 01-10A 50029201690200 225055 8/29/2025 HALLIBURTON RBT PBU 05-11A 50029202520100 196097 10/11/2025 BAKER RPM PBU 05-31B 50029221590200 210085 10/14/2025 BAKER SPN PBU F-06B 50029200970200 225054 9/27/2025 BAKER MRPM PBU F-42A 50029221080100 207093 10/27/2025 BAKER RPM PBU H-07B 50029202420200 225064 9/29/2025 BAKER MRPM PBU L5-27 50029236270000 219046 10/7/2025 BAKER SPN PBU Q-06A 50029203460100 198090 8/22/2025 YELLOWJACKET SCBL SD-06 50133205820000 208160 7/23/2025 YELLOWJACKET GPT-PERF SRU 222-33 50133207150000 223100 7/15/2025 YELLOWJACKET PERF Please include current contact information if different from above. T41066 T41067 T41068 T41068 T41069 T41069 T41070 T41071 T41072 T41073 T41074 T41074 T41075 T41076 T41077 T41078 T41079 T41080 T41081 T41082 T41083 T41084 NCIU A-07 50883200270000 169058 10/10/2025 AK E-LINE JetCut Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.07 15:03:51 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:6 Township:11N Range:9W Meridian:Seward Drilling Rig:Hilcorp 151 Rig Elevation:Total Depth:8126 ft MD Lease No.:ADL0017589 Operator Rep:Suspend:P&A:X Conductor:30"O.D. Shoe@ 388 Feet Csg Cut@ Feet Surface:O.D. Shoe@ Feet Csg Cut@ Feet Intermediate:10-3/4"O.D. Shoe@ 2522 Feet Csg Cut@ Feet Production:7"O.D. Shoe@ 8108 Feet Csg Cut@ Feet Liner:O.D. Shoe@ Feet Csg Cut@ Feet Tubing:3-1/2"O.D. Tail@ 6925 Feet Tbg Cut@ 3450 Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Fullbore Retainer 3420 ft 2781 ft 8.6 ppg Drillpipe tag Initial 15 min 30 min 45 min Result 2nd Test Tubing 3030 2911 2810 2751 IA 3030 2911 2810 2751 OA 34 34 34 34 Initial 15 min 30 min 45 min Result 3rd Test Tubing 3036 2900 2823 2771 IA 3036 2900 2823 2771 OA 34 34 34 34 Remarks: Attachments: I met with Steve Dambacher and we reviewed the sundry for this job. They were already in the hole with 4" drillpipe and milling assembly. Washed down and tagged TOC at 2781 ft MD. The rigs current RKB is 53.37 ft. They set 15K lbs down on the TOC twice to confirm good cement. Once they pulled up to a safe spot, they closed the upper pipe rams and attempted the MIT for the 7" casing and cement/retainer. 2 attempts, both failing. They flushed lines, double checked surface equipment, and eliminated the IBOP by pumping through the top drive and down the drill pipe for a 3rd attempt - also failed. I departed the rig after this test. October 16, 2025 Josh Hunt Well Bore Plug & Abandonment Norsth Cook Inlet Unit A-07 Hilcorp Alaska LLC PTD 1690580; Sundry 325-628 none Test Data: F Casing Removal: Steve Dambacher F Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2025-1016_Plug_Verification_NCIU_A-07_jh                                     STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________N COOK INLET UNIT A-07 JBR 11/25/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 3-1/2" & 4-1/2" joints. Sundry 325-628 - changed approved program (previous sundry 325-518). Test Results TEST DATA Rig Rep:Mitchell/BoydOperator:Hilcorp Alaska, LLC Operator Rep:Dambacher/Freeland Rig Owner/Rig No.:Hilcorp 151 PTD#:1690580 DATE:10/14/2025 Type Operation:WRKOV Annular: 250/2500Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopSAM251018143228 Inspector Austin McLeod Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 6 MASP: 1267 Sundry No: 325-628 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P Inside BOP 1 P FSV Misc 0 NA 13 PNo. Valves 1 PManual Chokes 2 PHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13-5/8"P #1 Rams 1 2-7/8"x5-1/2"P #2 Rams 1 Blinds P #3 Rams 1 3-1/2"x5-1/2"P #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3-1/8"P HCR Valves 2 3-1/8"P Kill Line Valves 3 3-1/8&4-1/16 P Check Valve 0 NA BOP Misc 0 NA System Pressure P3100 Pressure After Closure P1700 200 PSI Attained P26 Full Pressure Attained P132 Blind Switch Covers:PAll stations Bottle precharge P Nitgn Btls# &psi (avg)P16@2100 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator P PMeth Gas Detector P PH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P14 #1 Rams P10 #2 Rams P10 #3 Rams P10 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P2 HCR Kill P2        Gas Detector Test Report attached COMBUSTIBLE GAS DETECTION SYSTEM Rig and Mud Pits - State Compliance Testing FACILITY NAME:Tyonek Platform Rig 151 ROOM DESIGNATION:Rig, Shakers, Well Room Instructions: Use this form to record combustible gas detector calibration data and alarm tests. Cal Gas Cal Gas Verify Gas-Free Applied Gas-Free Applied Sensativity Alarms at Sensor Tag Name Faulted? Reading Reading Reading Reading With 50%20 and 40% Or Location (%LEL) (%LEL) (%LEL) (%LEL)Gas Applied YES NO Rig Gas Detectors 20 40 Yes 20 40 Yes 20 40 Yes 20 40 Yes 20 40 Yes 20 40 Yes 20 40 Yes Sensativity With 50% Gas Applied YES NO RIG H2S DETECTORS 10 20 Yes 10 20 Yes 10 20 Yes 10 20 Yes 10 20 Yes 10 20 Yes 10 20 Yes Note: Comb gas used 50% LEL H2S gas used 25ppm Conditions As Found Conditions As Left 151 Pits (Ch. 1)No 0 50%0 50% 151 Shakers (Ch. 3)No 0 50%0 50% 151 Trip Tank (Ch. 2)No 0 50%0 50% 151 Cellar (Ch. 5)No 0 50%0 50% Aux Shaker Tank (Ch. 4)No 0 50%0 50% Aux Wellbay Room (Ch. 7)No 0 50%0 50% 151 Rig Floor (Ch.6)No 0 50%0 50% Faulted?Reading Reading Reading Reading and 20 ppm Cal Gas Cal Gas Verify Gas-Free Applied Gas-Free Applied Alarms at 10 151 Trip Tank (Ch. 9)No 0 25 PPM 0 25 PPM (PPM)(PPM)(PPM)(PPM) 151 Pits (Ch. 8)No 0 25 PPM 0 25 PPM Aux Shaker Tank (Ch.11)No 0 25 PPM 0 25 PPM 151 Shakers (Ch.10)No 0 25 PPM 0 25 PPM 151 Rig Floor (Ch. 13)No 0 25 PPM 0 25 PPM 151 Cellar (Ch.12)No 0 25 PPM 0 25 PPM NOTES: All devices activated as they should, No Faults or Errors on system. TECHNICIAN:Ian Hanna STATE INSPECTOR: Austin McLeod Date:10/14/2025 Aux Wellbay Room (Ch. 14)No 0 25 PPM 0 25 PPM 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? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,126 N/A Casing Collapse Structural Conductor Surface 2,090psi Intermediate Production 3,270psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Sean Mclaughlin Contact Email:sean.mclaughlin@hilcorp.com Contact Phone:907-223-6784 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng North Cook Inlet Tertiary System Gas Same 6,920 4,109 3,627 1,267psi See schematic Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Drilling Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 169-058 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20027-00-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-07 Length Size Proposed Pools: See schematic TVD Burst 6,925 4,360psi MD 3,580psi 388' 2,364' 388' 2,522' 6,905'7" 30" 10-3/4" 388' 2,522' Perforation Depth MD (ft): 3,998 - 4,100 8,108' 3,539 - 3,620 CO 68A Other: 10/15/2025 See schematic See schematic See schematic 8,108' m n P s 1 6 5 6 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 11:02 am, Oct 14, 2025 10/14/25Monty M Myers 325-628 10-407 * BOPE test o 3000 psi. Annular to 2500 psi. * AOGCC to witness tag and pressure test of TOC ~2950' MD. * As well has no injectivity cement retainer should be set as deep as possible. A.Dewhurst 14OCT25MGR14OCT2025 DSR-10/14/25 10/14/25 Well Prognosis Well: NCIU A-07 Date: 10/14/2025 Well Name:NCIU A-07 API Number:50-883-20027-01-00 Current Status:Testing BOPE Estimated Start Date:10/15/2025 Rig:Spartan 151 Reg. Approval Reqd?403 Date Reg. Approval Recvd: Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:225-094 First Call Engineer:Sean Mclaughlin 907-223-6784 Second Call Engineer Sundry Number:325-518 Attachments: 1.Current Schematic 2.Proposed Schematic 3.BOPE Schematic Change to Approved Program Request: Hilcorp is requesting a change to the approved sundry 325-518 (plug for redrill). Current Status Rig 151 has pressured up on the 3-1/2 tubing to 3200 psi and is unable to achieve injectivity into the open perforations. The tubing has been cut at 3450 and the well circulated to KWF. The BOPE test is currently underway. The upper most CIBP topped with cement is at 4109. There are 3 sets of perforations between the TOC and tubing cut for a total of 45 of perforations. 7 annular cement has been logged to 2,525. Procedure: 1. Pull 3-1/2 tubing from cut as programed. 2. Set 7 23# cement retainer at 3350. 3. Attempt to inject into the perforations a. Limit pressure to 3000 psi. (7 23# J-55 Burst = 4360 psi) b. If successful, pump 20 bbls of 15.3# below the retainer. The 16 bbls above retainer (as planned). c. If unsuccessful with injection, lay in cement ~36 bbls of cement above retainer. 4. WOC Give AOGCC 48 hr notice for tag and PT witness opportunity. 5. Tag TOC with minimum of 15klbs. Pressure Test cement plug and casing to 2635 psi. 6. Continue operations on APD (225-094) Variance Request 20 AAC 25.112(c)(1)(C) -however, the commission will approve plugging from the top of fill or the top of junk instead of from the plugged-back total depth, if the commission determines that the objectives of this subsection will be met Justification: - Hard pack fill is expected in the 3-1/2 tubing - Running a 2-3/8 cleanout string, in 7 tubing, at a shallow depth would be a significant buckling risk. - Rig 151 is currently equipped with 2-7/8 x 5 VBRs (no 2-3/8 handling equipment). Pump additional cement for retainer set deeper near tubing stub. TOC to be ~2950' MD. - mgr Set cement retainer as deep as possible allowing offset of tubing stub. - mgr Well Prognosis Well: NCIU A-07 Date: 10/14/2025 - A cement retainer deep in the casing and near the production packer is a suitable base to place cement on top of. - Additional cement volume and increased plug length (~900 planned) would ensure a long lateral barrier across the production packer. _____________________________________________________________________________________ Updated By: JLL 10/02/24 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30Surf 388 10-3/451 J-55 BT&C 9.850 Surf 528' 45.5 J-55 BT&C 9.950 528'2,522 7 26 J-55 BT&C 6.276 Surf 79 23 J-55 BT&C 6.366 79 7,100 26 J-55 BT&C 6.276 7,1008,108 TUBING DETAIL 4-1/212.6 L-80 IBT 3.958Surf 383 3-1/29.2 L-80 IBT 2.9923833,549 3-1/29.2 L-80 8RD EUE 2.9923,5494,318 4-1/212.75 J-55 Mod EUE 8rd 3.958"4,3185,129 4-1/212.75 J-55 EUE 8rd 3.958"5,1296,925 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Sterling Z 3,998 4,018 3,539 3,555 2002/16/21 Open Stray 2 4,054 4,069 3,583 3,595 1506/13/20 Open Stray 3 4,090 4,100 3,612 3,620 1006/13/20 Open Sterling A 4,118 4,123 3,635 3,639 506/03/20 Isolated Sterling B 4,170 4,175 3,676 3,680 505/30/20 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,766 1,734 2.867 GLM #1 SPM 1 Dummy 5/29/2020 2 3,354 3,028 2.867 GLM #2 SPM 1 20 Orifice 5/30/2021 CEMENT DETAILS 10-3/415 hole: Pumped 1020sxs 11.5ppg class G lead followed by 125sxs 15.6ppg class G tail.Assumed ToC to surface 7 9-5/8 Hole: Pumped 525sxs 13ppg class G primary stage. Saw 20bbls primary stage back to surface when circd through stage collar.Primary ToC at stage collar (5,211 MD) Second stage: Pumped 760sxs 14.9ppg class G second stage cement through stage collar at 5211 MD. Lost partial returns with 25bbls remaining in displacement.5/23/20 CBL shows second stage ToC at 2,525 MD 3-1/2 Scab Pumped 25.7bbls of 15.8ppg cement into 3-1/2 x 7 annulus. Circd cement off liner top at 3,549 MD . 5/25/20 CBL shows ToC to ToL JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 26.07 26.07 Hanger Vetco 4 1/2 IBTsusp, 4.909 MCA lift threads, 4" Type H BPV profile 1 343 3433.813 5.400 Nipple, Camco BP-6I Landing WRDP, DB lock -No WL-SSSV installed as of 7/5/21 2 383 3833.000 5.210 4-1/2 x 3-1/2 Crossover 3 3,404 3,068 2.867 5.313Chemical Injection Mandrel 4 3,457 3,110 3.000 6.0007" 3 1/2" DLH Packer (46k Shear release) 5 3,501 3,144 2.813 3.750X-Nipple 6 3,532 3,169 2.992 3.500Dummy seal bore Assembly 7 3,549 3,182 4.176 5.924 ZXP Liner Top Packer with 10 extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 8 4,109 3,627 2.750 CIBP w/3.6 cement 9 4,111 3,629 2.750CIBP 10 4,165 3,672 2.750 CIBP w/ 18 cement 11 4,318 3,794Landing collar and float Assembly 12 4,318 3,794Tubing Cut A 4,328 3,8021.71 3.125 Profile Nipple R Nipple B 4,329 3,8033.813 5.030 Halliburton X Nipple w/ plug set _____________________________________________________________________________________ Updated By: JLL 10/02/24 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 ISOLATED JEWELRY No Depth (MD) Depth (TVD)ID OD Item C 4,370 3,8063.992 5.080 Ratch Latch Seal Unit 4,371 3,8063.880 5.980 Halliburton VSR Packer D 4,591 4,0133.813 5.530 Halliburton XD Sliding Sleeve (Closed) E 4,605 4,0243.992 5.560 Halliburton No-Go Locator 4,606 4,0254.000 5.815 Halliburton TWR Packer & Millout Extension F 4,711 4,1093.813 5.530 Halliburton XD Sliding Sleeve (Closed) G 4,723 4,1193.992 5.080 Halliburton No-Go Seal Unit 4,724 4,1204.000 5.815 Halliburton TWR Packer & Millout Extension H 4,849 4,2223.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) I 4,861 4,2323.950 5.080 Halliburton No-Go Seal Unit 4,862 4,2334.000 5.815 Halliburton TWR Packer & Millout Extension J 4,943 4,2993.950 5.080 Ratch Latch Seal Unit 4,944 4,2994.000 5.815 Halliburton TWR Packer & Millout Extension K 5,080 4,4113.813 5.530 Halliburton XA Sliding Sleeve (Closed) L 5,116 4,4413.950 5.080 Ratch Latch Seal Unit 5,117 4,4414.000 5.815 Halliburton TWR Packer & Millout Extension M 5,601 4,8413.813 5.530 Halliburton XD Sliding Sleeve (Open) N 6,294 5,4103.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) O 6,893 5,9843.725 5.030 Halliburton XN Nipple P 6,925 5,9203.992 5.580 WLREG ISOLATED PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status CI-1.0 4,406' 4,476' 3,864' 3,920'70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999'80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047'10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101'50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171'40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215'10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266'25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321'7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404'19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833'5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867'5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885'10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093'5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167'25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226'10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321'5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336'10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368'20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398'25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407'5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453'7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581'10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616'15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634'5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651'7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697'10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781'7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913'25' Jun-94 Isolated _____________________________________________________________________________________ Updated By: CJD 10/14/25 Proposed Schematic North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30Surf 388 10-3/451 J-55 BT&C 9.850 Surf 528' 45.5 J-55 BT&C 9.950 528'2,522 7 26 J-55 BT&C 6.276 Surf 79 23 J-55 BT&C 6.366 79 7,100 26 J-55 BT&C 6.276 7,1008,108 TUBING DETAIL 3-1/29.2 L-80 IBT 2.9923,450 (cut)3,549 3-1/29.2 L-80 8RD EUE 2.9923,5494,318 4-1/212.75 J-55 Mod EUE 8rd 3.958"4,3185,129 4-1/212.75 J-55 EUE 8rd 3.958"5,1296,925 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Sterling Z 3,998 4,018 3,539 3,555 2002/16/21 Open Stray 2 4,054 4,069 3,583 3,595 1506/13/20 Open Stray 3 4,090 4,100 3,612 3,620 1006/13/20 Open Sterling A 4,118 4,123 3,635 3,639 506/03/20 Isolated Sterling B 4,170 4,175 3,676 3,680 505/30/20 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 2 3,354 3,028 2.867 GLM #2 SPM 1 20 Orifice 5/30/2021 CEMENT DETAILS 10-3/415 hole: Pumped 1020sxs 11.5ppg class G lead followed by 125sxs 15.6ppg class G tail.Assumed ToC to surface 7 9-5/8 Hole: Pumped 525sxs 13ppg class G primary stage. Saw 20bbls primary stage back to surface when circd through stage collar.Primary ToC at stage collar (5,211 MD) Second stage: Pumped 760sxs 14.9ppg class G second stage cement through stage collar at 5211 MD. Lost partial returns with 25bbls remaining in displacement.5/23/20 CBL shows second stage ToC at 2,525 MD 3-1/2 Scab Pumped 25.7bbls of 15.8ppg cement into 3-1/2 x 7 annulus. Circd cement off liner top at 3,549 MD . 5/25/20 CBL shows ToC to ToL JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 2 2,710Whipstock 3 3,350 Cement Retainer Pump 20 bbls below / 16 bbls on top (Planned TOC @ ±2,950)If injectivity is unsuccessful lay all 36 bbls on top 4 3,457 3,110 3.000 6.0007" 3 1/2" DLH Packer (46k Shear release) 5 3,501 3,144 2.813 3.750X-Nipple 6 3,532 3,169 2.992 3.500Dummy seal bore Assembly 7 3,549 3,182 4.176 5.924 ZXP Liner Top Packer with 10 extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 8 4,109 3,627 2.750 CIBP w/3.6 cement 9 4,111 3,629 2.750CIBP 10 4,165 3,672 2.750 CIBP w/ 18 cement 11 4,318 3,794Landing collar and float Assembly 12 4,318 3,794Tubing Cut A 4,328 3,8021.71 3.125 Profile Nipple R Nipple B 4,329 3,8033.813 5.030 Halliburton X Nipple w/ plug set _____________________________________________________________________________________ Updated By: CJD 10/14/25 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 ISOLATED JEWELRY No Depth (MD) Depth (TVD)ID OD Item C 4,370 3,8063.992 5.080 Ratch Latch Seal Unit 4,371 3,8063.880 5.980 Halliburton VSR Packer D 4,591 4,0133.813 5.530 Halliburton XD Sliding Sleeve (Closed) E 4,605 4,0243.992 5.560 Halliburton No-Go Locator 4,606 4,0254.000 5.815 Halliburton TWR Packer & Millout Extension F 4,711 4,1093.813 5.530 Halliburton XD Sliding Sleeve (Closed) G 4,723 4,1193.992 5.080 Halliburton No-Go Seal Unit 4,724 4,1204.000 5.815 Halliburton TWR Packer & Millout Extension H 4,849 4,2223.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) I 4,861 4,2323.950 5.080 Halliburton No-Go Seal Unit 4,862 4,2334.000 5.815 Halliburton TWR Packer & Millout Extension J 4,943 4,2993.950 5.080 Ratch Latch Seal Unit 4,944 4,2994.000 5.815 Halliburton TWR Packer & Millout Extension K 5,080 4,4113.813 5.530 Halliburton XA Sliding Sleeve (Closed) L 5,116 4,4413.950 5.080 Ratch Latch Seal Unit 5,117 4,4414.000 5.815 Halliburton TWR Packer & Millout Extension M 5,601 4,8413.813 5.530 Halliburton XD Sliding Sleeve (Open) N 6,294 5,4103.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) O 6,893 5,9843.725 5.030 Halliburton XN Nipple P 6,925 5,9203.992 5.580 WLREG ISOLATED PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status CI-1.0 4,406' 4,476' 3,864' 3,920'70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999'80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047'10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101'50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171'40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215'10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266'25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321'7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404'19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833'5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867'5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885'10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093'5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167'25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226'10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321'5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336'10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368'20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398'25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407'5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453'7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581'10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616'15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634'5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651'7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697'10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781'7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913'25' Jun-94 Isolated Page 24 Drilling Program October 7, 2025 NCI A-07A Drilling Program PTD 225-094 19. BOP Schematic 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? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,126 N/A Casing Collapse Structural Conductor Surface 2,090psi Intermediate Production 3,270psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Sean Mclaughlin Contact Email:sean.mclaughlin@hilcorp.com Contact Phone:907-223-6784 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng North Cook Inlet Tertiary System Gas Same 6,920 4,109 3,627 1,267psi See schematic Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Drilling Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 169-058 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20027-00-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-07 Length Size Proposed Pools: See schematic TVD Burst 6,925 4,360psi MD 3,580psi 388' 2,364' 388' 2,522' 6,905'7" 30" 10-3/4" 388' 2,522' Perforation Depth MD (ft): 3,998 - 4,100 8,108' 3,539 - 3,620 CO 68A Other: 10/7/2025 See schematic See schematic See schematic 8,108' m n P s 1 6 5 6 tc N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:00 pm, Aug 26, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.08.26 11:12:37 - 08'00' Sean McLaughlin (4311) 325-518 A.Dewhurst 24SEP25 * BOPE pressure test to 3000 psi. Annular to 2500 psi. 48 hour notice to AOGCC. * State witness tag (TOC ~2525' MD) and pressure test to 2635 psi. 10-407 MGR05SEP2025 DSR-9/10/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.24 15:35:00 -08'00'09/24/25 RBDMS JSB 092625 Well Prognosis Well: NCIU A-07 Date: 8/26/25 Well Name:NCIU A-07 API Number:50-883-20027-00-00 Current Status:Plug For Redrill Estimated Start Date:10/7/25 Rig:Spartan 151 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Cody Dinger 777-8389 Permit to Drill Number:169-058 First Call Engineer:Sean Mclaughlin 907-223-6784 Second Call Engineer AFE Number: Attachments: 1.Current Schematic 2.Proposed Schematic 3.Proposed Operations 4.BOPE Schematic _____________________________________________________________________________________ Updated By: JLL 10/02/24 SCHEMATIC North Cook Inlet Unit Well:NCI A-07 Last Completed:06/14/20 PTD:169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4”51 J-55 BT&C 9.850 Surf 528' 45.5 J-55 BT&C 9.950 528'2,522’ 7” 26 J-55 BT&C 6.276 Surf 79’ 23 J-55 BT&C 6.366 79’7,100’ 26 J-55 BT&C 6.276 7,100’8,108’ TUBING DETAIL 4-1/2”12.6 L-80 IBT 3.958”Surf 383’ 3-1/2”9.2 L-80 IBT 2.992”383’3,549’ 3-1/2”9.2 L-80 8RD EUE 2.992”3,549’4,318’ 4-1/2”12.75 J-55 Mod EUE 8rd 3.958"4,318’5,129’ 4-1/2”12.75 J-55 EUE 8rd 3.958"5,129’6,925’ PERFORATION DETAIL Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status Sterling Z 3,998’ 4,018’ 3,539 3,555’20’02/16/21 Open Stray 2 4,054’ 4,069’ 3,583’ 3,595’15’06/13/20 Open Stray 3 4,090’ 4,100’ 3,612’ 3,620’10’06/13/20 Open Sterling A 4,118’ 4,123’ 3,635’ 3,639’5’06/03/20 Isolated Sterling B 4,170’ 4,175’ 3,676’ 3,680’5’05/30/20 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,766’1,734’2.867”GLM #1–SPM–1 Dummy 5/29/2020 2 3,354’3,028’2.867”GLM #2–SPM–1 20 Orifice 5/30/2021 CEMENT DETAILS 10-3/4”15” hole: Pumped 1020sxs 11.5ppg class G lead followed by 125sxs 15.6ppg class G tail.Assumed ToC to surface 7” 9-5/8” Hole: Pumped 525sxs 13ppg class G primary stage. Saw 20bbls primary stage back to surface when circ’d through stage collar.Primary ToC at stage collar (5,211’ MD) Second stage:Pumped 760sxs 14.9ppg class G second stage cement through stage collar at 5211’ MD.Lost partial returns with 25bbls remaining in displacement.5/23/20 CBL shows second stage ToC at 2,525’ MD 3-1/2” Scab Pumped 25.7bbls of 15.8ppg cement into 3-1/2” x 7” annulus. Circ’d cement off liner top at 3,549’ MD. 5/25/20 CBL shows ToC to ToL JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 26.07’26.07’Hanger Vetco 4 1/2 IBTsusp, 4.909 MCA lift threads, 4" Type H BPV profile 1 343’343’3.813 5.400 Nipple, Camco BP-6I Landing WRDP, DB lock -No WL-SSSV installed as of 7/5/21 2 383’383’3.000 5.210 4-1/2” x 3-1/2” Crossover 3 3,404’3,068’2.867”5.313”Chemical Injection Mandrel 4 3,457’3,110’3.000”6.000”7" 3 1/2" DLH Packer (46k Shear release) 5 3,501’3,144’2.813”3.750”X-Nipple 6 3,532’3,169’2.992”3.500”Dummy seal bore Assembly 7 3,549’3,182’4.176”5.924”ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 8 4,109’3,627’2.750”CIBP w/3.6’ cement 9 4,111’3,629’2.750”CIBP 10 4,165’3,672’2.750”CIBP w/ 18’ cement 11 4,318’3,794’Landing collar and float Assembly 12 4,318’3,794’Tubing Cut A 4,328’3,802’1.71 3.125 Profile Nipple R Nipple B 4,329’3,803’3.813 5.030 Halliburton X Nipple w/ plug set _____________________________________________________________________________________ Updated By: JLL 10/02/24 SCHEMATIC North Cook Inlet Unit Well:NCI A-07 Last Completed:06/14/20 PTD:169-058 ISOLATED JEWELRY No Depth (MD) Depth (TVD)ID OD Item C 4,370’3,806’3.992 5.080 Ratch Latch Seal Unit 4,371’3,806’3.880 5.980 Halliburton VSR Packer D 4,591’4,013’3.813 5.530 Halliburton XD Sliding Sleeve (Closed) E 4,605’4,024’3.992 5.560 Halliburton No-Go Locator 4,606’4,025’4.000 5.815 Halliburton TWR Packer & Millout Extension F 4,711’4,109’3.813 5.530 Halliburton XD Sliding Sleeve (Closed) G 4,723’4,119’3.992 5.080 Halliburton No-Go Seal Unit 4,724’4,120’4.000 5.815 Halliburton TWR Packer & Millout Extension H 4,849’4,222’3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) I 4,861’4,232’3.950 5.080 Halliburton No-Go Seal Unit 4,862’4,233’4.000 5.815 Halliburton TWR Packer & Millout Extension J 4,943’4,299’3.950 5.080 Ratch Latch Seal Unit 4,944’4,299’4.000 5.815 Halliburton TWR Packer & Millout Extension K 5,080’4,411’3.813 5.530 Halliburton XA Sliding Sleeve (Closed) L 5,116’4,441’3.950 5.080 Ratch Latch Seal Unit 5,117’4,441’4.000 5.815 Halliburton TWR Packer & Millout Extension M 5,601’4,841’3.813 5.530 Halliburton XD Sliding Sleeve (Open) N 6,294’5,410’3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) O 6,893’5,984’3.725 5.030 Halliburton XN Nipple P 6,925’5,920’3.992 5.580 WLREG ISOLATED PERFORATION DETAIL Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status CI-1.0 4,406'4,476'3,864'3,920'70'Jun-94 Isolated CI-2.0 4,494'4,574'3,935'3,999'80'Jun-94 Isolated CI-3.1 4,624'4,634'4,039'4,047'10'Jun-94 Isolated CI-4.0 4,651'4,701'4,061'4,101'50'Jun-94 Isolated CI-5.0 4,746'4,786'4,138'4,171'40'Jun-94 Isolated CI-6.0 4,831'4,841'4,207'4,215'10'Jun-94 Isolated CI-7.0 4,878'4,903'4,246'4,266'25'Jun-94 Isolated CI-8.0 4,963'4,970'4,315'4,321'7'Jun-94 Isolated CI-9.0 5,053'5,072'4,389'4,404'19'Jun-94 Isolated C-4 5,587'5,592'4,829'4,833'5'Jun-94 Isolated D-1 5,628'5,633'4,863'4,867'5'Jun-94 Isolated D-2 5,645'5,655'4,877'4,885'10'Jun-94 Isolated E-9 5,901'5,906'5,089'5,093'5'Jun-94 Isolated F-3 & F-4 5,970'5,995'5,146'5,167'25'Jun-94 Isolated G-1 6,058'6,068'5,218'5,226'10'Jun-94 Isolated H-1.1 6,180'6,185'5,317'5,321'5'Jun-94 Isolated H-2 6,193'6,203'5,328'5,336'10'Jun-94 Isolated H-4 & H-5 6,223'6,243'5,352'5,368'20'Jun-94 Isolated H-6 & H-7 6,254'6,279'5,377'5,398'25'Jun-94 Isolated H-7.1 6,285'6,290'5,403'5,407'5'Jun-94 Isolated H-9 6,340'6,347'5,447'5,453'7'Jun-94 Isolated J-1 6,495'6,505'5,573'5,581'10'Jun-94 Isolated J-3 6,533'6,548'5,604'5,616'15'Jun-94 Isolated K-1 6,566'6,571'5,630'5,634'5'Jun-94 Isolated K-2 6,584'6,591'5,645'5,651'7'Jun-94 Isolated K-5 6,638'6,648'5,689'5,697'10'Jun-94 Isolated M-4 6,746'6,753'5,776'5,781'7'Jun-94 Isolated N-2 & N-3 6,891'6,916'5,893'5,913'25'Jun-94 Isolated _____________________________________________________________________________________ Updated By: CJD 8/26/25 Proposed Schematic North Cook Inlet Unit Well:NCI A-07 Last Completed:06/14/20 PTD:169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4”51 J-55 BT&C 9.850 Surf 528' 45.5 J-55 BT&C 9.950 528'2,522’ 7” 26 J-55 BT&C 6.276 Surf 79’ 23 J-55 BT&C 6.366 79’7,100’ 26 J-55 BT&C 6.276 7,100’8,108’ TUBING DETAIL 3-1/2”9.2 L-80 IBT 2.992”3,450’ (cut)3,549’ 3-1/2”9.2 L-80 8RD EUE 2.992”3,549’4,318’ 4-1/2”12.75 J-55 Mod EUE 8rd 3.958"4,318’5,129’ 4-1/2”12.75 J-55 EUE 8rd 3.958"5,129’6,925’ PERFORATION DETAIL Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status Sterling Z 3,998’ 4,018’ 3,539 3,555’20’02/16/21 Open Stray 2 4,054’ 4,069’ 3,583’ 3,595’15’06/13/20 Open Stray 3 4,090’ 4,100’ 3,612’ 3,620’10’06/13/20 Open Sterling A 4,118’ 4,123’ 3,635’ 3,639’5’06/03/20 Isolated Sterling B 4,170’4,175’3,676’3,680’5’05/30/20 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 2 3,354’3,028’2.867”GLM #2–SPM–1 20 Orifice 5/30/2021 CEMENT DETAILS 10-3/4”15” hole: Pumped 1020sxs 11.5ppg class G lead followed by 125sxs 15.6ppg class G tail.Assumed ToC to surface 7” 9-5/8” Hole: Pumped 525sxs 13ppg class G primary stage. Saw 20bbls primary stage back to surface when circ’d through stage collar.Primary ToC at stage collar (5,211’ MD) Second stage:Pumped 760sxs 14.9ppg class G second stage cement through stage collar at 5211’ MD.Lost partial returns with 25bbls remaining in displacement.5/23/20 CBL shows second stage ToC at 2,525’ MD 3-1/2” Scab Pumped 25.7bbls of 15.8ppg cement into 3-1/2” x 7” annulus. Circ’d cement off liner top at 3,549’ MD. 5/25/20 CBL shows ToC to ToL JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 2 2,710’Whipstock 3 3,350’ Cement Retainer Pump 20 bbls below / 16 bbls on top (Planned TOC @ ±2,950’) 4 3,457’3,110’3.000”6.000”7" 3 1/2" DLH Packer (46k Shear release) 5 3,501’3,144’2.813”3.750”X-Nipple 6 3,532’3,169’2.992”3.500”Dummy seal bore Assembly 7 3,549’3,182’4.176”5.924”ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 8 4,109’3,627’2.750”CIBP w/3.6’ cement 9 4,111’3,629’2.750”CIBP 10 4,165’3,672’2.750”CIBP w/ 18’ cement 11 4,318’3,794’Landing collar and float Assembly 12 4,318’3,794’Tubing Cut A 4,328’3,802’1.71 3.125 Profile Nipple R Nipple B 4,329’3,803’3.813 5.030 Halliburton X Nipple w/ plug set _____________________________________________________________________________________ Updated By: CJD 08/26/25 SCHEMATIC North Cook Inlet Unit Well:NCI A-07 Last Completed:06/14/20 PTD:169-058 ISOLATED JEWELRY No Depth (MD) Depth (TVD)ID OD Item C 4,370’3,806’3.992 5.080 Ratch Latch Seal Unit 4,371’3,806’3.880 5.980 Halliburton VSR Packer D 4,591’4,013’3.813 5.530 Halliburton XD Sliding Sleeve (Closed) E 4,605’4,024’3.992 5.560 Halliburton No-Go Locator 4,606’4,025’4.000 5.815 Halliburton TWR Packer & Millout Extension F 4,711’4,109’3.813 5.530 Halliburton XD Sliding Sleeve (Closed) G 4,723’4,119’3.992 5.080 Halliburton No-Go Seal Unit 4,724’4,120’4.000 5.815 Halliburton TWR Packer & Millout Extension H 4,849’4,222’3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) I 4,861’4,232’3.950 5.080 Halliburton No-Go Seal Unit 4,862’4,233’4.000 5.815 Halliburton TWR Packer & Millout Extension J 4,943’4,299’3.950 5.080 Ratch Latch Seal Unit 4,944’4,299’4.000 5.815 Halliburton TWR Packer & Millout Extension K 5,080’4,411’3.813 5.530 Halliburton XA Sliding Sleeve (Closed) L 5,116’4,441’3.950 5.080 Ratch Latch Seal Unit 5,117’4,441’4.000 5.815 Halliburton TWR Packer & Millout Extension M 5,601’4,841’3.813 5.530 Halliburton XD Sliding Sleeve (Open) N 6,294’5,410’3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) O 6,893’5,984’3.725 5.030 Halliburton XN Nipple P 6,925’5,920’3.992 5.580 WLREG ISOLATED PERFORATION DETAIL Zone Top (MD)Btm (MD)Top (TVD)Btm (TVD)FT Date Status CI-1.0 4,406'4,476'3,864'3,920'70'Jun-94 Isolated CI-2.0 4,494'4,574'3,935'3,999'80'Jun-94 Isolated CI-3.1 4,624'4,634'4,039'4,047'10'Jun-94 Isolated CI-4.0 4,651'4,701'4,061'4,101'50'Jun-94 Isolated CI-5.0 4,746'4,786'4,138'4,171'40'Jun-94 Isolated CI-6.0 4,831'4,841'4,207'4,215'10'Jun-94 Isolated CI-7.0 4,878'4,903'4,246'4,266'25'Jun-94 Isolated CI-8.0 4,963'4,970'4,315'4,321'7'Jun-94 Isolated CI-9.0 5,053'5,072'4,389'4,404'19'Jun-94 Isolated C-4 5,587'5,592'4,829'4,833'5'Jun-94 Isolated D-1 5,628'5,633'4,863'4,867'5'Jun-94 Isolated D-2 5,645'5,655'4,877'4,885'10'Jun-94 Isolated E-9 5,901'5,906'5,089'5,093'5'Jun-94 Isolated F-3 & F-4 5,970'5,995'5,146'5,167'25'Jun-94 Isolated G-1 6,058'6,068'5,218'5,226'10'Jun-94 Isolated H-1.1 6,180'6,185'5,317'5,321'5'Jun-94 Isolated H-2 6,193'6,203'5,328'5,336'10'Jun-94 Isolated H-4 & H-5 6,223'6,243'5,352'5,368'20'Jun-94 Isolated H-6 & H-7 6,254'6,279'5,377'5,398'25'Jun-94 Isolated H-7.1 6,285'6,290'5,403'5,407'5'Jun-94 Isolated H-9 6,340'6,347'5,447'5,453'7'Jun-94 Isolated J-1 6,495'6,505'5,573'5,581'10'Jun-94 Isolated J-3 6,533'6,548'5,604'5,616'15'Jun-94 Isolated K-1 6,566'6,571'5,630'5,634'5'Jun-94 Isolated K-2 6,584'6,591'5,645'5,651'7'Jun-94 Isolated K-5 6,638'6,648'5,689'5,697'10'Jun-94 Isolated M-4 6,746'6,753'5,776'5,781'7'Jun-94 Isolated N-2 & N-3 6,891'6,916'5,893'5,913'25'Jun-94 Isolated Well Prognosis Well: NCIU A-07 Date: 8/26/25 1. BOP N/U and Test 1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug 2. N/U to 16-3/4 5M clamp hub 3. N/U 13-5/8” x 5M BOP as follows (top down): x 13-5/8” x 5M Shaffer annular BOP. x 13-5/8” Shaffer Type “SL” Double ram. (2-7/8” X 5” VBR in top cavity, blind ram in btm cavity) x 13-5/8” mud cross x 13-5/8” Shaffer Type “SL” single ram. (2-7/8” X 5” VBR) x N/U pitcher nipple, install flowline. x Install (2) manual valves on kill side of mud cross. Manual valve used as inside or “master valve”. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. x 16-3/4” 5M Clamp hub adapter required 4. Test BOPE. x Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. x Ensure to leave “A” section side outlet valves open during BOP testing so pressure does not build up beneath the TWC. Confirm the correct valves are opened!!! x Test VBRs on 3.5” and 4.5”test joints (3000 psi) x Test Annular on 3.5” test joint (2500 psi) x Ensure gas monitors are calibrated and tested in conjunction w/ BOPE. 5. Pull Blanking plug and BPV 2. Preparatory Work and Mud Program 1. Mix 9.0 WBM mud for 6-1/8” hole section. 2. 6” liners installed in mud pump #1 and pump #2. (PZ-10’s) x Gardner Denver PZ-10’s Pumps are rated at 4932 psi (98%) with 6” liners and can deliver 422 gpm at 115 spm. x Pump range for drilling will be 150-300 gpm. This can be achieved with one or both pumps. Well Prognosis Well: NCIU A-07 Date: 8/26/25 3. 6-1/8” Production hole mud program summary: x Primary weighting material to be used for the hole section will be barite to minimize solids. Ensure enough barite is on location to weight up the active system 1ppg above highest anticipated MW in the event of a well control situation. x Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:LNSD WBM Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 2710’- TD 8.8-10.3 40-53 6-15 13-24 8.5-9.5 ч 11.0 System Formulation: 2% KCL/BDF-976/GEM GP Product Concentration Water KCl Caustic BARAZAN D+ DEXTRID LT PAC L BDF-976 GEM GP BARACARB 5/25/50 STEELSEAL 50/100/400 BAROFIBRE BAROTROL PLUS SOLTEX BAROID 41 ALDACIDE-G 0.905 bbl 7 ppb 0.2 ppb (9 pH) 1.0 ppb (as required 18 YP) 1-2 ppb 1 ppb 4 ppb 1.0% by volume 5 ppb (1.7 ppb of each) 5 ppb (1.7 ppb of each) 1.7 ppb 4.0 ppb 2 – 4 ppb as needed 0.1 ppb Well Prognosis Well: NCIU A-07 Date: 8/26/25 4. Program mud weights are generated by reviewing data from producing & shut in offset wells, estimated BHP’s from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 5. A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation. 3. Decomplete, Plug parent wellbore Operation Steps: 1. Pull 4-1/2” tubing from the pre-rig cut at 3450’ 2. Set wear bushing in wellhead. Ensure ID of wear bushing >6-1/8”. 3. PU 7” cement retainer and set at 3350’ 4. Pump 20 bbls of 15.3# below the retainer x ~10 bbls to bottom perf 5. Unsting from retainer and lay in ~400’ of cement above the retainer (~16 bbls) x Annular 7” cement at 2525’ per 05/23/2020 CBL 6.Provide AOGGC notice of the opportunity to witness test and tag 7. WOC, Tag cement 8. Pressure test 7” casing to 2635 psi. x 7” 23# J-55 Burst = 4360 psi 4. Set Whipstock, Mill Window Operation Steps: 1. Make up the WIS hydraulic set Whipstock. 2. TIH with DP to the whipstock setting depth. Exercise caution when RIH / setting slips with whipstock assembly ¾Fill the drill pipe a minimum of every 20 stands on the trip in the hole with the whipstock assembly. ¾Avoid sudden starts and stops while running the whipstock. Well Prognosis Well: NCIU A-07 Date: 8/26/25 ¾Recommend running in the hole at a maximum of 90-120 seconds per stand taking care not to spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the work string to RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms and / or to avoid part / preset on the packer. 