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197-210
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): 14,537 N/A Casing Collapse Structural Conductor Surface 2,670psi Production 7,930psi Liner 10,870psi 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: Eric Dickerman Contact Email:Eric.Dickerman@hilcorp.com Contact Phone:(907) 564-4061 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 Other: CTCO / N2 North Cook Inlet Tertiary System Gas Same 13,377 7,330 6,737 2,432psi See schematic CO 68A 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): Operations Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 197-210 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20090-01-00 Hilcorp Alaska, LLC N Cook Inlet Unit B-02 Length Size Proposed Pools: 407' 407' L-80 TVD Burst 4,802, 10,626, 13,530 11,640psi MD 10,900psi 5,380psi 2,535' 8,123' 10,224' 2,602' 8,909' 407' 30" 20" 13-3/8" 2,602' 9-5/8"11,086' 8,909' 11,086' 4,799 - 6,205 2,784' 3-1/2" 4,483 - 5,746 12,460'7" 13,522' 2/14/2025 14,457'935' 4-1/2", 2-7/8", 3-1/2" 13,306' See schematic See schematic Perforation Depth MD (ft): 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 9:39 am, Feb 03, 2025 325-055 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2025.01.31 16:49:13 - 09'00' Dan Marlowe (1267) BJM 2/27/25 DSR-2/18/25 CT BOP test to 3000 psi X 10-404 Deepest approved perf is 6538' TVD. See attached email from Eric Dickerman 2/14/25. SFD 2/10/2025*&: 2/27/2025Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.27 12:34:33 -09'00' RBDMS JSB 022825 Fill clean out and Perf Well: NCIU B-02 Well Name:NCIU B-02 (sidetrack from Sunfish-3) API Number:50-883-20090-01-00 Current Status:Online gas well Leg:Leg #1 (NW corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:197-210 First Call Engineer:Eric Dickerman 307-250-4013 Second Call Engineer:Casey Morse 907-777-8322 Maximum Expected BHP:3,010 psi at 5,788’ tvd 0.52psi/ft to deepest proposed Max. Potential Surface Pressure:2,432 psi Using 0.1 psi/ft gradient to surface Brief Well Summary B-02 was completed in February 1998 as a dual string producer into the deep oil sands testing both the Sunfish oil and West Forelands formations for oil, 2,774 bopd and 1,607 bopd respectively. In 2002 the oil was isolated with cement plugs and the well was converted into a Sterling gas well with rates upwards of 15.5 mmscfd. In 2021 a recomplete pulled the dual completion, ran 4-1/2” tubing and targeted deeper Sterling and some Upper Beluga sands. During the most recent Upper Beluga add perfs, fill was tagged at 5,645’. Objective: Cleanout the production interval. Add Lower Beluga perforations. Notes on wellbore condition: - SSSV: Wireline retrievable. - Inclination less than 30 degrees above PBTD. - 3/1/2023: o Slickline confirmed sliding sleeve at 4,767’ md is closed. - 3/10/2024: o Eline tagged fill at 5,645’. Fill clean out and Perf Well: NCIU B-02 Slickline: 1. Pull SSSV from nipple at 359’. Coiled Tubing Procedure: 2. MIRU Fox Energy offshore Coiled Tubing and pressure control equipment. 3. Pressure test lubricator to 250 psi low / 3,000 psi high. a. Multiple wells planned for CT intervention on this Leg #1. b. Hilcorp requests a weekly CT BOP test requirement while on this leg, instead of each well. 4. MU cleanout BHA. Dry tag top of fill, then begin cleaning out to PBTD, approximately 7,330’. a. Working fluid will be 6% KCl (8.6ppg). b. Take returns to surface up the CT x tubing annulus. c. Add foam and nitrogen as necessary to carry solids to surface. d. Utilize gas lift to assist with hole cleaning. 5. RIH and blow well dry with nitrogen. 6. RDMO CT. 7. Repeat coil cleanout as needed to allow Eline to reach target perforation intervals. Eline Perf procedure: 8. MIRU Eline and pressure control equipment. 9. Pressure test lubricator to 250 psi low / 3,000 psi high. 10. RIH and perforate Beluga gas sands from ± 4,800’ - ± 7,300’ md (± 4,486’ - ±6,701’ tvd) per RE/Geo. a. All proposed perforations are within Tertiary System Gas Pool. b. Top pool is at top Sterling sands, bottom pool is below PBTD. 11. RDMO Eline. CONTINGENCY Eline plug: (if any zone makes unwanted solids or water) 12. RU nitrogen to tubing and pressure test lines to 3,000 psi (or higher if needed). 13. Pressure up on tubing to displace water back into formation. 14. MIRU Eline and pressure control equipment. 15. Pressure test lubricator to 250 psi low / 3,000 psi high. 16. Set expandable isolation plug and dump bail cement per OE. 17. RDMO Nitrogen and Eline. Slickline: 18. Re-set SSSV in nipple at 359’. SSSV must be tested within 14 days of the well being returned to production. See revised perf interval in email from Eric Dickerman 2/14/25. Deepest perf requested and approved is 6538' TVD - bjm BOP test required on each well. -bjm Fill clean out and Perf Well: NCIU B-02 Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. CT BOP Drawing (Fox energy) 4. Nitrogen procedure 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ 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 14,537 feet See schematic feet true vertical 13,377 feet N/A feet Effective Depth measured 7,330 feet 4,554 & 4,781 feet true vertical 6,737 feet 4,263 & 4,467 feet Perforation depth Measured depth 4,799 - 6,205 feet True Vertical depth 4,483 - 5,746 feet 4-1/2" L-80 4,802 (MD) 4,486 (TVD) Tubing (size, grade, measured and true vertical depth) 2-7/8" L-80 10,626 (MD) 9,783 (TVD) 3-1/2" L-80 13,530 (MD) 12,443 (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: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work:Tertiary System Gas 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: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title:Contact Phone: 54 324-045 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 1861 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Ryan Rupert Ryan.Rupert@hilcorp.com 907 777-8503Operations Manager N/A 407 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 407 N/A 108 Size 407 2,535 213 1091524 0 53246 13-3/8" 9-5/8" 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 197-210 50-883-20090-01-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0017589 North Cook Inlet / Tertiary System Gas N Cook Inlet Unit B-02 Plugs Junk measured Length measured TVD Liner Liner 11,086 2,784 935 Casing Structural 10,224 12,460 3-1/2" 11,086 13,522 14,457 13,306 2,602 8,909 2,602Conductor Surface Production 30" 20" 7,930psi 10,870psi 5,380psi 10,900psi 11,640psi 8,909 8,123 Burst Collapse 2,670psi Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 2:13 pm, Mar 22, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.03.21 15:56:37 - 08'00' Dan Marlowe (1267) RBDMS JSB 040224 DSR-3/29/24 _____________________________________________________________________________________ Updated By JLL 03/21/24 SCHEMATIC Well: NCI B-02 (Sidetrack from Sunfish #3) Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 PBTD: 7,330’ TD: 14,537’ 20” RKB = 59’ RKB to MSL = 132’, MLLW toMudline = 100’ 7” TBG punch 7,545’ H I 7 6 8 E F Stg Tool @ 4,045’ 13-3/8” 9-5/8” 5 1 3-1/2” 2 3 4 TOC @ 12,054’ WLM G 30” Stg Tool @ 7,385’ Tubing Punch @ 13,140’ – 13,142’ J K Sunfish N Forelands CI 8 Lwr CI 9 CI10 CI 11 Beluga A Beluga C Beluga D Beluga E Beluga F Beluga G Beluga B Tbg Cut 8,025’ Long String & 7,800’ Short String L M N O P Q R Beluga L Proposed X X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 4,802’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 359’ 359’ 3.813 5.510 Halliburton SVLN (WL-SSSV –Installed 3/11/23) 2 4,554’ 4,263’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 3 4,767’ 4,454’ 3.810 5.500 Sliding sleeve (Up to open)CLOSED as of 5/23/22 4 4,781’ 4,467’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 5 4,800’ 4,484’ 3.810 5.000 X nipple 6 4,802’ 4,486’ 3.958 4.500 WLEG 7 7,500’ 6,886’ - 8.125 Cement Retainer –TOC 7,330’ 8 7,604’ 6,977’ - 8.125 CIBP PERFORATION DETAIL Zone Top (MD)Btm (MD) Top (TVD) Btm (TVD) FT Date Status C.I. 8 Lower 4,584’ 4,596’ 4,290’ 4,301’ 12’ 05/28/21 Isolated 5/23/22 C.I. 9 4,615’ 4,623’ 4,318’ 4,325’ 8’ 05/28/21 Isolated 5/23/22 C.I. 9 4,665’ 4,673’ 4,363’ 4,370’ 8’ 05/28/21 Isolated 5/23/22 C.I. 10 4,694’ 4,710’ 4,389’ 4,403’ 16’ 05/27/21 Isolated 5/23/22 C.I. 11 4,742’ 4,762’ 4,432’ 4,450’ 20’ 05/27/21 Isolated 5/23/22 Beluga A 4,799’ 4,809’ 4,483’ 4,492’ 10’ 07/03/21 Open Beluga A Lwr 4,840’ 4,856’ 4,520’ 4,534’ 16’ 05/24/22 Open Beluga B Upr 4,892’ 4,898’ 4,567’ 4,572’ 6’ 05/24/22 Open Beluga B Mid 4,961’ 4,981’ 4,629’ 4,647’ 20’ 05/24/22 Open Beluga B Lwr 5,037’ 5,046’ 4,697’ 4,705’ ±9’ 05/24/22 Open Beluga C Lwr 5,143’ 5,148’ 4,793’ 4,798’ ±5’ 05/24/22 Open Beluga C 5,153’ 5,163’ 4,802’ 4,811’ 10’ 07/03/21 Open Beluga Da 5,170' 5,175' 4,633' 4,637' 5' 03/09/24 Open Beluga D 5,192’ 5,210’ 4,837’ 4,854’ 18’ 07/03/21 Open Beluga D 5,232’ 5,237’ 4,873’ 4,878’ 5’ 07/03/21 Open Beluga D 5,244’ 5,248’ 4,884’ 4,888’ 4’ 07/03/21 Open Beluga D 5,279’ 5,287’ 4,916’ 4,923’ 8’ 07/03/21 Open Beluga E 5,348’ 5,355’ 4,978’ 4,985’ 7’ 07/03/21 Open Beluga Eb 5,367' 5,373' 4,815' 4,820' 6' 03/09/24 Open Beluga E 5,377’ 5,391’ 5,004’ 5,017’ 14’ 07/03/21 Open Beluga E 5,409’ 5,416’ 5,033’ 5,040’ 7’ 07/02/21 Open Beluga E 5,449’ 5,469’ 5,069’ 5,087’ 20’ 07/02/21 Open Beluga Fa 5,497' 5,500' 4,936' 4,938' 3' 03/09/24 Open Beluga Fb 5,520' 5,527' 4,957' 4,963' 7' 03/09/24 Open Beluga F 5,554’ 5,562’ 5,164’ 5,171’ 8’ 07/02/21 Open Beluga F 5,598’ 5,604’ 5,204’ 5,209’ 6’ 07/02/21 Open Beluga G 5,612’ 5,622’ 5,216’ 5,225’ 10’ 07/02/21 Open Beluga L 6,187’ 6,205’ 5,730’ 5,746’ 18’ 03/08/23 Open GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,656’ 1,647’ 3.937 Camco MMG 1.5"24 DOME 805 5/29/2021 2 3,083’ 2,965’ 3.937 Camco MMG 1.5"24 DOME 773 5/29/2021 3 4,402’ 4,128’ 3.937 Camco MMG 1.5" w/1/2" Orifice 32 ORIFICE 5/29/2021 _____________________________________________________________________________________ Updated By: JLL 03/21/24 SCHEMATIC North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 OPEN HOLE / CEMENT DETAIL 20"24” Hole: Pumped 600bbls 12.8ppg class G lead followed by 124bbls 15.8ppg class G tail cement. 1” top job tagged cement 23’ below wellhead, and pumped 30sxs to bring ToC to surface. 13-3/8" 17-1/2” hole: Primary job pumped 900sxs (336bbls) 12.5ppg class G lead cement followed by 700sxs (144bbls) 15.8ppg class G tail cement. 2nd stage through DV at 7380’: Pumped 3700sxs (771bbls) of 15.8ppg class G. 117bbls cement circulated back to surface. Two subsequent 50sxs squeezes. 11/30/97 RTTS showed a leak somewhere between 4100’ – 7415’ (likely lower DV at 7380’ MD leaking) 3rd stage through DV at 4048’: Pumped 1000sxs (206bbls) of 15.8ppg class G. 10bbls cement returned to surface. One subsequent 100sxs squeeze. 11/30/97 RTTS set at 4100’ passed an MIT above. Fully cemented 13-3/8” casing from 8,909’ (shoe) to surface 9-5/8” 12-1/4” hole: Pumped 106bbls 15.8ppg class G cement. Volumetric ToC calculated assuming 30% washout = 9975’. 5/24/21 Annular cement job. Cement was circulated into the 9-5/8” x 13-3/8” annulus through punch holes at 7545’. 233bls 15.3ppg cement circulated in annulus bringing estimated ToC to 3,590’. ISOLATED TUBING / JEWELRY TUBING DETAIL 2-7/8” 6.5 L-80 CS Hydril 2.441” 8,025’ 10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection 7,800’ 13,530’ JEWELRY DETAIL Short String No Depth (MD) Depth (TVD)ID OD Item L 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM M 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM N 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM O 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer P 10,613’ 9,771’ 2.313” HES X Nipple Q 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set R 10,625’ 9,782’ 2.441” WLEG Long String E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug Isolated Perforations Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated Well Name:NCIU B-02 API #:50883200900100 Field:North Cook Inlet Unit Start Date:3/9/2024 Permit #:197210 Sundry #:324-045 End Date:3/9/2024 3/9/2024 Well Operations Summary MIRU AK EL. PT 250/2500 PSI good. RIH w/ GPT. Tag fill 5645'. POOH. RIH w/ Gun 1-Switch- Gun 2. Perforate Fb zone 5520' to 5527'. Switch. Perforate Fa zone 5497' to 5500'. POOH. RIH w/ Gun 3-Switch- Gun 4. Perforate Eb zone 5367' to 5373'. Switch. Perforate Da zone 5170' to 5175'. POOH. RDMO AK EL. Daily Operations: Page 1 of 1 _____________________________________________________________________________________ Updated By JLL 03/21/24 SCHEMATIC Well: NCI B-02 (Sidetrack from Sunfish #3) Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 PBTD: 7,330’ TD: 14,537’ 20” RKB = 59’ RKB to MSL = 132’, MLLW toMudline = 100’ 7” TBG punch 7,545’ H I 7 6 8 E F Stg Tool @ 4,045’ 13-3/8” 9-5/8” 5 1 3-1/2” 2 3 4 TOC @ 12,054’ WLM G 30” Stg Tool @ 7,385’ Tubing Punch @ 13,140’ – 13,142’ J K Sunfish N Forelands CI 8 -10 Beluga A Beluga C Beluga D Beluga E Beluga F Beluga G Beluga B Tbg Cut 8,025’ Lon String & 7,800’ Sho String L-N O P-R K Beluga L X X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 4,802’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 359’ 359’ 3.813 5.510 Halliburton SVLN (WL-SSSV –Installed 3/11/23) 2 4,554’ 4,263’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 3 4,767’ 4,454’ 3.810 5.500 Sliding sleeve (Up to open)CLOSED as of 5/23/22 4 4,781’ 4,467’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 5 4,800’ 4,484’ 3.810 5.000 X nipple 6 4,802’ 4,486’ 3.958 4.500 WLEG 7 7,500’ 6,886’ - 8.125 Cement Retainer –TOC 7,330’ 8 7,604’ 6,977’ - 8.125 CIBP PERFORATION DETAIL Zone Top (MD)Btm (MD) Top (TVD) Btm (TVD) FT Date Status C.I. 8 Lower 4,584’ 4,596’ 4,290’ 4,301’ 12’ 05/28/21 Isolated 5/23/22 C.I. 9 4,615’ 4,623’ 4,318’ 4,325’ 8’ 05/28/21 Isolated 5/23/22 C.I. 9 4,665’ 4,673’ 4,363’ 4,370’ 8’ 05/28/21 Isolated 5/23/22 C.I. 10 4,694’ 4,710’ 4,389’ 4,403’ 16’ 05/27/21 Isolated 5/23/22 C.I. 11 4,742’ 4,762’ 4,432’ 4,450’ 20’ 05/27/21 Isolated 5/23/22 Beluga A 4,799’ 4,809’ 4,483’ 4,492’ 10’ 07/03/21 Open Beluga A Lwr 4,840’ 4,856’ 4,520’ 4,534’ 16’ 05/24/22 Open Beluga B Upr 4,892’ 4,898’ 4,567’ 4,572’ 6’ 05/24/22 Open Beluga B Mid 4,961’ 4,981’ 4,629’ 4,647’ 20’ 05/24/22 Open Beluga B Lwr 5,037’ 5,046’ 4,697’ 4,705’ ±9’ 05/24/22 Open Beluga C Lwr 5,143’ 5,148’ 4,793’ 4,798’ ±5’ 05/24/22 Open Beluga C 5,153’ 5,163’ 4,802’ 4,811’ 10’ 07/03/21 Open Beluga Da 5,170' 5,175' 4,633' 4,637' 5' 03/09/24 Open Beluga D 5,192’ 5,210’ 4,837’ 4,854’ 18’ 07/03/21 Open Beluga D 5,232’ 5,237’ 4,873’ 4,878’ 5’ 07/03/21 Open Beluga D 5,244’ 5,248’ 4,884’ 4,888’ 4’ 07/03/21 Open Beluga D 5,279’ 5,287’ 4,916’ 4,923’ 8’ 07/03/21 Open Beluga E 5,348’ 5,355’ 4,978’ 4,985’ 7’ 07/03/21 Open Beluga Eb 5,367' 5,373' 4,815' 4,820' 6' 03/09/24 Open Beluga E 5,377’ 5,391’ 5,004’ 5,017’ 14’ 07/03/21 Open Beluga E 5,409’ 5,416’ 5,033’ 5,040’ 7’ 07/02/21 Open Beluga E 5,449’ 5,469’ 5,069’ 5,087’ 20’ 07/02/21 Open Beluga Fa 5,497' 5,500' 4,936' 4,938' 3' 03/09/24 Open Beluga Fb 5,520' 5,527' 4,957' 4,963' 7' 03/09/24 Open Beluga F 5,554’ 5,562’ 5,164’ 5,171’ 8’ 07/02/21 Open Beluga F 5,598’ 5,604’ 5,204’ 5,209’ 6’ 07/02/21 Open Beluga G 5,612’ 5,622’ 5,216’ 5,225’ 10’ 07/02/21 Open Beluga L 6,187’ 6,205’ 5,730’ 5,746’ 18’ 03/08/23 Open GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,656’ 1,647’ 3.937 Camco MMG 1.5"24 DOME 805 5/29/2021 2 3,083’ 2,965’ 3.937 Camco MMG 1.5"24 DOME 773 5/29/2021 3 4,402’ 4,128’ 3.937 Camco MMG 1.5" w/1/2" Orifice 32 ORIFICE 5/29/2021 _____________________________________________________________________________________ Updated By: JLL 03/21/24 SCHEMATIC North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 OPEN HOLE / CEMENT DETAIL 20"24” Hole: Pumped 600bbls 12.8ppg class G lead followed by 124bbls 15.8ppg class G tail cement. 1” top job tagged cement 23’ below wellhead, and pumped 30sxs to bring ToC to surface. 13-3/8" 17-1/2” hole: Primary job pumped 900sxs (336bbls) 12.5ppg class G lead cement followed by 700sxs (144bbls) 15.8ppg class G tail cement. 2nd stage through DV at 7380’: Pumped 3700sxs (771bbls) of 15.8ppg class G. 117bbls cement circulated back to surface. Two subsequent 50sxs squeezes. 11/30/97 RTTS showed a leak somewhere between 4100’ – 7415’ (likely lower DV at 7380’ MD leaking) 3rd stage through DV at 4048’: Pumped 1000sxs (206bbls) of 15.8ppg class G. 10bbls cement returned to surface. One subsequent 100sxs squeeze. 11/30/97 RTTS set at 4100’ passed an MIT above. Fully cemented 13-3/8” casing from 8,909’ (shoe) to surface 9-5/8” 12-1/4” hole: Pumped 106bbls 15.8ppg class G cement. Volumetric ToC calculated assuming 30% washout = 9975’. 5/24/21 Annular cement job. Cement was circulated into the 9-5/8” x 13-3/8” annulus through punch holes at 7545’. 233bls 15.3ppg cement circulated in annulus bringing estimated ToC to 3,590’. ISOLATED TUBING / JEWELRY TUBING DETAIL 2-7/8” 6.5 L-80 CS Hydril 2.441” 8,025’ 10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection 7,800’ 13,530’ JEWELRY DETAIL Short String No Depth (MD) Depth (TVD)ID OD Item L 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM M 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM N 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM O 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer P 10,613’ 9,771’ 2.313” HES X Nipple Q 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set R 10,625’ 9,782’ 2.441” WLEG Long String E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug Isolated Perforations Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated _____________________________________________________________________________________ Updated By JLL 01/31/25 PROPOSED Well: NCI B-02 (Sidetrack from Sunfish #3) Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 PBTD: 7,330’ TD: 14,537’ 20” RKB = 59’ RKBto MSL = 132’, MLLW to Mudline = 100’ 7” TBG punch 7,545’ H I 7 6 8 E F Stg Tool @ 4,045’ 13-3/8” 9-5/8” 5 1 3-1/2” 2 3 4 TOC @ 12,054’ WLM G 30” Stg Tool @ 7,385’ Tubing Punch @ 13,140’ – 13,142’ J K Sunfish N Forelands CI 8 -10 Beluga A Beluga C Beluga D Beluga E Beluga F Beluga G Beluga B Tbg Cut 8,025’Lon String & 7,800’Sho String L-N O P-R K Beluga L X X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 4,802’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 359’ 359’ 3.813 5.510 Halliburton SVLN (WL-SSSV –Installed 3/11/23) 2 4,554’ 4,263’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 3 4,767’ 4,454’ 3.810 5.500 Sliding sleeve (Up to open)CLOSED as of 5/23/22 4 4,781’ 4,467’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 5 4,800’ 4,484’ 3.810 5.000 X nipple 6 4,802’ 4,486’ 3.958 4.500 WLEG 7 7,500’ 6,886’ - 8.125 Cement Retainer –TOC 7,330’ 8 7,604’ 6,977’ - 8.125 CIBP PERFORATION DETAIL Zone Top (MD)Btm (MD) Top (TVD) Btm (TVD) FT Date Status BEL ±4,800’ ±7,300’ ±4,486 ±6,701’ ±2,500’ Future Proposed C.I. 8 Lower 4,584’ 4,596’ 4,290’ 4,301’ 12’ 05/28/21 Isolated 5/23/22 C.I. 9 4,615’ 4,623’ 4,318’ 4,325’ 8’ 05/28/21 Isolated 5/23/22 C.I. 9 4,665’ 4,673’ 4,363’ 4,370’ 8’ 05/28/21 Isolated 5/23/22 C.I. 10 4,694’ 4,710’ 4,389’ 4,403’ 16’ 05/27/21 Isolated 5/23/22 C.I. 11 4,742’ 4,762’ 4,432’ 4,450’ 20’ 05/27/21 Isolated 5/23/22 Beluga A 4,799’ 4,809’ 4,483’ 4,492’ 10’ 07/03/21 Open Beluga A Lwr 4,840’ 4,856’ 4,520’ 4,534’ 16’ 05/24/22 Open Beluga B Upr 4,892’ 4,898’ 4,567’ 4,572’ 6’ 05/24/22 Open Beluga B Mid 4,961’ 4,981’ 4,629’ 4,647’ 20’ 05/24/22 Open Beluga B Lwr 5,037’ 5,046’ 4,697’ 4,705’ ±9’ 05/24/22 Open Beluga C Lwr 5,143’ 5,148’ 4,793’ 4,798’ ±5’ 05/24/22 Open Beluga C 5,153’ 5,163’ 4,802’ 4,811’ 10’ 07/03/21 Open Beluga Da 5,170' 5,175' 4,633' 4,637' 5' 03/09/24 Open Beluga D 5,192’ 5,210’ 4,837’ 4,854’ 18’ 07/03/21 Open Beluga D 5,232’ 5,237’ 4,873’ 4,878’ 5’ 07/03/21 Open Beluga D 5,244’ 5,248’ 4,884’ 4,888’ 4’ 07/03/21 Open Beluga D 5,279’ 5,287’ 4,916’ 4,923’ 8’ 07/03/21 Open Beluga E 5,348’ 5,355’ 4,978’ 4,985’ 7’ 07/03/21 Open Beluga Eb 5,367' 5,373' 4,815' 4,820' 6' 03/09/24 Open Beluga E 5,377’ 5,391’ 5,004’ 5,017’ 14’ 07/03/21 Open Beluga E 5,409’ 5,416’ 5,033’ 5,040’ 7’ 07/02/21 Open Beluga E 5,449’ 5,469’ 5,069’ 5,087’ 20’ 07/02/21 Open Beluga Fa 5,497' 5,500' 4,936' 4,938' 3' 03/09/24 Open Beluga Fb 5,520' 5,527' 4,957' 4,963' 7' 03/09/24 Open Beluga F 5,554’ 5,562’ 5,164’ 5,171’ 8’ 07/02/21 Open Beluga F 5,598’ 5,604’ 5,204’ 5,209’ 6’ 07/02/21 Open Beluga G 5,612’ 5,622’ 5,216’ 5,225’ 10’ 07/02/21 Open Beluga L 6,187’ 6,205’ 5,730’ 5,746’ 18’ 03/08/23 Open GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,656’ 1,647’ 3.937 Camco MMG 1.5"24 DOME 805 5/29/2021 2 3,083’ 2,965’ 3.937 Camco MMG 1.5"24 DOME 773 5/29/2021 3 4,402’ 4,128’ 3.937 Camco MMG 1.5" w/1/2" Orifice 32 ORIFICE 5/29/2021 6538' TVD deepest -bjm _____________________________________________________________________________________ Updated By: JLL 01/31/25 PROPOSED North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 OPEN HOLE / CEMENT DETAIL 20"24” Hole: Pumped 600bbls 12.8ppg class G lead followed by 124bbls 15.8ppg class G tail cement. 1” top job tagged cement 23’ below wellhead, and pumped 30sxs to bring ToC to surface. 13-3/8" 17-1/2” hole: Primary job pumped 900sxs (336bbls) 12.5ppg class G lead cement followed by 700sxs (144bbls) 15.8ppg class G tail cement. 2nd stage through DV at 7380’: Pumped 3700sxs (771bbls) of 15.8ppg class G. 117bbls cement circulated back to surface. Two subsequent 50sxs squeezes. 11/30/97 RTTS showed a leak somewhere between 4100’ – 7415’ (likely lower DV at 7380’ MD leaking) 3rd stage through DV at 4048’: Pumped 1000sxs (206bbls) of 15.8ppg class G. 10bbls cement returned to surface. One subsequent 100sxs squeeze. 11/30/97 RTTS set at 4100’ passed an MIT above. Fully cemented 13-3/8” casing from 8,909’ (shoe) to surface 9-5/8” 12-1/4” hole: Pumped 106bbls 15.8ppg class G cement. Volumetric ToC calculated assuming 30% washout = 9975’. 5/24/21 Annular cement job. Cement was circulated into the 9-5/8” x 13-3/8” annulus through punch holes at 7545’. 233bls 15.3ppg cement circulated in annulus bringing estimated ToC to 3,590’. ISOLATED TUBING / JEWELRY TUBING DETAIL 2-7/8” 6.5 L-80 CS Hydril 2.441” 8,025’ 10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection 7,800’ 13,530’ JEWELRY DETAIL Short String No Depth (MD) Depth (TVD)ID OD Item L 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM M 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM N 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM O 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer P 10,613’ 9,771’ 2.313” HES X Nipple Q 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set R 10,625’ 9,782’ 2.441” WLEG Long String E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug Isolated Perforations Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated KLU A-1 Well Head Rig Up 1 1 1 1 4 1/16" 15K Lubricator - 10 ft 100" Gooseneck HR680 Injector Head 4 1/16" 10K Flow Cross, 2" 1502 10k Flanged Valves 4 1/16" 15K Lubricator - 10 ft API Flange Adapter 10K to 5K for riser/wellhead Hydraulic Stripper 4 1/6" 15K API Bowen CB56 15K 4 1/16" 10K Combi BOPs Blind/Shear Ram Pipe/Slip Ram 4 1/16" 10K bottom flange 4 1/16" 5K flanged Riser - 10 ft if necessary 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. 1 McLellan, Bryan J (OGC) From:Eric Dickerman <Eric.Dickerman@hilcorp.com> Sent:Friday, February 14, 2025 4:26 PM To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] NCIU B-02 (PTD 197-210) Perf sundry Hey Bryan, I apologize it took a while to respond. The FIT for the 20” was taken up to 12.0ppg and the FIT for the 13-3/8” was taken up to 14.8 ppg. Here is what I came up with. The boƩom perf TVD from the Geologist is 6,538’ tvd (they Ɵghtened up the interval aŌer I submiƩed the Sundry). 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. 2 3 Thank you, Eric Dickerman Hilcorp – CIO Ops Engineer Cell: 307-250-4013 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, February 10, 2025 3:13 PM To: Eric Dickerman <Eric.Dickerman@hilcorp.com> Subject: [EXTERNAL] NCIU B-02 (PTD 197-210) Perf sundry Eric, What was the FIT/LOT pressure at the 20” and 13-3/8” casing shoes? CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 4 Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/10/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240510-1 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 242-04 50283201640000 212041 3/11/2024 AK E-LINE Perf LRU C-01RD 50283200610100 201168 4/26/2024 AK E-LINE Perf LRU C-02 50283201900000 223057 4/28/2024 AK E-LINE Perf MPU F-65 50029227526000 223121 5/3/2024 AK E-LINE HoistCut MPU L-07 50029220280000 190037 4/26/2024 AK E-LINE Perf NCIU A-17 50883201880000 223031 4/28/2024 AK E-LINE GPT/Perf NCIU B-02 50883200900100 197210 4/29/2024 AK E-LINE PPROF NCIU B-02 50883200900100 197210 5/4/2024 AK E-LINE PPROF PAXTON 6 50133207070000 222054 4/13/2024 AK E-LINE GPT/CIBP/Perf PAXTON 6 50133207070000 222054 4/16/2024 AK E-LINE GPT/CIBP/Perf SRU 14B-27 50133206040000 212089 4/23/2024 AK E-LINE Caliper SRU 32C-15 50133206130000 213070 4/24/2024 AK E-LINE Caliper TBU M-15 50733204220000 190109 4/18/2024 AK E-LINE GPT/Puncher TBU M-23 50733207190000 224018 5/1/2024 AK E-LINE CBL Please include current contact information if different from above. T38780 T38781 T38782 T38783 T38784 T38785 T38786 T38786 T38787 T38787 T38788 T38789 T38790 T38791 NCIU B-02 50883200900100 197210 4/29/2024 AK E-LINE PPROF NCIU B-02 50883200900100 197210 5/4/2024 AK E-LINE PPROF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.05.13 15:31:19 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/15/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240315 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 12/6/2023 AK E-LINE Cement-JetCut BCU 13 50133205250000 203138 2/11/2024 AK E-LINE CIBP-Perf BCU 19RD 50133205790100 219188 2/20/2024 AK E-LINE Perf-CIBP BRU 232-26 50283200770000 184138 11/26/2023 AK E-LINE GPT-PLUG-PERF BRU 244-27 50283201850000 222038 2/27/2024 AK E-LINE GPT-Perf GP ST 18742 37 (AN- 37) 50733203940000 187109 11/22/2023 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 11/3/2023 AK E-LINE GPT-PERF KBU 42-6 50133205460000 204209 2/16/2024 AK E-LINE Patch PBU L-122 50029231470000 203051 12/7/2023 AK E-LINE Patch NCIU A-12B 50883200320200 223053 12/6/2023 AK E-LINE Perf-GPT NCIU A-17 50883201880000 223031 12/10/2023 AK E-LINE Perf-GPT NCIU B-02 50883200900100 197210 3/9/2024 AK E-LINE GPT-Perf SRU 241-33B 50133206960000 221053 3/6/2024 AK E-LINE GPT-Cmnt-CIBP- Perf Please include current contact information if different from above. T38630 T38630 T38631 T38632 T38633 T38634 T38635 T38636 T38637 T38638 T38639 T38640 T38641 NCIU B-02 50883200900100 197210 3/9/2024 AK E-LINE GPT-Perf Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.18 08:49:06 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 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): 14,537 N/A Casing Collapse Structural Conductor Surface 2,670psi Production 7,930psi Liner 10,870psi 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 2/14/2024 14,457'935' 4-1/2", 2-7/8", 3-1/2" 13,309' See schematic See schematic 13,522' Perforation Depth MD (ft): 11,086' 4,799 - 6,205 2,784' 3-1/2" 4,483 - 5,746 12,460'7" 407' 30" 20" 13-3/8" 2,602' 9-5/8"11,086' 8,909' MD 10,900psi 5,380psi 2,535' 8,123' 10,224' 2,602' 8,909' Length Size Proposed Pools: 407' 407' L-80 TVD Burst 4,802, 10,626, 13,530 11,640psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 197-210 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20090-01-00 Hilcorp Alaska, LLC N Cook Inlet Unit B-02 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 13,377 7,330 6,737 2,432psi 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 324-045 By Kayla Junke at 9:37 am, Feb 02, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.02.01 06:30:45 - 09'00' Dan Marlowe (1267) Perforate DSR-2/12/24SFD 2/5/2024BJM 2/5/24 10-404 *&:JLC 2/12/2024 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.02.13 10:48:23 -06'00'02/13/24 RBDMS JSB 021324 Perfs Well: NCIU B-02 Well Name:NCIU B-02 (sidetrack from Sunfish-3) API Number:50-883-20090-01-00 Current Status:Online gas well Leg:Leg #1 (NW corner) Regulatory Contact:Juanita Lovett (8332)Permit to Drill Number:197-210 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:3,010 psi @ 5,788’ TVD 0.52psi/ft to deepest proposed Max. Potential Surface Pressure: 2432 psi Using 0.1 psi/ft Brief Well Summary NCIU B-02 on the Tyonek platform is a Tertiary System Gas Pool producer open in several sands currently. There are some potential bypassed sands to complete still available. All existing and proposed perfs are within the Tertiary Gas System Pool The goal of this project is to add infill perfs Pertinent wellbore information: - SSSV: WL retrievable - Inclination all <30 degrees above PBTD - 5/24/22: SL D&T to 6955’ MD with a 3.8” gauge ring - 2/28/23: o Confirm SSD closed o Tag at 6388' o Bail to 6404' over 1.5 days (doesn't appear to be a bridge) - 3/8/23: EL perfs BEL-L with 21’ carrier of 2-3/4” gun. No issues - 3/11/23: SL tags at 6221’ MD Perfs Well: NCIU B-02 E-Line Perf procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 2500psi high 3. RIH and perforate sands from ±4,799 - ±6,252’ MD (±4,483’ - ±5,788’ TVD) per RE/Geo 4. RDMO EL CONTINGENCY: (if any zone makes unwanted solids or water) 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 2500psi high 3. RIH and set expandable plug per RE/Geo 4. Cap plug with cement if necessary (all within same pool) 5. RDMO EL NOTE: WL-SSSV will need to be pulled, and reinstalled. It must be tested within 14 days of the well being returned to production Attachments: 1. Proposed Wellbore Schematic _____________________________________________________________________________________ Updated By JLL 01/30/24 PROPOSED Well: NCI B-02 (Sidetrack from Sunfish #3) Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 PBTD: 7,330’ TD: 14,537’ 20” RKB = 59’ RKB to MSL = 132’, MLLW toMudline = 100’ 7” TBG punch 7,545’ H I 7 6 8 E F Stg Tool @ 4,045’ 13-3/8” 9-5/8” 5 1 3-1/2” 2 3 4 TOC @ 12,054’ WLM G 30” Stg Tool @ 7,385’ Tubing Punch @ 13,140’ – 13,142’ J K Sunfish N Forelands CI 8 Lwr CI 9 CI10 CI 11 Beluga A Beluga C Beluga D Beluga E Beluga F Beluga G Beluga B Tbg Cut 8,025’ Long String & 7,800’ Short String L M N O P Q R Beluga L Proposed X X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 4,802’ 2-7/8” 6.5 L-80 CS Hydril 2.441” 8,025’ 10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection 7,800’ 13,530’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 359’ 359’ 3.813 5.510 Halliburton SVLN (WL-SSSV – Installed 3/11/23) 2 4,554’ 4,263’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 3 4,767’ 4,454’ 3.810 5.500 Sliding sleeve (Up to open)CLOSED as of 5/23/22 4 4,781’ 4,467’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 5 4,800’ 4,484’ 3.810 5.000 X nipple 6 4,802’ 4,486’ 3.958 4.500 WLEG 7 7,500’ 6,886’ - 8.125 Cement Retainer –TOC 7,330’ 8 7,604’ 6,977’ - 8.125 CIBP PERFORATION DETAIL Zone Top (MD)Btm (MD) Top (TVD) Btm (TVD) FT Date Status C.I. 8 Lower 4,584’ 4,596’ 4,290’ 4,301’ 12’ 05/28/21 Isolated 5/23/22 C.I. 9 4,615’ 4,623’ 4,318’ 4,325’ 8’ 05/28/21 Isolated 5/23/22 C.I. 9 4,665’ 4,673’ 4,363’ 4,370’ 8’ 05/28/21 Isolated 5/23/22 C.I. 10 4,694’ 4,710’ 4,389’ 4,403’ 16’ 05/27/21 Isolated 5/23/22 C.I. 11 4,742’ 4,762’ 4,432’ 4,450’ 20’ 05/27/21 Isolated 5/23/22 Beluga ±4,799' ±6,252' ±4,483' ±5,788' ±1,453' Future Proposed Beluga A 4,799’ 4,809’ 4,483’ 4,492’ 10’ 07/03/21 Open Beluga A Lwr 4,840’ 4,856’ 4,520’ 4,534’ 16’ 05/24/22 Open Beluga B Upr 4,892’ 4,898’ 4,567’ 4,572’ 6’ 05/24/22 Open Beluga B Mid 4,961’ 4,981’ 4,629’ 4,647’ 20’ 05/24/22 Open Beluga B Lwr 5,037’ 5,046’ 4,697’ 4,705’ ±9’ 05/24/22 Open Beluga C Lwr 5,143’ 5,148’ 4,793’ 4,798’ ±5’ 05/24/22 Open Beluga C 5,153’ 5,163’ 4,802’ 4,811’ 10’ 07/03/21 Open Beluga D 5,192’ 5,210’ 4,837’ 4,854’ 18’ 07/03/21 Open Beluga D 5,232’ 5,237’ 4,873’ 4,878’ 5’ 07/03/21 Open Beluga D 5,244’ 5,248’ 4,884’ 4,888’ 4’ 07/03/21 Open Beluga D 5,279’ 5,287’ 4,916’ 4,923’ 8’ 07/03/21 Open Beluga E 5,348’ 5,355’ 4,978’ 4,985’ 7’ 07/03/21 Open Beluga E 5,377’ 5,391’ 5,004’ 5,017’ 14’ 07/03/21 Open Beluga E 5,409’ 5,416’ 5,033’ 5,040’ 7’ 07/02/21 Open Beluga E 5,449’ 5,469’ 5,069’ 5,087’ 20’ 07/02/21 Open Beluga F 5,554’ 5,562’ 5,164’ 5,171’ 8’ 07/02/21 Open Beluga F 5,598’ 5,604’ 5,204’ 5,209’ 6’ 07/02/21 Open Beluga G 5,612’ 5,622’ 5,216’ 5,225’ 10’ 07/02/21 Open Beluga L 6,187’ 6,205’ 5,730’ 5,746’ 18’ 03/08/23 Open Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,656’ 1,647’ 3.937 Camco MMG 1.5"24 DOME 805 5/29/2021 2 3,083’ 2,965’ 3.937 Camco MMG 1.5"24 DOME 773 5/29/2021 3 4,402’ 4,128’ 3.937 Camco MMG 1.5" w/1/2" Orifice 32 ORIFICE 5/29/2021 _____________________________________________________________________________________ Updated By: JLL 01/30/24 PROPOSED North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 OPEN HOLE / CEMENT DETAIL 20"24” Hole: Pumped 600bbls 12.8ppg class G lead followed by 124bbls 15.8ppg class G tail cement. 1” top job tagged cement 23’ below wellhead, and pumped 30sxs to bring ToC to surface. 13-3/8" 17-1/2” hole: Primary job pumped 900sxs (336bbls) 12.5ppg class G lead cement followed by 700sxs (144bbls) 15.8ppg class G tail cement. 2nd stage through DV at 7380’: Pumped 3700sxs (771bbls) of 15.8ppg class G. 117bbls cement circulated back to surface. Two subsequent 50sxs squeezes. 11/30/97 RTTS showed a leak somewhere between 4100’ – 7415’ (likely lower DV at 7380’ MD leaking) 3rd stage through DV at 4048’: Pumped 1000sxs (206bbls) of 15.8ppg class G. 10bbls cement returned to surface. One subsequent 100sxs squeeze. 11/30/97 RTTS set at 4100’ passed an MIT above. Fully cemented 13-3/8” casing from 8,909’ (shoe) to surface 9-5/8” 12-1/4” hole: Pumped 106bbls 15.8ppg class G cement. Volumetric ToC calculated assuming 30% washout = 9975’. 5/24/21 Annular cement job. Cement was circulated into the 9-5/8” x 13-3/8” annulus through punch holes at 7545’. 233bls 15.3ppg cement circulated in annulus bringing estimated ToC to 3,590’. ISOLATED JEWELRY Short String No Depth (MD) Depth (TVD)ID OD Item L 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM M 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM N 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM O 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer P 10,613’ 9,771’ 2.313” HES X Nipple Q 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set R 10,625’ 9,782’ 2.441” WLEG Long String E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug STATE OF ALASKA RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION [By Kayla Junke at 1:35 pm, Mar 29, 2023 REPORT OF SUNDRY WELL OPERATIONS 1. Operations Susp Well Insp ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing ❑ Operations shutdown ❑ Performed: Install Whipstock ❑ Perforate ❑� Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Mod Artificial Lift ❑ Perforate New Pool ❑ Repair Well ❑ Coiled Tubing Ops ❑ Other: ❑ 2. Operator Name 4. Well Class Before Work: 15. Permit to Drill Number: Hilcorp Alaska, LLC Development ElExploratory ❑� Stratigraphic ❑ Service ❑ 197-210 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-883-20090-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0017569 N Cook Inlet Unit B-02 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): WA North Cook Inlet / Tertiary System Gas 11. Present Well Condition Summary: Total Depth measured 14,537 feet Plugs measured See schematic feet true vertical 13,377 feet Junk measured N/A feet Effective Depth measured 7,330 feet Packer measured 4,554 & 4,781 feet true vertical 6,737 feet true vertical 4,263 & 4,467 feet Casing Length Size MD TVD Burst Collapse Structural 407 30" 407 407 Conductor 2,602 20" 2,602 2,535 Surface 8,909 13-3/8" 8,909 8,123 5,380psi 2,670psi Production 11,086 9-5/8" 11,086 10,224 10,900psi 7,930psi Liner 2,784 7" 13,522 12,460 11,640psi 10,870psi Liner 935 3-1/2" 14,457 13,306 Perforation depth Measured depth 4,584 - 6,205 feet True Vertical depth 4,290 - 5,746 feet 4-1/2" 12.6 / L-80 4,802 (MD) 4,486 (TVD) Tubing (size, grade, measured and We vertical depth) 2-7/8" 6.5 / L-80 10,626 (MD) 9,783 (TVD) 3-1/2" 12.95 / L-80 13,530 (MD) 12,443 (TVD) Packers and SSSV (type, measured and true vertical depth) See schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): WA Treatment descriptions including volumes used and final pressure: N/A 13a. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 2512 205 111 62 Subsequent to operation: 0 4302 0 174 1135 13b. Pools active after work: Tertiary System Gas 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations ❑✓ Exploratory 0 Development ❑ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas WDSPL LJ Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: N signed by Dan Matlme 323-107 Dan Marlowe (1267) Authorized Name and (1267) DN c D.b M.M (1262). =u..r, Digital Signature with Date: Data 2023ar.290950:21 a8VO' Contact Name: Ryan Rupert Contact Email: RVan.RUDert@hllC rP-Com Authorized Title: Operations Manager Contact Phone: 907 777-8503 Sr Pet Eng: Isr Pet Geo: I ISr Res Eng: DSR-3/31/23 RBDMS JSB 033023 Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov K Hilcorp Alaska, LLC Praprced RKB=59 RkBbVIR 132, MLLWto Mldllne=100' 30' . 1 20 ' 2 %Tod Cl 8 Lw @4,015 Cl9 Clio 3 Cl 11 4 x 5 Beluga A 6 Beluga B Beluga C Beluga D Beluga E Beluga F Beluga G Beluga L StgTwI @7,355' 133/B' c 9 5/8" TOC@12,054' VIJA Tubing Punch @ 13,140-13,142' H T' I J K 9mFish N Forelands i uz PBTD: 7,33Y TD: 14,537 SCHEMATIC Well: NCI B-02 (Sidetrack from Sunfish N3) Last Completed: 05/29/21 PTD:197-210 API: 50-883-20090-01-00 CASING DETAIL Size Wt Grade Conn ID Top Btm 30" 457 B Welded 27.000" Surf 407' 20" 169 x-56 Dril-Quip 18.376" Surf 2,602' 13-3/8" 72 N-80/P-110 BT&C 12.347" Surf 8,909' 9-5/8" 53.5 P-110 BT&C 8.535" Surf 11,086' 7" 32 P-110 BT&C 6.094" 10,738' 13,522' 3-1/2" 12.95 P-110 PH-6 2.750" Tube 2.687" Connection 13,522' 14,457' 1011110101111:11011 4-1/2" 1 12.6 1 L-80 1 Su ermax 1 3.958 1 surf 1 4,802' 2-7/8" 6.5 1 L-80 I CS Hydril I 2.441" 1 8,025' 1 ,526' 3-1/2" 12.95 L-80 PH-6 2.750"Tube 7,800' 13,530' 2.687" Connection JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 1 359' 359' 3.813 5.510 Halliburton SVLN(WL-SSSV- Installed 3/11/23) 2 4,554' 4,263' 3.990 8.250 9 5/8 43.5-53.3k DLH Packer 581, shear release 3 4,767' 4,454' 3.810 5.500 Sliding sleeve (Up to open) CLOSED as of 5/22/22 4 4,781' 4,467' 3.990 8.250 95/843.5-53.3k DLH Packer 581, shear release 5 4,800' 4,484' 3.810 5.000 X nipple 6 4,802' 4,486' 3.958 4.500 WLEG 7 7,500' 6,886' 8.125 Cement Retainer -TOC 7,330' 8 1 7,604' 6,977' 8.125 CIBP GAS LIFT MANDRELS STA MD ND ID Type Port Valve Psc Date 1 1,656' 1,647' 3.937 Camco MMG 1.5" 24 DOME 806 5/29/2021 2 1 3,083' 1 2,965' 1 3.937 1 Camco MMG 1.5" 1 24 1 DOME 1 773 1 5/29/2021 3 4,402' 4,128' 3.937 Camco MMG 1.5" w/1/2" Orifice 1 32 ORIFICE 5/29/2021 PFRFORATION DFTAII Zone (Mp) Btm (MD) Top (TVD) Btm (TVD) FT Date Status C.I.8 Lower 4,584' 4,596' 4,290' 4,301' 12' 05/28/21 Open C.I.9 4,615' 4,623' 4,318' 4,325' 8' 05/28/21 Open C.1.9 4,665' 4,673' 4,363' 4,370' 8' 05/28/21 Open C.I. 10 4,694' 4,710' 4,389' 4,403' 16' 05/27/21 Open C.I. 11 4,742' 4,762' 4,432' 4,450' 20' 05/27/21 Open Beluga A 4,799' 4,809' 4,483' 4,492' 10, 07/03/21 Open Beluga A Lwr 4,840' 4,856' 4,520' 4,534' 16' 05/24/22 Open Beluga B U r 4,892' 4,898' 4,567' 4,572' 6' 05/24/22 Open Beluga B Mid 4,961' 4,981' 4,629' 4,647' 20' 05/24/22 Open Beluga B Lwr 5,037' 5,046' 4,697' 4,705' ±9' 05/24/22 Open Beluga C Lwr 5,143' 5,148' 4,793' 4,798' ±5' 05/24/22 Open Beluga C 5,153' 5,163' 4,802' 4,811' 10, 07/03/21 Open Beluga D 5,192' 5,210' 4,837' 4,854' 18, 07/03/21 Open Beluga D 5,232' 5,237' 4,873' 4,878' 5' 07/03/21 Open Beluga D 5,244' 5,248' 4,994' 4,888' 4' 07/03/21 Open Beluga D 5,279' 5,287' 4,916' 4,923' 8' 07/03/21 Open Beluga E 5,348' 5,355' 4,978' 4,985' 7' 07/03/21 Open Beluga E 5,377' 5,391' 5,004' 5,017' 14' 07/03/21 Open Beluga E 5,409' 5,416' 5,033' 5,040' 7' 07/02/21 Open Beluga E 5,449' 5,469' 5,069' 5,087- 20' 07/02/21 Open Beluga F 5,554' 5,562' 5,164' 5,171' 8' 07/02/21 Open Beluga F 5,598' 5,604' 5,204' 5,209' 6' 07/02/21 Open Beluga G 5,612' 5,622' 5,216' 5,225' 10, 07/02/21 Open Beluga L 6,187' 6,205' 5,730' 5,746' 18, 03/08/23 O en Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579, 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 1 12,656' 1 18, 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated Updated By 1LL 03/24/23 K Hilcorp Alaska, LLC SCHEMATIC ISOLATED JEWELRY North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD:197-210 API: 50-883-20090-01-00 Short String No Depth (MD) Depth (TVD) ID OD Item L 8,184' 7,481' 2.347" 4.750" CAMCO KBMM GUM M 9,303' 8,485' 2.347" 4.750" CAMCO KBMM GUM N 10,290' 9,451' 2.347" 4.750" CAMCO KBMM GUM O 10,593' 9,751' 2.440" 8.340" Halliburton RDH Dual Packer P 10,613' 9,771' 2.313" HESX Nipple Q 10,624' 9,782' 2.250" HES XN Nipple w/ 2.313" PXN Plug Set R 10,625' 9,782' 2.441" 1 WLEG Long String E 9,238' 8,425' 2.867" 5.390" CAMCO KBUG GLM F 10,352' 9,513' 2.867" 5.390" CAMCO KBUG GUM G 10,592' 9,750' 2.900" 8.340" Halliburton RDH Dual Packer H 13,523' 12,461' 3.000" Baker No -Go Locator 1 13,524' 12,462' 3.000" 3-1/2"Seal Assembly 1 13,530' 12,467' End of Tubing K 13,625' 12,554' HES Magna Range Bridge Plug OPEN HOLE / CEMENT DETAIL 20" 24" Hole: Pumped 600bbls 12.8ppg class G lead followed by 124bbls 15.8ppg class G tail cement. 1" topjob tagged cement 23' below wellhead, and pumped 30sxs to bring ToC to surface. 17-1/2" hole: Primary iob Dumped 900sxs (336bbis) 12.5ppg class G lead cement followed by 700sxs (144bbis) 15.8ppg class G tail cement. 2nd stage through DV at 7380': Pumped 3700sxs (771bbis) of 15.8ppg class G. 117bbis cement circulated back 13-3/8" to surface. Two subsequent 50sxs squeezes. 11/30/97 RTTS showed a leak somewhere between 4100' —7415' (likely lower DV at 7380' MD leaking) 3'd stage through DV at 4048': Pumped 1000sxs (206bbls) of 15.8ppg class G. 10bbls cement returned to surface. One subsequent 100sxs squeeze. 11/30/97 RTTS set at 4100' passed an MIT above. Fully cemented 13-3/8" casing from 8,909' (shoe) to surface 12-1/4"hole: Pu mped 106bbis 15.8ppg class G cement. Volumetric ToC calculated assuming 30%washout= 9-5/8" 9975'. 5/24/21 Annular cement iob. Cement was circulated into the 9-5/8" x 13-3/8" annulus through punch holes at 7545'. 233bls 15.3ppg cement circulated in annulus bringing estimated ToC to 3,590'. Updated By: JLL03/24/23 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig AN Number Well Permit Number Start Date End Date NCIB-02 Eline 50-883-20090-01-00 197-210 3/8/23 3/12/23 Daily Operations: 03/08/2023 - Wednesday Fly to the Platform PJSM and PTW B-02 is flowing "'2.4MMCFD @ 60psi (500MCFD of gas lift going to the well). R/U AK E-line, grease swab valve Re -head E-line M/U 2"OD weight bars and 1-11/16"OD GPT tool Pressure test lubricator to 250psi/2500psi - Test good. (Open Beluga pert interval 4,799'-5,622') RIH with GPT tool with well flowing 2.4MMCFD @60psi (500MCFD of GL) Fluid level observed-4,850' 10 min stop count at 5,375ft (440psi, 95.6F) Log from 6,226' to surface. M/U 3.125"OD Gun gamma and 18' Geodymics 2-3/4"OD 6SPF, 15gm gun (CCL to top shot 9.Oft) RIH and pull correlation log. Send to town - re -pull log - on depth. Perforate Beluga L from 6,187-6,205'. POOH. Gun was damp Om - 2.2MMCFD 63PSI 5m - 1.5MMCFD 61PSI 10m - 1.2MMCFD 60PSI 15m - 0.3MMCFD 57PSI. Secure well and SDFN By the time we rigged down the well was flowing 2-3MMCFD again and slugging water. 03/09/2023 - Thursday PJSM and PTW B-02 is flowing at 4.8MMCFD @ 70psi;RD AK E-line and move to A-08. 03/12/2023 - Sunday Morning safety meeting, talk w/ company rep, sign permits. TGSM. Rig up on well. Rih w/ 4 1/2 BLB, brush SSSV nipple, pooh. Rih w/ 4 1/2 Vine w/ 41/2 X-lock safety valve to 359' kb, set valve, pooh. Ooh w/ tools, perform closure test - test good Secure well, Rig down Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 03/28/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230328 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 50133205300100 214070 2/18/2023 YELLOW JACKET PLUG BCU 18RD 50133205840100 222033 3/9/2023 YELLOW JACKET PERF CLU 10RD 50133205530100 222113 3/2/2023 YELLOW JACKET PERF-GPT-PLUG KBU 11-07 50133205560000 205165 3/3/2023 YELLOW JACKET PERF KBU 11-07 50133205560000 205165 3/1/2023 YELLOW JACKET PLUG KU 14X-6 50133203420000 181092 3/3/2023 YELLOW JACKET CALIPER-SCBL NCI B-02 50883200900100 197210 3/9/2023 AK E-LINE GPT Perf SRU 224-10 50133101380100 222124 2/15/2023 YELLOW JACKET PLUG TBU D-09RD 50733201310100 181080 2/27/2023 AK E-LINE Plug Punch Please include current contact information if different from above. NCI B-02 50883200900100 197210 3/9/2023 AK E-LINE GPT Perf 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: North Cook Inlet 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 14,537 N/A Casing Collapse Structural Conductor Surface 2,670psi Production 7,930psi Liner 10,870psi 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: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Operations Manager Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: 12.6 / L-80 & 6.5 / L-80 & 12.95 / L-80 4,802 & 10,626 & 13,530 3/4/2023 DLH Pkr and SLVN 4,554 (MD) 4,263 (TVD) 4,781 (MD) 4,467 (TVD) & 359 (MD) 359 (TVD) 4,584 - 5,622 4,290 - 5,225 4-1/2" & 2-7/8" & 3-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 197-210 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-883-20090-01-00 Hilcorp Alaska, LLC N Cook Inlet Unit B-02 Tertiary System Gas Same 11,086 Length Size Proposed Pools: 407 407 TVD Burst PRESENT WELL CONDITION SUMMARY 407 30" See schematic 10,900psi 5,380psi 2,535 8,123 10,224 Perforation Depth MD (ft): 2,784 3-1/2"935 11,640psi12,46013,522 14,457 13,306 7" 9-5/8"11,086 CO 68A 7,33013,377 6,737 2245 20" 13-3/8" 2,602 8,909 MD 2,602 8,909 Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Meredith Guhl at 7:25 am, Feb 21, 2023 323-107 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2023.02.18 07:21:11 -09'00' Dan Marlowe (1267) SFD 2/22/23 10-407 SFD 2/22/2023 DSR-2/22/23BJM 2/24/22 JLC 2/27/2023 2/27/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.02.27 12:28:19 -09'00' RBDMS JSB 022823 Perf add Well: NCIU B-02 Well Name:NCIU B-02 API Number:50-883-20090-01-00 Current Status:Online Gas Producer Permit to Drill Number:197-210 First Call Engineer:Ryan Rupert (907) 301-1736 (c)Leg 1 (NW corner) Second Call Engineer:Dan Marlowe (907) 398-9904 (c) Maximum Expected BHP:2905 psi @ 6,601’ TVD 0.44psi/ft to deepest proposed Max. Potential Surface Pressure: 2245 psi Using 0.1 psi/ft Brief Well Summary NCIU B-02 on the Tyonek platform is a Tertiary System Gas Pool producer open in several sands currently. There are some potential bypassed sands to complete still available. The goal of this project is to add gas sand perfs. All proposed perfs remain within the Tertiary Gas System Pool Pertinent wellbore information: - SSSV: WL retrievable - Inclination all <30 degrees above PBTD -5/24/22 o EL perf’d as deep as 5,148’ with 2-7/8” gund up to ~25’ long (no issues) o SL D&T to 6955’ MD with a 3.8” gauge ring E-Line Perf procedure 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 2500psi high 3. RIH and perforate Beluga sands from ±5,150’ – ±7,175’ MD (±4,800’ – ±6,601’ TVD) per RE/Geo 4. RDMO EL E-line contingency procedure (if any zone makes unwanted water and/or sand) 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250psi low / 2500psi high 3. RIH and set plug per RE/Geo 4. Cap plug with cement if necessary (all within same pool) 5. RDMO EL NOTE: WL-SSSV will need to be pulled, and reinstalled. It must be tested within 14 days of the well being returned to production Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic Agree. SFD 2/212/23 _____________________________________________________________________________________ Updated By JLL 02/13/2023 SCHEMATIC Well: NCI B-02 (Sidetrack from Sunfish #3) Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 PBTD: 7,330’ TD: 14,537’ 20” RKB =59’ RKBtoMSL = 132’, MLLW toMudline = 100’ 7” TBG punch 7,545’ H I 7 6 8 E F Stg Tool @ 4,045’ 13-3/8” 9-5/8” 5 1 3-1/2” 2 3 4 TOC @ 12,054’ WLM G 30” Stg Tool @ 7,385’ Tubing Punch @ 13,140’ – 13,142’ J K Sunfish N Forelands CI 8 Lwr CI 9 CI10 CI 11 Beluga A Beluga C BelugaD Beluga E Beluga F Beluga G Beluga B Tbg Cut 8,025’ Long String & 7,800’ Short String L M N O P Q R Proposed X X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 4,802’ 2-7/8” 6.5 L-80 CS Hydril 2.441” 8,025’ 10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection 7,800’ 13,530’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 359’ 359’ 3.813 5.510 Halliburton SVLN (WLR) Dummy ID=2.62 2 4,554’ 4,263’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 3 4,767’ 4,454’ 3.810 5.500 Sliding sleeve (Up to open)CLOSED as of 5/22/22 4 4,781’ 4,467’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 5 4,800’ 4,484’ 3.810 5.000 X nipple 6 4,802’ 4,486’ 3.958 4.500 WLEG 7 7,500’ 6,886’ - 8.125 Cement Retainer –TOC 7,330’ 8 7,604’ 6,977’ - 8.125 CIBP PERFORATION DETAIL Zone Top (MD)Btm (MD) Top (TVD) Btm (TVD) FT Date Status C.I. 8 Lower 4,584’ 4,596’ 4,290’ 4,301’ 12’ 05/28/21 Open C.I. 9 4,615’ 4,623’ 4,318’ 4,325’ 8’ 05/28/21 Open C.I. 9 4,665’ 4,673’ 4,363’ 4,370’ 8’ 05/28/21 Open C.I. 10 4,694’ 4,710’ 4,389’ 4,403’ 16’ 05/27/21 Open C.I. 11 4,742’ 4,762’ 4,432’ 4,450’ 20’ 05/27/21 Open Beluga A 4,799’ 4,809’ 4,483’ 4,492’ 10’ 07/03/21 Open Beluga A Lwr 4,840’ 4,856’ 4,520’ 4,534’ 16’ 05/24/22 Open Beluga B Upr 4,892’ 4,898’ 4,567’ 4,572’ 6’ 05/24/22 Open Beluga B Mid 4,961’ 4,981’ 4,629’ 4,647’ 20’ 05/24/22 Open Beluga B Lwr 5,037’ 5,046’ 4,697’ 4,705’ ±9’ 05/24/22 Open Beluga C Lwr 5,143’ 5,148’ 4,793’ 4,798’ ±5’ 05/24/22 Open Beluga C 5,153’ 5,163’ 4,802’ 4,811’ 10’ 07/03/21 Open Beluga D 5,192’ 5,210’ 4,837’ 4,854’ 18’ 07/03/21 Open Beluga D 5,232’ 5,237’ 4,873’ 4,878’ 5’ 07/03/21 Open Beluga D 5,244’ 5,248’ 4,884’ 4,888’ 4’ 07/03/21 Open Beluga D 5,279’ 5,287’ 4,916’ 4,923’ 8’ 07/03/21 Open Beluga E 5,348’ 5,355’ 4,978’ 4,985’ 7’ 07/03/21 Open Beluga E 5,377’ 5,391’ 5,004’ 5,017’ 14’ 07/03/21 Open Beluga E 5,409’ 5,416’ 5,033’ 5,040’ 7’ 07/02/21 Open Beluga E 5,449’ 5,469’ 5,069’ 5,087’ 20’ 07/02/21 Open Beluga F 5,554’ 5,562’ 5,164’ 5,171’ 8’ 07/02/21 Open Beluga F 5,598’ 5,604’ 5,204’ 5,209’ 6’ 07/02/21 Open Beluga G 5,612’ 5,622’ 5,216’ 5,225’ 10’ 07/02/21 Open Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,656’ 1,647’ 3.937 Camco MMG 1.5"24 DOME 805 5/29/2021 2 3,083’ 2,965’ 3.937 Camco MMG 1.5"24 DOME 773 5/29/2021 3 4,402’ 4,128’ 3.937 Camco MMG 1.5" w/1/2" Orifice 32 ORIFICE 5/29/2021 _____________________________________________________________________________________ Updated By: JLL 02/13/2023 SCHEMATIC North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 OPEN HOLE / CEMENT DETAIL 20"24” Hole: Pumped 600bbls 12.8ppg class G lead followed by 124bbls 15.8ppg class G tail cement. 1” top job tagged cement 23’ below wellhead, and pumped 30sxs to bring ToC to surface. 13-3/8" 17-1/2” hole: Primary job pumped 900sxs (336bbls) 12.5ppg class G lead cement followed by 700sxs (144bbls) 15.8ppg class G tail cement. 2nd stage through DV at 7380’: Pumped 3700sxs (771bbls) of 15.8ppg class G. 117bbls cement circulated back to surface. Two subsequent 50sxs squeezes. 11/30/97 RTTS showed a leak somewhere between 4100’ – 7415’ (likely lower DV at 7380’ MD leaking) 3rd stage through DV at 4048’: Pumped 1000sxs (206bbls) of 15.8ppg class G. 10bbls cement returned to surface. One subsequent 100sxs squeeze. 11/30/97 RTTS set at 4100’ passed an MIT above. Fully cemented 13-3/8” casing from 8,909’ (shoe) to surface 9-5/8” 12-1/4” hole: Pumped 106bbls 15.8ppg class G cement. Volumetric ToC calculated assuming 30% washout = 9975’. 5/24/21 Annular cement job. Cement was circulated into the 9-5/8” x 13-3/8” annulus through punch holes at 7545’. 233bls 15.3ppg cement circulated in annulus bringing estimated ToC to 3,590’. ISOLATED JEWELRY Short String No Depth (MD) Depth (TVD)ID OD Item L 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM M 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM N 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM O 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer P 10,613’ 9,771’ 2.313” HES X Nipple Q 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set R 10,625’ 9,782’ 2.441” WLEG Long String E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug _____________________________________________________________________________________ Updated By JLL 02/17/2023 PROPOSED Well: NCI B-02 (Sidetrack from Sunfish #3) Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 PBTD: 7,330’ TD: 14,537’ 20” RKB =59’ RKBtoMSL = 132’, MLLW toMudline = 100’ 7” TBG punch 7,545’ H I 7 6 8 E F Stg Tool @ 4,045’ 13-3/8” 9-5/8” 5 1 3-1/2” 2 3 4 TOC @ 12,054’ WLM G 30” Stg Tool @ 7,385’ Tubing Punch @ 13,140’ – 13,142’ J K Sunfish N Forelands CI 8 Lwr CI 9 CI10 CI 11 Beluga A Beluga C BelugaD Beluga E Beluga F Beluga G Beluga B Tbg Cut 8,025’ Long String & 7,800’ Short String L M N O P Q R Proposed X X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 4,802’ 2-7/8” 6.5 L-80 CS Hydril 2.441” 8,025’ 10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection 7,800’ 13,530’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 359’ 359’ 3.813 5.510 Halliburton SVLN (WLR) Dummy ID=2.62 2 4,554’ 4,263’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 3 4,767’ 4,454’ 3.810 5.500 Sliding sleeve (Up to open)CLOSED as of 5/22/22 4 4,781’ 4,467’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 5 4,800’ 4,484’ 3.810 5.000 X nipple 6 4,802’ 4,486’ 3.958 4.500 WLEG 7 7,500’ 6,886’ - 8.125 Cement Retainer –TOC 7,330’ 8 7,604’ 6,977’ - 8.125 CIBP PERFORATION DETAIL Zone Top (MD)Btm (MD) Top (TVD) Btm (TVD) FT Date Status C.I. 8 Lower 4,584’ 4,596’ 4,290’ 4,301’ 12’ 05/28/21 Open C.I. 9 4,615’ 4,623’ 4,318’ 4,325’ 8’ 05/28/21 Open C.I. 9 4,665’ 4,673’ 4,363’ 4,370’ 8’ 05/28/21 Open C.I. 10 4,694’ 4,710’ 4,389’ 4,403’ 16’ 05/27/21 Open C.I. 11 4,742’ 4,762’ 4,432’ 4,450’ 20’ 05/27/21 Open Beluga A 4,799’ 4,809’ 4,483’ 4,492’ 10’ 07/03/21 Open Beluga A Lwr 4,840’ 4,856’ 4,520’ 4,534’ 16’ 05/24/22 Open Beluga B Upr 4,892’ 4,898’ 4,567’ 4,572’ 6’ 05/24/22 Open Beluga B Mid 4,961’ 4,981’ 4,629’ 4,647’ 20’ 05/24/22 Open Beluga B Lwr 5,037’ 5,046’ 4,697’ 4,705’ ±9’ 05/24/22 Open Beluga C Lwr 5,143’ 5,148’ 4,793’ 4,798’ ±5’ 05/24/22 Open BELUGA ±5,150’ ±7,175’ ±4,800’ ±6,601’ ±2,025’ FUTURE PROPOSED Beluga C 5,153’ 5,163’ 4,802’ 4,811’ 10’ 07/03/21 Open Beluga D 5,192’ 5,210’ 4,837’ 4,854’ 18’ 07/03/21 Open Beluga D 5,232’ 5,237’ 4,873’ 4,878’ 5’ 07/03/21 Open Beluga D 5,244’ 5,248’ 4,884’ 4,888’ 4’ 07/03/21 Open Beluga D 5,279’ 5,287’ 4,916’ 4,923’ 8’ 07/03/21 Open Beluga E 5,348’ 5,355’ 4,978’ 4,985’ 7’ 07/03/21 Open Beluga E 5,377’ 5,391’ 5,004’ 5,017’ 14’ 07/03/21 Open Beluga E 5,409’ 5,416’ 5,033’ 5,040’ 7’ 07/02/21 Open Beluga E 5,449’ 5,469’ 5,069’ 5,087’ 20’ 07/02/21 Open Beluga F 5,554’ 5,562’ 5,164’ 5,171’ 8’ 07/02/21 Open Beluga F 5,598’ 5,604’ 5,204’ 5,209’ 6’ 07/02/21 Open Beluga G 5,612’ 5,622’ 5,216’ 5,225’ 10’ 07/02/21 Open Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated GAS LIFT MANDRELS STA MD TVD ID Type Port Valve Psc Date 1 1,656’ 1,647’ 3.937 Camco MMG 1.5"24 DOME 805 5/29/2021 2 3,083’ 2,965’ 3.937 Camco MMG 1.5"24 DOME 773 5/29/2021 3 4,402’ 4,128’ 3.937 Camco MMG 1.5" w/1/2" Orifice 32 ORIFICE 5/29/2021 _____________________________________________________________________________________ Updated By: JLL 02/17/2023 SCHEMATIC North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01-00 OPEN HOLE / CEMENT DETAIL 20"24” Hole: Pumped 600bbls 12.8ppg class G lead followed by 124bbls 15.8ppg class G tail cement. 1” top job tagged cement 23’ below wellhead, and pumped 30sxs to bring ToC to surface. 13-3/8" 17-1/2” hole: Primary job pumped 900sxs (336bbls) 12.5ppg class G lead cement followed by 700sxs (144bbls) 15.8ppg class G tail cement. 2nd stage through DV at 7380’: Pumped 3700sxs (771bbls) of 15.8ppg class G. 117bbls cement circulated back to surface. Two subsequent 50sxs squeezes. 11/30/97 RTTS showed a leak somewhere between 4100’ – 7415’ (likely lower DV at 7380’ MD leaking) 3rd stage through DV at 4048’: Pumped 1000sxs (206bbls) of 15.8ppg class G. 10bbls cement returned to surface. One subsequent 100sxs squeeze. 11/30/97 RTTS set at 4100’ passed an MIT above. Fully cemented 13-3/8” casing from 8,909’ (shoe) to surface 9-5/8” 12-1/4” hole: Pumped 106bbls 15.8ppg class G cement. Volumetric ToC calculated assuming 30% washout = 9975’. 5/24/21 Annular cement job. Cement was circulated into the 9-5/8” x 13-3/8” annulus through punch holes at 7545’. 233bls 15.3ppg cement circulated in annulus bringing estimated ToC to 3,590’. ISOLATED JEWELRY Short String No Depth (MD) Depth (TVD)ID OD Item L 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM M 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM N 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM O 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer P 10,613’ 9,771’ 2.313” HES X Nipple Q 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set R 10,625’ 9,782’ 2.441” WLEG Long String E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 06/14/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NCI B-02 (PTD 197-210) PERF 05/24/2022 Please include current contact information if different from above. 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Use Gamma/CCL to correlate H ,QVWDOO&U\VWDOJDXJHV RUYHULI\37VDUHRSHQWR6&$'$ EHIRUHSHUIRUDWLQJ5HFRUGWXELQJ SUHVVXUHVEHIRUHDQGDIWHUHDFKSHUIRUDWLQJUXQDWPLQPLQDQGPLQLQWHUYDOVSRVW VKRW I 7KHVHVDQGVDUHJRYHUQHGE\KϲϴEŽƌƚŚŽŽŬ/ŶůĞƚ͕dĞƌƚŝĂƌLJ'ĂƐWŽŽů ϵ͘WKK, ϭϬ͘ZĞͲůŝŶĞ ϭϭ͘dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶƚŽƚĞƐƚ ϭϮ͘^ůŝĐŬůŝŶĞƚŽƌĞƐĞƚ^^^sĂŶĚŶŽƚŝĨLJƐƚĂƚĞƚŽƚĞƐƚǁŝƚŚŝŶϱͲĚĂLJƐŽĨƐĞƚƚŝŶŐǀĂůǀĞ ƚƚĂĐŚŵĞŶƚƐ ϭ͘ƵƌƌĞŶƚtĞůů^ĐŚĞŵĂƚŝĐ Ϯ͘WƌŽƉŽƐĞĚtĞůů^ĐŚĞŵĂƚŝĐ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚLJ͗:>>ϬϳͬϮϴͬϮϭ ^, Dd/ EŽƌƚŚŽŽŬ/ŶůĞƚhŶŝƚ tĞůů͗E/ͲϬϮ >ĂƐƚŽŵƉůĞƚĞĚ͗ϬϱͬϮϵͬϮϭ Wd͗ϭϵϳͲϮϭϬ W/͗ϱϬͲϴϴϯͲϮϬϬϵϬͲϬϭͲϬϬ ^/E' d/> ^ŝnjĞ tƚ 'ƌĂĚĞ ŽŶŶ /dŽƉ ƚŵ ϯϬ͟ϰϱϳ tĞůĚĞĚ Ϯϳ͘ϬϬϬ͟^ƵƌĨ ϰϬϳ͛ ϮϬ͟ϭϲϵ yͲϱϲ ƌŝůͲYƵŝƉ ϭϴ͘ϯϳϲ͟^ƵƌĨ Ϯ͕ϲϬϮ͛ ϭϯͲϯͬϴ͟ϳϮ EͲϴϬͬWͲϭϭϬ dΘϭϮ͘ϯϰϳ͟^ƵƌĨ ϴ͕ϵϬϵ͛ ϵͲϱͬϴ͟ϱϯ͘ϱ WͲϭϭϬ dΘϴ͘ϱϯϱ͟^ƵƌĨ ϭϭ͕Ϭϴϲ͛ ϳ͟ϯϮ WͲϭϭϬ dΘϲ͘Ϭϵϰ͟ϭϬ͕ϳϯϴ͛ϭϯ͕ϱϮϮ͛ ϯͲϭͬϮ͟ ϭϮ͘ϵϱ WͲϭϭϬ W,Ͳϲ Ϯ͘ϳϱϬ͟dƵďĞ Ϯ͘ϲϴϳ͟ŽŶŶĞĐƚŝŽŶ ϭϯ͕ϱϮϮ͛ϭϰ͕ϰϱϳ͛ dh/E' d/> ϰͲϭͬϮ͟ϭϮ͘ϲ >ͲϴϬ ^ƵƉĞƌŵĂdž ϯ͘ϵϱϴ ^ƵƌĨ ϰ͕ϴϬϮ͛ ϮͲϳͬϴ͟ϲ͘ϱ >ͲϴϬ ^,LJĚƌŝů Ϯ͘ϰϰϭ͟ϴ͕ϬϮϱ͛ϭϬ͕ϲϮϲΖ ϯͲϭͬϮ͟ ϭϮ͘ϵϱ >ͲϴϬ W,Ͳϲ Ϯ͘ϳϱϬ͟dƵďĞ Ϯ͘ϲϴϳ͟ŽŶŶĞĐƚŝŽŶ ϳ͕ϴϬϬ͛ϭϯ͕ϱϯϬ͛ : t >Zz d/> EŽ ĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ / K /ƚĞŵ ϭ ϯϱϵ͛ϯϱϵ͛ϯ͘ϴϭϯ ϱ͘ϱϭϬ ,ĂůůŝďƵƌƚŽŶ^s>E;t>ZͿƵŵŵLJ/сϮ͘ϲϮ Ϯ ϭ͕ϲϱϲ͛ϭ͕ϲϰϳ͛ϯ͘ϵϯϳ ϳ͘ϬϯϮ '>DηϭĂŵĐŽDD'ϭ͘ϱΗs>s ϯ ϯ͕Ϭϴϯ͛Ϯ͕ϵϲϱ͛ϯ͘ϵϯϳ ϳ͘ϬϯϮ '>DηϮĂŵĐŽDD' ϭ͘ϱΗs>s ϰ ϰ͕ϰϬϮ͛ ϰ͕ϭϮϴ͛ ϯ͘ϵϯϳ ϳ͘ϬϯϮ '>Dηϯ ĂŵĐŽDD'ϭ͘ϱΗs>s tͬϭͬϮΗ KZ/& ϱ ϰ͕ϱϱϰ͛ ϰ͕Ϯϲϯ͛ ϯ͘ϵϵϬ ϴ͘ϮϱϬ ϵϱͬϴϰϯ͘ϱͲϱϯ͘ϯη>,WĂĐŬĞƌϱϴŬƐŚĞĂƌ ƌĞůĞĂƐĞ ϲ ϰ͕ϳϲϳ͛ϰ͕ϰϱϰ͛ϯ͘ϴϭϬ ϱ͘ϱϬϬ ^ůŝĚŝŶŐƐůĞĞǀĞ;hƉƚŽŽƉĞŶͿ ϳ ϰ͕ϳϴϭ͛ ϰ͕ϰϲϳ͛ϯ͘ϵϵϬ ϴ͘ϮϱϬ ϵϱͬϴϰϯ͘ϱͲϱϯ͘ϯη>,WĂĐŬĞƌϱϴŬƐŚĞĂƌ ƌĞůĞĂƐĞ ϴ ϰ͕ϴϬϬ͛ϰ͕ϰϴϰ͛ϯ͘ϴϭϬ ϱ͘ϬϬϬ yŶŝƉƉůĞ ϵ ϰ͕ϴϬϮ͛ϰ͕ϰϴϲ͛ϯ͘ϵϱϴ ϰ͘ϱϬϬ t> ' ϭϬ ϳ͕ϱϬϬ͛ϲ͕ϴϴϲ͛Ͳ ϴ͘ϭϮϱ ĞŵĞŶƚZĞƚĂŝŶĞƌ ʹ dKϳ͕ϯϯϬ͛ ϭϭ ϳ͕ϲϬϰ͛ϲ͕ϵϳϳ͛Ͳ ϴ͘ϭϮϱ /W W Z&KZd/KE d/> ŽŶĞ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ &d ĂƚĞ ^ƚĂƚƵƐ ͘/͘ϴ>ŽǁĞƌ ϰ͕ϱϴϰ͛ϰ͕ϱϵϲ͛ϰ͕ϮϵϬ͛ϰ͕ϯϬϭ͛ϭϮ͛ϬϱͬϮϴͬϮϭ KƉĞŶ ͘/͘ϵ ϰ͕ϲϭϱ͛ϰ͕ϲϮϯ͛ϰ͕ϯϭϴ͛ϰ͕ϯϮϱ͛ϴ͛ϬϱͬϮϴͬϮϭ KƉĞŶ ͘/͘ϵ ϰ͕ϲϲϱ͛ϰ͕ϲϳϯ͛ϰ͕ϯϲϯ͛ϰ͕ϯϳϬ͛ϴ͛ϬϱͬϮϴͬϮϭ KƉĞŶ ͘/͘ϭϬ ϰ͕ϲϵϰ͛ϰ͕ϳϭϬ͛ϰ͕ϯϴϵ͛ϰ͕ϰϬϯ͛ϭϲ͛ϬϱͬϮϳͬϮϭ KƉĞŶ ͘/͘ϭϭ ϰ͕ϳϰϮ͛ϰ͕ϳϲϮ͛ϰ͕ϰϯϮ͛ϰ͕ϰϱϬ͛ϮϬ͛ϬϱͬϮϳͬϮϭ KƉĞŶ ĞůƵŐĂϰ͕ϳϵϵ͛ϰ͕ϴϬϵ͛ϰ͕ϰϴϯ͛ϰ͕ϰϵϮ͛ϭϬ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂϱ͕ϭϱϯ͛ϱ͕ϭϲϯ͛ϰ͕ϴϬϮ͛ϰ͕ϴϭϭ͛ϭϬ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂϱ͕ϭϵϮ͛ϱ͕ϮϭϬ͛ϰ͕ϴϯϳ͛ϰ͕ϴϱϰ͛ϭϴ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂϱ͕ϮϯϮ͛ϱ͕Ϯϯϳ͛ϰ͕ϴϳϯ͛ϰ͕ϴϳϴ͛ϱ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂϱ͕Ϯϰϰ͛ϱ͕Ϯϰϴ͛ϰ͕ϴϴϰ͛ϰ͕ϴϴϴ͛ϰ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂϱ͕Ϯϳϵ͛ϱ͕Ϯϴϳ͛ϰ͕ϵϭϲ͛ϰ͕ϵϮϯ͛ϴ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂ ϱ͕ϯϰϴ͛ϱ͕ϯϱϱ͛ϰ͕ϵϳϴ͛ϰ͕ϵϴϱ͛ϳ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂ ϱ͕ϯϳϳ͛ϱ͕ϯϵϭ͛ϱ͕ϬϬϰ͛ϱ͕Ϭϭϳ͛ϭϰ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂ ϱ͕ϰϬϵ͛ϱ͕ϰϭϲ͛ϱ͕Ϭϯϯ͛ϱ͕ϬϰϬ͛ϳ͛ϬϳͬϬϮͬϮϭ KƉĞŶ ĞůƵŐĂ ϱ͕ϰϰϵ͛ϱ͕ϰϲϵ͛ϱ͕Ϭϲϵ͛ϱ͕Ϭϴϳ͛ϮϬ͛ϬϳͬϬϮͬϮϭ KƉĞŶ ĞůƵŐĂ&ϱ͕ϱϱϰ͛ϱ͕ϱϲϮ͛ϱ͕ϭϲϰ͛ϱ͕ϭϳϭ͛ϴ͛ϬϳͬϬϮͬϮϭ KƉĞŶ ĞůƵŐĂ&ϱ͕ϱϵϴ͛ϱ͕ϲϬϰ͛ϱ͕ϮϬϰ͛ϱ͕ϮϬϵ͛ϲ͛ϬϳͬϬϮͬϮϭ KƉĞŶ ĞůƵŐĂ'ϱ͕ϲϭϮ͛ϱ͕ϲϮϮ͛ϱ͕Ϯϭϲ͛ϱ͕ϮϮϱ͛ϭϬ͛ϬϳͬϬϮͬϮϭ KƉĞŶ ^ƵŶĨŝƐŚ ϭϯ͕ϭϭϬΖ ϭϯ͕ϭϳϬΖ ϭϮ͕ϬϴϰΖ ϭϮ͕ϭϯϵΖ ϲϬΖ ϭͬϮϱͬϭϵϵϴ ĞŵĞŶƚĞĚŽŶ ϵͬϮϱͬϮϬϬϮ E&ŽƌĞůĂŶĚƐ ϭϯ͕ϲϱϮΖ ϭϯ͕ϲϴϲΖ ϭϮ͕ϱϳϵΖ ϭϮ͕ϲϭϬΖ ϯϰΖ ϮͬϭϬͬϭϵϵϴ /ƐŽůĂƚĞĚ E&ŽƌĞůĂŶĚƐ ϭϯ͕ϳϭϴΖ ϭϯ͕ϳϯϲΖ ϭϮ͕ϲϯϵΖ ϭϮ͕ϲϱϲΖ ϭϴΖ ϮͬϭϬͬϭϵϵϴ /ƐŽůĂƚĞĚ E&ŽƌĞůĂŶĚƐ ϭϯ͕ϴϭϴΖ ϭϯ͕ϴϱϲΖ ϭϮ͕ϳϯϬΖ ϭϮ͕ϳϲϱΖ ϯϴΖ ϮͬϭϬͬϭϵϵϴ /ƐŽůĂƚĞĚ E&ŽƌĞůĂŶĚƐ ϭϯ͕ϵϰϰΖ ϭϯ͕ϵϲϲΖ ϭϮ͕ϴϰϰΖ ϭϮ͕ϴϲϰΖ ϮϮΖ ϮͬϭϬͬϭϵϵϴ /ƐŽůĂƚĞĚ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚLJ͗:>>ϬϳͬϮϴͬϮϭ ^, Dd/ EŽƌƚŚŽŽŬ/ŶůĞƚhŶŝƚ tĞůů͗E/ͲϬϮ >ĂƐƚŽŵƉůĞƚĞĚ͗ϬϱͬϮϵͬϮϭ Wd͗ϭϵϳͲϮϭϬ W/͗ϱϬͲϴϴϯͲϮϬϬϵϬͲϬϭ /^K>d : t >Zz ^ŚŽƌƚ^ƚƌŝŶŐ EŽĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ/ K /ƚĞŵ >ϴ͕ϭϴϰ͛ϳ͕ϰϴϭ͛Ϯ͘ϯϰϳ͟ϰ͘ϳϱϬ͟DK<DD'>D Dϵ͕ϯϬϯ͛ϴ͕ϰϴϱ͛Ϯ͘ϯϰϳ͟ϰ͘ϳϱϬ͟DK<DD'>D EϭϬ͕ϮϵϬ͛ϵ͕ϰϱϭ͛Ϯ͘ϯϰϳ͟ϰ͘ϳϱϬ͟DK<DD'>D KϭϬ͕ϱϵϯ͛ϵ͕ϳϱϭ͛Ϯ͘ϰϰϬ͟ϴ͘ϯϰϬ͟,ĂůůŝďƵƌƚŽŶZ,ƵĂůWĂĐŬĞƌ WϭϬ͕ϲϭϯ͛ϵ͕ϳϳϭ͛Ϯ͘ϯϭϯ͟, ^yEŝƉƉůĞ YϭϬ͕ϲϮϰ͛ϵ͕ϳϴϮ͛Ϯ͘ϮϱϬ͟, ^yEEŝƉƉůĞǁͬϮ͘ϯϭϯ͟WyEWůƵŐ^Ğƚ ZϭϬ͕ϲϮϱ͛ϵ͕ϳϴϮ͛Ϯ͘ϰϰϭ͟t> ' >ŽŶŐ^ƚƌŝŶŐ ϵ͕Ϯϯϴ͛ϴ͕ϰϮϱ͛Ϯ͘ϴϲϳ͟ϱ͘ϯϵϬ͟DK<h''>D &ϭϬ͕ϯϱϮ͛ϵ͕ϱϭϯ͛Ϯ͘ϴϲϳ͟ϱ͘ϯϵϬ͟DK<h''>D 'ϭϬ͕ϱϵϮ͛ϵ͕ϳϱϬ͛Ϯ͘ϵϬϬ͟ϴ͘ϯϰϬ͟,ĂůůŝďƵƌƚŽŶZ,ƵĂůWĂĐŬĞƌ ,ϭϯ͕ϱϮϯ͛ϭϮ͕ϰϲϭ͛ϯ͘ϬϬϬ͟ĂŬĞƌEŽͲ'Ž>ŽĐĂƚŽƌ /ϭϯ͕ϱϮϰ͛ϭϮ͕ϰϲϮ͛ϯ͘ϬϬϬ͟ϯͲϭͬϮ͟^ĞĂůƐƐĞŵďůLJ :ϭϯ͕ϱϯϬ͛ϭϮ͕ϰϲϳ͛ ŶĚŽĨdƵďŝŶŐ <ϭϯ͕ϲϮϱ͛ϭϮ͕ϱϱϰ͛, ^DĂŐŶĂZĂŶŐĞƌŝĚŐĞWůƵŐ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚLJ͗,ϱͬϵͬϮϮ WZKWK^ EŽƌƚŚŽŽŬ/ŶůĞƚhŶŝƚ tĞůů͗E/ͲϬϮ >ĂƐƚŽŵƉůĞƚĞĚ͗ϬϱͬϮϵͬϮϭ Wd͗ϭϵϳͲϮϭϬ W/͗ϱϬͲϴϴϯͲϮϬϬϵϬͲϬϭͲϬϬ ^/E' d/> ^ŝnjĞ tƚ 'ƌĂĚĞ ŽŶŶ /dŽƉ ƚŵ ϯϬ͟ϰϱϳ tĞůĚĞĚ Ϯϳ͘ϬϬϬ͟^ƵƌĨ ϰϬϳ͛ ϮϬ͟ϭϲϵ yͲϱϲ ƌŝůͲYƵŝƉ ϭϴ͘ϯϳϲ͟^ƵƌĨ Ϯ͕ϲϬϮ͛ ϭϯͲϯͬϴ͟ϳϮ EͲϴϬͬWͲϭϭϬ dΘϭϮ͘ϯϰϳ͟^ƵƌĨ ϴ͕ϵϬϵ͛ ϵͲϱͬϴ͟ϱϯ͘ϱ WͲϭϭϬ dΘϴ͘ϱϯϱ͟^ƵƌĨ ϭϭ͕Ϭϴϲ͛ ϳ͟ϯϮ WͲϭϭϬ dΘϲ͘Ϭϵϰ͟ϭϬ͕ϳϯϴ͛ϭϯ͕ϱϮϮ͛ ϯͲϭͬϮ͟ ϭϮ͘ϵϱ WͲϭϭϬ W,Ͳϲ Ϯ͘ϳϱϬ͟dƵďĞ Ϯ͘ϲϴϳ͟ŽŶŶĞĐƚŝŽŶ ϭϯ͕ϱϮϮ͛ϭϰ͕ϰϱϳ͛ dh/E' d/> ϰͲϭͬϮ͟ϭϮ͘ϲ >ͲϴϬ ^ƵƉĞƌŵĂdž ϯ͘ϵϱϴ ^ƵƌĨ ϰ͕ϴϬϮ͛ ϮͲϳͬϴ͟ϲ͘ϱ >ͲϴϬ ^,LJĚƌŝů Ϯ͘ϰϰϭ͟ϴ͕ϬϮϱ͛ϭϬ͕ϲϮϲΖ ϯͲϭͬϮ͟ ϭϮ͘ϵϱ >ͲϴϬ W,Ͳϲ Ϯ͘ϳϱϬ͟dƵďĞ Ϯ͘ϲϴϳ͟ŽŶŶĞĐƚŝŽŶ ϳ͕ϴϬϬ͛ϭϯ͕ϱϯϬ͛ : t >Zz d/> EŽ ĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ / K /ƚĞŵ ϭ ϯϱϵ͛ϯϱϵ͛ϯ͘ϴϭϯ ϱ͘ϱϭϬ ,ĂůůŝďƵƌƚŽŶ^s>E;t>ZͿƵŵŵLJ/сϮ͘ϲϮ Ϯ ϭ͕ϲϱϲ͛ϭ͕ϲϰϳ͛ϯ͘ϵϯϳ ϳ͘ϬϯϮ '>DηϭĂŵĐŽDD'ϭ͘ϱΗs>s ϯ ϯ͕Ϭϴϯ͛Ϯ͕ϵϲϱ͛ϯ͘ϵϯϳ ϳ͘ϬϯϮ '>DηϮĂŵĐŽDD' ϭ͘ϱΗs>s ϰ ϰ͕ϰϬϮ͛ ϰ͕ϭϮϴ͛ ϯ͘ϵϯϳ ϳ͘ϬϯϮ '>Dηϯ ĂŵĐŽDD'ϭ͘ϱΗs>s tͬϭͬϮΗ KZ/& ϱ ϰ͕ϱϱϰ͛ ϰ͕Ϯϲϯ͛ ϯ͘ϵϵϬ ϴ͘ϮϱϬ ϵϱͬϴϰϯ͘ϱͲϱϯ͘ϯη>,WĂĐŬĞƌϱϴŬƐŚĞĂƌ ƌĞůĞĂƐĞ ϲ ϰ͕ϳϲϳ͛ϰ͕ϰϱϰ͛ϯ͘ϴϭϬ ϱ͘ϱϬϬ ^ůŝĚŝŶŐƐůĞĞǀĞ;hƉƚŽŽƉĞŶͿ ϳ ϰ͕ϳϴϭ͛ ϰ͕ϰϲϳ͛ϯ͘ϵϵϬ ϴ͘ϮϱϬ ϵϱͬϴϰϯ͘ϱͲϱϯ͘ϯη>,WĂĐŬĞƌϱϴŬƐŚĞĂƌ ƌĞůĞĂƐĞ ϴ ϰ͕ϴϬϬ͛ϰ͕ϰϴϰ͛ϯ͘ϴϭϬ ϱ͘ϬϬϬ yŶŝƉƉůĞ ϵ ϰ͕ϴϬϮ͛ϰ͕ϰϴϲ͛ϯ͘ϵϱϴ ϰ͘ϱϬϬ t> ' ϭϬ ϳ͕ϱϬϬ͛ϲ͕ϴϴϲ͛Ͳ ϴ͘ϭϮϱ ĞŵĞŶƚZĞƚĂŝŶĞƌ ʹ dKϳ͕ϯϯϬ͛ ϭϭ ϳ͕ϲϬϰ͛ϲ͕ϵϳϳ͛Ͳ ϴ͘ϭϮϱ /W W Z&KZd/KE d/> ŽŶĞ dŽƉ ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ &d ĂƚĞ ^ƚĂƚƵƐ ͘/͘ϴ>ŽǁĞƌ ϰ͕ϱϴϰ͛ϰ͕ϱϵϲ͛ϰ͕ϮϵϬ͛ϰ͕ϯϬϭ͛ϭϮ͛ϬϱͬϮϴͬϮϭ KƉĞŶ ͘/͘ϵ ϰ͕ϲϭϱ͛ϰ͕ϲϮϯ͛ϰ͕ϯϭϴ͛ϰ͕ϯϮϱ͛ϴ͛ϬϱͬϮϴͬϮϭ KƉĞŶ ͘/͘ϵ ϰ͕ϲϲϱ͛ϰ͕ϲϳϯ͛ϰ͕ϯϲϯ͛ϰ͕ϯϳϬ͛ϴ͛ϬϱͬϮϴͬϮϭ KƉĞŶ ͘/͘ϭϬ ϰ͕ϲϵϰ͛ϰ͕ϳϭϬ͛ϰ͕ϯϴϵ͛ϰ͕ϰϬϯ͛ϭϲ͛ϬϱͬϮϳͬϮϭ KƉĞŶ ͘/͘ϭϭ ϰ͕ϳϰϮ͛ϰ͕ϳϲϮ͛ϰ͕ϰϯϮ͛ϰ͕ϰϱϬ͛ϮϬ͛ϬϱͬϮϳͬϮϭ KƉĞŶ ĞůƵŐĂϰ͕ϳϵϵ͛ϰ͕ϴϬϵ͛ϰ͕ϰϴϯ͛ϰ͕ϰϵϮ͛ϭϬ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂ >ǁƌ цϰ͕ϴϰϬ͛цϰ͕ϴϱϲ͛цϰ͕ϱϮϬ͛цϰ͕ϱϯϰ͛цϭϲ͛dWƌŽƉŽƐĞĚ ĞůƵŐĂ hƉƌ цϰ͕ϴϵϮ͛цϰ͕ϴϵϴ͛цϰ͕ϱϲϳ͛цϰ͕ϱϳϮ͛цϲ͛dWƌŽƉŽƐĞĚ ĞůƵŐĂDŝĚ цϰ͕ϵϲϭ͛цϰ͕ϵϴϭ͛цϰ͕ϲϮϵ͛цϰ͕ϲϰϳ͛цϮϬ͛dWƌŽƉŽƐĞĚ ĞůƵŐĂ>ǁƌ цϱ͕Ϭϯϳ͛цϱ͕Ϭϰϲ͛цϰ͕ϲϵϳ͛цϰ͕ϳϬϱ͛цϵ͛dWƌŽƉŽƐĞĚ ĞůƵŐĂ>ǁƌ цϱ͕ϭϰϯ͛цϱ͕ϭϰϴ͛цϰ͕ϳϵϯ͛цϰ͕ϳϵϴ͛цϱ͛dWƌŽƉŽƐĞĚ ĞůƵŐĂ ϱ͕ϭϱϯ͛ϱ͕ϭϲϯ͛ϰ͕ϴϬϮ͛ϰ͕ϴϭϭ͛ϭϬ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂϱ͕ϭϵϮ͛ϱ͕ϮϭϬ͛ϰ͕ϴϯϳ͛ϰ͕ϴϱϰ͛ϭϴ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂϱ͕ϮϯϮ͛ϱ͕Ϯϯϳ͛ϰ͕ϴϳϯ͛ϰ͕ϴϳϴ͛ϱ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂϱ͕Ϯϰϰ͛ϱ͕Ϯϰϴ͛ϰ͕ϴϴϰ͛ϰ͕ϴϴϴ͛ϰ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂϱ͕Ϯϳϵ͛ϱ͕Ϯϴϳ͛ϰ͕ϵϭϲ͛ϰ͕ϵϮϯ͛ϴ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂ ϱ͕ϯϰϴ͛ϱ͕ϯϱϱ͛ϰ͕ϵϳϴ͛ϰ͕ϵϴϱ͛ϳ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂ ϱ͕ϯϳϳ͛ϱ͕ϯϵϭ͛ϱ͕ϬϬϰ͛ϱ͕Ϭϭϳ͛ϭϰ͛ϬϳͬϬϯͬϮϭ KƉĞŶ ĞůƵŐĂ ϱ͕ϰϬϵ͛ϱ͕ϰϭϲ͛ϱ͕Ϭϯϯ͛ϱ͕ϬϰϬ͛ϳ͛ϬϳͬϬϮͬϮϭ KƉĞŶ ĞůƵŐĂ ϱ͕ϰϰϵ͛ϱ͕ϰϲϵ͛ϱ͕Ϭϲϵ͛ϱ͕Ϭϴϳ͛ϮϬ͛ϬϳͬϬϮͬϮϭ KƉĞŶ ĞůƵŐĂ&ϱ͕ϱϱϰ͛ϱ͕ϱϲϮ͛ϱ͕ϭϲϰ͛ϱ͕ϭϳϭ͛ϴ͛ϬϳͬϬϮͬϮϭ KƉĞŶ ĞůƵŐĂ&ϱ͕ϱϵϴ͛ϱ͕ϲϬϰ͛ϱ͕ϮϬϰ͛ϱ͕ϮϬϵ͛ϲ͛ϬϳͬϬϮͬϮϭ KƉĞŶ ĞůƵŐĂ'ϱ͕ϲϭϮ͛ϱ͕ϲϮϮ͛ϱ͕Ϯϭϲ͛ϱ͕ϮϮϱ͛ϭϬ͛ϬϳͬϬϮͬϮϭ KƉĞŶ ^ƵŶĨŝƐŚ ϭϯ͕ϭϭϬΖ ϭϯ͕ϭϳϬΖ ϭϮ͕ϬϴϰΖ ϭϮ͕ϭϯϵΖ ϲϬΖ ϭͬϮϱͬϭϵϵϴ ĞŵĞŶƚĞĚŽŶ ϵͬϮϱͬϮϬϬϮ E&ŽƌĞůĂŶĚƐ ϭϯ͕ϲϱϮΖ ϭϯ͕ϲϴϲΖ ϭϮ͕ϱϳϵΖ ϭϮ͕ϲϭϬΖ ϯϰΖ ϮͬϭϬͬϭϵϵϴ /ƐŽůĂƚĞĚ E&ŽƌĞůĂŶĚƐ ϭϯ͕ϳϭϴΖ ϭϯ͕ϳϯϲΖ ϭϮ͕ϲϯϵΖ ϭϮ͕ϲϱϲΖ ϭϴΖ ϮͬϭϬͬϭϵϵϴ /ƐŽůĂƚĞĚ E&ŽƌĞůĂŶĚƐ ϭϯ͕ϴϭϴΖ ϭϯ͕ϴϱϲΖ ϭϮ͕ϳϯϬΖ ϭϮ͕ϳϲϱΖ ϯϴΖ ϮͬϭϬͬϭϵϵϴ /ƐŽůĂƚĞĚ E&ŽƌĞůĂŶĚƐ ϭϯ͕ϵϰϰΖ ϭϯ͕ϵϲϲΖ ϭϮ͕ϴϰϰΖ ϭϮ͕ϴϲϰΖ ϮϮΖ ϮͬϭϬͬϭϵϵϴ /ƐŽůĂƚĞĚ BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB hƉĚĂƚĞĚLJ͗,ϱͬϵͬϮϮ WZKWK^ EŽƌƚŚŽŽŬ/ŶůĞƚhŶŝƚ tĞůů͗E/ͲϬϮ >ĂƐƚŽŵƉůĞƚĞĚ͗ϬϱͬϮϵͬϮϭ Wd͗ϭϵϳͲϮϭϬ W/͗ϱϬͲϴϴϯͲϮϬϬϵϬͲϬϭͲϬϬ /^K>d : t >Zz ^ŚŽƌƚ^ƚƌŝŶŐ EŽĞƉƚŚ ;DͿ ĞƉƚŚ ;dsͿ/ K /ƚĞŵ >ϴ͕ϭϴϰ͛ϳ͕ϰϴϭ͛Ϯ͘ϯϰϳ͟ϰ͘ϳϱϬ͟DK<DD'>D Dϵ͕ϯϬϯ͛ϴ͕ϰϴϱ͛Ϯ͘ϯϰϳ͟ϰ͘ϳϱϬ͟DK<DD'>D EϭϬ͕ϮϵϬ͛ϵ͕ϰϱϭ͛Ϯ͘ϯϰϳ͟ϰ͘ϳϱϬ͟DK<DD'>D KϭϬ͕ϱϵϯ͛ϵ͕ϳϱϭ͛Ϯ͘ϰϰϬ͟ϴ͘ϯϰϬ͟,ĂůůŝďƵƌƚŽŶZ,ƵĂůWĂĐŬĞƌ WϭϬ͕ϲϭϯ͛ϵ͕ϳϳϭ͛Ϯ͘ϯϭϯ͟, ^yEŝƉƉůĞ YϭϬ͕ϲϮϰ͛ϵ͕ϳϴϮ͛Ϯ͘ϮϱϬ͟, ^yEEŝƉƉůĞǁͬϮ͘ϯϭϯ͟WyEWůƵŐ^Ğƚ ZϭϬ͕ϲϮϱ͛ϵ͕ϳϴϮ͛Ϯ͘ϰϰϭ͟t> ' >ŽŶŐ^ƚƌŝŶŐ ϵ͕Ϯϯϴ͛ϴ͕ϰϮϱ͛Ϯ͘ϴϲϳ͟ϱ͘ϯϵϬ͟DK<h''>D &ϭϬ͕ϯϱϮ͛ϵ͕ϱϭϯ͛Ϯ͘ϴϲϳ͟ϱ͘ϯϵϬ͟DK<h''>D 'ϭϬ͕ϱϵϮ͛ϵ͕ϳϱϬ͛Ϯ͘ϵϬϬ͟ϴ͘ϯϰϬ͟,ĂůůŝďƵƌƚŽŶZ,ƵĂůWĂĐŬĞƌ ,ϭϯ͕ϱϮϯ͛ϭϮ͕ϰϲϭ͛ϯ͘ϬϬϬ͟ĂŬĞƌEŽͲ'Ž>ŽĐĂƚŽƌ /ϭϯ͕ϱϮϰ͛ϭϮ͕ϰϲϮ͛ϯ͘ϬϬϬ͟ϯͲϭͬϮ͟^ĞĂůƐƐĞŵďůLJ :ϭϯ͕ϱϯϬ͛ϭϮ͕ϰϲϳ͛ ŶĚŽĨdƵďŝŶŐ <ϭϯ͕ϲϮϱ͛ϭϮ͕ϱϱϰ͛, ^DĂŐŶĂZĂŶŐĞƌŝĚŐĞWůƵŐ 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 / N2 Operations 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 14,537 feet 12,054; 7,604; 7,330 feet true vertical 13,377 feet N/A feet Effective Depth measured 7,330 feet 4,554; 4,781 feet true vertical 6,737 feet 4,263; 4,467 feet Perforation depth Measured depth 4,584 - 5,622 feet True Vertical depth 4,290 - 5,225 feet 4-1/2" 12.6 / L-80 4,802 MD 4,486 TVD Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5 / L-80 10,626 MD 9,783 TVD 3-1/2" 12.95 / L-80 13,530 MD 12,467 TVD Packers and SSSV (type, measured and true vertical depth)DLH Pkr 4,554/4,263 & 4,781/4,467 SLVN 359/359 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 2,670psi 7,930psi 5,380psi 10,900psi 907 777-8376 11,640psi 2,535 8,123 10,224 12,460 13,306 2,602 8,909 Conductor Surface 10,870psi 20" 13-3/8" 9-5/8" 11,086 2,784 Size 3 Liner Casing Structural Liner 935 Length 407 Production N/A Junk 5. Permit to Drill Number: 5,914 North Cook Inlet / Tertiary Gas PoolN/A measured 11,086 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 82 N/A Oil-Bbl 0 Water-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-146 250 Authorized Signature with date: Authorized Name: 1 WINJ WAG STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 197-210 50-883-20090-01-00 Plugs ADL0017589 N Cook Inlet Unit B-02 measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 490 Casing Pressure 3-1/2" 30" 13,522 MD 407 2,602 8,909 14,457 TVD 407 measured true vertical Packer 7" Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Meredith Guhl at 8:38 am, Jul 30, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.07.30 07:14:05 -08'00' Dan Marlowe (1267) RBDMS HEW 8/2/2021 DSR-8/2/21 SFD 7/30/2021BJM 11/17/21 _____________________________________________________________________________________ Updated By: JLL 07/28/21 SCHEMATIC North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01 PBTD: 14,377’ TD: 14,537’ 20” RKB =59’ RKBtoMSL = 132’, MLLW to Mudline = 100’ 7” TOC 4000’ TBG punch 7,545’ H I 10 9 11 E F 2 3 Stg Tool @ 4,045’ 13-3/8” 9-5/8” 8 1 3-1/2” TOC @ 10,088’ 45 6 7 TOC @ 12,054’ WLM G 30” Stg Tool @ 7,385’ Tubing Punch @ 13,140’ – 13,142’ J K Sunfish N Forelands TOC 7,330’ CI 8 Lwr CI 9 CI10 CI 11 Beluga A Beluga C BelugaD Beluga E Beluga F Beluga G Tbg Cut 8,025’ Long String & 7,800’ Short String L M N O P Q R X X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 4,802’ 2-7/8” 6.5 L-80 CS Hydril 2.441” 8,025’ 10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection 7,800’ 13,530’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 359’ 359’ 3.813 5.510 Halliburton SVLN (WLR) Dummy ID=2.62 2 1,656’ 1,647’ 3.937 7.032 GLM #1 Camco MMG 1.5" VALVE 3 3,083’ 2,965’ 3.937 7.032 GLM #2 Camco MMG 1.5" VALVE 4 4,402’ 4,128’ 3.937 7.032 GLM #3 Camco MMG 1.5" VALVE W/1/2" ORIFACE 5 4,554’ 4,263’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 6 4,767’ 4,454’ 3.810 5.500 Sliding sleeve (Up to open) 74,781’4,467’3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 8 4,800’ 4,484’ 3.810 5.000 X nipple 9 4,802’ 4,486’ 3.958 4.500 WLEG 10 7,500’ 6,886’ - 8.125 Cement Retainer –TOC 7,330’ 11 7,604’ 6,977’ - 8.125 CIBP PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status C.I. 8 Lower 4,584’ 4,596’ 4,290’ 4,301’ 12’ 05/28/21 Open C.I. 9 4,615’ 4,623’ 4,318’ 4,325’ 8’ 05/28/21 Open C.I. 9 4,665’ 4,673’ 4,363’ 4,370’ 8’ 05/28/21 Open C.I. 10 4,694’ 4,710’ 4,389’ 4,403’ 16’ 05/27/21 Open C.I. 11 4,742’ 4,762’ 4,432’ 4,450’ 20’ 05/27/21 Open Beluga A 4,799’ 4,809’ 4,483’ 4,492’ 10’ 07/03/21 Open Beluga C 5,153’ 5,163’ 4,802’ 4,811’ 10’ 07/03/21 Open Beluga D 5,192’ 5,210’ 4,837’ 4,854’ 18’ 07/03/21 Open Beluga D 5,232’ 5,237’ 4,873’ 4,878’ 5’ 07/03/21 Open Beluga D 5,244’ 5,248’ 4,884’ 4,888’ 4’ 07/03/21 Open Beluga D 5,279’ 5,287’ 4,916’ 4,923’ 8’ 07/03/21 Open Beluga E 5,348’ 5,355’ 4,978’ 4,985’ 7’ 07/03/21 Open Beluga E 5,377’ 5,391’ 5,004’ 5,017’ 14’ 07/03/21 Open Beluga E 5,409’ 5,416’ 5,033’ 5,040’ 7’ 07/02/21 Open Beluga E 5,449’ 5,469’ 5,069’ 5,087’ 20’ 07/02/21 Open Beluga F 5,554’ 5,562’ 5,164’ 5,171’ 8’ 07/02/21 Open Beluga F 5,598’ 5,604’ 5,204’ 5,209’ 6’ 07/02/21 Open Beluga G 5,612’ 5,622’ 5,216’ 5,225’ 10’ 07/02/21 Open Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated Superseded TOC in 13-3/8 x 9-5/8" annulus = 4050 calculated bjm _____________________________________________________________________________________ Updated By: JLL 07/28/21 SCHEMATIC North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01 ISOLATED JEWELRY Short String No Depth (MD) Depth (TVD)ID OD Item L 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM M 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM N 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM O 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer P 10,613’ 9,771’ 2.313” HES X Nipple Q 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set R 10,625’ 9,782’ 2.441” WLEG Long String E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug _____________________________________________________________________________________ Updated By: JLL 07/28/21 SCHEMATIC North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01 CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 4-1/2” 12.6 L-80 Supermax 3.958 Surf 4,802’ 2-7/8” 6.5 L-80 CS Hydril 2.441” 8,025’ 10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection 7,800’ 13,530’ JEWELRY DETAIL No Depth (MD) Depth (TVD) ID OD Item 1 359’ 359’ 3.813 5.510 Halliburton SVLN (WLR) Dummy ID=2.62 2 1,656’ 1,647’ 3.937 7.032 GLM #1 Camco MMG 1.5" VALVE 3 3,083’ 2,965’ 3.937 7.032 GLM #2 Camco MMG 1.5" VALVE 4 4,402’ 4,128’ 3.937 7.032 GLM #3 Camco MMG 1.5" VALVE W/1/2" ORIFACE 5 4,554’ 4,263’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 6 4,767’ 4,454’ 3.810 5.500 Sliding sleeve (Up to open) 7 4,781’ 4,467’ 3.990 8.250 9 5/8 43.5-53.3# DLH Packer 58k shear release 8 4,800’ 4,484’ 3.810 5.000 X nipple 9 4,802’ 4,486’ 3.958 4.500 WLEG 10 7,500’ 6,886’ - 8.125 Cement Retainer – TOC 7,330’ 11 7,604’ 6,977’ - 8.125 CIBP PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status C.I. 8 Lower 4,584’ 4,596’ 4,290’ 4,301’ 12’ 05/28/21 Open C.I. 9 4,615’ 4,623’ 4,318’ 4,325’ 8’ 05/28/21 Open C.I. 9 4,665’ 4,673’ 4,363’ 4,370’ 8’ 05/28/21 Open C.I. 10 4,694’ 4,710’ 4,389’ 4,403’ 16’ 05/27/21 Open C.I. 11 4,742’ 4,762’ 4,432’ 4,450’ 20’ 05/27/21 Open Beluga A 4,799’ 4,809’ 4,483’ 4,492’ 10’ 07/03/21 Open Beluga C 5,153’ 5,163’ 4,802’ 4,811’ 10’ 07/03/21 Open Beluga D 5,192’ 5,210’ 4,837’ 4,854’ 18’ 07/03/21 Open Beluga D 5,232’ 5,237’ 4,873’ 4,878’ 5’ 07/03/21 Open Beluga D 5,244’ 5,248’ 4,884’ 4,888’ 4’ 07/03/21 Open Beluga D 5,279’ 5,287’ 4,916’ 4,923’ 8’ 07/03/21 Open Beluga E 5,348’ 5,355’ 4,978’ 4,985’ 7’ 07/03/21 Open Beluga E 5,377’ 5,391’ 5,004’ 5,017’ 14’ 07/03/21 Open Beluga E 5,409’ 5,416’ 5,033’ 5,040’ 7’ 07/02/21 Open Beluga E 5,449’ 5,469’ 5,069’ 5,087’ 20’ 07/02/21 Open Beluga F 5,554’ 5,562’ 5,164’ 5,171’ 8’ 07/02/21 Open Beluga F 5,598’ 5,604’ 5,204’ 5,209’ 6’ 07/02/21 Open Beluga G 5,612’ 5,622’ 5,216’ 5,225’ 10’ 07/02/21 Open Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated _____________________________________________________________________________________ Updated By: JLL 07/28/21 SCHEMATIC North Cook Inlet Unit Well: NCI B-02 Last Completed: 05/29/21 PTD: 197-210 API: 50-883-20090-01 ISOLATED JEWELRY Short String No Depth (MD) Depth (TVD) ID OD Item L 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM M 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM N 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM O 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer P 10,613’ 9,771’ 2.313” HES X Nipple Q 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set R 10,625’ 9,782’ 2.441” WLEG Long String E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug 1 Winston, Hugh E (CED) From:Katherine O'connor <Katherine.Oconnor@hilcorp.com> Sent:Tuesday, October 12, 2021 3:27 PM To:McLellan, Bryan J (CED) Subject:RE: [EXTERNAL] B-02 (PTD 197-210) CBL Attachments:NCI B-02 Final CBL Logs.pdf Hi Bryan Here is the final copy of the CBL we ran in B‐02. There is no indication of cement behind pipe per the log, but after cementing we are unable to pump down the annulus & it passes a pressure test to 2500 psi (there was >1bpm injection rate prior to cementing. Further, there is no indication of reservoir communication behind pipe between sands. Have not been able to figure out what happened with the log. Thanks Katherine From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 12, 2021 12:55 PM To: Katherine O'connor <Katherine.Oconnor@hilcorp.com> Subject: [EXTERNAL] B‐02 (PTD 197‐210) CBL Katherine, Can you send me the latest 9‐5/8” CBL run in this well? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Winston, Hugh E (CED) From:Katherine O'connor <Katherine.Oconnor@hilcorp.com> Sent:Wednesday, October 20, 2021 3:23 PM To:McLellan, Bryan J (CED) Cc:Aras Worthington Subject:FW: [EXTERNAL] NCIU B-02 (PTD 197-210) Closed Blind Rams on E-line tools Attachments:B-02 Schematic 2021-07-28.pdf Hi Bryan The rams got closed on the toolstring because the crew believed to have the EL tools fully bumped up and in the lubricator. They closed the rams to isolate the well (standard practice) and noticed the tools were across the BOPs. It was not related to a well control concern. They did not test the BOPs immediately after this event. They applied pressure to the casing but only up to 500 psi. They did not believe the BOPs to be damaged after a visual check, hence not doing a full test, but best practice would be to test BOPs and I intend to make that clear in the future. Also, attached is the updated schematic for B‐02. Thanks Katherine From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 19, 2021 11:37 AM To: Katherine O'connor <Katherine.Oconnor@hilcorp.com> Cc: Aras Worthington <Aras.Worthington@hilcorp.com> Subject: [EXTERNAL] NCIU B‐02 (PTD 197‐210) Closed Blind Rams on E‐line tools Katherine, Can you expand on the events of 5/22/21, when the blind rams were closed on the wireline toolstring? What was the cause? Were the blind rams tested after it happened? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 04/30/2021 - Friday Crews arrived at Tyonek platform and recieved orientation. Offload carrier, double and single base beams, rig mat, a- Legs, mud pits, drawworks. Prep deck for setting rig components. Cut handrails loose from skid beam and remove lifting eyes from hatch covers for base beams to sit. Spot double base beam, set rig mat and single base beam. Install and bolt up spreader beams. Sit carrier on base beams and install a-legs. Offload carrier landings and tool basket form boat. Install landings on carrier, Sit drawworks, and mast on carrier. Sit racking beam and racking mat in place. Off load boat. Spot mud pits, mud pump, bang board, accumulator house and connexs. Install stairs on front of carrier. Sit dog house. Run power to tool connexs. Off load boat. Run mud pump remote control lines and panel to rig. Welder re-installed handrails around carrier base beams. Installed vent extension on poor boy degasser. Prep mast, sit blocks in mast and reeve string up rope through crown and blocks. Rest of daylight crew arrived on location from Granite Point Platform. Raise mast, string up line crossed. Pull back string up line un cross and re-reeve same. Welder building an access panel to be installed from pits to sand trap. Welder cut access hatch in pits. Last of rig crews arrived on location form Granite Point Platform. Scope up derrick. Untangle guy wires. Lower derrick for wireline access. Run hoses from mud pits to pump. Assist crane crew with setting stairs, equipment and offshore baskets. Offload work boat. Finish hatch in pits. Assess access to top of tree for wireline work. Rig up air manifold under rig. Assist welder with modifying drip pan and securing stairs. Continue housekeeping and organizing. Prep bolts for nipple up. Secure handrails and stairs around rig package. Fill mud pit with drill water. Lay out circulating hoses and accumulator hoses. 05/01/2021 - Saturday 05/02/2021 - Sunday R/U circulating lines, swap out flanges on annulus for taking returns to production. Move equipment and secure rig to skid back 12" for access to pull 8' X 8' hatch cover when we N/D tree. Clean cap threads on annular and install studs. Prime and run mud pump. Continue with housekeeping from rig move. N/U adapter flange and Bowen connection to tree flange on long string side. Assist electrician with running power to rig bang board. Assist Quadco with installation of gas sensors and rig up of RigSense system. (Gave 48 hour notice to AOGCC for upcoming BOPE test). Continue helping Quadco with gas sensors and RigSense rig up. Stage equipment for skidding rig back 12". Install railing on back of doghouse. Check precharge on accumulator bottles. R/U Pollard wireline to drift 3 1/2" long string. Test lubricator at 1500 psi. Open SSSV with 8500 psi. Run 2.62" gauge ring but unable to pass SSSV. Run 2.52" gauge ring down to 9000' without issue. POOH. Simops: Weld jacking plates to skid rail. Skid rig +-8" to remove hatch cover. Rotate 11" 10K tree cap flange to SS side. Test lubricator at 1500 psi. Run 2.27" gauge ring to 9000' without issue. POOH. OOH pressure increased to 700 psi. Rig down slick line. Rig up Pollard e-line. Rehead tools. Production bled down tubing pressure to 0 psi. Make up jet cutter. Test lubricator at 1500 psi. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 Make up jet cutter. (Gave 48 hour notice to AOGCC for upcoming BOPE test) Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 Set and secure riser on wellhead. Skid rig back over hole center. N/U mud cross, double gate, annular and single gate. Spot choke manifold and install targeted tee on the inlet of same. Torque up all flange bolts on BOPE to specs. M/U targeted tee and 3" choke hose. Nipple up 2" kill line and 2" choke line to mud cross. Run and make up 2" line from choke manifold to gas buster. Raise & scope mast, secure same, run tugger Lines. R/U accumulator lines to stack, install drip pan, spacer spool & rig floor. Unload work string from boat, prep pipe racks. Install wind walls & stairs to rig floor. r/u choke panel, install choke line, weight indicator, p/u bails, troubleshoot & function test BOPE, good. R/U e-line unit on 2 7/8" short string side. O-rig leaked on lubricator on pressure test. Change out O-ring and test lubricator to 1500 psi- Good. Start in hole and e-line unit died. Trouble shoot issue (alternator) and mitigate problem. Open SSSV (showing 800 psi on tubing). RIH w/ 2.063" jet cutter to 8100' POOH to ~ 7050' for tie in to collars. RIH to 8100' pull up to put cutter at 8025' WLM and fire cutter. Good indication of cut at surface (tubing pressure dropped from 800 psi to 700 psi), POOH w/ cutter to lubricator. Shut in wellhead and bleed off pressure on lubricator. PJSM w/ production operator. R/U to reverse circulate to production header. Blow down lubricator, pop off and install plug on end of wireline tool. Stab lubricator back onto tree. Line up to reverse circulate. Open return line to production header slowly allow for pressure to bleed down f/ 700 psi to 0 psi. Start pumping slowly staging up to 3 bpm and 300 psi on annulus. Pumped 49 bbl. drill water. Bleed off pressure (tubing on a slight vac). Shut in well and pop off lubricator. Remove tree cap flange and re-orient w/ Bowen connection over long string. M/U 2.50" jet cutter on bottom of e-line tools, stab lubricator back onto tree. RIH to 8100'. POOH to ~ 7980' for tie in. RIH to 8100' pull up to put cutter @ 8025' WLM and fire cutter. Saw good indication of cut at surface. Tubing pressured up f/ 0 psi to 700 psi. POOH w/ e-line to lubricator. Tools hung up in SSSV but able to pull free. Lost spent tubing cutter in the process. Shut in well, bleed off pressure and R/D e-line. Remove adapter flange from tree and make up pumping flange on long string. Line up to reverse circulate. Bleed down 600 psi on long string to production header (all water with corrosion inhibitor). Reverse circulate at +-2 BPM /100 psi. Caught pressure after 59 bbls pumped. Increase rate to 2.8 BPM/850 psi. Reverse circulate total of 525 bbls. Well bore was pickled with corrosion inhibitor. Shut down. Monitor well 15 minutes. LS on slight vac. Annulus static. Blow down lines. Rig down circulating hoses. Unbolt and remove tree cap. Set BPV's. Both LS and SS on slight vacuum or static. Remove hatch cover. Remove wing valves. Nipple down tree (17,750 lbs). Clean tubing hanger and prepare for nipple up. Install blanking plugs. 05/04/2021 - Tuesday 05/03/2021 - Monday RIH w/ 2.063" jet cutter t Line up to reverse circulate. Open return line to production header slowly allow for pressure to bleed down f/ 700 psi to 0 psi. Start pumping slowly staging up to 3 bpm and 300 psi on annulus. Pumped 49 bbl. drill water. Bleed down 600 psi on long string to production header (all water with corrosion inhibitor). Reverse circulate at +-2 BPM /100 psi. Caught pressure after 59 bbls pumped. t cutter @ 8025' WLM and fire cutter. Reverse circulate total of 525 bbls. re-orient w/ Bowen connection over long string. M/U 2.50" jet cutter Annulus static. Skid rig back over hole center. Nipple down tree ( R/U e-line unit on 2 7/8" short string side. O LS on slight vac. o put cutter at 8025' WLM and fire cutter. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/05/2021 - Wednesday Build 2 7/8" & 3 1/2" test jt.s. Trouble shoot and correct Koomey remote control issue with single gate ram functions (loose Cad-5 connection). Function YellowJacket single gate rams, ODS ram body will not fully retract when placed in the open position. Trouble shoot single gate issue. Open doors and inspect cavity and ram block (cavity clear and no abnormalities observed on ram block. Locking mechanism is backed out and not making contact with ram shaft. Mobilize YellowJacket out to trouble shoot equipment. YellowJacket on location. Function single gate rams and take measurements. Visually inspect ram cavities, blocks, shafts and ram guides- appear to be good. Swap controls and function rams w/ same result - not fully retracting. Close doors. Install test jt. close rams on pipe, open w/ same result. Open bleeder gland on ODS ram body to bleed off trapped air (did not see any air). Function rams w/ same results. L/D test jt. R/D floor and N/D YellowJacket single gate. Open single gate remove rams, bleed system measure rods, finding trouble rod .07' longer than other side rod, attempt to see if able to change by rotating shaft with no results, consult & decide to bring double gate out to replace single setup transportation for a 1:00am callout to load at dock. (next available tide). Button up single gate, assist crane unload & spot strong-back & 3 400 bbl upright tanks, install 2 7/8" test joint fill stack with fluid. Shell test surface eq. & annular w/2 7/8" TJ repair leak on L/D pin, cont. test 250/2500psi, w/no visible leaks, test with variable rams same results. Pull test joint. Housekeeping & organizing decks. Unload boat with Double gate BOPE, load 2 3/8 x 3 1/2" dual flex rams, N/U to stack. install bolts & tq same. Install floor, l/d floor to trim obstruction. 05/06/2021 - Thursday Tighten flange bolts on Double gate. Modify rig floor mouse hole sleeves to fit over ram body, work on 400 bbl upright tank plumbing. Install rig floor and windwalls. P/U 2 7/8" test jt. and attempt to make up to short string blanking sub. Unable to get over. Pump out riser and stab onto short string sub, make up to same. P/U 3 1/2" test jt. and make it up to long string blanking sub. Fluid pack BOPE and shell test dual rams and top double gate flange connection w/ 250/2500 psi. Good test. Clear racking mat of power tongs, circ. head and misc. equipment. Pick up tools in well head room. Housekeeping around rig. Test BOPE to Hilcorp and AOGCC standards. Test all components to 250 psi low and 2500 psi high for 5 min. charted. Tested with 2 7/8" and 3 1/2" test jt.s. (tested dual flex rams with each test jt. on both short and long strings)Witness of test by AOGCC waived by Mr.Jeff Jones. HCR ck. failed initial HP test. Greased valve and retested good. R/D test e/q, pull blanking subs, pull BPV's from short & long string, well static. R/U slide, modify hand rail for slide on ODS, r/u working plate & dual slips, modify & install slide stand. r/u handling eq. M/U landing joint to short string hanger, BOLD pins. Pull short string hanger off seat @ 40k, string moving @ 50-60k, pulled 24' & started pulling over, attempt slack off but string would not move downhole, work pipe at 30k over no joy, rig up to circulate. (tested dual flex rams with each test jt. on both short and long strings)Witness of test by AOGCC waived by Mr.Jeff Jones. Pull short string hanger off seat @ 40k, Open single gate remove rams, bleed system measure rods, finding trouble rod .07' longer than other side rod, string moving @ 50-60k, pulled 24' & started pulling over, attempt slack off but string would not move downhole, work pipe at 30k over no joy, Test BOPE to Hilcorp and AOGCC standards. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/07/2021 - Friday Center rig over hole while waiting on arrival of NXS-Lube coming from the Granite Point platform. Run pump to establish pump rate and pressures. Work on stroke counter. Pump 2 drums NXS-Lube down tubing and chase w/ drill water @ 2 bpm , 700 psi. Circulate NXS-Lube up annulus @ 2 bpm , 730 psi. R/D circulating head and hose from string. Work pipe. Start pick up w/ 90k and down to 40k with no movement either way. Worked up in stages to max pull of 130k. Had 12" of play and then no more movement up. R/U 3" trash pump to annulus and pump out stack and riser to well head. Blow down hoses. Remove TIW valve and x/o from 3 1/2" test jt. and take to rig floor. Build 3 1/2" landing joint for Long string, install same, R/U dual elevators, install over landing joints. Pull on long string hanger came off seat @ 100k, cont. pulling up t/132k, moved approx. 1', short string started to move. Latched both strings, started moving @ 158k, -165k dragging, pulled SS hanger to floor, cont. pulling to get LS hanger to floor string stopped moving, pulled up t/178k no joy. Set slips. Long string cut 8005', SS tail 7981'. L/D landing upper section of landing joint on LS, L/D landing joint from SS & replace with 8' PUP. P/U on SS t/ 60k, P/U on long string t/95k, pull on both strings t/165k moved up hole 6' dragging, then stalled out, pulled up t/190 staging up with no joy, attempt to work down with no luck. SS tail@ 7974', L/S tail @ 7998'. Continue working with no joy. Attempt to wk strings independent with no luck. Discuss options for forward plan, unload boat organize decks. 05/08/2021 - Saturday Offload boat, housekeeping while discussing formulating a plan forward with town. Notify Ak. E-Line to mobilize tools and crew. Attempt to work 3 1/2" long string past 2 7/8" short string. At 150k short string started coming up with long string. Discuss situation with town. Perform rig maintenance and housekeeping while waiting on e-line crew to arrive. Inspect derrick from crown down (All Good). Housekeeping, Set both strings in the slips and verify short string SSSV is still open. Spot and R/U e-line unit. Run CCL log in short string f/ 450' to surface. Hung up in SSSV on TOH ( pressure had bleed off f/ 6000 psi to 2000 psi, had to pump up valve while pulling through due to pressure bleeding off) Pop off short string and inspect rope socket (Good). Move to long string and log from 430' to surface. L/D CCL tool, print and review logs. Make up string shot. RIH correlate & position @ 337', fire shot, good indication it went off, POOH w/e-line & L/D, r/u to string's pull on duals, wk string with no joy. Discuss options with Engineering for making cuts. Position both strings in slips with no OP. R/U e-line with 2.06" Jet cutter to SS, rih correlate to 444', (Just below tool joint across from LS TRSV) fire cutter with good indication cutter fired. Attempt POOH w/ e-line, unable to move, wk string free, cont. POOH hanging up at SSSV, (Pump on Valve to try & hold open (would not hold pressure const. pumping @ 4k psi), unable to wk through. R/U to pump-in sub, pump down SS @ various pump rates while working e-line tools, did get worked free. Cont. POOH cutter fired. Inspect rope socket, Re-head same, m/u 2.5" Jet cutter. RIH & correlate to 340' WLM, (2' below tool joint across from SS TRSV) Fire cutter, had good indication cutter fired, POOH r/d e-line. R/U t/Pull string, latch up to long & short string. Pull up t/70k with no movement. Wk Strings with no luck. Discuss options. fire cutter w Pull up t/70k with no movement. 340' WLM, (2' below tool joint across from SS TRSV) Fire cutter, rih correlate to 444', Latched both strings, started moving @ 158k, -165k dragging, pulled SS hanger to floor, cont. pulling to get LS hanger to floor string stopped moving, pulled up t/178k no joy. Jet cutter to SS, Jet cutter. attempt to work down with no luck. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/09/2021 - Sunday Discuss options among rig team on location and engineer in town. R/U e-line and run CCL tool in long string to verify separation on previous cut (36' of separation). M/U 2.5" Jet cutter, RIH and correlate to 210' WLM in long string. Fire cutter had good indication cutter fired. POOH. M/U 2.06" Jet cutter, RIH and correlate to 280' WLM in short string. Fire cutter, had good indication cutter fired. POOH and R/D e-line. P/U both strings (PUW 10k) and pull long string hanger above rig floor. Break out and lay down 3 1/2" long string landing jt. Back out and lay down 2 7/8" short string hanger and pups. L/D long string hanger, pups, 3 full jt.s and cut jt. (11.31'). C/O Weatherford dual string elevators for 2 7/8" YT elevators. POOH laying down 2 7/8" short string. 1 pup, 6 full jts and cut jt. (11.2'). R/D Weatherford dual string handling equipment. R/U BHA handling equipment. L/D McCoy tongs and R/U Gills. Adjust rig jacks and center elevators over hole. M/U Fishing BHA #1 (Spear, dbl. pin sub, bit sub, bumper sub, oil jars,4 ea. 4 3/4 DC= 148.04) and RIH, Tag TOF @ 135'. Attempt to spear into fish with no luck. POOH stand back drill collars, no markings on spear. Mobe out skirted spear. P/U BHA #2, (Skirted Spear, dbl. pin sub, bit sub, bumper sub, oil jars, 4ea. 4 3/4 DC= 151.74) TIH to TOF tag @ 135', turn & fall over dropped 8" unable to engage, wk several times no joy. POOH, Inspect BHA had markings 3/8" on outside of spear nose, L/D skirted spear, P/U BHA # 3, (overshot w/dress off guide, bumper sub, oil jars, 4ea. 4 3/4 DC=143.10). TIH, tag top of fish @ 135', dress off top of fish & engage same. Check grapple, set, start jarring working up t/ 50k op, no action, lost ability to cock jars. Rotate off of fish, POOH. Unload boat, r/u base plate for casing jack, prep to P/U BHA. P/U BHA #4 (overshot w/dress off guide, bumper sub, oil jars, 4ea. 4 3/4 DC=150.97). RIH engage fish @ 135'. M/U 2.5" Jet cutter, RIH and correlate to 210' WLM in long string. Fire cutter had good indication cutter fired. P POOH laying down 2 7/8" short string. 1 pup, 6 full jts and cut jt. RIH engage fish @ 135' M/U 2.06" Jet cutter, RIH and correlate to 280' WLM in short string. Fire cutter, h Break out and lay down 3 1/2" long string landing jt. Back out and lay down 2 7/8" short string hanger and pups. L Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/10/2021 - Monday Engaged fish @ 135', Check grapple, set, start jarring working up t/ 50k w/ no upward movement, having difficulties getting jars to cock. P/U casing jack and strip over pipe and onto hole. R/U hydraulics and verify controls function. Jack up on fish f/ 135' to top of DC's @ 112' (established upward movement @ 185k decreasing to pulling steadily @ 70k). L/D joint of 3 1/2" PH6 work string. R/D and lift jack over pipe and off of hole. Release overshot from fish and POOH, stand back 1 std. collars. L/D 1 DC, bumper subs and oil jars. M/U overshot on 3 1/2" PH-6 work string and RIH. Tag up and engage fish @ 112'. R/U casing jack, Position Gills over pipe on top of casing jack. Jack our work string 112' to top of 3 1/2" long string fish. Took 70 k to start moving pipe but fell off to 45k after a few feet. Last joint above the fish pulled @ 15-20k. L/D overshot and 3 1/2" cut jt. Pull and l/d full jt. of 3 1/2" tubing, while pulling 2nd full jt. 2 7/8" short string came to surface. Continue to pull 3 1/2" and make 2 cuts on 2 7/8 (8' and 6'),With 80 ' of 3 1/2" out of hole pipe pulled tight (~80k).When pick up weight dropped back 2 7/8" fish fell back down hole. (Did find obstruction in top of SS fish that would not let spear engage on previous run). Rig down casing jack, Pull remaining L/S fish from hole + cut joint 20.05', 3 full joints, 2- pup joints, bottom cut 4.21' = 130', C/O handling eq. prep overshot for 2 7/8" fishing. P/U BHA #6 - 7 3/4" od cut lip guide dress off overshot, xo, = 5.45', TIH tag at 159' work string to get over fish, it fell away, cont. tih to tof tag & wk over attempt to engage but no indication. POOH found markings on one side of guide. Prep handling tools & P/U BHA #7 - 7 3/4" od cut lip guide dress off overshot, bumper sub, jars, 4- 4 3/4" DC, XO = 144.93, C/O handling tools for wk string, cont. TIH with wk string from derrick t/268', up wt 11k, dn wt 11k, wk string unable to engage. POOH stand back wk string & collars, inspect BHA. No Markings inside of cut lip guide to give indication we were getting over fish, breakdown. R/U & run 5.5" LIB on wire, tag @ 267'wlm, POOH, inspect LIB, had impression of 2 7/8" tubing top off one side of LIB. P/U BHA #8, 8 .125" od cut lip guide dress off overshot, bumper sub, jars, 4- 4 3/4" DC, XO = 147.81. TIH t/ 268' up wt 11k dn wt 11k, engage fish, picked up t/ 20k, cont. pulling t/ 26k fish came free, had extra 900#, POOH rack back wk string. Jack up on fish f/ 135' to top of DC's @ 112' Rig down casing jack, Pull remaining L/S fish from hole ++ cut joint 20.05', 3 full joints, 2- pup joints, bottom cut 4.21' = 130', Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/11/2021 - Tuesday Cont. POOH stand back work string and DC's to fish. L/D fish. (4 jts, SSSV w/ pups, 2 cut jt.s= 152.11'. P/U BHA #9, 7-3/4" od cut lip guide dress off overshot, bumper sub, jars, 4- 4 3/4" DC, XO = 141.70', Tag TOF @ 310'. Attempt to work over fish with no luck. POOH. No fish. Calibrate block height. Switch Gill tongs for making up. Inspect equipment on rig floor and organize same while waiting on fishing tools. Make up fishing BHA #10: 8 .125" OD cut lip guide, overshot,bumper sub, jars, 4- 4 3/4" DC, XO = 147.81. RIH engage fish @ 313', P/U t/ 150k, moved fish up hole 10', unable to move down hole. Release overshot, POOH stand back wk string & collars, l/d jars & bumper sub. RIH w/BHA #11: 8 .125" OD cut lip guide, overshot, xo =8.33'. TIH engage fish @ 309', P/U set in slips 65k. R/U e-line, hang sheave & r/u circulating line to pump in sub, decision was made to use Jet cutter from beach mobe out same. RIH with 2.5" jet cutter but unable to pass fish top @ 309' (likely damaged from short string falling on it) POOH & l/d cutter. Mobe out Swages to open fish top. M/U 2.5" swage rih to top of fish @ 309', knock it through tight spot, POOH. M/U 2.25" swage (was marked 2.6) RIH t/ 336' & tagged up, worked through tool joint & tagged up @ 367' at next tool joint worked it a few strokes but did not fall through. RIH w/ brush worked it through tool joint @ 367' down to tool joint @ 370'worked through, POOH had 200# op @ 367' tool joint. ran back down through same tool joint unable to work through it with brush easily. RIH w/2.5 swage tagged up in same tool joint 367'. POOH discuss options, round up 2.15" weight bar & centralizer to see if it will drift for RTC. 05/12/2021 - Wednesday Pollard RIH with weight bar and 2.15 drift to 418' without issue. R/D wireline. Pull 75K on string and set in slips. R/U e- line. RIH with 2" RCT cutter and set down at 419'. Attempt to work through without success. POOH. Consult with town. Decision made to R/U slick line and attempt to chase object downhole. Change out e-line unit for slick line unit. R/U same. RIH with 2.15" blind box. Tagged up at 417'. POOH and add weight bar to string. RIH and tag up at same spot. Work spangs and make another 2' back to 419'. POOH and inspect blind box with no appreciable marks. Pressure on tubing to 500 psi with .7 bbls pumped. No bleed off encountered. POOH and rig down slick line. Consult with town. Rig up to reverse circulate. Reverse circulate at 1 BPM with returns ater 3.5 bbls pumped building up to 315 psi before immediate pressure drop and object went through reverse hose. Increase reverse pump rate to 3 BPM/360 bbls for 45 bbls total. Line up and pump down string and up annulus at 3 BPM/440 psi for 69 bbls without issue. Rig down from circulating. Rig up Pollard e-line. RIH with 2" RTC. 373, work but unable to pass, POOH c/o t/2.5" swage to attempt to clear or center obstruction, rih t/373 DPM tag up not passing, POOH rih w/ 2" RCT cutter t/ 373 unable to pass.P/U 3.5" brush RIH t/ 373 DPM, unable to pass, work up & have OP at 367' but fall off, cont. work POOH with OP @ 367, 336 & 313', (at overshot ) cont work lost OP, RIH w/2.5 magnet, set down @ 313', work with no OP POOH no recovery. Re-Run magnet with same results. RIH w/ Brush, tag @ 313' work but unable to pass, no OP, POOH r/d e-line. Shuck overshot from fish, POOH stand back work string, & l/d overshot, recovered 29' of control line & recovered one of our obstructions in overshot above grapple. Break down overshot assy to retrieve junk piece. M/U test joint & test plug for dry run to check for seal, no visible leaks from plug. Pull test plug & l/d. P/U BHA #12: 8 .125" OD cut lip guide, overshot, xo =7.33', TIH engage fish @ 313' up wt 11k dn wt 11k. L/D fish. (4 jts, SSSV w/ pups, 2 cut jt.s= 152.11' POOH stand back work string, & l/d overshot, recovered 29' of control line & recovered one of our obstructions in overshot above grapple. Break down overshot assy to retrieve junk piece. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/13/2021 - Thursday Pollard slick line RIH with 2.15" blind box without issue to 445'. Attempt to pull back through SSV without success. Pump at +5 BPM/900 psi to assist while slick line worked spangs. Pulled out of rope socket. R/D slick line. R/U Pollard e-line. RIH with 2" RCT but unable to pass SSSV at 420'. Attempt to pump through at 3 BPM/350 psi without success. Decision made to cut above SSSV. Pull up to 404' WLM and make cut at depth. Good indication cutter had fired. POOH. Pick up on fish to 20K (cutter not effective). Make up Jet cutter. RIH and correlate on depth. Make cut at 405' WLM. Good indication cutter fired. POOH and R/D e-line. POOH standing back work string. Lay down fish. Recovered 75.09' : Cuts 26.96' and 16.85', full joint 31.28'. Pick up 2 7/8" test joint. Fluid pack BOPE. Shell test 250/2500 psi. Annular unable to hold more than 1500psi, move to pipe rams, good test. Test BOPE as per Hilcorp & AOGCC expectations, Test was witnessed by AOGCC inspector Matt Herrera, tested with 2 7/8" & 3 1/2" TJ, Annular failed high test. Clear floor, Blow down stack, secure well, r/d accumulator lines, pull stairs, slide wind walls, working plate & floor. N/D upper doublegate with dual rams & annular, N/U replacement annular & 2' spool. Install rig floor, stairs, slide, wind walls, work plate, tq flange bolts. 05/14/2021 - Friday Finish rigging up rig floor. Make up 4" test joint. Test annular at 250 L/2500 H. Change out test joints to 2 7/8". Test at 250 L/2500 H. Lay down test joint. Pick up and make up BHA #13 overshot assembly. RIH with BHA #13: 8 1/8" overshot to 345' (TOF at 384') pushing obstruction down to 355'. POOH with BHA #13. Lay down overshot and pick up Bulldog spear. RIH to 374' and work down to 384' working 4 rounds into control line fish. POOH and recovered +-145' of control line. Make second run with same assembly. POOH with no recovery. M/U & test 4" tj with variable rams 250/2500 good. M/U BHA # 16- 8 1/8" overshot assy, xo = 8.72', TIH t/ 384', up wt 11k dn wt 11k, dress off top of fish, Engage same, put 3 left hand turns in string when connection broke, back off till free. Swap out handling tools POOH stand back DP in derrick. L/D fish, recovered cut joint 14.63', 2-pup joints 11.47', top component of safety valve .85 =26.95', control line 35' with broken fitting from valve. Break down fish, Prep BHA #17. P/U BHA #17-8 1/8 cut lip guide, overshot guide, xo bushing, 1 jt wash-pipe xo, xo = 44.16', tih & tag @ 436', Pick up across ares feeling slight bobbles @ 406 & 416', inconclusive fish tops, POOH stand back wk string, L/D BHA,R/U e-line. POOH and recovered +-145' of control line. Make second run with same assembly. POOH with no recovery. Test annular at 250 L/2500 H. Lay down fish. Recovered 75.09' : Cuts 26.96' and 16.85', recovered cut joint 14.63', 2-pup joints 11.47', top component of safety valve .85 =26.95', control line 35' w N/U replacement annular & 2' spool. Fluid pack BOPE. Shell test 250/2500 psi. Annular unable to hold more than 1500psi, m Make cut at 405' WLM. Test was witnessed by AOGCC inspector Matt Herrera, tested with 2 7/8" & 3 1/2" TJ, Annular failed high test. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/15/2021 - Saturday Pollard e-line RIH with 5.5" LIB to 408' WLM. POOH and inspect image. Results inconclusive. Gather HES information on SSSV and consult with engineer. Decision made to make cut below SSSV as opposed to 2nd blind back-off. Make up BHA #18: Outside cutter with 8 1/2" KHT box, 1 jt wash pipe, drive sub, XO 4 DC's, XO = 163.11. RIH with BHA #18. Tag TOF at 408'. Rotate to get over and slack off over fish to 428' (top of SS fish). 