3. Orient whipstock as directed by the directional driller. The directional plan specifies 150 deg LOHS. 4. Set the top of the whipstock at ~2710’ MD x 7” Collar location per tally and 2020 CBL (top log depth is 2350’) Mill Window under drilling permit. Well Prognosis Well: NCIU A-07 Date: 8/26/25 BOPE Schematic Sundry Application Well Name______________________________ (PTD _________; Sundry _________) Plug for Re-drill Well Workflow This process is used to identify wells that are suspended for a very short time prior to being re-drilled. Those wells that are not re-drilled immediately are identified every 6 months and assigned a current status of "Suspended." Step Task Responsible 1 The initial reviewer will check to ensure that the "Plug for Redrill" box in the upper left corner of Form 10-403 is checked. If the "Abandon" or "Suspend" boxes are also checked, cross out that erroneous entry and initial it on the Form 10-403. Geologist 2 If the “Abandon” box is checked in Box 15 (Well Status after proposed work) the initial reviewer will cross out that checkbox and instead, check the "Suspended" box and initial those changes. Geologist The drilling engineer will serve as quality control for steps 1 and 2. Petroleum Engineer (QC) 3 When the RA2 receives a Form 10-403 with a check in the "Plug for Redrill" box, they will enter the Typ_Work code "IPBRD" into the History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." Research Analyst 2 4 When the RA2 receives Form 10-407, they will check the History tab in RBDMS for the IPBRD code. If IPBRD is present and there is no evidence that a subsequent re-drill has been completed, the RA2 will assign a status of SUSPENDED to the well bore in RBDMS. The RA2 will update the status on the 10-407 form to SUSPENDED, and date and initial this change. If the RA2 does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. Research Analyst 2 5 When the Form 10-407 for the redrill is received, the RA2 will change the original well's status from SUSPENDED to ABANDONED. Research Analyst 2 6 The first week of every January and July, the RA2 and a Geologist or Reservoir Engineer will check the "Well by Type Work Outstanding" user query in RBDMS to ensure that all Plug for Redrill sundried wells have been updated to reflect current status. At this same time, they will also review the list of suspended wells for accuracy and assign expiration dates as needed. Research Analyst 2 Geologist or Reservoir Engineer CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:AOGCC Permitting (CED sponsored) To:Brooks, James S (OGC) Subject:FW: Withdraw Sundry # 324-578 - N Cook Inlet Unit A-07 PTD: 169-058 Date:Thursday, July 3, 2025 9:55:39 AM Attachments:10-403 N Cook Inlet Unit A-07 PTD 169-058_Sundry_324-578_Approved_101724.pdf Hi James, Please see the email below and withdraw this sundry. Have a Happy 4th, Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 From: Juanita Lovett <jlovett@hilcorp.com> Sent: Thursday, July 3, 2025 9:36 AM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Eric Dickerman <Eric.Dickerman@hilcorp.com> Subject: Withdraw Sundry # 324-578 - N Cook Inlet Unit A-07 PTD: 169-058 Please withdraw the above-mentioned sundry. Scope of work was to remove the sand screen, plug the well back, and perforate uphole Sterling sands. Thank you, 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,126 N/A Casing Collapse Structural Conductor Surface 2,090psi Intermediate Production 3,270psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Ryan Rupert Contact Email:Ryan.Rupert@hilcorp.com Contact Phone:(907) 777-8503 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng CO 68A Other: N2 Operations 10/17/2024 See schematic See schematic See schematic 8,108' Perforation Depth MD (ft): 3,998 - 4,100 8,108' 3,539 - 3,620 6,905'7" 30" 10-3/4" 388' 2,522' MD 3,580psi 388' 2,364' 388' 2,522' Length Size Proposed Pools: See schematic TVD Burst 6,925 4,360psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 169-058 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20027-00-00 Hilcorp Alaska, LLC N Cook Inlet Unit A-07 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY North Cook Inlet Tertiary System Gas Same 6,920 4,109 3,627 1,267psi See schematic No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:52 am, Oct 03, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.10.03 09:16:23 - 08'00' Dan Marlowe (1267) BJM 10/15/24 SFD 10/4/2024 10-404 DSR-10/10/24JLC 10/16/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.17 03:22:45 -08'00'10/17/24 RBDMS JSB 101724 Perforate Well: NCIU A-07 Well Name:NCIU A-07 API Number:50-883-20027-00-00 Current Status:Offline Gas Producer Leg:Leg #3 (SE corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:169-058 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:1,629 psi @ 3,620’ TVD 0.45psi/ft to deepest open perf Max. Potential Surface Pressure: 1267 psi Using 0.1 psi/ft Brief Well Summary A-07 is a shut-in Sterling gas producer. The well was plugged back and recompleted to the upper Sterling in 2Q- 2020. After a few plug and perfs, production was sustained from the stray 2&3 sands. By Feb-2021 the well was producing ~1MMCFD at 300psi FTP. It was shut in to pull the WL-SSSV in preparation for a perf add. Fill was found above the top perf. This was bailed out, and the Sterling Z shot. This comingled well lasted for ~1month before dying in March-2021. SL got on the well in May-2021, and set a sand screen in the X-profile at 3501’ MD. No meaningful production was sustained, and in July-2021 SL pulled the sand screen. The well has remained dead since. The goal of this project is to remove the sand screen, plug the well back, and perforate uphole Sterling sands Pertinent wellbore information: x SSSV: o Has hydraulic landing profile o WL-SSSV is currently NOT installed x Max Inclination: 38 degrees below 2000’ MD x 2020 RWO o Isolated perfs below 4329’ MD o Installed 3-1/2” scab liner from 3549’ – 4318’ MD o Cemented scab in place x 2/16/21: EL tagged at 4045’ MD with a 2-3/8” x 20’ perf gun, and shot Sterling-Z sand x 5/9/21 o Set sand screen at 3501’ MD o Set WL-SSSV, but had to modify packing. Had issues with lock as well (but got it) x 7/6/21: o Pulled WL-SSSV o Latch sand screen at 3501’ MD, moved it uphole 2-6’ o Successfully pulled sand screen on day 2 (no drift after that) Perforate Well: NCIU A-07 E-Line Plug and Perf procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 1500psi high 3. RIH and set 3-1/2” patch across existing Sterling Z sand perfs from 3,998 – 4018’ MD 4. Flow test well 5. Perforate / reperforate Middle Kenai Gas Pool sands from ±3,635 - ±4,109’ MD (±3,250’ - ±3,627’ TVD) per RE/Geo a. All proposed perfs are within Tertiary System Gas Pool b. Top pool is at 3626’ MD (3243’ TVD) c. Bottom pool is well below PBTD 6. RDMO EL CONTINGENCY patch or plug: (if any zone makes unwanted solids or water) 1. RU nitrogen or gas lift to tubing and PT lines to 1500psi (or higher if needed) 2. Pressure up on tubing and displace water back into formation 3. MIRU E-line and pressure control equipment 4. PT lubricator to 250psi low / 1500psi high 5. Set 3-1/2” isolation plug or patch per OE 6. RDMO Nitrogen and EL Note: WL_SSSV will need to be reset and state tested per regulation after the above interventions Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Nitrogen procedure Top pool is at 3626’ MD (3243’ TVD)Agree. SFD Tertiary System Gas Pool _____________________________________________________________________________________ Updated By: JLL 10/02/24 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4”51 J-55 BT&C 9.850 Surf 528' 45.5 J-55 BT&C 9.950 528' 2,522’ 7” 26 J-55 BT&C 6.276 Surf 79’ 23 J-55 BT&C 6.366 79’ 7,100’ 26 J-55 BT&C 6.276 7,100’8,108’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surf 383’ 3-1/2” 9.2 L-80 IBT 2.992” 383’ 3,549’ 3-1/2” 9.2 L-80 8RD EUE 2.992” 3,549’ 4,318’ 4-1/2” 12.75 J-55 Mod EUE 8rd 3.958" 4,318’ 5,129’ 4-1/2” 12.75 J-55 EUE 8rd 3.958" 5,129’ 6,925’ PBTD: 4,109’ TD: 8,126’ 2 30” RKB: 39.40’, RKB to MSL: 116’ RKB to Mudline: 236’ 7” 3 4 56 A C D E F G H I J K L M 10-3/4” 1 TOC @ 2,525’ N O P B Fill @ 4,837’ CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-8.0 CI-9.0 C-4 Thru N-3 Ci 1.0 CI-2.0 Tubing cut @ 4,318’ 12 Stray 2 Sterling Z Stray 3 Sterling A Sterling B10 7 8 9 Stage Collar @ 5,211' 11 XN R X PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Sterling Z 3,998’ 4,018’ 3,539 3,555’ 20’ 02/16/21 Open Stray 2 4,054’ 4,069’ 3,583’ 3,595’ 15’ 06/13/20 Open Stray 3 4,090’ 4,100’ 3,612’ 3,620’ 10’ 06/13/20 Open Sterling A 4,118’ 4,123’ 3,635’ 3,639’ 5’ 06/03/20 Isolated Sterling B 4,170’ 4,175’ 3,676’ 3,680’ 5’ 05/30/20 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,766’ 1,734’ 2.867” GLM #1 – SPM – 1 Dummy 5/29/2020 2 3,354’ 3,028’ 2.867” GLM #2 – SPM – 1 20 Orifice 5/30/2021 CEMENT DETAILS 10-3/4”15” hole: Pumped 1020sxs 11.5ppg class G lead followed by 125sxs 15.6ppg class G tail.Assumed ToC to surface 7” 9-5/8” Hole: Pumped 525sxs 13ppg class G primary stage. Saw 20bbls primary stage back to surface when circ’d through stage collar.Primary ToC at stage collar (5,211’ MD) Second stage: Pumped 760sxs 14.9ppg class G second stage cement through stage collar at 5211’ MD. Lost partial returns with 25bbls remaining in displacement. 5/23/20 CBL shows second stage ToC at 2,525’ MD 3-1/2” Scab Pumped 25.7bbls of 15.8ppg cement into 3-1/2” x 7” annulus. Circ’d cement off liner top at 3,549’ MD. 5/25/20 CBL shows ToC to ToL JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 26.07’ 26.07’ Hanger Vetco 4 1/2 IBTsusp, 4.909 MCA lift threads, 4" Type H BPV profile 1 343’ 343’ 3.813 5.400 Nipple, Camco BP-6I Landing WRDP, DB lock -No WL-SSSV installed as of 7/5/21 2 383’ 383’ 3.000 5.210 4-1/2” x 3-1/2” Crossover 3 3,404’ 3,068’ 2.867” 5.313” Chemical Injection Mandrel 4 3,457’ 3,110’ 3.000” 6.000” 7" 3 1/2" DLH Packer (46k Shear release) 5 3,501’ 3,144’ 2.813” 3.750” X-Nipple 6 3,532’ 3,169’ 2.992” 3.500” Dummy seal bore Assembly 7 3,549’ 3,182’ 4.176” 5.924” ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 8 4,109’ 3,627’ 2.750” CIBP w/3.6’ cement 9 4,111’ 3,629’ 2.750” CIBP 10 4,165’ 3,672’ 2.750” CIBP w/ 18’ cement 11 4,318’ 3,794’ Landing collar and float Assembly 12 4,318’ 3,794’ Tubing Cut A 4,328’ 3,802’ 1.71 3.125 Profile Nipple R Nipple B 4,329’ 3,803’ 3.813 5.030 Halliburton X Nipple w/ plug set _____________________________________________________________________________________ Updated By: JLL 10/02/24 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 ISOLATED JEWELRY No Depth (MD) Depth (TVD)ID OD Item C 4,370’ 3,806’ 3.992 5.080 Ratch Latch Seal Unit 4,371’ 3,806’ 3.880 5.980 Halliburton VSR Packer D 4,591’ 4,013’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) E 4,605’ 4,024’ 3.992 5.560 Halliburton No-Go Locator 4,606’ 4,025’ 4.000 5.815 Halliburton TWR Packer & Millout Extension F 4,711’ 4,109’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) G 4,723’ 4,119’ 3.992 5.080 Halliburton No-Go Seal Unit 4,724’ 4,120’ 4.000 5.815 Halliburton TWR Packer & Millout Extension H 4,849’ 4,222’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) I 4,861’ 4,232’ 3.950 5.080 Halliburton No-Go Seal Unit 4,862’ 4,233’ 4.000 5.815 Halliburton TWR Packer & Millout Extension J 4,943’ 4,299’ 3.950 5.080 Ratch Latch Seal Unit 4,944’ 4,299’ 4.000 5.815 Halliburton TWR Packer & Millout Extension K 5,080’ 4,411’ 3.813 5.530 Halliburton XA Sliding Sleeve (Closed) L 5,116’ 4,441’ 3.950 5.080 Ratch Latch Seal Unit 5,117’ 4,441’ 4.000 5.815 Halliburton TWR Packer & Millout Extension M 5,601’ 4,841’ 3.813 5.530 Halliburton XD Sliding Sleeve (Open) N 6,294’ 5,410’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) O 6,893’ 5,984’ 3.725 5.030 Halliburton XN Nipple P 6,925’ 5,920’ 3.992 5.580 WLREG ISOLATED PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status CI-1.0 4,406' 4,476' 3,864' 3,920'70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999'80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047'10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101'50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171'40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215'10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266'25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321'7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404'19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833'5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867'5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885'10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093'5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167'25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226'10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321'5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336'10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368'20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398'25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407'5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453'7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581'10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616'15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634'5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651'7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697'10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781'7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913'25' Jun-94 Isolated _____________________________________________________________________________________ Updated By: JLL 10/02/24 PROPOSED North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4”51 J-55 BT&C 9.850 Surf 528' 45.5 J-55 BT&C 9.950 528' 2,522’ 7” 26 J-55 BT&C 6.276 Surf 79’ 23 J-55 BT&C 6.366 79’ 7,100’ 26 J-55 BT&C 6.276 7,100’8,108’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surf 383’ 3-1/2” 9.2 L-80 IBT 2.992” 383’ 3,549’ 3-1/2” 9.2 L-80 8RD EUE 2.992” 3,549’ 4,318’ 4-1/2” 12.75 J-55 Mod EUE 8rd 3.958" 4,318’ 5,129’ 4-1/2” 12.75 J-55 EUE 8rd 3.958" 5,129’ 6,925’ PBTD: 4,109’ TD: 8,126’ 2 30” RKB: 39.40’, RKB to MSL: 116’ RKB to Mudline: 236’ 7” 3 4 56 A C D E F G H I J K L M 10-3/4” 1 TOC @ 2,525’ N O P B Fill @ 4,837’ CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-8.0 CI-9.0 C-4 Thru N-3 Ci 1.0 CI-2.0 Tubing cut @ 4,318’ 12 Stray 2 Sterling Z Stray 3 Sterling A Sterling B10 7 8 9 Stage Collar @ 5,211' 11 XN R X PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status ±3,635 ±4,109 ±3,250 ±3,627 ±474' Future Perf/Re-perf Sterling Z 3,998’ 4,018’ 3,539 3,555’ 20’ Future Isolate Stray 2 4,054’ 4,069’ 3,583’ 3,595’ 15’ 06/13/20 Open Stray 3 4,090’ 4,100’ 3,612’ 3,620’ 10’ 06/13/20 Open Sterling A 4,118’ 4,123’ 3,635’ 3,639’ 5’ 06/03/20 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,766’ 1,734’ 2.867” GLM #1 – SPM – 1 Dummy 5/29/2020 2 3,354’ 3,028’ 2.867” GLM #2 – SPM – 1 20 Orifice 5/30/2021 CEMENT DETAILS 10-3/4”15” hole: Pumped 1020sxs 11.5ppg class G lead followed by 125sxs 15.6ppg class G tail.Assumed ToC to surface 7” 9-5/8” Hole: Pumped 525sxs 13ppg class G primary stage. Saw 20bbls primary stage back to surface when circ’d through stage collar.Primary ToC at stage collar (5,211’ MD) Second stage: Pumped 760sxs 14.9ppg class G second stage cement through stage collar at 5211’ MD. Lost partial returns with 25bbls remaining in displacement. 5/23/20 CBL shows second stage ToC at 2,525’ MD 3-1/2” Scab Pumped 25.7bbls of 15.8ppg cement into 3-1/2” x 7” annulus. Circ’d cement off liner top at 3,549’ MD. 5/25/20 CBL shows ToC to ToL JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 26.07’ 26.07’ Hanger Vetco 4 1/2 IBTsusp, 4.909 MCA lift threads, 4" Type H BPV profile 1 343’ 343’ 3.813 5.400 Nipple, Camco BP-6I Landing WRDP, DB lock -No WL-SSSV installed as of 7/5/21 2 383’ 383’ 3.000 5.210 4-1/2” x 3-1/2” Crossover 3 3,404’ 3,068’ 2.867” 5.313” Chemical Injection Mandrel 4 3,457’ 3,110’ 3.000” 6.000” 7" 3 1/2" DLH Packer (46k Shear release) 5 3,501’ 3,144’ 2.813” 3.750” X-Nipple 6 3,532’ 3,169’ 2.992” 3.500” Dummy seal bore Assembly 7 3,549’ 3,182’ 4.176” 5.924” ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 8 4,109’ 3,627’ 2.750” CIBP w/3.6’ cement 9 4,111’ 3,629’ 2.750” CIBP 10 4,165’ 3,672’ 2.750” CIBP w/ 18’ cement 11 4,318’ 3,794’ Landing collar and float Assembly 12 4,318’ 3,794’ Tubing Cut A 4,328’ 3,802’ 1.71 3.125 Profile Nipple R Nipple B 4,329’ 3,803’ 3.813 5.030 Halliburton X Nipple w/ plug set _____________________________________________________________________________________ Updated By: JLL 10/02/24 PROPOSED North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 ISOLATED JEWELRY No Depth (MD) Depth (TVD)ID OD Item C 4,370’ 3,806’ 3.992 5.080 Ratch Latch Seal Unit 4,371’ 3,806’ 3.880 5.980 Halliburton VSR Packer D 4,591’ 4,013’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) E 4,605’ 4,024’ 3.992 5.560 Halliburton No-Go Locator 4,606’ 4,025’ 4.000 5.815 Halliburton TWR Packer & Millout Extension F 4,711’ 4,109’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) G 4,723’ 4,119’ 3.992 5.080 Halliburton No-Go Seal Unit 4,724’ 4,120’ 4.000 5.815 Halliburton TWR Packer & Millout Extension H 4,849’ 4,222’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) I 4,861’ 4,232’ 3.950 5.080 Halliburton No-Go Seal Unit 4,862’ 4,233’ 4.000 5.815 Halliburton TWR Packer & Millout Extension J 4,943’ 4,299’ 3.950 5.080 Ratch Latch Seal Unit 4,944’ 4,299’ 4.000 5.815 Halliburton TWR Packer & Millout Extension K 5,080’ 4,411’ 3.813 5.530 Halliburton XA Sliding Sleeve (Closed) L 5,116’ 4,441’ 3.950 5.080 Ratch Latch Seal Unit 5,117’ 4,441’ 4.000 5.815 Halliburton TWR Packer & Millout Extension M 5,601’ 4,841’ 3.813 5.530 Halliburton XD Sliding Sleeve (Open) N 6,294’ 5,410’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) O 6,893’ 5,984’ 3.725 5.030 Halliburton XN Nipple P 6,925’ 5,920’ 3.992 5.580 WLREG ISOLATED PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status CI-1.0 4,406' 4,476' 3,864' 3,920'70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999'80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047'10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101'50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171'40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215'10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266'25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321'7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404'19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833'5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867'5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885'10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093'5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167'25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226'10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321'5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336'10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368'20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398'25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407'5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453'7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581'10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616'15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634'5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651'7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697'10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781'7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913'25' Jun-94 Isolated STANDARD WELL PROCEDURE NITROGEN OPERATIONS 09/23/2016 FINAL v-offshore Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure supplier has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank. Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE : 03/05/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NCI A-07 (PTD 169-058) PERFORATING RECORD 01/16/2021 Please include current contact information if different from above. PTD: 1690580 E-Set: 34751 Received by the AOGCC 03/08/2021 03/09/2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 8,126 feet See schematic feet true vertical 6,920 feet N/A feet Effective Depth measured 4,109 feet See schematic feet true vertical 3,627 feet See schematic feet Perforation depth Measured depth 3,998 - 4,100 feet True Vertical depth 3,539 - 3,620 feet Tubing (size, grade, measured and true vertical depth)See schematic 6,925 (MD) / 5,920 (TVD) Packers and SSSV (type, measured and true vertical depth)See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Authorized Title: Contact Email: Contact Phone: Hilcorp Alaska, LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Daniel E. Marlowe Operations Manager Burst Collapse Katherine O'Connor Katherine.oconnor@hilcorp.com Tubing Pressure 2,090psi3,580psi 907 777-8376 4,360psi 388 2,364 6,905 388 2,522 Conductor Surface 3,270psi 30" 10-3/4" 8,108 Size 690 Production Casing Structural Liner Length Intermediate N/A Junk 5. Permit to Drill Number: 1,129 North Cook Inlet Unit / Tertiary Gas PoolN/A measured 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 275 N/A Oil-Bbl 926 Water-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-050 255 Authorized Signature with date: Authorized Name: 129 WINJ WAG STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 169-058 50-883-20027-00-00 Plugs ADL0017589 N Cook Inlet Unit A-07 Other: measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 2480 Casing Pressure 8,108 MD 388 2,522 TVD measured true vertical Packer 7" PL G Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 10:20 am, Mar 04, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.03.03 15:30:37 -09'00' Dan Marlowe (1267) DSR-3/4/21 SFD 3/12/2021RBDMS HEW 3/5/2021 BJM 4/6/21 _____________________________________________________________________________________ Updated By: JLL 03/02/21 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4” 45.5 & 51 J-55 BT&C Surf 2,522’ 7” 26 J-55 BT&C Surf 79’ 23 J-55 BT&C 79’ 7,100’ 26 J-55 BT&C 7,100’8,108’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surf 383’ 3-1/2” 9.2 L-80 IBT 2.992” 383’ 3,549’ 3-1/2” 9.2 L-80 8RD EUE 2.992” 3,549’ 4,318’ 4-1/2” 12.75 J-55 Mod EUE 8rd 4,318’ 5,129’ 4-1/2” 12.75 J-55 EUE 8rd 5,129’ 6,925’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 26.07’ 26.07’ Hanger Vetco 4 1/2 IBTsusp, 4.909 MCA lift threads, 4" Type H BPV profile 1 343’ 343’ 3.813 5.400 Nipple, Camco BP-6I Landing WRDP, DB lock 2 383’ 383’ 3.000 5.210 4-1/2” x 3-1/2” Crossover 3 1,766’ 1,734’ 2.867” 5.313” GLM #1 –SPM –1; Dummy Valve 3,354’ 3,028’ 2.867” 5.313” GLM #2 –SPM –1; Orifice 20/64” 4 3,404’ 3,068’ 2.867” 5.313” Chemical Injection Mandrel 5 3,457’ 3,110’ 3.000” 6.000” 7" 3 1/2" DLH Packer (46k Shear release) 6 3,501’ 3,144’ 2.813” 3.750” X-Nipple 7 3,532’ 3,169’ 2.992” 3.500” Dummy seal bore Assembly 8 3,549’ 3,182’ 4.176” 5.924” ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 9 4,109’ 3,627’ 2.750” CIBP w/3.6’ cement 10 4,111’ 3,629’ 2.750” CIBP 11 4,165’ 3,672’ 2.750” CIBP w/ 18’ cement 12 4,318’ 3,794’ Landing collar and float Assembly 13 4,318’ 3,794’ Tubing Cut A 4,328’ 3,802’ 1.71 3.125 Profile Nipple R Nipple B 4,329’ 3,803’ 3.813 5.030 Halliburton X Nipple w/ plug set C 4,370’ 3,806’ 3.992 5.080 Ratch Latch Seal Unit 4,371’ 3,806’ 3.880 5.980 Halliburton VSR Packer D 4,591’ 4,013’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) E 4,605’ 4,024’ 3.992 5.560 Halliburton No-Go Locator 4,606’ 4,025’ 4.000 5.815 Halliburton TWR Packer & Millout Extension F 4,711’ 4,109’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) G 4,723’ 4,119’ 3.992 5.080 Halliburton No-Go Seal Unit 4,724’ 4,120’ 4.000 5.815 Halliburton TWR Packer & Millout Extension H 4,849’ 4,222’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) I 4,861’ 4,232’ 3.950 5.080 Halliburton No-Go Seal Unit 4,862’ 4,233’ 4.000 5.815 Halliburton TWR Packer & Millout Extension J 4,943’ 4,299’ 3.950 5.080 Ratch Latch Seal Unit 4,944’ 4,299’ 4.000 5.815 Halliburton TWR Packer & Millout Extension K 5,080’ 4,411’ 3.813 5.530 Halliburton XA Sliding Sleeve (Closed) L 5,116’ 4,441’ 3.950 5.080 Ratch Latch Seal Unit 5,117’ 4,441’ 4.000 5.815 Halliburton TWR Packer & Millout Extension M 5,601’ 4,841’ 3.813 5.530 Halliburton XD Sliding Sleeve (Open) N 6,294’ 5,410’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) O 6,893’ 5,984’ 3.725 5.030 Halliburton XN Nipple P 6,925’ 5,920’ 3.992 5.580 WLREG PBTD: 4,109’ TD: 8,126’ 2 30” RKB: 39.40’, RKB to MSL: 116’ RKB to Mudline: 236’ 7” 3 4 5 67 A C D E F G H I J K L M 10-3/4” 1 TOC @ 2,510’ N O P B Fill @ 4,837’ CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-8.0 CI-9.0 C-4 D-1 K-1 D-2 E-9 F3 & F-4 G-1 H-1.1 H-2 H-4 & H-5 H-6 & H-7 H-7.1 H-9 J-1 J-3 K-2 K-5 M-4 N-2 & N-3 Ci 1.0 CI-2.0 Tubing cut @ 4,318’ 13 Stray 2 Sterling Z Stray 3 Sterling A Sterling B11 8 9 10 12 XN X R X _____________________________________________________________________________________ Updated By: JLL 03/02/21 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Sterling Z 3,998’ 4,018’ 3,539 3,555’ 20’ 02/16/21 Open Stray 2 4,054’ 4,069’ 3,583’ 3,595’ 15’ 06/13/20 Open Stray 3 4,090’ 4,100’ 3,612’ 3,620’ 10’ 06/13/20 Open Sterling A 4,118’ 4,123’ 3,635’ 3,639’ 5’ 06/03/20 Isolated Sterling B 4,170’ 4,175’ 3,676’ 3,680’ 5’ 05/30/20 Isolated CI-1.0 4,406' 4,476' 3,864' 3,920' 70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999' 80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047' 10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101' 50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171' 40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215' 10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266' 25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321' 7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404' 19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833' 5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867' 5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885' 10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093' 5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167' 25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226' 10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321' 5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336' 10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368' 20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398' 25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407' 5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453' 7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581' 10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616' 15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634' 5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651' 7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697' 10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781' 7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913' 25' Jun-94 Isolated Sterling Z 3,998’ 4,018’ 3,539 3,555’ 20’ 02/16/21 Open Rig Start Date End Date Eline 2/16/21 2/16/21 Fly to Tyonek, Check in, get PTW, PJSM. Spot equipment. MIRU ELINE. Make up GR/CCL, test wire, good test. Make up Gun #1, 20', 2.375", 6 spf, 60* phasing razor gun. Head to well, stabbed on well, PT WLV/LUB low/high 250/1500. Open well, WHP 950 PSI, RIH, Tag 4045'. Log up to 3850'. Send log to town for Approval to shoot the Sterling Z sands @ 3998'-4018'. Approval to shoot Sterling Z sands 3998'-4018' (Eng / Geologist) RIH to tag @ 4045'. PU getting on CCL depth @ 3988.8, CCL T/top shot 9.2', CCL T/bottom shot 29.2'. Shoot Sterling Z 3998'-4018', ITP 940, FTP 940. Log up 200', POOH, Tagged up, swab shut, bleed down, pop off well. All shots fired, Wet bull nose. RDMO. 02/16/21 - Tuesday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 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): North Cook Inlet / Tertiary Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,126'N/A Casing Collapse Structural Conductor Surface 2,090 psi Intermediate Production 3,270 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 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 169-058 50-883-20027-00-00 Authorized Signature: Operations Manager Katherine O'Connor CO 68A PRESENT WELL CONDITION SUMMARY See schematic6,920' 4,109' 3,627' 1,382 psi COMMISSION USE ONLY Authorized Name: Burst 6,925 4,360 psi Tubing Size: Anchorage, AK 99503 Hilcorp Alaska, LLC N Cook Inlet Unit A-07 MDLength Size 3,580 psi 388' 2,364' 388' 2,522' TVD 30" 10-3/4" 388' 2,522' Perforation Depth MD (ft): 4,054 - 4,100 8,108' Packers - see schematic & 343 (MD) 343 (TVD) Tubing Grade:Tubing MD (ft): 3,583 - 3,620 Perforation Depth TVD (ft): See schematic 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. 2/14/2021 See schematic Daniel E. Marlowe Packers (x8) see schematic &Camco BP-6I Other: 6,905'7" 8,108' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 11:50 am, Jan 26, 2021 321-050 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.01.26 08:36:31 -09'00' Dan Marlowe (1267) Perforate 10-404 gls 2/1/21 SFD 1/27/2021 DSR-1/27/21 GAS Comm. ion Required? Yes 2/1/21 dts 2/1 2021 JLC 2/1/2021 RBDMS HEW 2/2/2021 Well Work Prognosis Well Name:NCIU A-07 API Number: 50-883-20027-00 Current Status:Gas Well Leg:3 (SE Corner) Estimated Start Date:02/14/2021 Rig:E-Line Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett Permit to Drill Number:169-058 First Call Engineer:Katherine O’Connor Office: 907-777-8376 Cell: 214-684-7400 Second Call Engineer:Karson Kozub Cell: 907-570-1801 Current Bottom Hole Pressure:940 psi @ 4987’ TVD Maximum Expected BHP:1536 psi @ 3547’ TVD Maximum Potential Surface Pressure:1382 psi Based on 0.1 psi/ft gas gradient Brief Well Summary: A-07 was originally drilled and completed in 1969 as a comingled Cook Inlet and Beluga producer. It had a recomplete in 1994, and in 2005 fill came in and the well never recovered, staying shut in. In mid 2020 the well was recompleted, isolating the CI 1-4 sands with a plug, then installing a cemented liner to selectively allow perforations of the CI-A, CI-B, sterling and Stray 1-4. The objective of this program is to add perfs into the Sterling X and Z sands. E-line Procedure: 1. MIRU E-line, PT lubricator to 1,500 psi Hi 250 Low. 2. Perforate with well flowing per program. 3. RD E-line. 4. Turn well over to production. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic Perf Sterling X and Z sands (see attached wellbore sketch for intervals) _____________________________________________________________________________________ Updated By: JLL 07/10/20 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4” 45.5 & 51 J-55 BT&C Surf 2,522’ 7” 26 J-55 BT&C Surf 79’ 23 J-55 BT&C 79’ 7,100’ 26 J-55 BT&C 7,100’8,108’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surf 383’ 3-1/2” 9.2 L-80 IBT 2.992” 383’ 3,549’ 3-1/2” 9.2 L-80 8RD EUE 2.992” 3,549’ 4,318’ 4-1/2” 12.75 J-55 Mod EUE 8rd 4,318’ 5,129’ 4-1/2” 12.75 J-55 EUE 8rd 5,129’ 6,925’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 26.07’ 26.07’ Hanger Vetco 4 1/2 IBTsusp, 4.909 MCA lift threads, 4" Type H BPV profile 1 343’ 343’ 3.813 5.400 Nipple, Camco BP-6I Landing WRDP, DB lock 2 383’ 383’ 3.000 5.210 4-1/2” x 3-1/2” Crossover 3 1,766’ 1,734’ 2.867” 5.313” GLM #1 –SPM –1; IPOC-1 20/64” 3,354’ 3,028’ 2.867” 5.313” GLM #2 –SPM –1; Orifice 20/64” 4 3,404’ 3,068’ 2.867” 5.313” Chemical Injection Mandrel 5 3,457’ 3,110’ 3.000” 6.000” 7" 3 1/2" DLH Packer (46k Shear release) 6 3,501’ 3,144’ 2.813” 3.750” X-Nipple 7 3,532’ 3,169’ 2.992” 3.500” Dummy seal bore Assembly 8 3,549’ 3,182’ 4.176” 5.924” ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 9 4,109’ 3,627’ 2.750” CIBP w/3.6’ cement 10 4,111’ 3,629’ 2.750” CIBP 11 4,165’ 3,672’ 2.750” CIBP w/ 18’ cement 12 4,318’ 3,794’ Landing collar and float Assembly 13 4,318’ 3,794’ Tubing Cut A 4,328’ 3,802’ 1.71 3.125 Profile Nipple R Nipple B 4,329’ 3,803’ 3.813 5.030 Halliburton X Nipple w/ plug set C 4,370’ 3,806’ 3.992 5.080 Ratch Latch Seal Unit 4,371’ 3,806’ 3.880 5.980 Halliburton VSR Packer D 4,591’ 4,013’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) E 4,605’ 4,024’ 3.992 5.560 Halliburton No-Go Locator 4,606’ 4,025’ 4.000 5.815 Halliburton TWR Packer & Millout Extension F 4,711’ 4,109’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) G 4,723’ 4,119’ 3.992 5.080 Halliburton No-Go Seal Unit 4,724’ 4,120’ 4.000 5.815 Halliburton TWR Packer & Millout Extension H 4,849’ 4,222’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) I 4,861’ 4,232’ 3.950 5.080 Halliburton No-Go Seal Unit 4,862’ 4,233’ 4.000 5.815 Halliburton TWR Packer & Millout Extension J 4,943’ 4,299’ 3.950 5.080 Ratch Latch Seal Unit 4,944’ 4,299’ 4.000 5.815 Halliburton TWR Packer & Millout Extension K 5,080’ 4,411’ 3.813 5.530 Halliburton XA Sliding Sleeve (Closed) L 5,116’ 4,441’ 3.950 5.080 Ratch Latch Seal Unit 5,117’ 4,441’ 4.000 5.815 Halliburton TWR Packer & Millout Extension M 5,601’ 4,841’ 3.813 5.530 Halliburton XD Sliding Sleeve (Open) N 6,294’ 5,410’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) O 6,893’ 5,984’ 3.725 5.030 Halliburton XN Nipple P 6,925’ 5,920’ 3.992 5.580 WLREG PBTD: 7,050’ TD: 8,126’ 2 30” RKB: 39.40’, RKB to MSL: 116’ RKB to Mudline: 236’ 7” 3 4 5 67 A C D E F G H I J K L M 10-3/4” 1 TOC @ 2,510’ N O P B Fill @ 4,837’ CI -3.1 CI-4.0 CI-5.0 CI-6.0 CI -7.0 CI-8.0 CI-9.0 C-4 D-1 K-1 D-2 E-9 F3 & F-4 G-1 H-1.1 H-2 H-4 & H-5 H-6 & H-7 H-7.1 H-9 J-1 J-3 K-2 K-5 M-4 N-2 & N-3 Ci 1.0 CI-2.0 Tubing cut @ 4,318’ 13 Stray 2 Stray 3 Sterling A Sterling B11 8 9 10 12 XN X R X _____________________________________________________________________________________ Updated By: JLL 07/10/20 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Stray 2 4,054’ 4,069’ 3,583’ 3,595’ 15’ 06/13/20 Open Stray 3 4,090’ 4,100’ 3,612’ 3,620’ 10’ 06/13/20 Open Sterling A 4,118’ 4,123’ 3,635’ 3,639’ 5’ 06/03/20 Isolated Sterling B 4,170’ 4,175’ 3,676’ 3,680’ 5’ 05/30/20 Isolated CI-1.0 4,406' 4,476' 3,864' 3,920' 70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999' 80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047' 10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101' 50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171' 40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215' 10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266' 25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321' 7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404' 19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833' 5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867' 5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885' 10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093' 5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167' 25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226' 10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321' 5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336' 10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368' 20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398' 25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407' 5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453' 7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581' 10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616' 15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634' 5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651' 7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697' 10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781' 7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913' 25' Jun-94 Isolated _____________________________________________________________________________________ Updated By: JLL 01/21/2021 PROPOSED North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4” 45.5 & 51 J-55 BT&C Surf 2,522’ 7” 26 J-55 BT&C Surf 79’ 23 J-55 BT&C 79’ 7,100’ 26 J-55 BT&C 7,100’8,108’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surf 383’ 3-1/2” 9.2 L-80 IBT 2.992” 383’ 3,549’ 3-1/2” 9.2 L-80 8RD EUE 2.992” 3,549’ 4,318’ 4-1/2” 12.75 J-55 Mod EUE 8rd 4,318’ 5,129’ 4-1/2” 12.75 J-55 EUE 8rd 5,129’ 6,925’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 26.07’ 26.07’ Hanger Vetco 4 1/2 IBTsusp, 4.909 MCA lift threads, 4" Type H BPV profile 1 343’ 343’ 3.813 5.400 Nipple, Camco BP-6I Landing WRDP, DB lock 2 383’ 383’ 3.000 5.210 4-1/2” x 3-1/2” Crossover 3 1,766’ 1,734’ 2.867” 5.313” GLM #1 –SPM –1; Dummy Valve 3,354’ 3,028’ 2.867” 5.313” GLM #2 –SPM –1; Orifice 20/64” 4 3,404’ 3,068’ 2.867” 5.313” Chemical Injection Mandrel 5 3,457’ 3,110’ 3.000” 6.000” 7" 3 1/2" DLH Packer (46k Shear release) 6 3,501’ 3,144’ 2.813” 3.750” X-Nipple 7 3,532’ 3,169’ 2.992” 3.500” Dummy seal bore Assembly 8 3,549’ 3,182’ 4.176” 5.924” ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 9 4,109’ 3,627’ 2.750” CIBP w/3.6’ cement 10 4,111’ 3,629’ 2.750” CIBP 11 4,165’ 3,672’ 2.750” CIBP w/ 18’ cement 12 4,318’ 3,794’ Landing collar and float Assembly 13 4,318’ 3,794’ Tubing Cut A 4,328’ 3,802’ 1.71 3.125 Profile Nipple R Nipple B 4,329’ 3,803’ 3.813 5.030 Halliburton X Nipple w/ plug set C 4,370’ 3,806’ 3.992 5.080 Ratch Latch Seal Unit 4,371’ 3,806’ 3.880 5.980 Halliburton VSR Packer D 4,591’ 4,013’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) E 4,605’ 4,024’ 3.992 5.560 Halliburton No-Go Locator 4,606’ 4,025’ 4.000 5.815 Halliburton TWR Packer & Millout Extension F 4,711’ 4,109’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) G 4,723’ 4,119’ 3.992 5.080 Halliburton No-Go Seal Unit 4,724’ 4,120’ 4.000 5.815 Halliburton TWR Packer & Millout Extension H 4,849’ 4,222’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) I 4,861’ 4,232’ 3.950 5.080 Halliburton No-Go Seal Unit 4,862’ 4,233’ 4.000 5.815 Halliburton TWR Packer & Millout Extension J 4,943’ 4,299’ 3.950 5.080 Ratch Latch Seal Unit 4,944’ 4,299’ 4.000 5.815 Halliburton TWR Packer & Millout Extension K 5,080’ 4,411’ 3.813 5.530 Halliburton XA Sliding Sleeve (Closed) L 5,116’ 4,441’ 3.950 5.080 Ratch Latch Seal Unit 5,117’ 4,441’ 4.000 5.815 Halliburton TWR Packer & Millout Extension M 5,601’ 4,841’ 3.813 5.530 Halliburton XD Sliding Sleeve (Open) N 6,294’ 5,410’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) O 6,893’ 5,984’ 3.725 5.030 Halliburton XN Nipple P 6,925’ 5,920’ 3.992 5.580 WLREG PBTD: 7,050’ TD: 8,126’ 2 30” RKB: 39.40’, RKB to MSL: 116’ RKB to Mudline: 236’ 7” 3 4 5 67 A C D E F G H I J K L M 10-3/4” 1 TOC @ 2,510’ N O P B Fill @ 4,837’ CI -3.1 CI-4.0 CI-5.0 CI-6.0 CI -7.0 CI-8.0 CI-9.0 C-4 D-1 K-1 D-2 E-9 F3 & F-4 G-1 H-1.1 H-2 H-4 & H-5 H-6 & H-7 H-7.1 H-9 J-1 J-3 K-2 K-5 M-4 N-2 & N-3 Ci 1.0 CI-2.0 Tubing cut @ 4,318’ 13 Stray 2 Sterling Z Stray 3 Sterling A Sterling B11 8 Sterling X 9 10 12 XN X R X Sterling Xg Sterling Z ov DV _____________________________________________________________________________________ Updated By: JLL 01/21/2021 PROPOSED North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Sterling X ±3,936’ ±3,945’ ±3,489 ±3,496’ ±9’ Future Proposed Sterling Z ±3,998’ ±4,018’ ±3,539 ±3,555’ ±20’ Future Proposed Stray 2 4,054’ 4,069’ 3,583’ 3,595’ 15’ 06/13/20 Open Stray 3 4,090’ 4,100’ 3,612’ 3,620’ 10’ 06/13/20 Open Sterling A 4,118’ 4,123’ 3,635’ 3,639’ 5’ 06/03/20 Isolated Sterling B 4,170’ 4,175’ 3,676’ 3,680’ 5’ 05/30/20 Isolated CI-1.0 4,406' 4,476' 3,864' 3,920' 70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999' 80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047' 10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101' 50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171' 40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215' 10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266' 25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321' 7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404' 19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833' 5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867' 5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885' 10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093' 5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167' 25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226' 10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321' 5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336' 10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368' 20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398' 25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407' 5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453' 7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581' 10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616' 15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634' 5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651' 7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697' 10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781' 7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913' 25' Jun-94 Isolated Sterling X ±3,936’±3,945’±3,489 ±3,496’±9’Future Proposed Sterling Z ±3,998’±4,018’±3,539 ±3,555’±20’Future Proposed Samuel Gebert Hilcorp Alaska, LLC GeoTech Assistant 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 09/24/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NCIU A-07 (169-058) GASSAT3D ANALYSIS with TMD3D 02/29/2020 ANALYSIS FIELD DATA Please include current contact information if different from above. Received by the AOGCC 09/24/2020 PTD: 1690580 E-Set: 33983 Abby Bell 09/24/2020 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: G/L Completion Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 8,126 feet See schematic feet true vertical 4,701 feet N/A feet Effective Depth measured 4,109 feet See schematic feet true vertical 3,627 feet See schematic feet Perforation depth Measured depth 4,054 - 4,100 feet True Vertical depth 3,583 - 3,620 feet Tubing (size, grade, measured and true vertical depth)See schematic Packers and SSSV (type, measured and true vertical depth)See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Authorized Title: Contact Email: Contact Phone: TVD measured true vertical Packer 7" 8,108 MD 388 2,522 measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 1330 Casing Pressure STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 169-058 50-883-20027-00-00 Plugs ADL0017589 N Cook Inlet Unit A-07 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-150 & 320-246 530 Authorized Signature with date: Authorized Name: 19 WINJ WAG 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 22 N/A Oil-Bbl 0 Water-Bbl Intermediate N/A Junk 5. Permit to Drill Number: 1,993 North Cook Inlet Unit / Tertiary Gas PoolN/A measured 8,108 Size 566 Production Casing Structural Liner Length 388 2,522 Conductor Surface 3,270psi 30" 10-3/4" 907 777-8387 4,360psi 388 2,364 6,905 Collapse Mark McKinley mmckinley@hilcorp.com Tubing Pressure 2,090psi3,580psi Hilcorp Alaska, LLC 2. Operator Name Senior Engineer: Senior Res. Engineer: Daniel E. Marlowe Operations Manager Burst PL G Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Jody Colombie at 3:08 pm, Jul 13, 2020 Daniel Marlowe I am approving this document 2020.07.13 14:10:31 -08'00' Daniel Marlowegls 9/2/20 1,993 SFD 7/13/2020 DSR-7/13/2020 SFD 7/13/2020 6,920 RBDMS HEW 7/13/2020 _____________________________________________________________________________________ Updated By: JLL 07/10/20 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4” 45.5 & 51 J-55 BT&C Surf 2,522’ 7” 26 J-55 BT&C Surf 79’ 23 J-55 BT&C 79’ 7,100’ 26 J-55 BT&C 7,100’8,108’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surf 383’ 3-1/2” 9.2 L-80 IBT 2.992” 383’ 3,549’ 3-1/2” 9.2 L-80 8RD EUE 2.992” 3,549’ 4,318’ 4-1/2” 12.75 J-55 Mod EUE 8rd 4,318’ 5,129’ 4-1/2” 12.75 J-55 EUE 8rd 5,129’ 6,925’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 26.07’ 26.07’ Hanger Vetco 4 1/2 IBTsusp, 4.909 MCA lift threads, 4" Type H BPV profile 1 343’ 343’ 3.813 5.400 Nipple, Camco BP-6I Landing WRDP, DB lock 2 383’ 383’ 3.000 5.210 4-1/2” x 3-1/2” Crossover 3 1,766’ 1,734’ 2.867” 5.313” GLM #1 –SPM –1; IPOC-1 20/64” 3,354’ 3,028’ 2.867” 5.313” GLM #2 –SPM –1; Orifice 20/64” 4 3,404’ 3,068’ 2.867” 5.313” Chemical Injection Mandrel 5 3,457’ 3,110’ 3.000” 6.000” 7" 3 1/2" DLH Packer (46k Shear release) 6 3,501’ 3,144’ 2.813” 3.750” X-Nipple 7 3,532’ 3,169’ 2.992” 3.500” Dummy seal bore Assembly 8 3,549’ 3,182’ 4.176” 5.924” ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 9 4,109’ 3,627’ 2.750” CIBP w/3.6’ cement 10 4,111’ 3,629’ 2.750” CIBP 11 4,165’ 3,672’ 2.750” CIBP w/ 18’ cement 12 4,318’ 3,794’ Landing collar and float Assembly 13 4,318’ 3,794’ Tubing Cut A 4,328’ 3,802’ 1.71 3.125 Profile Nipple R Nipple B 4,329’ 3,803’ 3.813 5.030 Halliburton X Nipple w/ plug set C 4,370’ 3,806’ 3.992 5.080 Ratch Latch Seal Unit 4,371’ 3,806’ 3.880 5.980 Halliburton VSR Packer D 4,591’ 4,013’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) E 4,605’ 4,024’ 3.992 5.560 Halliburton No-Go Locator 4,606’ 4,025’ 4.000 5.815 Halliburton TWR Packer & Millout Extension F 4,711’ 4,109’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) G 4,723’ 4,119’ 3.992 5.080 Halliburton No-Go Seal Unit 4,724’ 4,120’ 4.000 5.815 Halliburton TWR Packer & Millout Extension H 4,849’ 4,222’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) I 4,861’ 4,232’ 3.950 5.080 Halliburton No-Go Seal Unit 4,862’ 4,233’ 4.000 5.815 Halliburton TWR Packer & Millout Extension J 4,943’ 4,299’ 3.950 5.080 Ratch Latch Seal Unit 4,944’ 4,299’ 4.000 5.815 Halliburton TWR Packer & Millout Extension K 5,080’ 4,411’ 3.813 5.530 Halliburton XA Sliding Sleeve (Closed) L 5,116’ 4,441’ 3.950 5.080 Ratch Latch Seal Unit 5,117’ 4,441’ 4.000 5.815 Halliburton TWR Packer & Millout Extension M 5,601’ 4,841’ 3.813 5.530 Halliburton XD Sliding Sleeve (Open) N 6,294’ 5,410’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) O 6,893’ 5,984’ 3.725 5.030 Halliburton XN Nipple P 6,925’ 5,920’ 3.992 5.580 WLREG PBTD: 7,050’ TD: 8,126’ 2 30” RKB: 39.40’, RKB to MSL: 116’ RKB to Mudline: 236’ 7” 3 4 5 67 A C D E F G H I J K L M 10-3/4” 1 TOC @ 2,510’ N O P B Fill @ 4,837’ CI -3.1 CI-4.0 CI-5.0 CI-6.0 CI -7.0 CI-8.0 CI-9.0 C-4 D-1 K-1 D-2 E-9 F3 & F-4 G-1 H-1.1 H-2 H-4 & H-5 H-6 & H-7 H-7.1 H-9 J-1 J-3 K-2 K-5 M-4 N-2 & N-3 Ci 1.0 CI-2.0 Tubing cut @ 4,318’ 13 Stray 2 Stray 3 Sterling A Sterling B11 8 9 10 12 XN X R X _____________________________________________________________________________________ Updated By: JLL 07/10/20 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/14/20 PTD: 169-058 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Stray 2 4,054’ 4,069’ 3,583’ 3,595’ 15’ 06/13/20 Open Stray 3 4,090’ 4,100’ 3,612’ 3,620’ 10’ 06/13/20 Open Sterling A 4,118’ 4,123’ 3,635’ 3,639’ 5’ 06/03/20 Isolated Sterling B 4,170’ 4,175’ 3,676’ 3,680’ 5’ 05/30/20 Isolated CI-1.0 4,406' 4,476' 3,864' 3,920' 70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999' 80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047' 10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101' 50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171' 40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215' 10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266' 25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321' 7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404' 19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833' 5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867' 5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885' 10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093' 5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167' 25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226' 10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321' 5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336' 10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368' 20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398' 25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407' 5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453' 7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581' 10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616' 15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634' 5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651' 7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697' 10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781' 7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913' 25' Jun-94 Isolated Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Stray 2 4,054’ 4,069’ 3,583’ 3,595’ 15’ 06/13/20 Open Stray 3 4,090’ 4,100’ 3,612’ 3,620’ 10’ 06/13/20 Open Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status y, , , ,p// Rig Start Date End Date HAK 404 5/18/20 6/14/20 05/20/2020 - Wednesday PJSM. Remove rear stairs from carrier. Remove loose equipment from around carrier. Organize drill deck. Pick and set carrier on south end of drill deck. Begin cleaning pits with vac unit. Set dog house main beam in place. Install spacer beams and rear spreader. Finish cleaning pits. Assist welder installing feet on beams. Stage Koomey hoses. Set carrier in position. install stairs, A-leg, install Drawworks, bolt down. Install driveline Spot accumulator & choke house. Unload mast from boat, remove bolster, pin to A leg, install lift rams. Prep mast to stand, stand mast, install guylines, prep to raise mast, organize decks, install tugger & man rider lines, cut 100' drill line. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Finish rigging down circulating lines from A-07. Cont prep floor for rig down. Cont. R/D, remove slide, N/D tree, pull lock down plate form hanger, prep wellhead, clean & inspect lift threads good, install blanking sub, n/u 16 3/4 x 11" 5k tubing spool. Install blanking plug and flange by hub on A-07. N/U BOPE on A-07. Cont. prep derrick for removal, unstring draw-works, tuggers tie up lines, install bolsters, pull derrick from carrier put on boat. Pump out pits, pull driveline from carrier, r/d super choke panel, pull draworks & load on boat, cont. backload boat for leg move. Pull A- leg from carrier, prep deck for carrier removal. R/U Pollard. Test lubricator at 1500 psi. Set 4 1/2" PX plug in A-07 at 4329'. R/D wire line. R/U circulating lines. Circulate hole volume until clean +-181 bbls. Monitor well static, set BPV. 05/19/2020 - Tuesday 05/18/2020 - Monday Daily Operations: 05/21/2020- Thursday Scope up mast and secure. Set in dog house and rig floor. Spool tuggers and manrider. Install wind walls. Set in DS, ODS and floor stairs. Set in beaver slide for lower brace. Rig up circulating hoses. Center rig over hole. Mobilize tool baskets and begin staging equipment for test joints. Rig up choke and kill lines. Install and test umbilical line for accumulator. Change oil on carrier engine. R/U derrick lights. Install beaver slide brace. Grease CMV's and manual/choke valves. Obtain RKB's. Fill pits with 100 bbls FIW. Make up 3 1/2" and 4 1/2" test joints. Install 3 1/2" test joint / fill stack. Shell Test 250/2500 good, Test BOPE as per Hilcorp & AOGCC requirements, test witnessed by AOGCC inspector Lou Laubenstein. Tested with 3 1/2" & 4 1/2" tj, All good. R/D test eq. pull test jt & blanking sub. Break down test joint. M/U landing jt, pull BPV. R/U e-line, RIH w/3 1/2" cutter GR & CCL. RIH w/ 3 1/2" jet cutter, GR, CCL on E-line t/4320 WLM tag, log up t/3850~, RIH tag & p/u 2' t/4318', cycle & fire cutter. POOH w/ e-line. cut tubing Shell Test 250/2500 good, Test BOPE as per Hilcorp & AOGCC requirements, N/U BOPE on A-07. Cont. RIH w/ 3 1/2" jet cutter, GR, CCL on E-line t/4320 WLM tag, log up t/3850~, RIH tag & p/u 2' t/4318', cycle & fire cutter. Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 05/22/2020 - Friday Rig down e-line. Pull tubing hanger off seat at 39 K. P/U to 45 K string weight. R/U up and test casing at 1650 psi on chart for 30 minutes. Good test. Rig down test equipment. R/U power tongs. Pull and lay down tubing hanger. Stage thread protectors and prepare for laying down tubing. POOH laying down 4 1/2" tubing completion assembly. Continue POOH laying down 4 1/2" tubing completion assembly. Laid down +-105 joints. Cont. POOH L/D 4 1/2" completion tubing, l/d 129 jts & one cut jt total. C/O handling tools, P/U BHA # 1- 6 1/8" bit, csg scraper, bit sub, 2- boot baskets, xo +19.93'. TIh p/u 3 1/2" PH-6 work string, t/638'. Cont.TIh p/u 3 1/2" PH-6 work string, t/2809'. 05/23/2020 - Saturday Continue TIH picking up 3 1/2" PH-6 work string from 2809' to TOF at 4303' SLM. P/U 42 K, S/O 36 K. Line up to pump through choke manifold. Circulate at 4 BPM/ 480 psi while adding ClayBrake to system. Circulate an additional STS to blend into system. Troubleshoot rig air issues (drawworks, crown-o-matic). POOH with clean out assembly to BHA. Lay down BHA. Rig up Pollard e-line. RIH log CBL 4328' up t/ 2349', 2526'~ R/D e-line. C/O handling tools to run 3 1/2" liner. Housekeeping & rig maint. while waiting on boat. Unload liner, strap & tally same while unloading rest of boat. Cont. prep to run liner & unload boat, spot CMT eq. & rig up while having discussions with Baker & HAK engineers on how to proceed with liner job. P/U & m/u shoe track, baker lock same- Mule shoe, float collar, landing color. Cont p/u 3 1/2" L-80 9.3#, EUE 8rd liner t/358', fill pipe & check float good, cont t/ 737', fill pipe. 05/24/2020 - Sunday General housekeeping while waiting on Baker technician. Pick up Baker SL ZXP liner hanger. RIH with stands out of derrick to 1520'. Fill every 10 stands. RIH with SL ZXP liner hanger fro 1520' to 4293'. Fill pipe every 10 stands. Install stripper rubber. Tag bottom at 4318'OKB. Space out and pick up cement head. Rig up Halliburton and floor manifold. Tag bottom, p/u 1' placing tail @ 4317' OKB, circulate hole volume @ 4.3 BPM, 500 psi, swap out tongs for POOH, hold PJSM for cmt job. Flood cmt lines w/5bbls water, P/T 860/4820 good, pump 5 bbls spacer, pump 25.7 bbls 15.8ppg cmt. Flush lines, pump .5 bbls Drill water w/claybreak, drop dart chase with 33bbls drill water w/claybreak, bump plug, pressure up t/2500psi sheart/set s/o 27k verify SLZXP set. Press up t/4500psi, observe shear @ 3100psi, bleed pressure back 1.74 bbls, check float good. P/U free @ 39k. cmt in place 22:00. L/T @ 3549' Org KB. Break out cmt head, & l/d, r/u head pin, pressure up t/700 psi, p/u observe pressure drop circulate @ 4.4 bpm, 410 psi. Cont. p/u 28', cont. circulate clean, observe spacer & cmt in returns (divert to cuttings box). L/D spacer pups & one single t/3495'. Pump wiper ball down wk string, @ 3.5bpm, 220 psi. POOH l/d 3 1/2" PH6 wk string, f/3795'. P/u pups & make breaks cont. POOH l/d 3 1/2" wk string t/350~'. cement scab liner Pick up Baker SL ZXP liner hanger. prep to run liner & unload boat, spot CMT eq. & rig up w cmt in place 22:00. L/ Pull tubing hanger off seat at 39 K. Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 05/25/2020 - Monday Finish POOH laying down work string and liner packer stinger assembly. RIH with 11 stands out of derrick. POOH L/D remainder of 3 1/2" PH-6 work string. R/D power tongs. Clear rig floor. R/U Pollard e-line. RIH with CBL. Run #1 unable to pass through TOL at 3549'. POOH and change out centralizer. RIH and able to perform CBL to 4318' WLM. POOH and rig down Pollard e-line. Rig up to run 3 1/2" completion assembly. RIH picking up 3 1/2" 9.3# L-80 IBT tubing completion assembly to +-500'. Continue RIH picking up 3 1/2" 9.3# L-80 IBT tubing completion assembly from +-500' to 4 1/2" X 3 1/2" X/O @ 3049'. Installed Cannon clamps every other jt from Chemical Injection Mandrel to 4 1/2" X 3 1/2" X/O. Change out 3 1/2" handling equipment for 4 1/2". Make up 4 1/2 X 3 1/2 X/O, 1 jt. 4 1/2", 12.6#, L-80 IBT tubing and SSSV. M/U and test control line w/ 5000 psi (Good). Continue RIH picking up 4 1/2", 12.6#, L-80 IBT tubing to 3545' SLM (Tagged up with dummy seal assembly), L/D 2 jt. 4 1/2" tbg. Space out w/ 1.90' 4 1/2" 12.6#, L-80 IBT pup jt, Hanger assembly and landing jt. Terminate control and chemical injection lines at hanger and test same. Land hanger. Run in lock down screws and check hubbed flange clamps on wellhead for tightness. Bottom of dummy seal assembly @ 3543' (2' from being fully inserted into PBR). Ran a total of 38 ea. Cannon Clamps and 26 ea. SS bands. Drop bar and rig up to set packer. Pressure up to 3900 psi to set packer. 05/26/2020 - Tuesday R/U and test IA at 1500 psi on chart for 30 minutes. Test tubing at 2500 psi on chart for 30 minutes. R/D test equipment. Rig up Pollard slick line. Run #1: retrieve SSSV sleeve with 4.5" PRS tool. Run #2: RIH with 2" JD and retrieve firing bar. Run #3: Retrieve plug. Run #4: 2.66 gauge ring and tag TD at 4289' WLM. Rig down Pollard wire line. Lay down landing joint. Set BPV. R/D rig floor and board. Disconnect service lines and accumulator lines. Break bolts on ram doors, inspect ram blocks, clean and grease ram cavities and blocks. R/D Koomey unit. Prep and scope down upper mast section. Hang blocks in mast. Spool drill line off of drawworks drum and onto drill line spool. Close and bolt up ram doors. Remove driller's dog house, koomey house, and dog house stairs. Remove carrier drive line. Lay over mast. Organize guy wires and tugger lines. Unpin hyd. rams for mast removal. Break bolts on BOPE flanges. Continue N/D BOPE, prep derrick for removal and stage equipment. Nipple up adapter flange and tree. 05/27/2020 - Wednesday Finish nippling up tree. Test tree at 5000 psi - Test good. Rig down test equipment. Finish securing mast for removal. Pressure wash choke house. Back load boat with derrick, Koomey house and choke house. Continue preparing carrier for removal from spreader beams. Remove drawworks. Continue houskeeping. Remove carrier break bolts on cross beams and remove cross beams. Continue with houskeeping. Send workover fluid from rig pits to production. Clean pits. Continue to clean and organize for rig move. Finish shipping fluids from pits to production and clean pits. Power wash carrier. Move and stage spreader beams for load out to work boat. Power wash deck where rig was sitting. Continue RIH picking up 3 1/2" 9.3# L-80 IBT tubing completion assembly from +-500' to 4 1/2" X 3 1/2" X/O @ 3049'. Installed Cannon clamps every other jt from Chemical Injection Mandrel to 4 r. RIH and able to perform CBL to 4318' WLM. floor. R/U Pollard e-line. RIH with CBL. R/U and test IA at 1500 psi on chart for 30 minutes. Test tubing at 2500 psi on chart for 30 minutes. Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 05/28/2020- Thursday Prep platform deck for slickline and e-line operations. Power wash deck, drawworks, carrier and mud pump. stage vac unit and clean pits. Perform maintenance operations and prep conex's for move. Assist slickline as needed. Consolidate and install panels in conex’s. Store grating walk ways and stairs in container’s. Clean out HPU drip pan. Clean out Super Choke control panel. Secure loose items on carrier skid. Secure hand rails on pipe rack. Add secondary restraints on spreader beam C-clamps. Assist slickline as needed. Assist crane crew rigging down slickline lubricator. Load out rig carrier double spreader beam, single spreader beam, racking beam, 2 ea. cross braces bars and a cargo basket onto work boat to the Steelhead. Clean trash from under skid rails and deck where spreader beams were stored. Remove test pump from welding shop, Rewrap containment on right angle drive of drawworks. 05/29/2020 - Friday Continue to clean decks and perform maintenance on tools and equipment. Secure parts and equipment in conexs and prep for load out. Load out boat for Steelhead with: Mud pits, Mud Pump, Carrier, Carrier Walk Around Landings, A-Leg Assembly, Dog House, Drawworks, 2 Parts Conexs, Electrical Distribution Panel, and Step Over Stairs. Clean deck area where equipment had been staged. Prep for next load out. Load out boat for Steelhead with: Conex, Magtec Air Tank, 1 box Quadco Equipment, 1 box Total Safety Gas Detection Sys, 13-5/8" 5M Double Gate BOPE, 13-5/8" 5M Annular, 13-5/8" 5M Mudcross w/ Valves, DSA Spool, 3 sets Power Tongs, Beaver Slide, Rig Floor, Test Pump, Misc. Stair Sets, Misc. Hoses Tools and Equipment. 05/30/2020 - Saturday PJSM & permit. Start RU ELU waitng on crane to be available. Continue RU w/ crane. MU & surface test GR/CCL tool suite. PU Perf Gun: 2-3/8" x 5' GeoRazor HS carrier, 5 spf, 60* phase, 10.8 gm RDX GeoRazor charges. Move to well. PT WLV & Lub = 250/2500. CCL-to-Top Shot = 10.3'. Open swab & RIH w/ 2-3/8" x 5' Perf Gun to Liner Top @ 3650'. Log up for correlation pass. Send log for correlation review & confirmation. Correlation log verified & approved. Log 2- 3/8" x 5' Perf Gun into place @ 4159.7' putting shots on depth (4159.7' + 10.3' = 4170' Top Shot). Fire Perf Gun to perforate Zone Sterling-B 4170' - 4175'. Log up 200' & POOH. OOH w/ all shots fired. Based on lack of pressure response, left well SI. Call for CIBP, dump bailer & cement. RD ELU. Fly ELine crew to beach. 05/31/2020 - Sunday No operations to report. Open swab & RIH w/ 2-3/8" x 5' Perf Gun to Liner Top @ 3650'. Log up for correlation pass. Send log for correlation review & confirmation. Correlation log verified & approved. Log 2- 3/8" x 5' Perf Gun into place @ 4159.7' putting shots on depth (4159.7' + 10.3' = 4170' Top Shot) Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 06/01/2020 - Monday Arrive Platform. PJSM & permit. RU ELU. MU GR/CCL tool suite w/ 2.805" Gauge Ring. Surface test tools. PT WLV & Lub = 250/2500 psi. Bleed down to 950 psi to equalize w/ T/IA = 950/950. Open swab & RIH to 3492' CCL resistance depth (X-nipple @ 3501' w/ MIN. ID = 2.813"). PU w/ 1000# overpull. RBIH to same, 1000# overpull on PU. POOH. Hang up at 3354' (GLM#2) & 1765' (GLM#1). Work wire w/ overpulls @ each. OOH w/ metal mark @ bottom of GR. Pressure up to 950 psi for equalization. Open swab & RBIH w/ spangs & 2.79" GR to 3496' CCL tag depth. Work tools, unable to pass. POOH. Hang up at 3354' (GLM#2) & 1765' (GLM#1). Work tools at each GLM 3 - 4 times before passing thru GLMs. OOH w/ metal marks at top of GR. Pressure up to 950 psi for equalization. Open swab & RBIH w/ spangs & 2.78" GR to 4222' CCL tag depth. PUH clean logging to 4000' CCL. POOH. Hang up at 3354' (GLM#2) & 1765' (GLM#1). Work tools at each GLM 3 - 4 times before passing thru GLMs. OOH w/ metal mark at top of GR. Surface test tool suite. PU 3-1/2" CIBP & setting tool. CIBP = 2.75" OD. CCL-to-Mid Element = 12.9'. CCL-to-Top CIBP = 12.5'. CCL-to-Bottom CIBP = 13.4'. Pressure up to 950 psi for equalization. Open swab & RIH to 4222' CCL. Log up to 4000' CCL for correlation pass. Correct +18.5' & send log files for review & approval. Log correction confirmed & approved. RBIH to 4249' CCL. Log up to 4152.1' CCL to put plug on depth @ 4165' Mid-Element. (4152.1' + 12.9' = 4165').Tension = 550#. Fire to set plug in 3-1/2", 9.2# tubing, Tension = 500#. Wait 5 minutes. Stack down 400# & PU off CIBP clean. Log up 200' & POOH. OOH with plug set in tubing. PU 2 of 2.50" OD X 10' dump bailer subs. Blend 4.5 gallon of 15.8 ppg cement & load dump bailer w/ same. CCL-to- Bottom of bailer = 21.5'. RIH to 4142.5' CCL tag depth. Fire to dump cement & cycle bailer in hole 3 times. POOH. OOH w/ empty bailer. Secure ELU & clean drill deck. SDFN. Wait on Cement. Job in Progress. 06/02/2020 - Tuesday Waiting on Cement. PJSM & permit. T/IA = 975/975. RU SLU. PU 1-3/4" TS w/ 2.50" DD Bailer. Move to well. PT WLV & Lub = 250/2500. Open swab & RIH. Fluid Top @ 2830' RKB. Continue TIH to tag at 4142' RKB. Work tools & fall to 4147' RKB hard tag. Work Tools, hard tag @ same. POOH. OOH w/ small sample of soft cement in bailer (~ 2 Tbsp). RU bleed line from tubing to header line. Bleed down tubing pressure for negative test of CIBP & cement. Initial Tubing = 975 psi. Final Tubing = 670 psi. Wait 30 minutes. T/IA = 750/950. RIH w/ 1-3/4" TS with 3-1/2" swab cup to fluid top @ 2807' RKB. POOH. Turn over well to Prod Operator. Bring on lift gas and flow well @ 1.8 MMSCFD to test separator to lift wellbore fluids out of hole down to OV @ 3354' RKB. Flowed 5 bbl water to test separator. Shut in well @ flowline. SLU RIH w/ 3-1/2" swab cup mandrel to 3535'. Open well to flowline. Working choke open to 1.8 MMSCFD & hydrate off flowline downstream of flowline choke. Pump methanol to flow line to remove hydrates. Still working to remove hydrate restriction down stream of choke. SI well @ flowline choke & wing valve. SI lift gas. Allow tubing & IA pressures to equalize. SLU POOH. Close swab & RD SLU for night. Continue to work hydrate restriction. SDFN. Job in Progress. Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 06/03/2020 - Wednesday PJSM & permit. RU SLUPU & changeout 3 new 3-1/2" swab cups on swab mandrel. Open swab & RIH to 3564' RKB. Production opens flowline wing valve & choke. Bring on lift gas. Work flow to 1.8 MMSCFD. SL starts making swab pulls up to 40' below OV @ 3354' RKB. Pull to 3400' +/- and allow GLV to carry water column above cups OOH. SL repeats swab pulls w/ 80' - 150' pull each run. SL seeing fluid w/ each swab pull but little fluid to surface. FR = 1.6 - 1.8 MMSCFD, T= 270 flowing pressure. Lift Gas = 2.1 MMSCFD,T = 270, rock flowline choke. Flowing Tubing = 125 psi, FR = 1.99 MMSCFD, Lift Gas = 2.1 MMSCFD. See fluid to surface @ test separator after rocking choke. SL tagging top of cement plug. Stop swab pulls & hold in hole below 3354' GLV and let well unload. Fluid returns to test separator stop. Shut in gas lift and flowline choke. Allow well to equalize. POOH. SLU RBIH w/ 2.65" blind box to fluid top @ 4147' RKB tag @ cement top no recognizable fluid top. RU ELU. MU GR/CCL tool suite w/ Firing Head. Surface test CCL & FH. PU Perf Gun: 2-3/8" X 5' GeoRazor carrier, 5 spf, 60* phase, 10.8 gm RDX GeoRazor charges. Move to well. Prod. Operators changing out plugged flowline choke. Find choke needle cone is broken. Wait for Production to install replacement choke. T/IA = 434/455. Start gas lift with flowline shut in and build tubing pressure to 863 psi, IA = 876 psi, CCL-to-Top Shot = 9.1' CCL-to-Bottom Shot = 14.1'. Open swab & RIH w/ 2-3/8" x 5' Perf Gun to 4137' CCL (4151' RKB) tag at top of cement plug. Log up to 3950' CCL. Correct +11.5'. RBIH to 4137' CCL & log up to 4108.9' to place shots on depth (4108'9' + 9.1' = 4118' Top Shot). T/IA = 845/855. Fire to perf Zone Sterling-A 4118' - 4123'. Log up 200' & POOH. OOH w/ all shots fired. Post-Perf T/IA = 830/841. RD ELU. Secure Well. Secure & clean drill deck. Turn over well to Production to bring well online. Fly crews to beach. 06/04/2020- Thursday No operations to report. 06/05/2020 - Friday ARRIVE AT PWL SHOP P/U CREW AND TOOLS. ARRIVE AT OSK CHECK IN FOR COVID TESTING- THEN STANDBY FOR FLIGHT. ARRIVE AT TYONEK PLATFORM. DO PERMITS AND JSA - TGSM. RIG UP SLICKLINE. STANDBY FOR CRANE MECHANIC TO FINISH CRANE WORK- THEN FINISH RIG UP. P/T LUB 2500 PSI GOOD. RIH/W 2.5" X 5' DD BAILER TO 3000' RKB TAG FLUID TO 4012' SLM(4024' RKB) TAG W/T TO 4018' SLM (4030'RKB) POOH. OOH/W FULL BAILER OF HARD PACKED FINE SAND MOSTLY DRY, TOP OF BAILER HAD VERY THICK FLUID IN UPPER 1". CONTACT TOWN WITH INFORMATION ABOUT HIGHER FLUID LEVEL AND DEPTH OF FILL. SEND OFF PICS OF SAMPLE. TOWN REQUSTED KEEPING 950 ON LUB ON OPEN AND ABOUT 950 ON TUBING FOR BAILING. PRESSURE UP LUB TO 950 WITH LIFT GAS- THEN RIH W/ 2.5" DD BAILER TO 4019' SLM (4031' RKB) W/T TO 4024' SLM (4036' RKB). POOH TO DUMP BAILER OOH/W SAND FULL (LARGE AMOUNT OF RED DYE COMING OUT OF SAND). PRESSURE UP LUB - RIH/W SAME TO 4020' SLM (4032' RKB) W/T TO 4026' SLM (4038' RKB) POOH OOH /W SAME. PRESSURE UP LUB- RIH/W SAME TO 4024' SLM (4036' RKB) W/T TO 4029' (4041' RKB) POOH. OOH/W 1/2" FULL, PRESSURE UP LUB- RIH/W SAME TO 4026' SLM ( 4038' RKB) W/T TO 4031' SLM (4043' RKB) POOH. OOH/W 1/2 FULL, PRESSURE UP/RIH/W 2.25" X 8' PUMP BAILER TO 4029' SLM ( 4041' RKB) W/T TO 4037' SLM (4049' RKB) POOH. OOH/W 1/2 FULL BAILER. LAY DOWN LUB FOR THE NIGHT SECURE AREA AND WELL. Flowing Tubing = 125 psi, FR = 1.99 MMSCFD, Lift Gas = 2.1 MMSCFD. S Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 06/06/2020 - Saturday ATTEND MORNING MEETING- DO PERMIT AND JSA- STANDBY FOR MONTHLY ALARMS. RIG UP SLICKLINE P/T 2500 PSI GOOD. RIH/W 3 1/2" BRAIDED LINE BRUSH TO 3536' RKB CAN NOT GET BACK IN 3 1/2" TUBING -HAD TIGHT SPOTS ON WAY DOWN. BRUSH WAS VERY OVERFULL SIZE, POOH TO RUN GAUGE RING. PRESSURE UP LUB-RIH/W 2.78" GAUGE RING TO 4010' SLM ( 4022' RKB) W/T TO 4035' SLM (4047' RKB) MAKE 5 PASSES TO CLEAN UP AREA AND POOH. PRESSURE UP LUB- RIH/W 2.5" X 5' DD BAILER TO 4033' SLM (4045' RKB) W/T TO 4038' SLM ( 4050' RKB)POOH. OOH/W 1/2 FULL SAND BAILER. PRESSURE UP LUB - RIH/W SAME TO 4038' SLM (4050' RKB) W/T TO 4040' SLM (4052' RKB) POOH. OOH/W 1/4 FULL. PRESSURE UP LUB - RIH/W1.8" CENTRALIZER/W DIGGER TOOL TO 4040' SLM (4052' RKB) W/T TO 4041' SLM (4053' RKB) POOH. PRESSURE UP LUB- RIH/W 1.8" CENTRALIZER/W DIGGER TOOL (FLAT TIP STYLE) TO 4040' SLM (4052' RKB) W/T TO 4043' SLM ( 4055' RKB ) POOH. PRESSURE UP LUB- RIH/W 2.25" X 8' PUMP BAILER TO 4040' SLM W/T TO 4043' SLM (4055' RKB) POOH. OOH/W 1/4 FULL SOLIDS 1/2 FULL HEAVY SLURRY 1/4 FULL FLUID. PRESSURE UP LUB- RIH/W1.8" CENTRALIZER/W 1.75" DD BAILER TO 4046' SLM ( 4058' RKB) W/T TO 4050' SLM (4062' RKB) POOH. OOH/W 1/2 FULL SAND 1/2 SLURRY. PRESSURE UP LUB- RIH/SAME TO 4051' SLM ( 4064' RKB) W/T TO 4554' SLM ( 4066' RKB) POOH OOH/W SAME. PRESSURE UP LUB- RIH/W 2.5"DD BAILER TO 4051'SLM (4064'RKB)W/T TO 4054'SLM (4066'RKB) POOH. OOH FULL SLURRY. LAY DOWN LUB AND SECURE AREA AND WELL FOR THE NIGHT. CUT LINE AND REPACK. LAY DOWN CREW FOR THE NIGHT. 06/07/2020 - Sunday ATTEND MORNING MEETING- DO PERMIT AND JSA- STANDBY FOR CRANE PICKS. RIG UP SLICKLINE P/T 2500 PSI GOOD. RIH/W 2" X 5' DD BAILER TO 4053' SLM ( 4065' RKB) W/T TO 4056' SLM ( 4068' RKB) POOH. OOH 3/4 FULL SAND 1/4 SLURRY. PRESSURE UP LUB-RIH/W SAME TO 4055' SLM ( 4067' RKB) W/T TO 4058' SLM (4070 RKB) POOH. OOH/W FULL SAND. PRESSURE UP LUB-RIH/W 2.77" GAUGE RING TO 4050' SLM ( 4062' RKB) W/T TO 4057' SLM ( 4069' RKB) POOH. PRESSURE UP LUB- RIH/W 2.5" X 5' DD BAILER TO 4055' SLM ( 4067 RKB) W/T TO 4059' SLM) 4071' RKB POOH. OOH FULL SLURRY SOME SOLIDS. PRESSURE UP LUB - RIH/W SAME TO 4060' SLM (4072' RKB) W/T TO 4063' SLM ( 4075' RKB) POOH OOH/W SAME. PRESSURE UP LUB -RIH/W 2" X 5' DD BAILER TO 4062' SLM ( 4074' RKB) W/T TO 4064' SLM (4072' RKB) POOH. OOH/W 1/2 SOLID 1/2 SLURRY. PRESSURE UP LUB- RIH/W SAME TO 4064'SLM (4076' RKB) W/T TO 4065' SLM ( 4077' RKB) POOH OOH/W SAME. PRESSURE UP LUB- RIH/W 2.5" X 5' DD BAILER TO 4062' SLM(4074'RKB) W/T TO 4063'SLM (4075'RKB) POOH OOH/W 1/4 FULL SAND 3/4" FULL SLURRY. LAY DOWN LUB AND REPACK STUFFING BOX (SAND CUT) PRESSURE UP LUB - RIH/W 1.8" CENTRALIZER/W 1.75" X 5' DD BAILER TO 4068' SLM ( 4080' RKB) W/T TO 4071' SLM (4083' RKB) POOH OOH/W,PRESURE UP LUB- RIH/W 2.77" GAUGE RING TO 4067' SLM ( 4079' RKB) W/T TO 4069' SLM (4081' RKB) POOH. PRESSURE UP LUB RIH/W 2.85" GAUGE RING TO 3489' SLM ( 3501' RKB ) TAG XNIPPLE POOH. PRESSURE UP LUB RIH/W 2.5" X 5' DD BAILER TO 4067' SLM W/T TO 4069' SLM ( 4081' RKB ) POOH OOH/W 3/4 FULL SLURRY 1/4 FULL SAND. RIG OFF FOR THE NIGHT SECURE AREA AND WELL. LAY DOWN CREW. Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 06/08/2020 - Monday ATTEND MORNING MEETING- DO PERMIT AND JSA. PLATFORM FIRE DRILL AND ABANDON PLATFORM DRILLS. RIG UP SLICKLINE P/T 2500 PSI GOOD. RIH/W 1.8" CENTRALIZER /W 1.75" DD BAILER TO 4072' SLM ( 4084' RKB) W/T TO 4073' SLM(4085' RKB) POOH OOH/W 1/3 BAILER SOLIDS 2/3 THICK SLURRY. PRESSURE UP LUB- RIH/W 2.25" X 10' PUMP BAILER TO 4073' SLM (4085'RKB) W/T 4077' SLM(4089' RKB) POOH. OOH/W 2CUPS SAND- MAJORITY OF BAILER SLURRY THICK. PRESSURE UP LUB- RIH/W 2" X 5' DD BAILER TO 4074' SLM W/T TO 4078' SLM (4090'RKB) POOH OOH/W 1/2SAND 1/2 SLURRY. PRESSURE UP LUB - RIH/W 2.77" GAUGE RING TO 4078' SLM ( 4090' RKB) W/T TO 4879' SLM (4091' RKB) POOH. PRESSURE UP LUB RIH/W 2.5" X 5' DDBAILER TO 4079' SLM ( 4091' RKB) W/T TO 4080' SLM (4092' RKB) POOH OOH/W 1/4 FULL SAND 3/4" SLURRY. PRESSURE UP LUB - RIH/W SAME TO 4079' SLM ( W/T TO 4080' SLM (4092' RKB) POOH OOH/W 1/8" SAND 7/8" SLURRY. PRESSURE UP LUB- RIH/W 2.77" GAUGE RING TO 4080' SLM (4092' RKB) W/T POOH. PRESSURE UP LUB- RIH/W 3 1/2" BRAIDEDLINE BRUSH TO 1700' SLM START WORKING BRUSH DOWN TO 4080' SLM VERY TIGHT THRU 3" TUBING ONCE AT 4080' SLM BRUSH TO 4020' SLM MULTIPLE PASSES THEN POOH. PRESSURE UP LUB RIH/W 2.85" GAUGE RING TO 3489' SLM (3501' RKB) POOH,PRESSURE UP LUB RIH/W 2.77" GAUGE RING TO 4081' SLM ( 4093' RKB) POOH. RIG DOWN - SECURE WELL. ATTEND MEETING ON MUSTERING FROM THE MORNINGS DRILLS 06/09/2020 - Tuesday Arrive platform. PJSM & permits. RU ELU. MU GR/CCL tools suite & surface test. PU junk basket w/ 2.78" Gauge Ring. Min. ID = 2.813" X-nipple @ 3501' RKB. CCL-to-Bottom GR = 12.0'. Initial T/IA = 932/981 psi. Move to well, PT WLV & Lub = 250/2500 psi. Bleed down to 1000 psi. Open swab & RIH w/ 2.78" GR to tag @ top of fill = 4095' CCL. Log up for correlation to 3800' CCL. Correct +8'. Send correlation pass for review & approval. Correction confirmed & approved. 4095' CCL tag depth + 8' correction + 12.0' CCL-to- Bottom of GR = 4115' TOP OF FILL. POOH. PU 3-1/2" CIBP & running tool. 3-1/2" CIBP = 2.75" OD. Surface test GR/CCL & fire test running tool. CCL-to-Top of CIBP = 12.7' CCL-to- Mid Element = 13.1' CCL-to Bottom CIBP = 13.6'. Pressure up to 1000 psi & open swab. RIH w/ 3-1/2" CIBP to 4071' CCL, log up to 3790' CCL. Correct +11'. RBIH to 4101.5' CCL top of fill tag depth (4101.5 + 13.6' = 4115.1' Top of Fill). 4101.5' CCL, log up to 4097.8' CCL to place 3-1/2" CIBP on depth Mid-Element (4097.8' + 13.1' =4110.9'). Fire to set CIBP @ 4110.9' Mid-Element. Tension = 590#. Wait 8 minutes, Tension = 578#. Slack down 400# on top of 3-1/2" CIBP & PUH clean off CIBP. Log up to 3800' & POOH. T/IA = 937/981 psi. OOH w/ 3-1/2" CIBP set in 3-1/2" tubing. RD ELU for night securing well. Secure & clean drill deck. Turn over well to Prod. Operators to bring online w/ gas lift to flow off down to GLM#2 @ 3354' RKB. SDFN. Job in Progress. Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 06/10/2020 - Wednesday PJSM & permits. RU SLU w/ 2.50" DD Bailer. PT = 250/2500 psi. Bleed WLV/Lub Pressure = 500 psi (500 psi on WLV &Lub for all 2.50" DD Bailer runs) T/IA = 438/454. RIH w/ 2.50" DD Bailer. Fluid Top @ 3375'. Tag @ 4080' RKB, work tools to 4094' RKB. OOH w/ sandy slurry in bailer. SLU RBIH w/ 2.50" DD Bailer to 4094' RKB, work tools to 4104' RKB. OOH w/ sandy slurry. RBIH w/ 2.50" DD Bailer to 4104' RKB, work tools to 4108' RKB. OOH w/ sandy slurry. SLU RIH w/ 2.25" Pump Bailer to 4108' RKB, work tool. OOH w/ thicker sand slurry. Pressure up 3-1/2" tubing completion to 950 psi. Pressure up WLV & Lub = 950 psi. RBIH w/ 2.25" DD Bailer to 4108' RKB, work tool. OOH w/ sandy slurry. RBIH w/ 2.25" DD Bailer to 4108' RKB, work tool. OOH w/ sandy slurry. RD SLU. RU ELU. MU CCL/GR tool suite & surface test. PU 2.78" GR w/ junk basket. CCL-to-Bottom of GR = 12'. PT WLV & Lub = 250/2500 psi. Bleed WLV/Lub = 1000 psi. RIH w/ 2.78" GR to 4047' CCL. Log up to 3858' CCL for correlation pass. Correct +9.75'. RIH to tag @ top of 3- 1/2" CIBP @ 4098.0' CCL. 4098.0' + 12' = 4110' TOP OF CIBP. Log up to 3990' & POOH. OOH w/ sand slurry covering tools suite. Surface test & GR/CCLfire check CIBP running tool. Pressure up WLV & Lub =1000 psi. Open swab & RIH w/ GR/CCL + 3-1/2" CIBP w/ running tool to 120'. STOP, Eline cable "bird nested". Slowly POOH w/ tool suite & close swab. RD Lub & LD tool suite. Eline crew working cable to remove bird nest. Work cable off drum to remove bird nest. Spool cable back to drum. SDFN. Job In Progress. Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 06/11/2020- Thursday PJSM & permit. T/IA = 936/936 psi. RU SLU w/ 2.25" Pump Bailer. Pressure up to 950 psi. Open swab & RIH w/ 2.25" Pump Bailer to 4108' RKB (SLM) Top of CIBP#2. OOH w/ thin, sandy slurry. RU ELU. MU GR/CCL & surface test. Fire check running tool & PU 3-1/2" CIBP (2.75" OD). CCL-to- Top of CIBP = 12.7' CCL-to-Mid Element = 13.1' CCL-to Bottom CIBP = 13.6'. Pressure up to 950 psi. Open swab & RIH to 4070' CCL, log up to 3814' CCL. Correct +10'. RIH to 4096.4' CCL (4096.4' + 13.6' = 4110' Bottom of Plug, 4109.5' Mid-Element). PU to T = 570#. Fire to set 3-1/2" CIBP#3 @ 4109.5 Mid-Element. Wait 10 minutes, T = 540#. Slack off 400#, PU clean off CIBP. PUH 50', RBIH to tag @ top of CIBP#3 @ 4109' RKB. Log up 200' & POOH. OOH w/ 3-1/2" CIBP#3 set in 3-1/2" Liner. Surface test GR/ CCL. PU 2- 1/2" X 10' dump bailer & load w/ 1.5 gal. of 15.8 ppg cement. CCL-to-Bottom of Bailer = 16.5'. Pressure up to 950 psi. Open swab & RIH to 4071' CCL, log up to 3882' CCL. Correct +10.75'. Pressure up to 950 psi. RIH to 4083.5' CCL tag depth (4083.5' + 16.5' = 4101' Bottom of Bailer). Tag is 8' above top of CIBP#3 set depth. PUH 20', RBIH to tag at same. Log up to check correlation, correctly correlated. RBIH to tag @ same, repeat w/ same. POOH w/ bailer. OOH w/ bailer still loaded w/ cement. Drain & clean bailer tube. Pressure up to 950 psi. RIH w/ GR/CCL tools suite to 4075' CCL. CCL-to-Bottom of CCL = 5.6'. Log up to 3894' CCL, Correct +13.5'. RIH to 4103.5' CCL tag top of CIBP#3 (4103.5' + 5.6' = 4109.1'). CIBP#3 is set on depth @ 4109' RKB. Log up 200' & POOH. Call for 2" x 10' bailer section. RU SLU. Pressure up to 950 psi. RIH w/ 2.50" X 5' DD Bailer (No additional 5' bailer sub in box to add ) to 4109' RKB w/o resistance or restriction. POOH. OOH w/ thin, sandy slurry. PU 2.25" Pump Bailer & RIH to same w/o resistance or restriction. OOH w/ thin, sandy slurry. Exterior of both tool strings came back with sandy slurry coating, same as all EL & SL tools have come to surface today & previous day. RD SLU. RU ELU. Waiting on helicopter. Helicopter arrives platform w/ 2" x 10' bailer sub. Surface test GR/CCL & load bailer w/ 15.8 ppg cement. CCL-to-Bottom of Bailer = 15.8'. Pressure up to 950 psi. RIH. Fluid top @ 3400'. Tool suite fails at 3433'. Turn off/on tool power, NO LOVE. Repeat w/ same. PUH above fluid, turn off/on tool power, same. POOH to PU replacement tools. OOH, drain cement from bailer. PU replacement tools & test. Re-load 2" X 10" dump bailer w/ 15.8 ppg cement. CCL-to-Bottom of Bailer = 15.9'. Pressure up to 950 psi. RIH. 2nd tool set fails at 3576'. Turn off/on tool power, NO LOVE. PUH to 3433', turn off tools, re-start software, turn on tools & tools powered on. RIH 50', tools fail. POOH. OOH, drain & clean cement from bailer sub. Secure well & drill deck. SDFN. Job In Progress. Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 06/12/2020 - Friday PJSM & permit. Troubleshoot ELU & tools. Rehead RS(6/2) & tested weight bars & identified 1 suspect WB. Tagged & removed WB. Connected tool suite & test GR/CCL - tested good. Test Fire tools - failed. Shooting panel in alarm is cause of failed test fire. Call for replacement shooting panel. Cut 100' of line & rehead RS(6&2). Tested the line - line good. Helo delivers replacement shooting panel. Hook up replacement shooting panel & test. No DC voltage to shooting panel. No DC power to ELU. Shut down ELU power pack, unable to re-start engine. Hooked up battery charger to ELU power pack battery. Able to start ELU power pack engine. Left battery charger hooked up to battery in charge mode. Have DC power to shooting panel. Added battery charger to Hot Work Permit. PU GR/CCL & 2" X 10' dump bailer. Load bailer w/ 15.8 ppg cement. CCL-to-bailer bottom = 15.9'. Move to well. Pressure up WLV & Lub = 1000 psi. Open swab & RIH to 4075' CCL, log up to 3888' CCL. Correct +9'. RIH to 4093.1' CCL (4093.1' + 15.9' = 4109' Top of CIBP#3). PUH 4', fire to dump - fails. Voltage, but no current, @ shooting panel. Repeated 2 more times w/ same result. Swap back to original shooting panel & attempt to fire - fails again. PUH to 4000' & RBIH @ 250 FPM to tag at top of CIBP#3. Bailer disc breaks w/ tag. Cycle 5' in hole, 6 times, dumping cement while watching tension weight fall. POOH. OOH w/ bailer disc broken & 3.6' of cement left on top of CIBP#3. RD ELU. Waiting on cement. Job in Progress. 06/13/2020 - Saturday PJSM & permit. RU SLU. RIH w/ 2.50" x 5' DD Bailer. Fluid Top @ 3400'. TIH to 4101' RKB. Work tools to 4102' RKB w/ little to no spang action. OOH w/ thin, sandy slurry. RBIH w/ 2.25" Pump bailer to 4101' RKB. Work tools to 4103' RKB hard tag. Cement Top = 4103' RKB. OOH w/ 3 cups thick slurry. Turnover to Prod. Ops. for drawdown & negative test of plug. Start DD @ 10:00, Initial T/IA = 932/932, 10:15 Start T/IA =654/654, 10:45 T/IA = 645/654, 11:00 Final T/IA = 645/654. SLU RIH w/ 2.72" Blind Box to fluid top @ 3400'. Negative test - PASS. SLU PU 3 cup #-1/2" swab mandrel. RIH to 3450'. to check cups & cut 100' of wire. RBIH w/ 3 cup 3-1/2" swab mandrel. Prod. Op. brings well online @ 1.9 MMSCFD w/ 2.2 MMSCFD gas lift. Flowing WHP = 58 psi. SLU begins swabbing, taking 75' - 125' bites. 12 swab pulls, tagging top of plug at 4103' RKB. SI well & Gas lift & allow well to equalize. POOH. SLU RIH w/ 2.72" Blind Box. Fluid top @ 4072' RKB. Tag top of CIBP#3 @4103' RKB. POOH. RD SLU. SDFN. Job in Progress. Rig Start Date End Date HAK 404 5/18/20 6/14/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name NCI A-07 50-883-20027-00-00 169-058 Daily Operations: 06/14/2020 - Sunday PJSM & permits. RU ELU. MU GR/CCL & test. Fire check firing head. PU Perf Gun#1: 2-3/8" X 10' 2311 XDP-Gas GeoRazor carrier, 5 spf, 60* phase, 10.8 gm RDX GeoRazor charges. CCL-to-Top Shot = 8.3' CCL-to-Bottom Shot = 18.1' T/IA = 839/850. Move to Well. PT = 250/2500. RIH w/ Perf Gun#1 to 4075' CCL, log up to correlate to 3800' CCL. Correct +10.75'. Send correlation pass files for review and verification. Correlation correction verified & approved. RBIH to 4083' CCL. Log up to 4081.7" CCL to put shots on depth (4081.7' + 8.3' = 4090' Top Shot). Fire Perf Gun#1 to perforate Zone Stray-3 4090' - 4100' RKB. Log up 200' & POOH. OOH w/ all shots fired. Surface test GR/CCL & firing head. PU Perf Gun#2: 2-3/8" X 15' 2311 XDP-Gas GeoRazor carrier, 5 spf, 60* phase, 10.8 gm RDX GeoRazor charges. CCL-to-Top Shot = 13.2' CCL-to-Bottom Shot = 28.2' T/IA = 834/845. RIH w/ Perf Gun#2 to 4063' CCL, log up to correlate to 3823' CCL. Correct +8.5'. Send correlation pass files for review and verification. Correlation correction verified & approved. RBIH to 4066' CCL. Log up to 4040.8' to put shots on depth (4040.8' + 13.2' = 4054' Top Shot). Fire Perf Gun #2 to perforate Zone Stray-2 4054' - 4069' RKB. Log up 200' & POOH. OOH w/ all shots fired. T/IA = 834/845. RD & secure ELU. Secure well & turn over to Prod. Ops. Secure & clean drill deck. Fly ELU crew to beach. CIBP & perforation correlation, set & shooting pass logs saved to O Drive A-07 Project file. FLOOR SAFTY VALVES: BOP STACK: STATE OF ALASKA Reviewed By: OIL AND GAS CONSERVATION COMMISSION P.I. Supry �_i *Zv BOPE Test Report for: N COOK INLET UNIT A-07 ✓ Comm Contractor/Rig No.: Hilcorp 404 PTD#: 1690580 ' DATE: 5/21/2020 ' Inspector Lou Laubenstein - Insp Source Operator: Hilcorp Alaska, LLC Quantity Operator Rep: Soule/Brumley Rig Rep: Hannevold/Steiner Inspector Type Operation: WRKOV - Sundry No: Test Pressures: Inspection No: bopLOL200525111918 NA Stripper Rams: Annular: Valves: MASP: Ty pe Tes[: [NIT - 320-150 2502500 250/2500 - 2502500- 1352 Related Insp No: .NA' Annular Preventer - TEST DATA P - MISC. INSPECTIONS: MUD SYSTEM: ACCUMULATOR SYSTEM: I P/F Visual Alarm Time/Pressure P/F Location Gen.: P Trip Tank NA NA- System Pressure 3000 - P Housekeeping: .P Pit Level Indicators P = P-1 Pressure After Closure 1900 - P PTD On Location P Flow Indicator NA NA • 200 PSI Attained 45 P - Standing Order Posted P Meth Gas Detector P _ P . Full Pressure Attained 199_ _P Well Sign P_ _ H2S Gas Detector P P - Blind Switch Covers: yes - P - Drl. Rig P _ MS Mise NA NA Nitgn. Bottles (avg): 6@1950 P ' Hazard Sec. P '_ ACC Misc . 0 NA Misc NA FLOOR SAFTY VALVES: BOP STACK: CHOKE MANIFOLD: Quantity P/F Quantity Size P/F Quantity P/F Upper Kelly _._ 0 NA Stripper 0 _ NA_ No. Valves _10 _ P Lower Kelly _0 — .NA' Annular Preventer - 1 - 13 5/8" P - Manual Chokes 1 P Ball Type I P 41 Rams I 2-7/8x5-1/2 P=_ Hydraulic Chokes 1 1' Inside BOP 1 - P ' #2 Rams 1 ' Blinds P CH Misc 0 NA FSV Misc _ _ _ 0 NA #3 Rams - 0 NA #4 Rams 0 NA INSIDE REEL VALVES: #5 Rams 0 NA_ #6 Rams 0 NA (Valid for Coil Rigs Only) Choke Ln. Valves 1 -2-1/16" P Quantity P/F HCR Valves 2 ' 2-1/16" P Inside Reel Valves 0 NA Kill Line Valves 22-1/16" P — Check Valve _ 0 NA BOP Misc 0 NA Number of Failures: 0 Test Results Test Time 3.5 Remarks: test completed with 3-1/2 and 4-1/2 test joints 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): North Cook Inlet / Tertiary Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,126'N/A Casing Collapse Structural Conductor Surface 2,090 psi Intermediate Production 3,270 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:mmckinley@hilcorp.com Contact Phone: (907) 777-8387 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: 6,905'7" 8,108' 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. In progress under Sundry 320-150 4-1/2" Daniel E. Marlowe Packers (x6) see schematic & Halliburton "XXO" SVLN Perforation Depth MD (ft): 4,406 - 4,701 8,108' Packers - see schematic & 285 (MD) 285 (TVD) Tubing Grade:Tubing MD (ft): 3,864 - 4,101 Perforation Depth TVD (ft): 12.6 / L-80 & 12.75 / J-55 TVD 30" 10-3/4" 388' 2,522'3,580 psi 388' 2,364' 388' 2,522' Anchorage, AK 99503 Hilcorp Alaska, LLC N Cook Inlet Unit A-07 MDLength Size COMMISSION USE ONLY Authorized Name: Burst 6,925 4,360 psi Tubing Size: Authorized Signature: Operations Manager Mark McKinley CO 68A PRESENT WELL CONDITION SUMMARY 4,849 & 6,2946,918' 4,837' 4,212' 1,352 psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 169-058 50-883-20027-00-00 Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 1:30 pm, Jun 08, 2020 320-246 Daniel Marlowe I am approving this document 2020.06.08 13:10:09 -08'00' Daniel Marlowe DSR-6/8/2020 In progress under Sundry 320-150 10-404 (Report 320-150 & 320-246) gls 6/9/20 SFD 6/9/2020 Comm n Required? Yes 6/10/2020 dts 6/9/2020 JLC 6/10/2020 RBDMS HEW 6/12/2020 Well Work Prognosis REVISION 2 06/08/2020 Well Name:NCIU A-07 API Number: 50-883-20027-00 Current Status:SI Gas Producer Leg:Leg #3 SE Corner Estimated Start Date:April 20th, 2020 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:169-058 First Call Engineer:Mark McKinley (907) 777-8387 (O) (907) 953-2685 (M) Second Call Engineer:Dan Marlowe (907) 283-1329 (O) (907) 398-9904 (M) Current Bottom Hole Pressure: 1,758 psi @ 4,061’TVD 0.433 psi/ft gradient to surface Maximum Expected BHP:1,758 psi @ 4,061’ TVD 0.433 psi/ft gradient to surface Maximum Potential Surface Pressure: 1,352 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary The NCIU A-07 well was drilled and completed in 1969 as a commingled Cook Inlet and Beluga producer. In 1994 the well was recompleted with a series of sliding sleeves and packers between several Cook Inlet and Beluga sands. In 2005, fill came in to 4,850’. In 2006 a coil tubing cleanout was performed down to 7,050’. The well continue to produce sand and bringing in fill. The well is currently shut-in. It is proposed to isolate the Cook Inlet 1, 2, 3, and 4 sands by placing an X-plug in the profile at 4,329’. Then install a cemented 3.5” liner from ±4,260’ – 3,550’ setting the well up to produce the Cook Inlet A, B,Stray 1, 2, 3, X, and Z sand through a single string completion. The intent is to produce these sands independently starting with the lowest. After the first interval is depleted, a plug would be set and the next sand perforated. **This revision to Sundry 320-150 includes the Stray 2 sands on the proposed schematic. The Sterling A & B both proved to be wet. The Stray X & Z will be added in the future under a separate sundry request. Waiver Request: Hilcorp requests waiver to 20AAC25.265(c)(1). We request locating the SSV on the tree wing allowing the SSV to remain in the production stream while providing concurrent well bore access. Additionally, a SSSV will be installed. Wellbore Notes: Tubing punch at ~4,314’ Slickline will removed SSSV and bail any sand in tubing to below 4,340’. An X-plug will be set in the profile labeled as “B” on the proposed schematic. Procedure: 1. Rig up E-line. PT lubricator to 2,500 psig 2. RIH with tubing cutter. Cut tubing at ~4,320’. RD E-line. 3. MIRU HAK 404 4. Test BOP’s to 250psi low/2,500psi high / 2,500 psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 5. Workover fluid will be brine. BOP’s will be closed as needed to circulate the well. a. Pressure test and chart IA to 1,500 psig for 30 min. 6. Pull upper completion, fishing tubing and cleaning out as needed to ±4,320’. Lay down 4-1/2” tubing completion. 7. RIH with casing scraper to tubing cut ±4,320’. Circulate clean. POOH. 8. RU E-line CBL Logging tool. RIH with tool. Log ±4,300’ to TOC). POOH. Send log to AOGCC as soon as practical. 9. P/U and rack back work string 10. RIH with 7” x 3-1/2” liner hanger assembly and 3-1/2” Liner to ±4,260’ per program 1. RIH with Shoe, 1 st liner joint, float collar, 2nd line joint, and landing collar. This may vary at time of running. *Keep joints as short as practical to minimize spacing. Well Work Prognosis REVISION 2 06/08/2020 2. RIH with liner and confirm number of joints. *Fill liner as necessary to prevent collapse. 3. PU Liner Hanger Assembly: Liner Hanger, Liner Top Packer, and 10’ Extension 4. PU running/setting tools 5. RIH with 3-1/2” work string. Confirm pipe tally. 11. At proper liner depth, circulate minimum of one bottoms up to condition the wellbore. 12. RU cementing equipment. Pressure test cementing equipment to 5,000 psig. 13. Position liner in tension. Shoe at ±4,260’. 14. Cement liner from ±3,550’ to ±4,260’ per program, 1. Pump ~40 bbl of 8.34 ppg spacer fluid at 3-4 GPM. 2. Pump ~33 bbl (includes 20%) of 15.8 ppg Cement at 3-4 GPM. 3. Engage Liner Wiper Plug 4. Pump ~37 bbl of 8.34 ppg Displacement fluid at 3-4 BPM. 5. As the liner wiper plug nears the landing collar, make note of volume. Bump Plug. 15. Set liner hanger system and/or liner packer per specific setting procedure for model run. 16. Release from Liner Hanger Assembly. Slack off to verify weight change. 17. PU until running tool assembly is just above TOL and circulate out excess cement. POOH. 18. RIH with 4-1/2” tubing to SSSV Nipple, 4-1/2” x 3-1/2” crossover, 3-1/2” tubing, 3-1/2” Gas Lift completion (live valves) and packer assembly. See proposed schematic for detail and set depths. 19. Set Packer / Pressure test completion: 1. Pressure up and set packer 2. Test tubing against plug in X nipple to >2,500psig and chart for 30 minutes. 3. Test IA to 1,500 psi and chart for 30 minutes (This will pressure up tubing also). 4. Pull prong and plug in X-Nipple. 20. Set BPV. NU tree, test same. 21. RU E-line and perforate per program. 22. RD HAK 404 23. Turn over to production. 24. If a sand tests wet, a plug will be set and the next sand perforated until a productive sand is found. 25. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed - Updated 3. Wellhead Schematic Proposed 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form _____________________________________________________________________________________ Updated By: JLL 06/08/20 PROPOSED SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/1994 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4” 45.5 & 51 J-55 BT&C Surf 2,522’ 7” 26 J-55 BT&C Surf 79’ 23 J-55 BT&C 79’ 7,100’ 26 J-55 BT&C 7,100’8,108’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surf ±395’ 3-1/2” 9.2 L-80 IBT 2.992” ±395’ ±3,550’ 3-1/2” 9.2 L-80 8RD EUE 2.992” ±3,550’ ±4,320’ 4-1/2” 12.75 J-55 Mod EUE 8rd ±4,320’ 5,129’ 4-1/2” 12.75 J-55 EUE 8rd 5,129’ 6,925’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 39.40’ 39.40’ 3.958 6.000 FMC / OCT 6” 3M 4-1/2” 8rd x 4-1/2” BTC Tbg Hanger 1 ±350’ ±350’ 3.813 4.920 Halliburton “XXO” SVLN 2 ±395’ ±395’ 4-1/2” x 3-1/2” Crossover 3 ±1,785’ ±1,751’ 2.867” 5.313” GLM #1 –SFM –1; IPOC-1 20/64” ±3,447’ ±3,100’ 2.867” 5.313” GLM #2 –SFM –1; Orifice 20/64” 4 ±3,470’ ±3,120’ 2.867” 5.313” Chemical Injection Mandrel 5 ±3,500 ±3,144’ 3.000” 6.000” Packer –Hydraulic Retrievable 6 ±3510’ ±3,152’ 2.813” 3.750” X-Nipple 7 ±3,540’ ±3,175’ 2.992” 3.500” Dummy seal bore Assembly 8 ±3,550’ ±3,183’ 4.176” 5.924” ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 9 ±4,115’ ±3,632’ CIBP w/ 5’ cement 10 ±4,170’ ±3,676’ CIBP w/ 5’ cement 11 ±4,320’ ±3,796’ Landing collar and float Assembly 12 ±4,320’ ±3,796’ Tubing Cut 4,328’ 3,802’ 1.71 3.125 Profile Nipple R Nipple A 4,329’ 3,803’ 3.813 5.030 Halliburton X Nipple w/ plug set B 4,370’ 3,806’ 3.992 5.080 Ratch Latch Seal Unit 4,371’ 3,806’ 3.880 5.980 Halliburton VSR Packer C 4,591’ 4,013’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) D 4,605’ 4,024’ 3.992 5.560 Halliburton No-Go Locator 4,606’ 4,025’ 4.000 5.815 Halliburton TWR Packer & Millout Extension E 4,711’ 4,109’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) F 4,723’ 4,119’ 3.992 5.080 Halliburton No-Go Seal Unit 4,724’ 4,120’ 4.000 5.815 Halliburton TWR Packer & Millout Extension G 4,849’ 4,222’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) H 4,861’ 4,232’ 3.950 5.080 Halliburton No-Go Seal Unit 4,862’ 4,233’ 4.000 5.815 Halliburton TWR Packer & Millout Extension I 4,943’ 4,299’ 3.950 5.080 Ratch Latch Seal Unit 4,944’ 4,299’ 4.000 5.815 Halliburton TWR Packer & Millout Extension J 5,080’ 4,411’ 3.813 5.530 Halliburton XA Sliding Sleeve (Closed) K 5,116’ 4,441’ 3.950 5.080 Ratch Latch Seal Unit 5,117’ 4,441’ 4.000 5.815 Halliburton TWR Packer & Millout Extension L 5,601’ 4,841’ 3.813 5.530 Halliburton XD Sliding Sleeve (Open) M 6,294’ 5,410’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) N 6,893’ 5,984’ 3.725 5.030 Halliburton XN Nipple O 6,925’ 5,920’ 3.992 5.580 WLREG P PBTD: 7,050’ TD: 8,126’ 2 30” RKB: 39.40’, RKB to MSL: 116’ RKB to Mudline: 236’ 7” 3 4 5 67 A C D E F G H I J K L M 10-3/4” 1 TOC @ 2,510’ N O P B Fill @ 4,837’ CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-8.0 CI-9.0 C-4 D-1 K-1 D-2 E-9 F3 & F-4 G-1 H-1.1 H-2 H-4 & H-5 H-6 & H-7 H-7.1 H-9 J-1 J-3 K-2 K-5 M-4 N-2 & N-3 Ci 1.0 CI-2.0 7” CIBP w/ 5’ cement Tubing cut @ 4,320’ 12 Stray 2 Stray 3 Sterling A Sterling B 10 8 9 11 XN X R X _____________________________________________________________________________________ Updated By: JLL 06/05/20 PROPOSED SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/1994 PTD: 169-058 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Stray 2 ±4,054’ ±4,069’ ±3,583’ ±3,595’ ±15’ Future Proposed Stray 3 ±4,090’ ±4,100’ ±3,612’ ±3,620’ ±10’ Future Proposed Sterling A ±4,120’ ±4,130’ ±3,636’ ±3,644’ ±10’ 06/03/20 Isolated Sterling B ±4,170’ ±4,175’ ±3,676’ ±3,680’ ±5’ 05/30/20 Isolated CI-1.0 4,406' 4,476' 3,864' 3,920' 70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999' 80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047' 10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101' 50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171' 40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215' 10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266' 25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321' 7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404' 19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833' 5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867' 5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885' 10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093' 5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167' 25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226' 10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321' 5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336' 10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368' 20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398' 25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407' 5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453' 7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581' 10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616' 15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634' 5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651' 7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697' 10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781' 7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913' 25' Jun-94 Isolated Well Work Prognosis REVISION 2 06/08/2020 Well Name:NCIU A-07 API Number: 50-883-20027-00 Current Status:SI Gas Producer Leg:Leg #3 SE Corner Estimated Start Date:April 20th, 2020 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:169-058 First Call Engineer:Mark McKinley (907) 777-8387 (O) (907) 953-2685 (M) Second Call Engineer:Dan Marlowe (907) 283-1329 (O) (907) 398-9904 (M) Current Bottom Hole Pressure: 1,758 psi @ 4,061’TVD 0.433 psi/ft gradient to surface Maximum Expected BHP:1,758 psi @ 4,061’ TVD 0.433 psi/ft gradient to surface Maximum Potential Surface Pressure: 1,352 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary The NCIU A-07 well was drilled and completed in 1969 as a commingled Cook Inlet and Beluga producer. In 1994 the well was recompleted with a series of sliding sleeves and packers between several Cook Inlet and Beluga sands. In 2005, fill came in to 4,850’. In 2006 a coil tubing cleanout was performed down to 7,050’. The well continue to produce sand and bringing in fill. The well is currently shut-in. It is proposed to isolate the Cook Inlet 1, 2, 3, and 4 sands by placing an X-plug in the profile at 4,329’. Then install a cemented 3.5” liner from ±4,260’ – 3,550’ setting the well up to produce the Cook Inlet A, B,Stray 1, 2, 3, X, and Z sand through a single string completion. The intent is to produce these sands independently starting with the lowest. After the first interval is depleted, a plug would be set and the next sand perforated. **This revision to Sundry 320-150 includes the Stray 2 sands on the proposed schematic. The Sterling A & B both proved to be wet. The Stray X & Z will be added in the future under a separate sundry request. Waiver Request: Hilcorp requests waiver to 20AAC25.265(c)(1). We request locating the SSV on the tree wing allowing the SSV to remain in the production stream while providing concurrent well bore access. Additionally, a SSSV will be installed. Wellbore Notes: Tubing punch at ~4,314’ Slickline will removed SSSV and bail any sand in tubing to below 4,340’. An X-plug will be set in the profile labeled as “B” on the proposed schematic. Procedure: 1. Rig up E-line. PT lubricator to 2,500 psig 2. RIH with tubing cutter. Cut tubing at ~4,320’. RD E-line. 3. MIRU HAK 404 4. Test BOP’s to 250psi low/2,500psi high / 2,500 psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 5. Workover fluid will be brine. BOP’s will be closed as needed to circulate the well. a. Pressure test and chart IA to 1,500 psig for 30 min. 6. Pull upper completion, fishing tubing and cleaning out as needed to ±4,320’. Lay down 4-1/2” tubing completion. 7. RIH with casing scraper to tubing cut ±4,320’. Circulate clean. POOH. 8. RU E-line CBL Logging tool. RIH with tool. Log ±4,300’ to TOC). POOH. Send log to AOGCC as soon as practical. 9. P/U and rack back work string 10. RIH with 7” x 3-1/2” liner hanger assembly and 3-1/2” Liner to ±4,260’ per program 1. RIH with Shoe, 1 st liner joint, float collar, 2nd line joint, and landing collar. This may vary at time of running. *Keep joints as short as practical to minimize spacing. A & B both The Stray X & Z will be added in the future under a separate sundry request. **This revision to Sundry 320-150 includes the Stray 2 sands on the proposed schematic. The Sterling yypp proved to be wet. T Well Work Prognosis REVISION 2 06/08/2020 2. RIH with liner and confirm number of joints. *Fill liner as necessary to prevent collapse. 3. PU Liner Hanger Assembly: Liner Hanger, Liner Top Packer, and 10’ Extension 4. PU running/setting tools 5. RIH with 3-1/2” work string. Confirm pipe tally. 11. At proper liner depth, circulate minimum of one bottoms up to condition the wellbore. 12. RU cementing equipment. Pressure test cementing equipment to 5,000 psig. 13. Position liner in tension. Shoe at ±4,260’. 14. Cement liner from ±3,550’ to ±4,260’ per program, 1. Pump ~40 bbl of 8.34 ppg spacer fluid at 3-4 GPM. 2. Pump ~33 bbl (includes 20%) of 15.8 ppg Cement at 3-4 GPM. 3. Engage Liner Wiper Plug 4. Pump ~37 bbl of 8.34 ppg Displacement fluid at 3-4 BPM. 5. As the liner wiper plug nears the landing collar, make note of volume. Bump Plug. 15. Set liner hanger system and/or liner packer per specific setting procedure for model run. 16. Release from Liner Hanger Assembly. Slack off to verify weight change. 17. PU until running tool assembly is just above TOL and circulate out excess cement. POOH. 18. RIH with 4-1/2” tubing to SSSV Nipple, 4-1/2” x 3-1/2” crossover, 3-1/2” tubing, 3-1/2” Gas Lift completion (live valves) and packer assembly. See proposed schematic for detail and set depths. 19. Set Packer / Pressure test completion: 1. Pressure up and set packer 2. Test tubing against plug in X nipple to >2,500psig and chart for 30 minutes. 3. Test IA to 1,500 psi and chart for 30 minutes (This will pressure up tubing also). 4. Pull prong and plug in X-Nipple. 20. Set BPV. NU tree, test same. 21. RU E-line and perforate per program. 22. RD HAK 404 23. Turn over to production. 24. If a sand tests wet, a plug will be set and the next sand perforated until a productive sand is found. 25. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed - Updated 3. Wellhead Schematic Proposed 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form completed work per sundry 320-150 ------------------------- currently perfing well work under this sundry application. _____________________________________________________________________________________ Updated By: JLL 06/08/20 PROPOSED SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/1994 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4” 45.5 & 51 J-55 BT&C Surf 2,522’ 7” 26 J-55 BT&C Surf 79’ 23 J-55 BT&C 79’ 7,100’ 26 J-55 BT&C 7,100’8,108’ TUBING DETAIL 4-1/2” 12.6 L-80 IBT 3.958” Surf ±395’ 3-1/2” 9.2 L-80 IBT 2.992” ±395’ ±3,550’ 3-1/2” 9.2 L-80 8RD EUE 2.992” ±3,550’ ±4,320’ 4-1/2” 12.75 J-55 Mod EUE 8rd ±4,320’ 5,129’ 4-1/2” 12.75 J-55 EUE 8rd 5,129’ 6,925’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 39.40’ 39.40’ 3.958 6.000 FMC / OCT 6” 3M 4-1/2” 8rd x 4-1/2” BTC Tbg Hanger 1 ±350’ ±350’ 3.813 4.920 Halliburton “XXO” SVLN 2 ±395’ ±395’ 4-1/2” x 3-1/2” Crossover 3 ±1,785’ ±1,751’ 2.867” 5.313” GLM #1 –SFM –1; IPOC-1 20/64” ±3,447’ ±3,100’ 2.867” 5.313” GLM #2 –SFM –1; Orifice 20/64” 4 ±3,470’ ±3,120’ 2.867” 5.313” Chemical Injection Mandrel 5 ±3,500 ±3,144’ 3.000” 6.000” Packer –Hydraulic Retrievable 6 ±3510’ ±3,152’ 2.813” 3.750” X-Nipple 7 ±3,540’ ±3,175’ 2.992” 3.500” Dummy seal bore Assembly 8 ±3,550’ ±3,183’ 4.176” 5.924” ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 9 ±4,115’ ±3,632’ CIBP w/ 5’ cement 10 ±4,170’ ±3,676’ CIBP w/ 5’ cement 11 ±4,320’ ±3,796’ Landing collar and float Assembly 12 ±4,320’ ±3,796’ Tubing Cut 4,328’ 3,802’ 1.71 3.125 Profile Nipple R Nipple A 4,329’ 3,803’ 3.813 5.030 Halliburton X Nipple w/ plug set B 4,370’ 3,806’ 3.992 5.080 Ratch Latch Seal Unit 4,371’ 3,806’ 3.880 5.980 Halliburton VSR Packer C 4,591’ 4,013’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) D 4,605’ 4,024’ 3.992 5.560 Halliburton No-Go Locator 4,606’ 4,025’ 4.000 5.815 Halliburton TWR Packer & Millout Extension E 4,711’ 4,109’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) F 4,723’ 4,119’ 3.992 5.080 Halliburton No-Go Seal Unit 4,724’ 4,120’ 4.000 5.815 Halliburton TWR Packer & Millout Extension G 4,849’ 4,222’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) H 4,861’ 4,232’ 3.950 5.080 Halliburton No-Go Seal Unit 4,862’ 4,233’ 4.000 5.815 Halliburton TWR Packer & Millout Extension I 4,943’ 4,299’ 3.950 5.080 Ratch Latch Seal Unit 4,944’ 4,299’ 4.000 5.815 Halliburton TWR Packer & Millout Extension J 5,080’ 4,411’ 3.813 5.530 Halliburton XA Sliding Sleeve (Closed) K 5,116’ 4,441’ 3.950 5.080 Ratch Latch Seal Unit 5,117’ 4,441’ 4.000 5.815 Halliburton TWR Packer & Millout Extension L 5,601’ 4,841’ 3.813 5.530 Halliburton XD Sliding Sleeve (Open) M 6,294’ 5,410’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) N 6,893’ 5,984’ 3.725 5.030 Halliburton XN Nipple O 6,925’ 5,920’ 3.992 5.580 WLREG P PBTD: 7,050’ TD: 8,126’ 2 30” RKB: 39.40’, RKB to MSL: 116’ RKB to Mudline: 236’ 7” 3 4 5 67 A C D E F G H I J K L M 10-3/4” 1 TOC @ 2,510’ N O P B Fill @ 4,837’ CI-3.1 CI-4.0 CI-5.0 CI-6.0 CI-7.0 CI-8.0 CI-9.0 C-4 D-1 K-1 D-2 E-9 F3 & F-4 G-1 H-1.1 H-2 H-4 & H-5 H-6 & H-7 H-7.1 H-9 J-1 J-3 K-2 K-5 M-4 N-2 & N-3 Ci 1.0 CI-2.0 7” CIBP w/ 5’ cement Tubing cut @ 4,320’ 12 Stray 2 Stray 3 Sterling A Sterling B 10 8 9 11 XN X R X Stray 2 added Stray 2 sand to approval list _____________________________________________________________________________________ Updated By: JLL 06/05/20 PROPOSED SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/1994 PTD: 169-058 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Stray 2 ±4,054’ ±4,069’ ±3,583’ ±3,595’ ±15’ Future Proposed Stray 3 ±4,090’ ±4,100’ ±3,612’ ±3,620’ ±10’ Future Proposed Sterling A ±4,120’ ±4,130’ ±3,636’ ±3,644’ ±10’ 06/03/20 Isolated Sterling B ±4,170’ ±4,175’ ±3,676’ ±3,680’ ±5’ 05/30/20 Isolated CI-1.0 4,406' 4,476' 3,864' 3,920' 70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999' 80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047' 10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101' 50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171' 40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215' 10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266' 25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321' 7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404' 19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833' 5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867' 5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885' 10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093' 5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167' 25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226' 10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321' 5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336' 10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368' 20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398' 25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407' 5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453' 7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581' 10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616' 15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634' 5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651' 7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697' 10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781' 7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913' 25' Jun-94 Isolated 1 Carlisle, Samantha J (CED) From:Dan Marlowe <dmarlowe@hilcorp.com> Sent:Monday, June 8, 2020 1:25 PM To:Schwartz, Guy L (CED) Cc:Juanita Lovett; Mark McKinley Subject:NCIU A-07 PTD 169-058 / Sundry 320-150 Change of approved program Attachments:10-403 N Cook Inlet Unit A-07 Chg to Apprvd 2020-06-08.pdf Follow Up Flag:Follow up Flag Status:Flagged Guy Perourconversationthismorning Wewillelectronicallysubmitthischangeofapprovedprogram(attached)tolisttheStray2sandswewouldliketoadd WeshouldbereadyassoonasJune8th,dependingonbailingandpluggingoperations. Pleaseadvise Thanks Dan Marlowe Hilcorp Alaska, LLC Area Operations Manager - CIO Office 907-283-1329 Cell 907-398-9904 Email DMarlowe@hilcorp.com Hilcorp A Company Built on Energy 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): North Cook Inlet / Tertiary Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8,126'N/A Casing Collapse Structural Conductor Surface 2,090 psi Intermediate Production 3,270 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:jkaiser@hilcorp.com Contact Phone: (907) 777-8393 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 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 Authorized Signature: Operations Manager Joe Kaiser CO 68 PRESENT WELL CONDITION SUMMARY 4,849 & 6,2946,918' 4,837' 4,212' 1,352 psi COMMISSION USE ONLY Authorized Name: Burst 6,925 4,360 psi Tubing Size: 169-058 50-883-20027-00-00Anchorage, AK 99503 Hilcorp Alaska, LLC N Cook Inlet Unit A-07 MDLength Size 3,580 psi 388' 2,364' 388' 2,522' TVD 30" 10-3/4" 388' 2,522' Perforation Depth MD (ft): 4,406 - 4,701 8,108' Packers - see schematic & 285 (MD) 285 (TVD) Tubing Grade: Tubing MD (ft): 3,864 - 4,101 Perforation Depth TVD (ft): 12.6 / L-80 & 12.75 / J-55 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. 4/20/2020 4-1/2" Daniel E. Marlowe Packers (x6) see schematic & Halliburton "XXO" SVLN Other: G/L Completion 6,905'7" 8,108' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Daniel Marlowe I am approving this document 2020.04.02 13:23:38 -08'00' Daniel Marlowe By Samantha Carlisle at 2:49 pm, Apr 02, 2020 320-150 10-404 * 2500 psi BOP test *Alternate placement of SSV approved per 20AAC 25.265 SFD 4/2/2020 (o)(1) gls 4/7/20 X DSR-4/20/2020GWV equir ed? Yes No Com m. 4/8/2020 JLC 4/8/2020 Well Work Prognosis REVISION 1 4/6/2020 Well Name:NCIU A-07 API Number: 50-883-20027-00 Current Status:SI Gas Producer Leg:Leg #3 SE Corner Estimated Start Date:April 20th, 2020 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:169-058 First Call Engineer:Joe Kaiser (907) 777-8393 (O) (907) 952-8897 (M) Second Call Engineer:Dan Marlowe (907) 283-1329 (O) (907) 398-9904 (M) Current Bottom Hole Pressure: 1,758 psi @ 4,061’TVD 0.433 psi/ft gradient to surface Maximum Expected BHP:1,758 psi @ 4,061’ TVD 0.433 psi/ft gradient to surface Maximum Potential Surface Pressure: 1,352 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary The NCIU A-07 well was drilled and completed in 1969 as a commingled Cook Inlet and Beluga producer. In 1994 the well was recompleted with a series of sliding sleeves and packers between several Cook Inlet and Beluga sands. In 2005, fill came in to 4,850’. In 2006 a coil tubing cleanout was performed down to 7,050’. The well continue to produce sand and bringing in fill. The well is currently shut-in. It is proposed to isolate the Cook Inlet 1, 2, 3, and 4 sands by placing an X-plug in the profile at 4,329’. Then install a cemented 3.5” liner from ±4,260’ – 3,550’ setting the well up to produce the Cook Inlet A, B, Stray 1, 2, & 3, and X sand through a single string completion. The intent is to produce these sands independently starting with the lowest. After the first interval is depleted, a plug would be set and the next sand perforated. Waiver Request: Hilcorp requests waiver to 20AAC25.265(c)(1). We request locating the SSV on the tree wing allowing the SSV to remain in the production stream while providing concurrent well bore access. Additionally, a SSSV will be installed. Wellbore Notes: x Tubing punch at ~4,314’ x Slickline will removed SSSV and bail any sand in tubing to below 4,340’. An X-plug will be set in the profile labeled as “B” on the proposed schematic. Procedure: 1. Rig up E-line. PT lubricator to 2,500 psig 2. RIH with tubing cutter. Cut tubing at ~4,320’. RD E-line. 3. MIRU HAK 404 4. Test BOP’s to 250psi low/2,500psi high / 2,500 psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 5. Workover fluid will be brine. BOP’s will be closed as needed to circulate the well. a. Pressure test and chart IA to 1,500 psig for 30 min. 6. Pull upper completion, fishing tubing and cleaning out as needed to ±4,320’. Lay down 4-1/2” tubing completion. 7. RIH with casing scraper to tubing cut ±4,320’. Circulate clean. POOH. 8. RU E-line CBL Logging tool. RIH with tool. Log ±4,300’ to TOC). POOH.Send log to AOGCC as soon as practical. 9. P/U and rack back work string 10. RIH with 7” x 3-1/2” liner hanger assembly and 3-1/2” Liner to ±4,260’ per program 1. RIH with Shoe, 1 st liner joint, float collar, 2nd line joint, and landing collar. This may vary at time of running. *Keep joints as short as practical to minimize spacing. 2. RIH with liner and confirm number of joints. *Fill liner as necessary to prevent collapse. 3. PU Liner Hanger Assembly: Liner Hanger, Liner Top Packer, and 10’ Extension Well Work Prognosis REVISION 1 4/6/2020 4. PU running/setting tools 5. RIH with 3-1/2” work string. Confirm pipe tally. 11. At proper liner depth, circulate minimum of one bottoms up to condition the wellbore. 12. RU cementing equipment. Pressure test cementing equipment to 5,000 psig. 13. Position liner in tension. Shoe at ±4,260’. 14. Cement liner from ±3,550’ to ±4,260’ per program, 1. Pump ~40 bbl of 8.34 ppg spacer fluid at 3-4 GPM. 2. Pump ~33 bbl (includes 20%) of 15.8 ppg Cement at 3-4 GPM. 3. Engage Liner Wiper Plug 4. Pump ~37 bbl of 8.34 ppg Displacement fluid at 3-4 BPM. 5. As the liner wiper plug nears the landing collar, make note of volume. Bump Plug. 15. Set liner hanger system and/or liner packer per specific setting procedure for model run. 16. Release from Liner Hanger Assembly. Slack off to verify weight change. 