14 K P/U, 13 K S/O. Rig up power swivel. Pick up from 428' to 421' and make cut under SSSV. 70 RPM/00 ft/lbs torque. Rig down power swivel. R/u handling tools. POOH stand back wk string & collars, L/D BHA with fish & break down, recovered TRSV & cut pup 3.65'= 10.92. Change oil in carrier, prep BHA. P/U BHA #19- 8 1/8" overshot assy, xo, xo, = 8.72'. RIH w/3 1/2" wk string t/ tag TOF @ 420', up wt 11k, dn wt 11k, engage fish, p/u 15k over string weight for cut depth. R/U e-line, & circulating line. Attempt to circulate tubing volume, pressured up 800 psi, shut down, bleed off, make several attempts with no luck. Pollard RIH w/ 2." swage on e-line t/420' work through obstruction at fish top, then drift several times. Continue RIH t/4500' with no issues. POOH logging cut area. Attempt to circulate with no luck. M/U 1 7/16" 3' 7 shot tubing punch. RIH & correlate on depth with top shot @ 4300', Fire punch. Inconclusive at surface if fired, POOH all shots fired. Break off tubing punch & make up 2" RCT. 05/16/2021 - Sunday Pollard e-line RIH with 2" RCT cutter and correlate on depth at 4335'. Make cut with good indication of fire. Troubleshoot issues with Pollard unit. POOH and rig down wireline. Pick up on string to 120 K before tubing parted at cut. String weight now 52K. Clear floor. POOH with fishing assembly #19. Lay down BHA. POOH laying down 3 1/2" PH6 fish. Clean and dope pin end threads. Recovered 124 joints and 2 cut joints = 3904.79'. New TOF on LS is 4335'. Clear and clean rig floor. Abandon platform drill. Pick up BHA #20: 8 1/8" X 2 7/8" Overshot cut lip dress-off, overshot, XO, XO, pup jt = 11.46, TIH t/ tof @429' with 3 1/2" wk string , m/u space out pups, engage fish & P/U t/ 427' up wt 48k. R/U e-line, & break circulation on SS, 1.5 BPM, 200psi, Good. RIH w/ 1.8" drift t/600 through fish top good, POOH. M/U RCT, RIH t/ 5950' correlate & cut @ 5825', drop back through cut verify good, POOH R/D e-line. POOH l/d space out pups, stand back wk string up wt 36k, c/o handling tools. POOH l/d 2 7/8" completion from 5400' t/2982'. New TOF on LS is 4335' top shot @ 4300', Fire punch. recovered TRSV & cut pup 3.65'= H l/d 2 7/8" completion from 5400' t/2982'. POOH laying down 3 1/2" PH6 fish. Pick up on string to 120 K before tubing parted at cut. o 421' and make cut under SSSV. RIH with 2" RCT cutter and correlate on depth at 4335'. Make cut with good indication of fire. M/U RCT, RIH t/ 5950' correlate & cut @ 5825', d Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/17/2021 - Monday Recovered 170 joints, 1 GLM, 8 pup joints. Finish POOH laying down 2 7/8" tubing and 2 cut off joints = +-5401'. New SS TOF at 5829'. Clean and clear rig floor. Change out handling equipment. Run 4" HT38 in hole and pull out laying down same. Change out handling equipment from 4" to 3 1/2". Pick up BHA #21: 8 1/8 Cutlip overshot, XO, XO, pup joint = 11.41'. RIH with BHA #21 picking up 3 1/2" PH6 work string to 4325'. P/U 44K, S/O 42K. Tag TOF at 4325' and engage to 4328'. P/U to 70K and set slips. Rig up Pollard e-line. RIH w/ 2.5 swage & ccl t/7200', clean, POOH pulled tight @ 4335', wk string free, cont. POOH. M/U & RIh w/2" RCT, log into position @ 5910', fire cutter, had good indication of cut. POOH r/d. Tubing u-tubing, rig up and equalize to pits. POH with work string, standing back in derrick. Breakdown BHA, L/D fish (3 1/2" PH6 completion, Long string ) L/D 49 joints, GLM with pups, 2- cut joints top-19.35, Btm 11.06'. Clear floor, prep to P/U BHA & wk string. 05/18/2021 - Tuesday Pick up BHA #22: 8 1/8" overshot, XO, XO, pup joint = 11.41. RIH with BHA #22 picking up PH6 work string to 2,860'. RIH with pipe out of derrick to TOF at 5798'. Swallow fish to 5,800'. Set slips with 71K. P/U 60K, S/O 54K. Rig up Pollard e- line. RIH with 1.69 drift to 7008'. POOH and make up 1 11/16" RCT. RIH and correlate on depth. Make cut at 6882'. POOH and R/D e-line. Pick up to 70K free string weight. POOH and lay down SS fish. recovered 2 cut joints, 2 GLM, 69 joints 2 7/8" tubing. (Did not see cut made @ 6,882'). new top of fish at 8,025, short string fish is out of hole. Pick up and make up 3 1/2" overshot. RIH to top of LS fish. Engage fish @ 5,910' attempt to work fish free, would not release, rig up E-Line for 2.5" blind box drift run. 05/19/2021 - Wednesday Pollard e-line RIH with 2.5" swage to 7822'. POOH. Make up and RIH with 2.5" Jet cutter. Unable to pass 5910' (TOF). POOH. Make up 2.0" RCT. RIH to 7790'. Lost continuity to CCL and tools. POOH. Rebuild tool string and check continuity. RIH and make cut at 7800'. POOH. R/D e-line. Pick up on string, free at 80K. POOH standing back work string. Lay down 3 1/2" LS fish. Recovered 2 cut jts, 2 pups, 1 GLM, 58 jts 3 1/2" tubing (1,891.11'), clear floor. Make up 9 5/8" scraper, would not go into well head. (body OD = 8', blade extended = 9.25', casing ID = 8.535') Lay down scraper, pick up and make up 8 1/2" concave mill. RIH, with 8 1/2" mill on tubing work string, to 7,789'. Rig up and circulate brine to shakers to clean hole. RIH and make cut at 7800' Make cut at 6882'. log into position @ 5910', fire cutter, Engage fish @ 5,910' attempt to work fish free, would not release, rig up E-Line (3 1/2" PH6 completion, Long string ) L/D 49 joints, GLM with pups, 2- cut joints top- Lay down 3 1/2" LS fish. Recovered 2 cut jts, 2 pups, 1 GLM, 58 jts 3 1/2" tubing (1,891.11'), c Make up 9 5/8" scraper, would not go into well head. (body OD = 8', blade extended = 9.25', casing ID = 8.535' lay down SS fish. recovered 2 cut joints, 2 GLM, 69 joints 2 7/8" tubing. (Did not see cut made @ 6,882'). Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/20/2021 - Thursday Reverse circulate STS to clean wellbore until clean at 3 BPM. Line up and displace well with clean drill water taking contaminated returns to production at 2 - 4 BPM. Pumped 1,000 bbls total. Simops: Slip and cut 72' drill line. POOH laying down 7 joints. POOH standing back work string. Lay down clean o ut BHA. Lay down 4 3/4" drill collars. Rig up Pollard e- line. Pick up 9 5/8" CIBP. RIH and correlate on depth. Set at 7600' WLM (16' above a collar). POOH. Rig down Pollard e- line. Test casing to 2,500 psi 30 min. (15 min loss = 20 psi, second 15 min loss 4 psi), total loss 24 psi, Good casing test . Strip rig floor equipment with crane too lift work platform. Nipple down BOPE, Lift BOPE and riser with tubing spool to platform floor, remove old tubing spool, install new adapter onto riser. 05/21/2021 - Friday Nipple up new tubing spool. Test pack off at 4500 psi for 15 minutes. Organize decks for bringing on Halliburton equipment. Rig up rig floor and pipe chute. Secure rig floor. Install choke and kill lines. Rig up accumulator hoses. Simops: rearrange equipment on drill deck. Offload remainder of Halliburton equipment. Blow off cement and set cement pumpkins back on boat. Test BOPE. Make up 3 1/2" test joint. Test annular at 250 psi/2500 psi. Change out test joints to 4 1/2", Test BOPE 250 psi /2500 psi. Lay down test joint, rig down test equipment. Rig up to displace 13 3/8" X 9 5/8' annulus from OBM to water, Move conexs and e-line unit to upper deck making room for cemt unit. Spot E-Line unit on upper deck. Test BOPE 250 psi /2500 psi. Test casing to 2,500 psi 30 min. (15 min loss = 20 psi, second 15 min loss 4 psi), total loss 24 psi, Good casing test. Pick up 9 5/8" CIBP. RIH and correlate on depth. Set at 7600' WLM (16' above a collar) r, remove old tubing spool, install new adapter onto riser. POOH laying down 7 joints. PO Test BOPE. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/22/2021 - Saturday Install shooting flange on annular preventer. Rig up HP hose from OA to drill deck with sample port. Install stairs from upper pipe deck to rig floor. Rig up Pollard to run perf gun. Offload work boat and rig up Halliburton equipment. Pollard RIH with perf gun and correlate on depth at 7,550'. Pressure test lubricator at 2,000 psi. Bleed back to 1000 psi. Fire guns (10 shots/ . 45 diameter) with no difference in hydrostatic pressures. POOH and rig down e-line. Guns had fired and had traces of OBM. Pressure up on tubing to 1,500 psi with no returns. Stage pressure up to 2,950 psi with same result. Bleed pressure off quickly with no change. Pressure up to +-2,900 psi 2 more times with same result. Consult with engineer. Swap hoses and pressure up 13 3/8" x 9 5/8" 1,500 psi with no returns several times. Establish injection rate at 1.5 BPM/1,650 psi. Pumped a total of 10 bbls. Monitor pressure for 10 minutes and bled off to 1,450 psi. Continue process of pressuring up tubing and annulus in attempt to 'rock' system. No circulation established. Mobilize crew to run CBL and next step larger perf guns. Continue to alternate pumping routes, without success, while waiting on personnel and additional perf guns from beach. Rig up Alaska E-Line, RIH with 9 5/8" CBL tools. Calibrate for 53.5# 9 5/8" casing @ 2,500', RIH tag CIBP at 7,604' wlm. log up to 5,550' wlm. No indication of cement bond. POH rig down CBL tools. Rig up lubricator. Make up (Charge part # 4C631 gun, 2.0", 7.0 gram, 19 each 5/8" shot) perforating gun, correlate on depth apply 1,000 psi to casing, fired guns at 7,545 wlm (5" below 9 5/8" casing collar), observed annulus pressure increase to 250 psi confirming communication between annulus and casing. POH with e-line. Bump up tools into lubricator. Close blind rams, bleed and make break in lubricator, observed wire line across lubricator, bleed pressure off casing and lubricator, open blind rams pull tools out of hole, lay down perf guns and tools. Blinds were closed on E-Line tools. Close blind rams and apply 500 psi to casing, observed annulus pressure increase to 200 psi. 05/23/2021 - Sunday Hold PJSM with all to be involved in displacement job. Halliburton prime pumps. Pressure up to 3500 psi on 9 5/8" with no returns from annulus. Bleed pressure and repeat process 3 times. Swap direction and pump down 13 3/8" x 9 /8" annulus. Injecting at 1. BPM/1600 psi. Shut down. Bleed off and monitor well. Zero pressure on both annulus and tubing. Consult with engineer. Rig up Pollard e-line. Stage perf gun (19 shot/.35" hole) at rig floor. Hold PJSM with all involved in operation. RIH with perf gun and set at 7545'. Halliburton pressure up on 9 5/8" to 2000 psi. Open annulus to surface tanks. Attempt to fire perf guns without success. Bleed off pressure. POOH and troubleshoot e-line issue. RIH with perf gun to 7545'. Pressure up to 2000 psi with Halliburton. Open annulus to surface tanks. Fire perf guns and establish circulation. Pump 50 bbls drill water, 60 bbls tuned prime spacer, 100 bbls surfactant wash and chase with +-1,320 bbls drill water. Various pump rates and pressures with final 800 bbls at 7 BPM/1450 psi. Recovered +-390 bbls of OBM. Shut down observe well, static. Rig up E-Line, make up 9 5/8" cement retainer, RIH, set at 7,500' wlm, (9' below collar), POH rig down E-Line. Make up cement retainer stinger. RIH on 3 1/2" work string. RIH tag CIBP at 7,604' wlm. log up to 5,550' wlm. Pressure up to 3500 psi on 9 5/8" with no returns from annulus. Rig up E-Line, make up 9 5/8" cement retainer, RIH, set at 7,500' wl Make up cement retainer stinger. RIH on 3 1/2" work strin perf gun and correlate on depth at 7,550' Fire perf guns and establish circulation. Pump 50 bbls drill water, 60 bbls tuned prime spacer, 100 bbls surfactant wash and chase with +-1,320 bbls drill water. Close blind rams, b Blind rams closed inadvertantly on e-line toolstring. Blind rams were not tested before next wellbore entry as required by 20 AAC 25.285(f)(2). Enforcement action issued - Docket OTH-21-053. E-Line, RIH with 9 5/8" CBL tools. Pressure up on tubing to 1,500 psi with no returns. Stage fired guns at 7,545 wlm No indication of cement bond. Fire guns (10 shots/ . 45 diameter) Swap direction and pump down 13 3/8" x 9 /8" annulus. Injecting at 1. BPM/1600 psi. Various pump rates and pressures with final 800 bbls at 7 BPM/1450 psi. Recovered +-390 bbls of OBM. Establish injection rate at 1.5 BPM/1,650 psi. observed annulus pressure increase to 250 psi confirming communication between annulus and casing. Blinds were closed on E-Line tools. Close blind rams and apply 500 psi to casing, observed annulus pressure increase to 200 psi. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/24/2021 - Monday Circulate at 1 BPM/100 psi while stabbing into cement retainer. Increase to 500 psi/shut down. Set down 20K, unsting and make space out adjustments. Rig up HES. Halliburton test lines at 4500 psi. Had leak. Replace 2" HP hose. Retest good. Sting into retainer at 7,500' with pressure increase noted. Pump 5 bbls drill water to verify circulation. Pump cement job as per procedure. Pumped 245 bbls primary cement and chase with 43 bbls drill water. CIP at 11:50 hrs. Pull out of retainer with 1100 psi to 0 psi leaving 12 bbls above retainer - TOC will be +-7,330'. POOH 4 stands to 7252'. Circulate pipe wiper ball at 3.5 BPM/450 psi. Simops: mixing 6% KCL in mix pit and transferring to 400 bbl upright. Circulate, displace well to 6% KCL, returned 8.6 clean KCL to surface. Total pumped 550 bbl. at 3.5 bpm at 420 psi. Pull out of hole laying down 3 1/2" work string. 05/25/2021 - Tuesday POOH laying down PH6 work string. R/U e-line RIH w/ 8.25 Gauge ring junk basket t/ 7330', WLM tag CMT, POOH left junk basket in hole. R/U CBL tools on e-line, not getting readings desired with 3.5" CBL tool, not finding cement behind pipe, made 3 runs calibrating tool with no change to results. Change out CBL tool to 2 .5" re run CBL from 2,800' to 4,980' no significant difference in results. POH rig down Alaska E-Line. Cleaning suction tank and rig up lines to pump down 9 5/8" X 13 3/3" annulus. Pump 12 bbl to fill annulus. rig up for charted casing test. Working boats. 05/26/2021 - Wednesday Cont. R/U & fill 13 3/8 x 9 5/8 annulus took 12 bbls to fill, stage pressures up & bleed air out until reaching 2250psi, held for 30 min lost 100 psi first 10 min, 70 psi last 20 min good. Bleed down & blow down lines. Unload 4 1/2" completion & tall from boat. Install shooting flange to BOPE. R/U e-line Pressure well bore up t/1050 psi, calibrated CBL tools & log from 7,300' to150'. Remove shooting flange. Rig up tubing tools, Pick up RIH with 4 1/2", 12.6#, L-80, Supermax completion tubing. CBL tools on e-line, not getting readings desired with 3.5" CBL tool, not finding cement behind pipe, made 3 runs calibrating tool with no change to results. leaving 12 bbls above retainer - p RIH with 4 1/2", 12.6#, L-80, Supermax completion tubing. no significant difference in results. - TOC will be +-7,330' calibrated CBL tools & log from 7,300' to150'. , displace well to 6% KCL, returned 8.6 clean KCL to surface. Ran CBL, 4th time in this well, once before cementing and 3 after. No indication of cement on logs, but pressure tests in the 9-5/8" x 13-3/8" annulus indicate that perfs are isolated. bjm & fill 13 3/8 x 9 5/8 annulus took 12 bbls to fill, Change out CBL tool to 2 .5" re run CBL from 2,800' to 4,980' Pump cement job as per procedure. Pumped 245 bbls primary cement and chase with 43 bbls drill water. reaching 2250psi, held for 30 min lost 100 psi first 10 min, 70 psi last 20 min good. R/U e-line RIH w/ 8.25 Gauge ring junk basket t/ 7330', WLM tag CMT, Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/27/2021 - Thursday Cont. Pick up RIH with 4 1/2", 12.6#, L-80, Supermax completion tubing, drift Pick up 144 joints total. POOH w/4 1/2", 12.6#, L-80, Supermax completion tubing, stand back in derrick 72 stands. Clear floor. R/u 4 1/2" TJ, m/u to test plug & install. Fill surface eq with test fluid,Test BOPE as per Hilcorp & AOGCC requirements. AOGCC inspector Jim Regg approved early test & waived witness. Tested 4 1/2" TJ 20/2500 psi, all tests good. Shut down operations due to high winds unable to work crane. Rig up shooting flange and lubricator, test to 250/2500 psi. RIH with perforating guns, 3 3/8" od, 20' loaded, 31' total length, 8.3 CCL to top shot, 6 spf, 60 deg phase, 22.7 gram charge, carrier type gun. Correlate on depth and send log to engineering group, approved correlation, perforate 4,742' to 4,762'. POH, keeping hole full with hole taking 8 bph 6% KCL. All shots fired. Make up perforating gun run #2, RIH perforating guns, 3 3/8" od, 16' loaded, 31' total length, 12.5 CCL to top shot, 6 spf, 60 deg phase, 22.7 gram charge, carrier type gun. Correlate on depth and send log to engineering group, approved correlation, perforate 4,694' to 4,710'. POH, keeping hole full with hole taking 8 bph 6% KCL. POOH all shots fired. 05/28/2021 - Friday Make up perforating gun run #3, RIH perforating guns, 3 3/8" od, 8' loaded, 21' total length, 10.2' CCL to top shot, 6 spf, 60 deg phase, 22.7 gram charge, carrier type gun. Correlate on depth and send log to engineering group, approved correlation, perforate 4,665' to 4,673'. POOH, keeping hole full with hole taking 6 bph 6% KCL. all shots fired. Make up perforating gun run #4, RIH perforating guns, 3 3/8" od, 8' loaded, 21' total length, 10.5' CCL to top shot, 6 spf, 60 deg phase, 22.7 gram charge, carrier type gun. Correlate on depth and send log to engineering group, approved correlation, perforate 4,615' to 4,623'. POOH, keeping hole full with 5.5bph loss rate 6% KCL. All shots fired. Make up perforating gun run #5, RIH perforating guns, 3 3/8" od, 12' loaded, 26' total length, 10.2' CCL to top shot, 6 spf, 60 deg phase, 22.7 gram charge, carrier type gun. Correlate on depth and send log to engineering group, approved correlation, perforate 4,584' to 4,596'. POOH, keeping hole full with 4bph loss rate 6% KCL. All shots fired. R/D e-line. N/D shooting flange, C/O handling RIH w/tools Prep to P/U 4 1/2" completion. M/U tubing tail, & packer assembly's as per plan. Cont. RIH with 4 1/2" L-80, 12.6# Supermax completion. P/U GLM's as per plan t/ 3145'. Cont. RIH with 4 1/2" L-80, 12.6# Supermax completion. P/U GLM's as per plan t/ 4579' up wt 51k dn wt 50k. R/U e-line, RIh w/ Gamma/ccl, send log to Geo, res & ops engineers to correlate discuss log. POOH, R/D e-line. Cont. RIH t/4802, up wt 54k dn wt 51k. R/U e-line for correlation pass on anticipated depth. Discuss with engineering group. +10' adjustment made to tally Confirm depths with gamma log, on depth. Rig down E-Line. Spaced out, p/u landing joint and tubing hanger. Tie in SSSV control line penetration, land hanger, run in hanger lock down screws placing tubing tail @ 4,802 tubing measure. Drop pkr setting bar, rig up to pump down tubing to set pkr. perforate 4,665' to 4,673' perforate 4,742' to 4,762' Cont. Pick up RIH with 4 1/2", 12.6#, L-80, Supermax completion t est BOPE as per Hilcorp & AOGCC requirements. AOGCC inspector Jim Regg approved early test & waived witness. s placing tubing tail @ 4,802 tubing perforate 4,615' to 4,623' perforate 4,584' to 4,596'. RIH with 4 1/2" L-80, 12.6# Supermax completion. perforate 4,694' to 4,710' Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 05/29/2021 - Saturday R/U on IA, to monitor pressure. Pressure up on tubing t/3700psi, hold 30 min setting packer & testing tubing good. Upper packer set @ 4553', lower packer @ 4781'. R/U on annulus to test upper packer @ 4553', fill & bleed air til full. Test t/2300psi f/ 30 min good. Change out landing joint t/4 1/2" R/U W/L, test 13 3/8 x 9 5/8" annulus 2150psi f/30 min good. 1) RIHw/ W/L retrieve dummy from SSSV @ 358'. 2) RIH t/ 4781' wlm retrieve ball & rod. 3) RIH t/4786'wlm retrieve plug.... OOH wo plug. 4) RIH t/3071' wlm retrieve plug, R/U pump down tubing test lower packer 2,100, f/ 10 min good, Slick line. 5) RIH to shift sliding sleeve open @ 4,756 kb wlm, w/ 4 1/2" B O 42 Shifting tool, pin not sheared indicating sleeve is open. 6) RIH with 4 1/2" X Line w/ prong and SSSV to 300', hook up to control line, purge, rih t/ 336 pressure up to 4,000 psi, holding, poh with SSSV set. 7) RIH with 4 1/2"check set tool to 366', POOH pin sheared, locked, Lay down landing joint, set BPV. Rig down rig floor and handling equipment, remove rig floor, nipple down BOPE. Scope down mast, lay mast over, setting out BOPE. 05/30/2021 - Sunday R/U pull riser, skid rig back & pull hatch cover. Prep Wellhead, N/U Tree, test void t/5k f/15min good. Cont. N/U tree SSV, flow line etc. Stand mast, place drill line spooler for unspooling Draworks. Backload boat, cont. prep rig to l/d, finish N/U tree, test 250/5000 good, pulled TWC. Rigging down HAK 404. Unstring Draworks, tugger, & manrider, prep & l/d mast, prep mast for removal. (R/U and circulate A-04) 05/31/2021 - Monday No operations to report. 06/01/2021 - Tuesday No operations to report. 06/25/2021 - Friday Simops meeting with Production, PJSM. Arrange deck & prep items for backload while waiting for boat. Unload boat & spot eq. Coil crews arrive @ 10:30 orientate same & PJSM. Arrange eq. & r/u same. R/U to test BOPE. Test BOPE as per Hilcorp & AOGCC requirements, witness waived By AOGCC inspector Jim Regg @ 11:11 am 6-25-21, Perform drawdown test good, tested 250 low 4000 high all tests good. Cont. r/u circulating lines, N/U riser & BOPE to wellhead. R/u supply & return lines. Rest Crew. Test t/2300psi f/ 30 min good. R/U on annulus to test upper packer @ 4553', test 13 3/8 x 9 5/8" annulus 2150psi f/30 min good. Pressure up on tubing t/3700psi, hold 30 min setting packer & testing tubing good. Upper packer set @ 4553', lower packer @ 4781'. tested 250 low 4000 high all tests good. Coil crews arrive @ Test BOPE as per Hilcorp & AOGCC requirements, witness waived By AOGCC inspector Jim Regg @ 11:11 am 6-25-21, Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 06/26/2021 - Saturday Simops mtg. w/ production. PJSM & permits. Continue to RU CTU. Stab 1-3/4" CT in injector. Drift 1.75" CT (WT = 0.156") w/ 1.25" OD ball displacing ball w/ 30 bbls of water. Recover ball. MU CTC. Pull Test CTC = 10K. Trouble shoot fluid pump air system. Unable to build pressure to start motor. Clear airline valve. Start engine. Press test CTC = 2500, MU BHA.: CTC(2.25" x 0.58), DFCV(1.25 x 1.67'), Stinger(1.75" x 4.0), Stinger(1.75" x 4.0), JSN(2.00" x 0.83') OAL = 11.08. Move to well. PT WHA/BOP & lubricator = 4000. Open swab (24T). Tubing = 90 psi. RIH, bend in CT from stabbing will not pass thru stripper brass. PUH & close swab. Bleed off surface pressures. Stand back from well. LD BHA. Cut off CT connector. Pull pipe above stripper. Remove stripper brass. Run CT back thru stripper & cut pipe until bent section is removed. Pull pipe above stripper. Install stripper brass. Run pipe thru stripper. MU CTC. Pull Test CTC = 10K. Stack down injector & secure well, injector & drill deck. SDFN. Job in Progress, will restart in morning. 06/27/2021 - Sunday Simops mtg w/ production. PJSM & permit. MU SLIM BHA: CTC(1.75" x 0.25'), Stinger(1.75" x 4.0'), Stinger(1.75" x 3.50'), JSN(1.75" x 0.87') OAL = 8.62'. Move to well. PT WHA/BOP & lubricator = 4099 psi. Open swab (24T). T/IA = 99/0. RIH to 4860'. Open choke & bleed WHP = 0 psi. Pump & circulate 60 bbl drill water @ 1.70 bpm to load hole to surface. 30 minute No-Flow Test - PASS. Cool down N2 pump. Ship 75 bbls fluid returns to production from FB tank. Pump N2 @ 1000 SCFM to CT x Tbg annulus taking returns to FB tank from 1.75" CT. WHP = 1700 psi, CTP = 20 psi w/ returns to tank @ 1.5 bpm. RIH @ 30 FPM. Total returns = 80 bbl, 6400'. Continue RIH @ 20 FPM. N2 = 1000 SCFM, WHP = 2685 psi, CTP = 12 w/ returns to tanks @ 1.0 BPM. Total returns = 150 bbl, 7100' RIH @ 13 FPM. N2 = 900 SCFM, WHP = 2650 psi, CTP = 10 psi w/ returns to tank @ 3/4 bpm. Total returns = 200 bbl, 7340' RKB holding in hole. N2 = 1000 SCFM, WHP = 2900 psi, CTP = 15 psi w/ returns to tank @ 3/4 bpm. 7340' RKB SD N2 pump. WHP = 2987, CTP = 75. Total returns = 250 bbl. POOH venting N2 pressure to FB Tank. Ship 250 bbl of fluid to production. OOH. WHP = 10 psi. Close swab & bleed off all surface pressures. Start RD & move to Well A-10A. SDFN. CTU portion of B-02 workover is complete. Total volume shipped to production = 325. 235 bbl of 6% KCL & 90 bbl drill water. 06/28/2021 - Monday No operations to report. 06/29/2021 - Tuesday No operations to report. 06/30/2021 - Wednesday No operations to report 07/01/2021 - Thursday No operations to report Pump N2 @ 1000 SCFM to CT x Tbg annulus taking returns to FB tank from 1.75" CT. W CTU portion of B-02 workover is complete. RIH to 4860'. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 07/02/2021 - Friday Simops mtg w/ production. PJSM & permits. RU ELU. MU Perf Gun #1 tool suite; RS, GR/CCL, Firing Head, 2-7/8" x 10' Razor HSC Low Swell, 5 spf, 60* phase, 15 gm charges. Surface test GR/CCL - PASS. Surface Test Firing Head - PASS. Move to well.CCL-to-Top Shot = 8.10'. PT WLV & lubricator = 250/1500 - PASS. Open Swab. Tubing = 0 psi. RIH w/ Perf Gun #1 to 5800' CCL. Log up to 4700' CCL for correlation pass. Correction = +4.50'. Send log files for review & correlation verification. Log on depth. RBIH to 5723' CCL. LOG up to 5603.9' CCL to put shots on depth (5603.9' + 8.1' = 5612' TS). Fire Perf Gun #1 to perforate zone Beluga G Upper 5612' - 5622'. Log up 200' & POOH. OOH w/ all shots fired & gun dry. Tubing = 400 psi. Surface test GR/CCL & FH. PU Perf Gun #2: 2-7/8" x 6' Razor HSC Low Swell, 5spf, 60* phase, 15 gm charges. CCL-to-top Shot = 8.10' Move to well. Open swab,Tubing = 400 psi. RBIH w/ PG#2 to 5804' CCL. Log up to 5400' CCL. Correction = +4.0'. Send log files for review & correlation verification. Log on depth. RBIH to 5695' CCL. Log up to 5589.9' CCL to put shots on depth (5589.9' + 8.1' = 5598' TS). Fire Perf Gun #2 to perforate zone Beluga F Lower 5598' - 5604'. Log up 200' & POOH. OOH w/ all shots fired & dry gun. Tubing = 400 psi. Surface test GR/CCL & FH. PU Perf Gun #3: 2-7/8" x 8'Razor HSC Low Swell, 5spf, 60* phase, 15 gm charges. CCL-to-top Shot = 9.80'. Tubing = 400 psi. RBIH w/ Perf Gun #3 to 5750' CCL. Log up to 5350' CCL. Correction = +4.0'. Send log files for review & correlation verification. Log on depth. RBIH to 5650' CCL. Log up to 5544.2' CCL to pit shots on depth (5544.2' + 9.8' = 5554' TS) Fire Perf Gun #3 to perforate zone Beluga F Mid 5554' - 5562'. Log up 200' & POOH. OOH w/ all shots fired & dry gun. Tubing = 400 psi. Surface test GR/CCL & FH. PU Perf Gun #4: 2-7/8" x 20' Razor HSC Low Swell, 5spf, 60* phase, 15 gm charges. CCL-to-top Shot = 8.10'. RBIH w/ Perf Gun #4 to 5750' CCL. Log up to 5250' CCL. Correction = +4.0'. Send log files for review & correlation verification. Log on depth. RBIH to 5570' CCL. Log up to 5544.2' CCL to put shots on depth (5540.9' + 8.1' = 5449' TS) Fire Perf Gun #4 to perforate zone Beluga E Lower 5449' - 5469. Log up 200' & POOH. OOH w/ all shots fired & dry gun. Surface test GR/CCL & FH. MU Perf Gun #5: 2-7/8" x 7' Razor HSC Low Swell, 5spf, 60* phase, 15 gm charges. CCL- to-top Shot = 8.10'. RBIH w/ Perf Gun #5 to 5740' CCL. Log up to 5200' CCL. Correction = +2.0'. Send log files for review & correlation verification. Log on depth. RBIH to 5520 ' CCL. Log up to 5398.0' CCL to pit shots on depth (5398.0' + 11.0' = 5409' TS). Fire Perf Gun #5 to perforate zone Beluga E Mid. No indication @ firing panel that Perf Gun #5 fired. No amp kick observed @ firing panel. RBIH to 5520' CCL. Log back up to 5398' CCL. Attempt to fire Perf Gun #5, no joy. POOH. OOH w/ no shots fired. LD Perf Gun #5 tool suite & disarm perf gun. LD lubricator. Nite cap WLV. Inspect tools. No obvious culprit. SDFN. Turnover well to Production to bring online. Job in Progress Fire Perf Gun #2 to perforate zone Beluga F Lower 5598' - 5604' Fire Perf Gun #1 to perforate zone Beluga G Upper 5612' - 5622'. Fire Perf Gun #4 to perforate zone Beluga E Lower 5449' - 5469. Fire Perf Gun #3 to perforate zone Beluga F Mid 5554' - 5562'. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 07/03/2021 - Saturday Simops mtg. w/ production. PJSM & permits. RU ELU. MU Perf Gun #5 tool suite for 2nd attempt run. Surface test GR/CCL & Firing Head. Perf Gun #5: 2-7/8" x 7' Razor HSC Low Swell , 5spf, 60* phase, 15 gm charges. CCL-to-top Shot = 11.0'. Tbg = 270, Flow Rate = 2.9 MMSCFD. Production adjusts Flow Line Control Valve = 0.75 MMSCFD @ 375 psi flowing tubing pressure. RIH flowing @ 0.75 MMSCFD to 5740' CCL. Log up 5200' CCL. Correction = -2.0'. Send log pass for review & correction verification. Log on depth. RBIH to 5520' CCL. Log up to 5398' CCL to put shots on depth (5398' + 11' = 5409' TS). Fire Perf Gun #5 perfing zone Beluga E Mid 5409' - 5416'. Log up 200' & POOH. OOH w/ all shots fired & dry gun. Tbg = 376 psi. Surface test GR/CCL & FH. MU Perf Gun #6: 2-7/8" x 14' Razor HSC Low Swell , 5spf, 60* phase, 15 gm charges. CCL-to-top Shot = 8.30'. RIH flowing to 5600' CCL. Log up 5200' CCL. Correction = +4.0'. Send log pass for review & correction verification. Log on depth. RBIH to 5414' CCL. Log up to 5368.7' CCL, Shots on depth (5368.7' + 8.3' = 5377' TS) Fire Perf Gun #6 perfing Beluga E Mid 5377' - 5391'. Log up 200' & POOH. OOH w/ all shots fired & dry gun. Tbg = 380 psi. Surface test GR/CCL & FH. MU Perf Gun #7: 2-7/8" x 7' Razor HSC Low Swell , 5spf, 60* phase, 15 gm charges. CCL-to-Top Shot = 11.1'. RIH flowing to 5557' CCL. Log up 5143' CCL. Correction = +3.50'. Send log pass for review & correction verification. Log on depth. RBIH to 5414' CCL. Log up to 5336.9' CCL to put shots on depth (5336.9' + 11.1' = 5348' TS). Fire PG #7 perfing zone Beluga E Upper 5348' - 5355'. Log up 200' & POOH. OOH all shots fired & dry gun. Tbg = 356 psi. Surface test GR/CCl & FH. MU Perf Gun #8: 2-7/8" x 8' Razor HSC Low Swell , 5spf, 60* phase, 15 gm charges. CCl-to-Top Shot = 10.1'. RIH flowing w/ Perf Gun #8 to 5450' CCL. Log up to 5130' CCL Correction = +4.0'. Send log pass for review & correction verification. Correct -1.0' to put log pass on depth. RBIH to 5374' CCL. Log up to 5268.9' to put shots on depth (5268.9' + 10.1' = 5279' TS). Fire Perf Gun#8 perfing zone Beluga D Lower 5279' - 5287'. Log up 200' & POOH. OOH w/ All shots fired & dry gun. Tubing = 350 psi. Surface test GR/CCL & FH. MU Perf Gun #9: 2-7/8" x 4' Razor HSC Low Swell , 5spf, 60* phase, 15 gm charges. CCL-to-Top Shot = 10.1'. RIH flowing w/ Perf Gun #9 to 5450' CCL. Log up to 5130' CCL Correction = +4.0'. Send log pass for review & correction verification. Log on depth. RBIH to 5383' CCL. Log up to 5233.9' to shots on depth (5233.9' + 10.1' = 5244' TS). Fire Perf Gun #9 to perf Beluga D Mid 5244' - 5248'. Log up 200' & POOH. OOH w/ all shots fired & dry gun. Tubing = 350 psi. MU Perf Gun #10: 2-7/8" x 5' Razor HSC Low Swell , 5spf, 60* phase, 15 gm charges. CCL-to-Top Shot = 9.1'. Fire Perf Gun #5 perfing zone Beluga E Mid 5409' - 5416' Fire Perf Gun #6 perfing Beluga E Mid 5377' - 5391' Fire Perf Gun #9 to perf Beluga D Mid 5244' - 5248' Fire Perf Gun#8 perfing zone Beluga D Lower 5279' - 5287' Fire PG #7 perfing zone Beluga E Upper 5348' - 5355'. Rig Start Date End Date HAK 404 / CTU 4/30/21 7/3/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name N Cook Inlet Unit B-02 50-883-20090-01-00 197-210 RIH flowing w/ Perf Gun #10 to 5450' CCL. Log up to 5043' CCL. Correction = +3.0'. Send log pass for review & correction verification. Log on depth. RBIH to 5383' CCL. Log up to 5222.9' to put shots on depth (5222.9' + 9.1') = 5232' TS). Fire Perf Gun #10 to perf Beluga D Mid 5232' - 5237'. Log up 200' & POOH. OOH w/ all shots fired & dry gun. Surface test GR/CCL & FH. Tubing = 350 psi. MU Perf Gun #11: 2-7/8" x 18' Razor HSC Low Swell , 5spf, 60* phase, 15 gm charges. CCL- to-Top Shot = 10.1'. RIH flowing w/ Perf Gun #11 to 5450' CCL. Log up to 5043' CCL. Correction = +4.0'. Send log pass for review & correction verification. Log on depth. RBIH Perf Gun #11 to 5383' CCL. Log up to 5181.9' to put shots on depth (5181.9' + 10.1') = 5192' TS). Fire Perf Gun #11 to perf zone Beluga D Upper 5192' - 5210'. Log up 200' & POOH. OOH w/ all shots fired & dry gun. Tubing = 350 psi. MU Perf Gun #12: 2-7/8" x 10' Razor HSC Low Swell , 5spf, 60* phase, 15 gm charges. CCL-to-Top Shot = 8.3'. RIH flowing w/ Perf Gun #12 to 5450' CCL. Log up to 5002' CCL. Correction = +4.0'. Send log pass for review & correction verification. Log on depth. RBIH to 5290' CCL. Log up to 5144.7' CCL to put shots on depth (5144.7' + 8.3' = 5153' TS) Fire Perf Gun #12 to perf zone Beluga C 5153' - 5163'. Log up 200' & POOH. OOH w/ all shots fired & dry gun. Tubing = 350 psi. Surface test GR/CCL & FH. MU Perf Gun #13: 2-7/8" x 10' Razor HSC Low Swell, 5spf, 60* phase, 15 gm charges. CCL-to-Top Shot = 8.3'. RIH flowing to 5448' CCL. Log up to 4644'. Correction = +4.5'. Send log pass for review & correction verification. Log on depth. RBIH to 4970' CCL. Log up to 4790.7' CCL to put shots on depth (4790.7' + 8.3' = 4799' TS). Fire Perf Gun #13 to perf zone Beluga A 4799' - 4809'. Log up 200' & POOH. OOH w/ all shots fired & dry gun. Completed 13 of 13 perf gun runs. RD ELU prepping all loads for backload to boat. Clean & secure drill & pipe deck. Secure well & turnover well to Production Operators. Fly crew to beach. Job Complete. Fire Perf Gun #13 to perf zone Beluga A 4799' - 4809' Fire Perf Gun #10 to perf Beluga D Mid 5232' - 5237' Fire Perf Gun #11 to perf zone Beluga D Upper 5192' - 5210'. Fire Perf Gun #12 to perf zone Beluga C 5153' - 5163' David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: DATE: 07/23/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL NCI B-02 (PTD 197-210) PERF RECORD 07/01/2021 Please include current contact information if different from above. eceived By: 07/23/2021 37' (6HW By Abby Bell at 2:43 pm, Jul 23, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4424 Received By: Date: Hilcorp North Slope, LLC Date: 07/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company NCI A-03 50883200200000 168099 07June2021 Jet Cut Record Alaska E-Line NCI A-04 50883200230000 169018 03June2021 Cement Retainer Alaska E-Line NCI B-02 50883200900100 197210 08May2021 Jet Cut Record Alaska E-Line NCI B-02 50883200900100 197210 17May2021 Plug Set – Punch Record Alaska E-Line NCI B-02 50883200900100 197210 22May2021 Tubing Cut – CBL Hoist Record Alaska E-Line NCI B-02 50883200900100 197210 25May2021 Radial Cement Bond Log Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Completion Record Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Perforation Record Alaska E-Line Please include current contact information if different from above. Received By: 07/15/2021 37' (6HW By Abby Bell at 4:12 pm, Jul 15, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4424 Received By: Date: Hilcorp North Slope, LLC Date: 07/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company NCI A-03 50883200200000 168099 07June2021 Jet Cut Record Alaska E-Line NCI A-04 50883200230000 169018 03June2021 Cement Retainer Alaska E-Line NCI B-02 50883200900100 197210 08May2021 Jet Cut Record Alaska E-Line NCI B-02 50883200900100 197210 17May2021 Plug Set – Punch Record Alaska E-Line NCI B-02 50883200900100 197210 22May2021 Tubing Cut – CBL Hoist Record Alaska E-Line NCI B-02 50883200900100 197210 25May2021 Radial Cement Bond Log Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Completion Record Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Perforation Record Alaska E-Line Please include current contact information if different from above. Received By: 07/15/2021 37' (6HW By Abby Bell at 4:12 pm, Jul 15, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4424 Received By: Date: Hilcorp North Slope, LLC Date: 07/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company NCI A-03 50883200200000 168099 07June2021 Jet Cut Record Alaska E-Line NCI A-04 50883200230000 169018 03June2021 Cement Retainer Alaska E-Line NCI B-02 50883200900100 197210 08May2021 Jet Cut Record Alaska E-Line NCI B-02 50883200900100 197210 17May2021 Plug Set – Punch Record Alaska E-Line NCI B-02 50883200900100 197210 22May2021 Tubing Cut – CBL Hoist Record Alaska E-Line NCI B-02 50883200900100 197210 25May2021 Radial Cement Bond Log Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Completion Record Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Perforation Record Alaska E-Line Please include current contact information if different from above. Received By: 07/15/2021 37' (6HW By Abby Bell at 4:12 pm, Jul 15, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4424 Received By: Date: Hilcorp North Slope, LLC Date: 07/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company NCI A-03 50883200200000 168099 07June2021 Jet Cut Record Alaska E-Line NCI A-04 50883200230000 169018 03June2021 Cement Retainer Alaska E-Line NCI B-02 50883200900100 197210 08May2021 Jet Cut Record Alaska E-Line NCI B-02 50883200900100 197210 17May2021 Plug Set – Punch Record Alaska E-Line NCI B-02 50883200900100 197210 22May2021 Tubing Cut – CBL Hoist Record Alaska E-Line NCI B-02 50883200900100 197210 25May2021 Radial Cement Bond Log Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Completion Record Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Perforation Record Alaska E-Line Please include current contact information if different from above. Received By: 07/15/2021 37' (6HW By Abby Bell at 4:12 pm, Jul 15, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4424 Received By: Date: Hilcorp North Slope, LLC Date: 07/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company NCI A-03 50883200200000 168099 07June2021 Jet Cut Record Alaska E-Line NCI A-04 50883200230000 169018 03June2021 Cement Retainer Alaska E-Line NCI B-02 50883200900100 197210 08May2021 Jet Cut Record Alaska E-Line NCI B-02 50883200900100 197210 17May2021 Plug Set – Punch Record Alaska E-Line NCI B-02 50883200900100 197210 22May2021 Tubing Cut – CBL Hoist Record Alaska E-Line NCI B-02 50883200900100 197210 25May2021 Radial Cement Bond Log Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Completion Record Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Perforation Record Alaska E-Line Please include current contact information if different from above. Received By: 07/15/2021 37' (6HW By Abby Bell at 4:12 pm, Jul 15, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4424 Received By: Date: Hilcorp North Slope, LLC Date: 07/15/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company NCI A-03 50883200200000 168099 07June2021 Jet Cut Record Alaska E-Line NCI A-04 50883200230000 169018 03June2021 Cement Retainer Alaska E-Line NCI B-02 50883200900100 197210 08May2021 Jet Cut Record Alaska E-Line NCI B-02 50883200900100 197210 17May2021 Plug Set – Punch Record Alaska E-Line NCI B-02 50883200900100 197210 22May2021 Tubing Cut – CBL Hoist Record Alaska E-Line NCI B-02 50883200900100 197210 25May2021 Radial Cement Bond Log Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Completion Record Alaska E-Line NCI B-02 50883200900100 197210 28May2021 Perforation Record Alaska E-Line Please include current contact information if different from above. Received By: 07/15/2021 37' (6HW By Abby Bell at 4:12 pm, Jul 15, 2021 STATE OF ALASKA Jr� OIL AND GAS CONSERVATION COMMISSION Reviewed By: P.I. Sup" 5 21 2erL� ROPE Test Report for: N COOK INLET UNIT 8-02 Comm Contractor/Rig No.: Hilcorp 404 Operator: Hilcorp Alaska, LLC Type Operation: WRKOV Sundry No: Type Test: WKLY 321-146 MISC. INSPECTIONS: FLOOR SAFTY VALVES: P/F Location Gen.: P Housekeeping: P " PTD On Location P Standing Order Posted P " Well Sign P " Drl. Rig P " Hazard Sec. P Mise NA FLOOR SAFTY VALVES: PTD#: 1972100 DATE: 5/13/2021 Operator Rep: Brumley/Soule Test Pressures: Rams: Annular: Valves: MASP: 250/2500 - 250/2500- 250/2500 1765 TEST DATA Quantity P/F Upper Kelly _0 _ NA Lower Kelly 0 NA Ball Type 1 I" Inside BOP I P FSV Mise 0 NA PTD#: 1972100 DATE: 5/13/2021 Operator Rep: Brumley/Soule Test Pressures: Rams: Annular: Valves: MASP: 250/2500 - 250/2500- 250/2500 1765 TEST DATA MUD SYSTEM: 2950. Visual Alarm Trip Tank NA NA. Pit Level Indicators P P Flow Indicator NA NA Meth Gas Detector P P - H2S Gas Detector P P ' MS Mise NA NA Inspector Matt Herrera InspSourcc Rig Rep: Reed/Fiannevold Inspector Inspection No: bopMFH210515055235 Related Insp No: ACCUMULATOR SYSTEM: Time/Pressure P/F System Pressure 2950. P Pressure After Closure 1750 " P 200 PSI Attained 21 P Full Pressure Attained 94 P " Blind Switch Covers: Yes P Nitgn. Bottles (avg): 4(a)2188 " P' ACC Mise 0 NA BOP STACK: Quantity Size P/F Stripper 0 P/F NA_ Annular Preventer 1 13 5/8" F_'_ #1 Rams 1 '. 27/8x51/2 _P #2 Rams 1 " Blinds _ P " #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA_ Choke Ln. Valves 1 -2 1/16" P . HCR Valves 2 2 1/16" P _ Kill Line Valves 2 . 2 1/16" P Check Valve 0 NA BOP Misc 0 NA CHOKE MANIFOLD: INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves _ 0 NA Number of Failures: 1 ✓ Test Results Test Time 4.5 Remarks: PVT active pit only. Gas Alarms tested with Contractor Quadco. Annular failed multiple attempts was to be replaced when � available from onshore. Test time does not reflect annular repairs and testing (opeator ended testing on 5/14/21). Quantity P/F No. Valves 11 P Manual Chokes 1 " _P_ Hydraulic Chokes 1 __ _P_ CH Mise 0 NA INSIDE REEL VALVES: (Valid for Coil Rigs Only) Quantity P/F Inside Reel Valves _ 0 NA Number of Failures: 1 ✓ Test Results Test Time 4.5 Remarks: PVT active pit only. Gas Alarms tested with Contractor Quadco. Annular failed multiple attempts was to be replaced when � available from onshore. Test time does not reflect annular repairs and testing (opeator ended testing on 5/14/21). 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?CO 68A 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): 14,537'N/A Casing Collapse Structural Conductor Surface 2,670 psi Production 7,930 psi Liner 10,780 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email:Katherine.oconnor@hilcorp.com Contact Phone: (907) 777-8376 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Other: G/L Completion / N2 Operations 13,377'12,054'11,116'1,765 psi 935'3-1/2" 12,460'7" 14,457' 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. 4/21/2021 2-7/8" & 3-1/2" Daniel E. Marlowe Halliburton RDH Dual Packer & Halliburton TRSV N/A 2,784' 10,592 (MD) 9,752 (TVD) & 338 (MD) 338 (TVD) 420 (MD) 420 (TVD) Tubing Grade:Tubing MD (ft): N/A Perforation Depth TVD (ft): 13,306' 6.5 L-80 & 12.95 L-80 9-5/8"11,086' 8,909' 13,522' Perforation Depth MD (ft): 11,086' 8,123' 10,224' 2,602' 8,909' 407'407' 30" 20" 13-3/8" 2,602' TVD Burst 10,626 & 13,530 11,640 psi Tubing Size: MD 5,380 psi 2,535' 197-210 50-883-20090-01-00Anchorage, AK 99503 Hilcorp Alaska, LLC N Cook Inlet Unit B-02 COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 Authorized Signature: Operations Manager Katherine O'Connor PRESENT WELL CONDITION SUMMARY Length Size 10,900 psi 12,054' 407' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 2:54 pm, Mar 25, 2021 321-146 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.03.25 14:22:34 -08'00' Dan Marlowe (1267) SFD 3/26/2021 DSR 3/30/21 10-404 BOP test to 2500 psi. Variance granted to allow SSV on production wing valve instead of in vertical run as normally required in 20AAC25.265(c)(1). BJM 4/7/21 See AOGCC conditions in BOP test procedure. X Comm. n Required? Yes 4/8/21 dts 4/8/2021 JLC 4/8/2021 RBDMS HEW 4/8/2021 Well Work Prognosis Well Name:N Cook Inlet Unit B-02 API Number:50-883-20090-01-00 Current Status:Suspended Leg:Leg B2, NE Corner Estimated Start Date:4/21/21 Rig:HAK 404 / Coil Tubing Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Juanita Lovett Permit to Drill Number:197-210 First Call Engineer:Katherine O’Connor Office: 907-777-8376 Cell: 214-684-7400 Second Call Engineer:Karson Kozub Office: 907-777-8434 Cell: 907-570-1801 Current Bottom Hole Pressure: N/A Suspended well/All perfs plugged and abandoned 20 AAC 25.110 Maximum Expected BHP: 2,295 psi @ 5,300’ TVD 0.433 psi/ft water gradient to surface Maximum Potential Surface Pressure:1,765 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)( 4) Well History: B-02 was originally drilled as Sunfish 3. It is a suspended well. It was most recently completed in 1998 as a dual string completion, into the oil sands @ ±13110’MD. The well only produced for a very brief period of time (only days, into tanks) to these sands, and has been shut in ever since. These sands were officially abandoned in 2002 – cement was pumped into the perfs and then a plug was set into the 3-1/2” and cement dump bailed on top, and a tubing tail plug set into the 2- 7/8”. It has been suspended like this since then. The objective of this program is to recomplete the well uphole into the gas sands by cutting tubing, cementing the 13-3/8” x 9-5/8” annulus for isolation, and running a 4-1/2” gas lift completion. 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 wellbore access. Safety Concerns: x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (venting methane and Nitrogen during this job) x Ensure all crews are aware of stop job authority (Review Standard Well Procedure – Nitrogen Operations) top MD bot MD Size ID bbls/ft. Ft. volume bbls 3-1/2” work string 3-1/2” 2.75” 0.007 9-5/8” casing 0 7500 9-5/8” 53.5# 8.535”0.071 7500 531 9-5/8” annulus x 13-3/8” annulus 0 (punch) 7550’ 9-5/8” 53.5# x 13-3/8” 12.347# 8.535” 0.058 7550 438 Procedure: 1. RU Eline pressure test lubricator 250psi low/1,500psi high a. RIH short string and make tubing cut above packer ±8000’ MD b. RIH long string and make tubing cut above packer ±8000’ MD. RD EL 2. Circulate well with KWF (produced water) 3. MIRU HAK 404 4. Ensure well is full of fluid and static Well Work Prognosis a. *Note: all perforations abandoned since 2002 5. Set BPV, ND Tree, NU BOPEs 6. Test BOPEs on duals and singles to 250psi low/2,500psi high /2,500psi annular. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). 7. Monitor well to ensure its static, pull BPV 8. Unseat hanger and pull completion as singles a. Laying down the SSSV, flow couplings, and GLM’s b. If tubing will not pull as singles due to casing ID restrictions, RU dual pulling equipment and pull as dual completion 9. RU Eline pressure test lubricator 250psi low/1,500psi high a. Set CIBP ±7600’ MD b. Punch tubing ±7550’ MD. Attempt circulation to ensure communication. POOH. 10. RU HAL cement pumps a. Test lines to 250psi low/4,500psi high 11. Circulate mud out of the annulus using FIW and a surfactant wash pill. Circulate minimum bottoms up volume. 12. EL set cement retainer ±7500’ MD. RD EL 13. RU cement a. At least 20 bbl water spacer b. Pump ±245bbl of cement TOC ±3500’ c. Work string volume water d. Unsting with ~12 bbls of cement in WS to lay on top of cement retainer e. Slowly pick up above cement and circulate clean (leaving ~12 bbls of cement on top of retainer as plug) 14. RU E-line CBL Logging tool. RIH and Log ±7500- TOC. 15. RU EL perforating, perforate upper most zone per perf sheet 16. RIH with 4-1/2” gas lift completion (live valves), SSSV, SSD and two packers (will straddle perfs). See proposed schematic for details and set depths. 17. Set Packer / Pressure test completion: a. Pressure up and set packer b. Test tubing against plug in X nipple to ш2,500psig and chart for 30 minutes. c. Test IA to 1,500 psi and chart for 30 minutes (This will pressure up tubing also). d. Pull prong and plug in X-Nipple. 18. Set BPV. NU tree, test same. 19. RD HAK 404 20. MIRU Coil tubing 21. Test BOP’s to 250psi low/3,000psi high. (Note: Notify AOGCC 48 hours in advance of test to allow them to witness test). a. Blow the well dry with N2 b. Returns taken to the production header c. RD Coil tubing 22. RU E-line and perforate per program. 23. Turn over to production. 24. Schedule SVS testing with AOGCC as per regulations Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Wellhead Diagram 4. BOP Stack 5. Standard Well Procedure – Nitrogen Operations Circulate minimum of 2x annular volume at max rate. - bjm PT IA to 2000 psi. - bjm 15.a -MIT 9-5/8" x 13-3/8" annulus to 2000 psi - bjm Well Work Prognosis 6. Flow Diagrams 7. Coil Tubing BOP stack 8. BOP Test procedure 9. RWO Sundry Revision Change Form _____________________________________________________________________________________ Updated By: JLL 07/19/2018 SCHEMATIC North Cook Inlet Unit Well: NCI B-02 Last Completed: 02/10/1998 PTD: 197-210 API: 50-883-20090-01 PBTD: 14,377’ TD: 14,537’ A 20” RKB = 59’ RKB toMSL = 132’, MLLW to Mudline = 100’ 7” B C D E F H I 3 4 5 6 7 8 9 10 11 Stg Tool @ 4,045’ 13-3/8” 9-5/8” 1 2 3-1/2” TOC @ 10,088’ TOC @ 12,054’ WLM G 30” Stg Tool @ 7,385’ Tubing Punch @ 13,140’ – 13,142’ J K Sunfish N Forelands X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 2-7/8” 6.5 L-80 CS Hydril 2.441” Surf 10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection Surf 13,530’ JEWELRY DETAIL Short String No Depth (MD) Depth (TVD)ID OD Item 53.6’ 53.6’ Hanger 1 338’ 338’ 2.313” 2-7/8” Halliburton TRSV 2 4,327’ 4,061’ 2.347” 4.750” CAMCO KBMM GLM 3 5,912’ 5,485’ 2.347” 4.750” CAMCO KBMM GLM 4 7,042’ 6,485’ 2.347” 4.750” CAMCO KBMM GLM 5 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM 6 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM 7 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM 8 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer 9 10,613’ 9,771’ 2.313” HES X Nipple 10 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set 11 10,625’ 9,782’ 2.441” WLEG Long String 53.6’ 53.6’ Hanger A 420’ 420’ 2.812” 3-1/2” Halliburton TRSV B 4,389’ 416’ 2.867” 5.390” CAMCO KBUG GLM C 6,610’ 6,105’ 2.867” 5.390” CAMCO KBUG GLM D 7,967’ 7,293’ 2.867” 5.390” CAMCO KBUG GLM E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated _____________________________________________________________________________________ Updated By: JLL 03/24/21 PROPOSED North Cook Inlet Unit Well: NCI B-02 Last Completed: FUTURE PTD: 197-210 API: 50-883-20090-01 PBTD: 14,377’ TD: 14,537’ 20” RKB = 59’ RKB toMSL = 132’, MLLW to Mudline = 100’ 7” TOC 4000’ TBG punch ±7550’ H I 10 9 11 E F 2 3 Stg Tool @ 4,045’ 13-3/8” 9-5/8” 8 1 3-1/2” TOC @ 10,088’ 45 6 7 TOC @ 12,054’ WLM G 30” Stg Tool @ 7,385’ Tubing Punch @ 13,140’ – 13,142’ J K Sunfish N Forelands TOC 9-5/8” ~7350’ CI 8 Lwr CI 9 CI10 CI 11 Beluga A Beluga C Beluga D Beluga E Beluga F Beluga G Beluga H Beluga K Beluga L Beluga S Tbg Cut ±8,000 Long & Short String L M N O P Q R Est TOC ±3500 X X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 4-1/2”Surf ±4,769’ 2-7/8” 6.5 L-80 CS Hydril 2.441”±8,000’10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection ±8,000’13,530’ JEWELRY DETAIL No Depth (MD) Depth (TVD)ID OD Item 1 ±338’ ±338’ SSSV 2 ±1,600’ ±1,593’ 3.833” GLM 3 ±3,050’ ±2,936’ 3.833” GLM 4 ±4,400’ ±4,126’ 3.833” GLM 5 ±4,568’ ±4,276’ 4.000 8.250 Packer 6 ±4,736’ ±4,426’ 3.812 5.200 Sliding Sleeve 7 ±4,750’ ±4,439’ 4.000 8.250 Packer 8 ±4,764’ ±4,452’ 3.812 5.200 X nipple 9 ±4,769’ ±4,456’ 3.958 5.200 WLEG 10 ±7,500’ ±6,886’ - 8.125 Cement Retainer 11 ±7,600’ ±6,973’ - 8.125 CIBP PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status C.I. 8 Lower ±4,584’ ±4,596’ ±4,290’ ±4,301’ ±12’ Future Proposed C.I. 9 ±4,615’ ±4,623’ ±4,318’ ±4,325’ ±8’ Future Proposed C.I. 9 ±4,665’ ±4,673’ ±4,363’ ±4,370’ ±8’ Future Proposed C.I. 10 ±4,694’ ±4,710’ ±4,389’ ±4,403’ ±16’ Future Proposed C.I. 11 ±4,739’ ±4,762’ ±4,429’ ±4,450’ ±23’ Future Proposed Beluga A ±4,799’ ±4,809’ ±4,483’ ±4,492’ ±10’ Future Proposed Beluga C ±5,153’ ±5,163’ ±4,802’ ±4,811’ ±10’ Future Proposed Beluga D ±5,192’ ±5,210’ ±4,837’ ±4,854’ ±18’ Future Proposed Beluga D ±5,232’ ±5,237’ ±4,873’ ±4,878’ ±5’ Future Proposed Beluga D ±5,244’ ±5,248’ ±4,884’ ±4,888’ ±4’ Future Proposed Beluga D ±5,279’ ±5,287’ ±4,916’ ±4,923’ ±8’ Future Proposed Beluga E ±5,348’ ±5,355’ ±4,978’ ±4,985’ ±7’ Future Proposed Beluga E ±5,377’ ±5,391’ ±5,004’ ±5,017’ ±14’ Future Proposed Beluga E ±5,409’ ±5,416’ ±5,033’ ±5,040’ ±7’ Future Proposed Beluga E ±5,448’ ±5,470’ ±5,068’ ±5,088’ ±22’ Future Proposed Beluga F ±5,554’ ±5,562’ ±5,164’ ±5,171’ ±8’ Future Proposed Beluga F ±5,598’ ±5,604’ ±5,204’ ±5,209’ ±6’ Future Proposed Beluga G ±5,611’ ±5,622’ ±5,215’ ±5,225’ ±11’ Future Proposed Beluga H ±5,694’ ±5,717’ ±5,290’ ±5,310’ ±23’ Future Proposed Beluga H ±5,769’ ±5,772’ ±5,357’ ±5,360’ ±3’ Future Proposed Beluga H ±5,782’ ±5,808’ ±5,368’ ±5,392’ ±26’ Future Proposed Beluga H ±5,816’ ±5,825’ ±5,399’ ±5,407’ ±9’ Future Proposed Beluga K ±6,136’ ±6,143’ ±5,684’ ±5,691’ ±7’ Future Proposed Beluga L ±6,186’ ±6,205’ ±5,729’ ±5,746’ ±19’ Future Proposed Beluga S ±6,996’ ±7,023’ ±6,445’ ±6,469’ ±27’ Future Proposed Beluga S ±7,090’ ±7,102’ ±6,527’ ±6,538’ ±12’ Future Proposed Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated _____________________________________________________________________________________ Updated By: JLL 03/24/21 PROPOSED North Cook Inlet Unit Well: NCI B-02 Last Completed: FUTURE PTD: 197-210 API: 50-883-20090-01 ISOLATED JEWELRY Short String No Depth (MD) Depth (TVD)ID OD Item L 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM M 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM N 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM O 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer P 10,613’ 9,771’ 2.313” HES X Nipple Q 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set R 10,625’ 9,782’ 2.441” WLEG Long String E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug Tyonek Platform B-02 Current 07/03/2020 Starting head, OCT-C29-L, 20 3/4'’3M x 20'’ SOW, w/ 2- 2'’LPO Casing spool, OCT- C-29L-BG 20 3/4'’ 3M x 13 5/8 5M, w/ 2- 2 1/16 5M EFO Tubing hanger, National DP7SV, Dual split, 11 X 3 1/2 8rd lift in both, 3 ½ PH-6 susp in long string, 2 7/8 CS hydril susp in short string , w/ 3'’ National B BPV profiles, 1- control line port per hanger half, prepped for seal sleeves on hanger neck, 5 3/64 centers BHTA, Dual, 11 10M FE X National DRX top, w/ 3 ½ EUE box connections Tree, dual block, master, National MS, 11 10M FE X 3 1/16 10M X 3 1/16 10M 5 3/64'’ centers Control line Short string Control line Long string Adapter, Dual, National- SSSV, 11 10M stdd, w/ National ball valve stdd flange ports for control line exits, 5 3/64 center 2 3/8'’ Tubing head, National DP-7, 13 5/8 5M x 11 10M, w/ 2- 1 13/16 10M SSO, BG bottom prep Tree, dual block, SSV, master, National MS w/ Axelson operators, 11 10M FE X 3 1/16 10M X 3 1/16 10M 5 3/64'’centers Tree, dual block, Swab, National MS, 11 10M FE X 3 1/16 10M X 3 1/16 10M 5 3/64'’ centers Tyonek Platform B-02 20 x 13 3/8 x 9 5/8 x 3 ½ x 2 7/8 2 7/8 3 1/2 13 3/8 9 5/8 20 Tyonek Platform B-02 Proposed 03/18/2021 Casing spool, OCT- C-29L-BG 20 3/4'’ 3M x 13 5/8 5M, w/ 2- 2 1/16 5M EFO Tubing hanger, CW-TC-EN- CCL, 11 x 4 ½ EUE 8rd lift and susp, w/ 4'’ type H-BPV profile, 2- ¼npt control line port 2 3/8'’ Tubing head, CW-HPS, 13 5/8 3M x 11 5M, w/ 2- 2 1/16 5M SSO, HPS bottom prep Valve, Swab, CIW-FC 4 1/16 5M FE, HWO, EE trim BHTA, Otis, 4 1/16 5M FE x 7.5'’ Otis quick union top Valve, Wing, SSV, WKM-M, 3 1/8 5M, w/ air oper, EE trim Valve, Master, CIW-FC, 4 1/16 5M FE, HWO, EE trim Valve, Master, CIW-FC, 4 1/16 5M FE, HWO, EE trim Starting head, OCT-C29-L, 20 3/4'’ 3M x 20'’ SOW, w/ 2- 2'’ LPO 20'’ 13 3/8'’ 9 5/8'’ 4 ½’’ Tyonek Platform B-02 20 x 13 3/8 x 9 5/8 x 4 ½ Tyonek Platform 2021 Rig 404-Well B-2 03/18/2021 CIW-U 2 3/8-3 ½ Dual flex rams 2.83' Shaffer SL 13 5/8 5M 2 7/8-5.5 variables Blinds 2' 14.20' Riser 13 5/8 5M FE X 13 5/8 5M FE ?Spacer spool 13 5/8 5M FE X 11 10M 4.54' 2.83' Choke and Kill valves 2 1/16 5M Mud Cross 4 1/16 5M EFO 4.30' Hydril GK 13 5/8-5000 DSA 4 X 2DSA 4 X 2?Spacer spool 13 5/8 5M X 13 5/8 5M Valve Position(O/C)Standpipe PumpManifold1(PM1) OManifold PumpManifold2(PM2) OPumpManifold3(PM3) CPumpManifold4(PM4) OPumpManifold5(PM5) CMud KillLine1OCross KillLine2OHCRvalve(ChokeLine1) CChokeLine2OChoke ChokeManifold1(CM1) OManifold ChokeManifold2(CM2) CChokeManifold3(CM3) OChokeManifold4(CM4) CChokeManifold5(CM5) OChokeManifold6(CM6) CChokeManifold7(CM7) OChokeManifold8(CM8) CChokeManifold9(CM9) CChokeManifold10(CM10) OSuperChoke CManualChoke CRigFloor SafetyValve O Valve Position(O/C)Standpipe PumpManifold1(PM1) OManifold PumpManifold2(PM2) CPumpManifold3(PM3) OPumpManifold4(PM4) CPumpManifold5(PM5) OMud KillLine1OCross KillLine2OHCRvalve(ChokeLine1) CChokeLine2OChoke ChokeManifold1(CM1) OManifold ChokeManifold2(CM2) CChokeManifold3(CM3) OChokeManifold4(CM4) CChokeManifold5(CM5) OChokeManifold6(CM6) CChokeManifold7(CM7) OChokeManifold8(CM8) CChokeManifold9(CM9) CChokeManifold10(CM10) OSuperChoke CManualChoke CRigFloor SafetyValve O Rig 404 BOP Test Procedure Attachment #1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Rig 404, WO Program – Oil Producers, Gas Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. x Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. Confirm that well is static. Initial Test (i.e. Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing (EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If the tubing hanger won’t pressure test due to either a penetrator leak or the BPV profile is eroded and/or corroded and BPV cannot be set with tree on. Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV. As approved in the sundry, proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2-way valve, or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale, attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand, or MU landing (test) joint to lift-threads d) For ESP wells - Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and / or a penetrator leaks, notify Operations Engineer (Hilcorp), Mr. Bryan McLellan (AOGCC) and Mr. Jim Regg (AOGCC) via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path, test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed, test the remainder of the system following the normal test procedure (floor valves, gas detection, etc.) BJMFill well with KWF before ND tree if fluid level is not at surface. BJM This procedure #3 is not approved as part of this sundry. Notify AOGCC if unable to get a passing test. Rig 404 BOP Test Procedure Attachment #1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile / penetrator wouldn’t hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger (or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests (i.e. Test Plug can be set in the Tubing-head) 1) Remove wear bushing. a) Use inverted test plug to pull wear busing. MU to joint of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same- RIH with test plug on joint of tubing. Install a pump-in sub w/ test line plus an open TIW or lower Kelly valve in top of test joint w/ open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE (after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump- install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 2) Note: When testing, pressure up with pump to desired pressure, close valve on pump manifold to trap pressure and read same with chart recorder (test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1 st valve on standpipe manifold, close valves 1, 2, 10 on choke manifold and close the annular preventer, open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer, close safety valve and open IBOP on test joint, close outside valve on kill side of mud cross, open 1st valve of standpipe, close valves 3, 4 & 9 on choke manifold, open valves 1 & 2 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. c) Test Dual Rams. If the well has dual tubing, and dual rams are installed in the stack, test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve / open outside valve on kill side of mud cross, close valves 5 & 6 / open valves 3 & 4 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke / open valves 5 & 6 on choke manifold. Pressure up to ~ 1200 psi and bleed off 200 – 300 #s recording change and stabilization. If passes after 5 minutes, bleed off pressure back to tank. f) Close HCR (outside valve on choke side of mud cross), open manual & super choke. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. Rig 404 BOP Test Procedure Attachment #1 g) Close inside valve / open outside valve (HCR) on choke side of mud cross. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Ensure all pressure is bled off- open pipe rams and pull test joint leaving test plug / 2-way check in place. Close blind rams and attach test line to valve 10 on choke manifold, close valve 7 & 8 / open valve 10 on choke manifold. Test to 250 psi for 5 minutes and xxx psi (see sundry) for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Test additional floor valves (TIW or Lower Kelly Valve) and IBOPs as necessary. STANDARD TEST PROCEDURE OF CLOSING UNIT (ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record “Accumulator Pressure”. It should be +/- 3,000 psi. 3) Close Annular Preventer, the Pipe Rams, and HCR. Close 2 nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read “10 bottles at 2,150 psi”). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre- charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually +/- 30 seconds. 8) Once 200 psi pressure build is reached, turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/- 3,000 psi). Note: Make sure the electric pump is turned to “Auto”, not “Manual” so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves, for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format. Document both the rolling test and the follow up tests. 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. Coiled Tubing BOP 05/21/2020 SWAB VALVE MASTER VALVE Hilcorp Flow Diagram Fluids Pumped Fluids Returned Valve Open Valve Closed Gate Valve Ball Valve Butterfly Valve Lo Torq Valve Automatic Choke Manual Choke Pressure Gauge Knife Valve Choke Line P PIT SYSTEM SucƟon SHAKER SHAKER CHOKE MANIFOLD GAS BUSTER Panic Line C12 C13 C15 C14 C16 A B C4 C5 C6 C7 C2 C10 C9 C11 C8 C3 P C1 C Hilcorp Alaska, LLCHilcorp Alaska, LLCChanges to Approved Rig Work Over Sundry ProcedureSubject: Changes to Approved Sundry Procedure for Well: N Cook Inlet Unit B-02 (PTD 197-210)Sundry #: xxx-xxxAny modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.Sec Page Date Procedure Change New 403Required?Y / NHAKPreparedBy(Initials)HAKApprovedBy(Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date 1 Carlisle, Samantha J (CED) From:Katherine O'connor <Katherine.Oconnor@hilcorp.com> Sent:Wednesday, April 7, 2021 3:07 PM To:McLellan, Bryan J (CED) Cc:Juanita Lovett Subject:RE: [EXTERNAL] NCI B-02 (PTD197-210) RWO, plug and add perfs Attachments:RE: [EXTERNAL] B-02 NCI suspended well question (PTD 197-210); TIO Sept 2020 - April 2021.PNG; CAMRAMDualBoreFlexPacker.pdf HiBryan Seemyrepliesinbluebelow. Thankyou, KatherineO’Connor CIOOperationsEngineer Katherine.oconnor@hilcorp.com W:(907)777Ͳ8376 C:(214)684Ͳ7400 From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Tuesday,April6,202111:30AM To:KatherineO'connor<Katherine.Oconnor@hilcorp.com> Subject:[EXTERNAL]NCIBͲ02(PTD197Ͳ210)RWO,plugandaddperfs HiKatherine I’mgoingthroughyourSundryapplicationforNCIBͲ02andhaveafewcomments/questions: 1. IseesomenotesinourfilesthatthelongstringhasahistoryofpressurebuildͲup.Haveyouseenanyelevated wellheadpressuresontubingorcasingstrings?Ifso,pleasesendthebleedandpressurehistorydata.There pressureshaveseemedtobeprettysteadyaroundT/T/IA/OA=900/20/50/150psi.Therewassomeconfusion duetooperatorsmisreadingthetubingpressure,whichresultedinmisreadingthetubingpressureas2500psi upwards–thishassincebeencorrected.Seeattachedemailchainw/Guyforcontext.Healsohadusbleed downthelongstringpressureandMITIAwhenthelastsuspendedwellinspectioncamearoundinlate2020.The MITIApassedandpressurehasstayeddownsince.SeeattachedTIOplot. 2. ThereservoirpressureandmaxsurfacepressureshouldbecalculatedfromPBTD,unlesstheshallowerreservoir pressurewouldresultinahighersurfacepressure(inthecaseofadepleteddeepreservoir).Thiswellhasbeen suspendedanddeemedincapableofflowsinceNov2002.Hencethedeepoilsandsarepluggedinaccordance with20AAC25.112.AllsandsabovethenewPBTDarewaterbearingandwouldnotresultinahigherreservoir pressurethanthedeepestgassand.Thepressureinthesundrywascalculatedfromthedeepestgassandwhich wewillberecompletingtointhisworkover. 3. TheBOPstackconfigurationisquiteunusual,withapiperamontopoftheAnnular.Whatisthereasonforthis configuration?IwouldliketoseeariskassessmentfortheBOParrangement,perAPIStandard536.1.2.7, attachedtotheSundry,andaprocedureforensuringthetwostringsofpipewillbealignedcorrectlywiththe twoholesinthedualpiperams.404hasbeendoingthisonthedualcompletionstogivethemtheabilityto removethesinglegateafterpullingthedualcompletionoutofthewellwithoutdisturbingtherestoftheBOP 2 andhavingtoreͲtest.Theextraramisnotneededforworkoveroperationsonceyougetthedualoutofthe hole.Italsobringsthefloordowntoasaferandmoreworkableheight.TheCamerontypesinglegateisthebest typethatHilcorphasfoundthatoffersagooddualramcoverage.AccordingtoourwellheadandBOPguru,“flex ramsarethebestthingtheyhaveeverinventedforpullingdualstringsastheycovermostallstandardranges foradualstringwell.”Thesearedualflexramssoitisnotcriticalonwhatsidethe27/8or3½completion is.Bothsidesoftheramscoverfrom2Ͳ3/8to3½piperanges.Iattachedtheinfoontheramforyoutolook at.Whenthestackisbuilttheramgateswillbealignedtomatchhowthedualstringissettinginthewellhead.I willlookforariskassessment. Feelfreetocallifyou’dliketodiscuss. Thanks BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAMRAM™ Dual Bore FLEXPACKER™ 13-5/8”-3000, 5000 and 10,000 psi WP U BOPs DRILLING SYSTEMS Availability CAMERON ® 13-5/8” CAMRAM Dual Bore FLEXPACKER is available from Cameron’s elastomer facility in Katy, Texas. Please call 713.391.4644 for price and delivery information. Description The 13-5/8” CAMRAM™ Dual Bore FLEXPACKER is designed to seal on three different pipe sizes in two different packer bores. Each of the pipe bores can adjust and seal on 2-3/8”, 2-7/8” and 3-1/2” pipe sizes. The centerlines of the two pipe bores are symmetrical to the centerline of the packer and are 5-3/64” apart. The 13-5/8” CAMRAM Dual Bore FLEXPACKER expands on the proven technology developed in the single bore CAMRAM FLEXPACKER which utilizes patented radially moving stacked anti-extrusion seg- ments. In the dual bore FLEXPACKER, each layer of the segments is machined to fit a specific pipe size within the sealing range (2-3/8” and 2-7/8”). The top plate and bottom packer plates are machined to match the 3-1/2” pipe. As different sizes of pipe are introduced into the sealing bore and the BOP rams are closed, the segments within the packer align to fit closely around the pipe and prevent rubber extrusion as pressure is applied. CAMRAM Dual Bore FLEXPACKER © 2008 Cameron | CAMRAM and FLEXPACKER are trademarks of Cameron International Corporation | 09/08, TC9609 E-07 29501 Katy Freeway, Katy, TX 77494, Tel: 281.391.4600, Fax: 281.391.4640, www.c-a-m.com 1 Carlisle, Samantha J (CED) From:Katherine O'connor <Katherine.Oconnor@hilcorp.com> Sent:Thursday, September 17, 2020 9:18 AM To:Schwartz, Guy L (CED) Cc:Juanita Lovett Subject:RE: [EXTERNAL] B-02 NCI suspended well question (PTD 197-210) Attachments:B2 Bleed down well readings.pdf; B2 MITIA AOGCC.PDF; B2 MITIA Barton Chart.jpg Guy, ThistookabitlongerduetosomevacationItook,butattachedisthelogforthebleeddown&monitorofthelong string(startingpressurewas805psibeforebleeddown),theMITIAformandtheMITIAbartonchart. Thanks, KatherineO’Connor CIOOperationsEngineer Katherine.oconnor@hilcorp.com W:(907)777Ͳ8376 C:(214)684Ͳ7400 From:Schwartz,GuyL(CED)[mailto:guy.schwartz@alaska.gov] Sent:Wednesday,September9,202010:47AM To:KatherineO'connor<Katherine.Oconnor@hilcorp.com> Subject:RE:[EXTERNAL]BͲ02NCIsuspendedwellquestion(PTD197Ͳ210) Katherine, InordertorenewthesuspensionstatusforBͲ02acoupleofitemsneedtobeaddressed. 1) BleeddownLongstringto200psiandmonitorfor24hrs. 2) TesttheIAto1500psiandchart.thisisactuallyasecondarybarriertoflowandshouldhavebeentestedback in2002. 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). From:KatherineO'connor<Katherine.Oconnor@hilcorp.com> Sent:Tuesday,September8,20201:21PM 2 To:Schwartz,GuyL(CED)<guy.schwartz@alaska.gov> Subject:RE:[EXTERNAL]BͲ02NCIsuspendedwellquestion(PTD197Ͳ210) Diggingintothisalittlemore,thepressuresonBͲ02boththeshortstringANDthelongstringwereincorrect.When gettingthedailypressurereadings,theoperatorswereonlyopeningthepneumaticmastervalvebutnotthemanual blockvalve,sotheywerejustgettingthepressurereadinginthatsmallvoidspacebetweenthetwovalves(notactually ofthetbgitself).Thisissuewasnotedandaddressedinternallyshortlyafterthesuspendedwellinspection,butwasnot recognizedasthesamewellwhenwesentoutthewrittenreportafewdaysago. ActualTBGpressuresare Longstring:900psi Shortstring:32psi Thosepressurearehistoricallywhatisseenbasedoffofprevioussuspendedwellreports.Also,duringtheinitial suspensionboththeshortstringandthelongstringwerepressuretestedandbothstringspassed.Apassingdrawdown testwasalsoperformed. Letmeknowifyouhaveanyquestions.Thanks Katherine From:Schwartz,GuyL(CED)[mailto:guy.schwartz@alaska.gov] Sent:Friday,September4,20209:14AM To:KatherineO'connor<Katherine.Oconnor@hilcorp.com> Subject:[EXTERNAL]BͲ02NCIsuspendedwellquestion(PTD197Ͳ210) Katherine, Canyoulookfurtherintotheplugtestingrecordwhenthewellwasinitiallysuspendedin2002?.Also,the3150psi tubingpressureonboththeLSandSSseemveryodd.Itsveryhighpressureandhowarethetwostringsseeingthe samepressureiftheabandonmentplugsareholding?Iftheyareactualpressuresthenwillneedtobleedthemandsee whatthewellresponseis. Regards, GuySchwartz Sr.PetroleumEngineer AOGCC 907Ͳ301Ͳ4533cell 907Ͳ793Ͳ1226office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, 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?N/A Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): North Cook Inlet Unit / Tertiary Gas Pool 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 14,537'N/A Casing Collapse Structural Conductor Surface 2,670 psi Production 7,930 psi Liner 10,780 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 Authorized Signature: Operations Manager Katherine O'Connor PRESENT WELL CONDITION SUMMARY Length Size 10,900 psi 12,054' 407' COMMISSION USE ONLY Authorized Name: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017589 197-210 50-883-20090-01-00Anchorage, AK 99503 Hilcorp Alaska, LLC N Cook Inlet Unit B-02 TVD Burst 10,626 & 13,530 11,640 psi Tubing Size: MD 5,380 psi 2,535' 8,123' 10,224' 2,602' 8,909' 407'407' 30" 20" 13-3/8" 2,602' 9-5/8"11,086' 8,909' 13,522' Perforation Depth MD (ft): 11,086' N/A 2,784' N/A Tubing Grade:Tubing MD (ft): N/A Perforation Depth TVD (ft): 13,306' 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. N/A 2-7/8" & 3-1/2" Daniel E. Marlowe N/A 6.5 L-80 & 12.95 L-80 Other: Suspended Well Renewal 13,377'12,054'11,116'0 psi 935'3-1/2" 12,460'7" 14,457' Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Jody Colombie at 2:59 pm, Sep 03, 2020 320-368 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2020.09.03 13:48:09 -08'00' Dan Marlowe (1267) SFD 9/8/2020 X SFD 9/8/2020 DLB 09/03/2020 r: Suspended Well Renewal No form required SFD 9/8/2020 Suspended DSR-9/3/2020gls 9/17/20 * Suspend status approved until 2030 (next inspection required in 2025) Comm. 9/18/2020 dts 9/18/2020 JLC 9/18/2020 RBDMS HEW 9/21/2020 Suspended Well Inspection Data Well: NCI B-02 Surface Location: 1249’ FNL, 981’ FWL, Sec 6, T11N, R9W S.M. Permit to Drill: 197-210 API: 50-883-20090-01-00 AOGCC Inspection Date: 08/14/20 AOGCC Inspector: Mr. Lou Laubenstein Size Pressure (psi) Tubing 2-7/8” & 3-1/2” 3150 Casing 9-5/8” 70 OA 13-3/8” 150 OOA 20” 10 *Note: Wellhead pressures to be recorded monthly at minimum. Other Notes: x The B-02 well was a sidetrack of the Sunfish#3 well that was drilled to a TD of 14,537’ with 9- 5/8” production casing and 7” and 3-1/2” liners in January 1998. A 3-1/2” (LS) & 2-7/8” (SS) dual completion was installed at that time. x B-02 was suspended in September 2002. The reservoir abandonment left the well in the following condition: bridge plug #1 set in the 3-1/2” (LS) liner at 13,625’ with of 27ft of 15 ppg class G cement dump bailed on top of plug to isolate the North Foreland sands (top perf 13,652’MD) (November 2001); cement plug #2 consisting of 29bbl of 15.8ppg Class G cement with tagged TOC at 12,054’WLM (in LS) to isolate the Sunfish sands (top perf 13,110’MD), wellbore was circulated with 3% KCl, with ~500ft diesel freeze protect in both long and short strings (September 2002). The abandonment plug was tested at 2,500psi for 15min. x The flowline has been removed and the well is not connected to the production facilities. x At this time there are plans to recomplete the B-02 to the Beluga sands during a planned major RWO in 2021. x Hilcorp requests that B-02 maintains suspended status due to it being located on an active gas platform, Tyonek, such that future gas development opportunity can be obtained from this wellbore. x Condition of Wellhead – Well looks good x Condition of Surrounding Surface Location: Good x Follow Up Actions needed: None Attachments: x Current Well Schematic x Picture(s) x Plat - 1/4mile radius of wellbore did not test IA ... RWO in 2021. At this time there are plans to recomplete the B-02 to the Beluga sands during a planned major act ual pressure was 805 psi ... bled to 175 psi and held. gls 0 See attached pressure charts.also tested IA to 1700 psi /30 min Future Utility---------> _____________________________________________________________________________________ Updated By: JLL 07/19/2018 SCHEMATIC North Cook Inlet Unit Well: NCI B-02 Last Completed: 02/10/1998 PTD: 197-210 API: 50-883-20090-01 PBTD: 14,377’ TD: 14,537’ A 20” RKB = 59’ RKB toMSL = 132’, MLLW to Mudline = 100’ 7” B C D E F H I 3 4 5 6 7 8 9 10 11 Stg Tool @ 4,045’ 13-3/8” 9-5/8” 1 2 3-1/2” TOC @ 10,088’ TOC @ 12,054’ WLM G 30” Stg Tool @ 7,385’ Tubing Punch @ 13,140’ – 13,142’ J K Sunfish N Forelands X XN CASING DETAIL Size Wt Grade Conn ID Top Btm 30” 457 B Welded 27.000” Surf 407’ 20” 169 X-56 Dril-Quip 18.376” Surf 2,602’ 13-3/8” 72 N-80/P-110 BT&C 12.347” Surf 8,909’ 9-5/8” 53.5 P-110 BT&C 8.535” Surf 11,086’ 7” 32 P-110 BT&C 6.094” 10,738’ 13,522’ 3-1/2” 12.95 P-110 PH-6 2.750” Tube 2.687” Connection 13,522’ 14,457’ TUBING DETAIL 2-7/8” 6.5 L-80 CS Hydril 2.441” Surf 10,626' 3-1/2” 12.95 L-80 PH-6 2.750” Tube 2.687” Connection Surf 13,530’ JEWELRY DETAIL Short String No Depth (MD) Depth (TVD)ID OD Item 53.6’ 53.6’ Hanger 1 338’ 338’ 2.313” 2-7/8” Halliburton TRSV 2 4,327’ 4,061’ 2.347” 4.750” CAMCO KBMM GLM 3 5,912’ 5,485’ 2.347” 4.750” CAMCO KBMM GLM 4 7,042’ 6,485’ 2.347” 4.750” CAMCO KBMM GLM 5 8,184’ 7,481’ 2.347” 4.750” CAMCO KBMM GLM 6 9,303’ 8,485’ 2.347” 4.750” CAMCO KBMM GLM 7 10,290’ 9,451’ 2.347” 4.750” CAMCO KBMM GLM 8 10,593’ 9,751’ 2.440” 8.340” Halliburton RDH Dual Packer 9 10,613’ 9,771’ 2.313” HES X Nipple 10 10,624’ 9,782’ 2.250” HES XN Nipple w/ 2.313” PXN Plug Set 11 10,625’ 9,782’ 2.441” WLEG Long String 53.6’ 53.6’ Hanger A 420’ 420’ 2.812” 3-1/2” Halliburton TRSV B 4,389’ 416’ 2.867” 5.390” CAMCO KBUG GLM C 6,610’ 6,105’ 2.867” 5.390” CAMCO KBUG GLM D 7,967’ 7,293’ 2.867” 5.390” CAMCO KBUG GLM E 9,238’ 8,425’ 2.867” 5.390” CAMCO KBUG GLM F 10,352’ 9,513’ 2.867” 5.390” CAMCO KBUG GLM G 10,592’ 9,750’ 2.900” 8.340” Halliburton RDH Dual Packer H 13,523’ 12,461’ 3.000” Baker No-Go Locator I 13,524’ 12,462’ 3.000” 3-1/2” Seal Assembly J 13,530’ 12,467’ End of Tubing K 13,625’ 12,554’ HES Magna Range Bridge Plug PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status Sunfish 13,110' 13,170' 12,084' 12,139' 60' 1/25/1998 Cemented on 9/25/2002 N Forelands 13,652' 13,686' 12,579' 12,610' 34' 2/10/1998 Isolated N Forelands 13,718' 13,736' 12,639' 12,656' 18' 2/10/1998 Isolated N Forelands 13,818' 13,856' 12,730' 12,765' 38' 2/10/1998 Isolated N Forelands 13,944' 13,966' 12,844' 12,864' 22' 2/10/1998 Isolated Suspended Well Inspection Review Report |nspectNu: susLUL200817102915 Date Inspected: 8/14/2020 - Inspector: Lou Laubenstein Well Name: NO]OK INLET UNIT Bf}2 - Permit Number: 1972100 Suspension Approval: Sundry ' # 302-234 ' Suspension Date: 9/29/2002 ' Location Verified? S� If Verified, How? Other (specify in comments) Offshore? W Type of Inspection: Subsequent Date AOGC[Notified: 8/10/2020 Operator: Hi|rorpAlaska, LLC Operator Rep: Scott bumbaugh Wellbore Diagram Avail? W Photos Taken? [] Well Pressures (psi): Tubing. 3150 / Fluid inCellar? El |A 70 / BPVinsta|hsd? El DA� 150 ' VRMug(dInstalled? [l VVeUheadCnndidon The wellhead is in good condition with no leaks or visible signs of leakage. The flowline has been removed and the well is blinded downstream of the wing valve. The instrument air lines that actuated the SSV and wing valve are removed and where closed at the time of my arrival. All gauges were in good condition and working order during my inspection. Condition ofCellar No cellar isvisab|e ' Surrounding Surface Condition The Well room was clean and in order. Comments TyninekP|utforno. ODAl0psi. - Supervisor Comments Wednesday, September 2,2U2O STATE OF ALASKA • AL _KA OIL AND GAS CONSERVATION CON 3SION REPORT OF SUNDRY WELL OPERATIONS 1 Operations Abandon r Rug Perforations r Fracture Stimulate r Pull Tubing r Operations shutdow n r Performed Suspend r- Perforate r Other Stimulate r Alter Casing r Change Approved Program r Rug for Redrill r Perforate New Pool r Repair Well r Re-enter Susp Well T Other:Suspend Well Inspect p- 2.Operator Name 4 Well Class Before Work: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development r Exploratory r 197-210 3.Address: 6 API Number: P. O. Box 100360, Anchorage, Alaska 99510 Stratigraphic r Service r 50-883-20090-01 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 17589 NCI B-02 9 Logs(List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): North Cook Inlet/Beluga 11.Present Well Condition Summary SS -PXN PLUG - 10624' Total Depth measured 14537 feet Plugs(measured) LS - BRIDGE PLUG - 13625' true vertical 13377 feet Junk(measured) CMT TOP @ 12015' Effective Depth measured 12054 feet Packer(measured) 10592 true vertical 11117 feet (true vertical) 9751 Casing Length Size MD TVD Burst Collapse CONDUCTOR 368 30 368 368 CONDUCTOR 2543 20 2602 2535 SURFACE 8849 13 3/8 8909 8123 INTERMEDIATE 12080 9 5/8 11088 10244 LINER 2788 7 14458 13306 RECEIVED CAN^6 .iuIN 1 7 2015 MAY 2 6 2015 Perforation depth Measured depth. Perfs P&A'd True Vertical Depth. Perfs P&A'd AOGCC 2 7/8, L-80, 10625 MD, 9783 TVD-SHORT STRING AOGCC Tubing(size,grade,MD,and TVD) 3.5, L-80, 13529 MD, 12466 TVD-LONG STRING Packers&SSSV(type,MD,and TVD) PACKER-HALLIBURTON RDH DUAL PACKER @ 10593 MD and 9751 TVD SAFETY VLV-HALLIBURTON TRSV @ 420&338 MD and 420 and 338 TVD 12 Stimulation or cement squeeze summary: NA Intervals treated(measured): Treatment descriptions including volumes used and final pressure: NA 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation NA NA NA Subsequent to operation NA NA NA 14 Attachments(required per 20 AAC 25 070,25 071,&25 283) 15.Well Class after work. Daily Report of Well Operations p Exploratory r Development p Service r Stratigraphic r Copies of Logs and Surveys Run r 16.Well Status after work Oil r Gas r WDSPL r Printed and Electronic Fracture Stimulation Data r GSTOR r WINJ r WAG r GINJ r SUSP P SPLUG r 17 I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C 0 Exempt. NA Contact MJ Loveland/Martin Wa ers Email N1878@conocophillips.com Printed Name MJ Loveland Title WI Proj Supervisor Signature//���_ 7 one:659-7043 Datesic:x1 3//3— fft G /n /s' RBDMSk MAY 1 9 1015 A 4 //7ç Form 10-404 Revised 5/2015 Submit Original Only ConocoPhillips RECEIVED Alaska MAY 2 6 2015 P.O. BOX 100360 AOGC ANCHORAGE,ALASKA 99510-0360 AO GCC 23, 2015 Commissioner Cathy Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Suspended Well Inspection 10-404 Sundry North Cook Inlet B-02 (PTD 197-210) Dear Commissioner Foerster: Enclosed please find the quinquennial suspended well inspection documentation as required by 20 AAC 25.110 for ConocoPhillips Alaska, Inc. North Cook Inlet well B-02 (PTD 197-210). The well will remain suspended for future utility as a sidetrack • candidate. The following documents are attached: - 10-404 Sundry - Suspended Well Check List - Wellbore Schematic - Location Plot Plan - Photographs Please call MJ Loveland or Martin Walters at 659-7043 if you have any questions. Sincerely, 477 MJ Lo eland WI Project Supervisor ConocoPhillips Suspended Well Site Inspection Form Notify AOGCC Inspectors at least 10 days prior to inspection to allow witness Well Name: NORTH COOK INLET UNIT B-02 Field/Pool: N COOK INLET/BELUGA Permit# (PTD): 197-210 Sundry 302-234 API Number: 50-883-20090-01-00 Operator: ConocoPhillips Alaska, Inc. Date Suspended: 9/29/2002 Surface Location: 1249' FNL, 980' FWL Section: 6 Township: 11N Range: 9W Nearest active pad or road: NA Meridian: SEWARD Take to Location Digital camera Map showing well location/Aerial photos Brief well history Wellbore diagram showing downhole condition Latest Sundry or Completion report Past Site Visit documentation Site clearance documentation Pressure gauges, fittings, tools Sample containers for fluids on or near pad Condition of Surface Location AOGCC requires: 1) a description of the condition of the surface location, including discoloration, fluids or sheens visible on the ground or in any nearby water, 2) photographs showing the condition of the location surrounding the well General location condition: The Well is located on the Tyonek Platform -The platform is in good condition Pad or location surface: Well Room 1 is clean and in good condition Location cleanup needed: None Pits condition: None Surrounding area condition: Well Room 1 is clean and in good condition Water/fluids on pad: None Discoloration, Sheens on pad, pits or water: NA Samples taken None Access road condition: NA Photographs taken (#and description): 4 Photos take of NCI B-02 in Well Room 1 Condition of Wellhead AOGCC requires: 1) a description of the condition of the wellhead, 2) well pressure readings, where practicable, 3) photographs showing the wellhead condition Wellhead/tree/valve description, condition: Tree Clean and in good condition all valves appear operational Cellar description, condition, fluids: Cellar is clean no fuid Rat Hole: NA Wellhouse or protective barriers: Well Room 1 Well identification sign: Placard and Stencil Tubing Pressure (or casing if no tubing): TS = 900 psi, TL = 0 PSI Annulus pressures: IA= 385, OA=410, OOA= 5 psi Wellhead Photos taken (#and description): 4 Photos take of NCI B-02 in Well Room 1 Work Required: None Operator Rep (name and signature): MJ Loveland AOGCC Inspector: Waived 5/20/15 by Jim Regg Other Observers. Rachel Kautz Inspection Date: 5/21/2015 AOGCC Notice Date: 5/6/2015 Time of arrival: 12:00 Time of Departure: 13:00 Site access method: Helicopter , SAK NCI B-02 ` Conoc©PhiIIIps -'1llArag A Well Attributes Max Angle&MD TD Wellbore APIIUWI Field Name ell Status Incl(°) MD(ftKB) Act Btm(ftKB) Alaska'ills' 508832009001 COOK INLET -IA/ 30.00 i 7,966 99 14,705 0 Ph Conocoill ps _ Comment H2S(ppm) Date Annotation End Date KB-Grd(R) Rig Release Date •.. Well Conlq -NCI 602,11/15201272945 AM - SSSV:TRDP Last WO: 4/2/1994 Schematic•Actual Annotation Depth(ftKB) End Date Annotation Last Mod...End Date Last Tag. 10,624.0 9/29/2002 Rev Reason:WELL REVIEW osborl 11/14/2012 Casing Strings Casing Description String 0... String ID...Top(ftKB) Set Depth(f. Set Depth(TVD)...String Wt..String...I String Top Thrd HANGER,54 CONDUCTOR 20 19.730 59.5 2,602.0 2,534.7 133.00 C-70 WELDED HANGER,54 ' L Casing Description String 0... String ID...Top(ftKB) Set Depth(f...Set Depth(TVD)...String Wt...String...String Top Thrd SURFACE 133/8 12.415 59.6 8,909.0 8,123.1 72.00 N-80 BTC Casing Description String 0... String ID...Top(ftKB) Set Depth(f...Set Depth(TVD)...String Wt...String...String Top Thrd PRODUCTION S/T 95/8 8.500 54.0 11,088.3 53.50 SAFETY VLV, __- _ i_ Casing Description String 0... String ID...Top(ftKB) Set Depth(f...Set Depth(TVD)...String Wt...String...String Top Thrd 33e WINDOW B-02 9 7.000 8,993.0 9,003.0 SAFETY VLV, 4 Casing Description String 0... String ID...Top(ftKB) Set Depth(f...Set Depth(TVD)...String Wt..String...String Top Thrd 420 LINER 7•'x3.5" 7 6.094 10,751.6 14,457.9 32.00 P-110 BUTT Liner Details ' W.1. Top Depth (TVD) Top Incl Nomi... CONDUCTOR. 1 I. Top(ftKB) MB) (°I Item Description Comment ID(in) 59-2'602 10,751.6 HANGER BAKER FLEXLOCK HANGER 6.250 13,525.6 XO Reducing CROSSOVER 7"TO 3.5°LINER 6250 13,526.7 SBE BAKER SEAL BORE EXTENSION 4.000 Tubing Strings± 4E F R[ Tubing Description String 0... String ID...Top(ftKB) Set Depth(1...Set Depth(TVD)..String Wt.. String... String Top Thrd GAS LIFT, 4,327 TUBING Short 2 7/8 2.441 53.6 10,625.9 6.50 L-80 CS HYDRIL GAS LIFT, Completion Details 4,389 Top Depth GAS LIFT, (TVD) Top Incl Norm... 5,912 L Top(ftKB) (ftKB) (°1 Item Description Comment ID(in) GAS LIFT, bY • 53.6 53.6 0.09 HANGER TUBING HANGER 2.875 6,610 337.9 337.9 0.61 SAFETY VLV HALLIBURTON TRSV 2.313 GAS LIFT. _r 10,593.3 PACKER HALLIBURTON RDH DUAL PACKER 2.347 7'002 10,612.5 NIPPLE HES X NIPPLE 2250 10,623.8 NIPPLE HES XN NIPPLE 2.250 10,625.2 WLEG WIRELINE ENTRY GUIDE 2.441 GASB 067 . Tubing Description String 0... String ID...Top(ftKB) Set Depth(f...Set Depth(TVD)...String Wt...String...String Top Thrd GAS LIFT. TUBING Long 31/2 2.750 53.6 13,529.8 12.95 L-80 PH-6 8.184 Abandoned Completion Details Top Depth (TVD) Top Incl Nomi... Top(ftKB) (ftKB) P1 Item Description Comment ID(in) SURFACE, 53.6 53.6 0.09 HANGER TUBING HANGER 3.500 420.4 420.4 0.92 SAFETY VLV HALLIBURTON TRSV 2.812 WINDOW 8-02, _ - 8.993-4.003 ' a I10,592.4 PACKER HALLIBURTON RDH DUAL PACKER 2.867 GAS LIFT, 9,238 r 13,523.0 LOCATOR BAKER NO GO LOCATOR 3.000 GAS LIFT, ice,:. 13,524.3 SEAL ASSY SEAL ASSEMBLY 3.000 9.303 GAS LIFT, Other In Hole(Wireline retrievable plugs,valves,pumps,fish,etc.) 10.280 Top Depth GAS UFT, (WD) Top Incl 10,352 - Top(RKB) (ftKB) (°) Description Comment Run pate ID(in) PACKER, 10,624.0 PLUG PXN PLUG SET IN XN NIPPLE 11/21/2001 0.000 10, , ..ie-•„ PACKER, 13,140.0 TBG TUBING PUNCHES PRE-CEMENT PLUG 9/18/2002 2.992 10,593 I'® PUNCHES NIPPLE,10.013 1 - 13,625.0 PLUG HES MAGNA RANGE BRIDGE PLUG 112/2/2001 0.000 NIPPLE,10,624-, )- Perforations&Slots PLUG,10,624 WLEG.10,825 Shot -.- --- Top(TVD) Btm(TVD) Dens I I Top(ftKB)Btm(ftKB) (RKB) (ftKB) Zone Date (aft... Type Comment 13,110.0, 13,170.0 Sh,NCI 1/25/1998 12.0 IPERF 45/8 "sttt(p guns-CEMENTED OFF SuOnZs 02 13,652.0 13,686.0 N.Forelands, 2/8/1998 12.0 IPERF 1-11/16"strip guns NCI B-02 PRODUCTION [ ,� A 13,718.0 13,736.0 N.Forelands, 2/8/1998 12.0 IPERF 1-11/16"strip guns SIT,54-11.089NCI B-02 =I; `3. 13,818.0 13,856.0 N.Forelands, 2/8/1998 12.0 IPERF 1-11/16"strip guns NCI B-02 IPERF, 13,110-13,2N �, - 13,901.0 13,920.0 N.Forelands, 2/8/1998 12.0 IPERF 1-11/16"strip guns PUNCHES, 1r _ NCI B-02 13,140 13,944.0 13,966.0 N.Forelands, 2/8/1998 12.0 IPERF 1-11/16"strip guns LOCATOR, NCI B-02 13.523 I Notes:General&Safety SEAL ASSY, End Date Annotation 13,524 •INN;,. 9/25/2002 NOTE:LONG TBG STRING ABANDONED w/CEMENT PLUG,COVER SUNFISH PERFS 11/14/2012 NOTE:This well is listed in WetlView as Legal name SUNFISH,Common Name NCI B-02 CMT PLUG. 12,054 . PLUG.13, IPE625RF. Mandrel Details - 1302-13.686 • = Top Depth Top Port (TVD) Incl OD Valve Latch Soo TRO Run Stn Top(ftKB) (RKB) CI Make Model 100 Sery Type Type lin) (psi) Run Date Com... IPERF. _ = 1 4,326.8 4,060,7 27.08 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 42/1994 13,718-13.738 _ -- IPERF, _ • 2 4,389.0 4,116.0 26.94 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 42/1994 13.81613,856 - 3 5,911.8 5,484.3 26.63 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 4/2/1994 13,001-13.920- _ • ` -- 4 6,610.4 6,105.6 27.88 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 4/2/1994 5 7,042.4 6,485.4 28.82 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 4/2/1994 13,94413.960 ----- • -_ 6 7,967.0 7,293.1 30.39 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 4/2/1994 '7 '8,184.2 7,481.3 29.12 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 42/1994' --'E 9,237.9 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 4/2/1994 .. 9 5,303.1 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 4/2/1994 - LINER Tx3.5", 10,752.14,458"\ 10 10,2902 CAMCO KBMM 1 GAS LIFT DMY BK 0.000 0.0 4/2/1994 TD(NCI B-02), \ a -- --- 14,708 ,. SAK NCI B-02 ConocoPhillips 0-4 Alaska,If le; COI1000PtYlBps �U-Grd(It) Rig Release Date ••• Confit. NCI B-02110520127'.2945 AM _ 4/2/1994 Schemallc-Actual HANGER,54- - HANGER,54 SAFETY VLV, 338 SAFETY VLV. 420 CONDUCTOR. 59-2,602 GAS LIFT, r. 4,327 GAS LIFT, 4,389 g GAS LIFT, -s 5,912 GAS LIFT, 6,610 GAS LIFT, 7,042 GAS LIFT, 7.967 GAS LIFT, 8,184 s` SURF-8ACE,909, 60 WINDOW B-02, _ 8,993-9,003 GAS LIFT, ,... 9,238 GAS LIFT, 9,303 GAS LIFT, 'C 10,290 . GAS LIFT, g 10,352 PACKER, PACKER 10.592 j , jl 10.593 - NIPPLE.10,613 I NIPPLE,10,624 )i PLUG,10.625II WLEG,10,625 -- e`t PRODUCTION 4 SIT,5411.088 (PERF, 13.110-13.170 TBG PUNCHES, 1 13,140 ■■� _ LOCATOR, 13,523 SEALASSY, 13,524 -S CMT PLUG, 12,054 625 pg� ,d i PLUG.IPER �_ /40,041 1 _.. .'ice ,GL'H,Y�I��IMG 16) 'P,e> iP fi'i II dMF .u*„F'. 13652-13686RF' - Top Depth Top Port (WD) Inel 00 Valve Latch Sloe TRO Run Stn Top(ttKB) (MKS) C) Make Model (in) Sery Type Type (in) (Pei) Run Date Corn... 13,718-1IPE3,73FR6 • -= 11 10,352.0 CAMCO KBUG 1 GAS LIFT DMY BK 0.000 0.0 4/2/1994 RF, 13,81&IPE13,856 13,901.13,920 I __ • PERF, IPERF, 13,944-13,986 LINER 7"[3.5, 10.752-14.458 TD(NCI B-02) 14.705 °;"`;" PHILLIPS pAlaska PETROLEUM,Inc. NCIU B-2 A Subsidiary of PHILLIOMPANY - - I BPV(Mke,Type.OD) Not Applicable RKB-THF: Tbg Hr(Make,Type) Not Applicable RKB-BHF 59.00 Annulus Fluid: RKB-MSL: 132.00 TOC: Water Depth: 130.00 s Ott TOP BTM WT GRADE CONN, BURST CO# TRO Casing Strings PPCO Allowable Ratings 30" 55 407 5471bs/ft WELD 20" 59 2602 169lbs/ft X-56 Del-Quip 2880 1410 1700 13 3/8" 59 8909 72 lbstft N-80:P-110 BT&C 4730 2520 761 9 5/8" 57 11086 52.5 lbs/Ft P-110 BT&C 8920 7480 1159 CEMENTING SUMMARY 20"Conductor Cement with 1070 ax Class"G"w/0.25 gal/sx D-77. 11/25/93 0.05 galtsx 0-47&0.28 gal/sx D-75.Tailed with 600 sx Class"G" mixed(d,/15.8 Ib/gal with 0.25 gal 0-77&0.05 galtsx D-47 vv.,aa,:,. Cement circulated to Surface. 13 3/8" 1st Stage Cemented with 900 sx 12.5lbi'gal Class"G" with 1.0"D-6 plus 0.05 galtsx D-47. Tailed with 700 sx Class"G" 15.8 lb/gal °"""""" with 0.04 gal/sx 0"47,0.5%D-59,0.15 galtsx D-801,0.4°k 0-65, @° 0.1%D-134 and 0.25%S-1, 2nd Stage Cemented with 3700 sx 18.6 Ibtgal Class"G"with 0.10%0-65,plus DMY Tool @ 7385' 0.1 galtsx D-47,0.1%D-135,1.0 gaVsx D-600,and 0.3%D-800. TOc @'i'" 3rd Stage Cemented with 1000 sx 15.8Ib/gal Class"G"with 0.20%0-65,plus DMY Tool /4045 0.1 gal/sx D-47,0.1%D-135,1.0 gal/ax D-600,and 0.3%0-800. 9 5/8" Cemented with 500 sx 15.8 Ib/gal Class"G";TOG©10,088' 7"&3.5" Cemented with 1310 sx 15.8 Iblgal Class"G"with 0.2%CFR-3,plus 0.13 gal/sx Haled 344L,0.25%MR-5. w- SHORT STRING TUBING 1 0.00 53.58 Elevation ■ e 53.58 0.93 Tubing Hanger 54.51 283.36 2 7/8"6.5 tbftt L-80 CS Hydric Tubing 337.87 4.00 2 7/8"Halliburton TRSV 341.87 3984.94 2 7/8"6.5 lb/ft L-80 CS Hydr91 Tubing 4326.81 6.48 2 7/8"CAMCO Gas Lift Mandrel 4333.29 1578.51 2 7/8"6.5 ib/ft L-80 CS Hydril Tubing \ \\ > 5911.80 6.43 2 718"CAMCO Gas Lift Mandrel 591623 1124.16 2 7/8"6.5 lb/ft L-60 CS Hydril Tubing 7042.39 6.45 2 7/8"CAMCO Gas Lift Mandrel i xi ro-ilini...„:,,`•••\\ ,, 7048.84 1135.35 2718"6.5 Ibtft L 60 CS Hydnl Tubing 8384.19 6.48 2 7/8"CAMCO Gas Lift Mandrel \,tW ..e.,.:r 8190.67 1112.45 2 7i8"6.5 lbtft L-80 CS Hydril Tubing 9303.12 6.48 2 7/8"CAMCO Gas Lift Mandrel 1xMa.'ae.c 9309.60 980.55 2 7/8"6..5!blit L-80 CS Hydra 1 x71..,1,.+x y Tubing 11111111111111111111111111 1'"16'1363 10290.15 6.44 2 7/8"CAMCO Gas Lift Mandrel 13001,3Y.20 '39144•139613 10296.59 296.75 2 7/8'6.5 lb/ft L-80 CS Hydric Tubing 10593.40 7.13 Halliburton RDH Dual Packer 10600 47 12.05 2 7/8"6.5 lb/ft L-80 CS Hydril Tubing 7•.'".s�."i' 10612.52 1.14 HES'X'Nipple r�-A. x--""' 10613,66 10.12 2 7/8"6.5 lb/ft L-80 CS Hydric Tubing ................. 10623.78 1.43 HEX XN Nipple I 10625.21 0.74 Wireline Entry Guide WELL BTORY.SHORT STRi NG '- ' 11/21/01 Set 2.313"PXN Plug in XN Nipple @ 10624'RKB 09/15/02 Change out 11"10K Flange from blind to open for SL work 09/29/02 Tag XN Nipple @ 10,154'WLM WELL HISTORY 1'' qI 11,'61 " ',,R 44411 %.1:1:3,ill:r1P1,?!7tt 12/02/01 Set 2.1875"HES Magna Range Bridge Plug @ 13,625'RKB 12/03/01 Dump bail 27'Class"G"Cement on Bridge Plug 09/18/02 Ran 2'2",HES TCP guns 6 SPF,60 deg phase,8 tota shots parked guns @ 13140'-13142' 09/25/02 Pump 29 bbls of 15.8 PPG Class G cement @ 12,000'CTMD to cover Sunfish PERFS 09/29/02 Tag TOC©12,015'WLM,P&A complete in long string Updated By : Osborn 911/2003 I'I3TD: 8,146'1 Supe: Tbg.Wt. SHORT STRING • REV DATE BY _ CK APP L__..RIPTION REV_ DATE BY CK , A, ` DESCRIPTION Z, !1 36 31 T 12 N 31 32 114.; I 1 6 1N T 11 N 6 5 ,..t. N 1206' SCALE: I":1320' o rn c ct I 6 6 5 12 7 7 8 GENERAL NOTES: ••� OF..44,744. I. SEE SHEET 3 FOR COORDINATE TABLE .:g',P:••'" • .� 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND i �' .1, `' • VERTICAL SURVEY DATA V 1a' 49th IN °``. ° 3. SECTION LINES AND TIES ARE BASED ON PROTRACTED if I VALUES. 1 . KENNETH W. AYERS .gam ��u'� t, LS-8535 ,, ! SURVEYOR'S CERTIFICATE .1.a''•••.•,,,..•,,, •",c) ,gar I HEREBY CER TIF Y THA T I AM PROPERLY REGISTERED AND �4 �;�NN\-*4 LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY DONE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL 0 LOUNSBURY DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OFSLOANIdo SSOCIATES. INC. ►LINMRI FEBRUARY 28, 2008. 'P PHONE: nor) 27.1.545 AREA: MODULE: UNIT: ConocoPhilll sNORTH COOK INLET jj TYONEK PLATFORM Alaska, 6fC. WELL CONDUCTOR AS BUILT CADD FILE NO. DRAVNNG NO: PART: REV: 08-005 AS BUILT 02/27/08 08-005 AS BUILT 1 of 3 0 • REV DATE BY CK APP L. <IPTION REV DATE BY CK AI DESCRIPTION Pa 99 0 ti<<\ 6,0 Q SCALE: I"-30' • ESD 600-50 ESD 600-51 Ala07 WELL HOUSE 3 IQ .SA AS AI_A. 113% Q6 •.A3� duo, AIM OAS s At• WELL HOUSE I WELL HOUSE 2 -614 A-15 O• :p Aro• LEGEND: A- A? • WELL O WELL CONDUCTOR ESD (EMERGENCY SHUT OFF VALVE) GENERAL NOTES: I. SEE SHEET 3 FOR COORDINATE TABLE 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND VERTICAL SURVEY DATA LOUNSBURY 3. NO WELLS EXIST IN WELL HOUSE NO. 4, AND IT WAS NOT & ASSOCIATES, INC. AS BUILT SURVEYORS ENGINEERS PLANNERS 4. PHONE: (lOT) 572-5151 VV. AREA: MODULE: UNIT: ConocoPhilfips • •NOf TH .:c-E�OK INLET FY'ONEK/frnTFORM Alaska, Inco WELL) IgUdITOR AS BUILT _ CARD FILE NO ; I?;'.' DRAWING-fJ0' " ' ".APART: REV: 08-005 AS; BUILT " 02/27/08, 4,'; UO-005 .Ab ,,BUILT I 2 OF 3 _.; 0. v . NCI b J2 PTO 197-210 ©ConocoPhillips Alaska, Inc , ; 1 F This photo is copyrighted by ConocoPhillips Alaska, Inc. and Ilk cannot be released or published without express written consent of ConocoPhillips Alaska s _ _ + 11 �z i 0,. tt Pe 1..". , .0:„. 1 6 lalirAi f fto inn. a' a ; t't '14000000e ..411m w,,,,, \ w vil:44 Ill1 fa{v$ } y g -.4. • • 4 4 yf ._ °`�',A / I ^yam , '''''.f,,N0N, ,,,,:' „ . . ,. N. •,, -,. u "ip.. aAt y`. w ,i'`q h \ ,. Esq ,t ,. �� a:^�„0.`• M'.yL, Yw , ' w aWt 1Y•4: i �... ,, -:,.:,.. , ;,7�► " .... ,.. ..,. ,„„ , „:„.„...-.,,,,,,,,, ,, - _ „ ,„,..... lip , , ,:,„,,,,,,,f,„„,-„„:„,...,-„:„.„..„-,,,,,,„,,,-,.14,4 4. % ,, ,,,,,, ,- ,, ,,,‘„,..,„, , .. i , , ilw,„,..„,,,,,,-„,,,,,,,,,,,,t,,,,,,.„,„.,,,,..„-- . . , , ....,,,," „.. , . ..,, „:„... ,,,,,„,,,,,,,,,r,„-:-- ,, 1 — . ,_.,- . - ,,,,,./- , :.,, 4i,,,,,,,,,:..„,„:„.....„,,,,.,,,,„,,,..,,•:. .,,,,„ „ ,, - - , .4,., , ... __ . _1 _1 ..,. ._• ....„..,:.:;.,....,..., ,,,, , v, , t_ „.:,,,, ____.,... _,,,,,,i 4„.., ... ., , ,,,.. , . n r y 4, -- .,,....... .., .,. _ , ,,,,.. 0 . ,. --, , M ,,,, c..,., . ; ..,,, , ., I -"S f ^ c- w c rte.°r ,SIX &.' }y^ p. k NCI B- TD 197-210 . � ©Conoc f lips Alaska, Irc ir 01. � � �_� , Illik tw, This hog is copyrighted b _ p Conoco fillips Alaska, Inc. and, , cannot be released or published a without express written consent of ConocoPhillips Alaska i♦ 1 g} , " ' , ,...1,7ft____ , of il .. _ _._,..,.. : , , i iv V ' $ a,w,Y '0.s; _.. 11114 unitik z _ ,„,,, , 4 1 ----1%,-....:- 4, 44- r , „ ..., . , .._, ,,,,,,, . , , ,;:i 1 ' I , ' tilti Able: °., :, 't„ * ' v*\ .vesittil!i I '''' �. M ' ‘10.6.* %?Ill +, �S '4 II, ' 4 ,. • ° dm 4 01 ,. t4� me 'h.'" , vit. it . i I, ‘ „41,41i.10. e ..c,4 ., - ip! .... , ,_ ,, , i „., .,. ,„, .,,L,,. . .. NCI B-02 PTD 197-210 ©ConocoPhillips Alaska, Inc This photo is copyrighted by ConocoPhillips Alaska, Inc. and cannot be released or published without express written consent of ConocoPhillips Alaska r r - -, ‘,.. « I I t , , f 1 wee 1. .....: 0 014 .., 1 1011 „. ,i. ..,... 4 PI •• w ir li ar , tr ..',, . , ,a..,, 1 Air i ., „4... , . 4,,,, _ .. , , ,4,411: 4,,,o, , , „ , iv NCI B-02 PTD 197-210 ©ConocoPhillips Alaska, Inc This photo is copyrighted by ConocoPhillips Alaska, Inc. and cannot be released or published without express written consent of ConocoPhillips Alaska Pages NOT Scanned in this Well History File XHVZE This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. 1 � 7' a File Number of Well History File PAGES TO DELETE Complete RESCAN ❑ Color items - Pages: Grayscale, halftones, pictures, graphs, charts - Pages: 138 ❑ Poor Quality Original - Pages: ❑ Other - Pages: DIGITAL DATA Diskettes, No. L' ❑ Other, No/Type OVERSIZED ❑ Logs of various kinds ❑ Other COMMENTS: Scanned by : Beverly Mildred Deretha albs dwell Date: 31 'y /s/ ❑ TO RE -SCAN Notes: Re- Scanned by : Beverly Mildred Deretha Nathan Lowell Date: Is/ t SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION F KORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 John Braden Staff Engineer JAN 1 8 all ConocoPhillips Alaska, Inc. �, P.O. Box 100360 Anchorage, AK 99510 ` Re: North Cook Inlet Field, Undefined Pool, NCIU B -02 Sundry Number: 310 -431 Dear Mr. Braden: 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 th- date of this letter, or the next working day if the 23rd day falls on a holida or ' eekend. S rely 0/1 - nf.. No an Comm -'oner DATED this 4. day of January, 2011. Encl. John Braden Cook Inlet Asset ConocoPhiIhps Email joh 263 -4536 Email: john.cbradenQconocophikips.com 700 G. Street P. 0. Box 100360 Anchorage, Alaska 99510 -360 December 20, 2010 Commissioner Dan Seamount State of Alaska Alaska Oil & Gas Conservation Commission RECEIVED 333 West 7 Avenue, Suite 100 DEC 2 0 2010 Anchorage, Alaska 99501 RE: Renewal of Suspended Well 10-403 Status 'Masks Oil Gas Coos. Commission Anc.'anaAe North Cook Inlet Unit B -2 (PTD 197 -210) Dear Commissioner Seamount: ConocoPhillips Alaska Inc. (CPAI) submits this request for renewal of the suspension status of North Cook Inlet Unit B -2 (PTD 197 -210) per 20 AAC 25.110. The well was visually inspected on September 10, 2010 by CPAI and by Inspector Bob Noble on November 14, 2010. A 10-404 was submitted for this well on November 22, 2010. As noted in the previously submitted 10 -404, the well has cement from 13,625 ft RKB to 12,015 ft RKB, isolating the perforations and will not allow migration of fluid that could threaten public health or impair the recovery of oil or gas. The perforations have been recognized by the Commission as plugged. The integrity of the existing plugs will be demonstrated by daily monitoring of pressures according to Conservation Order No. 507. The Tyonek platform is an active production platform and there are limited well slots for future wells. Hence, CPAI requests renewal of the suspension because this well has future utility as a sidetrack candidate. Sincerely, John C. Braden cc: Central Files Well Integrity Supervisor W4iA- STATE OF ALASKA 0 11312.011 ALASKA OIL AND GAS CONSERVATION COMMISSION 1/4/11 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request: Abandon r Rug for Redrill r Perforate New Pool r Repair well r Change Approved Program r Suspend FY Rug Perforations r Perforate r Pull Tubing r Time Extension Operational Shutdow n r Re -enter Susp. Well r Stimulate r Alter casing r g Other: Renewal of Suspended Status 17 , 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Alaska, Inc. Development pv Exploratory r 197 -210 3. Address: Stratigraphic r Service r 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50- 883 - 20090 -01 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line 8. Well Name and Number: where ownership or landownership changes: Spacing Exception Required? Yes r No 17 NCIU 8 -02 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL 17589 • North Cook Inlet Unit / Undefined 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): r 7 1 77 12054' 11117' 12054' 12015' I 14537 33 Casing Length Size MD TVD Burst Collapse Structural 368' 30" 368' 368' Conductor 2543' 20" 2602' 2535' Surface 8849' 13 -3/8" 8909' 8123' Intermediate 12080' 9-5/8" 11086' 10244' Liner 2788' T. 13522' 12460' Liner 14457' 13306' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): perfs P&A'd 2 - 7/8" & 3.5" L - 10625' & 12466' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft) Halliburton RDH dual packer 10593' MD, 9751' TVD Halliburton TRSV 338' MD, 338' TVD 12. Attachments: Description Summary of Proposal F 13. Well Class after proposed work: Detailed Operations Program r BOP Sketch r Exploratory r Development Service r 14. Estimated Date for Commencing Operations: 15. Well Status after proposed work: 12/31/2010 Oil r Gas r WDSPL r Suspended 16. Verbal Approval: Date: WINJ r GINJ r WAG r Abandoned r Commission Representative: GSTOR r SPLUG r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: John Braden © 263 -4546 Printed Name John Braden Title: Staff Engineer Signature ��G Phone: 263-4546 Date 20 Oa:- 1I) Commission Use Only Sundry Number: ✓ ) O. q 3 1 Conditions of approval: Notify Commission so that a representative may witness `1 I Plug Integrity r BOP Test r Mechanical Integrity Test r Location Clearance r Other: Pu IrS l.(gAilt �O V7 /k(�{ t . tl2Li, A A-torl �vl tuu2 1� i I� _- ((Wove DEC 2 C 2010 Subsequent Form Required: ij d h,Q. � Alaska Oil & G8; Cons. C®BiMTBSilAl1 • / APPROVED BY Anchorage Approved by: ' ' COMMISSIONER THE COMMISSION Date: im4 -'1/ 1NAL p licate i� Form 10- ' I (� Submit in Du f�lll'A�' 1 I 5 2 v , . PM1 * PHILLIPS Alaska Inc. �.1 A Subsidiary of PHILLIPS PETROLEUM COMPANY N I B-2 _ _ BPV (Mke, Type, OD) Not Applicable RKB -THF: Tbg Hr (Make, Type) Not Applicable RKB•BHF 59.00 Annulus Fluid: RKB -MSL: 132.00 TOC: Water Depth: 130.00 _ , a - e aam OD TOP BTM WT GRADE CONN. BURST CO# TRO Casing Strings PPCO Allowable Ratings 30" 55 407 547 Ibs /ft WELD 20" 59 2602 169 Ibs /ft X -56 Dnl -Quip 2860 1410 1700 13 3/8" 59 8909 72 Ibs /ft N -80:P -110 BT &C 4730 2520 761 9 5/8" 57 11086 52.5 Ibs /Ft P -110 BT &C 8920 7480 1159 - +," S CEMENTING SUMMARY 20" Conductor Cement with 1070 sx Class "G" w /0.25 gal /sx D -77. 11/25/93 0.05 gal /sx D -47 & 0.28 gal /sx D -75. Tailed with 600 sx Class "G" mixed @ 15.8 lb/gal with 0.25 gal D -77 & 0.05 gal /sx D -47 UF.a„ 801149/1 Cement circulated to Surface. 13 3/8" 1st Stage Cemented with 900 sx 12.5 lb/gal Class "G" with 1.0^ D -6 plus 0.05 gal /sx D -47. Tailed with 700 sx Class "G" @ 15.8 lb/gal "" " eawe with 0.05 gal /sx D -47, 0.5% D -59, 0.15 gal /sx D -801, 0.4% D -65, "' •eaaa 0.1% D-134 and 0.25% S-1. 2nd Stage Cemented with 3700 sx 18.6 lb/gal Class "G" with 0.10% D -65, plus DMY Tool @ 7385' 0.1 gal /sx D -47, 0.1% D -135, 1.0 gal /sx D -600, and 0.3% D -800. roc @ 10 OM 3rd Stage Cemented with 1000 sx 15.8 lb/gal Class "G" with 0.20% D -65, plus . DMY Tool @ 4045 0.1 gal /sx D -47, 0.1% D -135, 1.0 gal /sx D -600, and 0.3% D -800. 9 5/8" Cemented with 500 sx 15.8 lb/gal Class "G "; TOC @ 10,088' • 7" & 3.5" Cemented with 1310 sx 15.8 lb/gal Class "G" with 0.2% CFR -3, plus 0.13 gal /sx Naiad 344L, 0.25% HR -5. SHORT STRING TUBING 0.00 53.58 Elevation L•••■ roc r 0 ■-:s• 53.58 0.93 Tubing Hanger Pace 54.51 283.36 2 7/8" 6.5 lb/ft L -80 CS Hydril Tubing -)oee 337.87 4.00 2 7/8" Halliburton TRSV 341.87 3984.94 2 7/8" 6.5 lb/ft L -80 CS Hydril Tubing 4326.81 6.48 2 7/8" CAMCO Gas Lift Mandrel 4333.29 1578.51 2 7/8" 6.5 lb/ft L -80 CS Hydril Tubing 5911.80 6.43 2 7/8" CAMCO Gas Lift Mandrel 5918.23 1124.16 2 7/8" 6.5 lb/ft L -80 CS Hydril Tubing MENNIMIM 54■44•4 7042.39 6.45 2 7/8" CAMCO Gas Lift Mandrel 7048.84 1135.35 2 7/8" 6.5 lb/ft L -80 CS Hydr l Tubing • 8184.19 6.48 2 7/8" CAMCO Gas Lift Mandrel e .,..:. 