17. PU until running tool assembly is just above TOL and circulate out excess cement. POOH. 18. RIH with 4-1/2” tubing to SSSV Nipple, 4-1/2” x 3-1/2” crossover, 3-1/2” tubing, 3-1/2” Gas Lift completion (live valves) and packer assembly. See proposed schematic for detail and set depths. 19. Set Packer / Pressure test completion: 1. Pressure up and set packer 2. Test tubing against plug in X nipple to >2,500psig and chart for 30 minutes. 3. Test IA to 1,500 psi and chart for 30 minutes (This will pressure up tubing also). 4. Pull prong and plug in X-Nipple. 20. Set BPV. NU tree, test same. 21. RU E-line and perforate per program. 22. RD HAK 404 23. Turn over to production. 24. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Proposed 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form _____________________________________________________________________________________ Updated By: JLL 01/06/2020 SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/1994 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4” 45.5 & 51 J-55 BT&C Surf 2,522’ 7” 26 J-55 BT&C Surf 79’ 23 J-55 BT&C 79’ 7,100’ 26 J-55 BT&C 7,100’ 8,108’ TUBING DETAIL 4-1/2” 12.60 L-80 Mod BT&C Surf 287’ 12.75 J-55 Mod EUE 8rd 287’ 5,129’ 12.75 J-55 EUE 8rd 5,129’ 6,925’ Tubing Punch Hole (4,314 –4,315) JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 39.40’ 39.40’ 3.958 6.000 FMC / OCT 6” 3M 4-1/2” 8rd x 4-1/2” BTC Tbg Hanger 1 285’ 285’ 3.813 4.920 Halliburton “XXO” SVLN 2 4,314’ 3,791’ .33” -- Tubing Punch Hole (4,314 –4,315) 3 4,328’ 3,802’ 1.71 3.125 Profile Nipple R Nipple 4 4,329’ 3,803’ 3.813 5.030 Halliburton X Nipple 4,370’ 3,806’ 3.992 5.080 Ratch Latch Seal Unit 5 4,371’ 3,806’ 3.880 5.980 Halliburton VSR Packer 6 4,591’ 4,013’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) 4,605’ 4,024’ 3.992 5.560 Halliburton No-Go Locator 7 4,606’ 4,025’ 4.000 5.815 Halliburton TWR Packer & Millout Extension 8 4,711’ 4,109’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) 4,723’ 4,119’ 3.992 5.080 Halliburton No-Go Seal Unit 9 4,724’ 4,120’ 4.000 5.815 Halliburton TWR Packer & Millout Extension 10 4,849’ 4,222’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) 4,861’ 4,232’ 3.950 5.080 Halliburton No-Go Seal Unit 11 4,862’ 4,233’ 4.000 5.815 Halliburton TWR Packer & Millout Extension 4,943’ 4,299’ 3.950 5.080 Ratch Latch Seal Unit 12 4,944’ 4,299’ 4.000 5.815 Halliburton TWR Packer & Millout Extension 13 5,080’ 4,411’ 3.813 5.530 Halliburton XA Sliding Sleeve (Closed) 5,116’ 4,441’ 3.950 5.080 Ratch Latch Seal Unit 14 5,117’ 4,441’ 4.000 5.815 Halliburton TWR Packer & Millout Extension 15 5,601’ 4,841’ 3.813 5.530 Halliburton XD Sliding Sleeve (Open) 16 6,294’ 5,410’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) 17 6,893’ 5,984’ 3.725 5.030 Halliburton XN Nipple 18 6,925’ 5,920’ 3.992 5.580 WLREG PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status CI-1.0 4,406' 4,476' 3,864' 3,920' 70' Jun-94 Open CI-2.0 4,494' 4,574' 3,935' 3,999' 80' Jun-94 Open CI-3.1 4,624' 4,634' 4,039' 4,047' 10' Jun-94 Open CI-4.0 4,651' 4,701' 4,061' 4,101' 50' Jun-94 Open CI-5.0 4,746' 4,786' 4,138' 4,171' 40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215' 10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266' 25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321' 7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404' 19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833' 5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867' 5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885' 10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093' 5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167' 25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226' 10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321' 5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336' 10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368' 20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398' 25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407' 5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453' 7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581' 10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616' 15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634' 5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651' 7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697' 10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781' 7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913' 25' Jun-94 Isolated PBTD: 7,050’ TD: 8,126’ 30” RKB: 39.40’, RKB to MSL: 116’ RKB to Mudline: 236’ 7” CI -1.0 3 5 6 7 8 9 10 11 12 13 14 15 10-3/4” 1 2 TOC @ 2,510’ 16 17 18 4 Fill @ 4,837’ CI -4.0 CI -5.0 CI-6.0 CI -7.0 CI -8.0 CI -9.0 C-4 D-1 K-1 D-2 E-9 F3 & F-4 G-1 H-1.1 H-2 H-4 & H-5 H-6 & H-7 H-7.1 H-9 J-1 J-3 K-2 K-5 M-4 N-2 & N-3 CI -2.0 CI -3.1 XN X R tbg perfs _____________________________________________________________________________________ Updated By: JK 3/24/20 PROPOSED SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/1994 PTD: 169-058 CASING DETAIL Size Wt Grade Conn ID Top Btm 30”Surf 388’ 10-3/4” 45.5 & 51 J-55 BT&C Surf 2,522’ 7” 26 J-55 BT&C Surf 79’ 23 J-55 BT&C 79’ 7,100’ 26 J-55 BT&C 7,100’8,108’ TUBING DETAIL 4-1/2” 12.6 L-80 Mod BT&C 3.958” Surf ±365’ 3-1/2” 9.2 L-80 IBT 2.992” ±365’ ±3,550’ 3-1/2” 9.2 L-80 8RD EUE 2.992” ±3,550’ ±4,260’ 4-1/2” 12.75 J-55 Mod EUE 8rd ±4,320’ 5,129’ 4-1/2” 12.75 J-55 EUE 8rd 5,129’ 6,925’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 39.40’ 39.40’ 3.958 6.000 FMC / OCT 6” 3M 4-1/2” 8rd x 4-1/2” BTC Tbg Hanger 1 ±350’ ±350’ 3.813 4.920 Halliburton “XXO” SVLN 2 ±365’ ±365’ 4-1/2” x 3-1/2” Crossover 3 ±1,785’ ±1,751’ 2.867” 5.313” GLM #1 –SFM –1; IPOC-1 20/64” ±3,447’ ±3,100’ 2.867” 5.313” GLM #2 –SFM –1; Orifice 20/64” 4 ±3,470’ ±3,120’ 2.867” 5.313” Chemical Injection Mandrel 5 ±3,500 ±3,144’ 3.000” 6.000” Packer –Hydraulic Retrievable 6 ±3510’ ±3,152’ 2.813” 3.750” X-Nipple 7 ±3,540’ ±3,175’ 2.992” 3.500” Dummy seal bore Assembly 8 ±3,550’ ±3,183’ 4.176” 5.924” ZXP Liner Top Packer with 10’ extension Hydraulic Flex-Lock V-Dbl Grip Liner Hanger 9 ±4,260’ ±3,748’ Landing collar and float Assembly 10 ±4,320’ ±3,796’ Tubing Cut 4,328’ 3,802’ 1.71 3.125 Profile Nipple R Nipple A 4,329’ 3,803’ 3.813 5.030 Halliburton X Nipple w/ plug set B 4,370’ 3,806’ 3.992 5.080 Ratch Latch Seal Unit 4,371’ 3,806’ 3.880 5.980 Halliburton VSR Packer C 4,591’ 4,013’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) D 4,605’ 4,024’ 3.992 5.560 Halliburton No-Go Locator 4,606’ 4,025’ 4.000 5.815 Halliburton TWR Packer & Millout Extension E 4,711’ 4,109’ 3.813 5.530 Halliburton XD Sliding Sleeve (Closed) F 4,723’ 4,119’ 3.992 5.080 Halliburton No-Go Seal Unit 4,724’ 4,120’ 4.000 5.815 Halliburton TWR Packer & Millout Extension G 4,849’ 4,222’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Closed) H 4,861’ 4,232’ 3.950 5.080 Halliburton No-Go Seal Unit 4,862’ 4,233’ 4.000 5.815 Halliburton TWR Packer & Millout Extension I 4,943’ 4,299’ 3.950 5.080 Ratch Latch Seal Unit 4,944’ 4,299’ 4.000 5.815 Halliburton TWR Packer & Millout Extension J 5,080’ 4,411’ 3.813 5.530 Halliburton XA Sliding Sleeve (Closed) K 5,116’ 4,441’ 3.950 5.080 Ratch Latch Seal Unit 5,117’ 4,441’ 4.000 5.815 Halliburton TWR Packer & Millout Extension L 5,601’ 4,841’ 3.813 5.530 Halliburton XD Sliding Sleeve (Open) M 6,294’ 5,410’ 3.813 5.530 Halliburton XD Sliding Sleeve w/ PX Plug (Open) N 6,893’ 5,984’ 3.725 5.030 Halliburton XN Nipple O 6,925’ 5,920’ 3.992 5.580 WLREG P PBTD: 7,050’ TD: 8,126’ 2 30” RKB: 39.40’, RKB to MSL: 116’ RKB to Mudline: 236’ 7” 3 4 5 67 A C D E F G H I J K L M 10-3/4” 1 TOC @ 2,510’ N O P B Fill @ 4,837’ CI -3.1 CI-4.0 CI -5.0 CI-6.0 CI -7.0 CI -8.0 CI-9.0 C-4 D-1 K-1 D-2 E-9 F3 & F-4 G-1 H-1.1 H-2 H-4 & H-5 H-6 & H-7 H-7.1 H-9 J-1 J-3 K-2 K-5 M-4 N-2 & N-3 Ci 1.0 CI-2.0 7” CIBP w/ 5’ cement Tubing cut @ 4,320’ 10 Stray 3 Sterling A Sterling B 9 8 XN X R X SSSV <------Test IA to 1500 psi _____________________________________________________________________________________ Updated By: JK 3/24/20 PROPOSED SCHEMATIC North Cook Inlet Unit Well: NCI A-07 Last Completed: 06/1994 PTD: 169-058 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Stray 3 ±4,089’ ±4,111’ ±3,611’ ±3,629’ ±22’ Proposed Sterling -A ±4,120’ ±4,130’ ±3,636’ ±3,644’ ±10’ Proposed Sterling - B ±4,170’ ±4,175’ ±3,676’ ±3,680’ ±5’ Proposed CI-1.0 4,406' 4,476' 3,864' 3,920' 70' Jun-94 Isolated CI-2.0 4,494' 4,574' 3,935' 3,999' 80' Jun-94 Isolated CI-3.1 4,624' 4,634' 4,039' 4,047' 10' Jun-94 Isolated CI-4.0 4,651' 4,701' 4,061' 4,101' 50' Jun-94 Isolated CI-5.0 4,746' 4,786' 4,138' 4,171' 40' Jun-94 Isolated CI-6.0 4,831' 4,841' 4,207' 4,215' 10' Jun-94 Isolated CI-7.0 4,878' 4,903' 4,246' 4,266' 25' Jun-94 Isolated CI-8.0 4,963' 4,970' 4,315' 4,321' 7' Jun-94 Isolated CI-9.0 5,053' 5,072' 4,389' 4,404' 19' Jun-94 Isolated C-4 5,587' 5,592' 4,829' 4,833' 5' Jun-94 Isolated D-1 5,628' 5,633' 4,863' 4,867' 5' Jun-94 Isolated D-2 5,645' 5,655' 4,877' 4,885' 10' Jun-94 Isolated E-9 5,901' 5,906' 5,089' 5,093' 5' Jun-94 Isolated F-3 & F-4 5,970' 5,995' 5,146' 5,167' 25' Jun-94 Isolated G-1 6,058' 6,068' 5,218' 5,226' 10' Jun-94 Isolated H-1.1 6,180' 6,185' 5,317' 5,321' 5' Jun-94 Isolated H-2 6,193' 6,203' 5,328' 5,336' 10' Jun-94 Isolated H-4 & H-5 6,223' 6,243' 5,352' 5,368' 20' Jun-94 Isolated H-6 & H-7 6,254' 6,279' 5,377' 5,398' 25' Jun-94 Isolated H-7.1 6,285' 6,290' 5,403' 5,407' 5' Jun-94 Isolated H-9 6,340' 6,347' 5,447' 5,453' 7' Jun-94 Isolated J-1 6,495' 6,505' 5,573' 5,581' 10' Jun-94 Isolated J-3 6,533' 6,548' 5,604' 5,616' 15' Jun-94 Isolated K-1 6,566' 6,571' 5,630' 5,634' 5' Jun-94 Isolated K-2 6,584' 6,591' 5,645' 5,651' 7' Jun-94 Isolated K-5 6,638' 6,648' 5,689' 5,697' 10' Jun-94 Isolated M-4 6,746' 6,753' 5,776' 5,781' 7' Jun-94 Isolated N-2 & N-3 6,891' 6,916' 5,893' 5,913' 25' Jun-94 Isolated Current Wellhead 3/04/2020 NCIU A-07 Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'͛LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'͛ Starting head, OCT, 30 ½ 1M X 28'͛BW, w/ 2- 4'͛1M EFO Tbg hanger, FMC-UH-A-EN, 6'͛X 4 ½ EUE 8rd lift and 4 ½ IBT susp, w/ 4'͛Type IS BPV profile, 1- ¼ non cont control line port Hanger is nested in pack-off and held down by lock plate Lock-plate needs to be removed before nipple up of BOPE Tyonek Platform A-07 28 X 16 X 10 3/4 X 7 x 4 1/2 Tree assy, 4 1/16 3M Adapter, 16 ¾ 5M clamp hub x 4 1/16 3M stdd top, prepped f/ 1- non cont control line port 16'͛ 10 ¾͛͛ 7'͛ 4 ½͛͛ Proposed Wellhead 03/27/2020 NCIU A-07 Unihead, OCT type 3, 16 3/4 5M BX-161 hub top X 16'͛LTC casing bottom, w/ 2- 2 LPO on lower section, 2- 2 1/16 5M SSO on middle section, 2- 2 1/16 5M SSO on upper section , IP internal lockpin assy 28'͛ Starting head, OCT, 30 ½ 1M X 28'͛BW, w/ 2- 4'͛1M EFO Tubing hanger, Cactus-EN- CCL, 11 x 4 ½ EUE 8rd lift and susp, w/ 4'͛type H BPV, 2- ¼ cont control line ports Tyonek Platform A-07 28 X 16 X 10 3/4 X 7 x 4 1/2 16'͛ 10 ¾͛͛ 7'͛ 4 ½͛͛ Tubing head attachment, Cactus, 11 5M FE X 16 3/4 5M BX-161 hub bottom Valve, Master, CIW-FLS, 4 1/16 5M FE, HWO, EE trim BHTA, Otis, 4 1/16 5M FE x 7.5 Otis quick union top Adapter, Cactus-EN-CCL, 11 5M stdd x 4 1/16 5M, w/ 2- 1'͛npt control line exits Valve, Master, CIW-FLS, 4 1/16 5M FE, HWO, EE trim Valve, Swab, CIW-FLS, 4 1/16 5M FE, HWO, EE trim SSV Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: N Cook Inlet Unit A-07 (PTD 169-058)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 Well Work Prognosis Well Name:NCIU A-07 API Number: 50-883-20027-00 Current Status:SI Gas Producer Leg:Leg #3 SE Corner Estimated Start Date:April 20th, 2020 Rig:HAK 404 Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:169-058 First Call Engineer:Joe Kaiser (907) 777-8393 (O) (907) 952-8897 (M) Second Call Engineer:Dan Marlowe (907) 283-1329 (O) (907) 398-9904 (M) Current Bottom Hole Pressure: 1,758 psi @ 4,061’TVD 0.433 psi/ft gradient to surface Maximum Expected BHP:1,758 psi @ 4,061’ TVD 0.433 psi/ft gradient to surface Maximum Potential Surface Pressure: 1,352 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Brief Well Summary The NCIU A-07 well was drilled and completed in 1969 as a commingled Cook Inlet and Beluga producer. In 1994 the well was recompleted with a series of sliding sleeves and packers between several Cook Inlet and Beluga sands. In 2005, fill came in to 4,850’. In 2006 a coil tubing cleanout was performed down to 7,050’. The well continue to produce sand and bringing in fill. The well is currently shut-in. It is proposed to isolate the Cook Inlet 1, 2, 3, and 4 sands by placing an X-plug in the profile at 4,329’. Then install a cemented 3.5” liner from ±4,260’ – 3,550’ setting the well up to produce the Cook Inlet A, B, Stray 1, 2, & 3, and X sand through a single string completion. The intent is to produce these sands independently starting with the lowest. After the first interval is depleted, a plug would be set and the next sand perforated. Waiver Request: Hilcorp requests waiver to 20AAC25.265(c)(1). We request locating the SSV on the tree wing allowing the SSV to remain in the production stream while providing concurrent well bore access. Additionally, a SSSV will be installed. Wellbore Notes: x Tubing punch at ~4,314’ x Slickline will removed SSSV and bail any sand in tubing to below 4,340’. An X-plug will be set in the profile labeled as “B” on the proposed schematic. Procedure: 1. Rig up E-line. PT lubricator to 2,500 psig 2. RIH with tubing cutter. Cut tubing at ~4,320’. RD E-line. 3. MIRU HAK 404 4. Test BOP’s to 250psi low/2,500psi high / 2,500 psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 5. Workover fluid will be brine. BOP’s will be closed as needed to circulate the well. 6. Pull upper completion, fishing tubing and cleaning out as needed to ±4,320’. Lay down 4-1/2” tubing completion. 7. RIH with casing scraper to tubing cut ±4,320’. Circulate clean. POOH. 8. RU E-line CBL Logging tool. RIH with tool. Log ±4,300’ to ±3,700’. POOH 9. P/U and rack back work string 10. RIH with 7” x 3-1/2” liner hanger assembly and 3-1/2” Liner to ±4,260’ per program 11. Cement liner from ±4,260’ to ±3,550’ per program, POOH 12. RIH with 4-1/2” tubing to SSSV Nipple, 4-1/2” x 3-1/2” crossover, 3-1/2” tubing, 3-1/2” Gas Lift completion (live valves) and packer assembly. See proposed schematic for detail and set depths. 13. Set Packer / Pressure test completion: x Pressure up and set packer x Test tubing against plug in X nipple to >2,500psig and chart for 30 minutes. (see attached cement details) --circulate wellbore with KWF / MIT to 1500 psi /30 min /chart --Forward CBL to AOGCC via email TOC ---- (dummy seal assembly) FCO/scraper??--> SUPERCEDED Test BOP’s to 250psi low/2,500psi high / 2,500 psi annular. (Note: Notify AOGCC 48 hours in advance Well Work Prognosis x Test IA to 1,500 psi and chart for 30 minutes (This will pressure up tubing also). x Pull prong and plug in X-Nipple. 14. Set BPV. NU tree, test same. 15. RU E-line and perforate per program. 16. RD HAK 404 17. Turn over to production. 18. Schedule SVS testing with AOGCC as per regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Proposed 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form Superceded ... see revised procedure. gls (Bottom to top) 1 Carlisle, Samantha J (CED) From:Joe Kaiser <jkaiser@hilcorp.com> Sent:Monday, April 6, 2020 4:17 PM To:Schwartz, Guy L (CED) Cc:Davies, Stephen F (CED); Karson Kozub - (C); Dan Marlowe; Juanita Lovett Subject:RE: NCI A-07 RWO (PTD 169-058) Attachments:NCIU A-07 AOGCC Wellwork Procedure Completion 2020-4-1 REV 1.pdf Mr.Schwartz: PleaseseeattachedProcedureRevisionforAͲ7ScabLinerandrecomplete.Ifeltarevisiontotheprocedurewaseasier tocapturethedetailsforallpartiesinvolved.Youwillnoticethateachbulletpointbelowiscapturedintheattachment. Ifyouhaveanyfurthercommentspleasedonothesitatetoreachouttome. Thankyou, JoeKaiser CIOOperationsEngineer HilcorpAlaska,LLC O:907Ͳ777Ͳ8393 M:907Ͳ952Ͳ8897 From:JoeKaiser Sent:Friday,April03,20207:40AM To:'Schwartz,GuyL(CED)'<guy.schwartz@alaska.gov> Cc:Davies,StephenF(CED)<steve.davies@alaska.gov>;KarsonKozubͲ(C)<kkozub@hilcorp.com>;DanMarlowe <dmarlowe@hilcorp.com> Subject:RE:NCIAͲ07RWO(PTD169Ͳ058) Guy, Iappreciatethequickreply. Myresponseisbelow. 1) Wecanpressuretestthecasingto1,500for30min.I’dprefertoperformthistaskas“step5a”.Thiswaythe workoverequipmentcanfillthetubingandannularspacequicker. 2) Wewillbeperformingascraperruntocleananydebrisoffthecasing.Thiswillensurethelinerhanger,liner packer,andhydraulicpackerwillseatproperly.I’llsenddetailsforthelinerandcementingtoyoushortly. 3) WewillsendtheCBLtoAOGCCassoonaspracticalafterrunningthelog. Ifyouhaveanyquestions,pleasecontactme. JoeKaiser CIOOperationsEngineer HilcorpAlaska,LLC O:907Ͳ777Ͳ8393 M:907Ͳ952Ͳ8897 2 From:Schwartz,GuyL(CED)[mailto:guy.schwartz@alaska.gov] Sent:Thursday,April02,20204:28PM To:JoeKaiser<jkaiser@hilcorp.com> Cc:Davies,StephenF(CED)<steve.davies@alaska.gov> Subject:[EXTERNAL]NCIAͲ07RWO(PTD69Ͳ058) Joe, Reviewingsundrytorunthe3½“scablinerandtubing. 1) Recommendpressuretestingcasing/tubingandPXplugassoonaswellisloadedwithKWF.(ieCMIT)step2a ?aftertubingiscut. 2) Ineedaseparateattachmentwithyourlinerrunningdetailsincludingthecementingdetails.Doingcleanout run??etc.…cantreallypressuretestitasitisaclosedsystemalready. 3) LogCBLin7”toTOC.sendCBLbyemailassoonasready. 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). r STATE OF ALASKA ALA. OIL AND GAS CONSERVATION COMMOION REPORT OF SUNDRY WELL OPERATIONS AOGCC 1. Operations Abandon ❑ Repair Well U Plug Perforations [J Tubing Punch 0 Other 6i DGL installation Performed: Alter Casing ❑ Pull Tubing Stimulate - Frac ❑ Waiver ❑ Time Extension El Change Approved Program ❑ Operat. Shutdowrt❑ Stimulate - Other ❑ Re -enter Suspended WOO 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: ConocoPhillips Alaska, Inc. Development 0 Exploratory ❑ 169 -058 3. Address: P.O. Box 100360 StratigraphiC❑ Service ❑ 6. API Number: Anchorage, Alaska 99510 -0360 a 50- 883 - 20027 -00 -00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL 17589 NCIU A - 07 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): n/a North Cook Inlet / Tertiary Gas 11. Present Well Condition Summary: Total Depth measured 8126 feet Plugs measured 4854 Px feet true vertical 6926 feet Junk measured 4830 fill feet Effective Depth measured 4830 feet Packer measured 4373 feet true vertical 4197 feet true vertical 3832 feet Casing Length Size MD TVD Burst Collapse Structural n/a Conductor 347' 30" 388' 388' Surface 2483' 10 -3/4" 2522' 2359' Intermediate n/a Production 8108' 7" 8108' 6907' Liner Tubing Punch depth Measured depth 4514' - 4515' feet SCANNED MAR 2 7 2013 f True Vertical depth 3956' - 3957' feet Size Grade MD TVD Tubing (size, grade, measured and true vertical depth) 1.900" L -80 4330' - 4753' 3817' / 4147' Packers SSSV Packers and SSSV (type, measured and true vertical depth) WFT Wide Pack Halliburton XXO 4301' / 4319' 285' 3792' / 3807' 285' 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: Installed Deep Gas Lift to assist in de- watering the well 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 0 0 Subsequent to operation: _0 Negative 200 / day 40 -60 822 69 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development IS - Service ❑ Stratigraphic ❑ Daily Report of Well Operations x 16. Well Status after work: Oil ❑ , Gas © WDSPL ❑ WBD post install x GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 313 -037 Contact Marcus Barbee Email barbemc aconocophillips.com Printed Name Marcus Barbee Title: Wells Engineer Signature aet 6 : -1-ge Phone 265 -6932 Date: 3/14/2013 RBDA�S MAR 21 2013 d ,6__ .S2 s--- S ubmit Original Only Form 10 -404 Revised 10/2012 9 Y • • 2/10/2013 6:00 CHANGE OUT VALVES ON IA FOR DGL PREP, PRESSURE TEST 2500 PSI, JOB COMPLETE RU BOP, RU PUMP, TEST BOP, RU SL, DRIFT/TAG @4830' RKB, KILL WELL, 2/17/2013 6:00 RUN 13 JOINTS 1.900" TUBING AND LOWER DGL PACKER, SET @ 4324' RKB, RU SL, SET CAT STANDING VALVE, LOAD TUBING, PT LOWER PACKER TO 1000 PSI, SHUTDOWN FOR NIGHT, IN PROGRESS RU ELINE, PUNCH TUBING FROM 4314' TO 4315' RKB, RU SL, PULL CAT 2/18/2013 6:00 STANDING VALVE, PULL R PLUG, MU UPPER DGL PACKER, SET @ 4301' , RUN CAT STANDING VALVE, LOAD TUBING, TEST UPPER PACKER TO 1000 PSI, PULL CAT STANDING VALVE, ATTEMPT TO SET SSSV, SHUTDOWN FOR NIG 2/19/2013 6:00 RIG DOWN BOP & WH ASSEMBLY; ATTEMPT TO SET SSSV; OFFLOAD /BACKLOAD BOAT 2/20/2013 6:00 ATTEMPT TO INSTALL SSSV - NO SUCCESS 2/21/2013 6:00 STANDBY; WAITING ON DELIVERY OF PLUG TO TEST SSSV X- PROFILE; NO FLIGHTS DUE TO WEATHER 2/22/2013 6:00 INSTALL SSSV; RETURN TO PRODUCTION • • Customer Conoco Phillips Contact Marcus Barbee, Thure Johnson Contact Details Jake Bramwell / Jason Moseley W /ford Location Alaska - Cook Inlet Field/ Well No. NCI A -07 Toolstring Desc. DGL System Left In Hole BHA Seq Description Asset OD ID Weight Length Setting Number I (Inches) I (Inches) I (Lbs) I (Feet) Depth 1 Top Of Upper WidePak Packer 4301 2 374 Widepak Packer WFT 3.740" 2.375" 95.2 Lbs 6.21 8 x Setting pins (96001bs) CP 450020 5 x Release Pins (6000lbs) 3.5" VAM FJL Pin 2.875" Sealbore ID 3 Center Packing Element 4306 4 Tubing Punch 4314 -4315 5 2 -Each 9.2# Pup Joints WFT 3.530" 2.930" 179.6 Lbs 9.54 4307.21 3.5" VAM FJL Box x Pin 6 Centralift AVE Sub PCS 3. 515" N/A 14.5 Lbs 0.44 4316.75 3.5 "VamFJL Box X Pin 7 WP Anchor Seal Latch WFT 3.700" 2.240" 39.8 Lbs 1.50 4317.19 3.5" VAM FJL Box c/w Seal Stack CPS 45012 3.67 OAL 5 x Release Pins (6000lbs) X0 1 Dual Flapper Check Valve WFT 1.688" 0.790" 3.1 Lbs 0.00 1.0" CS pin X Stub Acme Box i 1, 8 Top Of Lower WidePak Packer 4319 9 374 Widepak Packer WFT 3.740" 2.375" 95.2 Lbs 6.21 II 8 x Setting pins (9600 lbs) CP 45002 5 x Release Pins (6000lbs) W H; 2.875" TS -8 Pin If 2.875" Sealbore ID A C Stinger Rod w/ DFCV WFT 1.750" 0.875" 41.6 Lbs 6.56 I 1" CS Pin X Guide Nose c/w Seal Stack td 10 Center Packing Element 4324 11 Slotted Sub WFT 3.215" 2.375" 10.3 Lbs 1.34 4325.21 2.875" WTS -8 Box x Stub Acme Box 12 PBR - Seal Bore WFT 2.875" 1.750" 26.3 Lbs 0.96 4326.55 Stub Acme Pin x 2.375" WTS - 8 Pin 13 Profile Nipple CoP 3.125" 1.710" 10.0 Lbs 0.96 4327.51 2 3/8 WTS -8 Box X Pin OE VIM 0.-- 14 Torq -Thru Quick Connect WFT 2.875" 1.375" 25.0 Lbs 1.66 4328.47 2.375" WTS -8 Box x 1.900 NU 10rd Pin LI 15 13 -JTS" Of Jointed Pipe CoP 2.115" 1.560" 1163 422.81 4330.13 1.90" NU 1ORD, 2.751b/ft IAN Mt 16 2.375" Dual Flapper Assembly WFT 2.375" 0.75" 10.0 Lbs 0.78 4752.94 III 1 900" NU 1ORD Box x Bullnose 4753.72 PREPARED BY: Gary Gilliam, Aaron McDonough Weight : 1713 Lbs Length: 452.7 Ft TRADE SECRET AND CONFIDENTIAL Copyright © Weatherford Inc. 2012 • • 0 Tyonek Platform Well A -07 API 50- 883 - 20027 -00 -00 1 , 1 ADL 17589 30" 347' l _" 1 PTD 169 -058 Leg 3 Slot 8 . . :- Original Completion 1969 10 -3/4" 2522' A . . . . I IL Squeeze perff ' '-- 1 1.4 iii . . .... oof- 6rd.:.:.; : : :::vV: i'i : ..:Oii a .... Btiisfi` 1 ... ... 0014::..11....T e 60:: :.i:i 4fr ,..s 1 CASING & TUBING VSR Pkr 4878, 30" 41' 388' 10 3/4 " 41' 2522' 45.5# & 51# J-55 BT &C 3350 1970 531 7 " 39' 79' 26# J5 BT &C 4660 4080 327 7 " 79' 7100' 23# J -5 BT &C 4080 3080 288 327 7 " 7100' 8106' 26# J55 BT &C 4 4080 Open Perfs 41/2 39' 287' 12.60# L -80 Mod BT &C 4730 4980 135 fi• 4 1/2" 287' 5129' 12.75# J-55 Mod EUE 8rd 4730 4980 134 H 4 1/2" 5129' 6920' 12.75# J-55 EUE 8rd 4730 4980 134 r , .. .. ..: r : ;::::.:.>: >:.Ttsp>: >: : ;: Length . . : s.. ............... : :::::::: ; .............. pt .. 10 . :o ;; ; ; ;; ;; ...........:...............:i .. .:: i2 ii: i:3 iiiQi is :: : :i;iiiii f. QM: � ;: >:<?�o.; :. . .... ...'? 5 'i ........ PRODUCTION TUBING STRING & JEWELRY 0.00 39.40 Elevation 39.40 0.60 FMC ./ OCT 6" 3M 4 1/2" 8rd x 4 1/2" BTC Tbg. Hanger 3.958 6.000 . 40.00 245.28 4 1/2" BTC-MOD J-55 8rd Tubing & Pup Jts. 3.992 5.180 TWR Pkr ; 46 09 ' 285.28 2.42 Halliburton "XXO" SVLN 3.813 4.920 287.70 4041.56 4 1/2" EUE -MOD J-55 8rd Tubing & BTC -MOD NO 3.992 5.563 4301.00 6.21 374 Widepack Packer (WFT) upper DGL Packer 2.375" 3.74" 4314 4315.00 1' tubing punch holes (see attachment for more detail) .33" - Open Perfs 4319.00 6.21 374 Widepack Packer (WFT) lower DGL Packer 2.375" 3.74" 4325.21 1.34 slotted sub 2.375" 3.215" 4326.55 0.96 PBR 1.75" 2.875" 4327.51 0.96 Profile nipple 'R' Nipple 1.71" 3.125" 432847 1.66 Quick Connect 1.375" 2.875" Siding sleeve 4714' I ' z 4330.13 42281 1.900" 2.76#,. L80, 1.56" 1.56" 1.900" :jt 4329.26 1.43 Halliburton "X' Nipple 3.813 5. 030 4330.69 31.27 4 1/2" EUE -MOD J-55 8rd Tubing 3.992 5.563 TWR Pkr 472.9' 4361.96 8.08 Halliburton Upper "PBR" 3.992 5.880 -• _--- s - =- - 4370.04 2.83 Ratch Latch Seal Unit 3.992 5.080 4371.31 6.52 Halliburton "VSR" Packer 3.880 5.980 Plugged Perfs 4377.83 213.18 41/2" EUE -MOD J-55 8rd Tubing 3.992 5.563 4837' fill t = y t 4591.01 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.530 r '�:a. p , s e 4595.23 10.08 4 1/2" EUE -MOD J-55 8rd Pup Jt. 3.992 5.563 4854' PX plug a 4605.31 2.6 Halliburton No-Go Locator 3.992 5.560 4605.97 10.14 Halliburton "TWR" Packer & Mill Out Extension 4.000 5.815 ' =Y 4616.11 94.51 41/2" EUE -MOD J -55 8rd Tubing & Box x PinXO�er 3.992 5.563 TWR Pkr � 4869' 4710.62 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.530 471484 8.09 4 1/2" EUE -MOD J-55 8rd Pup Jt. 3.992 5. 563 4722.93 2.6 Halliburton No-Go Seal Unit 3.992 5.080 PIU ed Perfs 4724.03 12.75 Halliburton "TWR" Packer & Mill Out Extension 4.000 5.815 gg �{ 1 4736.78 111.97 4 1/2" EUE -MOD J -55 8rd Tubing & Dbl. Pin X -0rer 3.992 5.563 t 4 ;.1 475294 .78' Dip tube shoe 0.750 2.375" 4848.75 4.22 Halliburton "XD" Sliding Sleeve with PX plug CLOSED 3.813 5.530 _,,,,: 4852.97 8.08 41/2" EUE -MOD J-55 8rd Pup Jt. 3.992 5.563 TWR Pkr _ 4952' 4861.05 2.6 Halliburton No-Go Seal Unit 3.950 5.080 ......, , 4862.15 11.28 Halliburton "TWR" Packer & Mill Out Extension 4.000 5.815 .. 487343 69.33 4 1/2" EUE -MOD J-55 8rd Tubing & Dbl. Pin X -0rer 3.992 5.563 Plugged Perfs 4942.76 2.6 Ratch Latch Seal Unit 3.950 5.080 5.815 ._ � ',. 4943.86 1275 Halliburton "TWR" Packer& Mill Out Extension 4.000 •' Y�.� 4956.61 123.63 41/2" EUE -MOD J -55 8rd Tubing & Dbl. PinX -0Oer 3.992 5.563 5.530 5080.24 4.22 Halliburton "XA" Sliding Sleeve CLOSED 3.813 5084.46 31.27 4 1/2" EUE -MOD J-55 8rd Tubing 3.992 5.563 TWR Pkr 1 j 6/ 5115.73 26 Ratch Latch Seal Unit 3.950 5.080 5116.83 12.75 Halliburton "TWR" Packer& Mill Out Extension 4.000 5. 815 5129.58 470.98 41/2" EUE J -55 8rd Tubing & Dbl. Pin X-Over 3.992 5. 560 Plugged Perfs 4 - - - xi , 5600.56 4.22 Halliburton "XD" Sliding Sleeve OPEN 3.813 5.530 _. 560478 689.38 41/2" EUE J -55 8rd Tubing 3.992 5.560 1 " _ j 6294.16 4.22 Halliburton "XD" Sliding Sleeve with PX plug OPEN 3.813 5.530 6265' PX plug 4E 6298.38 594.16 4 1/2" EUE J-55 8rd Tubing 3.992 5.560 Plugged Perfs 6892.54 1.5 Halliburton "AT Landing Nipple 3.725 5.030 r -' 6894.04 31.31 41/2" EUE J-55 8rd Tubing 3.992 5.560 I 1111 I 6925.35 0.65 Wireline Re -entry Guide 3.992 5.580 6920 6926.00 End of Tubing • • Original RKB 116' 1 :I E ._ Upper DGL Pkr 1 i el I ►: 1 spacer pipe 4 , �. the AVE Sub :; �� _ Lower DGL Pkr Tubing punch holes t "� „ f t i .. 1 2.375 ported sub Anchor Latch Seal Assy 0 1 �- 1.75 PB R Spacer pipe 1" Wft Quick connect ill ill. till I PBR Seal Assy VSR Pkr 4373' 1.71" R nipple 1.900" dip tube TWR Pkr 1.900" dip tube 1 9 TWR Pkr 1 2.375" dual float shoe . SAK NCI A -07 ConocoPhillips 01 Well Attributes • Max Angle & MD TD AI.jSkis 11>w�. Wellbore API/UWI Field Name Well Status Ind(*) MD (ftKB) Act Btm (ftKB) Blips 508832002700 COOK INLET PROD 38.25 3,670.01 8,126.0 Comment H2S (ppm) Date Annotation End Date KB -Ord (ft) Rig Release Date -- SSSV: WRDP Last WO: 7/7/1994 8/12/1969 Well Conk' -NCI A -0731141 201311.2509AM schematic - Actual Annotation Depth (ftKB) End Date Annotation Last Mod ... End Date MIISMIM _ - - _ _ _ _ _ _ AMON Last Tag: RKB 4,576.0 11/12/2012 Rev Reason: Add Attachment, Sset Packer Assy haggea 3/13/2013 HANGER, 39 o Casing Strings Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd NIPPLE.285 CONDUCTOR 30 28.000 41.0 388.0 388.0 WELDED WRDP. 285 - - Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd CONDUCTOR, SURFACE 103/4 9.950 39.0 2,522.0 2,364.2 45.50 J -55 BTC 47 -388 Casing Description String 0... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd S 39RFACE, PRODUCTION 7 6.250 39.0 8,108.0 6,907.6 23.00 J -55 BTC PACKER, 4,301 (264/234) PUNCHES, I J Tubing Strings 4,314 CENTRALIFT FT Tubing Description String 0... String ID... Top (ftKB) Set Depth (8... Set Depth (TVD) ... String Wt... String ... String Top Thrd SAL, 4,3 a TUBING 41/2 3.958 39.4 6,935.5 5,932.8 12.60 L - 80 BTCM SEAL, 4,3 PACKER, 4,321 21 Completion Details NIPPLE, 4,329 i _.. =' Top Depth STINGER. (TVD) )TVD) Top Incl Nonni... 4,327 fW:l Top (ftKB) )ftKB) (1 Item Description Comment ID (in) �� 39.4 39.4 x.32 HANGER FMC TUBING HANGER 3.958 PBR, 4,335 NIPPLE, 4,336- 11 1 285.3 285.3 -0.71 NIPPLE HALLIBURTON )0XO SVLN 3.813 CONNECT, Ilm 4,329.3 3,803.6 37.11 NIPPLE HALLIBURTON X NIPPLE 3.813 4.353 - ass. -_' ' '1 4,362.0 3,829.7 37.09 PBR HALLIBURTON UPPER PBR 3.992 PBR, 4882 4,370.0 3,836.1 37.08 RATCH LATCH 3.950 I 4,372.9 3,838.4 37.08 PACKER HALLIBURTON VSR PACKER 3.880 PACKER, 4,373 RPERF, } 4,592.6 4,014.3 36.02 SLEEVE -0 HALLIBURTON XD SLIDING SLEEVE (Open 8/1 /2006) 3.813 4,402-4,472 - I !E 4,606.9 4,025.8 35.99 LOCATOR HALLIBURTON LOCATOR no go 3.992 RPERF, 4,490x,570 ` 4. 4,609.5 4,027.9 35.98 PACKER HALLIBURTON TWR PACKER 4.000 SLEEVE -0, ` it 4,714.1 4,112.6 35.73 SLEEVE-0 HALLIBURTON XD SLIDING SLEEVE (Open 7/29/2006) 3.813 _ LOCATOOR, R, / _ 1 4,807 4,726.4 4,122.6 35.70 SEAL HALLIBURTON SEAL no go unit 3.992 PACKER. 4.609 4,729.0 4,124.7 35.69 PACKER HALLIBURTON TWR PACKER w /millout extension 4.000 RPERF, 1 4,620-4,630 4,853.8 4,226.4 35.40 SLEEVE -C HALLIBURTON XD SLIDING SLEEVE (Closed) 3.813 RPERF, -= - 4,866.1 4,236.5 35.37 SEAL HALLIBURTON SEAL no go unit 3.950 4,647-4,697 i SLEEVE -0, F 4,868.7 4,238.6 35.36 PACKER HALLIBURTON TWR PACKER 4.000 4,714 SEAL, 4,7228 6 1 1 4,949.3 4,304.2 35.17 RATCH LATCH 3.950 1 PACKER, 4,729 4,951.9 4,306.3 35.16 PACKER HALLIBURTON TWR PACKER 4.000 FLAPPER, 1 g 1 _. 5,088.2 4,418.0 33.86 SLEEVE -C HALLIBURTON XA SLIDING SLEEVE (Closed 7/26/2006) 3.813 4,761 \ 3.950 RPERF, - 5,123.7 4,447.5 33.97 RATCH LATCH 47 R ERF 1 5,126.3 4,449.6 33.98 PACKER HALLIBURTON TWR PACKER w /Millout Extension 4.000 4.830-4.840 -_ SLEEVE -C, 5,610.1 4,848.9 34.36 SLEEVE -C HALLIBURTON XD SLIDING SLEEVE (CLOSED 7/25/2006) 3.813 PLUG, 4.854 i # 1 6,303.7 5,419.7 35.24 SLEEVE-0 HALLIBURTON XD SLIDING SLEEVE (Open 7 /20/2006) 3.813 SEAL. 4,866 1_ * ] 6,902.0 5,906.6 37.78 NIPPLE HALLIBURTON XN NIPPLE 3.725 PACKER. 4.869 '..." 6,934.9 5,932.3 37.58 WLEG WIRELINE RE -ENTRY GUIDE 3.992 RPERF, .. ill 4,8784903 Tubin Description String o... String ID ... Top (ftKB) Set Depth (f... Set Depth (TVD) ... String Wt... String ... String Top Thrd RGL Packer Assy 2.115 1.560 4,301.0 4,762.1 4,151.6 1,162.70 PACKER, 4,952 '= Completion Details RPERF, - Top Depth 4,9634970 1 Top (ftKB) 1 (TVD) Top 1ncl Nonni... (ft (°) Item Description Comment ID (in) IPERF, r 5,0535,072 t i 4,301.0 3,781.1 37.14 PACKER 374 WIDEPAK PACKER 2.375 SLEEVE -C, I 4,317.2 3,794.0 37.13 SEAL WP ANCHOR SEAL LATCH 2.240 5,088 1 1 If. ' 1 4,320.8 3,796.9 37.12 PACKER 374 WIDEPAK PACKER 2.375 PACKER, 5,126 - 4,327.0 3,801.9 37.12 STINGER STINGER ROD w/DFCV 0.875 RPERF, ! 4,334.9 3,808.2 37.11 PBR PBR - SEAL BORE 1.750 5,5905,595 SLEEVE -C, -- 4,335.9 3,808.9 37.11 NIPPLE PROFILE NIPPLE 2 3/8 WTS-8 BOX X PIN 1.710 RPERF, R F, 4,336.9 3,809.7 37.11 CONNECT TORQ -THRU QUICK CONNECT 1.375 5,632 -5,837 4,761.3 4,151.0 35.62 FLAPPER 2.375 DUAL FLAPPER ASSEMBLY 0.750 RPERF, 6,648-5,658 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) RPERF, Top Depth 5,9035,908 RPERF. (TVD) Top Intl 5,9735,998 Top (ftKB) (ftKB) (1 Description Comment Run Date ID (in) RPERF, 285.3 285.3 -0.71 WRDP WRDP SET IN NIPPLE 11/12/2012 2.125 6,060-6,070 4,314.0 3,791.5 37.13 PUNCHES Tubing Punches 2/20 /2013 1.560 RPERF, 6,182 -6,187 4,853.8 4,226.5 35.40 PLUG PX PLUG TO ISOLATE BELUGA DUE TO WATER 7/30/2006 0.000 RPERF. -. - PRODUCTION 6,1955,205 RPERF, _ - 6,265.0 5,387.9 35.14 PLUG PX PLUG 7/19/2006 0.000 6,225-6,245 PLUG, 6,2651 Perforations & Slots RPERF, Shot 6,2565,281 Top (TVD) Btm (TVD) Dens RPERF. Top(ftKB) Btm MKS) (ftKB) )ftKB) Zone Date (oh... Type Comment 6.287 -6,292 I . 4,353.0 4,354.0 3,822.6 3,823.4 6/2/1994 12.0 SQZ SLEEVE -0, 6,304 ' RPERF. 8,342-6,349 RPERF, 6,497 -6,507 RPERF, 6,535 -6,550 RPERF, 6.568 -6573 RPERF, 6.586-6.593 RPERF, 6,640-6,650 RPERF, 6,7485,755 NIPPLE, 6,902 - RPERF. •• 6,8935,918 WLEG, 6,935 il PRODUCTION al (2691239), 39 -8,108 TD, 8,128 t SAK • NCI A -07 ConocoPhillips 01 Al ) .ietca, Itti;. spa KB - Grd (ft) Rig Release Date 8/12/1969 Well Cootie: - NCI A -07, 3/14/2013 11:25:00 AM Schematic - Actual HANGER, 39 -,- Perforations & Slots Shot Top (ND) Btm (TVD) Dens NIPPLE, 285 Top (ftKB) Btm (ftKB) (ftKB) (ftKB) Zone Date (sh.- Type Comment WRDP, 285 CONDUCTOR, I 4,402.0 4,472.0 3,861.6 3,917.4 CI -1, NCI A -07 6/29/1994 12.0 RPERF TCP GUNS 41 -388 SURFACE, j 4,490.0 4,570.0 3,931.8 3,996.1 CI -2, NCI A -07 6/29/1994 12.0 RPERF TCP GUNS 39 -2,522 PACKER, 4,301 4,620.0 4,630.0 4,036.4 4,044.5 CI -3.1, NCI A -07 6/29/1994 12.0 RPERF TCP GUNS PUNCHES, I a 4,647.0 4,697.0 4,058.2 4,098.7 CI-4, NCI A -07 6/29/1994 12.0 RPERF TCP GUNS 4,314 4,744.0 4,794.0 4,136.9 4,177.6 CI -5, NCI A -07 6/29/1994 12.0 RPERF TCP GUNS CENTRALIFT SEAL, 4,317 111.1 4,830.0 4,840.0 4,207.0 4,215.2 CI-6, NCI A -07 6/29/1994 12.0 RPERF TCP GUNS PACKER, 4,321"'' 4,878.0 4,903.0 4,246.2 4,266.5 CI -7, NCI A -07 6/29/1994 12.0 RPERF TCP GUNS NIPPLE, 4,329 STINGER. \ 4,963.0 4,970.0 4,315.4 4,321.1 CI -8, NCI A -07 6/29/1994 12.0 RPERF TCP GUNS 4,327 5,053.0 5,072.0 4,388.6 4,404.5 CI -9, NCI A -07 7/4/1994 12.0 IPERF TCP GUNS PLR, 4,335 p� 5,590.0 5,595.0 4,832.4 4,836.5 C-4, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS NIPPLE, 4,336- CONNECT, . 4,337 5,632.0 5,637.0 4,866.9 4,871.1 D-1, NCI A -07 ' 623/1994 12.0 RPERF TCP GUNS SoZ, 1 5,648.0 5,658.0 4,880.1 4,888.4 D-2, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS 4,353 -4,354 - 1 PBR, 4,362 5,903.0 5,908.0 5,093.1 5,097.1 E -9, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS 5,973.0 5,998.0 5,149.6 5,169.9 F -3, F-4, NCI 6/23/1994 12.0 RPERF TCP GUNS PACKER, 4,373 A -07 RPERF, - ' - 6,060.0 6,070.0 5,220.4 5,228.6 G-1, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS 4,402 -0,472 RPERF, 6,182.0 6,187.0 5,320.2 5,324.3 H -1.1, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS 4,4904,570 SLEEVE -O, 6,195.0 6,205.0 5,330.8 5,339.0 H -2, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS 4,593 6,225.0 6,245.0 5,355.4 5,371.4 H-4, H -5, NCI 6/23/1994 12.0 RPERF TCP GUNS LOCATOR, _ 4,607 A -07 PACKER, 4,609 6,256.0 6,281.0 5,380.4 5,401.0 H -6, H -7, NCI 6/23/1994 12.0 RPERF TCP GUNS RPERF, A -07 4,6204,830 RPERF, - 6,287.0 6,292.0 5,406.0 5,410.1 H -7.1, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS 4,6474,697 - SLEEVE -o, 6,342.0 6,349.0 5,451.2 5,456.9 H -9, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS 4,714 6,497.0 6,507.0 5,577.7 5,585.8 J -1, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS SEAL, 4,726 PACKER, 4,729 6,535.0 6,550.0 5,608.7 5,620.8 J -3, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS FLAPPER, ix _ 6,568.0 6,573.0 5,635.4 5,639.5 K -1, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS 4,761 RPERF, _ - 6,586.0 6,593.0 5,650.0 5,655.6 K -2, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS 4,7444,794 RPERF, 6,640.0 6,650.0 5,693.6 5,701,7 K -5, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS 4,8304,840 SLEEVE -C, 6,748.0 6,755.0 5,780.7 5,786.4 M-4, NCI A -07 6/23/1994 12.0 RPERF TCP GUNS PLUG, 4,854 6,893.0 6,918.0 5,899.6 5,919. N -2, N -3, NCI 6/23/1994 12.0 RPERF TCP GUNS A -07 SEAL, 4,866 PACKER, 4,669 Notes: General & Safety RPERF, - End Date Annotation 4,8784.903 1 1/25/2011 NOTE: VIEW SCHEMATIC w /Alaska Schematic9.OREV s .. PACKER. 4.952 RPERF, p e 4,963-4,970 ` IPERF, `F1 5,053 -5,072 SLEEVE -C, 5,088 PACKER, 6126; RPERF, 5,590-5,595 RPERF, SLEEVE -C, 5,610 RPERF, 5.632-5,637 � =_ RPERF, 5,648 -5,655 RPERF, 5,903 -5,908 RPERF, 5.973-5,998 - - RPERF, 6,060-6,070 RPERF, 6,1825,187 RPERF, 8,1955,205 RPERF, 6,2255,245 PLUG, 6,265 RPERF, 8.2565,281 RPERF, 6,2875,292 ••• SLEEVE -0, � �) 6,304 RPERF, 6,3425,349 -- RPERF, 6,4975,507 RPERF, 6,5355,550 -- RPERF, 6,5685,573 r, RPERF, 6,586-6,593 i -..