8190.67 1112.45 2 7/8" 6.5 lb/ft L -80 CS Hydril Tubing `O ~nO' \ "` s 9303.12 6.48 2 7/8" CAMCO Gas Lift Mandrel ; 7 ' 06°6 . ' 9309.60 980.55 2 7/8" 6.5 lb/ft L -80 CS Hydril Tubing 13610 -11666 `'' 10290.15 6.44 2 7/8" CAMCO Gas Lift Mandrel +19a.. 10296.59 296.75 2 7/8" 6.5 lb/ft L -80 CS Hydril Tubing p e14,377 10593.40 7.13 Halliburton RDH Dual Packer : ` Pro • 10600.47 12.05 2 7/8" 6.5 lb/ft L -80 CS Hydril Tubing 1,9.0,..3, 10612.52 1.14 HES 'X' Nipple T° - ' .. ' '" I I 10613.66 10.12 2 7/8" 6.5 lb/ft L -80 CS Hydril Tubing 10623.78 1.43 HEX XN Nipple 10625.21 0.74 Wireline Entry Guide WELL HISTORY - SHORT STRING 11/21/01 Set 2.313" PXN Plug in XN Nipple @ 10624' RKB 09/15/02 Change out 11" 10K Flange from blind to open for SL work 09/29/02 Tag XN Nipple @ 10,154' WLM WELL HISTORY - LONG STRING 12/02/01 Set 2.1875" HES Magna Range Bridge Plug @ 13,625' RKB 12/03/01 Dump bail 27' Class "G" Cement on Bridge Plug 09/18/02 Ran 2' 2 ", HES TCP guns 6 SPF, 60 deg phase, 8 tota shots parked guns @ 13140'- 13142' 09/25/02 Pump 29 bbls of 15.8 PPG Class G cement @ 12,000' CTMD to cover Sunfish PERFS 09/29/02 Tag TOC @ 12,015' WLM, P &A complete in long string Updated By : Osborn 9/1/2003 1 PBTD: 8.146'1 Supv: Tbg. Wt. SHORT STRING STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Suspended Well Inspection Report Date Inspected: 11/14/10 Inspector: Bob Noble Operator: CPA Well Name: NCIU B -2 ' Oper. Rep: Russ Allen PTD No.: 197 -210 Oper. Phone: 776 -2350 Location Verified? Yes Oper. Email: If Verified, How? Other (specify in comments) Onshore / Offshore: Offshore " vim• Suspension Date: 09/29102 Date AOGCC Notified: ? Sundry No.: 302 -234 Type of Inspection: Initial Wellbore Diagram Avail.? Yes ' Well Pressures (psi): Tubing ? Photos Taken? Yes IA 0 OA 270 Condition of Wellhead: The well location was verified with an as built. This wellhead is a 10,000 psi duel completion. All lines and valves were blinded. I saw signs of leaks. Was unable to get tubing pressure because the swab was blinded off. Condition of Surrounding Surface The wellhead looked fairly good. No signs of spills or leaks. Location: N Follow Up Actions Needed: Attachments: ph ( 3) REVIEWED BY: [In sp. S ry Z3 1l7 omm I PLB 08/2010 2010- 1114_Suspend_NCIU_B- 2_bn.xis • • Suspended Well Inspection — NCIU B -02 (CPAI) PTD 197 -210 Photos by AOGCC Inspector B. Noble 11/14/2010 i m r= A(rON. �F tS a, ,t John Braden Cook Inlet Asset Telephone: (907) 263 -4536 C onocoMillin.A. Email: john .c.braden @conocophillips.com 700 G. Street P. O. Box 100360 Anchorage, Alaska 99510 -360 November 22, 2010 Commissioner Dan Seamount XAMWX NOV 2 3 2010 State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7 Avenue, Suite 100 AI , Anchorage, Alaska 99501 V 010 RE: Suspended Well Inspection (20 AAC 25.110) 10 -404 Sundtj8Sj,A jib Gas Cons. C' North Cook Inlet Unit B -2 (PTD 197 -210) h karag@ Dear Commissioner Seamount: Attached is the suspended well inspection documentation as required by 20 AAC 25.110 for North Cook Inlet Unit B -2 (PTD 197 -210). In fulfillment of the requirement, the following documents are attached: • Form 10 -404 for PTD 197 -210 • Letter authorizing delay of inspection • Report of operator survey per 20 AAC 25.110 • Wellbore Schematic • As -built Survey • Estimated Pore Pressure vs Depth Plot of the NCIU Area • Letter indicating perfs are P &A' d • Tree Photos If you need clarification or more information regarding this suspended well inspection, you may contact me at the above phone number or addresses. Sincerely, It John C. Braden cc: Central Files Well Integrity Supervisor STATE OF ALASKA ALASK* AND GAS CONSERVATION COMMISS* REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon U RepairWellLi Plug Perforations Lj Stimulate U Other LJ 20.AAC25.110 Performed: Alter Casing ❑ Pull Tubincjj Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdowr❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator ConocoPhillips Alaska, Inc. 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development Q Exploratory ❑ 197 -210 3. Address: P.O. BOX 100360 Anchorage, Alaska 99510 Stratigraphic❑ Service ❑ 6. API Number: 50- 883 - 20090 -01 00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL 17589 I NCILI B -02 9. Field /Pool(s): 10. Present Well Condition Summary: Total Depth measured 14537 feet Plugs measured 12054 feet true vertical 13377 feet Junk measured cmt top @ 12015' feet Effective Depth measured 12054 feet Packer measured 10593 feet true vertical 11117 feet true vertical 9751 feet Casing Length Size MD TVD Burst Collapse Structural 368 30" 368' 368' Conductor 2543' 20" 2602' 2535' 115 Surface 8849' 13 -3/8" 8909' 8123' R^ ,i, 1 1 Intermediate 12080' 9 -5/8" 11086' 10244' Production N OV 2 3 Z 010 Liner 2788' 7" 13522' 12460' Liner 14457' 13306' f 4�.�lo ,B�S�Gt� Perforation depth Measured depth feet p p all perfs P&A D �,,, tane True Vertical depth all perfs P&A'D feet Tubing (size, grade, measured and true vertical depth) short string 2 -7/8" L -80 10625' MD 9783" TVD Long string 3.5" L -80 13529' MD 12466" TVD Packers and SSSV (type, measured and true vertical depth) dual packer 10593' MD 9751' TVD Haliburton TRSV 338' MD 338' TVD 11. Stimulation or cement squeeze summary: Not Applicable Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 140 0/790 Subsequent to operation: 0 0 0 140 01790 13. Attachments: 14. Well Class after work: 5�1 Copies of Logs and Surveys Run Exploratory[] Development ❑Q /I l6 Service ❑ Stratigraphic ❑ Daily Report of Well Operations XXX 15. Well Status after work: Oil I Gas WDSPL I GSTOR ❑ WINJ ❑ WAG ❑ GINJ d SUSP'i] SPLUG ❑ 16. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: None Contact John Braden Printed Name: John Braden Title: Staff Engineer Signature L ! Phone: 263 -4546 Date O . j ID RBDMS NOV 2 3 20 Form 10-404 Revised 10/2010 Submit Original Only (C(DPY John Braden Cook inlet Asset COnoCQ�11il1 S Email: joh 2634336 Email: john.c.tuadenQconocrophiNipa.com 700 G. Street P. O. Box 100360 Anchorage, Alaska 99510 -360 September 27, 2010 Commissioner Dan Seamount' State of Alaska S E P 2 8 ?01 0 Alaska Oil & Gas Conservation Commission 333 West 7 Avenue, Suite 100 A 618 ., ` a Anchorage, Alaska 99501 s RE: Scheduled Witnessed Suspended Well Inspection (20 AAC 25.110) North Cook Inlet Unit A -11 (PTD 169 -089) & NCIU B -2 (PTD 197 -210) Dear Commissioner Seamount: I have prepared suspended well inspection reports for the above- referenced wells based on Operator inspections. Per the attached, the witnessed inspection will be delayed to November 14, 2010, when the Operator expects a Commission Inspector to be on the Tyonek Platform to witness sales meter calibrations. I will have the prepared suspended well report available for his review at that time and then submit the witnessed suspended well report within 30 days after inspection. Contact me at the above phone number or addresses if you would like to discuss this matter in more detail. Sincerely, John C. Braden cc: Central Files Well Integrity Supervisor • Page 1 of 2 Braden, John C From: Aubert, Winton G (DOA) [winton.aubert@alaska.gov] Sent: Monday, September 27, 2010 8:52 AM To: Braden, John C Cc: Grimaldi, Louis R (DOA) Subject: RE: Suspended Well Inspection John, If there are regularly scheduled AOGCC- witnessed inspections on the platform within the next two months (by the end of November, 2010), please redo the NCIU A -11 and B -02 suspended well inspections, with AOGCC witness. If the next regularly scheduled witnessed platform inspections are more than two months distant, please submit A -11 and B -02 unwitnessed suspended well reports, based upon your recent (unwitnessed) inspections. Thank you, Winton Aubert AOGCC 793 -1231 From: Braden, John C {maiito: John .C.Braden @conocophillips.com] Sent: Monday, September 27, 2010 8:23 AM To: Aubert, Winton G (DOA) Subject: FW: Suspended Well Inspection Winton, I spoke with Tom on Friday. In spite of Lou's recommendation, Tom said this is in your shop. Thanks, John Braden From: Braden, John C Sent: Friday, September 24, 2010 7:48 AM To: 'Maunder, Thomas E (DOAr Cc: Aubert, Winton G (DOA): Ron, James B (DOA) Subject: FW: Suspended Wd inspection Tom, Per Lou's suggestion, I am writing to request a wavier of suspended well inspection for NCIU A -11 (PTD 169 -089) and NCIU B -02 (PTD 197 -210). The Operator has inspected the wells and found them to be in good mechanical condition. Pending your decision, I will finalize submit the suspended well report per 20 AAC 25.110 and submit. John C. Braden Cook Inlet Development ConocoPhillips Alaska, Inc. (907) 263 -4536 phone (907) 265 -1441 fax john .c.braden @conocophillips,com • Page 2 of 2 From: Tyonek Offshore Installation Manager Sent: Friday, September 24, 2010 7:09 AM To: Braden, John C Subject: RE: Suspended Well Inspection John, I just received a call from Lou Grimaldi concerning the suspended well inspection. He suggested that you contact Tom Maunder (793 -1250) about a waiver of inspection by AOGCC. Gary L. Smith // Tyonek ON 907 - 776 -2073H Fax 907- 776 -2044 "Remember at ConocoPhillips Alaska, Inc. our work is never so urgent or so important that we cannot take the time to do it SAFELY and in an Environmentally prudent manner." From: Braden, John C Sent: Wednesday, September 22, 2010 2:58 PM To: Tyonek Offshore Installation Manager Subject: Suspended Well Inspection Gary- 1 left a message for the AOGCC inspector to call me about suspended well inspection. He may call you. This is the same inspection that Dennis did last hitch on B-2 and A -11. We dropped the ball in not Inviting the AOGCC to witness. If he calls you, please let me know. I have a package prepared for him to review if he wants to witness. If he waives the Inspection, I need to note it in the final report. Thanks, John C. Braden Cook Inlet Development ConocoPhillips Alaska, Inc. (907) 263 -4536 phone (907) 265 -1441 fax john.c.braden @conocophillips.com 9/27/2010 North Cook Inlet Unit B -2 (PTD 197 -210) 20 AAC 25.110 (f) Report of Sundry Well Operations (Form 10 -404) 1. Description and condition of the wellhead and surface location, including any discoloration, fluid or sheen visible on the ground or in any nearby water; The well is located on the Tyonek Platform in Well Room #1. The well room is kept clean; there is no discoloration, fluid or sheen on the floor or in any nearby water. 2. A plat showing the location of the suspended well and any wells within one - quarter -mile radius of the wellbore; A plat showing the location of the Tyonek Platform and all wells on the platform is attached. There are no other operating or suspended wells within a quarter mile of the platform. 3. Well pressure readings, if practicable; Tubing: 0 psig. (3- 1/2 "), 790 psig (2 -7/8 ") Inner annulus: 140 psig. Outer annulus 775 psig. 4. Photographs clearly showing the condition of the wellhead and surrounding location; Photographs demonstrating the condition of the wellhead are attached 5. An update of all information and documentation required in (20 AAC 25.110(b) of this section. 20 AAC 25.110(b) requires that the well meet the requirements of 20 AAC 25.110(a) in addition to including a wellbore diagram, information of geopressured or depleted strata and proposed work plan. In accordance with 20 AAC 25.110(a), the well is mechanically sound. Casing pressures demonstrate the integrity of the casing. The attached schematic of the well indicates the well has cement from 13,625 ft RKB to 12,015 ft RKB, isolating the perforations and will not allow migration of fluid that could threaten public health or impair the recovery of oil or gas. The perforations have been recognized by the Commission as plugged and in accord with 20 AAC 25.112(8)(1) and (2) in the attached letter dated October 20, 2004. The integrity of the existing plugs will be demonstrated by daily monitoring of pressures according to Conservation Order No. 507. The Tyonek platform is an active production platform and there are limited well slots for future wells; hence, this well has future utility as a sidetrack candidate. Attachments Wellbore Schematic As -built survey Pressure vs depth plot Tree Photos Conoco' hWI ips NCIU WELL A - Completion Diagram Al. 5.6]299]100 G. FMC OCT RKB4MY Deck: Si C FMC 1112'eb x4113'BTdt RKB -TXF'. 38.9 42 Annulu4 flu.: S.SMY KCL C9m INbn Fluld wl1M1 30 %MatM1anel RK63L' tt9 390' TOC'. 3900' par CBL delad 1L1L66 WATER DEPTH: 120' RKBNL: CASING L TUBING 16•0 121' 30" 40' JWO' 40' 8 1 658 lti0 1540 630 291 1014 • 40' 2745' 45.58 A 518 146 B- 33. 1970 611 40' 2. 145 4660 ]" )T 6991' 145 iRC 1000 6991' BOOT' 2 61 j45 4660 4000 ]2e 7 112" M' JJ3' 1 601 d3 T3C 6601 135 1o.r Qn43 tn• aJT WJ' 11 -ss 134 mm mmm =am 1M' 4730 41. -R TON nom STRM A iffim" CMT top Q 3995' (1.2002) 45 5. O.1 ... E v CMT Relairror Q 4063 M 38.90 0.67 O0s Q 43 FMC IOOT 6'JM 412' BN x 4112'BT &C TUOir H 1958 6.000 VSII packer N9Y 39.57 258.31 41(2 12 . 61b:h}55- e-Tubinu 3.958 563 ] 42 WAS ltu•99NV lsyeY; w n.. 1 3.1.17 4115 4 t26ir.m 1 3.958 5561 T 1,1 BTLL 6.9 4.919 41 )68 -. tin 3.958 5.56 Cook Inlet Sands 39 4oe+96 o a x z994 ss 31 4082.66 : JNb IO pvera0 3.06 3.8 OYSRN1lyd- nMpk,@4- M 4113.1 1Ln W N rear SH RNew16M PK14r 3JW L9W >5 41. ].969 6.7. 1221. (a0z1 b 4097) ub 8 X-Over 26,192 ] 500 v 1 E O £ 1331.12. 34ay H 413L/3 1 9 'X' Land "n N 1 LT. Lm ,d' 1306-0)(sgzl 32 4119) rn8x -Over .992 60 3.SC0 l 31 41 7 _ 41 '. s V i X t e 2993 3500 41MA3 4.53 We•RH•H draWic 3sl ReWevabN PeaW LOW s BekarnF'Parm pkrQKtT 28 4186.84 tY1.75 31 9�IM1'1 ",.ring. Blasl lrn•'s X-0ver. 29-2 3965 4317.59 3.95 Gd, 3 I •'XA'Wdi SMen -r2os 121 1 mrellx3 E 43'.54 95.4 3 V 92 brY N O Buttress TUbin vi 2:932 3.500 p 1824 -SS (sqz) 5 4617 Baker dal UNI 17 23 --G 76.91 11n' 9.2 VIM Mn MI. lOints. X-0ve,. 2.991 3.865 1657 -4702 CI -1.0 22 4995.99 2.89 oust 719•'1U'BYeI 9lsava OPEN 2.31 1715 -4805 0-2.0 21 4-11 38.1 312' 92 Lrll NAO Bunress Tulin 8X-0vm 2992 15W 1816 -1846 Cl- 20 4937.00 ] Baker Seal UNl 4652 -1867 CI -3 W .f H N11 Baker 9ksMAT PerRlelrM Mw AIM SA 18 d )3 17 61)11) Ohs TI ••XA'Sidl S ::iEO 16 517 J1R" YNI N40 Buttress TUM 2.9 2 MM 15 52'!.00 Baker ad UM N 1211. 04. N"d PM818netM 13 52 1l ' T d X 2.992 .865 11 5]t CLOSED 2,31 Baker •F• Perm pkr Q 493T 11 5538A0 J 1!2' 92 E11 11-00 Bullrsu T 9 X-0ver 2.992 3.51X; O'k Sea' IkM OPBQ 1.1 '121 milled 1W T LOW Nn -NWT C14.0 9 1721 ,55 I -'113 Il RJh% BIasl,binh,X-0vx. 2.992 1865 SO3W -WW cM' 4 B 6015.41 L69 Olis 2 91iA BlssvB 2.313 6101.6137 CH.2 60610 W. a1r2"9.2 bn N408uttrnu TU' 6x -OVer 2992 3.500 1T Boxer Seal'). 11 coo 9AN S 6117.57 -53 31/2' T MJNnU X- 2.9H1 3.865 t Baker F" Perm pkr Q 5211' 4 VA 3.101 3 619)00 30.0 31 9. 9i5 N40 uttress TUN 6X -0ver 2.902 3.SC0 5148 -5262 CI -8.0 2 6497,02 0.98 Wireline e- PE�•^ .aide 3.]25 4,987 S2. 2. CI -8.2 -1 EMdTir :.. SIBS -5307 CI -B.2 5358 -5]fi9 CI -9.0 5399 -5119 CIf00 54w.ss6a a -1 r.0 WBB Hist 5468 -5498 CI -110 430 - Fes1 Pmdudbn k'Om C klel A, 1 -3, 511 Ir75 - a A, 1 -J, St t, sAw (Add Beluga) SSl9 -]9 (sgz) 7/83 -Run 3 1/2 mcb rtiMp MM muMpb packer and lidirg sleeves I. 10190 - Beluga wW <r4Y 1 Baker 4• Perm pkr Q 3733 5,91 -Run 4- 1 /21ncn tublrg. wN not repedpreled due to muMple packer. Beluga weY � Beluga Sands 613 -Tp FYSws' uros- Top of Fe 1.1 (L<we, sleeve <werea7. SB15 -5859 17 - Top OI FA 6366' soave covered). 5871 -5877 1-8 5197 -Open CI 11 - ,14917 SBgg -3909 <-OS 9199 -TeM 5.5 MMCFD 913.5 BWPIMb Yre 40p psi (U.G anO Beluga sleeves open) 5930 - 5950 t1 9 -COW not qnt Y pelge rY below 5987' 6962- 39)4 02 11/99 - dosed Upper CI sMnve. Teat 60-350 BWPO hwn Belupe (b Wmj 150 psI FTP a 1/00 - Tag M N 5818'. bal soli to IMN sam1. F- Indkatlons L- Cook Nbl eaeve open, cbsed M stoves. Open Law, Cask in M swve a155J6',,ro kw. FL 1600'. p,aswn up with gas. Open UppM Cook MM sleeve, eee wall not lbw. Checklpr M TD 5101', bail to 5106'. Bekar'F' Perm pkr Q 6115' Nov t t, 2001 - SCSSv NOV 28, 200 FC 1 - FCO'A9T - 5910. SL Tp 5 >20' RKB 6182 -6197 6 Nov 29. 2( 101 -Geier kp. J 11, Q 4989 1&1 RKB 8212 - 6218 d-3 5 Dec 14, 2001 -gat 2.187 Bridqa Plug Q 49fi6. Confirm XA slaws Q 4896 8 4318' open. Sal SG- 6216- 6261 d1 BemP1 b bw ra1:wM dMM. 12(5191 -pu I-, Cbsa 3..5'XA slewe Q 4318'. Tng Yne semlM 4318' 8112.8278 e-5 Oq. l- 2.3003 -mB C.mwd aH9 -6161 a -8 a1. 3, X62- complete PaA wlcemem Ocl4, 2002 - cement sou »ze ou. s. zoo3 -lap top d <em.m Q 39fis' 717 -71N N 7.7 -7277 k2 ,n 11 Up-d 9112120W By: Dan Baarhn T-1 Depth 9212' P8TD. 7 126 IF. T 4316' 1.2.1 welt. North Cook Inlet Unit No. A -11 L-1- T - Ptatlonn. Coo4lNet. AMnka Fiep NprU Cook Inlet Uril JDB REVI DATE 19Y ICK JAPPI DINWRIPTION REV I DATE I BY CK I A DESCRIPTION 36 31 T 12 N 31 32 1 6 N T 11 N 6 5 cv I 1206' SCALE: 1" =1320' 3 3 _o rn � � I 1 6 6 5 12 7 7 8 � \ \\ \\vit, GENERAL NOTES: ��4 Ott �� P EE.......... . 1. SEE SHEET 3 FOR COORDINATE TABLE �.,. 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND AV #'o ' VERTICAL SURVEY DATA a s s 49th '• 3. SECTION LINES AND TIES ARE BASED ON PROTRACTED 0 .. " " """ " " """" Jo VALUES. 0 . ♦♦ ; KENNETH W. AYERS AV ♦� J`� '• LS -85 35 IV SURVEYOR'S CERTIFICATE ♦ ♦j o ............••�'��,o��� i HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND 44 4�; �;:����� LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY DONE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL LOUNSBURY DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF & ASSOCIATES. INC. sun== Wonumn runr M FEBRUARY 28, 2008. 1% PHONE. MF) 2?2.54s� AREA: MODULE: UNIT: NORTH COOK INLET Conocohilli S TYONEK PLATFORM Alaska, 6nc. WELL CONDUCTOR AS BUILT 08- 005 BUILT ,2/27 Q8 ®RAv�NC N ®; 08 -005 AS BUILT PART; I OF Q REV DATE IBYI CKIAPPI DLIMIPTION REV DATE BY CK A DESCRIPTION EE � � p s i � i'3 g A A9 9 Y �O A o �� SCALE: I " -30' �9 R �. ESD 600 -50 ESD 600 -51 A13 WELL HOUSE 3 • Or B3• •82 AO j�� 0 A3* Al• • 91 A `• *A3 A4• • WELL HOUSE I WELL HOUSE 2 -l4 A - 131 �O 0 20 Aro05 LEGEND: A - RA 0 WELL O WELL CONDUCTOR ESD (EMERGENCY SHUT GENERAL NOTES: OFF VALVE) 1. SEE SHEET 3 FOR COORDINATE TABLE 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND VERTICAL SURVEY DATA LOUNSBURY 3. NO WELLS EXIST IN WELL HOUSE NO. 4, AND IT WAS NOT & ASSOCIATES, INC. AS BUILT SURVEYORS ENGINEERS PLANNERS PHONE. (907) 272 -3431 AREA: MODULE: UNIT: ConocoPhillin5 NORTH :� -E�OK INLET TyOOL-o - �rATFORM Alaska, Inc WELLINN9 1TOR AS BUILT CADD FILE t�0:.' ;: (? DRAWING fJ0 PART: REV: 08 -005 AS, BUILT 0/27/0 g a'; '. , n8 -005 A; 1B1}ILT 2, of 3, 0 REVI DATE 1BY ICK IAPPI 01MIPTION IREVI DATE IBYICK IAPW DESCRIPTION ASP ZONE 4, NAD83, FEET NA083 GEOGRAPHIC MLLW DESCFUPTION (POINT NO.) NORTHNG EASTING LATITUDE LONGITUDE ELEVATION NCIU W ELL TAG NO. WELL HOUSE NO.1 1001 2586492 1472018 61 04 34.38 150 57 03.71 72.0 Conductor 1 1002 2586489 1472017 61 04 34.34 150 57 03.72 73.9 B3 1003 2586485 1472019 61 04 34.31 150 57 03.67 74.1 Al 2 1004 2586485 1472023 61 04 34.31 150 57 03.59 73.8 Bi 1005 2586487 1472027 61 04 34.33 150 57 03.52 72.0 Conductor 5 1006 2586491 1472027 61 04 34.37 150 57 03.52 73.7 B2 1007 2586495 1472025 61 04 34.41 150 57 03.57 72.1 Conductor 7 1008 2586495 1472021 6104 34AI 150 57 03.65 73.7 Al WELL HOUSE NO.2 2001 2586437 1472060 61 04 33.84 150 57 02.83 71.9 A Gendactart 2002 2586433 1472059 61 04 03.38 150 57 02.84 71.9 Conductor 2 2003 2586430 1472062 61 04 33.77 150 57 02.79 71.8 A -16 Gend=br-S 2004 2586429 1472066 61 04 33.77 150 57 02.71 73.4 A9 2005 2586431 1472069 61 04 33.79 150 57 02.65 71.9 Conductor 5 2006 2586435 1472069 61 04 33.83 150 57 02.64 73.3 Al 0 2007 2586439 1472067 61 04 33.86 150 57 02.69 73.3 Al 1 2008 2586439 1472063 61 04 33.87 150 57 02.77 71.9 A -14 eonductvr7t WELL HOUSE NO.3 3001 2586488 1472128 61 04 34.36 150 57 01.47 73.0 Al 3002 2586484 1472127 61 04 34.32 150 57 01 AIS 73.1 AS 3003 2586481 1472130 61 04 3429 150 57 01.43 73.1 A6 3004 2586480 1472133 61 04 3428 150 57 01.35 73.0 A4 3005 2586483 1472137 61 04 34.31 150 57 0129 73.0 A2 3006 2586487 1472137 61 04 34.34 150 57 0128 73.0 A5 3007 2586490 1472135 61 04 34.38 150 57 01.33 73.0 A3 3008 2586490 1472131 61 04 34.38 150 57 01 Al 73.3 A7 50 2586540 1472069 61 04 34.86 150 57 02.69 72.7 ESD Valve 600 -50 51 2586501 1472011 61 04 34.46 150 57 03.86 72.6 ESD Valve 600 -51 100 2586572 1472123 6104 35A 8 150 57 01.58 115.3 Top center hell ad •n+ •a rr.r urr SURVEY NOTES: I. ALL COORDINATES ARE ASP ZONE 4, NAD83, US SURVEY FEET. GEOGRAPHIC COORDINATES ARE NAD83. 2. ELEVATIONS ARE IN FEET, BASED ON MLLW, REFERENCED TO DRAWING NO. MPD- TY04 -2021, SHEET I OF 1, REV. 2 3. ALL AS BUILTS ARE TO THE CENTER OF EXISTING STRUCTURE. 4. WELL CONDUCTOR ARE VERTICALLY AS BUILT TO THE TOP OF A 114" STEEL LID, TACK WELDED TO THE TOP OF THE CONDUCTOR. 5. WELLS ARE VERTICALLY AS BUILT TO THE TOP OF THE LOUNSBURY LOWEST HORIZONTAL FLANGE ON THE WELL. & ASSOCIATES, INC. SURVEYORS ENGINEERS PUNNERS PHONE: 1`907) 272 -5431 I,/ AREA: MODULE: UNIT: C {FORTH COLK: h onocoPhillip� TYdNE 6 `:`IC PLA,��nRM Alaska, Inc. 'WELL CONOU'CTORI IBS BUILT CADD FILE NO. DRAWING NO' PART: REV: -.005 AS BUILT 3 OF 3 08 -005 AS BUILT 02/27/08 08 - 0 North Cook Inlet Unit Estimated Pore Pressure \ — —Pore Pressure - High ♦ A -10 \ ■ B -3 2,000 B -1 A -16 \ O N. Forelands \ + 17589 X A -15 4,000 � + PorePressure @ NCIU, Tertiary Pool based on +� * A -10, A -15, A -16, B -1, B -3, NCI St 17589 �� 2C X + 6,000 0 \ 8,000 \ \ \ \ \ 10,000 \ \ + \ 12,000 ` +\ Pore Pressure N. Forelands No. 1 9700 psi @ 13282 \ Cl St 17589 1 -A 5236 psi @ 10927' 0 14,000 2,000 4,000 6,000 8,000 10,000 Formation Pressure, psia d _ I d ` / FRANC H. U IRKO*Wq GOVERNOR U u ALASNA OIL AND GAS 333 w 7- AVENUE, SUITE 100 CONS$BQAMON COMUSSION ! ANCHORAGE. ALASKA, OMI PHONE MM rte» FAX (9117) 270-rJO October 20, 2004 Wade Gilpin Alaska Dept. of Environmental Conservation 555 Cordova St., 2nd Floor Anchorage, AK 99501 Re: North Cook Inlet Platform ConocoPhillips Alaska, Inc. Tyonek Deep Well Abandonments Dear Mr. Gilpen: .This letter is in response to your inquiry regarding the plugging of the "deep oil wells drilled from ConocoPhillips' North Cook Inlet or Tyonek Platform in Cook Inlet. Your message asked if the abandonments were in accord with 20 AAC 25.105. 25.105 is applicable when all operations on a property are completed which is not the case here. Specific well plugging operations must be in accord with.20 AAC 25.112. During the 1990s a total of 4 exploration wells were drilled from the platform to determine if developable oil reserves were present. Oil was encountered in the deep formations below 12;000', however it was determined to be non - commercial. The deep intervals of these wells were subsequently plugged and abandoned and shallower gas intervals completed and placed into production. I have reviewed the information contained in the files for the respective wells. The deep intervals of NC1U A -13 (formerly Sunfish #2) were abandoned in late 1993 as part of the original work program. An AOGCC Inspector did not witness the plugging operations. Based on my review of the file, the work performed conforms to the requirements of 20 AAC 25:112. The deep intervals in the remaining wells, B-01 A, B -02 and B-03, were plugged and abandoned in late 2002. An AOGCC Inspector did witness weight "tags" and pressures tests to verify the competence of the plugs on each well subsequent to the cementing operations. These verifications were in accord with 20 AAC 25.112 (gXl) and (2) and the Inspector reported that the plugs were satisfactorily verified. SCANNED OCT 2 7 2004 w � ,.•.ww VV � ` �' '� ` �� � �, ., �. ,,, -# ,, . - �.�- -- � n •. ' � .., �� ; �. {. r rr �. 4 ' �� � wvP t yy Yy v x. �• � 4 1 �.„ � �� 1 � ' n w ... .r.. � �,. � 9!/ � 0 ��'2� ©��� �� �,� :. n M, y ,�u ��� �. X x v � � x i x e 7 s .. i VP's e t� n s1 J + f _... II f 4 F a w P': .,�......... a { \ii4a� `aaaaaaaa t Pre 2008 Survey Location Post 2008 Survey Location NAD27 ASP 4 NAD27 ASP4 Well Name Northing Easting Northing Easting Distance Moved NCI A -0 1 2,586,726.69 332,100.19 2,586,726.40 332,102.26 2.09 NCI A -02 _ 2,586,722.85 332,108.29 2,586,721.16 332,111.27 .' _ 3.43 NCI A -03 2,586,728.60 332,106.22 2,586,728.31 _332,109.43 _ 3.22 NCI A -0 4 2,586,719.62 332,105.09 2,586,718.58 332,108.09 _ 3.18 NCI A -05 2,586,725.55 332,110.17'211 2,586,725.14 332,111.79 `` 1.67 NCI A -06 2,586,719.66 332,102.09 2,586,719.22 332,104.19 2.15 NCI A -07 2 332,103.73 ` 2,586,728.78 332,105.40 1.94 NCI A -08 2,586,720.56 332,098.31 2,586,722.44 332,101.65 3.83 NCI A -09 2,586,666.58 332,039.08 2,586,667.35 332,040.44 „ 1.56 NCI A -10 _ 2,586,670.21 332,040 91 2,586,673.71 332,044.17 ' 4.78 NCI A -10A 2,586,670.21 332,040.91 2,586,673.71 332,044.17 4.78 NCI A -11 2,586,670.23 332,039.14 2,586,677.01 332,041.75 7.27 NCI A - 2,586,722.73 331,947.80 2,586,723.59 331,994.15 _ 46.36 NCI A -13 2,586,734.88 331,993.50 2,586,733.15 331,995.48 2.63 NCI B -01 2,586,730.03 331,999.80 2,586,723.04 331,998.16 7.18 NCI B -01A 2,586,730.03 331,999.80 2,586,723.04 331,998.16; 7.18 NCI B -02 2,586,731.14 331,999.29 2,586,729.60 332,001.86 3.00 NCI B -03 2,586,731.69 331,986 37 2,586,726.81 331,991.70 7.23 NCI B -03PB1 2,586,731.69 331,986.37 2,586,726.81 331,991.70 j - 7 .23 '3 • l - U APR 0 4 2008 9� a� REV -DATE BY I CK APP ESCRIPTION REV I DATE BY CK P DESCRIPTION I 2/29/08 $A$ KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., 5 HT.3 y 36 31 T 12 N � � y 31 32 1 6 T 11 N 6 5 MRS N s. rovs' SEC. 6 I 1206' I SCALE: I" -1320' o 0-- c 1 6 6 5 12 7 7 8 GENERAL NOTES: OF .... . . ...... q� q P•• •.,S 1. SEE SHEET 3 FOR COORDINATE TABLE • '� ,, '• ., �- . Gj , ♦ 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND A AV VERTICAL SURVEY DATA 49th io 3. SECTION LINES AND TIES ARE BASED ON PROTRACTED 0 ""' " " " 0 VALUES. 0... .. ........... .............................. r 0 KENNETH W. AYERS mo o` ♦ ♦,�� %, LS -8535 i SURVEYOR'S CERTIFICATE IFO••••.•,,,,.,.,•,..••�Pp�4W AW I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND , ��y�; ` IONP LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY DONE BY ME OR UNDER MY DIRECT SUPERVISION AND THAT ALL LOUNSBURY DIMENSIONS AND OTHER DETAILS ARE CORRECT AS OF ASSOCIATES tr LAN SURV EYORS ENGINEERS PLANNERS FEBRUARY 28, 2008. PHONE: (9071 272 -5451 AREA: MODULE: UNIT: ConocoPhillips NORTH COOK INLET TYONEK PLATFORM Alaska, Inc. WELL CONDUCTOR AS BUILT CADD FILE N0. AWING N0: PART: REV: 08 -005 AS BUILT 02/27/08 DR 08 -005 AS BUILT 1 OF 3 1 J1 REV -DATE I BY I C I APP , SCRIPTION REV DATE 1 BY I CKI DESCRIPTION 1 2129108 SAS I KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., SHT.3 g � c Y` ar $s'3 A.A. 9 TtlN Rp a'Q s. ro.A,. siS sc e o `s SCALE: I " =30' a9 A O ESD 600 -50 ESD 600 -5/ A13 007 Al B 3 0 •B2 AB•0A0 5 A30 Al• •BI A66 OA5 A4 A2• WELL HOUSE 2 B All 1 00 2 0 AlO0 LEGEND: 3 AB 0 WELL O WELL CONDUCTOR 0 ESD (EMERGENCY SHUT GENERAL NOTES: OFF VALVE) I. SEE SHEET 3 FOR COORDINATE TABLE 2. SEE SHEET 3 FOR NOTES ON HORIZONTAL AND VERTICAL SURVEY DATA LOUNSBURY 3. NO WELLS EXIST IN WELL HOUSE NO. 4, AND IT WAS NOT & ASSOCIATES, INC. AS BUILT SURVEYORS ENGINEERS PLANNERS V PHONE: 19071 272 -5451 AREA: MODULE: UNIT: ConocoPhilli S NORTH COOK INLET TYONFK PLATFORM Alaska, Inc. WELL CONDUCTOR AS BUILT CADD FILE NO. WING NO: PART: REV: 08 -005 AS BUILT 02/27/08 DRA 08 - 005 AS BUILT 2 OF 3 1 JIM dm� EV DATE I CK APP SCRIPTION REV DATE BY CK EVET DESCRIPTION 1 2129108 SAS KWA MODIFY WELL HOUSE SCHEMATIC, SHT.2 ADD MUD LINE ELEV., 5 HT.3 1 ASP ZONE 4, NAD83, FEET NAD83 GEOGRAPHIC MLLW DESCRIPTION (POINT NO.) I NORTHING EASTING LATITUDE LONGITUDE ELEVATION NCIU W ELL TAG NO. WELL HOUSE NO. 1 1001 2586492 1472018 61 0434.38 150 57 03.71 72.0 Conductor 1 1002 2586489 1472017 61 0434.34 150 57 03.72 73.9 133 1003 2586485 1472019 61 0434.31 150 57 03.67 74.1 Al2 1004 2586485 1472023 61 0434.31 150 57 03.59 73.8 131 1005 2586487 1472027 61 0434.33 150 57 03.52 72.0 Conductor 5 1006 2586491 1472027 61 0434.37 150 57 03.52 73.7 62 1007 2586495 1472025 61 0434.41 150 57 03.57 72.1 Conductor 7 1008 2586495 1472021 61 0434.41 150 57 03.65 73.7 A13 WELL HOUSE NO.2 2001 2586437 1472060 i 61 0433.84 150 57 02.83 71.9 Conductor 1 2002 2586433 1472059 61 0403.38 150 57 02.84 71.9 Conductor 2 2003 2586430 1472062 61 0433.77 150 57 02.79 71.8 Conductor 3 2004 2586429 1472066 61 0433.77 150 57 02.71 73.4 A9 2005 2586431 1472069 61 0433.79 150 57 02.65 71.9 Conductor 5 2006 2586435 1472069 61 0433.83 150 57 02.64 73.3 A10 2007 2586439 1472067 61 0433.86 150 57 02.69 73.3 All 1 2008 2586439 1472063 61 0433.87 150 57 02.77 71.9 Conductor 8 WELL HOUSE NO.3 3001 2586488 1472128 61 0434.36 150 57 01.47 73.0 All 3002 2586484 1472127 61 0434.32 150 57 01.48 73.1 A8 3003 2586481 1472130 61 0434.29 150 57 01.43 73.1 A6 3004 2586480 1472133 61 0434.28 150 57 01.35 73.0 A4 3005 2586483 1472137 61 0434.31 150 57 01.29 73.0 A2 3006 2586487 1472137 61 0434.34 150 57 01.28 73.0 A5 3007 2586490 1472135 61 0434.38 150 57 01.33 73.0 A3 3008 2586490 1472131 61 0434.38 150 57 01.41 73.3 A7 50 2586540 1472069 61 0434.86 150 57 02.69 72.7 ESD Valve 600 -50 51 2586501 1472011 61 0434.46 150 57 03.86 72.6 ESD Valve 600 -51 100 2586572 1472123 61 0435.18 150 57 01.58 115.3 Top center helipad -101 MUD LINE SURVEY NOTES: I. ALL COORDINATES ARE ASP ZONE 4, NAD83, US SURVEY FEET. GEOGRAPHIC COORDINATES ARE NAD83. 2. ELEVATIONS ARE IN FEET, BASED ON MLLW, REFERENCED TO DRAWING NO. MPD- TY04 -2021, SHEET I OF I, REV. 2 3. ALL AS BUILTS ARE TO THE CENTER OF EXISTING STRUCTURE. 4. WELL CONDUCTOR ARE VERTICALLY AS BUILT TO THE TOP OF A 114" STEEL LID, TACK WELDED TO THE TOP OF THE CONDUCTOR. 5. WELLS ARE VERTICALLY AS BUILT TO THE TOP OF THE LOUNSBURY LOWEST HORIZONTAL FLANGE ON THE WELL. & ASSOCIATES, INC. SURVEYORS ENGINEERS PLANNERS 0 '% PHONE: (9071272-5451 AREA: MODULE: UNIT: ConocoPhillips NORTH COOK INLET TYONEK PLATFORM Alaska, Inc. WELL CONDUCTOR AS BUILT CADD FILE NO. DRAWING NO: PART: =3 08 -005 AS BUILT 02/27/08 08 -005 AS BUILT 3 of e e ;("~., '~..!¡", . MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LascrFicbe\CvrPgs _ Inserts\Microfihn _ Marker. doc .,,-., ¡;:::--" r;' lí.---; ~""""'-ó f(Ù it' ¡A\r¡¡ ¡fp'\ Ir" \",- ,I (1\\ 1''--. 'Ii. ,L, '\.\ I' fw. ¡ ir' "I. Ir' Q¿) U 1.1"\1 U Lh IJ¿) lJ ~..-; ,--,~, _I"> r} ,--, f i \ ¡ ~ ¡ i \ i nJ If! j ¡¡ \ , í't \ ! i ; '\ ì ~ \ 'r I ' f\ ì. ¡'\i [1 ¡¡Ii '\:- !~\ ilJ' L~J I L, L~ c0 ~\i ¿~~-~ A.I~A.SIiA. OIL AND GAS CONSERVATION COMMISSION October 20, 2004 Wade Gilpin Alaska Dept. of Environmental Conservation 555 Cordova St., 2nd Floor Anchorage, AK 99501 Re: North Cook Inlet Platform ConocoPhillips Alaska, Inc. Tyonek Deep Well Abandonments Dear Mr. Gilpen: /97- ;?-It' FRANK H. MURKOWSKI, GOVERNOR 333 W. 7TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 This letter is in response to your inquiry regarding the plugging of the "deep" oil wells drilled from ConocoPhillips' North Cook Inlet or Tyonek Platform in Cook Inlet. Your message asked if the abandonments were in accord with 20 AAC 25.105. 25.105 is applicable when all operations on a property are completed which is not the case here. Specific well plugging operations must be in accord with 20 AAC 25.112. During the 1990s a total of 4 exploration wells were drilled from the platform to determine if developable oil reserves were present. Oil was encountered in the deep formations below 12,000', however it was determined to be non-commercial. The deep intervals of these wells were subsequently plugged and abandoned and shallower gas intervals completed and placed into production. I have reviewed the information contained in the files for the respective wells. The deep intervals of NCIU A-13 (formerly Sunfish #2) were abandoned in late 1993 as part of the original work program. An AOGCC Inspector did not witness the plugging operations. Based on my review of the file, the work performed conforms to the requirements of20 AAC 25.112. The deep intervals in the remaining wells, B-OIA, B-02 and B-03, were plugged and abandoned in late 2002. An AOGCC Inspector did witness weight "tags" and pressures tests to verify the competence of the plugs on each well subsequent to the cementing operations. These verifications were in accord with 20 AAC 25.112 (g)(1) and (2) and the Inspector reported that the plugs were satisfactorily verified. SCANNED OCT 2 7 2004 Wade Gilpin October 20,2004 Page 2 of2 Based on my review of the infonnation contained in the AOGCC's wells files, I confinn that any potential oil intervals penetrated by the 4 "deep" exploration wells were satisfactorily plugged and abandoned in compliance with AOGCC regulation 20 AAC 25.112. Please feel free to contact me with any questions. Sincerely, ,A-~ ~ '- Thomas E. Maunder, PE ~ Sr. Petroleum Engineer cc: We]] file: NClli A-13 PTD 192-106 NCIU B-OIA PTD 198-002 NCIU B-02 PTD 197-210 NClli B-03 PTD 198-059 Field file: North Cook Inlet Unit OCT 2 72004 IŒ: Tyonek Platfonn ?'s Subject: RE: Tyonek Platform ?'s From: "Gilpin, Wade" <Wade - Gilpin@dec.state.ak.us> Date: Fri, 08 Oct 200408:28:29 -0800 To: 'Thomas Maunder' <tom - maunder@admin.state.ak.us> Thanks Tom- Here is my snail mail address: Alaska Dept. of Environmental Conservation Attn: Wade Gilpin 555 Cordova St., 2nd Floor Anchorage, AK 99501 tks wg -----Original Message----- From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Friday, October 08, 20047:30 AM To: Gilpin, Wade Subject: Re: Tyonek Platform ?'s Hi Wade, Sorry not to get back to you sooner. so we can send the letter. Thanks, Tom Maunder, PE Could you please provide me with your snail mail address Gilpin, Wade wrote: HI Tom - I have been working this issue with our FR (Financial Responsibility) folks here. For them to lift the FR requirement for Tyonek (and for us to rescind the C-plan), they need confirmation in writing that all wells were plugged/abandoned iaw 20 AAC 25.105. Can you possibly provide us letter related to this? Thanks Wade -----Original Message----- From: Thomas Maunder [mailto:tommaunder@admin.state.ak.us] Sent: Thursday, September 16, 2004 7:54 AM To: Gilpin, Wade Cc: John D Hartz Subject: Re: Tyonek Platform ?'s Wade, Based on your reply, you are indeed concerned about the "B" or deep wells that were drilled in 1997 - 1998. I have checked our records with regard to the 3 wells. The deeper intervals are plugged in accord with our SCANNED OCT 2 7 2004 1 of3 10/8/2004 10:18 AM RE: Tyonek Platform ?'s 20f3 regulations. I do not have any concern about potential oil leakage. Tom Maunder, PE AOGCC Gilpin, Wade wrote: Thanks Tom - Sounds like I got this all wrong I'm quite the novice. Honestly, I don't know the difference between the B and Deep wells. We are concerned in any of the wells that had perforations into potential oil bearing zones. What I meant was concerns about the mechanical integrity of the well bore (after P&A), and the lack of oil leakage from the plugged perforations. Mostly, I need to confirm that you guys don't have any concerns about potential oil leakage. Thanks Wade -----Original Message----- From: Thomas Maunder rmailto:tom maunder@admin.state.ak.us] Sent: Tuesday, September 14, 2004 12:51 PM To: Gilpin, Wade Cc: John D Hartz Subject: Re: Tyonek Platform ?'s Wade, Are you talking of the "B or deep" wells. As I remember, we did have an Inspector witness the verifications of the plugging activities. CP AI's intent was to convert or re-equip the wells as gas wells from the shallower formations. What do you mean by "structural concerns"?? Tom Maunder, PE AOGCC Gilpin, Wade wrote: Hi Tom - I talked with Jack Hartz about this at the end of last week and he mentioned that you are who I should be talking to about Tyonek. I have been talking with Steve Geddes of CPA lately and CPA is interested in deactivating thier C-plan since they are only involved gas production. My questions to you are: Did you guys witness theP&A for the well(s)? If so, was everything done satisfactorily? Do you have any structural integrity concerns? I am just looking to make sure they have covered everything to your satisfaction as well as follow our regs/guideliens for deactivation. SCANNED OCT 2 7 2004 10/8/200410:18 AM ,j'E: Tyonek Platform ?'s ..... t'. .... Thanks for you help! Wade Gilpin Environmental Specialist Industry Preparedness Program Alaska Dept of Environmental Conservation 555 Cordova St. Anchorage AK 99516 (907) 269-3060 wade Çtilpin(éV,dec.state.ak.us 30f3 SCANNED OCT 2 7 2004 10/8/2004 10: 18 AM RE: Tyonek Platform ?'s - Subject: RE: Tyonek Platform 1's From: "Gilpin, Wade" <Wade_Gilpin@dec.state.ak.us> Date: Thu, 16 Sep 2004 08:15:16 -0800 To: 'Thomas Maunder' <tom_maunder@admin.state.ak.us> Thanks Tom. ~C\Ù ß-~ +C J d- i D \ \ -----Original Message----- l q 1... ?- I 0 From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Thursday, September 16, 2004 7:54 AM To: Gilpin, Wade Cc: John D Hartz Subject: Re: Tyonek Platform ?'s Wade Wade, Based on your reply, you are indeed concerned about the "B" or deep wells that were drilled in 1997 - 1998. I have checked our records with regard to the 3 wells. The deeper intervals are plugged in accord with our regulations. I do not have any concern about potential oil leakage. Tom Maunder, PE AOGCC Gilpin, Wade wrote: Thanks Tom - Sounds like I got this all wrong I'm quite the novice. Honestly, I don't know the difference between the B and Deep wells. We are concerned in any of the wells that had perforations into potential oil bearing zones. What I meant was concerns about the mechanical integrity of the well bore (after P&A), and the lack of oil leakage from the plugged perforations. Mostly, I need to confirm that you guys don't have any concerns about potential oil leakage. Thanks Wade -----Original Message----- SCANNED OCT {} 2 200~ From: Thomas Maunder rmailto:tom maunder@admin.state.ak.us] Sent: Tuesday, September 14, 2004 12:51 PM To: Gilpin, Wade Cc: John D Hartz Subject: Re: Tyonek Platform ?'s Wade, Are you talking of the "B or deep" wells. As I remember, we did have an Inspector witness the verifications of the plugging activities. CP AI's intent was to convert or fe-equip the wells as gas wells from the shallower formations. What do you mean by "structural concerns"?? lof2 9/16/20048:18 AM RE: Tyonek Platform ?'s .~ .' 2 of2 Tom Maunder, PE AOGCC Gilpin, Wade wrote: Hi Tom -I talked with Jack Hartz about this at the end of last week and he mentioned that you are who I should be talking to about Tyonek. I have been talking with Steve Geddes of CPA lately and CPA is interested in deactivating thier C-plan since they are only involved gas production. My questions to you are: Did you guys witness the P&A for the well(s)? If so, was everything done satisfactorily? Do you have any structural integrity concerns? I am just looking to make sure they have covered everything to your satisfaction as well as follow our regs/guideliens for deactivation. Thanks for you help! Wade Gilpin Environmental Specialist Industry Preparedness Program Alaska Dept of Environmental Conservation 555 Cordova St. Anchorage AK 99516 (907) 269-3060 wade qilpin@dec.state.ak.us 9/16/20048:18 AM PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 July 19, 2001 Mr. Thomas Maunder, Petroleum Engineer State of Alaska, Oil and Gas Conservation Commission 333 W. 7th Avenue, #100 Anchorage, Alaska 99501-3539 JUL ?- 5 ?_001 Alaska 0il & Gas c~ns. comm~¢O~ AnchOrage Subject: Tyonek Deep Wells B-lA and B-2 Dear Mr. Maunder: This letter is to follow up on the recent telephone conversations that we have had with you and other AOGCC staff, regarding the status and classifications for the Tyonek Deep wells B-lA and B-2. Phillips Alaska requested that the classifications of these wells be changed from "1-oi1" to "suspended", in a letter to the AOGCC on May 15, 2001. AOGCC's most recent input to Phillips is that the well classifications could be changed to "shut-in" in their present physical condition. This letter is to request that the classification of the Tyonek Deep Wells B-lA and B-2 be changed to "shut-in". The physical condition and status of the Tyonek Deep wells B-lA and B-2 are as follows: Well B-lA (sidetrack) Physical Condition: The well was perforated and tested. A completion report was filed 1/28/99. The well is shut in. No flow line is installed. The wing valve is closed with a blind flange installed. A SSSV is installed at 430'MD. The SSSV is closed and the control line is not connected to a control panel. Therefore, the valve cannot be opened without hooking up a hydraulic pump and manually pumping the valve open. Attachment 1 shows the wing valve with no flow line attached. Attachment 2 shows that the control line is not connected. Attachment 3 is a completion diagram. LSCANNED DEC 1 9 2005 July 19, 2001 Mr. T. Maunder, AOGCC Re: Tyonek Deep Wells B-lA and B-2 Page 2 Current Status: The current AOGCC status is "l-oil". Phillips Alaska requests that the status be modified to "shut-in". Well B-2 Physical Condition: The well was completed as a dual well. The well was perforated and tested. A completion report was filed 4/1/98. The well is shut in. No flow lines are installed. The wing valves are closed with blind flanges installed. SSSVs are installed in both tubing strings. The SSSVs are closed and neither control line is connected to a control panel. Therefore, the valves cannot be opened without hooking up a hydraulic pump and manually pumping the valves open. Attachment 4 shows the long string wing valve with no flow line attached. Attachment 5 shows the short string wing Valve with no flow line attached. Attachment 6 shows that the short string control line is not connected. Attachment 7 shows that the long string control line is not connected. Attachment 8 is a completion diagram. Current Status: The current AOGCC status is "l-oil". Phillips Alaska requests that the status be modified to "shut-in". The Tyonek Platform is not equipped to produce and process oil. The platform lacks flow lines to the wells, three-phase separation equipment, heater treaters, and oil pumps. Phillips Alaska has no plans to install oil-producing equipment for any of the Tyonek Deep wells. Please contact me with any questions at 265-6711. Sincerely, // Safety Engineer ,SCANNED DEC i 9 2002 gc/dt/djn ATTACHMENT 1 B-lA Wing Valve No Flow Line Attached ATTACHMENT 2 B-lA Control Line Control Line Is Not Connected NCIU B-1 SIDETRACK COMPLETION DIAGRAM ~sssv @ 4~ Mo {43~ TVO) J [20' ~ 2579' MO (2571' TVD) 2-3/8' injectien ~tring~ for [13-3/8' ~ 3760' MD (3521' TVD)~I P-110 _P~KR ~ 10,074' MD (8598' 'rVD) I 19-5/~' @ 10,376' MD {8846' 'I"VD~t ~ $-135 Drill Pipe with "G' Tool Joints (Min ID: 3.25'~i IN. FOREL~ NDS PERF$ ~ 16,080' - 16.118' MD ICMT IN DP ~ 16,590' MD ~-'DP ~ 16,650'.MD ATTACHMENT 4 B-2 Long String Wing Valve No Flow Line Attached ATTACHMENT 5 B-2 Short String Wing Valve No Flow Line Attached A1-TACI-~ ~ E ~T' 3' ATTACHMENT 6 B-2 Short String Control Line Control Line Is Not Connected ATTACHMENT 7 B-2 Long String Control Line Control Line Is Not Connected A TT qC Liner To~ P~:ker .Sunfish 13110.13170' 13652-13686' 1371~-13736' 13818-13856' 13g01o13920' 13944-13966' PRESENT COMPLETION NOl AppllGlbk ~M KKLIHF: KKLMSL: gtJQ ~ f~(,/ TOC: PPCk Ab,,,mbk N4G. P. I I 0 47,30 f-I IO 1920 LII0 il60 f. IO} I UMw I~up 133~'O #o~ TO(:: O 10.088' CeldKier I 1,1 ~1 2nd Stilt DY ~ { 731J' · 3~d Sla~ DY ~ ~ 98/1" I/2' CEMENTING SUMMARY Ca will, O= 12JIl~ld Cbu'G'whh 1.0% I)-6. plm 0.03 li~ D-47 'i*ikd e '/00 n O~ 'G' ~ IJ.I Ilqd 0.05 Id~n DM7. 0.~ D.~9. 0.15 plan D401.0.4% D.65. 0.10% D- 1 34. Md 0.2~% S-I. Cemflled e 37(X) p 15.1 II,ii Cb. 'O' via 0.10 % D-63. I)lm 0.1 pi/n DMT. 0.1% D-IJL 1.0 jl~fl D.(~)0. Ind 0.3% D-10Q 0. I ll/a DM7. 0.1% D-133.1.0 pi/n D-MX). Md 0.3% D-101. Canmud .~h ~OOn 15.1 bli Chu'G' TOC m IO.NF 0.13~M/n Hdad344L.0.25% HR-J O toT3r 11086 7'O 13J3~ PBTD · 14.377' 31~'O 1d.4~?' 'rD · 14537' Upaaled ~ 0.00 53JI 5~JI 317.17 341.17 4~2,~.11 4333.29 5911 J0 .q9117-1 704~39 7041.14 1114.19 1190.~? 9J03.12 10290.13 103L1.34 I0~1.t.~ 10~2.1.?1 106U.21 SHORT STroNG TUBING S3~ EMvabon 0.93 TWng H~nge 2UJ6 2 7~ 6.S M L~ ~ ~ T~ 29~.~ 2 7~ 6~ ~ L~ ~ ~ T~ 6.48 27~~~ L43 27~C0~ ~ 1134.16 27~ ~L~~T~ 6.45 27~0~~ 6.48 2 7~ ~ ~s ~ ~ I 112.4J 27~ 6.~ ~0., 27~ 6.SML~~T~ PU~u: 14.377' Well: 6.44 2 7/8' CA.W:O Gas UR Mandrel 396.?.~ 27/9' 6.~II~L.OOCSHy0dlTuI~ng 12.05 27~ 6.S~L~~T~ ' 1.14 HES 10.12 1.43 HES 0.74 ~ LONG ~ ~mNG 53.58 0.93 T~ M.51 365.~ 3 1~ 12.95~ L~ ~ T~ 420.41[10 3 4395.45 ~14.95 31~12.g5~L~T~ ~?.01 6.~ 3 ~?3JI 12M~ 3 t~ 12.~ ~ L~ ~ T~' flu.31 I I~.M 3 10]S2.0~ 6.# 3 2~.47 3 1~ 12.~ ~ L~ ~ T~ I~ w~: N~k CNk bkl UMI 'B' NL 2 (lem~ him Ne. 3~ ' NSH Tyonek C-Plan ADEC Comments Subject: Tyonek C-Plan ADEC Comments Date: Wed, 1 Aug 2001 11:10:06-0800 From: "Don P Turner'' <dptume@ppco.com> To: tom_maunder@admin.state.ak, us Per our conversation of this morning. Let me know (265-6056) or Gordon Caughman know (265-6711) of any news. Thank you. m_ Forwarded by Don P Turner/PPCO on 08/01/0.1 11:13 AM ---~ Gordon R Caughman 08101101 10:09 AM To: Steve Flndlay/PPCO@Phillips, David W HansonlPPCO@Phillips, Michael J NelsonlPPCO~lPhillips, Don P TumerlPPCO~Phillips, Ryan P Deines/PPCO~Phillips, C Lindsey ClarldPPCO~Phillips, Steven F ArbelovskyiPhillips Petroleum/us(~Phillips, Bob D HalelPPCO@Phillips, Leonard G Janson Jr/PPCO(~Phillips, J Scott Jepsen/PPCO@Phillips, Randal Buckendorf/PPCO@Phillips cc: Subject: Tyonek C-Plan ADEC Comments As you recall, we have been attempting to drop the Tyonek C-plan because the platform is a gas production facility and does not produce oil. ADEC has not concurred that the C-plan can be dropped because the Tyonek Deep wells B-lA and B-2 are perforated and completed in an oil bearing formation. Originally, we understood ADEC's concern to be that B-lA and B-2 are classif~J as "oil wells" on the AOGCC completion reports. We talked to AOGCC and sent a letter requesting reclassification of the wells from "oil" to "shut-in" since the wells have a) surface and subsurface safety valves closed, b) no flowlines connected to the wellheads and are c) incapable of being produced. Tom Maunder of AOGCC has transmitted our letter to Robert Watkins of ADEC. Robert called and indicated ADEC's currant primary concern is the "capability of the oil wells to flow to surface." Evidently, even though the wells are mechanically secured, ADEC is concerned that the wells do not have cement plugs, or kill weight fluid in the well bores / tubing strings. Robert indicated that he will review the subject with Susan Harvey and will respond back to me with their recommendations. However, it does appear that we will either have to install cement plugs or kill weight fluid to satisfy ADEC that Tyonek is incapable of flowing oil to surface. I will advise you of ADEC's official response when received. Gordon R. Caughman Phillips Alaska, Inc. 700 G St, Anchorage, AK 99510 - 0360 Phone: 907-265-6711 I of 1 8/1/01 11:46 AM PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 A. Worthington Phone (907) 265-6802 Fax: (907) 265-6224 October 16, 2002 Commissioner Cammy Oechsli Taylor State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Report of Sundry Well Operations NC1U B-02 (197-210 / 302-234) Dear Commissioner: Phillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent operations on the Tyonek well NCIU B-02. If there are any questions, please contact me at 907-265-6802. Sincerely, A. Worthington Wells Engineer Phillips Alaska Inc. AW/skad DUPLICATE RE£EIVED OCT 17 2002 Alas~ oitaGas~e,(~mn~ Anchorage STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_ Stimulate_ Plugging _ Perforate _ Pull tubing _ Alter casing _ Repair well _ Other _XX P&A 2. Name of Operator 5. Type of Well: 6. Datum elevation (DF or KB feet) Phillips Alaska, Inc. Development__X RKB 132 feet 3. Address Exploratory__ 7. Unit or Property name P. O. Box 100360 Stratigraphic__ Anchora~le, AK 99510-0360 Service__ North Cook Inlet 4. Location of well at surface 8. Well number 1249' FNL, 980' FWL Sec. 6 T11N, R9W NCIU B-2 At top of productive interval 9. Permit number / approval number 1404' FSL, 536' FWL, Sec. 31, T12N, R9W 197-210/302-234 At effective depth 10. APl number 50-883-20090-01 At total depth 11. Field / Pool 838' FSL, 653' FWL, Sec 31, T12N, R9W North Cook Inlet Field Development 12. Present well condition summary Total depth: measured 14537 feet Plugs (measured) Cement plug top @ 12054' true vertical 13377 feet Effective depth: measured 12054 feet Junk (measured) true vertical 11115 feet Casing Length Size Cemented Measured Depth True vertical Depth Structural 368' 30" Ddven 368' 368' Conductor 2543' 20" lO7O sx Class G, 600 sx Class G 2602' 2535' Surface 8849' 13-3/8" 6300 sx C~ass G 8909' 8123' Intermediate 12080' 9-5/8" 500 sx Class G 11086' 10244' Liner 2788' 7" 1310 sx Class G 13522' 12460' Liner 3.5" (included above) 14457' 13305' Perforation depth: measured 13110'- 13170', 13652'- 13686', 13718'- 13736', 13818'- 13856', 13901'- 13920', 13944'- 13966' true vertical 12084'- 12139', 12579'- 12610', 12639'- 12656', 12730' - 12765', 12806'- 12823', 12845' - 12864' Tubing (size, grade, and measured depth) Short String: 2-718", 6.5#, L-80 CS to 10625' md Long Stdng: 3-1/2", 12.95#, L-80, PH-6 to 13630' md Packers & SSSV (type & measured depth) Halliburton RDH Dual Pkr @ 10593' md OCT_ 1_ 7 2002 Halliburton TRSVs at 338' (short string) and 420' (long stdng) 13. Stimulation or cement squeeze summaryOil& Gas gOns. Commission Intervals treated (measured) see attachment anchorage Treatment description including volumes used and final pressure 14. Representative Daily Averaqe Production or Iniection Data OiI-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation N/A Subsequent to operation N/A 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations ._X Oil __ Gas __ Suspended _ Service _Water Injector 17. I hereby certify that the foregoing is ~j;ae and correct to the best of my knowledge. Questions? Cai/Aras Worthington 265-6802 Signed ,,,'~ ~'~~f Title: Wells Engineer Date ~'Z~/~'///~ Aras Worthington Prepared b)/ Sharon AIIsup-Drake (263-4612~ Form 10-404 Rev 06/15/88 · DUPLICATE SUBMIT IN DUPLICATE Date Comment NCI B-2 Event History 09/18/02 09/25/02 09/26/02 09/29/02 09/29/02 10/07/02 MADE DUMMY GUN RUN TO 13521' ON LONG STRING. RAN 2', 2" 6 SPF, 60 DEG PHASED HES TCP GUNS ON PRESSURE ACTUATED FIRING HEAD W/DUAL 6 MINUTE DELAY TIMERS (8 SHOTS TOTAL) - PARKED GUNS AT 13140' - 13142' WLM. PRESSURED UP AND FIRED GUNS, GOOD INDICATIONS AT SURFACE THAT GUNS FIRED. PRESSURE INCREASED FROM 1000 PSI TO 1800 PSI - WELL READY FOR CEMENT PLUG AND ABANDON. TEST BOPS TO 4200 PSI. CIRCULATE 300 BBL DRILL WATER DOWN 2-7/8" STRING W/RETURNS UP 3.5" STRING, FINAL PRESSURES 900 PSI ON BOTH STRINGS. RIH W/CMT NOZZLE, CANNOT PASS GLM #3. POOH AND CHANGE BHA, RUN BACK INTO HOLE TO 12,000 FT CTMD. PUMP 29 BBLS OF 15.8 PPG CLASS G CEMENT AND POOH, FILLING COIL VOID SPACE WITH FRESHWATER. PUT 3-1/2" AND 2- 7/8" TUBING IN COMMUNICATION (850 PSI). WAIT ON CEMENT. WAIT ON CEMENT. FREEZE PROTECT 3-1/2" TUBING TO 500' W/DIESEL. ROTATE TREE CAP FLANGE FOR ENTRY INTO 2-7/8" TUBING - P/T AND RIH TO 500' - LAY IN DIESEL AT ONE FOR ONE TO FREEZE PROTECT SHORT STRING - BOTH LONG AND SHORT STRING FREEZE PROTECTED. TAG XN NIPPLE IN SHORT STRING @ 10154' - TBG CLEAR OF CEMENT - SWAP TOP FLANGE TO LONG STRING - TAG CEMENT TOP @ 12054' WLM IN LONG STRING - WELL PLUG AND ABANDONED - WAITING ON AOGCC WITNESS FOR DRAWDOWN AND PRESSURE TEST OF TBG'S AND CSG'S. PRESSURE TEST SHORT STRING (2-7/8") AND LONG STRING (3-1/2") TO 2500 PSI FOR 15 MIN. PASSED TEST. BLED PRESSURE TO 0 AND HELD FOR 15 MIN. PASSED AOGCC REQUIRED PRESSURE AND DRAWDOWN PRE-TEST. READY FOR STATE WITNESS. BLED IA FROM 150 --> 0 PSI, RECOVERED 4 GAL FLUID (GAUGE SHOWING 50 PSI). BLED OA FROM 100 --> 0 PSI, RECOVERED 16 GAL FLUID. Page I of I 10/16/2002 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_ Stimulate_ Plugging_ Perforate _ Pull tubing _ Alter casing _ Repair well _ Other _XX P&A 2. Name of Operator 5. Type of Well: 6. Datum elevation (DF or KB feet) Phillips Alaska, Inc. Development__X RKB 132 feet 3. Address Exploratory__ 7. Unit or Property name P. O. Box 100360 Stratigraphic__ Anchorage, AK 99510-0360 Service__ North Cook Inlet 4. Location of well at surface 8. Well number 1249' FNL, 980' FWL Sec. 6 T11N, R9W NCIU B-2 At top of productive interval 9. Permit number / approval number 1404' FSL, 536' FWL, Sec. 31, T12N, R9W 197-210 / 302-234 At effective depth 10. APl number 50-883-20090-01 At total depth 11. Field / Pool 838' FSL, 653' FWL, Sec 31, T12N, R9W North Cook Inlet Field Development 12. Present well condition summary Total depth: measured 14537 feet Plugs (measured) Cement plug top @ 12054' true vertical 13377 feet Effective depth: measured 12054 feet Junk (measured) true vertical 11115 feet Casing Length Size Cemented Measured Depth True vertical Depth Structural 368' 30" Driven 368' 368' Conductor 2543' 20" lO7O sx Class G, 600 sx Class G 2602' 2535' Surface 8849' 13-3/8" 6300 sx Class G 8909' 8123' Intermediate 12080' 9-5/8" 500 sx Class G 11086' 10244' Liner 2788' 7" 1310 sx Class G 13522' 12460' Liner 3.5" (included above) 14457' 13305' Perforation depth: measured 13110'- 13170', 13652'- 13686', 13718'- 13736', 13818'- 13856', 13901'- 13920', 13944'- 13966' true vertical 12084'- 12139', 12579'- 12610', 12639'- 12656', 12730'- 12765', 12806'- 12823', 12845'- 12864' Tubing (size, grade, and measured depth) Short Stdng: 2-7~8", 6.5~, L-80 CS to 10625' md Long Stdng: 3-1/2', 12.95#, L-80, PH-6 to 13630' md Packers & SSSV (type & measured depth) Halliburton RDH Dual Pkr @ 10593' md Halliburton TRSVs at 338' (short stdng) and 420' (long stdng) 13. Stimulation or cement squeeze summary OCT Intervals treated (measured) see attachment Treatment description including volumes used and final pressure ,~l~l~ka 0~t& (~1~ 14. Representative Daily Avera.qe Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation N/A Subsequent to operation N/A 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations __X Oil __ Gas __ Suspended __ Service _Water Injector 17. I hereby certify that t~d correct to the best of my knowledge. Questions? CallAras Worthington 265-6802 Signed ~:~~' Title: Wells Engineer Date~'~,/~'~'/~°~'~ Aras Worthington Prepared b)/ Sharon AIIsup-Drake (263-4612) Form 10-404 Rev 06/15/88 · RBDNS BFL NOV £ 0 2002 SUBMIT IN DUPLICATE Date Comment NCI B-2 Event History 09/18/02 09/25/02 09/26/02 O9/29/02 O9/29/O2 10/07/02 MADE DUMMY GUN RUN TO 13521' ON LONG STRING. RAN 2', 2" 6 SPF, 60 DEG PHASED HES TCP GUNS ON PRESSURE ACTUATED FIRING HEAD W/DUAL 6 MINUTE DELAY TIMERS (8 SHOTS TOTAL) - PARKED GUNS AT 13140' - 13142' WLM. PRESSURED UP AND FIRED GUNS, GOOD INDICATIONS AT SURFACE THAT GUNS FIRED. PRESSURE INCREASED FROM 1000 PSI TO 1800 PSI - WELL READY FOR CEMENT PLUG AND ABANDON. TEST BOPS TO 4200 PSI. CIRCULATE 300 BBL DRILL WATER DOWN 2-7/8" STRING W/RETURNS UP 3.5" STRING, FINAL PRESSURES 900 PSI ON BOTH STRINGS. RIH W/CMT NOZZLE, CANNOT PASS GLM #3. POOH AND CHANGE BHA, RUN BACK INTO HOLE TO 12,000 FT CTMD. PUMP 29 BBLS OF 15.8 PPG CLASS G CEMENT AND POOH, FILLING COIL VOID SPACE WITH FRESHWATER. PUT 3-1/2" AND 2- 7/8" TUBING IN COMMUNICATION (850 PSI). WAIT ON CEMENT. WAIT ON CEMENT. FREEZE PROTECT 3-1/2" TUBING TO 500' W/DIESEL. ROTATE TREE CAP FLANGE FOR ENTRY INTO 2-7/8" TUBING - P/T AND RIH TO 500' - LAY IN DIESEL AT ONE FOR ONE TO FREEZE PROTECT SHORT STRING - BOTH LONG AND SHORT STRING FREEZE PROTECTED. TAG XN NIPPLE IN SHORT STRING @ 10154' - TBG CLEAR OF CEMENT - SWAP TOP FLANGE TO LONG STRING - TAG CEMENT TOP @ 12054' WLM IN LONG STRING - WELL PLUG AND ABANDONED - WAITING ON AOGCC WITNESS FOR DRAWDOWN AND PRESSURE TEST OF TBG'S AND CSG'S. PRESSURE TEST SHORT STRING (2-7/8") AND LONG STRING (3-1/2") TO 2500 PSI FOR 15 MIN. PASSED TEST. BLED PRESSURE TO 0 AND HELD FOR 15 MIN. PASSED AOGCC REQUIRED PRESSURE AND DRAWDOWN PRE-TEST. READY FOR STATE WITNESS. BLED IA FROM 150 --> 0 PSI, RECOVERED 4 GAL FLUID (GAUGE SHOWING 50 PSI). BLED OA FROM 100 --> 0 PSI, RECOVERED 16 GAL FLUID. Page I of I 10/16/2002 PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 A. Worthington Phone (907) 265-6802 Fax: (907) 265-6224 October 16, 2002 Commissioner Cammy Oechsli Taylor State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Report of Sundry Well Operations NCIU B-02 (197-210 / 302-234) Dear Commissioner: Phillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent operations on the Tyonek well NC1U B-02. If there are any questions, please contact me at 907-265-6802. Sincerely, A. Worthington Wells Engineer Phillips Alaska Inc. AW/skad RECEIVED OCT ~ ? ~2 An~homge STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown_ Stimulate_ Plugging _ Perforate_ Pull tubing _ Alter casing _ Repair well _ Other_XX Set Plug, dump cement 2. Name of Operator 5. Type of Well: 6. Datum elevation (DF or KB feet) Phillips Alaska, Inc. Development__X RKB 132 feet 3. Address Exploratory__ 7. Unit or Property name P. O. Box 100360 Stratigraphic__ Anchorage, AK 99510-0360 Service North Cook Inlet 4. Location of well at surface 8. Well number 1249' FNL, 980' FWL Sec. 6 T11N, R9W NCIU B-2 At top of productive interval 9. Permit number / approval number 1404' FSL, 536' FWL, Sec. 31, T12N, R9W 197-210 / 301-321 At effective depth 10. APl number 50-883-20090-01 At total depth 11. Field / Pool 838' FSL, 653' FWL, Sec 31, T12N, R9W North Cook Inlet Field Development 12. Present well condition summary Total depth: measured 14537 feet Plugs (measured) true vertical 13377 feet Effective depth: measured 13583 feet Junk (measured) true vertical 12516 feet Casing Length Size Cemented Measured Depth True vertical Depth Structural 368' 30" Driven 368' 368' Conductor 2543' 20" 1070 sx Class G, 600 sx Class G 2602' 2535' Surface 8849' 13-3/8" 6300 sx Class G 8909' 8123' Intermediate 12080' 9-5/8" 500 sx Class G 11086' 10244' Liner 2788' 7" 131o sx C~ass G 13522' 12460' Liner 3.5" (included above) 14457' 13305' Perforation depth: measured 13110'- 13170', 13652'- 13686', 13718' - 13736', 13818'- 13856', 13901'- 13920', 13944'- 13966' true vertical 12084'- 12139', 12579'- 12610', 12639'- 12656', 12730'- 12765', 12806'- 12823', 12845'- 12864' Tubing (size, grade, and measured depth) Short Stdng: 2-7/8", 6.5#, L-80 CS to 10625' md Long Stdng: 3-1/2", 12.95#, L-80, PH-6 to 13630' md Packers & SSSV (type & measured depth) Hallibudon RDH Dual Pkr @ 10593' md Halliburton TRSVs at 338' (short string) and 420' (Iong stdng) ,JUL 2 2002 13. Stimulation or cement squeeze summary AJask~a 0JJ ~ Gas Coti$. Cot~missio~ Intervals treated (measured) see attachment Anchorage Treatment description including volumes used and final pressure 14. Representative Daily Averaqe Production or Iniection Data OiI-Bbl Gas-Mcr Water-Bbl Casing Pressure Tubing Pressure Prior to well operation N/A Subsequent to operation N/A 15. Attachments Copies of Logs and Surveys run __ Daily Report of Well Operations __X Oil x~ Gas __ Suspended __ Service _' 17. J hereby certify that the foregoing'~,,,,"-~c,~,~ is t~y~he best of my knowledge. Ouestions?CallLenJanson(907) 776o2046 /~ Signed ,~ Title: Sr. Operations/Reservoir Engineer Date dX' .,,2,_ Brian Seitz Prepared by Sharon AIIsup-Drake (263-4612) & Brian Seitz (265-6961) Form 10-404 Rev 06/15/88 · SUBMIT IN DUPLICATE Date Comment NCI B-02 Event History 11/13/01 11/14/01 11/18/01 11/18/01 11/19/01 11/27/01 11/30/01 Pressure up SSSV control line to 5000 psi. Pump 15 gal methanol to increase WHP from zero to 2800 psi - max pressure of pump. Injectivity not confirmed, will need to RU Dowell pump. Pump 10 bbl diesel into well at 1.7 bpm. Initial pump pressure 3500 psi, final pump pressure 4900 psi. Confirm no shallow ice plug, but well is tight. Pump 5 bbl diesel/meth spear, 184 bbl 9.8 ppg CaCI2 w/3% KCl, 2 bbl diesel cap. Average rate/pressure 2.5 bpm, 6000 psi. Pressure fell off during overflush, final pump pressure 4500 psi. Locate top of wire @ 10330' SLM. In progress. Recovered 247' of .125 wire & 24' toolstring w/2.5" X-line running tool. In progress. Pumped 10 bbls diesel with 100 bbl 3% KCI water and 10 bbls diesel freeze protect @ 2 bpm and 6500 psi - unable to open.manual master fully (8 of 18 turns) - may be pressure locked Completed fishing operations - pulled gauges and plug - ran PXN 2.313" to XN nipple - P/T tubing to 2500 psi for 30 min. - drawdown well to 0 psi - held 30 min. - short string lower perfs plugged - short string temp. abandoned. 'Ddft tbg 2.25' x 5', encountered minor hydrates 2500'-3400', tagged @ 13895' MD. Pumped 25 bbl diesel, drift tbg 2.25" x 5' to 5000', no problem. Drift / taq tbg 12/03/01 12/04/01 12/05/01 Set magna range bridge plug @ 13625' MD below seals and above top perforations. Rig up magna range and RIH to 300 ft. - unable to maintain grease seal - pooh and rdfn Bleed well off from 5400 psi to 2500 psi to test plug - good 30 minutes - dump bail cement on top of plug (9' total class G cement on top of plug) Dump bail 18' of 15# class G cement on top of magna-range bridge plug @ 13625' Dump bail 15# class G cement on top of bridge plug - 27' total cement on bridge plug - bleed down long string to 1000 psi and annulus to 425 psi - left SSSV open to monitor tubing pressure - well short string and long string temporarily abandoned. Page I of I 2/22/2002 P ILLIPS Alaska, Inc. . .,"...~ubsidiary of PHILLIPS PETROLEUM COMPANY NCIU B-2 BPV (Mke, Type, OD) Tbg Hr (Make, Type) Annulus Fluid: TOC: Casing Strings 20" Conductor 11/25/93 13 3/8" 1st Stage Not Applicable RKB-THF: Not Applicable RKB-BHF 59.00 RKB-MSL: 132.00 Water Depth: 130.00 :GRADE . CONN. BURST CO# TRO PPCO Allowable Ratings 547 Ibs/ft WELD 169 Ibs/ft X-56 DnI-Quip 1700 72 Ibs/ft N-80:P-110 BT&C 761 52.5 I bs/Ft P-110 BT&C 1159 CEMENTING SUMMARY Cement with 1070 sx Class "G" w/0.25 gal/sx D-77. 0.05 gal/sx D-47 & 0.28 gal/sx D-75. Tailed with 600 sx Class "G" mixed @ 15.8 lb/gal with 0.25 gal D-77 & 0.05 gal/sx D-47 Cement circulated to Surface. 2nd Stage DMY Tool @ 7385' 3rd Stage DMY Tool @ 4045 9 5/8" 7" & 3.5" Cemented with 900 sx 12.5 lb/gal Class "G" with 1.0^ D-6 plus 0.05 gal/sx D-47. Tailed with 700 sx Class "G" @ 15.8 lb/gal with 0.05 gal/sx D-47, 0.5% D-59, 0.15 gal/sx D-801,0.4% D-65, 0.1% D-134 and 0.25% S-1. Cemented with 3700 sx 18.6 lb/gal Class "G" with 0.10% D-65, plus 0.1 gal/sx D-47, 0.1% D-135, 1.0 gal/sx D-600, and 0.3% D-800. Cemented with 1000 sx 15.8 lb/gal Class "G" with 0.20% D-65, plus 0.1 gal/sx D-47, 0.1% D-135, 1.0 gal/sx D-600, and 0.3% D-800. Cemented with 500 sx 15.8 lb/gal Class "G"; TOC @ 10,088' Cemented with 1310 sx 15.8 lb/gal Class "G" with 0.2% CFR-3, plus 0.13 gal/sx Halad 344L, 0.25% HR-5. SHORT STRING TUBING 0.00 53.58 Elevation 53.58 0.93 Tubing Hanger 54.51 283.36 2 7/8" 6.5 Ib/ft L-80 CS 337.87 4.00 2 7/8" 341.87 3984.94 2 7/8" 4326.81 6.48 2 7/8" 4333.29 1578.51 2 7/8" 5911.80 6.43 2 7/8" 5918.23 1124.16 2 7/8" 7042.39 6.45 2 7/8" 7048.84 1135.35 2 7/8" 8184.19 6.48 2 7/8" 8190.67 1112.45 2 7/8" 9303.12 6.48 2 7/8" 9309.60 980.55 2 7/8" 10290.15 6.44 2 7/8" 10296.59 296.75 10593.40 7.13 10600.47 12.05 10612.52 1.14 10613.66 10.12 10623.78 1.43 10625.21 0.74 Hydril Tubing Halliburton TRSV 6.5 Ib/ft L-80 CS Hydril Tubing CAMCO Gas Lift Mandrel 6.5 Ib/ft L-80 CS Hydril Tubing CAMCO Gas Lift Mandrel 6.5 Ib/ft L-80 CS Hydril Tubing CAMCO Gas Lift Mandrel 6.5 Ib/ft L-80 CS Hydril Tubing CAMCO Gas Lift Mandrel 6.5 Ib/ft L-80 CS Hydril Tubing CAMCO Gas Lift Mandrel 6.5 Ib/ft L-80 CS Hydril Tubing CAMCO Gas Lift Mandrel 2 7/8" 6.5 Ib/ft L-80 CS Hydril Tubing Halliburton RDH Dual Packer 2 7/8" 6.5 Ib/ft L-80 CS Hydril Tubing HES 'X' Nipple 2 7/8" 6.5 Ib/ft L-80 CS Hydril Tubing HEX XN Nipple Wireline Entry Guide Page 1 - NCIU B-2 PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 B. Seitz Phone (907) 265-6961 Fax: (907) 265-6224 June 19, 2002 Commissioner Cammy Oechsli Taylor State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Report of Sundry Well Operations NCIU B-02 (197-210 / 301-321) Dear Commissioner: Phillips Alaska, Inc. submits the attached Report of Sundry Well Operations for the recent operations on the Tyonek well NCIU B-02. If there are any questions, please contact me or Len Janson at 907-776-2046. Sincerely, B. Seitz Sr. OperationsfReservoir Engineer Phillips Alaska Inc. RECEIVED JUL 2 2002_ 0il & Gas Cons. LiUm~',~O~ BS/skad Subject: Phillips Tyonek Exemption Date: Thu, 20 Sep 2001 15:41:50 -0800 From: 'Watkins, Robert" <Robert_Watkins@envircon.state.ak.us> To: "'tom_maunder@admin.state.ak.us"' <tom_maunder@admin.state.ak.us> CC: "Harvey, Susan" <Susan_Harvey@envircon.state.ak.us> Tom-- Phillip Alaska is requesting DEC's approval to exempt their Tyonek Platfrom facility from oil discharge prevention and contingency plan requirements. Three well were drilled at this platform. In order to deregulate this facility, we are requiring Phillips to obtain a certification from AOGCC that the wells are in suspended classification under you regulations. If AOGCC Concurs that the well are in secure, suspended state, incapable of flow to the surface, and do not present any environmental risk. Upon receipt of your certification, we issue a letter exempting the facility from the State's contingency pla approval requirements. We will advise them that a contingency plan will be required to re-enter the wells in order to perform, the modifications converting them to gas production. Thanks, Robert Robert Watldns EPR Section Manager Alaska Department of Environmental Conservation 555 Cordova Street - Anchorage, AK 99501 Ph: (907) 269-7680 Fax: (907) 269-7687 Mailto: Robert Watkins~envircon.state.ak. us <rnailto:Robert Watkins~_.envircon.state.ak.us > Name: Clear Day Bkgrd.JPG _ i Encoding: base64 1 of 1 9/21/01 10:10 AM Note to File North Cook Inlet Unit Wells B-01A (198-002), B-02 (197-210) and B-03 (198-059) Phillips Petroleum Company (PPCo) is the operator of North Cook Inlet Platform (NClUP) in upper Cook Inlet. The platform produces gas from 13 producing wells, ships it to shore where it is liquefied for shipment to Japan. In late 1997 and continuing into 1998, PPCo drilled 3 wells and a sidetrack in a second attempt to further delineate the Sunfish prospect that had been identified with 2 ARCO wells ddlled in 1991/1992 and a platform well ddlle~finished in 1993. In the most recent drilling program PPCo completed and tested B-01A and B-02. The wells are equipped with tubing, packers, sub-surface safety valves, surface safety valves and other tree valves. B-03 was drilled to total depth, cased and cemented. An operations shutdown was granted in late 1998 and the well has never been completed. In order to drill and potentially produce oil wells, 'PPCo is required by DEC regulations to have an Oil Spill Discharge Prevention Plan (Spill Plan) in place. PPCo is required to maintain certain equipment and contractor relationships in order to assure available response resources in case of a spill. The current Spill Plan will expire in eady October and PPCo is seeking to be released from the need for a plan since the wells have been secured and PPCo does not have oil production equipment available' on board NCIUP. A meeting was held September 10 at DEC offices with Robert Watkins representing .DEC, myself representing AOGCC and 4 PPCo representatives. The currently carried status of the wells according to AOGCC records is 2 oil wells and 1 well .in operations shutdown. From the DEC perspective, the 2 oil wells (B-01A and B-02) are the concern. According to Mr. Watkins, based on the information provided by PPCo, he is ready to release PPCo from the Spill Plan requirements provided AOGCC concurs that the wells are secure and not at risk to flow. Please see his attached email regarding this subject. In conjunction with this determination, it may be appropriate to change the wells' status to Suspended. PPCo was able to flow test the 2 wells. Following the flow tests, the wells were shut in to await further development. With the drastic decline in crude prices, the potential for an. offshore development on a platform that could not produce oil without significant capital investment was erased. Although crude prices have increased, so has the investment cost and a development scenario has not been put forward. At the present time, the physical condition of the wells is as follows: All wells are "on board" NCIUP in Northern Cook Inlet. NCIUP is a continuously manned production platform with 13 producing gas wells and the 3 "Sunfish" wells. B-01A and B-02wWelis are equipped with tubing, packers, SSSVs and wellhead equipment with all appropriate valving including a SSV. Both wells do not have flowlines installed with such attachment locations covered with blind flanges. The $SSV and SSV control lines are not connected to any control system and valves with plugs have been affixed to the terminations. The SSSV in each tubing string is closed. The tubing above the S$SV in each string has been bled down to provide, a differential pressure across the valves. The SSV is not closed so the tubing space above the SSSV can be monitored for any leakage across the SSSV. Since the wells were secured, PPCo has not reported that the wells have leaked. B-03 has cemented, tested and unperforated casing set to total depth. The well has. never been completed and a deep retrievable bridge was set in the well during final operations. Through the discussions with PPCo, they have indicated that they do not intend for the wells to remain in their current configuration indefinitely. They have indicated that in their 2003 budget year, they plan to mobilize a rig to NCIUP. They intend to recomplete the wells as gas wells in the shallower Cook Inlet and Beluga sands. The lower oil intervals will be isolated with cement plugs and retainers to preserve the oil production opportunity should such production equipment and a pipeline be available. I recommend that the status of B-01A and B-02 be changed to suspended. The wells are mechanically secure on a continuously manned platform. PPCo does not have the necessary production or transportation equipment available to allow the wells to be produced. The wells are equipped with the necessary equipment (tubing, packers, SSSVs and wellheads) to prevent flow. The wells are not equipped with flow lines and their hydraulic control systems have been isolated from the active platform system. PPCo has indicated that within about 2 years, they plan to mobilize a rig to the platform to perform well work. At that time they have indicated that they intend to workover these wells, abandon the lower oil zones and recomplete the wells in the shallower gas intervals. . In support of this recommendation, the following regulations apply. Suspended Wells 20 AAC 25.110 (a) if allowed under 20 AAC 25.105... 20 AAC 25.105 (b) A well ddlled...from a fixed offshore platform must be abandoned before removal of the ddll rig unless the well is completed as an oil...well or is suspended, or unless well operations are shut down in accordance with 20 AAC 25.072. Each well ddiled for a fixed offshore platform must be abandoned before the platform is removed or dismantled. ...the commission will, upon application by the operator under (b)of this section, approve the suspension of a well if (1) the well (A) encounters hydrocarbons...to indicate the well is capable of producing in paying quanities or (D) is located on a...platform with active prOducing...wells and (2) the operator justifies...why the well should not be abandoned...or why the well should not be completed; sufficient reasons include (B) unavailability of surface production or transportation facilities (C) need for pool delineation and evaluation to determine the prudence of pool development (d) A well approved for suspension must be plugged in accordance with the requirements of 20 AAC 25.112, except that the requirements of 20 AAC 25.112(d) do not apply if (1) a wellhead is instailed...and (2) a bridge plug capped with 50 feet of cement...; the commission will waive the requirement of this paragraph for a development well drilled from a pad or platform, if the commission determines that the level of activity on the pad or platform assures adequate surveillance of that development well. 20 AAC 25.112(i) provides that The commission will, in its discretion, approve a variance from the requirements of the section if the variance provides for at least equally effective plugging of the well and prevention of fluid movement into sources of hydrocarbons or freshwater. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Camille Taylor, (j/~ DATE: Commissioner Tom Maunder, /j~_~ ' P. I. Supervisor THRU: October 11, 2002 FROM: John Spauiding, SUBJECT: Petroleum Inspector Plug 'and Abandonments PAl Tyonek Platform Wells Non Confidential October 11,, ,2002: ! traveled to PAl's Tyonek platform to witness the plug and abandonments of the bottom hole locations in preparation for eventual sidetracking and workovers of the following wells. In previous conversations PAl's rep. Jack Kralik asked how much pressure I wanted to see on the well upon my arrival, I requested that 500psi or at a mina positive pressure be displayed. All well were in the near area of 500psi. FA.:lO'was pressured from 500 psi to 1150 psi and held for 30 min. with no bleed down. The well was then de pressured to 0 psi and observed for 15 min. with no build up. -A-~ l:: was pressurea up from 500 psi to 1 t00 psi and held for 30 min with no bleed down. The well was then de pressured to 0 psi and observed for 15 min. with no build up. ~ was pressured up from 420 psi to 2200 psi and held for 30 min. with no bleed down. The well was then de pressured to 0 psi and observed for 15 min. with no build up. B-2 was pressured up from 500 psi to .2400 psi and held for 30 min. with no bleed down. The well was then de pressured to o psi and observed for 15 min. with no build up. ,SUMMARY: I witnessed 4 SuCCessful plug and abandonment pressure tests. Attachments: None P&A's Tyonek Plat 10-11-02is.doc PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P, O, BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 15, 2001 Mr. Thomas Maunder, Petroleum Engineer State of Alaska, Oil and Gas Conversation Commission 333 W. 7th Avenue, #100 Anchorage, Alaska 99501-3539 MAY 17 Alaska 0it & Gas '~' Subject: Tyonek Deep Wells B-lA and B-2 Dear Mr. Maunder: ~C.~_ ~) ~. (~ This letter is to follow up on the recent telephone conversations that you have had with Len Janson, the Tyonek Platform Engineer, regarding the status and classifications for the Tyonek Deep wells B-lA and B-2. The physical condition and status of the Tyonek Deep wells B-lA and B-2 are as follows: Well B-lA (sidetrack) Physical Condition: The well was perforated and tested. A completion report was filed 1/28/99. The well is shut in. No flow line is installed. The wing valve is closed with a blind flange installed. A SSSV is installed at 430'MD. The SSSV is closed and the control line is not connected to a control panel. Therefore, the valve cannot be opened without hooking up a hydraulic pump and manually pumping the valve open. Attachment 1 shows the wing valve with no flow line attached. Attachment 2 shows that the control line is not connected. Attachment 3 is a completion diagram. Current Status: The current AOGCC status is "l-oil". Phillips Alaska requests that the status be modified to "suspended". Well B-2 Physical Condition- The well was completed as a dual well. The well was perforated and tested. A completion report was filed 4/1/98. The well is shut in. No flow lines are May 15, 2001 Mr. T. Maunder, AOGCC Re: Ty'onek Deep Wells B-lA and B-2 Page 2 installed. The wing valves are closed with blind flanges installed. SSSVs are installed in both tubing strings. The SSSVs are closed and neither control line is connected to a control panel. Therefore, the valves cannot be opened without hooking up a hydraulic pump and manually pumping the valves open. Attachment 4 shows the long string wing valve with no flow line attached. Attachment 5 shows the shod string wing valve with no flow line attached. Attachment 6 shows that the short string control line is not connected. Attachment 7 shows that the long string control line is not connected. Attachment 8 is a completion diagram. Current Status: The current AOGCC status is "l-oil". Phillips Alaska requests that the status be modified to "suspended". The Tyonek Platform is not equipped to produce and process oil. The platform lacks flow lines to the wells, three-phase separation equipment, heater treaters, and oil pumps. Phillips Alaska has no plans to install oil-producing equipment for any of the Tyonek Deep wells. Please contact me with any questions at 265-6711. Sincerely, ~.~ _~.~~~ Gordon Caug Safety Engineer gc/dt/djn ,~GANNED NOV tqO FLo,~-./ LId~ A-ETA ck~P NCIU B-1 SIDETRACK COMPLETION DIAGRAM lSssv @ 43~ MD (430' TVD~ '1 120' @ 2579' MO (2571' TVD) I 2-3/8' injection stringSzone f~ [ I13-3/s' ~ 3760' MD (3521' 'I'VD;) I 12.75 ppf, P-110 tubing [PKR ~ 10,074' MD (8598' TVD) I 19-5/8' {~ 10,376' MD (8846' 'rVD) 5', 19.5 ppf, S-135 Drill Pipe with "G" Tool Joints (Min ID: 3.25") IN. FOREL~ NDS PERFS ~ 16,080' - 16,118' MD ICMT IN DP ~ 16,590' MD [5'DP ¢~ 16,65~ MD SGANNEO NOV PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 A. Worthington Phone (907) 265-6802 Fax: (907) 265-6224 October 23, 2002 Commissioner Cammy Oechsli Taylor State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Subject: Well Completion Report for NCIU B-2 (197-210 / 302-234) Dear Commissioner: Phillips Alaska, Inc. submits the attached Well Completion Report for the recent P&A operations on the Tyonek well NCIU B-2. If there are any questions, please contact me at 907-265-6802. Sincerely, A. Worthington Wells Engineer Phillips Alaska Inc. AW/skad SCANNED NOV 0 5 2002 RECEIVED OCT 2 9 2002 Ala~ 0il & Gas Cons. Commission -Anchorage STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of well Classification of Service Well Oil [] Gas [--] Suspended r~ Abandoned r-~ Service 2. Name of Operator 7. Permit Number ConocoPhillips Alaska, Inc. 197-210 / 302-234 3. Address 8. APl Number P. O. Box 100360, Anchorage, AK 99510-0360 50-883-20090-01 -" ...... ~-,~.,~ 9. Unit or Lease Name 4. Location of well at surface.,~ vu;;.~'~n~ ~'~c"' '~':'~ ~ 1249' FNL, 980' FWL, Sec. 6, TllN, ROW, SM I r~r~, ~ North Cook Inlet Unit At Top Producing Interval;~ ~-"-"-'-~ ~''~- ~--~]i 10. Well Number 1404' FSL, 536' FWL, Sec. 31, T12N, R9W, SM i YF. Ri~ i~ ~:~~'; B-2 838' FSL, 653' FWL, Sec. 31, T12N, R9W, SM · ~' '~--~' Cook Inlet Field 5. Elbvation in feet (indicate KB, DF, etc.) 16. Lease Designation and Serial No. Beluga Pool RKB 132' feetI ADL 17589 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. Or Aband. 115. Water Depth, if offshore 16. No. of Completions November 21, 1997 January 4, 1998 February 10, 1998 I 130 feet MSL Dual 17. Total Depth (MD + TVD) 18. Plug Back Depth (MD + TVD) 19. Directional Survey 120. Depth where SSSV set 21. Thickness of Permafrost 14537' MD /13377' TVD 12054' MD /11115' TVD YES ~ No E~'ITRSV @ 338' N/A 22. Type Electdc or Other Logs Run 23. CASING, LINER AND CEMENTING RECORD SE'I-rING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORDI AMOUNT PULLED 30" Surface 368' Ddven 20" 169# C-70 Surface 2602' 24" 1070 sx Class G, 600 sx Tail 13-3/8" 72# P-110, N-80 Surface 8909' 18.5" 6300 sx Class G 9-5/8" 53.5# P-110 Surface 11086' 12.25" 5oo sx Class G 7" 32# P-110 10738' 13522' 8.5" 1310 sx Class G 3.5" 12.95# P-105 13522' 14457' 8.5" cement plug top @ 12054' ~24. Perforations open to Production (MD + TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 2-7/8" 10625' 10593' 3.5" 1363O' all perfs P&A'd 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 12054' 29 bbls 15.8 ppg Class G 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) not applicable P&A Date of Test Hours Tested Production for OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE IGAS-OIL RATIO I N/A Test Pedod > Flow Tubing Casing Pressure Calculated OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY - APl (corr) press, psi !24-Hour Rate > 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and pressence of oil, gas or water. ,.~core chips. Anch0raoa Form 10-407 Rev. 7-1-80 ~CANNED NOV 0 5 2002 CONTINUED ON REVERSE SIDE Submit in duplicate NOV I 2002' 29. N/A NAME GEOLOGIC MARKERS MEAS. DEPTH TRUEVERT. DEPTH 30. FORMATION TESTS Include interval tested, pressure data, all fluids recovered and gravity. GOR, and time of each phase. RECEIVED OCT 2 9.2002 Oil,& Gas Cons. Commission Anchorage 31. LIST OF ATTACHMENTS Summary of Daily Operations 32. I hereby certify that the following is true and correct to the best of my knowledge. Signed ~;~ ~'~ Title Wells Enqineer Aras Worthi'~ton ~ Questions? Call Aras Worthington 265-6802 Date Prepared by Sharon Al/sup-Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 SCANNED NOV 0 Date Comment NCI B-2 Event History 09/18/02 09/25/02 09/26/02 O9/29/02 09/29/02 10/07/02 MADE DUMMY GUN RUN TO 13521' ON LONG STRING. RAN 2', 2" 6 SPF, 60 DEG PHASED HES TCP GUNS ON PRESSURE ACTUATED FIRING HEAD W/DUAL 6 MINUTE DELAY TIMERS (8 SHOTS TOTAL) - PARKED GUNS AT 13140' - 13142' WLM. PRESSURED UP AND FIRED GUNS, GOOD INDICATIONS AT SURFACE THAT GUNS FIRED. PRESSURE INCREASED FROM 1000 PSI TO 1800 PSI - WELL READY FOR CEMENT PLUG AND ABANDON. TEST BOPS TO 4200 PSI. CIRCULATE 300 BBL DRILL WATER DOWN 2-7/8" STRING W/RETURNS UP 3.5" STRING, FINAL PRESSURES 900 PSI ON BOTH STRINGS. RIH W/CMT NOZZLE, CANNOT PASS GLM #3. POOH AND CHANGE BHA, RUN BACK INTO HOLE TO 12,000 FT CTMD. PUMP 29 BBLS OF 15.8 PPG CLASS G CEMENT AND POOH, FILLING COIL VOID SPACE WITH FRESHWATER. PUT 3-1/2" AND 2- 7/8" TUBING IN COMMUNICATION (850 PSI). WAIT ON CEMENT. WAIT ON CEMENT. FREEZE PROTECT 3-1/2" TUBING TO 500' W/DIESEL. ROTATE TREE CAP FLANGE FOR ENTRY INTO 2-7/8" TUBING - P/T AND RIH TO 500' - LAY IN DIESEL AT ONE FOR ONE TO FREEZE PROTECT SHORT STRING - BOTH LONG AND SHORT STRING FREEZE PROTECTED. TAG XN NIPPLE IN SHORT STRING @ 10154' - TBG CLEAR OF CEMENT - SWAP TOP FLANGE TO LONG STRING - TAG CEMENT TOP @ 12054' WLM IN LONG STRING - WELL PLUG AND ABANDONED - WAITING ON AOGCC WITNESS FOR DRAWDOWN AND PRESSURE TEST OF TBG'S AND CSG'S. PRESSURE TEST SHORT STRING (2-7/8") AND LONG STRING (3-1/2") TO 2500 PSI FOR 15 MIN. PASSED TEST. BLED PRESSURE TO 0 AND HELD FOR 15 MIN. PASSED AOGCC REQUIRED PRESSURE AND DRAWDOWN PRE-TEST. READY FOR STATE WITNESS. BLED IA FROM 150--> 0 PSI, RECOVERED 4 GAL FLUID (GAUGE SHOWING 50 PSI). BLED CA FROM 100 --> 0 PSI, RECOVERED 16 GAL FLUID. SCANNED NOV 0 5 2002 Page I of I 10/23/2002 PERMIT 97-210 97-210 97 -210 97-210 97-210 97-210 97-210 97-210 97-210 97-210 97-210 97-210 97-210 97-210 97-210 97-210 97-210 DATA ........... CDR-MD CDR-MD CDR-TVD CDR-TVD MWD-FET-TVD FET-MD MWD FET-MD DDL-MD FET-TVD CN/LDT/GR AIT DSI MSCT GR/CCL PERF RELABEL DSI GR/CCL AOGCC Individual Well Geological Materials Inventory Page: 1 Date: 03/03/99 T DATA PLUS L LGR 8909-13416.6 L 'LGR 8909-13416.6 L LGR 8142-13340 L LGR 8142-13340 L BH (BL) 8123-13377 L BH(BL) 8990-14537 L BH(BL) 8990-14537 L BH(BL) 8990-14537 L BH(BL) 8123-13377 L LGR 11000-14500 L LGR 11000-14500 L LGR 11000-14500 L LGR 13175-13956 L LGR 12624-13007 L LGR 13000-13999 L LGR(C) 11000-13500 L LGR 13000-13999 1-9 02/03/98 1-9 02/03/98 1-9 02/03/98 1-9 02/03/98 02/26/98 02/26/98 02/26/98 02/26/98 02/26/98 1 03/25/98 1 03/25/98 1 03/25/98 1 03/25/98 1 03/25/98 1 03/25/98 1 02/09/99 1 02/09/99 PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 NORTH AMERICA EXPLORATION AND PRODUCTION COMPANY February 3, 1999 BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Attn: Mr. Robert Crandall Re: Well Information Tyonek Deep Project Cook Inlet, Alaska Gentlemen: Phillips Petroleum hereby delivers two boxes containing the well information as described on the attached schedule. This information covers the four wells (North Cook Inlet Unit wells B-1, B-2, B-1 ST and B-3/B-3 ST1/B-3 BP1) which have been drilled to date as part of the captioned project. Some of the material included in this package may be redundant with information that was provided to you earlier. Please contact the undersigned at 713-669-2942 if you have any questions. Sincerely, Robert N. Welch Landman cc: J. W. Lachenmaier $CANNF--¢' SIP ], % 2005 TYONEK DEEP WELL INF~, ~2/3/99) General: Folder B-1: Folder B-1 ST: Folder B-2: Folder B-3: Core Sample Report (B-l, B-1ST, B-2, B-3, B-3BP1, B-3ST) Geologic Tops (B-l, B-1ST, B-2, B-3) Operations Summary Report Well Completion/Re-completion Report and Log Schlumberger LIS Tape Verification Listing Blueline Logs: Fluid Comp. Cement Bond Phasor Induction w/GR Repeat Formation Tester - 32 Pressure Stations Comp. Neutron Litho-Density & Microlog w/GR/Calipers Comp. Neutron Litho-Density (TVD) Comp. Neutron Litho-Density (MD) CDR (TVD) CDR (MD) Repeat Formation Tester 14-Oct- 1997 Array Induction (TVI)) Array Induction (MI)) Dipole Shear Sonic (MD) Dipole Shear Sonic (TVD) Gamma Ray CCL Formation Evaluation 2"MD Drilling Data Log 2" MD MWD 2" TVD MWD T° MD Operations Summary Report Well Completion Report Directional Survey Permit to Drill Scan Well Test (Prod. Test #1) Logs: CDR (TVD) Comp. Neutron Litho-Density w/GR (TVI)) and (MD) Pressure Data Log Film: ADNR (TVD) Vellum: Pressure Data Log 1":250' Sepia: Pressure Data Log 1":250' Operations Summary Report Well Completion or Recompletion Report Well Test Results = Short & Long String Diskette: Surveys Diskette: Scan Data NF.ASC and SUN. AS Logs: Army Induction 2" MD Array Induction 5" = 100' MD Comp. Neutron Litho - Density W/GR Digital Sonic Tool - Long Army Dipole Sonic Relabelled Delta T's Formation Evaluation 2" TVD Drilling Data Log 2" MD Formation Evaluation 2" MD MWD Integrated Formation Evaluation 2" TVD MWD Integrated Formation Evaluation 2" MD G/R Collar Log Perf. Record 6-Feb- 1998 G/R Collar Log Perf. Record 23-Jan-1998 Mechanical Sidewall Coring Tool SGANNED' SEP J,. g 21102 Blueline Logs: Completion Reports 99-021.doc Folder B-3 ST: Folder B-3 BP1: c,v,:rafions Summary Report Permit to Drill; Sundry Approvals Blueline Logs: Platform Express Three-Detector Lift,o-Density Comp. Neutron/GR Caliper/GR MWD Integrated Formation Evaluation 2" TVD MWD Integrated Formation Evaluation 2" MD Formation Evaluation 2" MD Formation Evaluation 2" TVD Drilling Data 2" MD Film: Caliper Log/GR Sepias: Formation Evaluation 2" TVD Drilling Data Log 2" MD MWD 2'i TVD Formation Evaluation 2" MD Pressure Data MWD 2"MD Vellums: Formation Evaluation 2" MD Pressure Data Log MWD 2" TVD Formation Evaluation 2" TVD Drilling Data Log 2" MD MWD 2" MD Blue Line Logs: Diskette: 4MM Tape: Film: Vellums: Direction Survey 0-17864' Formation Evaluation 2" TVD Formation Evaluation 2" MD MWD 2" MD MWD 2" TVD Pressure Data Log 8918' TVD-12332' TVD Pressure Dta Log 9134' TVD-13368' TVD Drilling Data Log 2" MD Impulse TVD Impulse MD ADN4 MD ADN4 TVD Resistivity TVD 1:600 & 1:240 Resistivity MD 1:600 & 1:240 B3-ST1.LAS and Survey. TXT-Dir. Survey MD & TVD LAS Files (final data) Survey Files Resistivity 1:600 & 1:240 MD ADN4 MD Resistivity 1:600 & 1:240 TVD Formation Evaluation 2" MD Formation Evaluation 2" TVD Drilling Data 2" MD MWD Integ. Formation Evaluation 2" MD MWD Integ. Formation Evaluation 2" TVD Pressure Data Log Blueline Logs: Sepias: Formation Evaluation 2" TVD lVlWD 2" TVD Pressure Data Log Formation Evaluation 2" MD MWD 2"MD Drilling Data 2" MD MWD 2" MD Pressure Data Log Drilling Data Log 2" MD Formation Evaluation 2" TVD MWD 2" TVD Formation Evaluation 2" MD 2002 99-021.doc / I T~YONEK DEEP WELL IN.. o (2/3/99) General: Folder B- 1' Folder B- 1 ST: Folder B-2: Folder B-3: Core Sample Report (B-l, B-1ST, B-2, B-3, B-3BP1, B-3ST) Geologic Tops (B-l, B-1ST, B-2, B-3) /Operations Summary Report Well Completion/Re-completion Report and Log Schlumberger LIS Tape Verification Listing Blueline Logs: Fluid Comp. Cement Bond Phasor Induction w/GR Repeat Formation Tester- 3~essure Stations ~ ~'~' Comp. Neutron Litho-Density & Microlog w/GR/Calipers Comp. Neutron Litho-Density (TVD),- Comp. Neutron Litho-Density (MD)-' CDR (TVD) ,, CDR (MD) Repeat Formation Tester 14-Oct-1997 Army Induction (TVD)., Array Induction (MD) Dipole Shear Sonic (MD) Dipole Shear Sonic (TVD)" Gamma Ray CCL -' /v't.~,a ,~ O ~-- Formation Evaluation 2" MD Drilling Data Log 2" MD MWD 2" TVD .- MWD 2" MD ~ Diskette: Logs: Operations Summary Report Well Completion Report Directional Survey Permit to Drill Scan Well Test (Prod. Test #1) Logs: CDR (TVD) '~ Comp. Neutron Litho-Density w/GR" (TVD) and (MD), Pressure Data Log Film: ADNR (TVD) '-~ Vellum: Pressure Data Log I":250' e' Sepia: Pressure Data Log 1":250'-~ Operations Summary Report Well Completion or Recompletion Report Well Test Results = Short & Long String Diskette: Surveys Scan Data NF.ASC and SUN. AS Array Induction 2" MD ~' Array Induction 5" = 100' MD ~' Comp. Neutron Litho - Density W/GR Digital Sonic Tool - Long Array ~ Dipole Sonic Relabelled Delta T's Formation Evaluation 2" TVD e. Drilling Data Log 2" MD .~ Formation Evaluation 2" MD" MWD Integrated Formation Evaluation 2" TVD MWD Integrated Formation Evaluation 2" MD Blueline Logs: G/R Collar Log Perf. Record 6-Feb-1998 G/R Collar Log Perf. Record 23-Jan-1998 Mechanical Sidewall Coring Tool Completion Reports SGANhIED' SEP -'[. ~ 200? 99-021.doc ~ Folder B-3ST: Folder B-3 BP1: derations Summary Report Permit to Drill; Sundry Approvals Blueline Logs: Platform Express Three-Detector Litho-Density Comp. NeutrordGR Caliper/GR MWD Integrated Formation Evaluation 2' TVD MWD Integrated Formation Evaluation 2" MD Formation Evaluation 2', MD Formation Evaluation 2" TVD Drilling Data 2" MD Film: Caliper Log/GR Sepias: Formation Evaluation 2" TVD Drilling Data Log 2" MD MWD T' 'I'VE} Formation Evaluation 2" MD Pressure Data MWD 2" MD Vellums: Formation Evaluation 2" MD Pressure Data Log MWD 2" TVD Formation Evaluation 2" TVD Drilling Data Log 2" MD MWD 2" MD Blue Line Logs: Diskette: 4MM Tape: Film: Vellums: Direction Survey 0-17864' Formation Evaluation 2" TVD Formation Evaluation 2" MD MWD 2" MD MWD 2" TVD Pressure Data Log 8918' TVD-12332' TVD Pressure Dm Log 9134' TVD-13368' TVD Drilling Data Log 2" MD Impulse TVD Impulse MD ADN4 MD ADN4 TVD Resistivity TVD 1:600 & 1:240 Resistivity MD 1:600 & 1:240 B3-STI.LAS and Survey. TXT-Dir. Survey MD & TVD LAS Files (final dam) Survey Files Resistivity 1:600 & 1:240 MD ADN4 MD Resistivity 1:600 & 1:240 TVD Formation Evaluation 2" MD "' Formation Evaluation 2" TVD Drilling Data 2" MD ~' MWD Integ. Fonnation Evaluation 2" MD '" MWD Inte§. Formation Evaluation 2 Pressure Data LOg .,. Blueline Logs: Sepias: Pressure Data Log Drilling Data Log 2" MD Formation Evaluation 2" TVD MWD 2. TVD Formation Evaluation 2" MD Formation Evaluation 2" TVD MWD 2" TVD ~'.,~' Pressure Data Log Formation Evaluation 2" MD MWD 2" MD ~'~,~' Drilling Data 2" MD ~'~' MWD 2" MD 99-021.doc STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of request: Abandon_XX Suspend_ Operational shutdown _ Re-enter suspended well _ Alter casing _ Repair well _ Plugging _ Time extension _ Stimulate _ Change approved program _ Pull tubing _ Variance _ Perforate _ Other _ 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 4. Location of well at surface j V' v 1249' FNL, 980' FWL Sec. 6 T11N, R9W At top of productive interval 1404' FSL, 536' FWL, Sec. 31, T12N, R9W At effective depth At total depth 838' FSL, 653' FWL, Sec 31, T12N, R9W 5. Type of Well: Development Exploratory __ Stratigraphic __ Service__ 6. Datum elevation (DF or KB feet) RKB 132 feet 7. Unit or Property name North Cook Inlet 8. Well number NClU B-2 9. Permit number / approval number 197-210 10. APl number 50-883-20090-01 11. Field / Pool North Cook Inlet Field Development 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length Structural 368' Conductor 2543' Surface 8849' Intermediate 12080' Liner 2788' Liner 14537 feet V/ Plugs (measured) 13377 feet -~ 13583 feet Junk (measured) 12516 feet Size Cemented Measured Depth True vertical Depth 30" Driven 368' 368' 20" 1070 sx Class G, 600 sx Class G 2602' 2535' 13-3/8" 6300 sx Class G 8909' 8123' 9-5/8" 500 sx Class G 11086' 10244' 7" 1310 sx Class G 13522' 12460' 3.5" (included above) 14457' 13305' Perforation depth: measured 1311~'~1317~'~13652'~13686'~13718'~13736'~13818'~13856'~139~1'-1392~'~13944'-13966' true vertical 12084'- 12139', 12579'- 12610', 12639'- 12656', 12730'- 12765', 1 , Tubing (size, grade, and measured depth Packers & SSSV (type & measured depth) Short String: 2-7/8", 6.5#, L-80 CS to 10625' md Long String: 3-1/2", 12.95#, L-80, PH-6 to 13630' md Halliburton RDH Dual Pkr @ 10593' md Halliburton TRSVs at 338' (short string) and 420' (long string) 13. Attachments Description summary of proposal __X Detailed operations program __ JUL 2 5 2.002 14. Estimated date for commencing operation August 1,2002 16. If proposal was verbally approved Oil __ Name of approver Date approved Service 17. I hereby certify that the foregoing is true and co~e b~t of my knowledge. Signed J~ Title: Wells Engineer Aras Worthin~lton FOR COMMISSION USE ONLY 15. Status of well classification as: Gas __ Suspended __XX Questions? Call Aras Worthington 265-6802 Date ~;;~/~'~~" Prepared by Sharon AIIsup-Drake 263-4612 Conditions of approval: Notify Commission so representative may witness, ~ . Plug integrity __ BOP Test ~ Location c earanc~ __ Mechanical Integrity Test__ Subsequer~.~form required 10- Ong,n~l Approved by order of the Oommission Camffl), Oechsli Ta~:~ Oommissioner Form 10-403 Rev 06/15/88 o J Approval no. Date hUG ?, 1 2002' SUBMIT IN TRIPLICATE NCIU B-2 Intended P&A for Completion as a Gas Well Objective: Plug & Abandon all perforations for re-completion as a gas well. Intended P&A procedure: 1. Pull tbg tail plug from 2 7/8" tbg. 2. RU CTU; Test BOPE to 4000 psi. 3. RIH to bottom of 2 7/8" tbg string & pump cement to P&A Sunfish perfs. 4. Drawdown & PT cement plug to 3000 psi. 5. Run Tbg-Tail Plug into 2 7/8" tbg tail. 6. Set a bridge plug in the 3 ½" tbg. Dump-bail 25' of cement on top of B.P. 7. Cut & pull 2 7/8" & 3 ½" tbg strings (cuts staggered by depth)... 8. Set a Retrievable Bridge Plug in the 9 5/8" casing & dump-bail sand'"~n ~0p. 9. Shoot holes in 9 5/8" casing above RBP & circulate/squeeze cement into 9 5/8"xl 3 3/8" annulus to surface. Pull RBP. 10. 11. Sting over 3 ½" tbg stub with gas completion. B-2 Revised P&A Procedure Subject: B-2 Revised P&A Procedure Date: Tue, 13 Aug 2002 17:09:54 -0800 From: "Aras Worthington" <ajworth@ppco.com > TO: tom_m aunder@admin.state.ak.us CC: "Scott D Reynolds" <sreynol2@ppco.com >, "Lewis Ledlow" <lledlow@ppco.com >, "Brian Seitz" <bseitz@ppco.com>, "John C Braden" <jbraden@ppco.com> Tom, Following is a revised P&A procedure as discussed via phone this afternoon. Please call if there is anything else I can help you with. Thanks, Aras (See attached file: NCIU B2 Intended P&A. doc) l ~NCIU B2 Intended P&A.doc Name: NCIU B2 Intended P&A. doc Type: WINWORD File (application/msword) Encoding: base64 1 of I 8/20/2002 7:48 AM NCIU B-2 Intended P&A for Completion as a Gas Well Objective: Plug & Abandon all perforations for re-completion as as well. Intended P&A Procedure: 1. Drawdown & Pressure test the 5/8" casing string). 2. Drawdown & Pressure test the 3 ¥2" tbg s (this will test the CIBP/cement plug in the liner). 3. Shoot holes in the 3 ¥2" tbg 100' abc the seal assy @ 13,525' (below the Sunfish perforations) 4. Pull tbg tail plug from 2 7/8" 5. RIH w/CT & pump shot holes to P&A Sunfish perfs 100' above top of perfs taking returns 2 7/8" tbg; balance cement plug to same depth in tbg as in tbg x casing ~Q) -x-x-~,~ - -5~.q,~ x¢~\~. ~-x,~-' Drawdown & the cement plug. o 7. 8. 9. 10. 11. 12. Run & set the 2 tbg-tail plug in place. Cut 2 7/8" & tbg strings (cuts staggered by depth). Drawdown Pressure-test the 9 5/8" casing string. Pull the & 3 V2" production tbg strings with the rig. Cut th~ 5/8" casing above the 13 3/8" shoe & pull 9 5/8". gas well completion into well. B NED 1 2002 PHILLIPS Alaska, inc. '~-.-~ A Subsidia. c/of PHILLIPS pETROLEUM CO~4P, ANY BPV (Mke; Type, OD) Hr (Make, Type) Annulus Fluid: NCIU Not Applicable RKB-THF: Not Applicable RKBqBHF 59.00 RKB-MSL: 132.00 Water Depth: 130.00 Casing Strings PPCO Allowable Ratings 547 WELD 169 Ibs/f~ X-56 DnI-Quip 1700 721bsRt N-80:P-110 BT&C 761 52.5 Ibs/Ft P-110 BT&C CEMENTING SUMMARY 20" Conductor Cement with 1070 sx Class "G" w/0.25 gal/sx D-77. 11/25/93 0.05 gal/sx D~47 & 0.28 gai/sx D-75. Tailed with 600 sx Class mixed @ 15.8 lb/gal with 0.25 gal D-77 & 0.05 gaVsx D~47 Cement circulated to Surface, 13 3/8" 1st Stage Cemented with 900 sx 12.5 lb/gal Class "G" with 1.0^ D~6 ptus 0,05 gal/sx D-47. Tailed with 700 sx Class "G" @ 15.8 lb/gal with 0,05 gal/sx D-47, 0,5% D-59, 0.15 gal/sx D-801, 0,4% D-65. 0.1% D-t34 and 0,25% S-1. 2nd Stage Cemented with 3700 sx 18.6 ih/gal Class "G" with 0,10% D-65, plus DMY Tool @ 7385' 0.1 gal/sx D-47, 0.1% D-135, 1.0 gaVsx D-600, and 0.3% D-800. 3rd Stage Cemented with 1000 sx t 5.8 lb/gal Class "G" with 0.20% D-65, plus DMY Tool @ 4045 0.1 gal/sx D-47, 0,1% D-135.1.0 gal/sx D-600, and 0,3% D-800, 9 5/8" Cemented with 500 sx 15.8 IbJgal Class "G"; TOC @ 10,088' 7" & 3.5" Cemented with 1310 sx 15.8 lb/gal Class "G" with 0.2% CFR-3, plus 0.13 gal/sx Halad 344L. 0.25% HR-5. SHORT STRING TUBING 0,00 53.58 53.58 0.93 54.51 283.36 337.87 4.00 341.87 3984,94 4326.81 6,48 4333.29 1578.51 5911.80 6.43 5918.23 1124.16 7042.39 6.45 7048.84 1135,35 8184.19 6.48 8190.67 1112.45 9303.12 6.48 9309.60 980,55 10290.15 6.44 10296.59 296~75 10593.40 7.13 10600.47 10612.52 10613.66 10623,78 10625.21 Tubing Hanger 2 7/8" 6.5 lb/ft L-80 CS Hydrit Tubing 2 7/8" Halliburton TRSV 2 7/8" 6.5 lb/it L-80 CS Hyddl Tubing 2 7/8" CAMCO Gas Lift Mana~ei 2 7/8" 6.5 lb/it L-80 CS Hydril Tubing 2 7/8" CAMCO Gas Lift Mandrel 2 7/8" 6.5 Ib/ft L-80 CS Hyddl Tubing 2 7/8" CAMCO Gas Lift Mandrel 2 7/8" 6.5 Ib/ft L-80 CS Hydrii Tubing 2 7/8" CAMCO Gas Lilt Mandrel 2 7/8" 6.5 Ib/ft L-80 CS Hyddl Tubing 2 7/8" CAMCO Gas Lift Mandrel 2 7/8" 6.5 Ib/ft L-80 CS Hydril Tubing 2 7/8" CAMCO Gas Lift Mandrel 27/8" 6.5 lb/it L-80 CS Hyddl Tubing Halliburton RDH Dual Packer 12.05 2 7/8" 6,5 lb/it L-80 CS Hydril Tubing 1.14 HES ~X' Nipple t0,12 2 7/81t 6.5 lb/it L~80 CS Hyddl Tubing 1.43 HEX XN Nippte 0.74 Wiretine Entry G~ide Page 1 - NOIU B-2 PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY COOK INLET AREA BOX 66 KENAI, ALASKA 99611 Phone: (907) 776-8166 Fax: (907) 776-6240 August 30, 2001 Ms. Cammy Taylor, Chair AlaSka Oil and Gas Conservation Commission 333 West 7th Avenue, #100 Anchorage, AK 99501-3539 Re:RE: Tyonek Deep wells B-lA and~-,~ Dear Ms. Taylor This letter is a follow-up to our July 19, 2001 correspondence to Mr. Maunder in which we requested the classification of Tyonek Deep wells B-lA and B-2 be changed to 'shut-in'. We would like to advise the AOGCC of our future plans for these two wells. Tyonek Deep wells B 1-A and B-2 are scheduled to have the oil zones suspended and be completed as shallow gas wells in the Beluga and Sterling formations in 2003. The wells current mechanical condition will be maintained until a rig is mobilized to perform this remedial work in 2003. Should we change the mechanical condition of the wellbore by the addition of a wireline retrievable plugging device we will advise AOGCC of the change. Additionally, we will implement a monthly annulus monitoring program. The current physical condition of these two wells is outlined in our letter of July 19, 2001. Please contact me with any questions at 776-2021. Lindsey Clark Cook Inlet Operations Manager SeiNED MAY 2 9 2002' AUG 3 0 200 Alaska Oil 8, Gas Cons, Commission AnChorage ALASKA OIL AND GAS CONSERVATION COMMISSION TONY KNOWLES, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 October 4, 2001 Mr. Robert Watkins Environmental Specialist Alaska Department of Environmental Conservation 555 Cordova Street Anchorage, Alaska 99501 Re: Tyonek Deep Wells B-01A, B-02 and B-03 PPCo Petroleum Company (PPCo) North Cook Inlet Platform (Tyonek) Cook Inlet Alaska Dear Mr. Watkins: In early September, a meeting was held with PPCo representatives, yourself and myself to discuss the status of the subject wells. PPCo is seeking relief from DEC requirements with regard to maintaining spill response plans and equipment since there is no oil production from their platform. In support of their request, PPCo has submitted information regarding the physical condition of the wells and represents that the wells are well secured and that the chance of any release to the environment is remote. I have reviewed the submitted information. My analysis follows. All wells are "on board" Tyonek Platform in Northern Cook Inlet. Tyonek is a continuously manned production platform with 13 producing gas wells and the 3 "Tyonek Deep" wells. As described below, the Tyonek Deep wells are physically well secured. The present condition of the wells is beyond simply being shut in and the Deep wells have been physically isolated from any platform production system. B-01A and B-02 are equipped with tubing, packers, SSSVs and wellhead equipment with all appropriate valving including a SSV. Both wells do not have flowlines installed with such attachment locations covered with blind flanges. The SSSV and SSV control lines are not connected to any control system and valves with plugs have been affixed to the terminations. The SSSV in each $t; NED MAY ,t 9 2002: Tyonek Deep Wells B-01A, B-02 and B-03 October 4, 2001 Page 2 0£2 tubing string is closed. The tubing above the SSSV in each string has been bled down to provide a differential pressure across the valves. The SSV is not closed so the tubing space above the SSSV can be monitored for any leakage across the SSSV. Since the wells were secured, PPCo has not reported that the wells have exhibited any pressure increase that would indicate a leaking SSSV. B-03 has cemented, tested and unperforated casing set to total depth. The well has never been completed and a deep retrievable bridge plug was set in the well during final operations. Based on my knowledge of no oil production equipment existing on board Tyonek Platform, the documentation submitted by PPCo relating to how the wells have been physically secured and isolated, I concur that the subject wells are well secured and that an oil discharge is not likely. I endorse PPCo's request for the relief requested. Please contact me at 793-1250 if you require further information. Sincerely, Thomas E. Maunder, PE Senior Petroleum Engineer jjc cc: Well Files B-01A-198-002 B-02-197-210 B-03-198-059 SCANNED MAY ~, g 2002 i' .. 1. Type of request: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS Abandon_ Alter casing _ Change approved program 2. Name of Operator Phillips Alaska, Inc. 3. Address P. O. Box 100360 Anchorage, AK 99510-0360 5. Type of Well: Development __ Exploratory __ Stratig raphic __ Service X __ 4. Location of well at surface 1249' FNL, 980' FWL Sec. 6 T1 1 N, R9W At top of productive interval 1404' FSL, 536' FWL, Sec. 31, T12N, R9W i: i :: At effective depth At total depth 838' FSL, 653' FWL, Sec 31, T12N, R9W 6. Datum elevation (DF or KB feet) RKB 132 feet 7. Unit or Property name North Cook Inlet 8. Well number NCIU B-2 9. Permit number / approval number 97-210 10. APl number 50-883-20090-01 11. Field / Pool North Cook Inlet Field Development 12. Present well condition summary Total depth: measured true vertical 14537 feet Plugs (measured) 13377 feet Effective depth: measured : 14377: feet :: : true vertical 13234::: feet Junk (measured) Casing Length Structural 368' Conductor 2543' Surface 8849' Intermediate 12080' Liner 2788' Liner Size Cemented Measured Depth 30" 368' 20" 1070 :SXClasS; G;: 600sXClass: G:: 2602' 13-3/8" 63°° ~x°iaSS;G :;:i ;:;; :; ;;;; ;;; :;: 8 90 9' 9-5/8" .500;~x bias~::G:;: :: :::;:!::::: :::i:::::::: 11086' 7" : :i:3 ~ d: ~;:~i~:8 :;:i:;: :; :;: 13522' 3.5" (included above) 14457' True vertical Depth 368' ::: :::::: :::: :::::::::::: iii:i!::! · ! Perfo ration depth: measu red I I i true vertical i I !Tubing (size, grade, and measured depth Packers & SSSV (type & measured depth) 13. Attachments 14. Estimated date for commencing operation I 15. Status of well classification as: November 16, 2001 I 16. If proposal was verbally approved ,1,",~,, ,~ l S-NoV-01: : Name of approver Tom Maunder", Date;apProved :1 13110'~ i 3 i 70', i36521~ i3686!1:i ~718!~:~:3~36i:~:!1 S8 I8:1~i 38S~!!: i~0~1:i~1~920'. 13944'-13966' 12084'- t 2139';:i 2579;:.:t2810~i 128:~9!~it2~5~i i;: '1 ~730)~12~6Siii :1:~80:g!~:i~823'. 12845'-12864' · :: i:::::::: :i ] i :]: ;::::i::::::;::] ::i::::;::::]:];:; 'i :] : :::::::::::::::::::::::::::::::::::: ' .................................................... ik;,~ ? ~ ? :J 't~ 8horl 8kin~: 2-7/8" ~.~ L-80 08 to ~0~2S' md Long String: 3-1/2 12.95~ L-80 PH-6 to 13530' md ~ -., , . r~F~ Halliburton RDH Dual Pkr G 10593' md ~'. ;..~'V' [b ~.J(} Ha burton TRSVs at 338' (short string) and 420' (long str ng) ............ · : :::':::::: : ::: ::~:;~ , ~ ¢, ~ ~,~ .~- ....... of proposal ~:. ::::: :Deta ed:operationS pr0g~am~ ~ :':;:::::;~:~&~,~2r];~ Description summaw Oil X Gas__ Suspended__ Service 17.1 hereby certify that the foregoing is true and c,~rrect t~,41~e best ofmy knowledge. Questions? Call Len Janson (907)776-2046 Signed _.