- RPERF, 6,6405,650 - I ° ", RPERF, 6,7485,755 - -•--• NIPPLE, 6,902 RPERF, 6,8935,918 WLEG, 6,935 PRODUCTION (26R/23a), 39 -8,108 TD, 8,126 WELL LOG TRANSMITTAL PILAR 2 2 2033 AOC70C To: Alaska Oil and Gas Conservation Comm. February 27, 2013 Attn.: Makana Bender �) 0 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: Deep Gas Lift Hoist/ Packer Setting Record/ Perforation Record: NCIA-07 Run Date: 2/18/2013 The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Klinton Wood, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518 NCIA-07 Digital Data (LAS), Digital Log file 50-883-20027-00 1 CD Rom PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Halliburton Wireline & Perforating Attn: Klinton Wood 6900 Arctic Blvd. Anchorage, Alaska 99518 Office: 907-273-3527 Fax: 907-273-3535 klinton.wood@hailiburton.com Date: %ANNETI Signed: oF gw i% - s THE STATE Alaska Oil and Gas °-f AL l l s� Conservation Commission am - _ _ - - -- - o GOVERNOR SEAN PARNELL 333 West Seventh Avenue pF rR, Q+ Anchorage, Alaska 99501 -3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Marcus Barbee Wells Engineer ConocoPhillips Alaska, Inc. / P.O. Box 100360 Anchorage, AK 99510 Re: North Cook Inlet Field, Tertiary Gas Pool, NCIU A -07 Sundry Number: 313 -037 SCANNED MAR 15 2013 Dear Mr. Barbee: 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 Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Chair DATED this 1 day of February, 2013. Encl. •' • • vg. RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION a' JAN 2013 / /„.3 APPLICATION FOR SUNDRY APPROVALS AOG C 20 AAC 25280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Deep Gas Litt Installatio El 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Conocophillips Alaska, Inc. Exploratory ❑ Development 0 4. • 169 -058 , 19426- " 13- 3. Address: Stratigraphic ❑ Service ❑ 6. API Number 2146 I ' Z 5 j2' 3 P.O.Box 100360, Anchorage, Alaska 99510 50- 83- 20027 -00-00 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 ❑ No 0 NCIU A -07 9. Property Designation (Lease Number): 10. Field /Pool(s): old I ADL - 17589 • Ft Inl -Cook ets /UoI\1)f Cml< 1n /,I' / E G. ' 11 � � oi5 11. PRESENT WELL CONDITION SUMMARY / Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): • 8126 6918 • 4837 4220 px plugs 4854' / 6265' sand 4837 Casing Length Size MD TVD Burst Collapse Structural n/a Conductor 347' 30" 388' 388' Surface 2483' 10 -3/4" 2522' 2359' Intermediate n/a Production 8108' 7" 8108' 6907' Liner n/a Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 4402' - 6918' • 3858' - 5923' 4 -1/2" L -80 6936' Packers and SSSV Type: sssv = HES XXO NIP w/ WRDP Packers and SSSV MD (ft) and TVD (ft): 285' / 285' HES, VSR / HES TWR / HES TWR / HES TWR / HES TWR / HES TWR 4373', 3832' / 4609', 4039' / 4729', 4126' / 4869', 4231' / 4952', 4298' / 5126', 4449' 12. Attachments: Description Summary of Proposal ❑ 13. Well Class after proposed work: Detailed Operations Program © - BOP Sketch 0 - Exploratory ❑ Stratigraphic ❑ Development El- Service ❑ 14. Estimated Date for 2/5/2013 15. Well Status after proposed work: Commencing Operations: Oil ❑ Gas EI • WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Marcus Barbee Email barbemc aconocophillips.com Printed Name Marcus Barbee Title Wells Engineer Signature ,`, � / Phone 265 -6932 Date 1/24/2013 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31 5-93 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: R BDMS FEB 0 4 201`' Spacin Exception Required? Yes ❑ No I Z1 Subsequent Form Required: / O — YQ / / APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 2_1_ 13 i g, Submit Form and O . A iAI Approved application is valid for 12 months from the date of appr al. 00d'b t ♦ • • Tyonek Well A -07 Deep Gas Lift Install Pre - Installation well work 1 Close in the well at the wing valve 2 Pull the SCSSSV 3 Tag bottom 4 Clean out the production tubing below Sliding sleeve @ 4718' and leave +- 75' of ratt hole 5 Drift the production tubing with a Deep Gas Lift Packer Drift below the production packer © 4373' 6 Pressure test the Inner Annulus to 1000 psi Leave the well shut in until Deep Gas Lift can be installed Deep Gas Lift Installation Procedure 1 Mobilize Slick -Line, E -Line, Mud hands, Roustabouts, Crane operator, Banksman, Down hole pump and crews to the Tyonek Platform. Perform platform orientation upon arrival, hold SIMOPS meeting with operations when checked in 2 Mix 780 Bbls of 6% KCL in the pits while laying pump side hard line 3 Flange up the 7" wireline valves with 1.900" inserts to the well head of A -07 4 Pick up the shoe tract and lower it into the Wireline valve and close same on the 1.900" tubing. 5 Fluid pack and pressure test the pump side hard line 250 psi low andsi high. 6 Test the wire line valve 250 psi low and 3000 psi high 30 j► S 7 Bleed test pressure to zero, lay down test joint and cap the Wire -Line valve 8 Line up the down hole pump to bull head and come on line pumping 1 -1/2 wellbore volumes prior to shut down 9 Lay out the 1.900" tubing and strap same with a steel tape measure, generate a pipe talley and give to the company man 10 Isolate pump and monitor well for 30 minutes to establish a leak off rate 11 Come online and catch fluid, measure the volume required to catch fluid and record same in job log. SD pump and secure same 12 Repeat step 11 and verify the leak rate after an additional 30 minutes have passed 13 Rig up the handling equipment for the 1.900" tubing, bowls, slips, elevators, TIW valve, crummies etc. 14 Pick up the shoe tract and lower it into the well and set the hand slips on same 15 Continue picking up 1.900" tubing until all 11 joints have been picked up and run in the hole 16 Install the lower portion of the Weatherford quick connect to the box end of the 1.900" tubing looking up 17 Pick up the Wire -Line lubricator with standard 1- 11/16" tool string with Gamma Ray & CCL 18 MU the DPU and setting tool to the Wire -Line tool string, MU the Wide pack packer to the setting adaptor 19 MU the ported sub, PBR, 1.71" 'R' Nipple profile with 'Rx' plug installed and upper portion of the Weatherford quick connect 20 MU the upper quick connect to the lower quick connect and tighten with pipe wrenches 21 Pick up the entire BHA with the wire -line hoist / drum, remove the slips and bowl and stab lubricator & wire line valve on the well head 22 Close the rams on the 1.900" tubing and pressure test the lubricator 250 psi low 1000 psi high 23 Bleed test pressure to zero, open the tubing rams and run in the hole logging the packer on depth 24 Set the packer with the center of the element exactly 5' above the bottom of the first full joint above the PBR 25 POOH & BO & LD the DPU and packer setting adaptor / Rig back Wire - line 26 Rig up Slick - Line with a standard 1 -3/4" tool string 27 PU &MU Weatherford packer test tool, RIH & stop + -5' above the lower wide pack packer 28 Line up the down hole pump to bull head and come on line until fluid is caught / shut down the pump 29 Set the packer test tool inside the lower wide pack packer and pressure test the assembly to 250 psi low & 1000 psi high 30 Bleed test pressure to zero, shear off the test tool and pull it out of the hole. BO &LD the test tool when complete 31 Rig back slick line and rig up E - Line 32 PU &MU a tubing punch gun for 4 -1/2" tubing with (2) two 1/2" jet holes to the Wire -Line tool string 33 Ensure the inner annulus has a minimum of 100 psi on the surface prior to firing the tubing punch gun 34 RIH & tubing punch the production tubing exactly 5' above the top of the Wide Pack packer / POOH when complete 35 Rig back E - Line and rig up slick - line 36 PU & MU standard 1 -3/4" tool string with GS and watermellon prong to equalize and pull a 1.71 " 'Rx' Plug 37 RIH and recover the 1.71" 'Rx' Plug inside the lower DGL dip tube, POOH when complete 38 BO &LD the 'Rx' plug, PU & MU the upper DGL packer assembly consisting of HES DPU, setting tool, setting adaptor, Wft wide pack packer LE, 3 -1/2" spacer pipe, AVE sub, Anchor Latch Seal Assembly, spacer pipe, PBR seal assembly. Zero the counter with the PBR @ the tubing hanger 39 RIH with the upper DGL assembly, set the same in the top of the lower DGL assembly previously set in the hole Verify the upper assembly is latched to the lower with a 1500# straight pull bind on the anchor latch seal assembly 40 Set the full weight of the upper assmbly on the lower and allow the DPU to fire. POOH when complete 41 BO & LD the HES DPU. PU & MU the Wft packer test tool. RIH to +- 5' above the upper DGL packer assembly. 42 Line up the down hole pump and come on line at maximum rate until fluid is caught. Shut down the pump. 43 Set the packer test tool inside the upper DGL packer and pressure test the production tubing to 250 psi I;ow & 1000 psi high 44 Bleed test pressure to zero, pull the test tool OOH 45 BO & LD the packer test tool. PU & MU SCSSSV 46 RIH & set the SCSSSV as per SOP. POOH when complete. Perform function test on SSSV, continue procedure when valve passes test. 47 Rig down from A -07 and return the well to production 48 Walk through the well bay room with the production operators and ensure they are happy with the way we are returning the well to them. Production to bring the well on line as per instructions from Matt Ortwein • • ` • . E IICo,1V:- NC I A-OF. 112320136:43:8 AU .. SGemaDd- AD11al -. ENINNEN MANG ER. 39 N IPPLE,Z66 WRO P .266 .,. CONDUCTOR. 4l- ' - SUR FACE,3E-2$22 NIPPLE. 4,323 SOZ, 430-4354 '7®d�/ PDR,4,362 �,,,_ ••.I PAC KSN.43f3 RP ERF, 4,02 -4,472 RP ER F, 4,490 -4,630 SLEEVE-0 4,633 OEM 13=1•11111=10 3 LOCATOR, 4,607 PACKER. 4609 RP ER F, 462.-4 3 = P R PERF, 4647-1837 SLEEVE-O. 4311 I SEAL, 4,76 PACKER, 4,123 RP ERF, 4,7 41-4,794 R PER F, 4,6- ]- 4610 SLEEVE-C, 4664 0 .._ PLUG,4664 SEAL, 4656 1 PACKER, iges RP ER F 46/6 -4903 - PROVER, 4952 RPERF, 49634940 IPER -6CT2 SLEEVE-C.61:133 11 a PAC KER,6,126 RPERF.6,R46665 SLEEVE-C ,5;610 RPERF,51632 -6X8 N PERF,5b486,658 _ -1 ; R P ER F.69036963 R P ER F.6933S9 B RPERF,61:I33-61 R P ER F.6.182-6,16i PERF,6,196fi2W kiYY RP ER F .6226-6245 PLUG.6266 RPERF,625E -6231 I�r RPERF,6234b232 SLEEVE-0.6304 RPER F, 6642 -6,319 4: RPERF,6,l9T -6,504 RPERF.6,S 6560 3. Fe r R P ER F,6983-5,573 r � RPER F,6b40 -6,831 RP ERF,6,TP8 -6,365 N ,661E-6902 3 RPERF,6693-6916 VOLES .6905 PRODUCTKGN 6301.03.0,3 -6,106 TD, 6126 . . • • .. : Tyonek Platform Well A-07 ., API 50-883-20027-00-00 -• .. .4... E ■ - r ADL 17589 1.4. it.7 I . .. 3O 34T PTD 169-058 Original Completion 3 ionS1lo9t 8 1969 . .......... . ail 10-3/4 L " 2522' — t -- .4 i lird 7 4 - ve.A....., Squeeze perfs :: .: 'NT ', . '.7 .. Gas Producer FMC OCT 1E(9-Dril Deck: Single Carp. FMC 6 3M 4 92 )(4 112 EiT&C R(B-TFE: 4 39.4 VSR Pkr .. 4373' Arriukis Fluid, 8.5 lagal KCL Completion Fluid with 30 % Glycol RKB-SL : 3 116 i . I - , . Open Perfs ',I TOO 2510 from �L dated 06/2969 WATER DEPTH 120" RKE43L: Niii:i eiiA3:::::N*'1:-WtaMitit'iiii6':::EM:::itiliii: .:,: C4SPIG & TUBING XI° 41' 388 ii 104' 41' 2522' 11 14 .: 7 39 79 litii - 7 ' 79 00' 7 ' 7100 8109 4 Tr 39 287 7 am 6129" 4 1/2° 5129 6920' 4558 & 514 J-55 254 2.3r1 256 3-55 J-55 .165 BT&C BT&C BT&C BTSC 3350 1970 4560 4080 4090 3080 4660 4080 531 327 71 288 327 1260g L-80 Mod BT&C 473Q 4900 13$ 4 112 12.75# 4-55 Mod EUE 8rd 4730 4980 12754 J-55 EUE 8rd 4730 4980 134 134 TWR Pkr 46 9 . ... PRODUCTION TUBING STRING & JEKELRY 1 1 !ii• II: , 'i.' ,.-•.. k ,... 1 -,:-. 4343706 39.40 Elevation II 3940 060 FMC I OCT 6 313 4 112 8rd x 4 112 BTC Rig. 1-langer . 528 00 40 24628 41/2 ETC-MOD 3-55 8rd Tubing & Fuels 1992 5 1873 242 Halibiston'h04.0" SVLN 37313 4920 287.70 4041.56 4 1/7 EUE-1300 3-55 8rd Tubing & BTCAMOD X10 7992 5.563 4329.26 143 Halliallontx" tiro 4330.69 31.27 4 1/27 EUE-M00 ...)- erd Tubing 2 Ra 99 BIZ 652 Hamilton "VSR" Packer 1958 6 000 Open Perfs -, 28 3 813 5 030 3992 6.663 Sidingsleeve 4714 i,,,,', ..! !:. .* 3. 5 5' 437131 93 080 0 1880 g980 ' , TWR Pkr 47?9' 4377 83 21118 41/7 EUE-MOD J-56 034 Tubing 7992 5 563 - erfs ,,, ii . ,. '. 4591.01 422 Halliburton 'XD" Sliding Sleeve 459523 1908 4 112 EUE4400 3-65815 Pup I. 3992 5663 4605.31 26 Halliculon No-Go Locatox OPEN 3.813 5.530 Pl d p ugge 1992 5,550 • 483T fill ,....... .... 460697 10.14 Hall arton 1 R° Pack& & Mil Oot Extension .., 4000 5 815 - . .. .... . 461611 94,51 41/7 ELE4300 3-511815 Tutting & Box x Pin X-Over 7992 5.563 4854" PX piug el 6 , 4710.62 422 Halliourton "XD" Sliding Sleeve OPEN 3 813 5 530 471484 009 4 112 ELE-MOD 3-55 8rd P i 3992 5E53 472293 2.6 Haliburton No-Go Sea Unt 7.992 6990 TWR Pin X- ELE 3-55 Pkr , 486 473678 11197 4 112 ELE44 9' 472473 12 75 eialiarton'TVIR" Packer & Mil Out Extension 4.000 5 815 „. i. 00 3-558113 Tubing & Da Pin X-Criar 3992 5563 — II , , " , Plugged Perfs . 484175 .... ., ' - 26 Ha 1 .z....„ -4 1;,,...:,, ..:: .:IF — .....,,,,.: . _ 1 485297 4861E6 422 liaiburton 7W 5103119 SleasnittiP.Xplog 8 08 4 1/2 EUE-M00 ...456 8K1 Pup I iibuton No-Go Sea Unit 486215 1128 Haliturton AMR' Packer & Mil Out Extension 4 3,992 5 563 1950 5080 000 5.915 487143 6933 41/7 ELE-MOD J-55 8n3 Tubing & CO5/ Pit X-Exier CLOSED 3. 5 494276 26 Rath Latch Seal Unit am 5 060 TWR Pkr .4952' 4943.86 1275 Halibtxton'TWR` Packer 0, moi cia Extension 4000 5915 . ' 495661 123 63 4 117 EUE-6100 3-55 8rd Tubing & Obi P11)7-Owl 1992 5 653 - 1 ' l 4 ' :4 t4..t. 1.4.:::.7. .!. 51 53E624 422 Naliburton "")( Sliding Sleeve 508446 31 27 41/2 ELE4400 J-56 8rd Tubing 511573 266 etch Latch Seal Urit 511583 1276 lialibuIcin Packer & Mil Out Extension 29 58 470.98 4 1/7 end Tubing & Dbl. Cver 6 60056 422 Hai:ninon "XD" Sliding Sleeve OPEN 3813 5 530 CLOSED as 5.530 Plu::ed Perfs 1992 6 563 1950 5980 4.000 5915 3992 5 560 TVVR Pkr 660478 689.38 4 1/2 ELE 3-65 8rd Toting 1992 5560 5126 6294 16 422 Halltudon "XD" Biding Sleeve with PX plug OPEN 3.813 5 530 i AK 6298.18 594.16 4 1/2 EUE 3-65 8rd Tubing 3992 6 Plugged Perfs c.; :;=-4!!' 36 689254 1.5 Kalitmlon - ixtir Ming tAppie 3.725 5 070 6894.04 3111 4 1/2 ELIE 3-56 Sid Tubing 3992 5 560 I 17 !" 5 i 692535 655 Maine Re-entry Guide 3992, 5 580 6265' PX pin * * 6920 692000 End of Tubing Plugged Perfs I 1 • i Original RKB 116' Upper DGL Pkr 041 „i 3 -1/2" spacer pipe t fib AVE Sub u ; ` - i �' f — Lower DGL Pkr Tubing punch holes --�. ; �,, 2375" ported sub Anchor Latch Seal Assy I'L . 1.75" PBR Spacer S p pipe 1 " 1� p p Wft Quick connect . I PBR Seal Assy VSRPkr � ' 1.71" R nipple I L9OO p" dip tube . 1111 TWR Pkr ' MILL mi - ° , 0 I� 1.900F?diPth1 be .. . IL � t 1 , . .- TWR Pkr 47319 ' I" 2.375" dual float shoe ACTUAL DEPTH WILL BE PROVIDED ON A 10 -404 POST INSTALL. . • . RECEIVE • _ JAN 3 0 2013 11981A Spencer Rd. Houston. TX 7704,1 INSPECTION REPORT'`:`: OGCC 713- 896 -1115 JOB # NS30133 713- 896 -7575 (fax) DATE: 5-Jun-2012 INSPECTION TYPE Company Name & Address Crane Conoco Phillips Make UNIT Model # 6500 ANNUAL Location: Kenlc Serial # 130160 INSPECTOR Jack Rouse I. ENGINE 111, BOOM AND SHEAVES VI. WINCHES 1. Model # Jun -71 1. A2B operation Ok BOOM MIN CH17523120 -01 -4 2. Serial # J Does it creep? no SIN 9004628 3. Hours 6166 Type ofA2B: Wireless 1. Operation ok 4. Hyd. Oil Cooler ok 2. Boom Structural ok 2. Drum spooling ok 5.011 Level Ok 3. Boom Length 80 ft 3. Mounting bolts ok 6. Coolant Level ok 4. Cond. 0t pins/bolts Ok 4. Hydraulic motor ok 7. Radiator Hoses ok _ 5. Boom foot pins ok 5. Oft level ok 8. Fluid leaks Ok 6. Inspect sheaves ok B. Change drum oil no 9. Fuel level ok 7. Angle/Radius Indicator Ok 7. Castings Ok 10. Drain tank sludge ok 8. Extendable booms n/a 8. Wedge condition ok 11. Fan belts ok 9. Inspect boom cylinders n/a 9. Personnel rating yes 12. Aux belts ok 10. Boom stops ok 10. Ratchet/Pawl ok 13. Starting system ok IV. HYDRAULIC SYSTEM Load MIN CH18538120.02 -1 14. Starting system fluid n/a 1. Drain tank sludge Ok SIN 9605979 15. Accumulator press. nla 2. Hyd. Oil level/cond. ok 1. Operation ok 16. Instruments ok _ 3. Pump/Motor fasteners ok 2. Drum spooling ok 17. Exhaust System ok 4.Operation/Norse ok 3. Mounting bolls ok 18. Throttle ok 5. Control valve condition ok 4. Hydraulic motor ok 19. Engine shutdovm ok 6. Inspect fittings/leaks ok 5. Oil level ok 20. ESD X 7. Filter condition Ok 6. Change drum oil no 21. Pump shaft ok 8. Relief system press. Ok 7. Castings ok 22. Gearbox oil level Ok 9. Picot system press. n/a 8. Wedge condition ok 23. Fuel filters ok 10. Change hyd. 011 no 9. Personnel rating yes 24. Jr A filter ok 11. inspect strainers ok Aux. MIN CH150A23 1 20 -01 -1 25. Starter pinion Ok 12. Hydraulic swivel nla SIN 9203112 26. Change oil & filter ok V. UPPER STRUCTURE 1.Operation ok II. Wire Rope and Hooks 1. Swing clutches n/a 2, Drum spooling ok 1. Boom Line 5/8 6x19 2, Swing Brake ok 3. Mounting bolts ok 450ft .630 3. Swing Lock ok 4. Hydraulic motor ok 2. Load Lino 314 dyf. 18 4. Swing Gearbox Ok 5. 031 revel ok 1500ft .764 5. Swing Chain nfa 6. Change drum 011 no 3. Aux. Line 314 dyf. 18 6. Ring gear/pinion ok 7. Castings ok 370ft .767 7. Gearbox oil level ok 8. Wedge condition Ok 4. Pendant (R) 1 3/8 8. Ring gear bolts ok 9. Personnel rating yes 1.397 9. Hooks and Rollers n/a VII. GENERAL 5. Pendant (L) 1 318 10. Bearing deflection Ok 1. Inspect for corrosion ok 1.398 N .018 2. Inspect handraits ok B. Hooks condition ok E .017 3. Cab condition ok 7. Safety Latches ok S .019 4. Inspect welds ok 8. Wedge sockets ok w .018 5. Fire Extinguisher ok 9. Proper dead end ok 11. Grease sample no 8. Controls labeled' ok 10. Swivel condition ok 7. Load Chart ok 11. Pin condition ok 8. Log book ok 12. Hook throat opening load 6.4 In 9. Weight Indicator) Ok Aux: 3.5 in Is crane in full service ?: see notes 10. Safety systems ok • 11. Elec. /Alydevices ok INSPECTOR SIGNATURE Jack Rouse fr CUSTOMER SIGNATURE .101.5:.-: r • • �' Manitowoc 2�0 `C70 6 Month Inspection Lis ' Ma itowoc 2800 - t : ' onth Inspection List To b erformed every 2000 hours of operatic qr f, o (whichever comes first) \ Hours on Crane Yellow highlighted items should be done with mechanic present. SIN 29239 W/O N830134 Please note if check was satisfactory or if adjustment necessary (OK, A Jack Rouse crane Is currently out of service due to boom hoist Shift Comments Grease all 4 hour 8 hour tube points ok Clean and check al dows for cracks and breakage \ ok Clean all debris from floor stairs, and catwalks ok Check that all machinery gua s(s are In place ok (room doors) Inspect secondary containment as hd clean as ok necessary i Check radiator coolant level \ ok Check fuel tank level \ \ ok \ ` Check engine air cleaner service Indicators \ ok Check that all railings, catwalks, and non-skld "•, material are In place °k inspect roller path for damage and Lubricate with ./ ok gear oil Check ring gear and lubricate with open gear/ ok lubricant Clean Cuno oil filter by turning handle several ok times dally Check for fluid leaks (oil, fuel, coolant) ok Check that the fire extinguisher on crane is fully \ charged Check alt oil levels (dipsticks, sight gauges, and ok \\ \ level plugs): Converter output housings ok Chain case ok Engine ok Operator's guide and capacity charts are in ok operator's cab Check drum brake pedals for proper operation and that pedal latch holds pedal In fully applled ok position Inspect blocks, ball, safety latches & keepers ok Check all boom pins & keepers In place ok check all cables, sheaves & cable reeving in order and working ok White Engine Is running and at Operating ok Temperature: Check gauges on engines and In operator's ok cab for proper readings Check all brakes for proper operation and \ contact mechanic If adjustment needed ok V \ (must hold load): \ 2 t ' ,- Page 1 of 3 x i • • J 11381 -A Spencer Rd. (FM 529) Houston, Texas 77041 f Phone: 713- 896 -1115 Fax: 713 -896 -7575 Test Date: 6/6/2012 Load Test Report Customer Conoco Phillips Job Location Tyonek Job Number NS30133 Crane Manufacturer Unit Model # 5500 Serial # 130160 Boom Length so It 100% Pull 125% Load Water- weight Bag Annual Inspection Performed? Yes El No ❑ Test Test ❑ Yes El No 0 Dynamometer Mod. / ser. #: 3112501 s/n 08094254/ Dynomometer Calibration Date: 1/24/2012 Notes: Main Hoist Load Rope: Size 3/4 in Construction dyf. 18 Wire rope Breaking Strength 64500 (Load only)(3.5 or 5.0)= 12900 Single Line Safe Working Load x 6 Parts of Line = 77400 Main Hoist Safe Working Load Auxiliary Hoist Load Rope: Size Construction Wire rope Breaking Strength (3.5 or 5.0)= Single Line Safe Working Load x Parts of Line Main Hoist Safe Working Load LOAD TEST / PULL TEST RESULTS Testing? Main El Aux. LI Angle of Boom 77 degrees Verified? Yes Id No ❑ Radius Verified? Yes ❑ No ❑ Crane tested to lbs. 67000 Crane Load Chart Rating at above angle/radius 67000 Test includes percent overload? Yes ❑ No U Load Indicator System Verified? Yes El No ❑ Percent of overload Was Load Raised/Lowered? Yes El No ❑ Comments: raised lowered and swung crane.had no problems operating Tested Successfully? Yes 151 No ❑ with load of 67000 Ibs Was Boom Raised /Lowered? Yes El No ❑ Was Crane Rotated Left/Right? Yes El No ❑ Testing? Main ❑ Aux. ❑ Angle of Boom Verified? Yes ❑ No ❑ Radius Verified? Yes ❑ No ❑ Crane tested to lbs. Crane Load Chart Rating at above angle /radius Test includes percent overload? Yes LI No LI Load Indicator System Verified? Yes ❑ No ❑ Percent of overload Was Load Raised /Lowered? Yes D No ❑ Comments: Tested Successfully? Yes ❑ No ❑ Was Boom Raised /Lowered? Yes ❑ No 0 Was Crane Rotated Left/Right? Yes ❑ No ❑ Testing? Main ❑ Aux. ❑ Angle of Boom Verified? Yes ❑ No ❑ Radius Verified? Yes ❑ No ❑ Crane tested to Ibs. Crane Load Chart Rating at above angle /radius Test includes percent overload? Yes LI No LI Load Indicator System Verified? Yes ❑ No ❑ _ Percent of overload Was Load Raised /Lowered? Yes ❑ No ❑ Comments: Load Tested Successful? Yes ❑ No ❑ Was Boom Raised/Lowered? Yes ❑ No ❑ Was Crane Rotated Left/Right? Yes ❑ No ❑ Testing? Main ❑ Aux. ❑ Angle of Boom Verified? Yes 11 No ❑ Radius Verified? Yes ❑ No ❑ Crane tested to lbs. Crane Load Chart Rating at above angle /radius Test includes percent overload? Yes U No ❑ Load Indicator System Verified? Yes 0 No ❑ Percent of overload Was Load Raised /Lowered? Yes ❑ No ❑ Comments: Load Tested Successful? Yes ❑ No ❑ Was Boom Raised/Lowered? Yes ❑ No ❑ Was Crane Rotated Left/Right? Yes ❑ No ❑ Crane Inspectors's Signature: ,a .4C/' Printed Name: Jack Rouse / Oryan Vinsant �--� / Customer Representative's Signature: �� Printed Name: 1/71.• �S J 9 • • < 11981 -A SPENCER RD. (FM 529) HOUSTON,TEXAS 77041 PHONE: 713 -896 -1115 FAX: 713 - 896 -7575 Customer onoco Philips Job Location Tyonek Job # NS30133 Manufacturer Unit Model 5500 Serial # 130160 1 INSPECTION REPORT SUMMARY INITIAL AND CHECK OFF AFTER # PRIORITY REPAIRS 1 took aux. winch out of service till winch has been changed has been on crane over 6 yeark_ R 2 esd cable broke needs replaced (on order) R 3 needs muffler wrap installed R 4 hydro contro D -16 cap for swing cotrol valve needs replaced R PRIORITY LEGEND: (R) COMPONENT REPAIR OR REPLACEMENT NEEDED (M) MONITOR CONDITION (I) INFORMATION ONLY NO ACTION NEEDED AT THIS TIME Crane Inspector: Jack Rouse 0444. /4 6/7/2012 P S DATE Customer Representative: ‘77// Z SIGNATURE DATE • 11981 -A Spencer Rd. (FM 529) Houston, Texas 77041 sparrows Phone: 713-896-1115 Fax: 713 -896 -7575 LNGINEEPING &OPERAWNS Test Date: 6/18/2012 Load Test Report Customer Conoco Phillips Job Location Tyonek Job Number NS3013i Crane Manufacturer Unit Model # 5500 Serial # 130160 Boom Length 1ooft 100% Pull 125% Load Water - weight Ba Annual Inspection Performed? Yes EI No ❑ Test Test ❑ Yes El No 12 Dynamometer Mod. / Ser. #: RON2501 sin 08094254111 Dynomometer Catibration Date: 1/24/2012 Notes: Main Hoist Load Rope: Size 3/4 in Construction dyf. 18 Wire rope Breaking Strength 64500 (Load only)(3.5 or 5.0)= 12900 Single Line Safe Working Load x 6 Parts of Line = 77400 Main Hoist Safe Working Load Auxiliary Hoist Load Rope: Size 3/4" dy 18 Wire rope Breaking Strength 64500 (3.5 or 5.0)= 12900 Single Line Safe Working Load x 1 Parts of Line = 12900 Main Hoist Safe Working Load LOAD TEST ! PULL TEST RESULTS Testing? Main p Aux. LI Angle of Boom 77 degrees Verified? Yes LI No LI Radius Verified? Yes ❑ No ❑ Crane tested to lbs. 55000 Crane Load Chart Rating at above angle /radius 55000 Test includes percent overload? Yes U No Li Load indicator System Verified? Yes El No ❑ Percent of overload Was Load Raised /Lowered? Yes El No ❑ Comments: raised lowered and swung crane.had no problems operating Tested Successfully? Yes EI No ❑ with load of 55000 lbs Was Boom Raised /Lowered? Yes El No 0 Was Crane Rotated Left/Right? Yes EI No ❑ Testing? Main ❑ Aux. El Angle of Boom 77* Verified? Yes IA No U Radius Verified? Yes ❑ No ❑ Crane tested to lbs. 12,000 Crane Load Chart Rating at above angle /radius Test includes percent overload? Yes U No IA Load indicator System Verified? Yes El No ❑ Percent of overload 0 Was Load Raised /Lowered? Yes El No ❑ Comments: Tested Successfully? Yes i0 No ❑ Was Boom Raised /Lowered? Yes IS No 0 Was Crane Rotated Left/Right? Yes EI No ❑ Testing? Main ❑ Aux. U Angle of Boom Verified? Yes U No U Radius Verified? Yes ❑ No ❑ Crane tested to Ibs. Crane Load Chart Rating at above angle /radius Test includes percent overload? Yes U No U Load Indicator System Verified? Yes ❑ No ❑ Percent of overload Was Load Raised/Lowered? Yes ❑ No ❑ Comments: Load Tested Successful? Yes ❑ No ❑ Was Boom Raised /Lowered? Yes 0 No ❑ Was Crane Rotated Left/Right? Yes ❑ No ❑ Testing? Main ❑ Aux. U Angle of Boom Verified? Yes U No 0 Radius Verified? Yes ❑ No U Crane tested to Ibs. Crane Load Chart Rating at above angle /radius Test includes percent overload? Yes U No U Load Indicator System Verified? Yes ❑ No ❑ Percent of overload Was Load Raised /Lowered? Yes ❑ No ❑ Comments: Load Tested Successful? Yes ❑ No ❑ Was Boom Raised /Lowered? Yes ❑ No ❑ Was Crane Rotated Left/Right? Yes 0 No ❑ Crane Inspectors's Signature: A ,, .® Printed Name: Jack Rouse / Oryan Vinsant /l r G , Customer Representative's Signature: Printed Name: Tn i t; _ ' ,,.,..".., S r. - HOUSTON SERVICE LOCATION 11981 -A Spencer Road (FM 529) I.:1L § . rte; E. :=.=t' 5 ry Houston, 7X 77084 •Sk CD P.E1,;,.%1" -r C r • q 713 896 -1115 f�(: 713- 896 -7575 �+ CUSTOMER NAME & ADDRESS WORKORDE NS30134 NAME& CONOCO PHILLIPS UNIT P. LOCATION MFG. Manitowoc N0, OF UNIT TYONEK UNIT START STOP JUMP OFF TOTAL SIN 29239 TIME TIME POINT HRS. UNIT BEACH BEACH REPORT OFFSHORE M/N 2900 OUT IN TIME REQUESTED CUSTOMER HRS. BY PHONE NO. DATE 07-Jun-12 REASON FOR CALL ANNUAL INSPECTION WORK PERFORMEC had safety meeting filled out jsa got work permit went out to crane moved worm gear around done dye penetrant test on other side found about • 20 cracks on that side showed Ernie he took pics we put inspection covers back on filled boom hoist with oil and boomed crane drown in rest inspected boom inspected bridle and pantry sheaves greased sheaves inspected boom cable pendants Conoco took crane out of service on my recommendation cleaned up work area got parts book made parts list to repair boom hoist called h &e talked to David Romano faxed him a copy of parts list waiting to hear back on avalibility of parts as of this time crane is out of service till boom hoist is repaired unable to finish annual at this time due to boom hoist parts have been ordered IS CRANE SAFE TO OPERATE AT THIS TIME? No IS THE INSPECTION COMPLETE? No CHARGES DAILY TOTAL EXT. TOTAL IS THE CRANE IN SERVICE? No MEALS LODGING TOTAL HOURS: 15 X 2 MEN= 30 MILEAGE MILPTGE LABOR • QTY PART N0. /DESCRIPTION PRICE QTY PART NO. /DESCRIPTION PRICE PARTS SUBLET MSC. TOTAL 0 SERVICE REP. X Jack Rouse CUSTOMER REP. X f ems/ ,c Oryan Vinsant 1 . • 1 • . • ?Z/o5 • . ConocoPhillips • COOK INLET WRITTEN LIFTING PLAN Lift Locat � t� � - i5 V R. i 4 ( .1E ' 6.;?,:` }6 CC4 i0 Date 916 6 . - U J2. Specify below Mobile, Overhead or Pedestal equipment used to execute the lift (example - . LNG Hydrolift Mobile Crane, Tyonek Manitowoc Pedestal Crane, BRU Contract Crane, etc). Lifting Equipment: ri o,.. /e 0d » i I • . S66 Craw; . 1. Conditions that require a ) Permit: A. Critldal Lifts: See Page 33, Item 8 of the ASH (Handbook). "A written lifting plan Is required before making picks over live process lines. The plan will be approved by the Safety Representative and the First -Line Supervisor ". '. •: B. Lifts in excess of 75% of the load chart will be regarded as critical lifts. Lift Loci~:io •: Lifts of crane suspended work platforms will be regarded as critical lifts. • -•--- All -tasks -to be-completed while having heavy equipment in service must follow the guidelines ef-- -- • I :fin :WASH SASH (Handbook) Pages 33 - 37. To be considered, but not required of the Written vi-mi , I� - 1 t LI'J!tifting Plan, are the following conditions: - : ;.:;,, • 1. Process Condition • Lifting over operating process equipment containing hazardous material or lifting over equipment which Is shut down and isolated from the process but contains hazardous materials to include chemicals, fuel sources and high pressures. 2. Proximity to Personnel / Equipment • Lifting over operating equipment, control rooms, office buildings or around . • personnel. �;, : . • . _ 3. Size of Lift ' • .. F. As physical dimensions and weight increase, risk typically increases. Problems at Lr:) : r, 3 r,•• are more likely as the limits of weight and reach of the crane are approached •' the job requirements. ' ----- -"— - - • :Ai€'r': . . 4. Complexity :�!s! evf - ••' f Multiple cranes make the lift more difficult. The number and difficulty of-m• ! :.F'`•• • • maneuvers and confinement due to surrounding equipment increases complexity. Weather conditions such as wind and decreased visibility situations are a factor. 5. Consequences of Failure • For small routine lifts, failure may result in personnel injury and minor damage to equipment. Where operating equipment is involved, major financial • . consequences can result from failure during a large lift. If the load Is dropped on live operating egiuipmerit, the result may be fire, explosion, equipment•darnage, injury to employees and loss of production. Consequences of failure should be examined by maintenance and operations personnel in determining critical lifts. • Steps should be taken to minimize risk. :x: •• • 6. Hoisting of Personnel v:!-s?.: See Page 33, item 11 of the ASH (Handbook). "Man - baskets and other • • • • personnel lifting devices shall be used only as a last resort and only as after:: • s • • • completing a preloaded trial lift". • • • • 2. Inspections: :. •'• • A. Daily lifting equipment inspections are required prior to lifting. B. Conduct a pre -lift inspection of lifting devices such as spreader bars and slings for proper condition. {. ° ' Routing: Operations Manager Safety Spec. _ File: B16 -1(1) LNG B16 -1(2) NCIU B16 -1(3) BRU ,.• t . W. . • • . •. .q-, _ . Insure that a competent person inspects the rigging for safety, review past similar lifts for lessons learned. D. Conduct pre -lift site Inspection for potential hazards; consider scheduling changes to avoid lifting over operating equipment or alternative lift paths when possible. Consider Lock Out/Tag Out of auxiliary or adjacent lines and equipment. • 3. Other Considerations: -i=ter A. Conduct a pre -lift meeting with the person(s) responsible for the task, the crane operator, signal persons and tag line handlers, operations personnel and any other affected °: personnel as applicable. B. USCG approved PIiD or work vests are required for personnel for hoisting operations performed over water. C. Consider appropriate harnesses and lanyards or other special personal protection equipment and devices for personnel where appropriate. - D. Consider that an agequate number of trained persons are available for rigging, .sign aiing; handling tag lines, safety watches and crane control operations. E, If offshore, consider the availability of response personnel In an emergency. f,, 4. Checklist: A. Site inspection 1•'a yes ❑ no 3. 13t Meeting $J yes ❑ no 14 1:1 n/a G. Persohal protective equipment yes no a s • D, Lifting' devices Inspection yes ❑ no " ❑ n/a E. • Rigging inspection yes ❑ no 0 n/a - F. Equipment Inspection tgl yes ❑ no ❑ n/a G. Personnel Basket Pre - Operation Checklist ❑ yes 0 no fg n/a • • • j , (Form PF- 0025) H. Other 1`� _,Jc� E° (.0,;'C -.t (Z, / , , w 'r.° T5() [4 yes ❑ no - . .0 n/a Describe e item to be lifted and intended lift path, include potential hazards: Wmmi-i,S6 {< v , L.: f4 LQ isl fii locoh !-/0 It -- tK r, C1 ` / r Effective f C , 20 l L ' T 2- 30 4/11a9 u3' Expires: 0 , 20 / 2, Time: d AM/ PLEASE :SIGN, IF APPLICABLE, AFTER ALL TESTS AND INSPECTIONS HAVE B -- N MADE: — 1 �� Person Responsible for Task e e lI ^ a- Ve, drar�e �p,erator V /'t_Li.- (,-t' .;: 0-.t!' ,1 (5p t, .. • ignai er on (6 l� ', E �k'h�'f.4t ' � �}�h Frei (.�` - 1� ! :� { se r rations (9 Line Supervisor) ; -- - `-7� --.` n • r , Perhoris to be Lifted 4 Safety Spec. (Critical Lift Only) . jOAI/ Z C.c - y i, 4 ) t • L tit ng: ; Operations Manager Safety Spec. File: B16 -1(1) LNG B16 -1(2) NCIU B16 -1(3) BRU -" - �; t : .t ,. ,, . . - .. 11981A Spencer Rd. : - Houston, TX 77041 ,' ` I I V SPECTtON IP O~i� :;`': -- . " ;`, 713- 896 -1115 JOB # rl r:' IL I NJ r t 1 g t - C_:::, NSSv -20 713 -896 -7575 (fax) DATE: 20-Nov-2012 .E.::.,• C :r P E:+4: .1'.. 1 1'C] P • INSPECTION TYPE Company Name & Address Crane INITIAL CONOCO PHILLIPS Make UNIT QUARTERLY X Model # 5500 ANNUAL Location: TYONEK Serial # 130160 INSPECTOR JACK ROUSE 1. ENGINE III. BOOM AND SHEAVES VI. WINCHES 1. Model # DETRIOT 1. A2B operation OK BOOM MIN CH17523120 -01 -1 2. Serial # N/A Does it creep? WIRELESS SIN 9004628 3. Hours 6290 Type of A2B: LSI 1. Operation OK 4. Hyd. 00 Cooler OK 2. Boom Structural OK 2. Drum spooling OK 5.00 Level OK 3. Boom Length SOFT 3. Mounting bolls OK 6. Coolant Level OK 4. Cond. Of pinslbolts OK 4. Hydraulic motor OK 7. Radiator Hoses OK 5. Boom foot pins OK 5. Oil level OK 8. Fluid Teaks OK 6. Inspect sheaves OK 6, Change drum oil NO 9. Fuel level OK 7. Angle /Radius Indicator OK 7. Castings OK 10. Drain tank sludge OK 8. Extendable booms N/A 8. Wedge condition OK 11. Fan belts OK 9. Inspect boom cylinders N/A 9. Personnel rating YES 12. Aux belts OK 10. Boom stops OK 10. Ratchet/Pawl OK 13. Starting system OK IV. HYDRAULIC SYSTEM Load MIN CH18536120 -01 -1 14. Starting system fluid N/A 1. Drain tank sludge OK SIN 9605979 15. Accumulator press. NIA 2. Hyd. 00 levellcond. OK 1. Operation OK 16. Instruments OK 3. PumplMotor fasteners OK 2. Drum spooling OK 17. Exhaust System OK 4. Operation/Noise OK 3. Mounting bolts OK 18. Throttle OK 5. Control valve condition OK 4. Hydraulic motor OK 19. Engine shutdown OK 6. Inspect fittings/leaks OK 5. level OK 20. ESD OK 7. Filter condition OK 6. Change drum oil NO 21. Pump shaft OK 8. Relief system press. OK 7. Castings OK 22. Gearbox oil level OK 9. Pilot system press. NIA 8. Wedge condition OK 23. Fuel filters OK 10. Change hyd. 011 N/A 9. Personnel rating OK 24. Air filter OK 11. Inspect strainers OK Aux. MIN 011150A23120 -01 -1 25. Starter pinion OK 12. Hydraulic swivel N/A SIN 9203112 • 26. Change oil & filter N/A V. UPPER STRUCTURE 1.Operation OK II. Wire Rope and Hooks 1. Swing clutches N/A 2. Drum spooling OK 1. Boom Line 6/8 6X19 2. Swing Brake OK 3. Mounting bolts OK 450FT .630 3. Swing Lock OK 4. Hydraulic motor OK 2. Load Line 3/4 DYF18 4. Swing Gearbox OK 5. Oil level OK 1500FT .764 5. Swing Chain N/A 6. Change drum oil NO 3. Aux. Line 314 DYF18 6. Ring gear/pinion OK 7. Castings OK 370FT .767 7. Gearbox oil level OK 8. Wedge condition OK 4. Pendant ( R) 1 3/8 8, Ring gear bolts OK 9. Personnel rating YES 1.397 9. Hooks and Rollers N/A VII. GENERAL 5. Pendant (L) 1 3/8 10. Bearing deflection N/A 1. Inspect for corrosion OK 1.398 N N/A 2. Inspect handrails OK 6. Hooks condition OK E N/A 3. Cab condition OK 7. Safety Latches OK S N/A 4. Inspect welds OK 8. Wedge sockets OK W N/A 5. Fire Extinguisher OK 9. Proper dead end OK 11. Grease sample N/A 6. Controls labeled' OK 10. Swivel condition OK 7. Load Chart OK 11. Pin condition OK 8. Log book OK 12. Hook throat opening Load: 6.5 IN 9. Weight Indicator OK Aux: 3.5 IN Is crane in full Service ?: YES 10. Safety systems OK 1 t. Elec. /Air devices OK INSPECTOR SIGNATURE d' K ROUSE - i . CUSTOMER SIGNATURE - L( r� i i • • • 11981 -A Spencer Rd. (FM 529) Houston, Texas 77041 sparrows Phone: 713-896-1115 Fax: 713 -896 -7575 ENGINEERING & OPER/ t IONS Test Date: 11/19/2012 PULL Test Report Customer conocophillips Job Location tyonek Job Number NS30880 Crane Manufacturer UNIT Model # 5500 Serial # 130160 Boom Length 80 FT 100% Pull 125% Load Water weight Bag • Annual Inspection Performed? Yes ❑ No El Test Test Yes El No S p ❑ Dynamometer Mod. / Ser. #: RON2501/08094254/1' Dynomometer Calibration Date 1/26/2012 Notes: Main Hoist Load Rope: Size 7/8 IN Construction DYF 18 Wire rope Breaking Strength (Load only)(3.5 or 5.0)= Single Line Safe Working Load x 6 Parts of Line Main Hoist Safe Working Load Auxiliary Hoist Load Rope: Size Construction Wire rope Breaking Strength (3.5 or 5.0)= Single Line Safe Working Load x Parts of Line = Main Hoist Safe Working Load LOAD TEST / PULL TEST RESULTS Testing? Main p Aux. U Angle of Boom 28 DEG. Verified? Yes LI No Ll Radius 75 FT Verified? Yes p No ❑ Crane tested to lbs. 17,640 Crane Load Chart Rating at above angle /radius 17,640 Test includes percent overload? Yes U No k] Load Indicator System Verified? Yes ❑ No p Percent of overload Was Load Raised /Lowered? Yes ❑ No El Comments: held load for five min Tested Successfully? Yes El No ❑ Was Boom Raised /Lowered? Yes ❑ No El Was Crane Rotated Left/Right? Yes ❑ No 12 Testing? Main ❑ Aux. ❑ Angle of Boom Verified? Yes U No U Radius Verified? Yes ❑ No i•J Crane tested to lbs. Crane Load Chart Rating at above angle /radius Test includes percent overload? Yes LI No U Load Indicator System Verified? Yes ❑ No ❑ Percent of overload Was Load Raised /Lowered? Yes ❑ No ❑ Comments: Tested Successfully? Yes ❑ No ❑ Was Boom Raised /Lowered? Yes ❑ No ❑ Was Crane Rotated Left/Right? Yes El No ❑ Testing? Main ❑ Aux. U Angle of Boom Verified? Yes U No 0 Radius Verified? Yes 11 No ❑ Crane tested to lbs. Crane Load Chart Rating at above angle /radius Test includes percent overload? Yes U No U Load Indicator System Verified? Yes ❑ No ❑ Percent of overload Was Load Raised /Lowered? Yes ❑ No ❑ Comments: Load Tested Successful? Yes ❑ No ❑ Was Boom Raised /Lowered? Yes ❑ No ❑ Was Crane Rotated Left/Right? Yes ❑ No ❑ Testing? Main ❑ Aux. LI Angle of Boom Verified? Yes U No U Radius Verified? Yes ❑ No ❑ Crane tested to lbs. Crane Load Chart Rating at above angle /radius Test includes percent overload? Yes U No U Load Indicator System Verified? Yes ❑ No ❑ Percent of overload Was Load Raised /Lowered? Yes ❑ No ❑ Comments: Load Tested Successful? Yes ❑ No ❑ Was Boom Raised /Lowered? Yes 0 No ❑ Was Crane Rotated Left/Right? Yes ❑ No ❑ Crane Inspectors's Signature: 7-, t _ Printed Name: JACK ROUSE Customer Representative's Signature: 4„..46, `sus" Printed Name: c • neS r c M A; 5 j f I - - .. . -,.... -.- HOUSTON SERVICE LOCATION 11981 -An Spencer Road (FM 529) Houston, TX 77084 E Ss'"'" L NJ ER . o N 713 -896 -1115 fax 713 -896 -7575 CD cat` WORK ORDER NS30880 CUSTOMER NAME & ADDRESS NAME& UNIT P.O. LOCATION TYO N EK CONOCO PHILLIPS MFG. UNIT NO, OF UNrT UNIT START STOP 'JUMP OFF TOTAL WV 130160 TIME TIME POINT HRS. UNIT BEACH BEACH REPORT OFFSHORE M!N 5500 OUT IN TIME HRS. REQUESTED CUSTOMER BY PHONE NO. DATE 19 -Nov -12 REASON FOR CALL BOOM CHANGE & QUARTERLY INSPECTION • WORK PERFORMED FLEW TO ANCHORAGE THEN TO KENAI GOT IN AT 4:30 AM TOOK CAB TO OSK WAITED ON FLIGHT FLEW OUT TO PLATFORM SIGNED IN GOT WORK PERMIT FILLED OUT JSA HAD SAFETY MEETING BOOMED CRANE DOWN ON STAND UNHOOKED PENDANTS REMOVED • TIP SECTION THEN REMOVED 20 FT SECTION INSTALLED TIP BACK ON HOOKED UP PENDANTS BOOMED CRANE UP DONE PULL TEST ON MAIN LINE PULLED 17,640 AT 28 DEG. HELD FOR FIVE MIN CLEANED UP WORK AREA DONE PAPER WORK G✓ 0O# 9315523 IS CRANE SAFE TO OPERATE AT THIS TIME? YES IS THE INSPECTION COMPLETE? YES CHARGES DAILY TOTAL EXT. TOTAL MEALS IS THE CRANE IN SERVICE? YES LODGING MILEAGE • TOTAL HOURS: 18 x 1 MEN= 18 MILEAGE LABOR QTY PART NO. /DESCRIPTION PRICE QTY PART NO. /DESCRIPTION PRICE PARTS SUBLET MISC. TOTAL 0 SERVICE REP. X /l ,c4 / CUSTOMER REP. X /,_ ;,' , . = li k -• HOUSTON SERVICE LOCATION 1:20,2 iv iv „ csimtsw. 11981 -A Spencer Read (FM 529) `."G t NI E EIR E Houston TX 77084 .& O P E;r E a : I lc I' S 713- 896 -1115 fax: 713- 896 -7575 WORK ORDER NS30880 CUSTOMER NAME & ADDRESS NAME& UNIT P.O. LOCATION TYO N E K CONOCO PHILLIPS MFG. UNIT NO. OF UNIT UNIT START STOP JUMP OFF TOTAL S!N 130160 TI ME TIME POINT FIRS. UNIT BEACH BEACH REPORT OFFSHORE MIN 5500 OUT IN TIME HRS. REQUESTED CUSTOMER BY PHONE NO. DATE 20 -Nov -12 REASON FOR CALL BOOM CHANGE & QUARTERLY INSPECTION • WORK PERFORMED HAD SAFETY MEETING GOT WORK PERMIT FILLED UOT JSA WENT OUT TO CRANE DONE PRE -USE INSPECTED ENGINE,RADIATOR FUEL SYSTEM,HYD. SYSTEM,WINCHES,BOOM AUX. AND MIAN CABLES, INSPECTED BOOM,SHEAVES IN TIP,PENDANT LINES,BLOCK AND BALL,TESTED A2B,BOOM KICK OUTS, AND RAN CRANE ALL FUNCTIONS WORKING CLEANED UP WORK AREA DONE PAPER WORK 6k1 .'O# 9144726 IS CRANE SAFE TO OPERATE AT THIS TIME? YES IS THE INSPECTION COMPLETE? YES CHARGES DAILY TOTAL EXT. TOTAL MEALS I IS THE CRANE IN SERVICE? YES LODGING MILEAGE • TOTAL HOURS: 7 x 1 MEN= 7 MILEAGE LABOR QTY PART NO./DESCRIPTION PRICE QTY PART NO./DESCRIPTION PRICE PARTS SUBLET MISC. TO L 0 SERVICE REP, X CUSTOMER REP. ' r ''l/ 1� • • Cie !Itf June 9, 2011 GE Oil and Gas RE: BOP Control System (Diesel Powered) CAD Control System Model No. CAD 30- 3LCO4ZT8O is manufactured to meet the specification as follows: CAD's ISO 9001 Quality Program, API 16D, accumulators are provided with ASME U -1A certificates. ri One (1) Reservoir and Skid Module RSM- 80AC2A manufactured by CAD Control Systems. H Consists of: (A) One (1) — Carbon Steel 80 gallon fluid reservoir complete with baffles, inspection ports, sight glass and 3" inspection points. Space is provided for up to four (4) manifold. . ^d cJ (B) Assembled on a welded structural steel skid with four post frame basket top with 4 mounting provisions for Diesel driven pumps, hydraulic control manifold modules described in the following paragraphs of this quotation. rir 0 a (C) Tank Fluid Level Indicator to be located on reservoir where clearly visible. zz 00 (D) Blasting & Coating_ Consisting of Blast to near white metal per SSPC Specification NI a SP 10 -63T, NACE #2 and coating with a two part paint system consisting of aluminum ul oxide base coat and polyurethane top coat. 7 • � x � o One (1) - Accumulator Module Model ACM- U22032301A manufactured by CAD Control Systems. Consists of: (A) Three (3) - Eleven (11) gallon 3,000 psi working pressure separator (bladder type) Cold C ri W weather accumulators. The accumulator shell is manufactured from a single piece of H « chrome molybdenum steel and is free from joints, seams or welds. The bottom loading d t design permits field repair without voiding certification. tot 1'Lic'it:L ttit,I,1 �• i) Sri`).' ,. m a ,afcs(i;caduil.cocn a z wv v∎.i_ aduit.0nn R ()I'' ( nrttrid Systems 1)kcrter ( onlrnl cslends Ili14h Pressure 1 estin9 Stste»tc • • 6/10/2011 Page 2 The accumulator assembly is tested to 4,500 psi. These vessels meet ASME, API, and other agency requirements. ASME U -1A certificates are provided for each accumulator may be provided for an additional cost if requested other agency certifications y uested at time p q of order. (B) One (1) - 4'A" O.D. machined steel accumulator manifolds. These manifolds are free from welds, seams or joints and meets requirements for working pressures up to 5,000 psi and will have space for mounting three (3) accumulators. (C) One (1) - 3/4" pressure relief valves set at 3,300 psi. These pressure relief valves prevent over pressuring the accumulators and pump systems and are self - resetting. One (1) - E -Series Diesel Pump Module Model U8XHD 12V manufactured by CAD Control Systems. This module is mounted on item 1 of this quotation and is used to pump fluid stored in the reservoir at atmospheric pressure, up to 3,000 psi to charge the accumulators and operate the --N B.O.P. stack functions. Consists of: t3 ' s N 2 (A) One (1) - positive displacement reciprocating triplex plunger pump. �r (B) One (1) - 10X horse power Yanmar air - cooled diesel engine. Includes electric start and spark arrestor muffler. z e (C) One (1) - electric pressure switch set to automatically stop the pump when system 5 a pressure reaches 3,000 psi and an auto starter system to start the pump when system pressure is below 2,600 psi. N (D) One (1) Solar Powered trickle charger to maintain battery charge. N ° (D) Complete with %" 20 mesh suction strainer and 1 /2" 5,000 psi working pressure discharge check valve. ri NN Flow Rate - 4.5 GPM A A One (1) - T -Series Air Pump Module Model APM -B 1 SBA manufactured by CAD Control FA 0 FA' Systems. This unit is mounted on item 1 of this quotation and is used in conjunction with the 0 . primary electric pump. Consists of: (A) One (1) - 7 3/8" air motor driven 60:1 ratio plunger pump with self - adjusting packing. o This assembly produces approximately 3.7 GPM at mid range pressure of 2,000 psi. • Approximate air consumption: 117 SCFM. 9d (B) One (1) - hydro - pneumatic pressure switch set to automatically stop the pump(s) when PI 04 system pressure reaches 2,800 psi. The pump(s) will automatically start again if system H o pressure falls approximately 400 psi. >a ma, (C) One (1) - I" air control supply manifold with inlet air filter, air pressure gauge, air line lubricator and 1" NPT female customer inlet connection. Includes Y4" air motor lines and shutoff valves to each pump. Exl (D) One (1) - 1" 20 mesh suction inlet strainer. x •- N W u) 4 H HW • • 6/10/2011 Page 3 (E) One (1) -''A" 5,000 psi working pressure discharge check valve. One (1) - Hydraulic Control Manifold Module HMM-261722DC1D6 manufactured by CAD Control Systems and unit mounted on item 1 of this quotation. Consists of: (A)One (1) - manually operated 1/2" ported, pressure reducing and regulating valve for controlling manifold regulated pressure to the ram type preventers and/or hydraulic actuated choke and kill line valves. This regulator is manually adjusted and limits maximum outlet pressure to 1,500 psi during normal operation. Maximum outlet pressure of 3,000 psi is available upon demand. (B) Four (4) - CAD Integrated Hydraulic Four -Way Valves, 1/2" size stainless steel fitted, 4- way, 3 position manually operated rotary shear seal selector valves rated for 3,000 psi working pressure to control pressure to open and close ram preventers and/or hydraulically actuated choke and kill line valves. Integrated Hydraulic Four -Way Valves c integrate the remote cylinder into the body of the Hydraulic Four -Way Valve. With utilizing the integrated valve the following results are a faster response time, elimination of mounting brackets, time - consuming adjustments, and corrosion problems. 1 4 (C) One (1) - CAD Integrated Hydraulic Four -Way By -Pass Valve, 1/2" size, 4 -way, 3 rl position manually operated rotary shear seal selector valve for operation of the manifold N H regulator by -pass function. This valve allows selection of regulated pressure or 3,000 I PSI (full accumulator pressure) to the manifold valves for emergency operation of the ry� ram type preventers. >Q (D) One (1) - gauge panel assembly with dual scale, panel mount, 6" face pressure gauges complete with pulsation dampeners for direct indication of the below. 1. Accumulator pressure 0 -6,000 psi and 0- 42,000 KPA 2. Manifold regulated pressure 0 -6,000 psi and 42,000 KPA o O One (1) - 10,000 psi working pressure manifold bleeder valve for bleeding system pressure to ry N the reservoir when required for maintenance. c c w (G) Manifold supply piping which consists of: «4 1. 1" steel Schd. 160 main supply line. 2. 1" steel branch lines. 3. 1/2" steel supply & vent lines for each 1/2" 4-way selector valve. c 4. 1/2" steel tubing outlets for open /close functions on 4 -way valves. > g 5. 1" steel filter assembly. al re Rq 4-1t4 WO W Wa 1 u z is oz H W as «z 0 •• H WtA FH aa {71 R' • • "- SPECIFICATIONS AND REPLACEMENT PARTS BOWEN SNUBBING BLOWOUT PREVENTERS . I i RAM TYPE BLOWOUT PREVENTERS - CLOSING /OPENING VOLUMES & PRESSURES GALLONS GALLONS ASSEMBLY B.O.P. WORKING VERTICAL HYD. PRESS. TO TO CLOSE NO. SIZE PRESSURE BORE FOR OPERATION CLOSE OPEN RATIO INCHES INCHES PSI (PER SET OF RAMS) (PER SET OF RAMS) a 79289 2%, Single 20,000 2%, 1,200 .65 .78 22.7:1 79926 3 %, Single 20,000 3y 1,250 .69 .74 16.2:1 78684 4%, Single 15,000 4%. 1,250 .89 .74 16.2:1 1 ) 4 ± I 81296 4%, Single 20,000 4%, 1,250 69 .74 16.2:1 Keyless . 79288 4'J„ Twin 15,000 4%, 1,250 .69 .74 16.2:1 i 63642 7'4„ Single 10,000 7%,, 900 1.02 1.10 16.2:1 79466 7%, Twin 10,000 7q„ 900 1.02 1.10 16.2:1 RAM ASSEMBLY 41) 1 Size 2%,' 3' /,," 4'/ „” 4'/„" Keyless 7'4," COMPLETE RAM ASSEMBLY Part No. 74542 77692 77692 ! 146469 63643 i Weight 14 34 ..... 110 • Consists of BODY Part No. ; 74202 80875 80875 146312 63644 • Weight 4' 13 j 30 30 # t OUTER SEAL Part No. 81073 43603 43603 43603 66409 Weight . .. 4 INNER SEAL Part No. 74182 1 77729 77729 77729 66408 Weight INNER SEAL RETAINING SCREW Part No. + 74184 77691 77691 77691 64227 Weight V, h '4, 1 Oz. Part No. 50476 61654 79550 61654 RAM KEY Weight Z 1 Y. b RAM KEY SCREW Part No. 64219 22830 22830 ..... 62887 Weight 1 Oz. 1 Oz. 1 Oz ..... 1 Oz. • 3 ; u k: -23- ✓, • A I• B 0 C • I D U Ali i``i''i g. 4 -v- ■ 4 el II Idl I I L /�� „ ,li:� 1III 1 . r .1 „I' � (/ 1 % 9,97 L^I� .._�,�v 1t Y • ' '1 1l► wei il __ A F _ 1•11_ =.1 5 0.12 M NW , 50 31 on ME ISITC X- MASEPSI 3 .. 3 m. MU i I 12 ., _- - == 1 1 PSI HOLD DOWN FLANGE ,W ICI 0 ICI _ 2 - -5000 PSI 15100 2218 GATE VALVE D I ' y . � I, 1 i � I ;,�w3I ' a � - o. 4 I I 3502 � _ i 1 ' � 4 FA i 1' -50 PSI API FLG S . 4 I.. IH r .,,ta N I• I• GA7�E•V 5000 PSI 25 98 a � I Imo, ii 1 -5000 P51 MODIFIED FLANGE 2 2 52w . 1I 'd VG -SEAL III 11111.1 NG HGR, 18.19X9 -5/8 26.93 II iilr. 07 zee Lao 111111111111 .9 r -.OPPF 11.81 -L80 SURFACE CASING -LICK DISCONNECT 23 -5/8 X 20.00 I' 28 BUTT WELD A ` I A:I>111m ► 1 + 4• LP OUTLETS 11.00 \ I II WELL FLOOR I -82 &00 -0.50 WALL CONDUCTOR 1 - + I 1 1 M00095 vetcog ray _ ASSEMBLY/SAE 1 R' SPLIT MULTIBOWL SYSTEM, FOR 1 B. M OVAFFAGH = CONOCO PHILIPS, TYONEK PLATFORM GH c. wa+c 2r X 9-5/8 X 7 X 4-1/2 1 THIS IS A GENERIC DRAWING. l',.."4..- C/W 4- 1/16 -5M, X -MASS TREE REFER TO DASH NUMBERED PARTS S HOWING MULTIBOWL & X -MASS TREE NOTES: UST FOR ADDITIONAL INFORMATION. 08 2008 pp a D ACENOB -075 NC P 00 1101 SCALE IIMMM0 EN2008 -0741 Hr.* aes l NA I z "EE 1 , 2 • PRINT SCALE: 1 =8 A I B U C 1 0 A ID B V C D 4 4 DRILLING ADAPTER 21 -1 /4 -2000 QD BOTTOM — 1 1 - 4 ) \ !! �! 18.41 21.35 QUICK DISCONNECT - A r -- 23 -5/8 X 20.00 �� 4 28 BUTT WELD 3 11.81 0 0 ��.:: 3 BUTT WELD , ,4 ,e —017.62 ID 11.00 4" LP OUTLETS C \11111 1 I 4 WELL FLOOR — 028.00 -0.50 I WALL CONDUCTOR 028.00 2 2 7;00095 vetcogray _ _ ASSEMBLY/SINE _ " +641.. SPLIT MULTIBOWL SYSTEM, FOR `WL�' CONOCO PHILIPS, TYONEK PLATFORM 1 M ➢ a DvAFFAGN ARRANGEMENT SHOWING w > vne O.D. DRILLING ADAPTER 1 THIS IS A GENERIC DRAWING. i7 .2 NOTES: REFER TO DASH NUMBERED PARTS Pooe UST FOR ADDITIONAL INFORMATION. 0 _ • E{ D I 2= a CEN08 -075 INC 00 NOT 000E MAWS EN2008 -024 I + h 1 . 7 « NA I z EE 2 oF 2 PRINT SCALE: 1 =4 A I B L C I D • • CONOCO PHILLIPS TYONEK PLAFORM 4- 1/16" 15M TUBING BOP STACK II--o_H 4" 10M WIRELINE CAP I., ....... II. UNKNOWN HEIGHT DSA 4" 15M X 4" 10M - 3" TALL 4" 15M BOWEN SGL GATE 1 :: III :•* '. DRESSED 1.900" ..r ,., - e.e ,., 28" TALL IL Ilir 1111 e.e ue e.e e.r ne 4" 15M BOWEN SGL GATE i 1��, DRESSED CSO e itl Ir. r.r e.e 28" TALL DSA 4" 15M X 4" 5M - 3" TALL min,Imn'reu _ % ^\ _ - = 4" 5M CROSS W /2" 5M OTL ®=�`� b1-1 = _ ;I = _ '� ` W/2 EACH 2" 5M MGV'S - ,9i IRl I f 1 e. r --- 18" TALL a ili DSA 4 "5MX4 "3M -3 "TALL 4" 3M WELLHEAD I ti G / r i Se 1 5wA-9 (7,4 4.-Vt 83" TOTAL HEIGHT FOR COMPONENTS ADD 1 " -2" FOR RING GASKETS = "'84 " -85" TALL STACKUP Page l of l • Schwartz, Guy L (DOA) From: Barbee, Marcus G (Swift Technical Services LLC) [Marcus.G. Barbee @contractor.conocophillips.com] Sent: Wednesday, January 30, 2013 2:45 PM To: Schwartz, Guy L (DOA) Subject: Tyonek Wells A -7 & 8 10-403 information Attachments: KOOMEY_CAD Unit Spec Sheet.pdf; Single Gate BOPE.pdf; TREE PROPOSAL2.pdf; CONOCO TYONEK 41N BOPE.pdf Mr. Schwartz , Here is a generic wellhead drawing of wells with 4 -1/2" production tubing on the Tyonek Platform. The trees are equipped with valves as follows: It is not 5000 psi equipment as indicated on the drawing. ryonek Well Manual Master Pneumatic Master k -7 WKM WKM 'roducer 4" 3000 4" 3000 Body: type 2 Body: type 2 Model: Stat -T -Seal gate valve Model: Stat -T -Seal gate vale Cast on body: Cast on body: F 203 K Y F 203 K Y k -$ FMC FMC 'roducer 4 FE 3000 # Size: 4 1/16 3000 Body: 60 -90 Body: API -60K Model: 20 Model: 120 Trim: Type:B Gate: Gate: SS -1 We have located (2) 15M, 4.06" Bowen single gate BOPE's to be dressed with 1.900" inserts (slips & pipes) along with a Koomey unit from GE oil and Gas. All of the information given to me from my vendors is attached pertaining to the single gate BOPE and the Koomey Unit. Please let me know if you require any additional information. The Crane inspection reports did not scan well and are in hard copy format headed your way via currier. Our plans are to start with well A -08. Thank you, ilaicu' [3arb Wells Engineer ConocoPhillips Alaska, Inc. 1 -907- 265 -6932 O. 1- 907 -250 -1163 C. This transmission may contain information that is privileged, confidential and / or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, or use of the information contained herein (including any reliance therein) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether in electronic or hard copy format. Thank You. 1/31/2013 STATE OF ALASKA (" "~ ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation Shutdown~ Pull Tubing X 2. Name of Operator: Phillips Petroleum Co. 3. Address: P.O. Box 1967 Houston, Texas 77251-1967 Stimulate Plugging __ Alter Casing Repair Well Perorate X Other 5. Type of Well Development __ __ Exploratory Stratigraphic Service 6. Datum elevation (DF or RKB) RKB 1 16 Feet 7. Unit or Property Name North Cook Inlet Unit Location of well at surface: 1249' FNL & 1084' FWL Sec6-T1 At top of productive interval: 2292' FSL & 1426' FWL Sec 6 - T1 At effective depth: 2292' FSL & 1426' FWL Sec 6 - T1 At total depth: 785' FSL & 1719' FWL Sec6- T1 Leg 3, Slot 8 PPCo. Tyonek Platform 1N - R9W North Cook Inlet, Ak. 4402' MD 3850' TVD 1N - R9W 4402' MD 3850' TVD 1 N - R9W 7050' MD 6012' TVD 1N - R9W 8. Well Number A-07 9. Permit Number / Approval Number 69-58 94-128 10. APl Number 50-283-20027 11. Field / Pool Cook Inlet / Beluga Present well condition summary: Total Depth: measured true vertical Effective Depth: measured true vertical 8,126 feet Plugs (measured) 6,920 feet 4,406 feet Junk (measured) 3,853 feet PBTD 7,050' ORIGINAL Casing: Structural Conductor Surface Intermediate Production Liner Length Size Cemented Measured Depth True Vertical Depth 30 " Driven 388 388 10 3/4" 1145 sx CI "G 7" 1285 sx CI "G 2,522 2,356 8,108 6,920 Perforation Depth: measured 4406' - 6916' true vertical 3853' - 5902' Tubing (size, grade and measured depth) Packers and SSSV ( type and measured depth) 4 1/2" 12.6 Ib/ft J-55 Mod BT&C Tubing 39-287' 4 1/2" 12.75 Ib/ft J-55 Mod 8rd Tubing 287-5129' 4 1/2" 12.75 Ib/ft J-55 8rd Tubing 5129-6920' Halliburton "XXO" SVLN at 285', Halliburton "VSR" packer at 4300' Halliburton "TWR" packers at 4605', 4724', 4862', 4943', 5116' 13. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment description including volumes used and final pressure: 14. Representative Daily Average Production or Injection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Prior to well operation: 0 5000 0.36 185 RECEIVED jAN 2 7 1995 A!a$~ 0il & Gas Cons. C0mmissi0r Tubing Pressure 909 04/06/94 Subsequent to operation 0 14200 6.64 565 96O 12/O4/94 15. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations 16. Status of Well Classification as: X Oil__ Gas X Suspended Service 15. I hereby certify that the foregoing is true and correct to the best of my knowledge: Signed '~' ~- '~,~~ Title Principle Engineer Form 10-404 Rev. 06/15/88 Date 19-Jan-95 SUB'MIT IN DUPLICATE PHILLIPS PETROLE~ DAILY REPORT SUMMARY PAGE:I WELL:North Cook Inlet Unit No. ~-7 RIG:Pool Arctic Alaska/Pool Arctic Alaska FIELD: COOK INLET NORTH AFE$: P-V193 CNTY/STATE: TYONEK OFFSHORE/ALASKA AUTH COST: $1,486,000 DATE DEPTH RPT NO Hid OPERATIONS SUN4ARY DALLY COST CWI COST WENT TYP~ ~ WOrkover 06119194 8,126 06120194 8,126 2 8.5 FINISHED JETTING IN A-I/SKIDDED RIG TO A-?/PROCEEDED WiTH KILLING A'? 3 8.5 FINISHED LUBRICATING FLUID INTO W~LL/PULL DHSV/SET DEEP PLUG SET BPV/ND TREE/NU BOP'S 06/21/94 8,126 & 8.6 S37,646 $37,6~6 S32,088 $69,7'34 S50,000 $119,734 06/22/94 8,126 5 8.6 FINISHED TESTING BOP'S/PULLED WL PLUG/PULLED PACKER FREE/ CIRCULATED OUT GAS/POOH LAYING DM TUBING/RIH WITH BIT & SCRAPER/DRILL OUT SAND BRIDGE/CIRC OUT SANE CLEAN SAND OUT OF WELL DM TO 7050' .PUMP SWEEPS.CBU.TOH. SLH.SAFETY & PRE-JOB SAFETY HEETING.P/U & 5/8" TCP GUNS I,// 22.1' Git DP CHARGES TO PERF BELUGA SANDS 5581'' TO 6916'. S36,843 $156,5T7' 06/23/94 8,126 6 8.6 P/U TCP GUNS & TEST TOOLS.TIH.CORRELATE.R/U TEST EQUIP.RE- PERFORATE BELUGA SANDS 5587-6916.FLOU FOR CLEANUP.KILL WELL. TOH.PACKER I 280.CIRCULATE,LUBRICATE & BLEED GAS IN ANNULUS. $49,725 S206,301 06/24/94 8,126 7 8.9 LUBRICATE OUT GAS FROH ANNULUS.L/D TCP GUNS.TIH.CIRCULATE SEVERE GAS CUT HIJD AT 1665,5600,1,050.08SERVE.CBU.SEVERE GAS CUT FROg BELUGA.RAISE gT TO 8.9#.CBU.SHORT TRIP.CBU.OK.TOH. $41 , 522 $247,823 06/25/94 8,126 8 8.9 06/26/94 8,126 9 8.9 TON W/BIT & SCRAPER.P/U TAILPIPE & PKR.TIH.DISPLACE STRING W/N2.SET PKR I 5573.TAILPIPE ~ 6924.BLEED OFF N2.WELL DEAD. R/U COILED TBG.JET WELL IN.R/D TBG.R/U TEST TREE.DST #2. FINISH DST #2 (BELUGA INTERVAL).KILL WELL.CBU.OBSERVE.CBU. L/D TEST TREE.TOH.P/U EZSV.TIH & SET G 5031.TOH.P/U TEST TOOLS & TIH.DST # 3 C-8/NOVE PKR.DST # 4 C-7 & C-8 $63,359 $311,182 S3~,156 S345,338 06/27/94 8,126 10 8.9 DRILL STEM TESTING COOK INLET SANDS FROg THE BOTTOM UP. DST II~ THRU #8. TESTING ZONES C1'8 TO C1'3 FROg 49?0' TO 4624'. $229,968 S575,306 06/28/94 8,126 11 8.9 DST #8(CI-3 TO CI-8).DST #9(Cl-2 TO CI-8).SHUT IN.R/D TEST EQUIP.SHEAR IPO.KILL WELL.TOH.L/D TEST TOOLS.MEEKLY BOP TEST SAFETY HTG.P/U PERF GUNS TO RE-PERF COOK INLET SANDS.TIH. $46,402 $621,708 06/29/94 8,126 12 8.8 CORRELATE GUNS TO DEPTH.PERF CI-1 TO C1-8.FLOg FOR CLEANUP. KILL IdELL. TOH.L/D GUNS.TIH W/BIT & SCRAPER.CBU.TOH.P/U EZSV TIH.SET ~ 49&2.TOH.P/U TEST TOOLS.TIH. $171,197 S792,905 06/30/94 8,126 13 8.8 TIH FOR DST 11.R/U TEST TOOLS.DST 11.WELL DEAD.R/D TEST TREE R/U COILED TBG.JET H20 FROg TEST STRING(52.5 BBLS)~ELL DEAD. R/D TBG.KILL WELL.TOH.L/D TOOLS.TIH TO SET EZSV AT 6869. S54,817 S847,722 01,/01/94 8,126 14 8.9 SET EZSV a/~B69.TOH.TIH FOR DST # 12 (CI-6).DST # 12.CLOSE TOOL.HOVE PKR TO 6727 FOR DST # 13 (CI-6 & CI-7).DST # 13. S38,61,0 $886,392 $31,31'4 S917,766 01'/02/94 8,126 15 8.8 DST 13(CI-5 & CI-6).KILL WELL.TOH.L/D TEST TOOLS.P/U EZSV & TIH.SET g6721'.TOH.PU TEST TOOLS.TIH.DST 16.CI-6.NOVE PKR.DST 15.CI-3 & CI-6).HOVE PKR.DST16.CI-2,3,6.CLOSE TOOL.CBU g ·PO 01'/03/94 8,126 16 8.8 CIRC OUT GAS.TOH.L/D TEST TOOLS.TIH W/BIT & JUNK BASKETS. DRL EZSV ~ 6727.DRL EZSV g 6869.DRL EZSV g 6962.CLEAN OUT TO 5018.SUEEP & CBU.TOH.TIH.CLEAN OUT 5018-5031.DRILL EZSVgS031 S87,576 S1,005,340 07/04/94 8,126 17 8.8 DRLG EZSV ~5031.ClRC GAS AS NEEDED.TZH TO 7050.CBU.CUT LINE. TOH.TIH W/BIT & SCRAPER TO 7050.CBU.TOH.P/U TCP GUNS TO PERF CI-9(5053-5072).TIH.CORRELATION LOG.PERFORATE.CLEANUP FLO~. $45,600 $1,050,939 07/05/94 8,126 07/06/96 18 8.8 CLEANUP FLOg FROg CI-9.FILL PIPE.SHEAR IPO.KILL WELL.TOH.L/D GUNS & TOOLS.TIH TO ?050.CBU.TOH.P/U 6 1/2" TAILPIPE & PKR ASSEMBLY #1.TIH.SET TOP OF PACKER AT 5116.TAILPIPE g 6926'. $66,633 $1,141,188 8,126 19 8.8 SET PACKER ASSEMBLIES # 2, 3, 4, & 5. $46,818 S1,162,390 07/07/94 07/08/94 10/30/94 8,126 20 8.8 SET PACKER ASSEMBLIES # 5 & 6, RUN REMAINING COMPLETION TO SURFACE,SET BPV, ND BOP'S, $86,794 Sl,272,800 8,126 8,126 21 8.8 FINISHED ND BOP'S/NU TREE/JETTED IN WELL/FLOWED FOR CLEAN UP RELEASED TO PROOUCTION/***NOTE*W*FINAL REPORT*** $275,904 $1,548,703 $2,100 $1,550,80~" 22 8.8 TIH W/GUAGE RING & SHIFTING TOOL CHECKING SLEEVES. ALL SLEEVES WERE CLOSED. BELUGA ZONE PRODUCING. TURN WELL TO PRODUCTION FLOUING. DAYSLM.RP1 12/07/96 FINAL WELL COMPLETION'. ;I/AM PBTD 7050' TOC {~ 2510 2522 Otis VSR packer ~ 430(7 Cook Inlet Sands 4406-4476 1 4494-4574 2 4624-4634 3 4651-4701 4 packer ~ 4724 4746-4786 5 4831-4841 6 packer ~ 4862 4878-4903 7 packer (~ 4943 4963 - 497O 8 5053- 5072 ** 9 packer (~ 5116 Beluga Sands 5587 -5592 5628-5633 5901-5906 597O-5'395 6180-6185 6193-6203 6223-6243 6254-6279 6340-6347 6.566-6571 6584-6591 6746-6753 6891-6916 FMC OCT FMC 6" 3M 4 ]/2" 8r4 X 41/2" wr&c Deck: RKB-Th~: 39.40 RKB-SL: 116.00 RKB-ML: Ann_u!m Fluid: 8.5 lb/gal KCL Completion Fluid with 30 % Glycol TOC: 2510' from CBL dated 06/20/69 WATER DEPTH: 120 ' Production Casing: 30" 41 388 10 3/4" 41 2,522 7" 39 79 7" 79 7,100 7" 7,100 8,108 StrinI 4 1/2" 39 287 4 1/2" 287 5,129 4 1/2" 5,129 6,920 42 0.00 39.40 & 51 Ib/fl J-55 BT&C 3350 1970 26 Ib/fl J-55 BT&C 4660 4080 23 lb/fl J-55 BT&C 4080 3080 26 lb/fl J-55 BT&C 4660 4080 12.60 lb/it L-80 Mod BT&C 4730 4980 12.75 lb/it J-55 Mod EUE 8rd 4730 4980 12.75 lb/it J-55 EUE 8rd 4730 4980 PRODUCTION TUBING STRING Elevation 41 39.40 0.60 FMC ./OCT6" 3M 4 1/2" 8rd x 4 1/2" BTC Tbg. 3.958 3.992 40 40,00 245.28 39 285.28 2.42 38 287.70 4041.56 37 4329.26 1.43 36 4330.69 31.27 4 1/2" BTC-MOD J-55 8rd Tubing & Pup Jts. burton '9(XO" SVLN 3.813 1/2" EUE-MOD J-55 8rd Tubing & BTC-MOD X/O 3.992 iburton "X" Nipple 3.813 4 1/2" EUE-MOD J-55 8rd Tubing 3.992 3.992 3.992 3.880 3.992 3.813 3.992 3.992 4.000 35 4361.96 8.08 Halliburton Upper "PBR" 34 2.83 Ratch Latch Seal Unit 33 4371.31 6.52 Halliburton "VSR" Packer 32 4377.83 213.18 4 1/2" EUE-MOD J-55 8rd Tubing 31 4591.01 4.22 Halliburton "XD" Sliding Sleeve 30 4595.23 10.08 4 1/2" EUE-MOD J-55 8rd Pup Jt. 29 4605.31 2.60 Halliburton No-Go Locator 28 4605.97 10.14 Halliburton "TWR" Packer & Mill Out Extension 27 4616.11 94.51 26 4710.62 4.22 25 4714.84 8.09 24 4722.93 2.60 23 4724.03 12.75 22 4736.78 111.97 21 4848.75 4.22 20 4852.97 8.08 19 4861.05 2.60 18: 4862.15 11.28 17~ 4873.43 69.33 16 4942.76 2.60 15 4943.86 12.75 14 4956.61 123.63 4 1/2" EUE-MOD J-55 8rd Tubing & Box x Halliburton "XD" Sliding Sleeve 4 1/2" EUE-MOD J-55 8rd Pup JL 3.992; 3.813i 3.992 3.992 Halliburton No-Go Seal Unit Halliburton "FWR" Packer & Mill Out Extension 4.000 1/2" ED'E-MOD J-55 8rd Tubing & Dbl. Pin X-Over 3.992 Halliburton "XD" Sliding Sleeve 3.813 4 1/2" EUE-MOD J-55 8rd Pup JL 3.992 No-Go Seal Unit 3.950 '"TWR" Packer & Mill Out Extension 4.000 4 1/2" EUE-MOD J-55 8rd Tubing & Dbl. Pin X-Over 3.992 Seal Unit 3.950 '"rWR" Packer & Mill Out Extension 4.000 1/2" EUE-MOD J-55 8rd Tubing & Dbl. Pin X-Over 3.992 13 5080.24 12 5084.46 4.22 Halliburton '~Ltt" Sliding Sleeve 31.27 1/2" EUE-MOD J-55 8rd Tubing 11 5115.73 2.60 Ratch Latch Seal Unit 3.813 3.992 3.950 10 5116.83 12.75 Halliburton '"TWR" Packer & Mill Out Extension 4.000 9 5129.58 470.98 4 1/2" EUE J-55 8rd Tubing & Dbl. PinX-Over 3.992 8 5600.56 4.22 Halliburton ',XD" Sliding Sleeve 3.813 7 5604.78 689.38 4 1/2" EUE J-55 8rd Tubing 3.992 6 6294.16 4.22 Halliburton "XD" Sliding Sleeve 3.813 5 6298.38 594.16 1/2" EUE J-55 8rd Tubing 3.992 4 6892.54 1.50 Halliburton "XN" Landing Nipple 3.725 3 6894.04 31.31 4 1/2" EUE J-55 8rd Tubing 3.992 2 6925.35 0.65 Wireline Re-entry Guide 3.992 I 6920.00 6926.00 End of Tubing PRODUCTION PERFORATION INTERVALS COOK INLET SANDS "M iddle" BELUGA SAND (cont.) C1-1 4406-4476 5901-5906 ci-2 44-_CUl-4574 5970-5995 CI-3 4624-4634 6058-6068 Cl-4 4651-4701 6180-6185 CI-5 4746-4786 6193-6203 Cl-6 4831-4841 6223-6243 L,L,! CI-7 4878-4903 6254-6279 CI-8 4963-4970 6285-b'290 Cl-9 5053-5072 6340-6347 LLLE BELUGA SAND ~ 6566-~71 "Uppe~" 5587-5592 ~1 5628-5633 6638-6648 5645-5655 6746-6753 ** New Perforations 6891-6916 TD = 8,126' 7" (~ 8108' PBTD: 7050' [Supv: lTbg Wt: 4 1/2" - 12.6 & 12.75 lb/it Well: North Cook Inlet Unit No. A-07 ] Location: Lower Cook Inlet, Alaska Field: Cook Inlet Unit November2,1994 MPG MEMORANDU State o Alaska Alaska Oil and Gas Conservation Commission TO: · David Jo~ Chairman DATE: June 27, 1994 THRU: Blair Wondzell,~-f.~ FILE NO: P. I. Supervisor ~'=~/~ FROM: ~'~u Grimaldi, SUBJECT: Petroleum Inspector AX8JF1BD.doc BOP Test Pool rig # 429 North Cook Inlet Unit PTD #69-58/Sundry #94-128 Monday,June 27, 1994: I traveled to Phillips Tyonek platform to witness the weekly BOP test on Pool rig #429 which is presently working over well # A-7. The rig was not quite ready when I arrived. I made a cursory tour of the platform and randomly checked the SVS systems, I found all to be operational and appearing to be in good condition. The test once started went very well with all components functioning properly and holding its pressure test. The test lasted 2 hours. Tom Covington (Pool Toolpusher) provided a good test of the BOPE. I found the overall condition of the platform and rig to be in good shape. Summary: I witnessed the weekly BOP test on Phillips Tyonek platform. Test time two hours. No failures. Attachment: AX8JF1BD.XLS cc: Walt Carrico (Phillips Drlg. supt.) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE TeM Report OPERATION: Drlg: Drlg Contractor: Pool Arctic Operator: Phillips Well Name: A-07 Casing Size: Test: Initial Workover: X DATE: Rig No. 428 PTD # 69-58 Rig Ph.# Rep.: Lydsey Lyons Rig Rep.: Tom Covin~on Set~ Location: Sec. 6 T. 11N R. Weekly X Other 6/27/94 776-6074 9W Meridian Seward TEST DATA MISC. INSPECTIONS: LocalJon Gen.: OK Housekeeping: OK (Gen) Reserve Pit N/AJ Well Sign OK Drl. Rig OK BOP STACK: Quan. Annular Preventer 1 Pipe Rams 1 Pipe Rams 1 Blind Rams 1 Choke Ln. Valves 1 HCR Valves 1 Kill Line Valves 1 Check Valve N/A Test Pressure 150/3000 150~3000 150~3000 150/3000 15O/3000 450/3000 150/3000 N/A P/F P P P P P P P N/AI MUD SYSTEM: Visual Alarm Trip Tank P P Pit Level Indicators P P Flow Indicator ' P"' P Gas Detectors P P FLOOR SAFETY VALVES: Quan. Upper Kelly / IBOP 0 Lower Kelly / IBOP 0 Ball Type 1 Inside BOP I Pressure P/F 150/3000 P 150/3000 P 150/3000 P 150/3000 P CHOKE MANIFOLD: No. Valves 16 No. Flanges 42 Manual Chokes 1 Hydraulic Chokes 2 Test Pressure 150~3000 150~3000 P/F P P P P ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure System Pressure Attained Blind Switch Covers: Master: Nitgn. Btl's: Six Bottles 2250 Average 3,000 I P 1,500 P minutes 13 sec. 2 minutes 15 sec. , ,, OK Remote: OK Psig. TEST RESULTS ...... ' .: :.:~;:~:! i , Number of Failures: 0 ,Test Time: 2 Hours. Number of valves tested" 26 RePair or Replacement of Failed Equipment will be made within N/A days. Notify the inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax N~. 276-7542 Inspector North Slope Pager No. 659-3607 or 3687 if your call is not returned by the inspector within 12 hours please contact the P. I. Supervisor at 279-1433 REMARKS: Good Test. , .Distribution: orig-Well File c - Oper./Rig c - Database c - Trip Rpt File c -Inspector FI-021L (Rev. 2/93) STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: W(messed By: AX8JF1BD.XLS Louis R Grimaldi PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 EXPLORATION AND PRODUCTION GROUP COMPANY BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING May 16. 1994 North Cook Inlet Unit "A-07" Phillips Tyonek Platform "A" North Cook Inlet, Alaska Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: North Cook Inlet Unit A-7 Workover Program Attached are three copies of the Application for Sundry Approvals, form 10-403, and three copies of the tentative workover program for the workover of the A-07 well on the North Cook Inlet Unit. Included in the program are the BOP schematic and the well control policy for the workover. If you have any questions concerning this workover or need any additional information please contact Paul R. Dean at (713) 669-3502. D. C. Gill, Manager Drilling and Production Engineering CC: A. R. Lyons M. L. Jones (r) P._R~ Dean J.F. Mitchell Central files ~¥ 1 8 1994 Gas Cons. C0mmissio~" Anchorage 1. Type of Request: Abandon Suspend ~ Alter Casing __Repair Well Chan~e Approved Pro~lram 2. Name of Operator: Phillips Petroleum Co. 3. Address: 6330 W. Loop South Bellairer Texas 77401 4. Location of well at surface: 1249' FNL & 1084' FWL At top of productive interval: 2292' FSL & 1426' FWL At effective depth: 2292' FSL & 1426' FWL At total depth: 212' FSL & 1777' FWL Sec 6 - T11N - R9W 12'i" Present well condition summary: Total Depth: measured 8,126 feet true vertical 6,920 feet STATE OF ALASKA ~/~, ALASKA OIL AND GAS CONSERVATION COMMISSION "' APPLICATION FOR SUNDRY APPROVALS Exploratory Strafigraphic Service Leg 3, Slot 8 PPCo. Tyonek Platform Sec 6 - T11N - R9W North Cook Inlet, Ak. 4402' MD 3850' TVD Sec 6 - T11N - R9W 4402' MD 3850' TVD Sec 6 - T11N - R9W Operation Shutdown Plugging Time Extension . Pull Tubin~ ~1( Variance 5. Type of Well Development ~ Reenter Suspended Well ~ Stimulate Perforate X Other 6. Datum elevation (DF or RKB) RKB 116 Feet 7. Unit or Property Name North Cook Inlet Unit 8. Well Number A-07 9. Permit Number / Approval Number 10. APl Number 50-~83-20027 11. Field / Pool Cook Inlet/Beluga Plugs (measured) Effective Depth: measured 4,402 feet Junk (measured) true vertical 3,850 feet Casing: Structural Conductor Surface Intermediate Production Liner Length Size Cemented Measured Depth True Vertical Depth 30" Driven 388 388 10 3/4" 1145 sx Cl "G" 2,522 2,356 7" 1285 sx Cl "G" 8,108 Perforation Depth: measured 4402' - 6918' REC ED MAY 1 8 1994 true vertical 3850' - 5904' Alaska Uti & Gas Cons, Commissiop Tubing (size, grade and measured depth) 4" 10.9 Ib/ft J-55 BT&C & 3 1/2" 9.2 Ib/f~l~-~ag~q'&C set at 4,060'. Packers and SSSV ( type and measured depth) Otis "RH" retrievable packer @ 4,015' Otis Wireline Retrievable SSSV ~ 288.61 '. 13. Attachments: Description Summary of Proposal .~ Detailed Operations Program m 14. Estimated Date for Commencing Operations: June 15r 1994 , 16. If Proposal was Verbally Approved: 15. Status of Well Classification as: BOP Sketch ..~ Oil __ Gas ~ Suspended Name of Approver 17. I herebycert~he Signed Conditions of Approval: Plug Integrity Mechanical Integrity Test Date Approved Service ,, cringing is true and correct to the best of my knowledge: ~ D.C. Gill Title Drip. & Prod. En~r. Manager DateS~, FOR COMMISSION USE ONLY Notify Commission so Representative may witness I Approval No. BOP Test Location Clearance ..... I Subsequent Form Required 10 - Approved b~/Order of the Commission Form 10-403 Rev. 06/15/88 Original Signed By David W. Johnston Commissioner Date ~"//J~ ~/~4/ Approved Copy SUBMIT IN TRIPLId'ATE Returned May 16, 1994 Houston, Texas North Cook Inlet Unit "A"-7 North Cook Inlet Unit Tyonek County, Alaska Tentative Procedure ® · · · · Skid rig over No. 8 slot in Leg 3. Kill well with 8.5 lb/gal KCl water / XanVis polymer. Fill tubing and annulus with 2 % kcl water. Bleed off pressures and monitor same. Close SSSV. Install BPV, remove XMAS tree, NU and test 13 5/8" 10M BOP equipment. Utilize a 16 3/4" 5M x 13 5/8" 10M DSA (FMC Unihead with 16 3/4" 5M BX Clamp Hub). Test the BOP equipment as per the attached "Well Control" program. Rig up to pull tubing. Release Otis "RH" packer (4,015'). Pull 4" tubing, SSSV and retrievable packer with tailpipe. All tubing should come in one piece unless sanded in place. Inspect all tubulars for "NORM" contamination. TIH with 6 1/8" bit and casing scraper for 7" 23 and 26 lb/ft casing. Clean out casing to PBTD of 8054'. Circulate hole clean and POOH. Make up and TIH with tubing conveyed perforating assembly to reperforate the existing BelUga Sands as follows: 5590' - 5595' 5632' - 5637' 5648' - 5658' 5903' - 5908' 5973' - 5998' 6060' - 6070' 6182' - 6187' 6195' - 6205' 6225' - 6245' 6256' - 6281' 6287' - 6292' 6342' - 6349' 6497' - 6507' 6535' - 6550' - RECEIVED 6586' - 6593' 6640' - 6650' 6748' - 6755' MAY 1 8 1994 6 8 9 3 ' - 6 918 ' Ai~S~ Oil & Gas Cons. ~mmi~ion Anchor~e · · Use Gamma Ray log to correlate guns on depth. Set packer and pressure up on tubing with nitrogen to fire guns. Unload well and flow for initial clean-up. 8. Kill well and POOH with perforating assembly. · TIH with bit and scraper and clean out well to PBTD. gas until well is stable. Circulate out ~ 10. If significant volumes of water and/or sand is produced during Step No. 7, TIH with DST tools and isolate intervals to check for water production. Squeeze any interval that indicates it is water productive. 11. Make up and TIH with tubing conveyed perforating assembly to ~ reperforate the existing Cook Inlet Sands as follows: 4402' - 4472' 4490' - 4570' 4620' - 4630' 4647' - 4697' 4744' - 4784' 4830' - 4840' 4878' - 4903' 4963' - 4970' 12. Use Gamma Ray log to correlate guns on depth. Set packer and pressure up on tubing with nitrogen to fire guns. 13. Unload well and flow for initial clean-up. 14. Kill well and POOH with perforating assembly. 15. TIH with bit and scraper and clean out well to PBTD. Circulate out' gas until well is stable. 16. If significant volumes of water and/or sand is produced during Step No. 13, TIH with DST tools and isolate intervals to check for water production. Squeeze any interval that indicates it is water productive. 17. TIH with Halliburton 7" retrievable "VSR" packer with 4 1/2" tailpipe equipped as per the proposed wellbore schematic. Set packer at 4,300' with sliding sleeves at 4,350' and 5,400'. 18. Make up Halliburton packer seal assembly onto the 4 1/2" tubing. TIH with 4 1/2" tubing and SCSSV landing nipple. Land seal assembly into isolation paCker. Test annulus, then pull out of seal assembly and circulate 70/30 methanol / KCl packer fluid into annulus. Space out tubing. 