~'~,¢¢'/? ~/i~'~f~ Title: Sr. Operations/Rese~oir Engineer Date /]//~/~' Brian Seit2 Prepped by Sharon AIIsup-Drake (263-4612) & Brian Sei~ (265-6961) FOR COMMISSION USE ONLY Conditions of approval: Noti~ Commission so representative may witne~ ~ Approval I Approved by order of the Commission Plug integrity __ BOP Test Mechanical Integrity Test__ Form 10-403 Rev 06/15/88 · Location clearance__ Subsecuent form required 10- Commissioner SUBMIT IN TRIPLICATE NCIU B-2 Well Suspension 2 7/8" tbg string: . 2. 3. 4. 5. 6. Kill 2 7/8" tbg string (Sunfish perforations) with brine. RU Slickline to 2 7/8" tubing string. Run PXN plug into XN nipple in tubing tail. Perform drawdown test to 0 psi for 30 minutes. Pressure test plug to 3000 psi for 30 minutes. Close SSSV, Master, SSV, & Swab valve. 3 1/2" tbg string: o 2. 3. 4. 5. 6. 7. RU Slickline & drift for Cast-Iron Bridge Plug (CIBP). RU E-Line & Set CIBP in 3 V2" liner. RU Slickline & dump-bail 25' cement plug on top of CIBP. WOC for 3 days. Perform drawdown test to 0 psi for 30 minutes. Pressure test plug to 3000 psi for 30 minutes. Close SSSV, Master, SSV, & Swab valve. PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY Post Office Box 100360 Anchorage, Alaska 99510-0360 B. Seitz Phone (907) 265-6961 Fax: (907) 265-1441 November 16, 2001 Ms. Cammy Oechsli Taylor Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 W. 7'" Avenue, Suite 100 Anchorage, Alaska 99501 Subject: NCIU B-02 Application for Sundry Approval Dear Commissioner Taylor: Phillips Alaska, Inc. hereby files this Application for Sundry Approval for suspension of the Cook Inlet NCIU B-02 well. This well is not producing from the perforated intervals and will be recompleted as a gas-producing well at a later date. In addition, the cement/mechanical downhole plugs will provide an additional barrier to flow from the well. If you have any questions regarding this matter, please contact Len Janson at (907) 776-2046. Sincerely, Brian Seitz Sr. Operations/Reservoir Engineer BS/skad Re: NCIU B-1 & B-2 Well SuspensIons Subject: Re: NCIU B-1 & B-2 Well Suspensions Date: Tue, 13 Nov 2001 14:42:06 -0900 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Tyonek Supervisor <tyksupv@ppco.com> CC: Aras Worthington <ajworth@ppco.com>, AOGCC North Slope Office <aogcc_prudhoe_bay@admin.state.ak.us> Aras and Len, Chuck Scheve and I reviewed the original plans you submitted by email this morning. You have made edits and provided further information as requested. Based on the information you have provided and our discussions, you have approval to proceed with your planned operations, Please note that sundry notices for the activities will need to be submitted as soon as practical, i would like the see the appropriate forms before weeks end if possible. I am copying the inspectors with this approval. As far as witnessing any operations goes, I imagine that the pressure testing planned on each string is likely the operation we will witness. Please keep the North Slope office informed. Tom Maunder, PE Sr. Petroleum Engineer AOGCC Tyonek Supervisor wrote: Yes, we are planning to pump a 3% KC/flush down the tubing on B-lA prior to pumping cement. We are also planning to pump a 3% KC! flush down the Iongstdng on B-2 prior to setting the CIBP. Thanks, Aras Tom Maunder <torn_maunder~,admin.state. ak. us> 1/13/2001 12:42 PM To: Tyonek Supervisor/PPCO@Phillips cc: Subject: Re: NCIU B-1 & B-2 Well Suspensions Aras, ! have looked at the procedures. They are essentially as we discussed, however I have noted one item. It is specifically stated to kill the short string in B-2. You did mention that you will be pumping quite a volume of fluid into B-lA, but it is not mentioned in the procedure. Will you also be killing the long string in B-277 Given that you do not have any oil handling or separation equipment, it would seem like a good practice to employ. Look 1 of 3 2/21/02 5:26 PM Re: NCIU B-1 & B-2 Well Suspensions forward to your reply. Tom Tyonek Supervisor wrote: > > Tom, ·· > > As per our conversation earlier today, the following work scopes for B-1 >& > > B-2 are attached with editions including a 20' cement cap on top of the > > CIBP in the iongstring of B-2. > > Please call back if there are any questions/concerns @ 776-2073. ·· > > Thanks, > > Aras > > (See attached file: NCIU Bl.doc)(See attached file: NCIU B2. doc) > > -~- Forwarded by Tyonek Supervisor/PPCO on 11/13/'2001 12:19 PM ---- ·· > > Leonard G Janson Jr >> > > 11/13/2001 08:11 AM ·· > > To: tom_maunder@admin.state, ak. us > > cc: Aras Worthington/PPCO@Phillips, C Lindsey · · · · Clark/PPCO@Phillips, Scott B > Rennie/PPCO@Phillips, Michael J Nelson/PPCO@Phillips, Tyonek Supervisor/PPCO@Phiilips, Ryan > P Deines/PPCO@Phillips > bcc: · Subject: NCIU B-1 & B-2 Well Suspensions · > Tom, · > Attached are the expected work scopes for B-f and B-2. in addition to this · .work, we will repeat the M/Ton A-12's disposal string. If you oran AOGCC · rep would like to witness any of this work, call the platform at 776-2073 for helicopter connections. If you have any comments, contact me on the platform. Thanks... Len Janson 0~ce-90~776-2046 Fax-907-776-6246 Ceil-g0~252-6748 >· 2 of 3 2J21/02 5:26 PM Re: NCIU B-1 & B-2 Well Suspensions > (Embedded image moved to file: pic'lO291.pcx) Name: NCIU Bl.doc NCIU Bl.doc Type: WINWORD File (application/msword) Encoding: base64 Name: NCIU B2. doc NCIU B2. doc Type: WINWORD File (application/msword) Encoding: base64 Name: pic 10291.pcx pic10291.pcx Type: PCX Image (application/x-unknown-content-type-pcxfile) > Encoding: base64 (See attached file: torn_maunder, vcf) i Tom Maunder <tom maunder@admin.state.ak, us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 3 of 3 2J21/02 5:26 PM NCIU B-2 Well Suspension 2 7/8" tbg string: . 2. 3. 4. 5. 6. Kill 2 7/8" tbg string (Sunfish perforations) with brine. RU Slickline to 2 7/8" tubing string. Run PXN plug into XN nipple in robing tail. Perform drawdown test to 0 psi for 30 minutes. Pressure test plug to 3000 psi for 30 minutes. Close SSSV, Master, SSV, & Swab valve. 3 ~' tbg string: o 2. 3. 4. 5. 6. 7. RU Slickline & drift for Cast-Iron Bridge Plug (CIBP). RU E-Line & Set CIBP in 3 ½" liner. RU Slickline & dump-bail 20' cement plug on top of CIBP. WOC for 3 days. Perform drawdown test to 0 psi for 30 minutes. Pressure test plug to 3000 psi for 30 minutes. Close SSSV, Master, SSV, & Swab valve. NCIU wells B1 and B2 Subject: NCIU wells B1 and B2 Date: Fri, 12 Oct 2001 13:33:16 -0800 From: "Leonard G Janson Jr" <lgjanso@ppco.com> To: tom_maunder@admin.state.ak.us Len Janson Office - 907-776-2046 Fax - 907-776-6246 Cell- 907-252-6748 ---- Forwarded by Leonard G Janson Jr/PPCO on 10/12/2001 01:34 PM ..... Delivery Failure Report Your NClU wells B1 and B2 document: was not delivered to: tom-maunder@admin.state.ak, us because: 551 User unknown What should you do? 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BVLNOTES 10/CIT/Phillips Petroleum/us, NSATOH02/AAI/^RCO To: C Lindsey ClarkJPPCO@Phiilips 1 of 3 2/21/02 5:01 PM NCIU wells B1 and B2 cc: Michael J Nelson/PPCO@Phillips, NSK Problem Well Supv/PPCO@Phillips, Brian Seitz/PPCO@Phillips, Aras Worthington/PPCO@Phillips, tom-maunder@admin.state.ak, us, J Scott Jepsen/PPCO@Phillips, Michael G Knight/PPCO@Phillips, Scott R Fahrney/PPCO@Phillips, F Steve T ow n sen d/P PCO@ Phillips Date: 01:24:45 PM PST Today Subject: NCIU wells B1 and B2 Lindsey, As a follow up to our conversation, i contacted Tom Maunder of the AOGCC to discuss NClU B-1 and B-2 in reference to our "C" plan. The follow is an out line of our conversation. I asked Tom what is going to be required for AOGCC to consider the two wells as suspended. Tom replied that bottomhole plugs of "whatever" type (meaning cement or wireline set) would be required for AOGCC to consider the wells suspended. I asked Tom if AOGCC planned to issue a letter to DEC stating what the requirements for "suspended" status would be. Tom replied that he was not sure. He stated that he and Cammy will discuss if a letter would be sent. I expressed our desire for a letter so that we could request an extension to our "C" plan based on meeting AOGCC's requirements. Tom replied that he and Cammy will discuss the need for a letter to DEC. He additionally stated that he and Cammy will be contacting Susan with DEC on Monday to discuss both the need for a letter from AOGCC as well as our extension of the "C" plan. Tom did state that he had received a verbal statement from Susan at DEC that she saw "no problem in extending the "C" plan" beyond the 22nd of October. Our conversation centered around a 4 to 6 week extension. I explained to Tom that we are working on equipment availability as well as a work timeline to accomplish AOGCC's requirements. Obviously, whatever the extension, we must have all work complete before that date. 2 of 3 2/21/02 5:01 PM NCIU wells B1 and B2 I explained that we are currently taking the following steps to address the wells: Brian Seitz is searching well records. Aras Worthington is searching for equipment and developing a timeline for availability. NSK Problem Well group is assisting in locating equipment and developing a timeline for availability. I told Tom that I would keep him abreast of our progress on a continual basis and inform him of any changes. If you have any questions, please let me know. Len Janson Office - 907-776-2046 Fax- 907-776-6246 Cell- 907-252-6748 3 of 3 2/21/02 5:01 PM THE MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED _ ON OR BEFORE 01_ P L M ATE IA L E W U N D E R TH IS M ARK E R C:LORIXMFILM.DOC 197-210-0 N CO~NLET UNIT B-02 50- 883-20090-01 PHILLIPS MD 14537 TVD 13377 ~6mpletion Date: c'2~0/98 Completed Status: SUSP Current: T Name Interval Sent Received T/C/D '~I~3R 11000-14500 OH D SCAN DATA 2/4/99 2/9/99 L AlT 3/23/98 3/25/98 L CDR-MD ~' LGR 8909-13416.6 OH 5 2/3/98 2/3/98 L CDR-MD j LGR 8909-13416.6 OH 2 2/3/98 2/3/98 L CDR-TVD ~ LGR 8142-13340 OH 5 2/3/98 2/3/98 L CDR-TVD ~ LGR 8142-13340 OH 2 2/3/98 2/3/98 L CN/LDT/GR ~/~ LGR 11000-14500- OH 3/23/98 3/25/98 L DDL-MD (~.T~,,.)~-'L~' BH(BL)8990-14537 OH 2 2/20/98 2/26/98 L DSI uJ// LGR 11000-14500 ~' OH 3/23/98 3/25/98 L FET-MD (._('g~3 c"'~BH(BL)8990-14537 OH 2 2/20/98 2/26/98 L FET-TVD~?~¢v~_.) t-~BH(BL)8123-13377 OH 2 2/20/98 2/26/98 L GR/CCL ~ LGR 12624-13007 CH 5 3/23/98 3/25/98 L GR/CCL El~- LGR 13000-13999 CH 5 2/3/99 2/9/99 L MSCT ~ LGR 13175-13956 OH 3/23/98 3/25/98 L MWDFET-MD [~.[t~ ~ BH(BL)8990-14537 OH 2 2/20/98 2/26/98 L MWD-FET-TVDI'4L/J~ ~ BH(BL)8123-13377 OH 2 2/20/98 2/26/98 L PERF 1LGR 13000-13999 J CH 5 3/23/98 3/25/98 L RELABELDSI ,.~// mR(C) 11000-13500 ~// OH 2 Daily Well Ops 1/~/./,7 -- ;l{o//q ~ Are Dry Ditch Samples Required~~no Was the well cored?/~ no ~ Analysis Description Received.~~ Comments: ~_, c. ~.~a._'.l '~ ~-~ q,,./~ 2/3/9'9 2/9/99 And Received?~; no Sample Set# ~ ~4 ~"~ Thursday, February 03, 2000 [ (3 ~i~gelofl PHILLIPS PETROLEUM COMPANY HOUSTON, TEXAS 77251-1967 BOX 1967 NORTH AMERICA PRODUCTION DIVISION BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING April 1, 199'6~ North Cook Inlet Unit "B" No 2 PPCo. Tyonek Platform North Cook Inlet Unit, Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Attn: Blair Wondzell Gentlemen: Enclosed for your consideration and approval is the Form 10-407 for the NCIU B-2 well. A final well completion diagram, daily report of well operations, directional survey, core description, perforation record, and DST report are included with this form. Should you have any questions or require any additional information, please contact Paul R. Dean at (713) 669-3502 or Raj Hingorani at (713) 669-3554. Regards, N. P. Omsberg rd North America Drilling Manager CC: J. W. Konst (w enc) W. L. Carrico (w/o enc) J. R. Soybel (w/o enc) P. R. Dean (w/enc) Central Files STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL ~ GAS ~ SUSPENDED._~ ABANDONED ~ SERVICE ~i ~ 2. NaFfle o'f Operator 7. Permit Number Phillips Petroleum Co. 97-210 3. Address 8. APl Number 6330 W. Loop South, Bellaire, TX 77401 50-883-20090-01 4 Location of well at surface 9. Unit Name 1249' FNL & 980' FWL SEC 6-T 11N-R09W North Cook Inlet Unit At Top Producing Interval 10. Well Number 1404' FSL & 536' FWL SEC 31-T 12N-R09W NCIU B-2 Sidetrack At Total Depth 11. Field and Pool 838' FSL & 653' FWL SEC 31-T 12N-R09W 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. North Cook Inlet RKB 132 ft.[ NCIU Exploration/Tyonek Deep 12. Date Spudded 13. Date T.D. Reached 14. Date Suspended 15. Water Depth 16. No. of Completions 11/21/97 01/04/1998 02/10/1998 130 Dual 17. Total Depth 18. Plug Back Depth (MD+TVD) 19. Directional Survey 20. SSSV Depth 21. Thickness of Permafrost 14537(MD), 13,377'(TVD) 14,377(MD), 13,234(TVD) YES IXi NO~ 429', 342' NA 22. Type Electric Logs Run AIT-LSS-LDT-CNL-GR, MSCT-GR, SHDT-GR 23. CASING, LINER AND CEMENTING RECORD Casing Size wt, per ft. Grade Setting Depth (MD) Hole Size Cementing Record Amount Pullc~; 30" 368 Driven 20" 169 C-70 2,602 24" Previous None 13 3/8" 72 P-110;N-80 8,909 17.5" Previous None 9 5/8" 53.5 P-110 11,086 12.25 500 sx. None 7" (liner) 32 P-110 10,738'- 13,522' 8.5" 1310 sx. None 3.5"(liner) 12.95 P-105 13522 - 14457' 8.5" 24. Perforations open to Production(MD+TVD of Top and 25. Tubing Record Bottom and interval, size, and number) Size Depth Set (MD) Packer Set (MD) 3.5" 13,530 10,600 See Attached Sheet 2 7/8" 10,626 10,600 26. Acid, Fracture, Cement Sqeeze, ETC. 27. PRODUCTION TEST Date First Production Method of Operation (flowing, gas lift, etc.) NA Temporarily abandoned (See attached DST Reports) Date of Test Hours Tested Prod. for Oil .Gas Water-BBL Choke GOR Test Period FTP Casing Pressure Calculated Oil .Gas Water-BBL Choke GOR 24 hr Rate DateofTest Hours Tested Prod. for Oil .Gas Water-BBL Choke GOR Test Period FTP Casing Pressure Calculated Oil Gas Water-BBL Choke GOR 24 hr Rate 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. Sidewall cores taken, No Sidewall Core recovery for the Sunfish sands (see attached Core Description) Form 10-407 Rev 7-1-80 Submit in Duplicate ORIGINAL 129 30 GEOLOGICAL MARKERS FORMATION TESTS Include interval tested, pressure data, all NAME MEAS. DEPTH TRUE VERT. DEPTH fluids recovered and gravity, GOR, and time of each phase. Sunfish Top 13,113' 12,087' Base 13,186' 12,153' Sunfish Test BOPD FTP (psi) #1 2774 450 N. Forelands #2 960 910 Upper Lobe (top) 13,653' 12,580' Upper Lobe (base) 13,752' 12,671' N. Forelands Middle Lobe(top) 13,818' 12,731' #1 1607 2500 Middle Lobe(bottom) 13,860 12,778' Lower Lobe (top) 13,900' 12,805' Lower Lobe (bottom) 13,977' 12,873' See Attached Report for More Details 31. LIST OF ATTACHMENTS Wellbore Diagram, DDRs, Directional Survey, Core Description, Perforation Record, DST Report 32 I hereby certify that the foregoing is true and correct to the best of my knowledge \ Signed ~ _~-'-~z¢~ Title From 10-407 Rev 7-1-80 Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Spud Date: 11/19/93 Event Name: Sidetrack Start: 11/t4/97 End: Contractor Name: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Name: Rig Number: 429 Date i FrOm To Hours SUbCO 11/21/97 !12:00- 14:00 2.003.00 MV r 00MMIR SKIDcHEcKRIGpRESSuRETO NC U B-2.ON i 14:00 - 17:00 DR ,1 00MM R 95/8" CSG 0#. CHECK PRESSURE ON 95/8" I I I ix 13 3/8" ANNULUS 0 #. RD 11" 10M x 13 5/8" 5M TBG HEAD. 17:00 - 00:00 7.00 DR I 00MMIR NU 13 5/8" 5M x 13 5/8" 10M DSA, RISER, & DOPE. 11/22/97 100:00 - 02:30 2.50 DR 1 95RNTR F NISH NU DOPE & STRIP O MAT C. '02:30 - 05:00 2.501 DR 8 i95RNTR !CLOSE BLIND RAMS & TEST STACK TO 250/5000 PSI AGAINST CSG. ~ I i I TEST ALL , ~ i CHOKE MANIFOLD, CHK LINE, KILL LINE & FLOOR VALVES TO i ' ' I i 250/5000 PSI 105:00 - 06:00 1.00 DR 2 195RNTR ~PU BIT #1 & BHA. 106:00-07:00 1.00 DR 14 !95RNTR ITIH&TAGGEDCMT@335'. 07:00 08:00 1.00 DR '5 95RNTR t ClRC OUT 40 BBLS CONTAMINATED FLUID TO APOLLO F/ I ~ I [ l INJECTION. BUILD VOLUME IN ACTIVE 08:00 - 14:00 6.00 DR I !95RNTR DRLG CMT FR/335 TO 468'. 14:00 17:30 3.50 WC z 95RNTR AT 468' PRESSURE BELOW CMT PLUG PUSHED DP 2' UP HOLE. SHUT DOWN PUMP & OBSERVE WELL - STATIC. CONT DRLG CMT I I IFR/468- 472'. CMT PLUG PUSHED DP UP HOLE 6'.-BENT 2 JTS DP. II i SHUT WELL IN. WELL STATIC, SI PRESSURES = 0. LB BENT JTS. PU i i I I j DART VALVE, I JT DP & 1 - 10' DP PUP JT. DRILLED FR/472 - 475'. [ I PIPE WAS HYDRAULICED UP 6'. CLOSED RAMS TO HOLD DP. WELL l, i i I !STILL WOULD NOT FLOW. CIRCULATE THROUGH CHOKES. OBSERVED OIL & GAS IN 117:30 - 20:00 2.50i WC !5 95RNTR RETURNS. PLUGGED ALL CHOKES. i20:00 - 23:00 3.00 WC 17 195RNTR ICLOSED HCRVALVE. BLED OFF CHOKE MANIFOLD. CLEAN OUT ! i i I HAND ADJUSTABLE, REMOVED HYD CHOKES & CLEAN OUT CMT. ' i i ND CHOKES & RETESTED MANIFOLD TO 250/5000 PSI. ;~' 23:00 - 00:00 1.00 WC i5 i95RNTR I OPEN HCR - WELL DEAD. OPEN PIPE RAMS & CIRCULATE OUT GAS ~ I J 'CUT MUD THROUGH FLOW LINE. 3100 UNITS '. I i i MAXIMUM & GAS DECREAS NG. 11/23/97 ~i00:00 - 02:00 2.00 WC 5 95RNTR ClRC OUT GAS CUT MUD. WASH DOWN TO 480'. ClRC TILL GAS ,, FELL BELOW 100 UNITS. MAX GAS 3100. 102:00 - 02:30 0.50 WC 4 95RNTR POOH, LD 10' PUP & I BENT JT DP. ATTTEMPT TO BREAK OUT I GRAY VALVE BUT FLUID UNBALANCED. 02:30 - 03:00 0.50 WC ,5 95RNTR i ClRC & COND MUD. LD GRAY INSIDE VALVE. 03:00 - 03:30 0.50, WC 4 195RNTR I POOH TO BHA TO CHECK F/BENT DP. 03:30- 05:00 1.50i WC d 95RNTR PUI JT DP & TIH TO 462', TAG CMT PLUG. WASH DOWN TO 472'. PU i ' I 95RNTR & MADE CONNECT ON. THEN TAGGED CBT @ 464'. PLUGGED BIT. 05:00 06:00 1.00I WC i z WORKED & SURGED PIPE IN ATTEMPT TO UNPLUG BIT W/NO '~ i SUCCESS. WELL STATIC- WILL NOT FLOW. CONFIRMED PLUG i t STILL @ 464'. 106:00 - 07:30 1.50j WC 4 95RNTR POOH. CLEAN CMT OUT OF BIT & BIT SUB. INST FLOAT. TIH TO i I I ~472'. DID NOT TAG PLUG. i07 30- 08:00 0.50 WC 0 95RNTR HELD PRE JOB SAFETY MEETING. 08:00 19:00 11.00 DR d 95RNTR TIH. STOP & ClRC OUT GAS CUT MUD @ 1123', 2430', 3460', 5513', . 7464'. GAS IN BOTTOMS UP PEAKING BETWEEN 3100 5513 UNITS. I ~, CONTINUED TIH TO 8314'. DRAG INCREASED TO 40K. SCREWED IN I ! ! W/TOP DRIVE & BROKE CIRC. EST ROTATION W/TOP DRIVE - ! i i TOOK 1700 PSI TO BREAK CIRC. i 19:00 - 20:00 1.00 i DR ~5 195RNTR ClRC BOTTOMS UP. 20:00 - 23:00 3.001 DR d 95RNTR WASH (ROTATING) FR/8314' - 9500'. 23 00 00:00 1.00 DR .5 95RNTR ClRC& COND MUD. 11/24/97 00:00 01:00 1.00 DR !5 95RNTR ClRC & COND MUD. PUMP DRY JOB. [01 00 06:00 5.00 DR 4 195RNTR /POOH' Printed: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 11/24/97 11/25/97 11/26/97 From To 06:00 - 06:30 06:30 - 11:00 11:00- 12:00 12:00- 16:00 16:00 - 23:00 23:00 - 00:00 00:00 - 02:30 102:30 - 03:30 03:30 - 07:30 07:30 - 08:30 08:30- 10:00 10:00 - 13:00 13:00 - 13:30 13:30 - 16:30 16:30 - 20:00 20:00 - 23:30 23:30 - 00:00 00:00 - 02:30 02:30 - 05:00 11/27/97 05:00 07:00 09:00 14:00 15:00 21:00 i22:30 I00:00 108:30 ~ 10:30 i12:00 !l 18:00 11/28/97 - 07:00 - 09:00 - 14:00 - 15:00 - 21:00 - 22:30 - 00:00 ~ 08:30 - 10:30 - 12:00 - 18:00 - 19:30 19:30 - 21:00 21:00 00:00 00:00 - 01:00 SUNFISH 000003 North Cook Inlet Unit B-2 Spud Date: 11/19/93 Sidetrack Start: 11/14/97 End: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Number: 429 Hours :: SUb~ 0.50 DR 4.50 DR 14 195RNTR ITIH TO 9500' (BROKE CIRC @ 4860'). 1.00 DR 5 !95RNTR ClRC BOTTOMS UP ( MAX GAS 180 UNITS ). SLIP & CUT DRLG LINE. 4.00 DR 14 95RNTR PUMP DRY JOB. POOH & LD BHA. 7.00 DR 4 95RNTR PU 9 5/8" EZSV BP. TIH & SET BP @ 9437'. PRESS UP & TESTED BP ~ TO 2500 PSI - OK. BROKE CIRC, MIXED & PUMPED DRY JOB. 1.00 DR 14 95RNTR POOH w/EZSV RUNNING TOOL. 2.50 DR 4 95RNTR POOH. 1.00 DR 2 95RNTR LD RUNNING TOOL F/ EZSV. MU CSG CUTTER. 4.00 FI 4 95RNTR TIH W/CSG CUTTER. 1.00 FI i 95RNTR CUT 9 5/8" CSG @ 9100'. 1.50 FI 95RNTR ClRC BOTTOMS UP & PUMP DRY JOB. 3.00 FI 95RNTR POOH W/CSG CUTTER. 0.50 FI 0 95RNTR HELD PRE JOB SAFETY MEETING. 3.00 FI 12 95RNTR PU SPEAR ASSY & 2 - 8" DC'S. ENGAGED SPEAR. PU 650K LBS ' ( CALC'D BOUYED WT OF CSG = 475K) SLACK OFF. APPLY 1000 PSI PUMP PRESS TO 9 5/8". PU 650K AGAIN & PIPE STARTED MOVING. PRESS GRADtJALLY BLED OFF BUT DID NOT CIRC. PU 60' SO THAT CUT & SLIPS WERE ABOVE ROTARY. 3.50 FI 2 95RNTR RU WEATHERFORD'S 350T SPIDER. RELEASED SPEAR, PULL ASSY ~ OUT OF CSG. LD 2 8" DC'S & FISHING TOOLS. CHANGED OUT RIG ELEVATORS & BALES F/WEATHERFORD'S TOOLS & RU POWER TONGS. MU SWAGE, LOTORQUE & CMT L NE. 3.50 0.50i 2.50 2.50] 200i 2.00 5.00 1.00 6.00 1.50 1.50 8.50 2.00 1.50 6.00 1.50 1.50 3.00 1.00 FI 5 95RNTR !PRESS TEST TO 1500 PSI - OK. BROKE CIRC WHILE PU ON CSG. I PU WT 500K. MIX & PUMP DRY JOB. FI 0 95RNTR HELD PRE JOB SAFETY MEETING PRIOR TO LD 9 5/8. FI y 95RNTR POOH, LD 9 5/8" CSG. HOLE TRYING TO SWAB WHILE PULLING. WILL NOT FILL FR/ANNULUS SIDE. PULL SLOWLY & FILL PIPE EVERY 5 JTS FR/INSIDE. FI 5 95RNTR BROKE ClRC @ 8700'. MIXED & PUMPED 40 BBL DESCO/WTR PILL. PUMPED 2 X BTMS UP @ 900 GPM. FI y 95RNTR CONTINUE POOH LD 9 5/8" CSG STILL PULLING SLOWLY & FILLING PIPE FR/THE INSIDE EVERY 5 JTS. FI 7 95RNTR ClRC CSG @ 8200'. GAS 0 - 10 UNITS. CHANGE OUT ELEVATORS, SLIPS & TONG HEADS FOR 9 7/8" CSG. FI y 95RNTR POOH LD 9 7/8" CSG. ClRC BTMS UP @ 7785'. FI 7 95RNTR CIRC & CHANGED OUT ELEVATORS, SLIPS & TONG HEADS F/9 5/8" CSG. FI - !y 95RNTR CONTINUE POOH LD 9 5/8 CSG. FI 15 95RNTR ClRC BTMS UP WHILE WORKING BOAT. FI y 95RNTR CONTINUED POOH LD 9 5/8" CSG. FI ~y 95RNTR FINISHED LAYING DOWN CSG FOR A TOTAL OF 211 JTS. FI 16 95RNTR R/D CSG TOOLS & SET WEAR BUSHING 'FI ~16 95RNTR BREAK DOWN FISHING SPEAR. FI i4 '95RNTR MU BIT & RIH TO 13 3/8" SHOE AT 8909' FI 5 95RNTR WASH & REAM TO TOP OF 9 5/8" CSG STUB AT 9100'. REAM OPEN ~ HOLE SECTION CLEAN & BACK REAM TO 13 3/8" SHOE AT 8909'. FI 5 95RNTR CBU FROM INSIDE SHOE. FI i4 95RNTR POOH TO PU CEMENT STINGER. DR 4 95RNTR FINISH POOH. Printed: 03/31/98 4:38:24 PM Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Spud Date: 11/19/93 Event Name: Sidetrack Start: 11/14/97 End: Contractor Name: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Name: Rig Number: 429 Date From To HoUrs: - SubCo ,:,~:. ;; era~oBs 11/28/97 101:00 - 02:00 1.00 DR 12 J95RNTR J LD 12 1/4" BIT & 9 - 6 1/2" DC'S. 02:00 - 04:00 2.00. CE i2 95RNTR PU 2 7/8" DIVERTER SUB & 15 JTS OF ~5 2 7/8" PAC DP. 04:00 - 07:30 3.50 CE 4 95RNTR RIH W/CMT STINGER TO 13 3/8" SHOE. 07:30 - 08:30 1.00, CE 95RNTR , BREAK CIRC & WASH TO 9200' = 100' INSIDE 9 5/8" CSG STUB. 08:30 11:00 2.50 CE 15 95RNTR !CIRC & COND MUD FOR CEMENTING. 11:00 11:30 0.50, CE 0 i95RNTR IL/D TOP SINGLE & RU HALLIBURTON. ! f i i HELD SAFETY MEETING & TESTED LINES TO 2500 PSI. ! 11:30- 13:00 1.50 CE !v i95RNTR j PUMPED 30 BBLS OF FW AHEAD OF 98 BBLS (555 SX) OF CLASS "G"' ~! W/ADDITIVES AS PER PROG AT 17.0 PPG. BALANCED W/4.3 BBLS " I FW & DISPLACED W/148.4 BBLS OF MUD. !13:00- 13:30 0.50 CE 14 95RNTR PULLED 10 STDS. 113:30- 16:00 2.50 CE '5 ]95RNTR jCIRC DP CLEAN. 116:00-20:00 4.00 CE 4 i95RNTR iPOOH&L/D27/8"STINGER. 120:00 - 22:00 2.00 RM rni95RNTR I CHANGED SWIVEL PACKING. !22:00 - 00:00 2.00 DR 8 95RNTR I PULL WEAR BSHG & SET TEST PLUG. i !TEST DOPE: U & L VB RAMS, C & K LINE VALVES/HCR'S TO I 1250/5000 PSI. ANNULAR TO 250/3500 PSI. 11/29/97 I00:00 - 04:00 4.00 WC 8 95RNTR I FINISH TESTING BOP'S. NOTE: WITNESSING OF BOP TEST WAVED i' i ' I' ~AIR WONDZEL W/AOAGCC AT 0845 HRS ON 11-26-97. HE ALSO ' [ ~ WAVED WITNESSING ANY CSG TESTS IN THIS SECTION AT 0926 ~ 4 50 I 95RNTR HRS ON 11-28-97. i04:00 - 08:30 . , RM i m CHANGED OUT BRAKE BLOCKS ON DRAWWORKS. i08:30 - 09:30 1.00 CS 19 95RNTR ATTEMPTED TO TEST CSG TO 2000 PSI. PRESSURE LEAKED OFF i I TO 1700 PSI IN 17 MIN. PRESSURED BACK UP BUT LEAK OFF ONLY i i ' I GOT WORSE. 109:30 - 12:30 3.00 RM c 95RNTR SLIPPED & CUT 119' OF DRILL LINE. REPACKED STANDPIPE VALVE. '~ i ' I REPAIRED BLADDER IN KOOMEY BOTTLE. !12:30 - 19:30 7.00 CS t :95RNTR MU 12 1/4" BIT W/CSG SCRAPER. PU 30 JTS OF HWDP W/JARS & : CONTINUE IN HOLE TO 8300'. ] 19:30 - 21:00 1.50 CS z ' 95RNTR WASH FROM 8300 - 8634'. TAGGED HARD CMT. 21:00 21:30 0.50 CS It 95RNTR ATTEMPT TO PRESS TEST CSG. APPLIED 2000 PSI BLED BACK TO , , I i ] 1800 i ' t 95RNTR PSI IN 2 MIN. WOULD NOT HOLD. i21:30 - 22:30 1.00 CS ClRC BOTTOMS UP. i22:30 - 00:00 1.50, CS ~t 95RNTR PUMP DRY JOB & POOH. 11/30/97 i 00:00 - 05:30 5.50 CStt 95RNTR POOH & LD BIT & SCRAPER. 05:30 - 09:30 4.00 CS 95RNTR PU RTTS TOOL & CIRCULATING VALVE. TIH & SET RTTS AT 4100'. i ' ~ i (DV TOOL AT 4045'). ¢09:30 - 10:00 0.50 CS it 95RNTR TEST BACK SIDE TO 2000 PSI FOR 15 MIN. OK. 10:00- 12:15 2.25 CS It 95RNTR i RIH W/RTTS & SET SAME AT 7415'. (DV TOOL AT 7385"). 12:15 - 13:30 1.25J CS t 95RNTRiTESTED BACK SIDE (DV TOOL AT 7385'), TO 2000 PSI PRESSURE ~ BLED TO 1500 PSI IN 10 MIN. PRESS BACK TO 2000 P~I. PRESS I ~ FELL TO 1550 PSI IN 7 MIN & LEVELED OFF. PRESS BACK UP TO 2200 PSI. PRESS FELL TO 1750 PSI IN 6 MIN & LEVELED OFF. ! , I I I PRESS BACK UP TO 2200 PSI. PRESS BLED OFF TO 1750 PSI IN 6 ] ! I MIN AGAIN & LEVELED OFF. PUMPED 6.5 BBLS& BLED OFF 6.0 J t i EELS. 1750 PSI = 14.5 EMWAT 13 3/8" SHOE & 15.3 PPG EMWAT , I I i THE DV TOOL. PRESSURED DOWN DP TO 2000 PSI. GOOD TEST ON ~ I I I LOWER CSG. BLED OFF PRESSURE. 113:30 - 17:00 I 3.501 CS It 95RNTR RELEASE & POOH W/RTTS. LB SAME. I Pdnted: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 11/30/97 12/01/97 12/02/97 12/03/97 12/O4/97 From - TO 17:00 - 19:30 19:30 - 00:00 00:00 - 01:00 01:00 - 08:00 08:00 - 09:45 09:45 - 00:00 00:00 - 05:00 05:00 - 07:30 07:30 - 08:00 08:00 - 11:00 11:00 - 18:00 18:00 - 22:00 22:00 - 00:00 00:00 - 00:00 00:00 - 02:30 02:30 - 04:30 04:30 - 05:30 05:30 - 08:00 08:00 - 10:00 10:00 - 23:00 SUNFISH 000003 North Cook Inlet Unit B-2 Spud Date: 11/19/93 Sidetrack Start: 11/14/97 End: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Number: 429 Hou rs 'SUb Cd:' P:ha~,::: .C~d~ i; .'i i BeSC~iPti~ ~[: ~era~i~ :..: ::.~ .: ::: : : f :::::::::::::: :::::: ................... ::: :: ~;::; ............................ ::::::::::::::::::::::::::::::::::::::::::::::::::::::: :: ::::: ::::::::::: ::: ::: ::!':. ,':'i~'.:':::':.".:.":::'.'~ : '" ::.:...:i". ~-:'.;'.' '.':i,i:.:'?...:. :':':: : :.:: "..:'::..'.i 2.501 DR 4.50 DR 1.00 CE 7.00 CE 1.75 DR 14.25 DR 5.001 DR 2.50 DR 0.50 FT 3.00 DR 7.00 DR 4.00 DR 2.00 DR 24.001 DR 2.50 DR 2.00 DR 1.00 DR 2.50 DR 2.00! RM 13.00 DR 4 4 h W W W JZ id 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR PU HYCALOG "STEERING WHEEL" PDC BIT & STEERABLE BHA W/A SLICK 9 1/2" EXP MOTOR SET @ 1.5 DEG. TIH. FINISH TIH W/PDC BIT & STEERABLE BHA. DRILLED HARD CMT F/8640' TO 13 3/8" SHOE AT 8909'. CONTINUE DRILLING CMT F/8909' TO KICK OFF POINT AT 8970'. ORIENTING & SLIDING WHILE TIME DRILLING TO KICK OFF F/8970' TO 9003'. ONLY 20% FORMATION IN RETURNS AT REPORT TIME. CONTINUE SLIDING WHILE TIME DRILLING TO KICK OFF WELL F/9003' TO COAL AT 9014'. RETURNS WENT F/40% FORMATION TO 100% COAL. GAS WENT F/8 UN TS TO 29 UNITS. DRILLED 5' MORE TO 9020'. . CBU PRIOR TO LEAK OFF. GAS RUNNING 18 UNITS BACK GROUND WHERE IT HAD BEEN 8 UNITS. LARGE COAL CHUNKS OVER SHAKERS. WITH BIT INSIDE 13 3/8" CSG AT 8909'MD (8123'TVD), & W/10.5PPG MUD, PERFORMED LEAK OFF TEST. LEAK OFF PRESS = 905 PSI = 12.6 EMW TRANSFERRED MUD F/PITS TO APPOLLO FOR INJECTION DUE TO HIGH PH OF MUD & SLIPPED & CUT 153' OF DRILL LINE. CLEANING PITS IN PREPARATION FOR BUILDING OIL BASE MUD. OPERATION SLOWED DUE TO APPOLLO'S LIMITED INJECTION RATE OF CUTTINGS & WASH WATER. MIXED & PUMPED 30 BBL SPACER. TRANSFERRED & BUILT 300 BBLS OF OIL BASE MUD IN RIG PITS TO 11.0PPG. BEGAN DISPLACEMENT BY PUMPING 300 BBLS OF 11.0 PPG OIL BASE MUD & TAKING RETURNS TO APPOLLO FOR INJECTION. WILL HAVE TO DISPLACE HOLE IN 300 BBL BATCHES DUE TO LIMITED PIT SPACE & APPOLLO'S ABILITY TO INJECT RETURNS FAST ENOUGH. CONTINUE BUILDING 300 BBL BATCHES OF OIL BASE MUD TO 11.0 PPG & DISPLACING HOLE WHILE TAKING RETURNS TO APOLLO FOR DISPOSAL. HAD TO SHUT DOWN SEVERAL TIMES BECAUSE APOLLO NEEDED TIME TO THIN & DISPOSE OF THE WATER-BASE MUD. MUD RETURNS STILL THICK & CONTAMINATED W/ i WATER-BASE MUD. Build oil-base mud & displ out contaminated water-base/oil-base mud. Apollo having to work at dealing w/thick mud. MW 10.7#. Mud returns became better while circ oil-base mud & screens working OK at 750 gpm. Washed to bottom. Had I spot right below shoe taking weight, then cleared up. Took 15,000# wt at 8980'. Picked back, then went back down thru spot w/no wt. WIH to TD 9020'. Started drilling. Rotated 20', then slid. Screens became unable to handle pump rate due to thick contaminated mud. Pulled one screen f/end of one shaker. Drilled to 9039' but DP screen & pump suction plugging up w/ coal. Put 10 mesh screen back on & cleared pump suction. Attempt to drill but blew pop off valve on # 1 mud pump 3 times. Repaired same. Drilling directionally f/9039' to 9,256' MD (8,441' TVD). Total sliding time 5 hrs; rotating time 11-1/2 hrs. Last survey at 9156' MD: 22.83 deg incl, Pdnted: 03/31/98 4:38:24 PM Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Spud Date: 11/19/93 Event Name: Sidetrack Start: 11/14/97 End: Contractor Name: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Name: Rig Number: 429 Date 12/04/97 !10:00- 23:00 13.00 DR q 95RNTR 351.06 deg azimuth. ~123:00 - 00:00 1.00 DR 7 95RNTR Rep ac ng pump impe ers on Apo os cutt rigs inject on equ p. Unab e to i take any more drilling cuttings from hole (everything full). Pulling bit up i into casing. Worked tight spot off bottom until free. ~ 95RNTR 12/05/97 00:00 - 09:00 9.00~ DR 17 Repairing Apollo drill cutting injection equip. Had to replace one pump i i [ (impeller was broken into several pieces) & change motor on another. !I i !Changed shaker screens during repairs & did rig maintenance. 09:00 - 12:00 3.00 DR d 95RNTR WASH & REAM F/CSG SHOE TO TD. LAST 100' VERY TIGHT. i STARTED MW UP TO HOLD OPEN COALS, 10.3-10.6. 112:00 - 00:00 12.00 DR I q'I95RNTR I DRLG F/9256' TO 9429' HAVING TO SLIDE MORE BECAUSE RATE I ~ OF ANGLE DROP IS INSUFFICIENT (1 DEG INSTEAD OF 2-1/4 DEG). i I 'GOT STATE PERMISSION TO FOREGO TRIP OUT FOR JUST THE i~ BOP TEST, DUE FRIDAY, UNTIL NECESSARY TO TRIP OUT OR i I I UNTIL REACH CASING DEPTH. SLIDING TIME = 7 HRS, ROTATING !,I I HOURS = 5. LAST SURVEY = 12/06/97 00:00 - 09:00 9.001 DR Iq 95RNTR Drilling. Had tight spot at 9442' while sliding - rotated thru spot until free. Increasing MW to 11.0# while drilling. Press tested BOP manifold & I safety valves while drilling. Drilled to 9,751'. 12 hrs sliding, 12 hrs i ~ rotating. Had large chunks of coal to surface occasionally. MW 11.0 ppg. 12/07/97 i 00:00 - 15:00 15.00 DR qm 95RNTR Drilled directionally from 9,751' to 9,898'. 115:00 - 17:00 2.00 RM 95RNTR REPAIRED LEAK IN DISCHARGE MODULE FLANGE. 17 00 - 20:30 3.50 DR ,q 95RNTR DRLG F/9898' to 9928'. MOSTLY SLIDING TO DROP ANGLE. 1,20:30 21:30 I 1.00 RM m 95RNTR Changed #1 pump swab. 121:30 - 00:00 2.50 DRq 95RNTR Drld from 9928' to 9949'. Today's sliding time = 16 hrs, rotating time = 5 ~ ~ hrs. 12/08/97 i00:00 - 08:00 8.001 DR !q 95RNTR i Directional drilling (mostly sliding) from 9,949' to 9,996'. Fixed leaking i I I Ipump valve cover gasket twice (15 min + 10 min) Drilling became slow .50 i after 02:00 & motor began stalling too easily. Did OK rotating. · 08:00 - 19:30 11 . DR I p 95RNTR Backream to shoe. very tight all the way. CBU. POOH for mud motor ~ I I and/or bit. Blair Wondzell w/AC&GCC, at 08:00 12/7/97, gave permission I 3'001 to test BOPs w/o AC&GCC rep to witness. Bit still looked OK. 119:30 - 22:30 DR 8 95RNTR Weekly BOP test perf PPCo specs: 250# Io/5000# hi, except Hydril 250# [ i ~ I 1ow/3500# hi. ' .50 ~ ' i22:30 - 00:00 1 RM i3 95RNTR i Service top drive. Check brushes in motor. Prep to MU directional BHA i I~ lw/new mud motor & bit. 12/09/97 100:00 - 06:00 ' 6.00i DR i2 95RNTR MU DIRECTIONAL BHA W/NEW MOTOR & BIT. TESTED MWD & I I I ;MOTOR 1 HR. ~ 95RNTR i 06:00 - 11:30 5.501 DR 14 RIH TO CSG SHOE AT 8909'. 11:30 - 15:00 3.501 DR ~p 95RNTR HAD TO WORK & REAM THROUGH COALS TO BTM W/NEW BHA. !' 15:00 - 16:00I~ 1.00 . DR Iz 95RNTR SAME.UNABLE TO DRILL DUE TO BALLED UP BIT. WORKED TO UNBALL ~16:00 - 00:00t 8.00 DR q i95RNTR DRILLING FROM 9996' TO 10,095'. PUMPED 30 BBLS OF 30 PPB MED ' i ~ ~ NUT PLUG TO CLEAN BIT. 2.2 HRS SLIDING, 5 HRS ROTATING 7,.2 ' i t !95RNTR TOTAL DRILLING TIME. 12/10/97 00:00 - 00:00 I 24.00! DR lq 10,307'. Last Survey at 10179.23' = 2.08 deg, azm 74.72, TVD 9340.69' I - starting to make turn toward South. Actual sliding time 12.6 hrs, rotating ! ! ~ 18.6 hrs. 2.8 hrs connections, backreaming, orienting & change shaker 00:00- ' q 95RNTR Drilling directionally. 12/11/97 05:15 05:15 ~I 5.251 DR jscreens. - 06:00 I 0.75i RM i m 95RNTR Change pump swab. 06:00 15:30 I 9.50JDR q 95RNTR Drilling directionally to 10409'. ! 15:30 - 16:30 I 1.001 RM i m 195RNTR I#1 mud pump cap gasket leaking. Repair w/epoxy. ' ' I I' 16:30 - 17:00 il 0.50 il DR q 95RNTR Drill to 10415'. Printed: 03/31/98 4:38:24 PM Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Spud Date: 11/19/93 Event Name: Sidetrack Start: 11/14/97 End: Contractor Name: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Name: Rig Number: 429 -! Hours Date i From To 12/11/97 17:00 - 18:30 1.50 RM . m 95RNTR #1 mud pump cap leaking. Welded washed out area in cap. i 18:30 - 20:30 2.00 DR iq 95RNTR Drilled to 10,435'. Low ROP except in coal section. 120:30 - 00:00 3.50 DR i4 ! 95RNTR Trip for bit; backreaming out of open hole. Had tight & or sticky spots at I I ! 95RNTR !9839', 9700-9751', 9606-9652', & 9526'. 12/12/97 00:00 - 11:00 11.00 DR 4 POOH backreaming. Was very tight 9166' - 9076". Backreaming very i I I slowly. Very tight at 9106'. Finally worked up to csg shoe at 8909'. I J4 Pumped weighted hi-vis sweep. 11:00- 13:00 2.00 DR 5 95RNTR Circ at casing shoe. 13:00 17:00 4.00 DR 95RNTR POOH. Ii17:00 20:00 3.00 DR 2 95RNTR LD bit. Change MWD. Test motor & MWD. PU 12-1/4" previously used , PDC bit. 20:00- 23:45 3.75 DR i4 95RNTR GIH to casing shoe. 23:45 00:00 0.251 RM j c 95RNTR Cut drill line. 12/13/97 00:00 - 03:00 3.00! RM lc 95RNTR Cut drill line. Serviced top drive. i03:30 - 08:00 4.50i DR 4 95RNTR Go in open hole. Had several tight places same as when POOH. 08:00 - 10:00 2.001 DR id ~95RNTR Wash 60' fill to btm. 10:00 00:00 14.001 DR q 195RNTR I Drilling from 10,435' to10,594' (9752' TVD). 4.4 hrs sliding time, 8.2 hrs I ! t I rotating time. 12/14/97 i00:00 - 00:15 0.25i DR la1 95RNTR At 10,594' while sliding, motor stalled in minor 2' coal section. When att to i I J pick up, was stuck. Worked loose. 00:15 - 09:30 9.251 DR q 95RNTR Drilled to 10,694'. 09:30 10:00 0.501RM m 95RNTR Changed pump valve cover gasket. J 10:00 - 20:15 10.251 DR q 95RNTR Drilled to 10,821' i20:15 - 20:45 0.501 RM m 95RNTR Repair leaking valve cap gasket. 20:45 - 21:30 0.75 DR q 95RNTR Drilled to 10,825'. 21:30 - 23:00 1.50 RM m 95RNTR Changed liner on #2 pump 23:00 - 00:00 1.00 DR q 95RNTR I Drilling at 10,834' MD (9,986' TVD). ' 95RNTR ISliding time 7 hrs, rotating time 13-1/2 hrs. !00:00 - 14:30 14.50 DR lq I Directionally ddlled from 10,834' MD (9986' TVD) to 10,975'. 12/15/97 i I ., · I BOP weekly test due Sunday: received AO&GCC, Blair Wondzell, ' i I permission to forego test until after run casing. I14:30 - 15:00 0.50 RM m 95RNTR Change swab on #1 mud pump. 15:00 16:00 1.00 DR iq 95RNTR Drill to 10,985' i 16:00 - 16:30 0.501RM m 95RNTR #1 pump swab change. 16:30 - 00:00 7.50! DR ~q 95RNTR Drilling, now at 11,039' MD (10,180' TVD). Rotate 13 hrs, slide 10 hrs. 12/16/97 00:00 02:00 2.001 DR q 95RNTR Directionally drilled from 11,039' MD - 11051' 102:00 - 02:30 0.50 RM m 95RNTR Pump repair, change cap gasket. i 02:30 - 05:30 2.00 DRq 95RNTR Drlg 11051' - 11088' MD (10,226' TVD) 05:30 - 07:00 1.50 DR ,z 95RNTR Lost MWD signal & 200 psi. Check surface equipment & cycle pumps i several times. Did not find problem. 1 07:00 - 13:30 6.501 DR 14 95RNTR i Backream out of hole into csg shoe @8909' Slight torque in a few spots, / i overall no problems as seen on previous trip. ' ! 4 113:30- 14:00 f 0.50 DR 15 95RNTR Mix & pump slug. !14:00 - 20:00 I 6.00 DR 95RNTR POOH laydown Anadril equipment, 2 dcs, mwd, Iwd/cdr, lead collar, i motor, & bit. Stabilizer on motor 1/4" out of guage. Drill bit 1/16" out of guage. Blades were worn back app 2" from od of bit. I ' I ***NOTE: Blair Wondzell waived testing BOP until after run csg. Also i i 1 .00 waived witness of csg & cmt job. 12/15/97 1700 hrs. 20:00 - 21:00 i , CS i z 95RNTR Clean rig floor. Pull wear bushing. Pull iron roughneck track. ,21:00 - 23:00 i 2.001 CS 11 95RNTR RU Weatherford 9-5/8" casing handling tools. 23:00- 23:30 0.501 CS 0 95RNTR Safety meetings. ~23:30 00:00 0.50 CS ~ 1 95RNTR Begin picking up 9-5/8" 53.50# P-110 BTC intermediate casing ! i ! threadlockding float equip. I Printed: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/17~97 SUNFISH 000003 North Cook Inlet Unit B-2 Spud Date: 11/19/93 Sidetrack Start: 11114197 End: POOL ARCTIC ALASKA Rig Release: 04~02~94 Group: Rig Number: 429 From - To Hours I :: 00:00 - 21:30 I 21:30 - 23:00 23:00 - 00:00 00:00 - 00:30 00:30 - 02:30 02:30 - 03:00 03:00 - 03:30 [ 03:30 - 04:00 04:00 - 06:00 06:00 - 09:00 09:00 - 12:00 12:00 - 00:00 00:00 - 01:30 01:30 - 06:00 06:00- 15:00 15:00- 19:00 19:00 - 21:30 21:30 - 00:00 00:00 - 00:30 00:30 - 03:00 03:00 - 07:30 07:30 - 13:00 12/18~97 12119~97 12~20~97 13:00 - 13:30 13:30- 14:00 14:00- 15:00 15:00 - 16:00 6:00 - 17:00 21.50 CS 95RNTR Continue running 9-5/8" 53.50# P-110 BTC intermediate casing, total 261 jts tag td @11088' Crc & cond. I RD Weatherford fillup tool. RU Halliburton cementing head. 1.50 CS 1.00 CS 0.50' CS 2.00 CE 0.50 CE 0.50 CE 0.5O CE 2.00 CE 3.00 WC 3.00 WC 12.00 WC 1.50 WC 4.50 DR 9.ooi wc 4.ooi wc 2.50 WC 2.50, DR 0.50 DR 2.501 DR 4.50 DR 5.50 DR 0.50 DR 0.50 DR 1.00 DR 1.00 DR 1.00 DR 8 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR 95RNTR '95RNTR i FINISH RU CEMENT HEAD. I ClRCULATE PRIOR TO CEMENTING. I HELD PRE JOB SAFETY MEETING. TEST LINES TO 2500 PSI - OK. PUMPED 20 BBLS DIESEL FOLLOWED BY 50 BBL 13 PPG WB SPACER AHEAD OF CMT. MIXED & PUMPED 106 BBLS - 500 SX CL "G" CMT & ADDITIVES MIXED AT 15.8 PPG. DROP PLUG & DISPLACED WITH 3 BFW FOLLOWED BY 766 BBL OBM & ANOTHER 14.3 BBL FW. PUMPED 3.25 BBL OVER CALCULATED & DID NOT BUMP PLUG. BLED PRESS OFF, FLOATS HELD. HAD GOOD RETURNS THROUGHOUT JOB. 95RNTR WOC...MONITOR WELL FOR FLOW ON TRIP TANK...WELL STATIC. 95RNTR . DRAIN STACK & ND RISER/BOP STACK. 95RNTR PU STACK & SET SLIPS ON 9 5/8" CSG (STRG WT = 440K DOWN) SET 350K ON SLIPS. CUT OFF 9 5/8" CSG. INST'D 11"10M X 13 5/8" 10M FMC TBG SPOOL. TEST BETWEEN SEALS TO 4500 PSI F/15 C MIN - OK. 50PRDR ITEST CHOKE MANIFOLD, IBOP, FLOOR VALVE, UPPER KELLY VLV & IBOP TO 250/8000 PSI. 50PRDR LD 6 5/8" HWDP & 8" JARS THROUGH MOUSE HOLE. 50PRDR NU RISER, BOP STACK, BELL NIPPLE, STRIP-O-MATIC ETC. 50PRDR RU & ATTEMPT TO TEST CSG. FLANGE ON DSA LEAKED @ 3200 PSI. TIGHTENED FLANGE & TESTED CSG TO 5000 PSI - OK. TESTED BOP STACK: RAMS & VALVES 250/8000 PSI. TESTED HYDRIL TO 250/3500 PSI. BLOW OUT CHOKE MANIFOLD, CHOKE & KILL LINES. START PU BHA. PU XP MOTOR, CDR & MWD. PROGRAM CDR. SURF TEST MWD & CDR @ 500 GPM - OK. FINISH TESTING MWD & CDR. PU 5" HWDP TIH. TAG CEMENT PLUG @10734' DRILL CEMENT PLUG @10734' CON'T DRLG CEMENT TO FC @11030' DP MEAUREMENT & SHOE @11080'. TD @11088' CIRCULATE DRILL 11088'- 11098' 10' NEW FORMATION. CIRCULATE FOR FIT. PULL INTO CSG. PERFORM FIT. PUMPED AS FOLLOWS: 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR BBLS PUMPED PRES. 0.5 200 4.5 1150 1.0 200 5.0 1390 1.5 225 5.5 1560 2.0 300 6.0 1710 2.5 500 6.5 1850 3.0 700 7.0 2000 3.5 900 7.5 2150 ~4.0 1080 8.0 2320 TVD = 10234' = EMW @16.2# DRLG. SLID FR/11098 - 11106' Printed: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date From - To 12/20/97 12/21/97 16:00 - 17:00 17:00- 18:00 18:00 - 00:00 00:00 - 06:00 06:00 - 08:00 08:00 - 13:30 13:30 - 16:00 16:00 - 17:00 17:00 - 18:00 18:00 - 00:00 00:00 - 00:30 00:30- 12:00 12:00- 13:00 13:00 - 13:30 13:30 - 18:30 18:30 - 20:00 20:00 - 00:00 00:00 - 01:30 01:30 - 02:00 02:00 - 02:30 02:30 - 00:00 SUNFISH 000003 North Cook Inlet Unit B-2 Spud Date: 11/19/93 Sidetrack Start: 11/14/97 End: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Number: 429 Hours SUb,,Co i .i ::.D~iP~i~of ~ra~io~ i.:: DR q 50PRDR ROTATE FR/11106 - 11109'. 12/22/97 ! 00:00 - 02:30 i 02:30 - 08:30 108 30 - 10:30 10:30 12:00 i 12:00 - 12:30 !12:30 - 17:00 117:00 - 18:30 118:30 - 19:30 12/23/97 12/24/97 1.00 1.00 DR 6.00 DR 6.00 DR 2.00 RM 5.50 DR 2.50 DR 1.001 DR 1.001 RM 6.001 DR 0.501 DR 11.50 DR 1.00 DR 0.50i DR 5.00! DR 1.50t DR 4.00 DR 1.50 DR 0.50 RM 0.50 DR 21.50 DR 2.50 DR 6.00 DR 2.00 DR 1.50' RM 0.50 DR 4.50 DR 1.50 DR 1.00 DR i7 i50PRDR q 150PRDR I q q 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR ANADRILL SURFACE COMPUTOR PROBLEM. DRILLING FR/11109 - 11177'. ROTATE SLI DE 11109- 11118' 11118 - 11137' 11137 - 11165' 11165 - 11177' DRILLED (ROTARY) FR/11177 - 11212'. MUD MOTOR FAILED...P-RATE DECREASED, PUMP PRESSURE ERRATIC, NOTED DIFFERENTIAL PRESS DECREASE & FOUND STATOR RUBBER ON SHAKERS. PULL INTO 9 5/8" CSG. CBU WHILE SLIP & CUT 97' DRILL LINE. POOH. LD MWD & MOTOR...PU NEW MWD & MOTOR. PROGRAM MWD & SURFACE TEST SAME - OK. SERVICE RIG. TIH, FILLED PIPE @ 3885', 7621' & 10998'. CONTINUE TIH, WASH TO BTM @11212' NO PROBLEMS. SLIDING & ROTARY DRLG 11212'- 11366'. LAST 40' DRILLED, TOP DRIVE STALL NG . MOTOR NOT STALLING. 50PRDR t BACKREAM INTO CSG. SLIGHT PULL WHEN ANDERGUAGE I STABILIZER PULL INTO CSG. LOWER DP, SHUTDOWN PUMP TO RELAX STABILIZER & PULL INTO CSG WITHOUT PROBLEM. 50PRDR PUMP SLUG. BLOW DOWN TOP DRIVE. 50PRDR POOH. 50PRDR BROKE OFF BIT. BIT WAS IN GOOD CONDITION. INSPECTED ANDERGUAGE STAB & LD SAME. ORIENT MOTOR W/MWD & !DOWNLOAD MWD. RERAN BIT RIH ON 3 STDS HWDP & SURFACE TESTED MWD/CDR - OK. 50PRDR TIH. 50PRDR FINISH TIH TO 9 5/8" SHOE. 50PRDR SERVICE TOP DRIVE, GREASE SWIVEL PACKING. 50PRDR FINISH TIH. 50PRDR DIRECTIONAL DRILLING FR/11366 TO 11594'. SLI DE ROTATE 11366-11371'(.5 HR) 11371-11374'(1HR)I1374-11475'(8.5H R) 11475-11476'(1HR)I 1476-t 1571 '(4.5H R) 11571-11574'(1HR)11574-11582'(1 HR) 11582-11594'(2.5HR) DRLG (SLID) FR/11594- 1623'. DRLG (RTRY) FR/11623 - 11723'. BACKREAM TO 9 5/8" SHOE. CBU WHILE SLIP & CUT DRILL LINE. PUMP DRY JOB. BLOW DOWN TOP DRIVE. POOH. LD BIT & MOTOR. (NOTE: PIECE OF MOTOR SLEEVE STABILIZER 2" X , 9" MISSING) DOWNLOAD MWD. CLEAN RIG FLOOR. PU NEW BIT & MOTOR. RIH W/MOTOR, CDR & MWD ON 2 STD 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR Printed: 03/31/98 4:38:24 PM :: :: ~-~-.'_ .'.'-~' "-~.- :...7: · ":' ". :' '..'.'. :'.-: .'.' .':"" .'- .::.. · .' '.. · .' '- - . "..' -~:.. Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Spud Date: 11/19/93 Event Name: Sidetrack Start: 11/14/97 End: Contractor Name: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Name: Rig Number: 429 : i : :: : ~ ..... ~ - Hours: Sub:Co Phase~ Dede ~ : ~:::. ~; ~:.:~Des~npt[~n of~Qpera~[~ns Date i From To : :;:; ~':~:':'~;~ :' ; 12/24/97 18:30- 19:30 1.00 DR 9 50PRDR HWT & SURFACE TEST MWD. 19:30 00:00 00:00 4.50 DR 4 50PRDR TIH TO 9 5/8 SHOE. 12/25/97 01:00 1.00~ DR 4 50PRDR FINISH TIH. (NOTE: STILL HAD TIGHT SPOT IN 9 5/8" FR/10940 - i 10960') !01:00- 13:00 12.00 DR q 50PRDR DRLG (RTRY) FR/11723 - 11800'. 13:00 - 19:00 6.00 DR 4 50PRDR BACKREAM 1 STD OOH. POOH (WET) TO 9 5/8 SHOE. PUMPED DRY ~ JOB THEN FINISHED POOH. 119:00 - 20:30 I 1.50 DR i2 50PRDR LAY OUT BIT, MOTOR, CDR & MWD. 120:30 - 00:00 3.501WC 8 50PRDR PULL WEAR BSHG & RAN TEST PLUG. TEST BOPE. TESTED ALL i I RAMS, CHK/KILL LINES & VALVES, FLOOR VALVES & IBOP TO I ! 250/5000 PSI. TESTED ANNULAR TO 250/3000 PSI. TESTED CHK I i MANIFOLD TO 250/5000 PSI WHILE POOH. PULL PLUG & RERAN ' i I WEAR BSHG. 12/26/97 00 00 - 03:00 3.001 DR 2 50PRDR PU NEW BIT & BHA. SURF TEST MWD. 03:00 03:30 0.501 RM 3 50PRDR SERVICE TOP DRIVE & GREASE SWIVEL. 03:30 08:30 5.001 DR4 50PRDR TIH. WASH LAST STD TO BTM (NO FILL). 08:30 16:00 7.501 DR iq 50PRDR DRILL (RTRY) FR/11800 - 11941' BLEW VIBRATOR HOSE #1 MUD I,~ PUMP. RESUME DRLG W/¢¢2 PUMP ONLY THEN BLEW VIBRATOR I 4m HOSE ON # 2 PUMP. 16:00 - 17:00 1.001 DR 50PRDR POOH TO 9 5/8 SHOE. 17:00 - 19:00 2.00t RM 50PRDR REPLACE VIBRATOR HOSES. 119:00 - 20:00 1.00~ DR 4 50PRDR TRIP BACK IN HOLE. i20:00 - 00:00 12 50 DR iq 50PRDR DRLG (RTRY) FR/11941 - 12002'. NOTE: DRLG W/#2 PUMP ONLY i 4'001 ~ LOST ELECTRIC POWER TO #1 PUMP...NOW EFFECTING REPAIRS. 12/27/97 i 00:00 - 12:30 ' DR lq 50PRDR ROTARY DRLG FR/12002 - 12265'. 112:30 - 13:30 1.001 DR q 50PRDR DRLG (SLID) FR/12265 - 12269'. 113:30 - 14:00 0.501 DR q 50PRDR ROTARY DRLG FR/12269 ~ 12279'. i14:00 - 14:30 0.50 DR q 50PRDR [DRLG (SLID) FR/12279 - 12280'. 114:30 - 16:00 1.50 DR q 50PRDR ROTARY DRLG FR/12280 ~ 12345'. !16:00 - 16:30 0.50 DR q 50PRDR ATTEMPTED TO SLIDE W/NO SUCCESS @ 12345'. 116:30 - 00:00 7.50 DR q 50PRDR ROTARY DRLG FIR/12345 ~ 12504'. NOTE: INCREASED MOTOR i DIFFERENTIAL & SLOWED TD ROTARY 12/28/97 00:00 - 00:00 24.00 DR q 50PRDR !DRILLED (ROTARY) FR/12504 - 13032'. 12/29/97 00:00 - 00:00 24.00 DR iq 50PRDR ROTARY DRILLING FPJ 13032 - 13233'. 12/30/97 i00:00- 11:30 11.50t DR q 150PRDR 'DRILLED (RTRY) FR/13233 - 13320'. j 11:30 - 12:00 0.501 RM 3 ! 50PRDR SERVICE TOP DRIVE & GREASE SWIVEL. 12:00 - 22:30 10.50 DR q 50PRDR DRILLED (RTRY) FR/13320 - 13418'. · 22:30 00:00 1.501 DR p i50PRDR BACKREAM OOH TO 12674'. 12/31/97 00:00 02:30 2.50 DR p :50PRDR BACKREAM FR/12674 - 11080' (9 5/8 shoe) 02:30 - 04:00 I 1.50 RM c i50PRDR BIRC BU WHILE SLIP & CUT DRLG LINE PUMP DRY JOB. ~ 3 ' 04:00- 04:30 i 0.50i RM 50PRDR SERVICE RIG. 04:30- 10:00 I 5.50 DR 14 50PRDR FINISH POOH. 10:00 - 12:00 i 2.00, DR 12 50PRDR LD I JT HWDP. DOWNLOAD CDR. LD MOTOR. 112:00- 12:30 ~ 0.50 DR '0 50PRDR CLEAN RIG FLOOR. i12:30 - 17:00 4.50 WC8 50PRDR MU TEST JT. PULL WEAR BUSHING & SET TEST PLUG. TESTED ~ RAMS, CHOKE/KILL LINE & VALVES 250/5000 PSI. HYDRIL 250/3000 f . I PSI. TESTED FLOOR VALVES, IBOP ETC TO 250/5000 PSI. RETRIEVE I !i I I ITEST PLUG & RAN WEAR BUSHING. BLAIR WONDZEL I t i AOAGCC WAIVED WITNESS OF BOP TEST @ 08:20 HRS 12/30/97. !17:00-19:00 ! 2.00iRM 32 50PRDR i CHANGED OIL IN TOP DRIVE & ADJUST I I RAISED BACKUP SYSTEM. 19:00-21:301 2.50 DR '50PRDR MU NEW BIT & MOTOR. ORIENT&PROGRAMMWD. TIHTO250'& i! i i SURFACE TEST. ~ I I Printed: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 12/31/97 01/01/98 01/02/98 01/03/98 01/04/98 SUNFISH 000003 North Cook Inlet Unit B-2 Spud Date: 11/19/93 Sidetrack Start: 11/14/97 End: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Number: 429 From- To Hours SUb¢O'B~i ~od~.:::i'-: .i:ii:':: ::~..:i'...:i.i.:~":'::::~.7 :~.De~CriPtioi~f?.~p 21:30- 00:00 2.50 DR !4 50PRDR TIH TO 3880'. 00:00- 04:00 4.00 DR !4 50PRDR Fin tripping into hole. 04:00-05:30 / 1.501 DR p 50PRDR IReamed 13,329'to 13,418', OK. Had 199 units tripgas. 05:30 - 21:45 16.25 DR Iq 50PRDR I Drilled to 13,728'. 21:45 - 23:45 2.00 DR 5 50PRDR Had sudden 1846 units gas to surface w/ temporary flow rate increase i 5 bbl pit gain. SI. No press. Check flow- no flow. Circ out gas. Gas I decr to 150 units, then back to 1050 units, then 200-800 units, then 250-600 units, then 350 units. 23:45- 00:00 0.25 DR I 50PRDR Drilling at 13,735', 300-400 units gas. 00:00 - 04:30 4.50 DR q 50PRDR Drilled to 13,813' MD (12,758' TVD). 04:30 - 11:00 6.50 DR 5 50PRDR Had sudden 1800 units gas at surface - had gas at shakers & at rotary. i SI. Had approx 50 psig. Circ thru choke 15 min, gas decr to 1400 units. 11:00 - 00:00 00:00 - 03:30 03:30 - 04:00 04:00 - 00:00 00:00 - 21:30 21:30 - 00:00 00:00 - 08:30 08:30- 12:00 12:00- 13:30 13:30 - 19:00 19:00 - 20:00 20:00 - 00:00 00:00 - 01:30 01:30 - 03:30 03:30 - 04:30 04:30- 10:00 10:00- 12:30 12:30 - 00:00 00:00 - 02:00 02:00 - 03:00 03:00 - 07:00 07:00 - 08:00 08:00 - 08:30 08:30 - 09:00 09:00 - 13:30 13:30 - 16:30 16:30 - 19:30 19:30 - 00:00 13.00 3.50 O.50 2O.O0 21.50 2.50 8.50. 3.50 1.50. 5.5oi 1.001 4.00i 1.50 2.00 1.00 5.50 2.50 11.50 2.00 1.00 4.00 1.00 0.50 0.50 4.50 3.00 3.00 4.50 7.00 DR ,q RM DR DR RM ~ im DR q LG 4 LG 5 LG 4 LG LG DR DR LG LG LG LG LG LG LG RM RM LG CS RM CS 'CS RM 01/05/98 01/06/98 01/07/98 01/08/98 00:00 - 07:00 lB 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 50PRDR 150PREV 50PREV 50PREV 50PREV 50PREV 50PRDR 50PRDR 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PREV 50PRRC 50PREV 50PREV 50PREV 50PREV Open. Circ out flowline. Gas would not drop out. Incr MW to 14.5 ppg & gas steadily decr to 550-700 units. Drilling. Background gas gradually decr to less than 300 units & steady. Last survey at 13,824' = 24.65 deg at azm 168.4 deg. Show report 13,665' - 13,840' MD: sandstone/conglomerate. Drilled from 14,007' to 14,043'. Changed pump swab. Drilling. Now at 14,278' MD (13,146' TVD). Drilled from 14,278' to 14,439' MD t (13,290' TVD) . Repair top drive. While making connection, could not break out saver isub. Pipe handler torque wrench hydralic cylinder rod broke. Drilled from 14,439' to 14,537' MD (13,377' TVD). Circ 30 min. Short trip to 13,418'. GIH, no fill. Circ btms up, max gas 199 units, normal 115 units. Backreamed up to casing shoe at 11,088'. Hole was slick - no problem areas. Circ btms at shoe. Slug DP. POOH. LD jars. Stand back HWDP. Laying down directional tools. Stand back HWDP. LD 2 DCs, MWD, CDR, mud motor, & bit. Remove subs from floor. Removed torque wrench cylinder rod from top drive. Clean floor. RU Schlumberger logging unit. Ran Quad-Combo logging tools (115' OA length). Logger's TD 14,510'. Logger's casing shoe 11,078'. LD quad-combo. PU sidewall cores. Taking sidewall cores. Attempted 23. POOH w/Schlumberger after running quad-combo log. LD quad-combo tools. PU Dipmeter log. Ran Dipmeter log to 13,800'. Was taking weight. Logging up to 13,200'. Hung up. Worked loose after pulling 5000# over 5 times. POOH. Install pipe handler parts & adjust. Service top drive Clean Schl tools off beaver slide. GIH PU tooth bit & three 6-1/2" DCs. Troubleshoot pipe handler. Will not release. GIH to 11,039' (near btm of 9-5/8" casing). Circ & cond mud. WO parts & repairman for pipe handler & WO 7" pipe ~ram for BOPs (none found in Alaska). Top drive torque wrench hydraulic lines plugged w/trash. Flushed lines. Printed: 03/31/98 4:38:24 PM Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Spud Date: 11/19/93 Event Name: Sidetrack Start: 1 1/14/97 End: Contractor Name: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Name: Rig Number: 429 ~ : : :i:: ....t ' ;' ~' ~::.' i ::::;.';.' "6~':. i" ': i:'.! k=~.~:'.~'. :':': ~i.. ~?:':. '.~:;':;';: '-;~:~ =='~ :'"":,::~ ~i" ..'~::~.~;~..~.~.~.;'!;~: ~:~....'i · ;''.:: Date From - To Hours: Sub:Ce;: P:base nof:.~@~8~on~ ;; 01/08/98 f oo:oo - 07:00 7.00 RM~mi 50PREV Cut drill line. 07:00-09:00[ 2.00[ be ii 50PREV WIN to TD 14,537' OK. 09:00 11:00 2.001LG 50PREV Circ & cond mud. Max gas 453 units. ~ 11:00 - 15:30 4.50' LG 50PREY POOH backreaming to shoe. No tight places. 1.00 LG 50PREV Circ. Slug DP. 15:30 - 16:30 16:30 21:00 4.50 LG 4 50PREV POOH. 21:00 21:30 0.50 LG 6 50PREV Clean floor. ,21:30 00:00 2.50 LG 2 50PREV MU Schlumberger MDT tool & test. Prep to run in hole on DP (no DCs or I jars). 01/09/98 100:00 - 06:00 6.00 LG 7 50PREV Schlumberger troubleshooting MDT tools - not operating properly. LD I MDT tools. 06:00 - 18:30 12.501LG 1 50PREV MU RFT tool & ran in on WL. Tool failure. POOH & RD RFT tools. ,18:30 21:30 3.00, LG 1 50PREV MDT tools working perfectly at surface. Start making up to GIH. Checked ' t OK until last section or two, then would not work. RD Schl. Tested choke ~ ! manifold 250/5000 psi while Schl checking tools. I 21:30 - 00:00 2.50 CS 'z 50PREV Drain stack of OBM mud to trip tank & Apollo. Pull wear bushing. 01/10/98 00:00 10:00 10.00 CSz 50PRRC Monitor well. Drain stack. Clean rig floor. Clear top deck for test tanks. I I I Put casing tools on rig floor. Pre-test Hydril & lower pipe rams, OK. i10:00 - 17:30 7.50 CS 8 50PRRC Changed top pipe rams to 7". Tested BOP 250/5000 psi, hydril 250/33500 i' 6 50I psi. Install wear bushing. Move HWDP in derrick. i17:30-00:00 . cs . 50PRRC i Ran 29 jts 3-1/2"12.95#, PH-6, P-110prodliner&PBR. Now running 7" ' 2.50 1 ! liner casing. 01/11/98 00:00 - 02:30 CS 50PRRC Safety meeting. Ran 66 jts 7" 32# P-110 BTC casing on top of 29 jts ~ i~ 3-1/2" tubing. i02:30 - 04:30 2.00 CS 16 50PRRC Changed handling too s from 7 to 3-1/2'. RU false rotary. NU !i. Weatherford torque analysis computer. i 4.50 i04:30 - 09:00 I CS I 50PRRC IRan 87 jts 3-1/2" 12.95#, PH-6 P-110 tubing w/seals inside 7" liner ] I casing. 