19. Close SCSSV, install BPV, ND BOP equipment and NU and test 7 1/16" x 4 1/2" Xmas Tree. Remove BPV's. 20. Use coiled tubing (if necessary) and nitrogen to lower fluid level and get well kicked off. Unload well and allow clean up through the production testing equipment. Release workover rig to next well. NOTE: BHP at 3521 TVD is approx 1400 psi (7.6 lb/gal equivalent), somewhat less than the 8.5 lb/gal equivalent which will be used to kill the well during the recompletion phase. RECEIVED MAY ] 8 1994 AlaSka Oil & Gas Cons. Commiss~, Anchorage WELL CONTROL PROCEDURES This well is a category 3 well, as defined in Phillips Completion Workover and Well Control Policy. As such two barriers must be in place during nipple up and nipple down operations. For all other operations, two barriers, e.g. the BOP's, fluid column, etc. must be in place in order to conduct simultaneous operations. The BOP equipment is 10000 psi WP Class 4 as per Phillips Well Control manual. The bottom set of rams should be 5" pipe rams, the middle set will be blind rams and the top set should be variable rams. Although the BOP is rated to 10000 psi, the riser and the wellhead are rated to 5000 psi. The BOP and choke manifold should be stump tested to 3000 psi. The BOP should be tested to 3000 psi upon nipple up and to 1500 psi on a weekly basis. The Alaska Oil and Gas Conservation Commission (AOGCC) should be notified prior to conducting BOP tests. The notification to AOGCC should be made early enough for them to witness the test if they desire. The maximum surface pressure for the well is 1080 psi. This pressure was obtained during the welltest of February 10, 1994. The well can be killed and stability maintained with 8.5 lb/gal fluid. Well control drills are to be conducted with each crew as per Phillips well control manual. Drills should be reported on the IADC daily drilling report and on Phillips Daily Drilling Report. This well produces from a series of very permeable sands. A small decrease in pressure at the perforations can result in very large flowrates. It is vital that good well control practices be followed during the course of this workover. Trip speed while POOH should be kept relatively slow to avoid any tendency to swab. Before any trip is made swab and surge calculations should be made based on the properties of the fluid in the hole. DO NOT exceed the running speed determined by the calculations. A detailed trip book comparing measured fill up requirements to the calculated requirements should be maintained for each trip. The cause for any discrepency between the actual and required fill up volume must be determined before continuing with the trip. MAINTAINING CONTROL OF THE WELL IS OF THE UPMOST IMPORTANCE, TRIP SPEED IS SECONDARY. The perforated intervals are below the Otis "RH" retrievable packer, therefore, 27 different intervals between 3521' and 5910' TVD are effectively commingled at the present time and cannot be isolated. Ail of the zones presently perforated in this well can be killed with water. As a precautionary measure, a line should be ran from the annulus valves on the tubing head to supply workover fluid, drillwater, or seawater. This line can be used to supply workover fluid as discussed above or as a last resort can be used to kill the well with drillwater or seawater. Pumping drillwater or seawater through the annulus valves should be considered only in an emergency situation as these fluids could result in formation damage. R [ C [ i~ ~ ~ & Gas (;ohs. uommismo~, Anchorage NCIU A-"I RISER AND BOP ARRANGEMENT I I 6M ANNULAR PREVENTER I I I 1OM VARIABLE BORE PIPE RAMS 1OM BLIND RAMS DRILLING SPOOL 1/2' 1OM PIPE RAMS RISER 13 6/8' 1OM X 13 5/8' 6M ADAPTER 13 5/8' 6M X 16 3/4' 6M CLAMP RISER 16 3/4' 6M X 16 3/4' 6M UNIHEAD 16' 8RD X 16 3/4' 6M CLAMP HUB ~ /"~' EXISTING WELL COMPLETION DI~"~'~AM t BPV{~ ~ FMC OCT RKB-Drili Deck: Tb~.H~r. fMake,Type) FMC 6" 3M 4 1/2" 8rd x 4 1/2" BT&C RKB-THF 39.40 'SSV' Annulus Fluid: salt water with 3 bbi methanol RKB-SL: 116.00 388 TOC: 2510' from CBL dated 06/20/69 WATER DEPTH: 120 RKB-ML: Production Casing: 30" 41 388 10 3/4" 41 2,522 45.5 & 51 lb/f~ J-55 BT&C 3350 1970 531 7" 39 79 26 lb/ft J-55 BT&C 4660 4080 327 7" 79 7,100 23 lb/ft J-55 BT&C 4080 3080 288 7" 7,100 8,108 26 lb/ft J-55 BT&C 4660 4080 327 'GLM' Tubing String: 3 1/2" 4,029 4,059 9.3 lb/ftI J-55IIBT&C 5700 6440 :::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::::::::::::::::::::::::::::::::::::: ili::i!i!i::~tif::i?:~i~, ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::: i::::?::::::::: ::?: ::::::::::::::::::::::::::::::::: ~:: ::::::::::::::::::::::::::::::::: i TOC @ 2510 PRODUCTION TUBING STRING ::25~ 14 13 -0.00 39.40 Elevation 12 39.40 1.00 FMC / OCT 6" 3M 4 1/2" 8rd x 4" BT&C Tubing Hah 3.958 6.000 11 40.40 248.21 4" 10.9 lb/ft J-55 BT&C Tubing 2.992 4.500 10 288.61 4.00 Otis 3 1/2" NO Ball Valve Nipple and SCSSV 2.992 4.520 9 292.61 1210.72 4" 10.9 lb/ft J-55 BT&C Tubing 2.992 4.500 Otis RH packer 8 1503.33 3.00 CAMCO 3 1/2" GLM 2.992 4.500 ll~l @4015' 7 1506.33 2505.52 4" 10.91b/ft J-55 BT&C Tubing · x' 6 4011.85 1.07 4" BT&C x 3 1/2" X-OVER 2.992 4.500 5 4012.92 2.52 Otis Type "S" Latching Assembly 'O' 4 4015.44 13.22 Otis 7~ x 3" "RH" Hydraulic Set Retrievable Packer 2.992; 4.500 3 4028.66 1.00 Otis 3 1/2" "X" Nipple 2 4029.66 29.01 3 1/2" 9.3 lb/ft J-55 BT&C Tubing + Blast Joints 2.992 4.500 1 4058.67 1.21 Otis 3 1/2" "Q" Nipple 4059.88 End of Tubing Cook Inlet Sands 2.992 4.500 2.992 4.500 ~ 440~ - 4472 ~ 449O - 457O 2.992 4.500 ~ 4647 - 4~97 2.992 4.500 ~ 4744 - 4784 ~ 4630- 4840 .... ~tt t" I'~ 2.992 4.500 ~ 4876-490a D i=! l-lu I$ ~ 4~3- 4970 l\ I, x,, ~ a · ,.- - 2.992 4.500 : 2.992 3.500 : ] ~/~Y '1 ~" ,r~t~.~too.? 2.992 4.500 i JuU I~1 IUI ~ 5560 - 5595 ~ 5632 - 5637 PRODUCTION PERFORATION INTERVALS COOK INLET SANDS BELUGA SAND (cont.) ~ 5903 - 5908 ~ 5973 - 5998 'Middle' ~ 6060 - 6070 Cl-1 4402 - 4472 5903 - 5908 ~ 6182 - 6187 CI-2 4490 - 4570 5973 - 5998 ~ 6195 - 6205 CI-3 4620 - 4630 6060 - 6070 ~ 6225 - 6245 CI-4 4647 - 4697 6182 - 6187 ~ 6256 - 6281 CI-5 4744 - 4784 6195 - 6205 ~ 6287 - 6292 CI-6 4830 - 4840 6225 - 6245 ~ 6342 - 6349 CI-7 4878 - 4903 6256 - 6281 ~ 6497 - 6507 CI-8 4863 - 4970 6287 - 6292 ~ 6556 - 6573 BELUGA SAND 8497 - 6507 ~ 6586 - 6593 6535 - 6550 ~ 6640 - 6650 "Upped 6568 - 6573 ~ 6748 - 6755 5590 - 5595 6586 - 6593 5632 - 5637 6640 - 6650 5648 - 5658 6748 - 6755 'Lower' ~ 6893 - 6918 6893 - 6918 -- 3TD 8054' ~ 7" @ 8108' PBTD: 8,054' [ Supv: I Tbg Wt: 4" - 9.3 lb/ft Well: North Cook Inlet Unit No. A-07 I May 13, 1~94 TD 126' Location: 2ook Inlet Alaska Field: Cook Inlet Unit PRD TOC (~ 2510 2522 Otis RH packer @4300' Cook Inlet Sands 4402 - 4472 4490 - 4570 4620 - 4630 4647 - 4697 4744-4764 4830 - 4840 4878 - 4903 4963 - 4970 Beluga Sands 5590- 5595 5632-5637 5648- 5658 5903-5908 5973-5998 6060- 6070 6182-6187 6195 - 6205 6225- 6245 6256- 6281 6287-6292 6342-6349 6497- 6507 6535-6550 6568-6573 6586- 6593 6640-6650 6748-6755 6893- 6918 PROPOSED WELL COMPLET~II DIAGRAM PV(Make,T~pe,OD) FMC OCT [ FMC 6'31~/t -, 1/2' 8rd X 4 lt'2' BT&C Annnlus Fluid: salt water with 3 bbi methanol RKB-Drill Deck: RKB-THF 39.4O RKB-SL: 116.00 TOC: 2510' from CBL dated WATER DEPTH: 120 RKB-ML: Production Casing:. 41 388 41 39 79 79~ 39 4OO 45.5 & 51 J-55 J-55 BT&C 3350 1970 23 Ib/ft J-55 BT&C 4080 26 lb/ft J-55 BT&C 4660 4080 12.60 Ib/ft J-55 Mod BT&C 4730 4980 Mod EUE etd 4730 498O PRODUCTION TUBING STRING 0.00 39.40 Elevation 0.60 405.00 4299.00 4310.00 4300.00 10.00 30.00 4340.00 3.00 4343.00 5300.00 957.00 1615.00 1.00 6918.00 6919.00 1.00 FMC / OCT 6' 3M 4 1/2' 8rd x 4 1/2' BT&C Tubing Hanger 4 1/2" 12.6 lb/ft J-55 Mod BT&C Tubing Otis 4 1/2" SC. KSV Landing Nipple X-Over 4 1/2" BT&C to 4 1/2" MOd EUE 8rd 4 1/2" 12.6 Ib/ft J-55 MOd EUE 8rd Tubing Otis "X" Landing Nipple Otis "RIP Hydraulic Set Retrievable Packer 4 1/2" 12.6 Ib/ft J-55 MOd EUE 8rd Tubing Otis 4 1/2" "XA" Sliding Sleeve 4 1/2" 12.6 lb/It J-55 Mod EUE 8rd Tubing Otis 4 1/2" "XD" Sliding Sleeve 4 1/2" 12.6 lb/ft J-55 Mod EUE 8rd Tubing Otis 4 1/2" "X_N" Nipple Wireline Reentry Guide End of Tubing i EC !VCu 3.958 3.958 3.958 PRODUCTION PERFORATION INTERVALS COOK INLET SANDS CI- 1 4402 - 4472 CI-2 4490 - 457O 01-3 4620 - 4630 CI-4 4647 - 4697 CI-5 4744 - 4764 CI-6 4830 - 4840 CI-7 4878 - 4903 CI-8 4963 - 4970 BELUGA SAND 'Upped 5590- 5595 5632-5637 5648 - 5656 'Middle' 'Lowed BELUGA SAND (cont.) 5903 - 5908 5973-5998 6060 - 6070 6182- 6187 6195 - 6205 6225 - 6245 6256 - 6281 6287-6292 6342-6349 6497-6507 6535 - 6550 6568- 6573 6586- 6593 6640-6650 6748 - 6755 6893 - 6918 7"@ 8108' Well: [ Supv:. I Tbg Wt: 4" - 9.3 lb/ft North Cook Inlet Unit No. A-07 I May 13, 1994 Field: Cook Inlet Unit PRD Fo rrr~ 10-403 REV. 1-10~73 Submit "1 ntentions" in Triplicate & "Subsequent Reports" in Duplicate STATE OF ALASKA 0IL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT--" for such proposals.) OiL I--'1 GAS ~ WELLL..J WELL OTHER ~, NAME OF OPERATOR Phillips Petroleum Company- 3. ADDRESS OF OPERATOR P.O. DraVer 66 / Kenai, Alaska 99611 4. LOCATION OF WELL Atsurface Leg 3, Slot 8, 1249.' FNL, 1084' .FWL, Sec. 6, TllN, Rgw, S.M. BHL 212' ~BL, 1777' FWL, Sec. 6, T112~I, Rgb, S.M'. 13. ELEVATIONS (Show whether DF, RT, GR, etc.) 14. CheCk Appropriate Box To Indicate Nature of Notice, Re 5. APl NUMERICAL CODE 50-2 83~20027. 6. LEASE DESIGNATION AND SERIAL NO. ADL~17589 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 8. UNIT, FARM OR LEASE NAME NRTU 9. WELL NO. A---7 10. FIELD AND POOL, OR WILDCAT N~rth ~nn~ THlet, 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) See Item 4 AHL 12. PERMIT NO. 6~-58 )ort, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF ~ PULL OR ALTER CASING FRACTURE TREAT MULTIPLE COMPLETE SHOOT OR ACIDIZE ABANDON* REPAIR WELL CHANGE PLANS (Other) Cle au out SUBSEQUENT REPORT OF: WATER SHUT-OFF ~ REPAI RING WELL FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report results of multiple completion on Well Completion or Recompletion Report and I_og form.) DESCRIBE.PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. 1. Rig up. Kill well with. 10.0 ppg mud. Remove tree. Install 12"-3000# WP riser and 12" 3000# WP double gate preVentor and Hydril., Test BOP and riser, 2. Pull 4" tbg and retrievable packer, 3. Clean out to 8054 PBTD. 4, Run combination 4 '" x 3 1/2" tuhi.ng string ~i.tk Otis. suhsurface safety valve set about 290' RKB and Otis retrievable packer s:et about 4300 MD RKB and tubing set 6926' MD RKB. 5. Install tree and displace mud ~ith ~ater. Set hydraulic packer. Test packoff. 6. -Clean ~p well and conduct 4 point BrPT. 7. Utilize as a producer commingled in Cook. Inlet and Beluga pays. Estimated start of Operations is 9/9/75. 16. , hereby certl~/~a.t th:~d~~ is true and correct ~ ;N. E. Porter Senior Petroleum EnMi.ne~roATE . 7!15/75 TITLE (Tt~s space for State office use) APPROVED BY CONDITIONS OF APPROVAL, IF ANY'. T IT LE DATE See Instructions On Reverse Side Form · HLB · SUBMIT IN DUPLICATE* STATE OF ALASKA (See otherin-1 TRM structions on reverse side ] 5. APl NUIVEF.~CAJ~ CODE OIL AND GAS COHSERV~qH~.~COM ,TTEE WELL COMPLETION OR RECOMPLET~O~'REPORT AND LOG * la. TYPE OF WELL: ozI, F'] UAS · b. TYPE OF COMPLETION: 99 NEW [EWOR, E3 DEE,-E3 ,L~ RACK ~ EN WELL OVER ( 2. NAME OF OPERATOR ,'~. ADDRESS OF OPERATOR 4. LOCATION OF WELL (.~ep~'t ]OCGt{O~ C~e~Z~-G~d ~ GCCO~d~Oe ~ ~ ~ requirements)* $.M.~ Ne~h C~k ~et, P~tfem"~~,, ~ ' At top prod. laterval report~ below ~ ~'~ l-, o .. See, 6.- T~, R~. $.M. ............ ~ ..... ...- --..~ -u~ ..,. .,, ,.. ~-_...?...~ ..:,.~:::~-. ..... :,::¥~'~:: . .:'. :' .. 6~-58 18. T~ D~H .~ & TVD[9. :PLUG. :~CK MD & ~. ~ ~LT~ ~L., ' ': J 21. ;" .~: INTERVALS' DRILLED BY ~l. ~E ~C~C ~D OT~ ~S~UH- ' ? , ~; - - ~ :' ~ C~G ~ (Re~ all strl~s set in ~I1) " " ' ' '" ' , : CA~G SIZE HO~ S~E HO~ PULL~ · i I--j LINER ILECO~D [. ' 27. TUBING REOOP~D SIZE TOP (1VID) BOTTOM (MD) SACKg, CEMENT* SC'REE~ (MD) ~IZE . . (Mb)-, PACKER BET (MD) 28,' OPEN TO (Interval, size sEE PER~,"~NO & SO.~ I~O01H) ATTA0iiED ;~0. C '~ ~ PI%ODUCTION ;: . : -, DATE FIRST PRODUCTION J ~OD~CTION ME'I'IfO9 (Flow~, gas hit, pump~g--size and type o/.p~p) . [~-E~L' STArt ('~oduc~.:or ~. [ .-, '. [~-~OU~ ~ ;I I / e ' ,, I - I I I 1 31. mSPOS~TWS Or O~S (~0l~, b~e~ ~0~ 7~el, ~e~te~, etc.) J TEST WITNESSED BY Shut-~ · ~,a~e~ Ra~. A. ~lue~e ~d ~oia ~s. ~33. I hereby c~y}that the tforeg0t~g a~ attached information Is complete and correct as determined from alFavailable records /L~ ~ .... ~~'/~~__'~ Dist~ct .fioe ~er Au~st 28, 1969 SIGNED ~' ~ ~/~~ TITLE ..... DATE , *(see Instructions and S~ces tor AdditiOnal Data on ReVerse Side) INSTRUCTIONS General: This form is designed for submitting ~ complete and correct well complet}on report and log "' f.~ all types of lands and leases inr~l'aska. r~ L~ Item:'~ 16: Indicatd.'which elevation is used as reference (Where not ot-h~ise sho~h) for de'th measur~ ';: ':~ ~ ments'given in ~'~r spaces on fthis form and in any attachments. ~ ~ c -: '"· -' '~ Items 20, ~nd22:: If this well is completed ~or~eporatc production from more thb'n one ~erval zon~. ~..~ -r.~ : .. (multiple c0"m~leti~h), s'~ state in item 20, ~'h~) in item 22 show the producing ~terval, ~. interval~. ~.~ 1 "~ 'top(s), bottom(s) an'8'"name (s) 0,~ any)for o~ ~e interval reported in item 30. Su~mit a separate re~r.t ..~'~ c' '. (page) on this form,':adequatel~jdentified, for each additional inte, val to lng the a~itioaal data pertinent to such in'tercel ...... '., :.,) . Item26: "Sacks Cement": Attached supp~em~r~ records for th'is well ..should show the details of any mul-" -~ ,~ tiple stage cementing and the location of the, cementing t~l.~ '' c, ~Nem 28: Submit a separate complehon re~rt on this form f~ each interval to ~ separably produ~. (~ . ~-. ' ,~ ~ instruction for items 20 arid 22 above),c~ / ~ . J .. .. SUMl~"j~Ry OF P[ORMATION TESTS INCLUDIN(; INT£RV~L TESTED. P~URE D~ ~ ~OV~'.OF OIL. G~, ~ 35.~ O~GIC M~RK~ , WA~ AND MUD ~ I ) . ,, ~ ~ , ?" ~pper Ceok I~et ', ~-9 ' ' , CO , , .: -'- .l.:,:i: ~:: ~ -~ o I.,.~ ~ : · _ ~ · (' r'. ~ j , · ,, , _ [..~ ~<~ ~ ) .. DATA. AaWACII BRieF D~CRIPI~O~S OF LITHOLOGY. POROSITYI FRAC~R~J APp~T DIPS I',' '. AND DE'FEC~EI) SllOWS OF OIL. G~ OR ~ ; ' --~' r- - ] ~ 'r.k . . ~ , ~ ~ ~ , , ] ~ ~ ~ -~ . , , . : ' ' . ./:[ / ~ C] ~'~ ~. ~3 0 c'- ~ , ~ ) . ~ , ~ - . j..-q j~ ~ ..~ (~ .- : ~ ·-; -J- r',~ ' . . 'l'- ~ ', . f'9 ,' ' ,, J ,,,, , (. ( ~ATTACHMENT #1 ~//Z/~ _CHRONOLOGICAL ~I~L HISTORY .,WELL #A,7 6-1o/18%9 6-19%9 6-2o%9 6-21/23%9 6-28~29%9 6-3o%9 7-1/31%9 8-11/12~9 2562' Spudded 15" hole and drilled to 2562'. Ran 10-3/~" OD casing. Set at 2522'. Cemented w/lO20 sx Type "G" cement w/&% Gel prehydrated inlet water. Tailed in w/125 sx Type "G" Neat cement w/2% cc inlet water. 8126, Drilled 9-5/8" hole to 8126'. Ran IES, FDC & SNP Logs. Ran 7" casing, set at 8108'. Cemented w/525 sx Type "G" cement mxd w/130 bbls prehydrated 10% Diacel 'D' and 2% cc wtr. Tailed in w/760 sx Type "G" cmt mxd w/91 bbls 2% cc wtr. Good returns until lacked 25 bbls being displaced, then lost partial returns. Perforated 1', ~353' - ~35~' & squeezed w/130 sx Type "G" cmt. Perforated as follows w/~ shots/ft., .~7" holes, No Plug Jet Gun: 6918'%893', 6755'-67~8', 6650'%6~0', 6593'-6586', 6573'-6568r' 6550'%535', 6507'-6~97', 63A9'%3~2', 6292'-6287', 6281'-6256', 62~5'-6225', 6205'%195', 6187'-6182', 6070'-6060' 5998'-5973' 5908'-5903' 5658'-56&8' 5637'-5632' 5595'-5590'A A970'-~963' ~903'-~878', ~8~0'-~830', ~78~'-~7~4', ~697'-~6~7', ~630'-~620', ~570'-4490' and 2~.7~ -/4/~02 '. Ran 3½" & ~" tubing, set @ ~091' and flwd to clean up. Prep to run ~-pt tests. Ran &-pt test. 805~' PBTD Temporarily suspended. Pkr leaking. Wait on rig.~. Temporarily suspended. Wait on rig. Pulled and repaired packer. Ran tailpipe assembly, packer and tubing. Ran k-pt test as follows: #1 - Flwd 2½ hfs on 3/~" chk, FTP 1600 PSI, Temp 63°, FARO 23,~17 MCFD. #2 - Flwd 1½ hrs on 5/8" c~, FTP 1858 PSI, Temp 66°, FARO 18,770 MCFD. #3 - Flwd 1 hr on ~" chk, FTP 1996 PSI, Temp 67°, FARO 12,624 MCFD. #4 - Flwd 1 hr on ~" chk, FTP 2009 PSI, Temp 67°, FARO 2,978MCFD. SI for BHP. CAOF 56.5 MMCFD. Completed as commingled gas well in Cook Inlet and Beluga Sands. Perf's ~J. O2' - 6918', North Cook Inlet Field. OlW$10N OF 01£~ OAS · ATTACHMENT #2 PHILLIPS PETROLEI~ CO~-~ANY N. C.I. Unit #A-7 North Cook Inlet Field Cook Inlet, Alaska SA~LE DESCRIPTION 255O- 3545 3545 - ~085 /,085- 4330 4330- &375 4375- 5125 5125- 5820 5820- 7060 7060- 8126 Sand- Mod gy, f-rog, mod srtd, subang- subrnd Clyst - Gy and bm, soft, slty, se carb; w/sand - Mod gy, rog, mod srtd; and w/sctd thin coal beds. S~nd - Lt gy, f-rog, mod srtd, subang - subrnd, pred. q~' and feld- Clyst - Gy, soft, mic; an~ coal. Sand- Mod g~, f-rog, poorly srtd, subang- subrnd, w/clyst- gy to bm, slty, soft, carb; and w/thin coal beds. Clyst - Gy and bm, slty, pt mic, carb, soft, w/thin, sctd, coal and sand beds. Sand- Lt ~v, fg, mod srtd, prod qtz; w/clyst - tan to gy, firm to hd. Sltst - Gy, sli clayey, sli carb, v. calc; w/se clyst and sand. Clyde R. Seewald August 27, 1969 AUG ' I 9 I r' /Lt._) ,-) -\ ,.). :,-~ ,.'.. ~..~ ;.~0 ~. ,. , .._ .... L ":"- :i t, "_'.', ,-.. ,-,. :I 11 I! !! !: It Il 1! II :1 I! I! II 11 !1 11 !I t! I1 I1 I1 I! 11 :! !! ',1 I; :: $~IIIOL OF REPORT SUB-SURFACE DIRECTIONAL SURVEY .. PHILLIPS PETROLEUM COMPAI~' PLATFORM "A" A- 7 wrd. L NAME ,. 'NQRTH COOK INLET L{~ATION AM6 - 1569 TYPE OF SURVEY SINGLE SHOT ANCHORAGE j- ~1 i i i iii ii I II Hill UmO IV EA~TCO I~ u. s. A. l, ,nlm · II I 11 ] , il DATE dUNE 1969 PHILLIPS HFASU~ED COUR'SE - - D DEPTH LENGTH ANGLE ORIGI¢~ LOCATED AT ND = 390. 34, 0 50' 424. 34. 1 20' 469. 45. 2 10' ' 541. 72. 1 30' 636. 95. 1 733. 97, 0 30' 800. 67. 0 i5' 862. 62. 2 O' 890. 28. 3 921. 3i. 5 O' 1012. 91. 8 O' 107~. 62. 8 30' llTq. 105. 9 45' 1274.. 95. 12 O' 1306. 92. 15 O' 1460. 94. 17 30' 1553. 93. 18 ~5' 1647. 94. 22 O' 1'740. 93. 25 15' 1834. 94. 28 15' 1928. 94. 30 15' 202I. 93. 33 O' 2114. 93. 35 95' 2215. 101. 36 O' 2346. 131. 35 30' 2438. 92. 35 15' 2563. 125. 35 O' 2647. 84. 35 45' 2802. 155. 36 45' .2987. 185. 37 30' 3140. 153. 37 45' WELL COMPLETION PETROLEUM WELL A-? PREPARED BY SCS REPORT 06/23/69 FOR EASTMAN E V I A T I O N .... C 0 U R DIR6CTION AMOUNT V.DEPTH LATITUDE TVD = 355.98, LATITUDE = 0.49 33.99 0.43 N 0.79 33.99 0.79 N 1.70 4-4.96 1.69 N 1.88 71.97 1.85 N 1.79 94.98 1.79 N 0.84 96.99 0.83 N 0.2q 66.99 0.26 N 2.16 61.96 1,58 27.95 t.45 S 2.70 30.88 2.60 S 12.66 90.11 i2.23 S 9.16 61.31 8.99 S 17,78 103.48 17.64 S 19.75 92.92 19.50 S 23.81 88.86 23.51 S 28.26 89.64 27.83 S 29.89 88.06 29.43 S 35.21 87.15 34,77 S 39.67 84.11 39.18 S 44.49 82.80 43.94 S 47.35 81.20 46,77 S 50.65 77.99 50.15 S 55.42 74.67 54.74 S 59.36 81.71 58.78 S 76,0T 106.64 75.13 S 53.09 75.13 52.58 S 71,69 102,39 70,99 S 49°07 68.17 48.59 S 92.74 124.19 91.83 S 112.62 146.77 110.90 S 93.66 120.97 356.00, N 29 W N 2 E N 6 E Nile N 0 E N I0 E N 25 E S 17 E S 24 E S 15 [ S 15 E S 11 E S 7 E S 9 E S 9 E SlOE S 10 E S 9 E S 9 E S 9 E S ~ E S ~ E S 9 E S 6 E S 9 E S 8 E S 8 E S 8 E S 8 E SlOE S 11 E S E T DEPARTURE V. DEPTH 7.13, DEPARTURE 0.23 W 389.97 0.02 E 423.96 0.17 E 468.93 0.35 E 540.91 0.00 E 635.89 0.14 [ 752.88 0.12 E 799.88 0.63 E 861.85 0.64 E 889.80 0.69 E 920.68 3.27 E 1010.80 1.74 E 1072.12 2.16 E 1175.60 3.08 E 12~8.52 3.72 E 1357.39 4.90 [ 1447.04 5.19 E 1535.10 5.50 ~ 16f2.26 6.20 E 1706.37 6.96 E 1789.18 7.40 5 1870.38 7.04 E 1948.37 8.67 E 2023.05 8.26 E 2104.76 11.90 E 2211.41 7.38 E 2286.54 9.97 E 2388.94 6.83 E 2457.11 12.90 ~ 2581.~0 19.55 5 2728.07 17.87 E '2849.05 8 3 12 30 49 73 101 t30 165 204 248 295 345 40O 458 534 586 657 706 798 9O8 1000 P-GE 1 TANGENTIAL METk~OO T A L LATITUDE DEPARTURE -2.21 7.56 N 8.35 N 10.04 N ll.Sg N 13.69 N 14.5g N 14.78 N 12,72 N 11.27 N · 6:~ N .5~ S · 5'~ S · 2~ S .7,~ S · 2:~ S .0~! S · 5- S .3 S .48 S ,4£ S .1~ S ~ .1o S .89 S .02 S .60 S .60 S .2O S .0~ S~ ,95 S .90 S 2.44. W 2.42 w 2.24 W 1,88 W 1.88 W 1,73 W 1.61 W 0.98 W O. 33 W 0.3~b ~ 3.64 'E 5.38 E 7.55' E 10.64 E 14.37 E 19.28 E 24.47 E 2'9.97 E 36.18 E 43.14 E 50.55 E 57.60 E 66.27 E 74.53 E 86.43 E 93.82 E 103.80 E 110,63 E 123.54 E 143.0') E 160.97 S DEPTH 3325. 3482 o 3670. 3826. 3961. 4179. 4457. 4706. 5019, 5134. 5385. 5697. 581b. 6021. (>242 o 651b, b82C~. 7073. 7323. 7696. 7936 · 8120. ~ E L L C O M P L E T I O N R E P O R T PHILLIPS: ETROLtUM WELL A-? PREPARED BY SCS 0:6/23/69 FOR EASTMAN COURSE - -O E v ! ~, T 0 N - -C 0~] U R; S ~< - - - r LENGTH ANGLE DIRECTION AMOUN [ V.DEPTH LATITUDE DEPARTURE V.DEPTH 185. 38 O' S 13 E 1t3.89 145.78 1t0.97 S 25.52 E 2994.83 157. 37 45' S 13 E 96.11 124.13 93.65 $ 21.02 E 3118.97 188. 38 .t5' S 13 E 116.38 147.63 113.40 S 26.18 E 32~0.6t 15~. 37 O' S I5 E 93.88 12~.58 90.68 S 24.29 E 3391.20 13~. 36 45' S 14 E 80.77 108.16 78.37 S 19.5q E 34'~9.37 218. 37 15' S 14 E 131.95 173.52 128.03 S 31.92 E 36'Z2.89 278. ~7 O' S i4 E 167.30 222.02 1~2.33 S 40.47 ~ 3894.91 249. 35 ~5' S 15 E 145.47 202.08 140.52 S 37.65 E 4097.00 313. 35 O' S t4 E 179.52 256.3~ 17~.19 S ~3.43 E 4353.3q 115. 3~ O' S 14 E 64.30 95.33 62.39 S 15.55 E 4448.73 251. 34 45' S 1~ E 143.06 206.23 I39.40 S 32.18 E 4654.96 3/2. 34 O' S 11 E 174.46 258.65 17t.26 S 33.29 E 4913.62 121. 33 30' S t0 E 66.78 100.90 ~5.76 S 11.59 E 5014.52 209, 35 ]0' S 10 E 121.36 1~0.15 119.52 S 21.07 ~ 5184.67 215, 35 45' S 9 E 125,61 174,48 124,06 S 19,65 E 5359,16 274, 35 45' S 9 E 160,08 222,~7 158,11 S g5.04 E 5581,53 BIO. 36 30' S 8 E 184.39 249.19 182.60 S 25.66 E 581{0.73 247. 3b 4.5' S 6 ~ 147.78 197.90 146,97 S 15,44 E 6028,64 250. 35 15' S 6 E 1~4,~8 204,16 143,49 S 15,08 ~ 6232.80 37~. 3g O' S 6 E 197.65 BIO.B2 196.57 S 20.b6 ~ 6549.12 240. 30 45' S 7 E 122.71 200.25 121.79 S 14.95 E 6755.38 190. 30 15' S b E 95,71 164.I2 ~5.19 S 10.00 E 691.9.51 PAGE 2 TANGENTIAL ME'TH,OD 0 T A L LAT I TUDE DEPARTURE 1111.87 S × 186.59 1205.53 S 208.21 1318.94 S 234.39 1409.62 S 258.69 1487.99 S ~ 2'78.23 1616,0~ S._ 3i0,15 1778.36 S 350.6~ 1918.88 S ~ 388.28 2093.08 S 431.71 'E . 2155.48 S ~ 447.27.E 2~4 88 S 479.45.~ 2466.14 S ~ 512.74 25'31.91S 524.34 2651.44 S 545.42 2775.50 S ~ 565.07 2933.62 S 590,11 3116.22 S ~ 6!5.77 3263.19 S 631.22 3406,69 S ~ 6q6,30 3603.27 S 666.96 3725.06 S 681.92 3820,26 S ~ 691,92 CLOSURE 3882.41 S I0- 16' E STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS W~rLL [~ GA~ ~t'eLL ~] OTHER 2. N~E OF OP~TOR 4. ~CA~O~ SUBMIT IN DUPLICATE ~SurfaRe_: Leg 3, Slot 8, 1249' FNL, 1084' FWL, Sec. 6, TllN, Rgw, S.M., North Cook Inlet, Platform "Tyenek,' .. SEc.. T.. R.. M.. mo~JM HO~ ~: 2A00' FSI,, 1~50' FWL, Sec. 6, TllN, RgW, S.M. See. 6, TllN, RgW, S.M. ~-. PERMIT NO. REPORT TOTAL DEPTH AT Ell~p..D OF MONT~. CI-IA~TGF. S IN T4OLE ,~TZ~. Ck-~INC~ AND SET A/W'D VOLU1VrES USED. F-~-FORATIOATS, TESTS A/~D I~ESULTS. FISHIN~ JO~ .~ir~f~ ~ ~,~--;~-~---~ ~ ~un~ ~E~T~ AD A3~Y OT~ER S]GNIFIC~ CI-IA/~ IN HOL~ CONDITIONS. -~ ........... ,-,~ 10. FJT. LD AND POOL. OR WILDCk? 8-1/5%9 Completed as commingled gas well. Temporarily suspended. ~0R. Pulled and repaired packer. Ran tailpipe assembly, packer and tubing. Ran 4-pt test as £ellowz: #1- Flwd 2½ hfs on 3/4" chk, FTP 16OO PSI, Temp 63° FARO 2 . _ , _3.~!7 MOFD. #2 - Flwd ~ 1858 PSI, Temp 66e, FARO 18,770 MCFD. #3 :~.hk, FTP 1996 PS][, Temp 67°, FARO ~,6~ MCFD. #4 - Flwd I hr. en chk, FTP 2OO9 PSI, Temp 67©, FARO 2,97? MCFD. SI for BHP. CAOF 56.5 MMCFD. ,, - ~ons anct must be fried m wit f , ' ' duplicate o the succeeding month, unless otherwise directed. JAN. STATE OF ALASKA SUI~.MUI' L~ DL'PLICAT'E OiL AND GAS CONSERVATION COMMI]q'EE GAS WELL OPEN FLOW POTENTIAL IEST REPORT 4-POI.',,'T TEST ~itia~. L_J .~nm, at LJ Completion Date j Total Depth ~... '/ ~ .(..> , ,/?.Z"./'.,"/.~' %P-- . I Type Taps Gas-Liquid Hydroczrbon Ratio MCF pcr Bbl. Gravity of Liquid (Api) .~Iultiple Completion (Dual or Triple) Type produ6tion from each zone Tithe No. of Flow iCiours % / 3. .../ z ~. ./ ¢~-~.~ (Line) S~ze OBSERVED DAT~. Flow Data (Choke) 40~4~ce) Size Press. psi~ Diff. h w FLO%r CALCULATIONS Tubing Press. psig Casing Press. psig Flowing Temp. °F Coeffi- 'Flow Temp. Gravity Comprcss. (24 Hr.) [V W m psia Pt Fg Fpv{ Q AfCF/D · . . ""~ ' , ~.~ /,..-.. - ~ ~., , ~._ j._::.,. :.,,, , , ~,:. ~,,: ,,, , ,~ , ~:...:.:.;' .... ,.:>.~-),a' ' ' j /, ).: : ...... ~:, ........... ...' · : ...... :. . .,,..,, -,.... ., PRESSt: RI~ CALCULATIONS . ..... ~ ~ . . ~D .~:%t~- ..... ::5-'>/~:.' ~ "~ /' > 4. ~ .' ............ ' .. ~ . -I":: .ap ./:":;'~/ ..... ~..~:""_ 'F.':~:' ...... ~ ':' .' -" Absolute Potenhat n (company), and ~a~ I am author~ed by said comply to make ~is report;.....~nd that th~ report was ~ne best of my ~owledge. ~'" /~'oi~ature 10 AUGJe o'1969 --7 8 9 10 2 3 4- 5 6 7 8 9 .. ~Oz'm 1',1'o. , RE[VISE:D ~ dAN. i ~ 1969 STATE OF ALASKA- OIL'AND GAS CONSERVATION COMMITTEE. SUBMIT E~ DL'PLICATE GAS WELL OPEN FLOW POTENTIAl. TEST REPORT 4-POIXT TEST Test ~nltlal. ~ Annual [~ Special Field _. /9 .__._. J Reservoir / ~ J Test Date ~ttov. ) ' ' ~. ) ~" r' ~ I Lease- ' ~ . / / . - -Iwe~l Xo. ~ ' - ·" . , ' . ~rodueing Thru I ae~n'olr/ I Wellh,~d J C80. Slz, I SVt/Ft~.. I"}.~. - ~l'sa ~ /' ' r T~G.. J' C8~. J Tempt. ratur~ I' Temg~tlt~ti i ~ I '. . i . ~ I ' ~ A ' ~ . ' J ,~ ~ j /_, . J ' ~ ' /~ j ~ .... 'J (Separator). J LengthiLy J _, / / J Ratio MCF per Bbl. Liquid (Apl) ~ ' - I /~', ~/ I ~'~'~ ~ I~. ~ P>~.,'7 I · 5~'~1 -~:<%Z. I~/~ I e Connection J ~ype cJ_~ . / . J ' /.v,//~ /~;xf~, ~//~ :~Z~>-- ~" .~..~ ~ ~ Multiple Completion (Dual or Tripl~) / ~ / .... · Xpe produ~tion ~rom eaoh zone OBSERVED DATA. · Flow Data ' Time ' . (:P-r~u~r-) (Choke) Press. Diff, , Tubing .. Casing Flowing ,~o, of Flow (Line) . ' 4~r.l~oe) ' ' h · :Press. ' Press. Temp.. Hours ' Size Size. pslg w psig pstg . 'F . , · ..... ~ s~ ' ~0 '~'~'" . . , /.,9 ........ · . . , ,, (D -,, . - , ~. ?~./ "~,~c, .'~4:~)o /~' ' //,,:~ ?~ d~/... 2 . / , ,. .... : , ~,~,,,..~ .... . .. .' . ..... ,. · / J ...... . . ..~.~.(,~). ~/4~,~;~ ~, .~.~'.~ · ... FLOXV CALCULATIONS Coeffl- 'FloTM Temp. Gravity Compress. 1~o. clent ._~/hw p pressure :Factor . Factor' Factor Rate of FloW (24 ,Hi'.) m psia , , F . F F Q ~ICF/D . , t :.. g . pv . . , , .. /. ,- .. , ~'~'.,::~'.'/2 '"'/, ~,~,/ ~..~ '"~,~ ~. /z.~'d, J /,:~/.~ .... . . /,t~ .. . /~r' ~''' ,. , . , " .. .~- . ~ ,, , , PRESSURE CALCULA.TIONS CERTIFICATE: I, the undersigned, state that ! am ,h" ~.~.~..' ..r--' of the (company), and that I am author/zed by said company to make this report; pared under my supervision and direction and that the facts stated the b~st of my knowledge. Signature .. l .... that this report was .,, correct and complc~ OIVIONOFOILMIOAS l~rm No. REV. STATE OF ALASKA OIL AND GAS CONSERVATION COMMI'I'I'EE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS SUBMIT I~T DUPLICA'I~ OIL ~-~ GAB ~ OT~ER WELL WELL 515 "~" St .r~e.t. An~ae .rage, Alaska 4, LOCATION OF WEI~ ~fa~e~ Leg 3, $1et 8, 12%9' ~, ID&' F~L, 5eo. 6, T31-W, Rgb, S.~, ~h ~ I~t, ~fo~ "~n~" To~ of ~t ~' ~, ~'.~, ~o. 6, ~, R~, S.M. _ Fll; 8. L~-'IT,F.~,AI OR LEASE N.~ME ~lq~h O~ok ~ Unit 9. WELL NO. #A-7 10, F~ AND POOL. OR WILDCAT Ner~h ae~k ~ , 11. SEC.. T.. l:t., M., CBOT'TOM HOLE :Sea. 6, ?~, Rgb,, S.M. 12. PEP.MIT ~TO. 69-~8 / , 13. REPORT TOTAL DEPTH AT END OF MONTH, CI-IA.NGES IN HOLE SIZE, CASING AATD CEI%IENTING JOBS INCLUDING DEPTH SET AND VOL~ USED, PEH~OKATIOHS, TESTS ~ RESULTS, FISHING JOBS, JUnK ~ HOLE AND SIDE-TH~CKED HOLE A2VD ~Y O~R SIGNIFIC~T ~~ ~ HO~ ~ITIONS, 7-~31~9 ~5~" P~ T~~ ~nde~. ~ 1~. ~ on ~g. DI¥1SIOHOFOILAliDGAS ce {hat e fore g is SiG~mD . , // -,,, ~),/, , , NOTE--Report on this form is quired for each calendar month,, regardless of the status of operations, ,an~ must ~ filed in duplicate With the Division of Mines & Minerals by the 15th of the succeeding month, unless othe~ise directed. ' ro~ so. ~--4 STATE OF AbASKA SUB~rr i/q D~LIC~ OK~ ~. ~-s0-~ ~. ~ N~S~c~ CODs KtV ~'~ ~ ~I 50--283--~27 HWZ ~ 1. % IF INDIAN, A~ 1 lEE OR TRI~~~ GA8 ~ WELL OTHER 2. N~E OF OP~TOR 8. L~'IT,F.~M OR LEASE N.~ME OXL ~ WgLL L-~' OIL AND GAS CONSERVATION COMMITTEE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS AbI~RESS OF OPERATOR 515 "O" Street~ Anchora~;e~ Alaska LOCATION O'F WELL Surface: Leg 3, Slot 8, 12~9' F~L, 108~' F~., Sec. _ _ Rgw, S.H., North 0ook Inlet, Platform "TYonek". Tea_of Pa~t 23+00, ~SL,~1250' FWL, Sec..6, TllN, R9W, 9, %YELL NO. , ~A-7 10. F~rE[.~ A-ND POOL, OR WILDCAT -!1. SEC., T., R., M.. ~BO/'TOM HOL~ Sec. 6~ Tll~, R9W, lg. PER/VIIT NO. 69-~8 REPORT TOTAL DEPTH AT END OF MONTH, CH.A-NGES IN HOLE SI~E, CASING A_ND CEMENTING JOBS INCLUDING DEPTH SET A/%TD VOLTJiVIES USED, PERFO.I{ATIO/~TS, TESTS ~ ~SULTS, FISKING JO~, J~K ~ HO~ ~D SIDE-~CKED HOLE ~ ~Y O~R SIGNIFIC~T ~~ ~ ~O~ ~ITIONS. 6-30-69 Ranning /+-Pt. test. 6.-8/9..69 2562' $~ded 15" hole and dEiCed to 2562'. Raa lO-3/&" OD easing. Set at 2522'. Cemented w/1020 ax Type cement w/~% ~el prehy4rate4 i~let water. Tailed in w/125 ax Type "8" Neat cement w/2% co inlet water. 6-zo/l -69 6-19-69 8126, DEiCed 9-5/8" hole te 8126'. Ran IES, F~ & SNP Iogs. 6-20-69 Ram' 7" easing, set at 8108'. ~.C~mentea w/525 sx Type "~" cement mx~ w/130 bb~ pre~rat~ 10% Diacel 'D' ~d ~ cc ~r. Tail~ ~ w/T&0 ~ ~ "~" ~ ~ w/91 bbls ~ cc ~r. ~til ~cke~. 25 bbls be~ die, ced, then lo~ ~~1 6-21/23-69 Perforated 1:', ~353' -&3~&' & sgueeze4 w/130 mc Type "O" amt. 6-2g-69 DIVISION OF OiL AND GAS ANCHOR,GE Perforate4 as follows w/& shots/ft., .&7" holes, ~o Plng Jet { Gan. 6918'-6893", 6755'-67&8', 66 50' -66;+0 ' , 659~'-6586', 6573'- ~ 6568', 6550"-6535', 65~7'-6&97', 63&9'~3~', 6292.'~2~', 6281'2 $255', 62&5'~225', 6Z05'~195', 6~'~1~', ~7~'~~', 5~8'- 5~3', 5~8'-5~3', 5558'-~', 5637'-5632', 5595'-55~', ~0'- &963', &~3'~8', ~'~30', &78~'~7~', ~'~AT', ~30'- 6- 5/27-69 Ran 3~" & A" tubing, set e ~91' a~d flwd t,o clean up. 6-28/29-69 Prep %e ~ /+-pt. tests. I hereby certi ego~g correct , ', !!-: .... , , ~lO/TE--Report on this form is r~quired for each calendar month, regardless of the status of operations, and must be filecl in duplicate withl,tfie Division of Mines & Minerals by the 15th of the succeeding month, unless otherwise directed. II Form No. G-1 RE¥1$£D .' JAN. STATE OF ALASKA OIL AND GAS CONSERVATION COb, AMI'Iq'El SIJIIMI-f 1~ DUI:'LICA. TIE GAS WELL OpEN FLOW POTENTIAL TEST REPORT 4-POIXT TEST Test ' I - //-., ...,., ,,. > .z:....."'~.-';-~-,..~.....x~,~ d, /~ ~- ::"' ,.. ':'' ~ ~ 'T , ~ ~ J . ~ t Interval · ~a. ~'.~ ~ '~ ,,, ~ J CSG. Temp~ratur~ T~mperitu~ '~ ' r ~ ~ ...... ............. ~(~,~: 2,? ._,t ~:xC. C,~ . ~ ..... , ,J, )Iultlple Completion (Dua~ or Triple) · ._ j Type productidn from each zone OBSERVED DATA Flow Data Time (Prover) ' (Choke) Press. Diff. Tubing Casing J Flowing NO. of FIow (~.~i.ne)- ~f~r~) h Press. Press. t Temp. Hours Size Size psig w psig pstg I ' 'F st ........j ,...~d,,~.]-' ..... i" ' ,. , "..~.'" J ........... ~/~i'" /;,.:~,:,.~ ,',.~,s~ ' ................. :~'..,'p ~. , ..¢; ~ j ..... 'Se~,, , / .,q_eg". ,/:,-~t;'/ 7.~,.. ~.. , ........ /,,,,,,?, ,, i :5/n f /~_;~2 /7.~:7',~ , 7-;-Z -*~- ' ,, , ........ , , , ,, , ,, ,,r ,,i- ~',', ~ .,.,, ,, ., ,, '' , ,i ,,, , ,., ,,, , ,,,., · F~O%V CALCULATIONS .... Flow Temp. Gravity Compress. Coefft- ----~ /h P Pressure Factor Factor Factor Rate of Flow ~o. cient~ F F F Q ~ICF/D (24 Hr.) W m psla t g pv ...................... ~z ~, ' ...... ,~,..:,~...~ .,: ~ / '/.,,,,~ 1. /~'_~ .... ~.~ / .... ,~V-' c~ ~ · ~.":.,':.-", v ,"7,' . ,j'~ ' , ........... ;' ~ ............ ~x. ..... ?v.-~_ __ ~ ~,~ x , . . .... ~...~'.~{.."~? .............. PRESSURE CALCULATIONS [FICATE: I, the undersized, state that I am the ~'"'gC':~,~ JUL9 '" ...... any), and ~at I am au~or~ed by said comply to ma~e ~is reporq~4 ~at ~fs report was pre- ~i l m~--' '.~,.A~ ~ ~ / AN~':~ 'best o~ my ~owledge. , · / / // Si~at~ .} .... ~J'l'A'llg L~I~' ALASKA OIL AND GAS CONSERVATION COMMITTEE Opera '-6r ./] / 7/~y' .7 ' ~ " . '-. : -'eld ' gj'oduei~_Formation ] oi!G,:a'd~t- · ~ ~ater Gradient. / . ] 7i~ ~ompletion* 8hut-In Lease RESERVOIR PRESSURE .REPORT .. Date Tubing Test Tested Pressure Depth Address Special* Test Data ~See Instructions on Bcver.;e Side . . General Survey:*. - Prod~ Test Pressure Sonic Instrument Test Data Designate type of report by "X". . Ol~served Pressure (Bbls. per Day) Casing Pressure Datum (company), and that I am authorized by said company, to make this re?port?axnd that this report was prepared under my supervision and direction and tha~t~'the facts st.at~d therein~ are true, correct and complete to the best of my knowledge. ~!.~// /~:-- ? J . . ~ L'7~""': ............. "~ .... ~ ................................................ = ............................ ~lgnature ) MINER PUBLISHING CO. 4 . ' 8 '3 1 4 5 6 7 8 910 GAS / 1018 ItlTEi~IIATIOtfAL A!£PO?T £8AD'~.~'/..~_~'~ ' ANCHORAGE 99502 ~ ~ June 12, 1'~6~ Hr. John B. ~ipson FILE .- ~ Phillips Petroleum Company 5]5 'ID'~ Street Anchorage, Alaska 99501 Re: North Cook Inlet Unit ~A-7 Phillips Petroleum COmpany Operator Dear Mr. Gipson: In reference to the subject offshore drill-site, the following stipulations are required to preserve and protect fish and game resources: . No foreign materia] to the environment wi11 be discharged from this platform. This incl'udes §arbage, trash, refuse, petroleum and/or its products, drilling mud and debris. 2. Drilling operations are not to interfere with commercial fishing. . The Habitat Biologist's Office, 10]8 West International Airport Road, Anchorage, Alaska 99502, will be notified prior to abandonment of-this location. .~...?rn c e~r ely i - ' . //7 ~'~ Kober~/S, Wienhold Habitat Bi.olog ist RJW: bb CC' B. Hilliker H. Burrell P. Denton DIVISION OF OIL AND GAS ANCHUI~,'~GE 1969 OKCJ KLV ~"~orrn REV. STATE OF ALASKA SUBMIT IN TRI ~I (Other instructions oL reverse side) OIL AND GAS CONSERVATION ,COMMITTEE' , , APPLICATION FOR PERMIT TO DRILL, DEEPEN, OR PLUG BACK la. TYPE OP WORK DRILL ~-q DEEPEN ~] PLUG BACK OIL [] 0AS ~] 8INGLE ~-~ MULTIPLE[] WELL WELL OTHER ZONE ZONE 2. NAME OF OPERATOR Phillips Petreleum 0e _~a~ 3. ADDRESS O~ OPERATOR 515 "D" ~at. lneho~, l~ska ~501 R~, S.M., ~o~h ~k I~t, P~tf~ "~mek" At pro~dp~od, zone ~, F~, ~50j ~, Sec. 6, T~, R~, S.M. 13. DISTANCE IN MILES AND DIRECTION FZOM NEAREST TOWN OR POST OFFICE* 10, 5 miles East ,ef=~aek, Alaska i4. BOND INTONATION: ~I~ Sta~e Wide B~d RI-1 TYPE Surety and/or No. 15. DISTANCE FROM PROPOSED*; LOCATION TO NEAREST PROPERTY OR LEASE LINE, 'FT, (Also to nearest drig, unit, if any) 18. DISTANCE FROM PROPOSED LOCATION* TO NEAREST WELL DRILLING, COMPLETED, OR APPLIED FOR, FT. 19. PROPOSED DEPTH '7000' ~ 50-283-20027 5. 6. LF. ASE DESIGNATION ~ SERIAL NO. A~I--17589 ?. IF .12TDIAN, AI.,J..K)~ OR %~PJRg NAM~ S. UNIT, FARM OR LEASE NANrE Ner~h C~k Inlet Unit 9. WELL NO. #A-? 10. FIELD AND POOL. OR WILDCAT Ne~h Ceek Inlet 11. SEC.-, T.. R., Ai., (BOTTOM HOLE OBJECTIVE) ~ec. 6: T~I,_N, RgW, S.M. 12. A~nount ri7. NO. ACRES ASSIGNED TO THiS WELL 20. ROTARY OR CABLE TOOLS 21. ELEVATIONS (Show whether DF, RT, C-R, etc.) ~. APPROX. DATE WORK WILL START* 23. ' ' * PROPOSED CASING AND CEMENTING PROGRAM SIZE OF HOLE , SIZE OF CASING WEIGHT PER' FOC~T i -- , .. ---.. r . . ,j, 'J, , ', . .:.., ' , ', D, ~. ~, , ' ~ ' ~, '' , "~ ~" ' ~,' -* , ' L '' .... . , -.: , 1. Devia%ien required te reach B~qfr~ permanent platform; 2. There are mo' effecte~ epera%ers. 3. B~ Spe=ifieatiea attached. &. Intervals ef interest will be perferated and may be stimmlate4. * Refer to State:'ef ~].-~ska, Ala~0il & ~as Censervatien Oem~tee, ~enservation 0rater #1~, dated 6-8-67 and ~68, dated 12-7-~8. RECEIVEI) IN ABOV]~ SP/~CE u proposed ne, W~ l~oductive true vert~o~l /epths. i Give blowoud~lfpreventer program. ~4. i ~e~eW oMtm~at,~e Forwom~ ~ ~a Co=r~ ~.~ _~ 28, 1969 (T~e ~~ ~ OO~DI~ON~ OF ~P~O~, IF A~: [SA~L~ 'D CO~ CroPS REQUI~ J ~ ~U~S: zone. If Proposal is to drill or deepen direct 5onally, give pertinent data on st~bsurface k)catioll~ and measured and DIVISION,OF OIt AND GAS TI~ Dist. 0fc. 14~. DIRECTIONAL SURVEY REQUIRED .~ YES [] NO APPROvEDPERMIT ATO_Bv_~ Ai~~~ " ~"~ ~:>~ ~" ~~ ////~ ,,,~ *See InstructiOns On Reve~e Side June 3, 1969 APPROVAL DATE Director , TITL~.Div- of Oil & Ca~ DATE June 3, 1969 36 I 12 LEG N-°. 31 6 4., 975' ~/~3 / 2 LAT. 61° 04' 36.38" LONG.150° 56' 55.63" Y-- 2,586,731 X-- 331,995 FROM N.W. COR. 1,250' SOUTH & 975' EAST. LEG No-. 4 LAT. 61° 04' 36.89" LONG. 150° 56' 54.25" Y: 2,586,78 I X=, 3 32,063 FROM N.W. COR. 1,198' SOUTH & .1,04:5' EAST. · IZN i~11 ,liN 31 6 SCALE LEG N-e. 2 LAT. 61° 04' $5.83" LONG. 150° 56' 54.77" Y= 2,586,674 X= 332,056 FROM N.W. COR. 1,305' SOUTH ~ 1,018' EAST. LAT. 61° :04' 36-'34'' LONG. 150° 56' 53'.39" Y:2,586,724 X: 332,105 FROM N.W. COR. 1,254'.SOUTH &' 1,085' EAST. CERTIFICATE OF SURVEYOR 5 :NOTE: Plat., a~nd~d. 7AUG.68!: fo *show revised leg number:lng, I hereby certify that I am properly registered and licensed to practice land surveying in the State of Alaska and that this plat represents a location survey made by me or under my supervision and that all dimensions and other details are correct. ~ "' DA~'E SU F~V,~YOR ~ NOTE The location of the platform legs was accomplished by using triangulation stations BELUGA,TERRACE,and TYONEK which are all U.S.C.S G.S. stations. AIl coordinates are Alaska State Plane, Zone 4. .NORTH. ,COOK IN~_~T uNIT ":: P.LATFORM~'A"i" 'i'.,i.'." FO. PHILLIPS pETROLEUM, CO DATE: 21 JU EM.'LINDSEY SCALE: Land:&. H~mgraphicr-. .... IH I 36 31 PHILLIPS ',, ..... ~...--__, , "% . . . ~ _ ,~g , ~ ~'~~.A'4 ' I . ',,_ ,4DL $ 7,~$/ 12 13 i A'7,, ADL I;/589,,, ~ Il Il I ,,~f I II Illlll ~PROPOSED B.H.L -"'N.C.I. Un. No. A-7 I I (60'FSL ~ 1500'FWL of Sec.6-11N-gW S.M.) 7' 18 , , I 11 ~11 r I , I I II l[ I I 32 r~ ' 5 8 GRID PHILLIPS PETROLEUM COMPANY 515 "1~' STREET ANCHORAGE ,ALASKA PLAT OF NORTH COOK INLET UNiT TYONEK PLATFORM , , , .... , ,,, DRWN. N. J. Powell I$C'ALE: I"=ZOOd' ' , {~^TE': s-~8-o9 ,i · ,, Fl 0 0 F,U P F'O R ' HYORIL OK SERIES 1500 - . __.__,.,_. ·. (BJND RAMS) : . . - ~... - ' . _ ' ~ .' :.. : ' "~- R~- ~ !, ,,, ~ ~'::' ~ ~ ,,~,,-~,o~ s~,,~,~oo ~.-- , .--- --. ' ' ~- '"' '" ''~:': ::' .'.:...":.~Z .... -. ' ~ . :' ".'...-. ' (PIPE RAMS) - . ' " .- . ' " . ' 1 I -' .'-' · '-- ~~ m DOuble Preventers are used' with flanged side 'outlets for choke manifold and fillup line connec~tions._: :: ' -:' . ._ . . . .- - . .. DOUBLE PREVE N'I'ERS · N, C..L. u_~ P L A T F O R 4" SERIES 1500 VALVE 2" SERIES 1500 VALVE 2_" MUD PRESSURE GAUG~ ON 4"X " SERIES 1500 STEEL TEE 4" SERIES 1500 X 2" SERIES 1500 STE'EL CROSS 2" SERIES 1500 POSITIVE CHOKE 2" SERIES 1500 ADJUSTABLE CHOKE · PHILLIPS PcT°OLL:.U,',.,,_,,-, CO,';,PANY PRODUCTION DEPART M ENI' 5000 PS! WORKING PR BLO\VOUI' PR,'L'VEN'I'h'R HOOK-UP ,/ FORM SA-lB MEMORANDUM TO: I'- State of Alaska FROM: DATE SUBJECT: CHECK LIST FOR NEW WELL PERMITS Company Phillips Petroleum Company North Cook Inlet Unit Lease & Well No. Yes No Remarks 1. Is well to be located in a defined pool ................. 2. Do statewide ru, les apply ........................ 3, Is a re§istered survey plat attached )is well located proper distance from property line ........... ot~er ~,Jel Is 5~ )Ls well located proper distance from ' .... . -: Is st~'F'Fici,::'~t undedicated acreage available in this pool ........ 9. Can pem~it be approved before ten-day wait ............... 10, Does opera,~.o;~ h~,.¥~, a bond in forca , ll. Is conductor strin,~ provided ..................... 12 !'s enot~gh cement uscd 1~o circulate on conductor and Will cement tie in surface and intermediate or production 'i,~,, ~ill cement cover all possible productive horizons ........... 15. Will surface casing cover all fresh water zones ............ 16. ~ill surface csg. internal b~,~t equal .5 psi/ft, to next string 17. Will all casing give adequate safety in collapse and tension ...... 18.. Does BOPE have sufficient pressure rating ............... Additional Requirements' Appro~al Recon]'r~e~!ded' J TRM ~__- REL KLV OKG ~