109:00 - 12:00 3.00 CS [1 50PRRC Space out 3-1/2" to install liner hanger - sub had galled threads. Obtain t ' new sub. Install liner hanger. 12:00- 13:30 1.50 CS 6 50PRRC RD casing handling tools 13:30 19:00 5.50 CS I 50PRRC GIH on DP to 9-5/8"shoe. 119:00 - 20:00 I 1.00 CS 5 50PRRC I Circ DP & tbg volume. 120:00-22:30I 2.50 CS I i50PRRC GIH to14,473'. FilIDP. 22:30 00:00I 1.50, CS 5 ~50PRRC WIH to 14,500'. Circ & work pipe. Unable to get back down below ~ ! 14,450'. 01/12/98 00:00 - 02:00 2.00. CS 5 50PRRC Circ. Safety meeting. Driller was working pipe up to 14,457' & then pipe would not go back down. 02:00-03:00 1.00i CEI iz II 50PRRC Drop ball. RU cementing head. Press DP to 3100# , slack off 20,000# to I i [ i set liner hanger at 10,752'. Shoe at 14457'. Release running tool w/ 03:00 ~ 6 I 4550#. - 06:30 3.50i CE 50PRRC Pump 10 bbl diesel. Test lines. Pump 15 bbls spacer. Hallib mixed 1310 I I I sx "G" cement + 0.2% CFR-3 + 0.13 gfal/sk Haled 344Lk + 0.25% HR-5. ! I ~ Began displacing w/oil based mud. Had good returns until had displaced i w/90 bbls mud (150 bbls in annulus), then lost full returns of mud. Press ~ ~ i begain icreasing. Was 3760 psi at 4-1/2 bpm, then had 5700 psi at 2.5 i ! ! bpm, then 5700 psi at 1.7 bpm just before bumping plug w/213 bbls OBM. i i [ Still no returns.. Bumped plug w/6400#. After 5 minutes, was 6160# , I i i Bled off press (5 bbls), then floats held. 106:30 - 09:30 3.00! CE [ 1 50PRRC Att to pull 3-1/2" seals from PBR. Unable to pull. Worked pipe, then ' I i begain to get small amount of returns, then good returns. Pulled ' I 345,000# on string & came loose. 09:30 - 12:00 , 2.50 CS 6 50PRRC Set wt down to set Halliburton packer. LD cementing head. Pump pill. Printed: 03/31/98 4:38:24 PM Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Spud Date: 11/19/93 Event Name: Sidetrack Start: 1 1/14/97 End: Contractor Name: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Name: Rig Number: 429 Hours Su Date i From - To 01/12/98 "12:00 - 15:30 3.50 cs i4 50PRRC POOH w/7" casing handling tool - Did not have 3-1/2" wash string. Had ! ' i broken off "slick stick" in running tool. I; 15:30 - 17:00 1.501 CS !6 50PRRC Removed csg tools & cement head from rig floor. 117:00 - 22:00 , 5.00 CS 18 50PRRC Change top pipe rams to 3-1/2' x 5" variables & tested ~ were leaking. 22:00 - 00:00 2.00 CS 8 50PRRC Blow down & drain stack. Chang ng to new 3-1/2" x 5" pipe rams. · 00:00 01:00 1.00 FId 80CMPL Test variable pipe rams 250/5000#. Install wear bushing. 01/13/98 . 01:00 - 08:00 7.00 FI 80CMPL LD drlg jars from derrick. Clean platform pits for completion fluids. '~08:00 - 12:00 4.00 FI ~ 80CMPL Offload fishing tools from workboat. PU BHA to washover fish. TIH I i w/same. !12:00- 14:00 2.00 FI i4 80CMPL TIH to 10764' break circulation. 114:00 - 17:00 3.00 FI d 80CMPL Tag top of fish @10764' dp measurement. Washover fish from 10764'- I 10816'. Had to wash entire length of fish, recovered cement as washing. , I 17:00 t 4 Washover assy would not go over fish without rotating & pumping. - 21:15 4.25 FI 80CMPL POOH wi wash assy - shoe was approx 60% worn. 0.50. FI2 80CMPL LD shoe. PU cut-lip guide & outside cutter, 5-7/8" OD x 4-7/8" ID. '21:15 - 21:45 21:45 00:00 2.25 FI 4 80CMPL GIH w/cutter. 01/14/98 00:00 01:30 1.50 FI 4 80CMPL WIH wi mechanical outside cutter on washpipe to 10,810' 101:30 - 04:00 2.50 FI x 80CMPL Rotating while slowly easing upward to feel the way into a tool joint. Cut I ?4 tbg @10793' ,04:00- 08:00 4.00 FI 80CMPL Pooh 108:00 - 09:00 1.00 FI 80CMPL LD fish. Recovered tbg collar, xo sub, pup it., xo sub, swivel, xo sub, 2 - 3 I I 1/2" pups, + 2.29' of 3 1/2" tbg. total 28.64' New TOF @10793' i ,09:00 - 11:00 2.00 FI 2 80CMPL PU new washover shoe & 3 more jts of washpipe, i 11:00 - 16:00 5.00 FI 80CMPL TIH TO TOF @10793' BREAK CIRC. '1. 6:00 - 17:00 I 1.00!i FI ! d 80CMPL WASHOVER FISH FROM 10793' - 10943' ROTATE BY 3 TBG TOOL ~' i JTS & DIDNOT HAVE TO ROTATE BY LAST TOOL JT. INDICATIONS ! ' OF VERY LITTLE IF ANY CEMENT. !17:00-18:00 1.00 FI 15 80CMPL CBU i18:00 - 19:00 1.00 FI iz 80CMPL lOUT DRLG LINE. WHILE FINISHING CBU. 19:00 - 23:00 4.001 FI 14 80CMPL !POOH. 23:00 00:00 . 1.001 FI i2 80CMPL . LD JARS, BUMPER SUB, 4 3/4" DC & 2 JTS WASH PIPE. 01/15/98 00:00 04:30 4.50 FI !4 80CMPL MU OVERSHOT ASSY & TIH. EST CIRC & LATCHED ONTO FISH 10793'. KICKED OUT PUMP AS PRESS INCR'D WHEN WORKED I I I O/SHOT OVER F SH. 04:30 - 05:30 1.00! FI a 80CMPL JARRING ON FISH. PU WT 240K. STARTED JARRING W/340K LBS. , INCR'D PULL TO 450K PRIOR TO SETTING OFF JARS. PULLED TO ! I 475K AFTER HITTING JARS @ 450K TWICE WHEN FISH CAME FREE. I lyy ATTEMPT TO EST CIRC W/NO SUCCESS. 105:30 - 14:00 8.50 FI 80CMPL POOH W/FISH (WET). PU 1 - 4 3/4" DC TO STAND BACK STAND. LD i OVERSHOT ASSY. 14:00 - 20:30 6.50~ FI 80CMPL LD 87 JTS OF 3 1/2" PH-6, 22 JTS OF WHICH WERE FULL OF CMT. LD !,i0 8' SEAL ASSY. .20:30- 22:30 2.00 FI z2 80CMPL CLEANED RIG FLOOR. 122:30 - 23:30 1.00 FI 80CMPL PU OVERSHOT & CUT OFF JT. BROKE DOWN ASSY & LD SAME. i23:30 - 00:00 0.50 FI 80CMPL PREPARE TO RUN 6" MILL, 7" SCRAPER & PU 3 1/2" PH-6 TBG. 01/16/98 i00:00 - 05:00 5.00 CM 2 80CMPL PU 6" MILL, 7" SCRAPER & 89 JTS OF 3 1/2" PH-6 TBG. RD W/FORD'S L I ' TBG TONGS. 05:00 - 09:30 4.50 CM 4 80CMPL TIH W/MILL, SCRAPER ASSY ON 5" DP TO TOP OF 3 1/2" LINER. EST ! ~ ' CIRC. WASH TO TOP OF 3 1/2". TAGGED I t 3 1/2"@ 13525'. 09:30- 15:00 5.50 CM 15 80CMPL CIRCULATE & CONDITION MUD. ~15:00 - 19:00 4.00i CM '4, 80CMPL PUMP SLUG & POOH W/5" DP 119:00 20:30 1.501 CM,~ 180CMPL RU WEATHERFORD'S TBG TONGS & FINISHED POOH W/3 1/2" TBG. I Printed: 03/31/98 4:38:24 PM Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Spud Date: 11/19/93 Event Name: Sidetrack Start: 11/14/97 End: Contractor Name: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Name: Rig Number: 429 Date From - To Hours SUb60~Ph~ ~6~' .:; : D'~iPti~f:::~era~i~i~ o1/16/98 01/17/98 01/18/98 19:00 - 20:30 1.50 CM 20:30 - 21:00 0.50 WC 21:00 - 00:00 3.00 WC 00:00 - 03:00 3.00 ! CM 03:00 - 04:30 1.50 CM 04:30- 09:30 5.00 CM 09:30 - 10:00 0.50 CM 10:00 - 11:00 1.00 CM 1.00 CM 1.00 CM 8.00 CM 1.50! CM 1.50 CM 2.00 CM 5.00 CM 3.50' CM 2.50, GM 1.001 RM 4.001 CE 5.00 CE 1.00 CE 6.5O CE 4.50i LG 2.00 CE 7.50 CM 0.5O CM 1.00 CM 2.00 CM 2.50 CM 11:00- 12:00 12:00 - 13:00 13:00 - 21:00 21:00 - 22:30 22:30 - 00:00 00:00 - 02:00 02:00 - 07:00 07:00 - 10:30 10:30 - 13:00 13:00- 14:00 ~ 14:00 - 18:00 i 8:00 - 23:00 ! 23:00 - 00:00 i00:00 - 06:30 '06:30 - 11:00 I 1:00-13:00 ,13:00 - 20:30 i20:30 - 21:00 121:00 - 22:00 122:00 - 00:00 00:00 - 02:30 01/19/98 01/20/98 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL i80CMPL 80CMPL 80CMPL ;80CMPL 80CMPL LD 2 JT TBG, SCRAPER MILL & XO. DRAIN STACK. PULL WEAR BUSHING & SET TEST PLUG. TEST BOP'S. HYDRIL 250/3500 PSI, RAMS, HCR'S, MAN VALVES & IBOP TO 250/5000 PSI. PULL TEST PLUG & RAN WEAR BUSHING. ( NOTE: TESTED FLOOR VALVES & CHOKE MANIFOLD TO 250/5000 PSI WHILE POOH. PU 19 JTS 1.25" TBG + 2.125" DRLG MTR. TIH W/SAME. TEST DRLG . MTR, OK. RU TBG TONGS FOR 3.5" TBG & TIH W/SAME. TIH W/5" DP FILLING PIPE EVERY 30 STDS. TAG TOP OF 3 1/2" LINER. FILL DP TO BREAK CIRC. TBG PRESSURE TO 4500#. BLEED OFF PRESSURE. TRY 2ND TIME & EST ClRC 2 BPM @2700# AS LOWER NTO 3 1/2" L NER. ATTEMPT DRILL CMT IN 3 1/2" LINER. DID NOT SEE DIFFERENTIAL PRESSURE ON MOTOR. WORK & ATTEMPT SEVERAL TIMES. J ClRC & MIX SLUG. SERVICE RIG, CLEAR RIG FLOOR & PUMP SLUG. POOH (WET) W/5" DP & 3 1/2" TBG. POOH, LD I 1/4" CS HYD TBG & 2 1/8" MOTOR. NOTE: ClRC SUB HAD A BLOWN RUPTURE DISC IN REVERSE ClRC PORT. HELD PRE JOB SAFETY MEETING, CONCERNING CHANGING OUT TBG HEAD. PRESSURE TESTED CSG/LINER LAP TO 2500 PSI - OK. CLEAN RIG FLOOR. BLOW DOWN BOP STACK. RETRIEVE WEAR BSHG. ND TBG SPOOL & LIFTED STACK. REM'D FMC TBG SPOOL. NOTE: NAT'L SPOOL REQUIRED MODIFICATION IN ORDER TO NU DSA ON TOP OF IT. INSTALL 11"10M X 13 5/8"5M NAT'L TYPE DP-7 DUAL TBG SPOOL. TESTED BETWEEN SEALS TO 4500 PSI - OK. RUN TEST PLUG. TESTED BREAK ON STACK TO 5000 PSI. PULL TEST PLUG & RUN WEAR BSHG. SLIP & CUT DRILL LINE. RU SCHLUMBERGER UNIT, LUBR & PACKOFF. TEST SAME TO 1000 PSI. MU & RAN CET...TOOL CHECKED OUT ON SURFACE... FAILED DOWN HOLE. !RU & NOW RIH W/CBL. FINISHED RUNNING CBL. TOC @ 12000' APPROX 1100' ABOVE UPPER SUNFISH PERF, BOND LOOKS GOOD. RERAN DIPOLE SONIC LOG. RD SCHLUMBERGER. PU SEAL ASSY W/O SEALS, TIH ON 30 STDS 3 1/2" PH-6 TBG & 114 ~STDS 5" DP. PU 20' DP PUP & SINGLE DP, RU CMT HOSE. ,EST CIRC. TAG TOP OF 3 1/2" LINER @ 13524'. STING INTO TIE i BACK EXT 4' iWHEN STINGER TOOK WT. PULL STINGER UP & RESUME CIRC'G. MIXING PREFLUSH SPACERS & INJECTING OBM TO PREPARE TO ~ DISPLACE OBM. FINISHED MIXING SPACERS. Pdnted: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 01/20/98 01/21/98 01/22/98 FrOm - To 02:30 - 03:00 03:00 - 05:30 05:30 - 09:30 09:30 - 00:00 00:00 - 00:00 00:00 - 02:00 !02:00 - 09:00 109:00 - 11:00 ! 11:00 - 14:00 14:00- 16:30 16:30 - 18:30 01/23/98 01/24/98 18:30 21:00 00:00 02:00 04:00 06:30 10:00 12:00 13:00 14:00 - 21:00 - 00:00 - 02:00 - 04:00 - 04:30 - 10:00 - 12:00 - 13:00 - 14:00 - 17:30 17:30 - 00:00 00:00 - 01:00 01:00 - 02:00 02:00 103:30 05:00 09:00 10:30 11:00 14:00 21:30 22:00 - 03:30 - 05:00 - 09:00 - 10:30 - 11:00 - 14:00 - 21:30 - 22:00 - 00:00 SUNFISH 000003 North Cook Inlet Unit B-2 Sidetrack POOL ARCTIC ALASKA Start: 11/14/97 Rig Release: 04/02/94 Rig Number: 429 Spud Date: 11/19/93 End: Group: Hours SubCo ~ ~ 0.50 CM i 80CMPL 2.50l CM 80CMPL 4.00 CM 14.50 CM 24.00 CM 2.00 CM 7.00 CM 2.00 CM 3.00, OM 2.50~ CM 2.OO OM 2.50 OM 3.00! OM 2.00 CM 2.00 CM 0.50 CM 3.50 CM 2.001 GM 1.001 OM 1.001CM 3.501 wc 6.5O CM 1.00 CM 1.00 CM 1.50 CM 1.50 CM 4.00 CM 1.50 CM 0.50 CM 3.00 CM 7.50 CM 0.50 CM 2.00 CM lo 4 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 75CRSR 75CRSR 75CRSR 75CRSR 75CRSR 75CRSR 75CRSR 75CRSR 75CRSR 80CMPL 80CMPL 80CMPL 180CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL !HELD PRE JOB SAFETY MEETING. i PUMPED SPACERS AS FOLLOWS: 150 BBL DIESEL, 50 BBL WT'D VISCOUS BARACLEAN SPACER, 50 BBL CACL W/BARACLEAN & 50 BBL VISCOUS CACL W/BARACLEAN. DISPLACE OBM & SPACERS. PUMPED 960 BBLS 10.5 PPG CACL BRINE. APOLLO DISPOSING XS MUD, SPACERS & EMULSION. CLEAN PUMP LINES & ACTIVE MUD PITS. APOLLO DISPOSING OF WASTE. REMOVE WINDWALL TO ACCOMODATE CTU. OFFLOAD CTU FR/ BOAT. PARTIALLY RU SAME. CLEAN UP OIL BASE MUD MESS. CLEAN PITS, MUD CLEANING EQUIPMENT & CIRCULATING SYSTEM. WASHING RIG & PLATFORM. FINISH CLEANING PITS, CHK LINE, STACK & FLOW LINE. RU CTU 7 MIX 200 BBL CACL BRINE. FILL CT W/CACL BRINE. TESTED TBG & BOP'S TO 4500 PSI. RIH W/1 5/8" CMT MILL, 2 1/8" MACH I MOTOR, ClRC SUB & 3 WT BARS. RIH & TAGGED UP @ 13530'. DRILLED OUT TO 14360'. ClRC @ 1.6 BPM & WORK PIPE UNTILL RETURNS CLEANED UP. POOH (PUMPING) W/CT. BLOW DOWN CT SPOOL W/N2. RD CTU. HELD PRE JOB SAFETY MEETING. PULL SEAL ASSY ABOVE 3 1/2". FLUID U-TUBING. ClRC TO BALANCE FLUID. PRESS TESTED CSG TO 3500 PSI. POOH W/5" DP. REPLACE WIND WALLS ON PIPE RACK SIDE OF RIG FLOOR. POOH W/30 STDS 3 1/2" TBG. LD 3 - 4 3/4" DC'S FROM DERRICK. PULL WEAR BSHG. SET TEST PLUG. TEST RAMS, CHK/KILL VALVES, HCR'S, FLOOR VALVES, ETC TO 250/5000 PSI. TESTED HYDRIL TO 250/3500PSl. PRESSURE TESTED CHOKE MANI FOLD TO 250/5000 PSI WHILE POOH. NOTE: BLAIR WONDZELL W/AOAGCC WAIVED STATE WITNESS OF BOP TEST 13:45 HRS 1/21/98. PULL TEST PLUG & RAN WEAR BUSHING. 'PU BLANK SEAL ASSY & TIH ON 3 1/2" TBG & 5" DP. 11695' @ MIDNIGHT. TIH W/PBR PLUG ASSY. BROKE CIRC @ LOW RATE. STING INTO PBR (SHUT DOWN PUMP) DROP BALL, LET IT FALL 15 MIN. SET 20K DOWN ON PLUG ASSY !TO SHEAR OFF. APPLY 1000 PSI & PU OFF PLUG. FLUID U-TUBING. ClRC TO BALANCE FLUID. SPOT 2 SX SAND W/30 BBL HI-VIS PILL & 205 BBL CACL BRINE. POOH W/DP. RU PWR TONGS & HANDLING TOOLS F/3 1/2". POOH W/30 STDS 3 1/2" PH-6 TBG. RD TONGS ETC. HELD PRE JOB SAFETY MEETING. PU TCP ASSY & TIH W/3 1/2" TBG. FINISH TIH W/TCP ASSY ON DP. i HELD PJSM. RU SCHLUMBERGER. RIH W/GR FOR Printed: 03/31/98 4:38:24 PM Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Spud Date: 11/19/93 Event Name: Sidetrack Start: 11/14/97 End: Contractor Name: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Name: Rig Number: 429 Date ~i FrOm - To Hours 01124198 22:00- 00:00 2.00 GM ~r 80CMPL DEPTH CORRELATION. 01/25/98 .il00:00 - 01:30 1.50 CM ~ q 80CMPL SCHLUMBERGERpooH & RD SCHLUMBERGER.CORRELATED RA SUB W/IND LOG DATED 114198. 01:30 - 03:00 1.50 CM q 80CMPL !PU HEAD PIN & CMT HOSE. SET PKR @ 13059' DPM. PRESS UP ON ] ANNULUS TO 300 PSI, OPEN BY-PASS & OBSERVE P - DROP· 03:00 - 04:30 1.50i CM iq i GOCMPL PUMPED 171 BBLS DRILL WTR INTO DP TO REDUCE HYD HEAD. i SET DOWN & CLOSED BYPASS. 04:30 - 06:00 1.50 i CM , q 80CMPL MIX 30 BBL 4 PPB XANVIS POLYMER PILL. RU TO REV CIRCULATE. ! ! I iTEST LINES TO 3000 PSI. 106:00 - 08:00 2.00i CM q 80CMPL I PRESSURE UP ON ANNULUS SLOWLY. ! GUNS FIRED @ 1750 PSi. PERF'D 7" OPPOSITE SUNFISH SAND WI 4 i 1518" GUNS LOADED @ 12 SPF. NO PRESSURE INCREASE ON DP. ~ REVERSED OUT 2 DRILL VOLUMES. NO OIL OR GAS IN RETURNS, I I LOST 12 BBb 08'00 i CACL BRINE WHILE ClRC'G. · - 11:30 3.50 CM 5 80CMPL ATTEMPTED TO SPOT POLYMER PILL THRU DP. PLUGGED BYPASS I ~ IN CHAMP PKR. OPEN RD CIRC'G VALVE & SPOTTED 30 BBL [ i i POLYMER PILL ACROSS PERFS. i 11:30 - 12:00 0.50 WC g 80CMPL OBSERVED WELL FOR FLOW - STATIC. 112:00 - 19:00 7.00 CM4 80CMPL POOH W/TCP ASSY. .119:00 - 20:00 1.001 CM 2 80CMPL LD TCP ASSY. ALL SHOTS FIRED. 120:00 - 22:00 2.00i CM 2 80CMPL CLEAN RIG FLOOR. MU FISHING ASSY. i22:00 - 00:00 2.00 i CM4 t G0CMPL TIH W/OVERSHOT TO RETRIEVE PER PLUG. 01/26/98 00:00 04:00 J G0CMPL FINISH TIH W/OVERSHOT. RU TO REVERSE CIRC. 14:~) OM ~ ESTREVOIRO@7.6BPM, 1500PSI. REVERSED OUT 2 DRILL 104:00 - 05:30 1 CM 80CMPL STRING VOLUMES. LATCH UP PER PLUG. PRESS INCR'D. SD PUMP. I FLUID U-TUB NG UP DP. (NO LOSSES OBSERVED, SOME GAS I ! 2.00 DURING BU ON 1ST ClRC) !05:30 - 07:30 CM 5 80CMPL I RD REV ClRC HOSE, ETC. EST ClRC CONVENTIONAL & ClRC TO , BALANCE FLUID. ,07:30 - 08:30 1.001WC g 80CMPL SAT BACK DOWN WITH OVERSHOT A coUPLE OF TIMES. I ~ OBSERVED WELL FOR FLOW - WELL STATIC. !08:30-11:001 2.50 OM 4 80CMPL POOH W/OVERSHOTASSYTO10752'. 111:00 - 12:00 RM c 80CMPL SLIP & CUT DRILL LINE. 5.00 CM .4 80CMPL FINISH POOH W/OVERSHOT ASSY. ~ 12:00 - 17:00 17:00 - 18:30 I 1.50. CM 2 80CMPL LD FISHING TOOLS & PER PLUG. 18:30 - 19:00 0.501WC 14 80CMPL TIH W/15 STDS 5" DP. 19:00 - 21:00 2.00 RM 3 80CMPL SERVICE RIG & TOP DRIVE. CLEAN RIG FLOOR. REPAIR LIGHTS IN I DERRICK. 21:00 - 22:30 1.50 WC 6 180CMPL MU STORM PKR & SSC VALVE R H ON 3 STDS. SET PKR@ 274'. ' 50! !80CMPL 'POOH & LD SETTING TOOL. 22:30 - 00:00 I 1. WC 6 START CHANGING VB RAMS TO DUAL RAMS & MU TEST JTS. 01/27/98 00:00 03:00t 3.00 WC e 180CMPL i FINISHED CHANGING PIPE RAMS TO DUALS FOR 3-1/2" AND 2-7/8" I I ' I ! TUBING. 03:00 - 04:00 1.00 WC 12 i GOCMPL I RIGGED UP 3-1/2" AND 2-7/8" TEST JTS AND RIGGED UP BOP TEST I I i iUNIT. i 104:00 - 04:30 0.50 WC 8 80CMPL TESTED DUAL PIPE RAMS W/3-1/2" AND 2-7/8" TUBING TO 25015000 I " ~PSI, TESTED OK. 04:30 - 05:00 0.50 WC 2 80CMPL , RIGGED DOWN BOP TEST UNIT AND TEST JTS. ~,05:00 06:00 1.00 WC 4 180CMPL TIH W/5" DRILL PIPE AND SCREWED INTO STORM PACKER AT 274'. i06:00 - 07:00 i 1.00 WC4 180CMPL POOH AND LAYED DOWN HALLIBURTON STORM PACKER. {07:00-08:00 ! 1.00 CB 6 80CMPL i RIGGED UP WEATHERFORD POWER TONGS AND TOOLS TO RUN / i ' I i J 3-1/2" TUBING. . Printed: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 01/27/98 01/28/98 01/29/98 01/30/98 01/31/98 02~01/98 02/02/98 02/03/98 SUNFISH 000003 North Cook Inlet Unit B-2 Spud Date: 11/19/93 Sidetrack Start: 11/14/97 End' POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Number: 429 From- To H°Urs 08:00 - 08:30 0.501CM 14 i 08:30 - 15:00 6.50 CM 1 15:00 - 19:00 19:00 - 00:00 00:00 - 00:00 00:00 - 00:00 00:00 - 18:00 18:00 - 00:00 00:00 - 03:30 03:30 - 10:00 10:00- 12:30 12:30 - 17:00 17:00 - 17:30 17:30 - 00:00 00:00 - 03:00 103:00 o 11:00 '11:00- 14:00 114:00 - 17:00 ~ 17:00 - 17:30 ~17:30 - 20:00 20:00 - 00:00 00:00 - 03:00 03:00 - 20:00 4.00 CM 5.001CM 24.00! CM 24.001 (gM 18.00 CM 6.00 CM 3.50 CM 6.50 CM 2.50 CM 4.50 CM 0.50 CM 6.50 CM 3.00 CM 8.00 CM 3.00 CM 3.00i CM 0.501 OM 2.50[ CM 4.00 CM 3.00 CM 17.00 CM 4.00 CM 17.00 CM i20:00 - 00:00 00:00 - 17:00 1 4 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL i80CMPL 80CMPL 80CMPL ,80CMPL PICKED UP BAKER 4.0" OD SEAL ASSY. W/8 SEAL SEGAMENTS AND LOCATOR SUB. TIH W/30 STDS. OF 3-1/2" TUBING FROM DERRICK. BROKE EA. CONN. AND INSTALLED SEAL RING, MADE UP AND RETORQUE CONN. PICKED UP HALLIBURTON 9-5/8" DUAL PACKER ASSY. RIGGED UP WEATHERFORD DUAL TOOLS TO RUN 3-1/2" AND 2-7/8" DUAL TUBING STRING. RUNNING 3-1/2" AND 2-7/8" DUAL TUBING STRING. Cont to run 3-1/2" & 2-7/8" dual prod strings simultaneously & installing gas lift mandrels as required. Continue running 3-1/2" x 2-7/8" dual production strings; approximately 1700' left to run. All gas lift mandrels in hole. Fin running dual prod strings. Running w/1/4" SS control line on each string above SCSSV's. Tested control lines & SCSSV's: 7000 psi on long string & 5000 psi on short string. Sting into PBR at 13,534'. Spacing out strings for hanger. Spaced out both strings. WIH wi hanger just above tubing head. Circ biocide to anls. Drained BOP stack. Landed tubing & hung in tubing head. Had indication o 6' of seals going into PBR. Att to press test 3-1/2" tubing (long string) to 6000 psi. At 2500 psi, seals pumped out of PBR. Att to press 3-1/2" tbg to 500 psi - would not hold. PU tubing & restung into PBR. Press 3-1/2" tbg to 500 psi & it held OK. Pulled & added 2.8' pup jt to each string. Stung into PBR & hung tbg strings in tubing head. Had 156,000# (w/o blocks) slack off string wt before stung in & 145,000# when hung off. Weight on seal Iocator at PBR = 11,000#. Press tested 3-1/2" long string 1500 psi, OK. Press tested SCSSV 1500 psi, OK (had less bleed-off volume above SCSSV than when bled off full string. RU Hallib slick line unit. Ran 2.45" OD gauge ring. Set down temporarily at some GL mandrels, then worked thru easily. Set down at 13,580'. Had to work 15 times before would start going down hole. Worked from '13580' down to 14,052'. Now POOH. 'Hallib slickline POOH w/2.45" gauge ring. Ran 2.25" x 25-1/2" perf Idummy to 14.052' OK. POOH. RD off long string. RU on short string. Run 2.25" gauge ring. Run plug & set in "XN" nipple at 10,624'. ! Press test long string 4000 psi, OK. Press short string (2-7/8") to 2400 psi i to set dual packer. Test short string SCSSV 1500#. i Slick line pulled "XX" plug. i Press test anls 1500 psi 30 min, OK. i Back out & pull landing joints. Close both SCSSV's. Install BPV's in both i strings. Nippling down BOP stack. ] Nippled down BOP stack & riser. NU Kvaerner Naetional dual 3-1/2" tree. Test flange - would only hold 5500 psi. PU tree & replace seal collar. Tested 10,000 psi, OK. Install blind flange & actuator valves Test tree 250/5000 psi 10 minutes OK. NU 3-1/2" flanged riser onto short string section of tree up to rig floor. Tested 250,5000 psi, OK. Halliburton continuing to RU well test lines & equipment. Continued RU Halliburton well test equipment. Printed: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 02/03/98 02/04/98 02/05/98 From - To 17:00 - 23:30 23:30 - 00:00 00:00 - 03:00 03:00 - 04:00 04:00 - 05:00 05:00 - 06:30 06:30 - 07:30 07:30 - 08:00 08:00 - 10:00 10:00 - 13:30 13:30 - 15:00 15:00 - 16:00 16:00 - 19:30 19:30 - 21:00 21:00 - 23:30 23:30 - 00:00 00:00 - 01:00 01:00 - 05:00 05:00 - 07:00 07:00- 12:00 12:00- 16:00 16:00 - 18:30 SUNFISH 000003 North Cook Inlet Unit B-2 Sidetrack POOL ARCTIC ALASKA HOurS 6.50 0.50 3.00 1.00 1.00 1.50 1.00 0.50 2.00 3.50 1.50 1.00 3.50 1.50 2.50 0.50 1.00 4.00 2.00 5.00 4.00 2.50 Spud Date: 11/19/93 Start: 11/14/97 End: Rig Release: 04/02/94 Group: Rig Number: 429 CM CM CM CM CM CM CM CM CM CM CM CM CM CM CM CM CM CM CM CM CM LG 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL i80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL RU coil tubing unit & fin RU test equip. Filling lines prior to testing well test equip & coil tubing. Pressure testing well test equip & coil tubing 150 Iow/5,000 high. Safety meeting w/rig crew, coil tubing, well testing, production. WIH w/1.5" coil tbg to 4333' coil tbg depth, unable to get past gas lift mandrel. Start jetting w/nitrogen 300 scf/min, unloaded 2.875" tbg & tbg reel, 43 bbls. Reduced hyd pressure from estimate of 6000# to 5000#. Well will not flow. Pooh w/coil tbg. Installed 1.75" X 8' stiff circulating tool on btm of coil tbg. Ran in hole w/coil tbg to 8000' no problem going thru gas lift mandrels. Jetting @500 scf/min w/700# pressure slowly increasing w/very little fluid recovery. Work coil tbg up hole to 7000' @500 scf/min. Fluid recovery increasing & coil tbg pressure decreasing. Recovered 116 bbls oil & wtr(60% oil), with 50# wellhead pressure. RIH w/coil tbg to 8000' pumping 6500 scf/min. Reduced nitrogen rate to 300 scf/min, w/1700# coil tbg & wellhead press 6180#. TIH w/coil tbg to 9000' jetting 6300 scf/min, w/2600# on coil & 185# wellhead. Total recovery 6 156.7 bbls, last sample 45% oil. TIH to 10500' jetting 6500 reducing to 300 scf/min. 190# on wellhead. Wellhead pressure increasing 61635 hrs to 327# in 10 minutes. & 497# next 10 minutes. Well seems to be restricted by coil tbg & flowing in slugs. DOWELL ALMOST OUT OF NITROGEN, COIL TUBING COULD BE RESTRICTING FLOW. POOH W/COIL TUBING. WELL STILL FLOWING 6 600 BOPD W/300 PSI 6 WELLHEAD ON 45/64 CHOKE. FLOWING WELL W/O NITROGEN. PRESSURE SLOWLY INCREASED TO 450 PSI ON WELLHEAD W/RATE OF OIL INCREASING FROM 600 BPD TO 1280, 1700, 1880. WELL SHUT IN DUE TO SCSSV CLOSING. REOPENED SCSSV. TOOK 2700 PSI ON TOP OF SCSSV TO OPEN VALVE. SERVICE MAN HAD BLED OFF A LITTLE TOO MUCH PRESSURE ON CONTROL LINE AND SCSSV CLOSED. REOPENED VALVE W/NO PROBLEM. WELL PRESSURE INCREASED TO 2700 PSI UNDER SCSSV WHILE REOPENING SCSSV. FINISHED REOPENING SCSSV, HAD TO R/U TEST PUMP AND PRESSURE UP ON TOP OF SCSSV TO 2700 PSI TO OPEN VALVE. FLOWING WELL THRU 45/64" CHOKE 6 2000 - 2200 BOPD RATE W/ WELLHEAD PRESSURE 6 500 PSI. TOTAL OIL REC., 890 BBLS. SHUT WELL IN. HALLIBURTON 400 BBL HOLDING TANK LEAKING. FOUND 2" BULL PLUG MISSING FROM LINE ON BOTTOM OF TANK. CLEANED UP OIL SPILL ON MIDDLE DRLG. DECK. SPILLED APPROX. 15 BBLS, SPILL WAS CONTAINED. RIGGED DOWN DOWELL COIL TBG. UNIT AND NITROGEN ( WILL HOLD CTU 6 DOCK ). PUMPED WATER AND BLEW AIR THRU HALLIBURTON LINES. RIGGED DOWN HALLIBURTON AND RIGGED UP HALLIBURTON SLICKLINE TO WELLHEAD FLANGE. TESTED HALLIBURTON SLICKLINE LUBRICATOR TO 250/3500 PSI W/ FRESH WATER, TESTED OK. RIH W/HALLIBURTON PRESSURE GAUGES. TAGGED SCSSV 6 347', COULD NOT GET THRU SCSSV. POOH W/SLICKLINE AND GAUGES. INSPECT TOOLS - ALL OK. R/U LUBRICATOR AND RETEST SAME. PRESSURE UP AND CYCLE SCSSV. RIH W/SLICKLINE AND PRESSURE GAUGES. WIRELINE STOPPED Printed: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 02/05/98 02/06/98 ,2/07/98 SUNFISH 000003 North Cook Inlet Unit B-2 Spud Date: 11/19/93 Sidetrack Start: 11/14/97 End' POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Number: 429 From-To Hours lSUb OO?~i::::: I:~.. i .i: :: 1 i::i: :: :: :..:. ~..i. De~i~ ofi.~rati~n~ ~: i i..i :: :..: :~, :~:::: ,::: t ~ : :::: 16:00 - 18:30 2.50i LG f 80CMPL @ 282'. WORKED TOOL DOWN HOLE LOCATING EA. TUBING CONN. ~ NO PROBLEM TIH. SET PRESSURE GAUGES IN XN NIPPLE @ ~ 10624'. POOH W/WIRELINE TO 323', RUNNING TOOL STUCK AT OR 5.50 NEAR SCSSV. 18:30 - 00:00 LG f 80CMPL ATTEMPT TO WORK SLICKLINE PAST SCSSV, WIRELINE STILL STUCK. ATTEMPT TO CYCLE SCSSV, WIRELINE STILL STUCK. ATTEMPTING TO UNPLUG TUBING. SUSPECT ICE PLUG IN TUBING. BLED PRESSURE OFF OF SLICKLINE LUBRICATOR AND FILLED W/ I METHANOL. STARTED GETTING ICE W/OIL FROM LUBRICATOR. I / PRESSURE UP ON LUBRICATOR TO 3500 PSI AND BLEED BACK TO ! 2500 PSI, TRYING TO WORK METHANOL DOWN HOLE. 6.00¢I LG f 80CMPL CONTINUE TO ATTEMPT FREE WIRELINE, PRESSURE UP TO 3500# I~ . & BLEED BACK TO 2500# W/METHANOL 1.00 LG f 80CMPL BLEED PRESSURE OFF LUBRICATOR TO 0#. VERY LITTLE FLUID i ! RECOVERED. PRESSURE LUBRICATOR TO 3500# W/METHANOL & I I BLEED OFF TO 0# SEVERAL TIMES WITHOUT SUCCESS. 1.00 LG !f 80CMPL PRESSURE BLED TO 0#, HALLIBURTON SLICK LINE PULL 400# ON ~ WIRELINE. CLOSE BOTTOM TREE VALVE & CUT WIRELINE. ~ RECOVER LINE, CLOSE VALVES ON TREE. ~ NOTE: TOOL STRING LEFT IN HOLE, 24' OVERALL + 250' OF .125 I WIRE. ROPE SOCKET, KNUCKLE JT, 5' STEM, 5' STEM, KNUCKLE JT, HYD JARS, SHORT SPANG JARS, XO SUB, MALE & FEMALE QUICK CONNECT, 2 1/2 X-LINE RUNNING TOOL. 1.001LG 6 80CMPL RD HALLIBURTON WIRELINE EQUIPMENT & RISER FROM SHORT ~ STRING. 3.00i CM i6 80CMPL PULL BPV ON LONG STRING. RU RISER FROM TREE TO RIG i FLOOR. INSTALL 3 1/16" 10K WING VALVE ON LONG STRING SIDE .: OF TREE. 1.50 LG 6 80CMPL RU SCHLUMBERGER WL & LUBRICATOR. PU GR/CCL TOOLS. 0.501 LG 0 80CMPL SAFETY MEETING. 1.00 LG 8 80CMPL PRESSURE TEST LUBRICATOR, TREE, WING VALVE 250 LOW & · 8000 HIGH W/60-40 GLYCOL-WTR SOLUTION. 5.00 LG I 80CMPL TIH W/GR-CCL TO 14000', LOGGING TOOL WOULD NOT GO DEEPER. ~ POOH W/LOGGING TOOL AND LAYED DOWN SAME. 0.50i LG 0 80CMPL HELD SAFETY MEETING W/ALL HANDS. 0.50i CM q 80CMPL PICHED UP AND ARMED STRIP GUN. 2.00 CM q 80CMPL RIH W/2-1/8" STRIP GUN AND CCL TO 12225', LOADED 22' OF STRIP W/6 SPF. TAGGED ? IN 3-1/2" TUBING. PICKED UP AND SET BACK DOWN ON ?. PICKED UP SECOND TIME AND PULLED TO 1350-1400# ON WIRELINE. PULLED FREE BUT LOST WT. OF PERF. GUN AND WT I BARS. ROPE SOCKET SET TO PULL OUT ¢_, 2000#. POOH W/ f 80CMPL WIRELINE, HAD PULLED OUT OF ROPE SOCKET. 1.00 FI ~ CALLED OUT HALLIBURTON SLICKLINE CREW ( SLICKLINE UNIT ALREADY ON RIG ). ORDERED OUT FISHING TOOLS TO FISH PERF. GUN OUT OF 3-1/2" TUBING. 5.00 WO i u 80CMPL WAIT ON HALLIBURTON SLICKLINE CREW & WIRELINE FISHING TOOLS TO RETRIEVE SCHLUMBERGER PERF. TOOLS LEFT IN I HOLE. 1.50 FI 6 80CMPL RIGGED UP HALLIBURTON SLICKLINE UNIT. PICKED UP OVERSHOT DRESSED TO CATCH 1.18" OD FISHING NECK ON ROPE SOCKET. TESTED LUBRICATOR TO 3500 PSI W/60%/40% GLYCOL & WATER I MIXTURE, TESTED OK. 1.50 FI f ,'!80CMPL RIH WI FISHING TOOLS ON 1.25 SLICKLINE, TAGGED TOP OF FISH 00:00 - 06:00 06:00 - 07:00 ;07:00 - 08:00 108:00 - 09:00 09:00 - 12:00 12:00- 13:30 13:30 - 14:00 14:00 o 15:00 15:00 - 20:00 20:00 - 20:30 20:30 - 21:00 21:00 - 23:00 23:00 - 00:00 00:00 - 05:00 05:00 - 06:30 06:30 - 08:00 Printed: 03/31/98 4:38:24 PM Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Spud Date: 11/19/93 Event Name: Sidetrack Start: 11/14/97 End: Contractor Name: POOL ARCTIC ALASKA Rig Release: 04/02/94 Group: Rig Name: Rig Number: 429 IH°uts SUb~has~'.::. ?i :::i:ii.:ii'iii~'i"'~::?.:,::¥:i:i...::~ii~:i': Date From- To ~ 02/07/98 06:30 - 08:00 1.50! FI f 80CMPL @ 12235' WLM. ENGAGED & CAUGHT FISH. WORKED FISH AND / i STARTED MOVING DOWNHOLE. WORKED FISH AND STARTED 08:00 - 10:00 10:00- 11:00 11:00 - 14:30 4:30 - 15:30 15:30- 16:00 16:00 - 17:00 17:00 - 19:00 19:00 - 19:30 02/08/98 19:30 - 20:30 20:30 - 22:00 22:00 - 23:00 23:00 - 00:00 00:00 - 00:30 00:30 - 01:30 01:30 - 02:00 02:00 - 03:00 03:00 - 04:00 04:00 - 04:30 04:30 - 06:00 06:00 - 07:00 2.00! FI 1.00 FI 3.50 LG 1.00 CM 0.50 CM 1.00 CM 2.00 CM O.50 CM 1.00 CM 1.50 CM 1.00 CM I 001 CM 0.50 CM 1.00. GM 0.50 CM 1.001 CM 1.00 GM 0.50 CM 1.50! CM 1.001CM lq 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL ,80CMPL 80CMPL 180CMPL i80CMPL i80CMPL MOVING UPHOLE. POOH W SLICKLINE FISHING TOOLS & SCHLUMBERGER PERF. STRIP GUN. HAD FULL RECOVERY, EXCEPT FOR 1 BOLT MISSING FROM GUN CARRIER 3/4" OD X 1/2" LONG X 1/2" THREADS. LAYED DOWN PERF. GUN AND SLICKLINE FISHING TOOLS. PICKED UP HALLIBURTON 2.45" OD GAUGE RING AND RIH TO 14050' W/NO PROBLEM. POOH AND LAYED DOWN GAUGE RING AND RIGGED DOWN SLICKLINE UNIT. RIGGED UP SCHLUMBERGER WIRELINE LUBRICATOR AND BOLT UP TO WELLHEAD FLANGE. HELD SAFETY MEETING ON PERF. W/ALL CREW MEMBERS. WENT ON RADIO SILENCE, PICKED UP AND ARMED 2-1/8" STRIP GUN. TESTED LUBRICATOR TO 5000 PSI W/GLYCOL AND WATER MIXTURE, TESTED OK. RIH W/PERF. GUN. CORRELATE GUNS ON DEPTH W/GAMMA RAY/CCL. PRESS UP ON TBG TO 1700 PSI. FIRED GUN AND PERF. N. FORELANDS @ 13966' TO 13944', 22' W/6 SPF. PRESSURE INCREASED TO 1800 PSl. START TO POOH W/PERF. GUN. GUN STUCK. WORK WIRELINE, HAD NO MOVEMENT. PRESSURE UP ON TUBING TO 3000 PSI, STILL NO MOVEMENT. INCREASED PRESSURE TO 3500 PSI, WORKED WIRELINE, PERF. GUN MOVING UP A LITTLE. CONTINUE WORKING WIRELINE AND WORKED GUN FREE. POOH W/2-1/8" PERF. GUN. PRESSURE BLED BACK TO 0 PSI WHILE POOH. LAYED DOWN PERF. GUN, ALL SHOTS FIRED. GUN HAD BENDS IN STRIP AND HAD 5 SHOT CARRIERS MISSING WHICH COULD HAVE CAUSED GUN TO HANG UP IN HOLE. PICKED UP NEW GUN, 1-11/16" STRIP GUN 19' LONG LOADED W/6 SPF. RIH W/1-11/16' STRIP GUN. CORRELATE GUN ON DEPTH W/ GAMMA RAY/CCL. NOW PREP TO SHOOT 2nd GUN. FINISHED CORRELATING GUNS ON DEPTH W/GAMMA RAY/CCL. HAD TUBING PRESSURE ALREADY @ 1800 PSI DUE TO LINE DISPLACEMENT. FIRED PERF. GUN & PERF. FROM 13920 TO 13901 W/6 SPF. HAD NO CHANGE IN PRESSURE. WORK WIRELINE, PERF. STRIP HANGING UP. WORKED STRIP FREE AND POOH. LAYED DOWN STRIP GUN, HAD 81 SHOT CARRIERS MISSING. PICKED UP STRIP GUN #3.38' GUN LOADED 4 SPF. ARMED STRIP GUN. RIH W/1-11/16" PERF. STRIP GUN #3. CORRELATE GUNS ON .DEPTH IW/GAMMA RAY/CCL. HAD TUBING PRESSURE ALREADY @ 2200 i PSl. FIRED GUN AND PERF FROM 13856 TO 13818. TUBING PRESSURE INCREASED TO 2800 PSI. POOH W/STRIP GUN W/PRESSURE REMAINING @ 2800 PSI. LAYED DOWN GUN #3, HAD 63 SHOT CARRIERS MISSING. PICKED UP STRIP GUN #4, 18' LONG LOADED 4 SPF. ARMED GUN AND PREP. TO RIH. RIH W/1-11/16" STRIP GUN # 4. TUBING PRESSURE STILL @ 2800 PSI. CORRELATE GUN ON DEPTH W/GAMMA RAY/CCL. NOW HAVE 2900 Printed: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 02/08/98 02/09/98 j From - To ] 06:00 - 07:00 07:00 - 09:00 09:00 - 10:00 10:00 - 11:00 11:00 - 15:00 15:00 - 15:30 15:30 - 16:00 16:00 - 00:00 00:00 - 02:30 02:30 - 04:30 04:30 - 14:00 SUNFISH 000003 North Cook Inlet Unit B-2 Sidetrack POOL ARCTIC ALASKA Hours i 1.00 Spud Date: 11/19/93 Start: 11/14/97 End' Rig Release: 04/02/94 Group: Rig Number: 429 :: : ;::::: :i :::: '::: ................. :: :: :: ~ ~;~:: ~: ........................................................................ ::: ....... :::::::::::::::::::::::::::::::::::::::: .... Sub:Co :. :.:BesS~iptis~ i'0f:,':~fa~ic~s i f~' i i '.::ii': 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL 80CMPL '80CMPL CM 14:00 - 15:00 15:00 - 16:30 2.00 CM 1.001CM 1.00 CM 4.00 CM 0.50 CM 0.50 CM 6 8.00 CM 2.5O CM 2.00 CM 9.5O CM 1.00 CM 1.50 CM 80CMPL JPSI ON TUBING. FIRE GUN AND PERF. FROM 13736-[O 13718, HAD NO CHANGE IN PRESSURE. POOH W/STRIP GUN W/2800 PSI. HAD 112 SHOT CARRIERS MISSING. PICKED LIP 1-11/16" STRIP GUN #5, 34' LONG LOADED 4 SPF. iARMED GUN AND RIH W/3000 PSI. CORRELATE GUN ON DEPTH W/ GAMMA RAY/CCL. STILL HAVE 3000 PSI ON TUBING. FIRED GUN AND PERF. FROM 13686 TO 13652 W/4 SPF. HAD NO CHANGE IN PRESSURE. POOH W/STRIP GUN #5. PRESSURE STILL @ 3000 PSI. RIGGED DOWN SCHLUMBERGER ELECT. WIRELINE PERF. UNIT. RIGGED UP HALLIBURTON FLOW TESTING EQUIP. TO 3-1/2" LONG STRING. 'TESTED HALLIBURTON FLOW TESTING EQUIP TO 250/8000 PSI, ALL TESTED OK. . HELD SAFETY MEETING W/ALL CREWS ON FLOW TESTING PROCEDURES. OPEN WELL TO HALLIBURTON WELL TESTERS W/2960 PSI ON 8/64 CHOKE, STEPPING UP CHOCK SIZE TO 16/64 THEN TO 24/64 CHOKE IN FIVE MIN. INCREMENTS FOR ACOUSTIC SAND DETECTION BASE LINE. WELL FLOWING IN RANGE OF 2500 TO 2600 PSI. HAD NUMEROUS PROBLEMS W/PERF. AND OTHER DEBRIS PLUGGING CHOKES. AT 20:00 HRS. SWITCHED TO SEPERATOR. AT REPORT TIME, FLOWING AT 2490 PSI. FTP ON 26/64 FIXED CHOKE. APP. RATE OF 4000+ BBLS FLUID PER DAY. 70% WATER AND 30% OIL W/1MMSCFD OF GAS, NO SAND. FLUID SAMPLING IN PROGRESS. NOTE: HIGHER RATE FLOW TEST TO FOLLOW AFTER SAMPLING IS CONCLUDED, AT APP. 01:30 HR. FLOW TEST TO END AT APP. 05:00 HR. ALASKA TIME. REDUCED CHOKE SIZE TO 8/64" FOR SAMPELING. PRESSURE @ 4450 PSI. COMPLETED CATCHING 2 SAMPLES. KEPT WELL FLOWING @ REDUCED RATE WHILE TRANSFERING FLUID FROM STORAGE TANKS. INCREASED CHOKE SIZE TO 36/64" FOR HIGH FLOW RATE TEST, TUBING PRESSURE @ 1600 PSI. KEPT 36/64" CHOKE FOR 10 MIN., I THEN CHOKED BACK TO 30/64" FIXED CHOKE. TOOK 6 BS&W ISAMPLES DURING TEST PERIOD. WATER CONSlSTANTLY IN THE RANGE OF 78%. MAX. FLOW RATE EST. @ 5113 BPD W/1125 BOPD AND 3988 BWPD. FTP @ 2000 PSI, GOR 1200, OIL GRAVITY 39.5, iWHT 1407, GAS GRAVITY .86, CHL 12500, NO SAND. !SHUT WELL IN @ 0424 HRS W/2048 PSI ON TUBING AND MONITOR iWELL FOR PRESSURE BUILD UP. @ 0430 HAD 4479 PSI; 0530-4751 I PSl; 0630- 4801 PSI' 0730-4825 PSI; 0830-4835 PSI; 0930-4839 PSI; 1030-4845 PSI; 1130-4859 PSI; 1230-4878 PSI; 1330-4866 PSI. DURING DURATION OF FLOW TEST, BLED OFF A TOTAL OF 7.5 BBLS FLUID FROM ANNULUS DUE TO EXPANSION. LEFT ANNULUS W/0 PRESSURE. ~CLOSED SCSSV ON LONG STRING AND CLOSED LOWER MASTER iVALVE. DISPLACED TREE,RISER, AND HES TEST LINES W/60/40% i GLYCOL AND WATER MIXTURE. I RIGGED UP HES TO 2-7/8" SHORT STRING. TESTED HES EQ. TO Printed: 03/31/98 4:38:24 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date From - To 02/09/98 02/10/98 15:00 - 16:30 16:30 - 17:00 17:00 - 19:30 19:30 - 20:00 20:00 o 20:30 20:30 - 00:00 00:00 - 12:00 SUNFISH 000003 North Cook Inlet Unit B-2 Sidetrack POOL ARCTIC ALASKA HOUrs tSu~ ii~~: 1.50 CM 0.50 CM 0.50 CM 3.50 CM 12.00 CM Spud Date: 11/19/93 Start: 11/14/97 End: Rig Release: 04/02/94 Group: Rig Number: 429 ~I ~d~.:i i;:i: '.. i':'i ! !!::. "::.. ?-.;i .:.:. i'.:::De~iPtio~i:of-::i'O~ati~'n~ :i'.i :::: ~ :::: ;: ~ ~ ~ ~ ;~ .'~ ~' ~ .'~.~ ; : ~ .: ~}~ ?'~ ~ .'~'. ~ ~ ~ ~': i~: ~ ~ '~ ~.' ~ ~. ~ ~ ~ ~ :~:::::~:::~:::: :::';: ::~:: 0 80CMPL HELD SAFETY MEETING W/ALL CREWS. u 80CMPL OPEN WELL TO HES ON 14/64 CHOKE W/1500 PSI INITIAL 80CMPL 80CMPL 80CMPL 80CMPL PRESSURE ON WELLHEAD. INCREASE CHOKE SIZE TO 28/64 OVER 15 MIN. PERIOD, PRESSURE DOWN TO 790 PSI. KEPT WELL ON 28/64 CHOKE AND FLOWED BACK APPROX. 70 BBLS OF FLUID TO VERIFY NO RESRICTIONS IN TUBING, PRESSURE INCREASED TO 910 PSI. STARTED FLOWING WELL @ 400 BPD W/NO OIL FOR FIRST 15 MIN, THEN HAD OIL TO SURFACE. FINISHED FLOWING WELL @ 960 BPD W/NO WATER. CLOSED WELL IN AFTER FLOWING 70 BBLS. CLOSED SCSSV ON SHORT STRING AND BLED OFF 400 PSI TO TEST SCSSV, HOLDING OK. PUT 1500 PSI BACK ON TOP OF SCSSV AND CLOSED BOTTOM MASTER VALVE. DISPLACED RISER, TREE, AND HES TEST LINES W/GLYCOL AND WATER MIXTURE, BLEW ALL LINES DOWN W/AIR. RIGGED DOWN 3-1/2" RISER AND SECURE B-2 TREE. RIGGING DOWN HES FLOW TESTING EQ. RD HALLIBURTON FLOW TEST EQUIPMENT & LOAD OUT ON WORKBOAT. RE, LEASE RIG FROM NClU B -2. PREPARE TO SKID TO NClU B-1. Printed: 03/31/98 4:38:24 PM Geologic Tops for Rock Unit: Sunfish SS. N.Forelands SS. NCIU B-2 13,110' 13,644' Oil Shows: Excellent oil 13,160'(tested sandstone from 1,125 BOPD). shows in the Sunfish sandstone 2,000 BOPD) and in the North 13,644 - 13,685' and 13,725' from 13,100' - Forelands - 13,755'(tested Zones of Abnormal Pressure: North Forelands SS. 30 ' @ .. BPV(Make,Type, OD) Not Applicable ..~/ RK~: Tbg. Hgr.(Make,Type) Not Applicable RKB-BHF: 59.00 Annulus Fluid: RIC~MSL: 132.00 TOC: Water Depth 130.00 .~?:~::~::~::~::~::~1::~::~::~?:~?:~ ~::~::~?:~::~::~::~::~?:~?:~:??:~?:~::~::~::~::~::?:~::~::~::~::~::~::~::~::~::~::g~?:~::~::~::~::~::~ :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ~ Casing Strings: PPCo. Allowable Raflngs ' 30" ] 55 I 407 457 lb/ft Welded 20" 59 2,602 169. lb/f~ X-56 Dril-QuiF 2860 1410 1700 13 3/8" 59 8,909 72.0 lb/ft N-80;P-110 BT&¢ 4730 2520 761 9 5/8" 57 11,086 53.5 lb/g P-110 BT&(; 8920 7480 1159 Production Liner: 3 1/2" 13,522 14,457 112.95 lb/gl ?-105 C£MENTING SUMMARY 20" Conductor Cemented with 1070 sx 12.8 lb/gal Class "G" with 0.25 gal/sx D-77, 11/25/93 0.05 gal/sx D-47 and 0.28 ~gal/sx D-75. taiIed with 600 sx Class "G" mixed @ 15.8 lb/gal with 0.25 gal/sx D-77 and 0.05 gal/sx D~47. Cement Circulated to Surface. 13 3/8" 1st Stage Cemented with 900 sx 12.5 lb/gal Class "G" with 1.0 % D-6, 12/I 8/93 plus 0.05 gal/sx D-47 Tailed with 700 sx Class "G" ~ 15.8 lb/gal with iilii ~/ and0'05 gal/sx D-47, 0.5% D-59, 0.15 gal/$x D-801, 0.4% D-65, 0.10% D-134,0.25% S-l. 2ndStage Cemented with3700sxlS.81b/gal Class "G" with 0.10 % D-65, plus DV tool ~ 7385' 0.1 gal/sx D47, 0.1% D-135, 1.0 gal/sx D-600, and 0.3% D-800 3rd Stage Cemented with 1000 sx 15.8 lb/gal Class "G" with 0.20 % D-65, plus DV tool ~ 4045' 0.1 gal/sx D47, 0.1% D-135, 1.0 gal/sx D-600, and 0.3% D-801. 9 5/8" Cemented with 500 sx 15.8 lb/gal Class "G" TOC at 10,088' 7" & 3 1/2" Cemented with 1310 sx 15.8 lb/gal Class "G" with 0.2 % CFR-3, plus TOG ~ 10,088' 0.13 gal/sx Halad 344L, 0.25 % HR-5 SHORT STRING TUBING 0.00 53.58 Elevation 53.58 0.@3 Tubing Hanger 54.51 283.36 2 718" 6.5 Ib/ft L-go CS Hydril Tubing :' 7042.39 6.45 2 718" CAMCO Gas Lift Mandrel 337.87 4.00 2 718" Halliburton TRSV 341.87 3984.94 2 718" 6.5 Ib/ff 1-80 CS Hydril Tubing 4326.81 6.46 2 718" CAMCO Gas I_ift Mandrel i I 4333.29 1578.51 2 718" 6.5 Ib/ft L-80 CS Hyddl Tubing 5911.80 6.43 2 7/8" CAMCO Gas Lift Mandrel 5918.23 1124.16 2 7/8" 6.5 Ib/ft L-80 CS Hyddl Tubing :: Topof7' 7048.84 1135.35 2 7/8" 6.5 Ib/R L-80 CS Hyddl Tubing Li~er To I i @ lo738' 8184.19 6.48 2 7/8" CAMCO Gas Lift Mandrel P,~cker p 8190.67 1112.45 27/8" 6.51b/ft L-80CSHyddlTubing i 9303.12 6.48 2 7/8" CAMCO Gas Lift Mandrel 9 5/8' @ 9309.60 980.55 2 7/8" 6.5 Ib/ff L-80 CS Hyddl Tubing ::: , 11086 10290.15 6.44 2 7/8" CAMCO Gas Lift Mandrel 10296.59 296.75 2 7/8" 6.5 Ib/ft L-80 CS Hydril Tubing 10593.34 7.13 Halliburton RDH Dual Packer 10600.47 12.05 2 7/8" 6.5 Ib/ft L-80 CS Hyddl Tubing 10612.52 1.14 HES X-Nipple 1O613.66 10.12 2 7/8" 6.5 Ib/ft L-80 CS Hyddl Tubing 10623.78 1.43 HES XN Nipple I0625.21 0.74 Wirelline Entry Guide LONG STRING TUBING 0.00 53.58 Elevation 317 54.51 365.90 3 112" 12.95 lb/fi I_-80 PH-6 Tubing 420.41 8.10 3 1/2" Halliburton TRSV 428.51 3960.44 3 112" 12.95 Ib/ft 1_-80 PH-6 Tubing 4388.95 8.50 3 112" CAMCO Gas I_ift Mandrel 7' @ 13,526' 4395.45 2214.95 3 112" 12.95 Ib/ft 1--80 PH-6 Tubing ] 6610.40 6.52 3 1/2" CAMCO Gas 1-fit Mandrel N. r 6616.92 1350.09 3 1/2" 12.95 Ib/ft L-60 PH-6 Tubing iiiiiiiiiii 7967.01 6.5031/2" CAMCO Gas lift Mandrel 7973.51 1264.36 3 1/2" 12.95 Ib/ft/-80 PH-6 Tubing 9237.87 6.51 3 112" CAMCO Gas 1_ift Mandrel 9244.38 1107.64 3 1/2" 12.95 Ib/ft 1-80 PH-6 Tubing 10352.o2 6.4@ 3 1/2" CAMCO Gas I_iff Mandrel 10358.51 233.93 3 1/2" 12.95 Ib/ft L-60 PH-6 Tubing 10592.44 8.10 Halliburton RDH Dual Packer 10600.54 2922.47 3 1/2~ 12.95 lb/fl 1--80 PH-$ Tubing PBTD = 14,377' 13523.01 1.33 Baker No-Go Locator 13524.34 5.50 3 1/2~ Seal Assembly 3 ~t2 · @ ~,~57' 13529.84 End of Tubing ~ PBTD: 14,377' Isup~: I~g TD = 14537' Well: North Cook Inlet Unit "B" No. 2 (formerly Sunfish No. 3) 3/28/98 Updated 031261~8 Location: Tyonek Pht£om, Cook Inlet, Alaska Field: North Cook Inlet NSH t Ui',li tUg. t't l i IL PHILLIPS PETROLEUM CO : Well Summary Report · z Page 1 of 1 Legal Name: SUNFISH 000003 Common Name: North Cook Inlet Unit B-2 Well LoCation Country: USA APl #: 5088320090 Location: Leg I Slot 6 Field Name: Block: License No: Spud Date/Time: 11/19/93 - 21:30 Well ID: D0121 S[ate/Prov: ALASKA County: TYONEK OFFSHORE Slot No: Platform: TYONEK License Date: Licensee: P&A Date: Latitude: Longitude: Distance North/(-)South: Distance EastY(-)West: Measured From: Surface l Bottom Hole·CoordinateS :.~ : ~ : Surface Location Bottom Hole Location [1,249.00 (ft) :980.00 (ft) i FNL & FWL of Sec 6 · ::ReferenCeEievations:: .: :: ~ermanent Datum: Mean Sea Level (elly Bushing: 132.00 (ft) Ground Level/Mudline: (ft) Casing Flange: (ft) Tubing Hanger: (ft) KB to Datum: 132.00 (ft) <B to GL/Mudline: 132.00 (ft) Date Measured: Date Measured: Datum Elev: 132.00 (ft) Water TMD: 100.00 (ft) Measured Depth: 14,705.00 (ft) TVD: 13,281.00 (ft) Plugback TMD: 300.00 (ft) Fill: (ft) Deviated Well: Y Division: KENAI SUBDIST Status: PENDING CO Operator: PHILLIPS PETROLEUM CO Region: E&P KENAI AREA Well Type: EXPLORATION / OIL Geological Play: Authorized TVD: 13,732.00 (ft) Authorized TMD: 15,800.00 (ft) Event Type ~- Objective :. : :.: ;::: ;'::~I~'-: :: Start:: I::: ::End Date:; Orig Drilling Drill and Test 11/13/93 04/02/94 Sidetrack ',Sidetrack and Complete 11/14/97 : District: KENAI SUBDIST Printed: 05/28/98 12:13:08 PM Final Well/Eventsummary ' : Legal Well Name: Common Well Name: Event Name: SUNFISH 000003 North Cook Inlet Unit B-2 Sidetrack Start Date: 11/14/97 End Date: DATE TMD .: :~ ::: 124 HOUR SUMMARY ;':: :: ' 11/21/97 11/22/97 11/23/97 11/24/97 11/25/97 11/26/97 11/27/97 11/28/97 11/29/97 11/30/97 12/01/97 12/02/97 1 2/03/97 12/04/97 1 2/O5/97 12/06/97 12/07/97 12/O8/97 12/09/97 12/10/97 12/11/97 1 2/1 2/97 1 2/13/97 1 2/14/97 1 2/15/97 12/16/97 12/17/97 12/18/97 12/19/97 12/20/97 12/21/97 12/22/97 12/23/97 12/24/97 12/25/97 12/26/97 (ft) (ft) (fi:) (ft) (ft) (rt) (fi:) (ft) (fi:) (fi:) 9,003 (fi:) .9,020 (ft) 9,020 (fi:) 9,256 (ft) 9,429 (ft) 9,751 (ft) 9,949 (ft) 9,996 (ft) 10,095 (ft) 10,307 (ft) 10,435 (ft) 10,435 (ft) 10,594 (ft) 10,834 (ft) 11,039 (ft) 11,088 (ft) 11,088 (ft) 11,088 (fi:) 11,088 (ft) 11,177 (ft) 11,212 (fi:) 11,366 (fi:) 11,594 (fi:) 11,723 (ft) 11,800 (ft) 12,002 (fi:) SKID RIG TO NCIU B-2. ND TBG HEAD, NU RISER & BOP STACK. FINISHED NU. TESTED BOPE. DRILL CMT 335 - 475'. CIRC & CLEAN CHOKE MAN WASH TO 480'. RT TO BHA. TAG CMT @ 462'. PLUG BIT. RTRIP. WASH TO 9500 POOH. PU SCRAPER & TIH. ClRC BU. POOH. TIH W/EZSV. POOH. PU CSG CUTTER. CUT 9 5/8. POOH. SPEAR CSG. PU 60'. ClRC. POOH, LD 9 5/8" CSG. FINISHED L/D CSG.CLEANED OUT TO 9 5/8" STUB AT 9100'.CBU. POOH. FINISH POOH. PU CMT STINGER. TIH & SPOT ST PLUG. POOH, LD STINGER. TESTED BOPE. RIG REPAIR. P TEST 13 3/8"-FAILED. TIH, TAG CMT. POOH. POOH. TIH W/RTTS. TEST CSG TO 1750 PSI. POOH. PU BHA & TIH. DRILLED CMT F/8640' TO KOP AT 8970'.ORIENT & SLIDE TO 9003'. CONT W/KICKOFF TO 9020'/CBU/LEAKOFF/CLEAN PITS/BUILD OIL BASE MUD Building & displacing hole w/oil-base mud. Fin displ hole w/oil-base mud. Drilled to 9,256' MD. Repair Apollo Fin repairing cuttings injection equip. Wash to btm. Drilling at 9429' Drilled directionally from 9429' to 9751' (322'). Drld 9751-9898'. 3 hours pump repair. Drld to 9949'. Drilled from 9949' to 9996'. Tripped for motor & bit. Drilled to 10,095'. Drilled from 10,095' to 10,307' (212') Fin POOH. Change bit. GIH. Drlg. Worked way out of tight hole for bit. GIH to csg shoe. Cut drill line Cut drill line. GIH. Wash 60' to btm. Drilling at 10,594'. Drilling & repairing pumps. Drilled from 10,834' MD (9986' TVD) to 11,039'MD (10,180' TVD). Drilled to 11,088' MD (10,226' TVD). POOH. Now running casing. Run 261 jts 9°5/8" casing, circ-cond, ru cmt head CMTD 9 5/8" CSG. ND, PU STACK, NU TBG HEAD. NOW TEST CHK MAN. LD 6 5/8" HWDP. NU BOP. TEST CSG & BOPE. START PU BHA. FINISH PU BHA & TIH. DRILL OUT. RAN FIT. DRLG 8 1/2 HOLE (SLIDE/ROT) DRILL TO 11212'. SLIP/CUT DRLG LINE. TRIP F/MUD MOTOR. TIH TO SHOE. W&R TO BTM. DRLD TO 11366'. POOH. LD AG STAB. TIH. FINISH TIH. W&R LAST STND TO BOTTOM. DRLG & SLIDING 11366-11594'. DIRECTIONAL DRILL TO 11723'. TRIP F/BIT. FINISH TIH. DRILL (RTRY)TO 11800'. POOH & TEST BOP'S. FINISH TIH. DRILL TO 11941'. REPAIR RIG. DRILL TO XXXXX'. Printed: 05/28/98 12:09:43 PM Final weiI :l Event isummary :, Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Event Name: Sidetrack Start Date: 11/14/97 End Date: DATE TMD : : ::24 HOUR. : .SUMMARY~: 12/27/97 12/28/97 12/29/97 12/3O/97 1 2/31/97 01/01/98 01/02/98 01/03/98 01/04/98 01/05/98 01/06/98 01/07/98 01/08/98 01/09/98 01 / 1 O/98 01/11/98 01/12/98 01/13/98 01/14/98 01/15/98 01/16/98 01/17/98 01/18/98 01/19/98 01/20/98 01/21/98 01/22/98 01/23/98 01/24/98 01/25/98 01/26/98 01/27/98 01/28/98 01/29/98 01/30/98 01/31/98 12,504 (ft) 13,032 (ft) 13,233 (ft) 13,418 (ft) 13,418 (ft) 13,735 (ft) 14,007 (ft) 14,278 (ft) 14,439 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) DIRECTIONAL DRILL FR/12002 - 12504'. ROTARY DRILLED FR/12504- 13032'. DRILLED FR/13032 - 13233'. DRILLED (ROTARY) FR/13233 - 13418'. BACKREAM OOH. TRIPPED F/NEW BIT & TESTED BOP'S. Fin GIH. Drilled to 13,728'. Circ out gas. Now drilling at 13,735' Drilled to 13,813'. Had gas at surf. Circ & wt mud to 14.5#. Drilling Drilled from 14,007' to 14,278' MD. Drilled from 14,278' to 14,439' MD. Repairing top ddve. Drilled to 14537'. Short trip. POOH. Now LD directional tools LD directional tools. RU Schl. Ran quad-combo log. Now sidewall coring POOH w/1st log OK. Att Dipmeter, sticking. RD Schl. GIH w/bit. C&CM Made wiper trip, hole OK, 453 units gas. POOH. Now GIH w/MDT tool Work on Schl MDT tool. Att to run RFT - tool failed. Clean rig floor. Change top rams to 7" & test. Now running liner. Ran 3-1/2" x 7" liner. Circ at 14,450'. Cmtg liner - losing returns. Circ. Set liner hgr. Cmtd w/1310 sx, lost circ. POOH. Chg pipe rams. Chgd pipe rams & tstd. Ran shoe on WP & washed to 10816'. POOH. TIH W/CUTTER. CUT 3 1/2 @ 10793'. POOH. TIH W/WAHS PIPE. WO TO 10943 TIH W/O/SHOT. LATCH FISH. JARRED SAME LOOSE. POOH, LD 3 1/2". TIH W/MILL & SCRAPER. TO TOP OF 3 1/2". C&CM. POOH. TESTED BOP'S. · TIH W/I 1/4" TBG & MOTOR. UNABLE TO DRILL CMT. POOH. TEST CSG. NU & TEST DUAL TBG SPOOL. RU SCHLUMBERGER RUN CET & CBL. FINISH LOGGING & RD SCHLUM. TIH W/SEAL ASSY ON 3 1/2" & 5" DP. DISPLACED HOLE TO CACL. PARTIALLY ItU CTU & CLEAN MUD SYSTEM. CLEANED OBM FR/MUD SYSTEM. CLEANED PITS. RU CTU. MIX CACL. RIH & DRILL CMT. POOH RD CTU. RD CTU. PU ABOVE 3 1/2". CIRC. POOH. TEST BOP'S. TIH W/PLUG. TIH & SET PBR PLUG. POOH. PU TCP ASSY. TIH. PERF SUNFISH. PERF SUNFISH. REVERSE OUT. POOH. LD TCP ASSY. TIH W/OVERSHOT RETRIEVE PBR PLUG. SET RTTS PKR. INST DUAL PIPE RAMS IN STACK. , Running dual prod strings. Cont running tubing strings. Fin run tbg. Spacing out for hanger. Circ. Hung off tbg. Tested LS 1500# & SCSSV. Ran gauge dng to 14052' Pdnted: 05/28/98 12:09:43 PM Legal Well Name: SUNFISH 000003 Common Well Name: North Cook Inlet Unit B-2 Event Name: Sidetrack Start Date: 11/14/97 End Date: DATE TMD i 24 HOUR SUMMARY: Run dummy in LS. Run gauge in SS. Set plug. Set pkr. ND BOPs 02/01/98 02/02/98 02/03/98 02/04/98 02/05/98 02/06/98 02/O7/98 02/08/98 02/09/98 02/10/98 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (ft) 14,537 (fi) 14,537 (ft) 14,537 (fi) 14,537 (ft) 14,537 (ft) Fin RU test equip. RU coil tubing. Prep to test well test equip. Pdnted: 05/28/98 12:09:43 PM AnadriI1 Schlumberger Alaska District 1111 East 80th Avenue Anchorage, AK 99518 <907) 349-4511 Fax 344-2160 19 Mar 1998 u 0 Client .... : PHILLIPS PETROLEUM COMPkNY Field ..... : Cook Inlet Well ...... : NCIU-B2 Vert sect.: 166.66 deg az DD engnro.: Units ..... : FEET WELLHEAD coordinates...: 0,0 Position ca!c.: Minimum Curvature DLS calc meth.: Lubinski Survey Date...: 19 Mar 1998 [CB Elevation..: 132.00 ft Reference ..... : 14 Magnetic dctn.: +22,211 (E) R]ECORD OF SURVEY (Calculated from a tie-in station at 8930 MD) MEASURED INCLN DIRECTIOlq DEPTH ANGLE AZIMUTH 8930 , 00 25 . 70 347 . 80 8967.26 25.09 349°85 8998.38 23.98 350.07 9029,62 23 . 62 350 . 10 9060.18 23.38 349.55 3 9156.42 22,83 351.06 3 9248.17 22,01 350.68 3 9342.87 19.15 352.53 3 9433.99 16.96 354.02 3 9530.51 15,99 351.45 Pg: 1 VERTICAL -DEPTHS SECTION TVD SUB- SEA DEPART 8142.06 8010.06 -3360,30 8175.72 8043.72 -3376,27 8204.03 8072.03 -3389,17 8232.61 8100.61 -3401,75 8260.64 8128.64 -3413.92 8349. I6 8217 . 16 -3451 . 61 8433 . 97 8301.97 -3486.51 8522 . 62 8390 . 62 -3519 . 67 8609.25 8477.25 -3547.72 8701.81 8569.81 -3574.93 CO 0RD I NATES - FROM WELLHEAD 3291.75 N 682.04 W 3307.42 N 685.14 W 3320.15 N 687.39 W 3332.57 N 689.56 W 3344.56 lq 691.72 W 3381.78 lq 698.08 W 3416.33 N 703..63 W 3449.25 N 708,53 W 3477.29 N 711.85 W 3504.44 N 715.30 W 3 9624.06 13.91 352.60 3 971'7.25 12.07 350.57 3 9810.50 10.49 351.13 3 9904.51 8.25 350.47 8792.19 8660.19 -3598.96 8882.99 8750.99 -3619.82 8974.43 8842.43 -3638.01 9067.18 8935.18 -3653.28 3528.34 N 718.66 W 3549.06 N 721.70 W 3567.06 N 724.61 W 3582.17 N 727.04 W ~Station Types: 3/MWD 8/TIE-IN (A~adrill (c)98 ~CII~2D 3.2C 8:]2 .~ D) i00 <TIE 2.87 3.58 1.15 1.06 0.84 0.91 3.10 2.46 1.26 2.25 2.03 1-70 2.39 NCIU-B2 S MEASURED INCLN T DEPTH ANGLE 3 9992.26 6.56 3 10085.40 3.68 3 10179.23 2.08 3 10274.65 3.97 3 10377.98 6.57 3 10472.97 8,76 3 10565.29 !0.74 3 10659.12 12.36 3 10754.19 14.64 3 10850.89 16.82 RECORD OF SURVEY (Calculated from a tie-in station at 8930 MD) DIRECTION VERTICAL-DEPTHS SECTIOlq AZIMUTH TVD SUB-SEA DEPART COORDINATES-FROM WELLHEAD 354.90 9154.20 9022,20 -3664.52 3593 13.8% 9246.96 9114.96 -3672.45 3601 74.72 9340.69 9208,69 -3675.18 3604 117.10 9435.98 9303.98 -3673.10 3603 132.40 9538.87 9406.87 -3665.89 3598 19 Mar 1998 139.75 9633.01 9501.01 -3654.95 3589 142. !1 9723 . 99 9591 . 99 -3640 . 85 3576 142 o 92 9815.92 9683.92 -3623.7l 3562 144.42 9908.36 9776.36 -3603.27 3544 147.69 10001.43 9869.43 -3578.73 3522 · 37 N 728.53 W .58 N 728.29 W · 95 N 72S.93 W .90 lq 721,31 W .29 N 713.76 W · 10 N 705.08 · 95 N 695.25 · 03 N 683.82 .14 N 670.70 .38 N 656.11 DL/ 100 2.03 3.55 3.44 2.94 2.84 2.52 2.19 1.74 2 2.43 I- 3 10944,83 18.52 3 11020.13 19.89 3 11114,90 21.00 3 11208.03 21.70 3 11284.32 23.02 3 11349.49 22.71 3 11396.42 22.99 3 11492.90 22.44 3 11586.13 22.84 3 11650.91 23.87 150.81 10090.94 9958.94 ~3551.52 3497 t53.00 10162.05 10030.05 -3527.57 3476 155.51 10250.85 10118.85 -3495.24 3446 160.62 10337.59 10205.59 -3461.74 3414 164.22 10408.15 10276.15 -3432.81 3387 165.15 10468.20 10336.20 -3407.50 3362 165.05 10511.45 10379.45 -3389.29 3345 165.80 10600.44 10468.44 -3352.04 3309 166.64 10686.49 10554.49 -3316.16 3274 167.56 10745.96 10613.96 -3290.48 3249 .86 N 641.56 W .01 N 629.92 W · 19 N 615.56 W .76 N 602.93 W .09 N 594.19 W .67 N 587.50 W .06 N 582.81 W .0I N 573.43 W .15 N 564.89 W .12 N 559.16 W . 2, 1, 2, 2. · 0. 0. 0. 1. 07 06 49 13 49 73 6O 55 69 3 11679.09 23.63 3 11737,48 23 , 33 3 11772.70 23.48 3 11862.40 23.43 3 11958.29 22.85 3 12051 · 44 22.74 ~Station Types: 3/MWD (A~adrill (c) 98 I~CIUB2D 3·2C S:32 A~ D) 167.56 10771.75 10639.75 -3279.13 168.21 10825.31 10693.31 -3255.87 168.12 10857.63 10725.63 -3241.89 168.45 10939.92 10807.92 -3206.20 168.43 11028.10 10896.10 -3168.53 168.53 11113.97 10981.97 -3132.46 3238.04 N 556.71 3215.29 N 551.83 3201.60 N 548.96 3166.6% N 541.71 3129.72 N 534.16 3094.36 N 526.95 W 0.85 0.68 0.44 0.16 0.60 0,13 NCIU-B2 S MEASURED IlqCLN T DEPTH ANGLE 3 12146,84 22.66 3 12237.33 22,35 3 12331.90 22.82 3 12424,28 23.49 3 12518.52 23.66 3 12611.99 23.99 3 12706.21 24.04 3 12792.74 24.40 3 12887.73 24.21 3 12982,42 24,t5 RECORD OF SURVEY {Calculated from a tie-in station at 8930 MD) DIRECTION VERTICAL -DEPTHS SECTION AZ IMUTH TVD SUB- SEA DEPART 168.71 11201.98 11069.98 -3095.67 168.41 11285.58 11153.58 -3061,05 168.87-11372.90 11240.90 -3024,75 169.58 11457.83 11325.83 -2988.46 169.63 11544.21 11412,21 -2950,82 COORD IlqATES - FROM WELLHE~D 3058,27 N 519.69 3024.32 lq 512.82 2988.71 N 505.67 2953.02 lq 498.88 2915.95 N 492.08 169.68 11629,71 11497,71 -2913.12 169,73 11715,78 11583,78 -2874.83 169,85 11794.69 11662,69 -2839.38 170,08 11881,26 11749.26 -2800.35 169,73 11967.64 11835.64 -2761.62 2878.81 N 485.30 2841,08 lq 478.45 2806.15 lq 472,15 2767.65 lq 465.34 2729.46 lq 458.54 19 Mar 1998 DL/ 100 0.11 0.37 0.53 0.79 0.18 0,35 0.06 0.42 0.22 0,16 3 13076.83 24,38 3 13170.67 24.21 3 13264.53 24.09 3 13357.74 23.94 3 13452,27 23.97 3 13544.95 23.96 3 13636,82 23,99 3 13730o18 24.22 3 13823.65 24.65 3 13915.10 25.08 169.24 12053,71 11921.71 -2722,87 169.43 12139.24 12007.24 -2684,31 169.05 12224.89 12092.89 -2645.94 169.02 12310.03 12178.03 -2608,04 169.02 12396.42 12264.42 -2569,69 2691.31 lq 451.46 W 2653.37 lq 444.32 W 2.615.65 lq 437.15 W 2578.41 lq 429.93 W 2540.'73 N 422.62 W 168.60 12481.11 12349.11 -2532.07 2503.80 lq 415.32 168.48 12565.05 12433.05 -2494.76 2467.21 lq 407.90 168.62 12650.27 12518.27 -2456,66 2429.84 N 400.33 168.37 12735.37 12603.37 -2418,01 2391.95 N 392.62 167.65 12818.34 12686.34 -2379.57 2354.34 N 384.63 0.32 0.20 0.21 0.16 0.03 0.18 0.06 0.25 0.47 0.58 3 14008,75 25.45 3 14098, 80 25.67 3 14191,82 25, 90 3 14286.00 26.01 3 14374.48 26.66 167.21 12903,03 12771,03 -2339,60 167.03 12984.27 12852.27 -2300.75 167.37 13068.03 12936.03 -2260.29 168.49 13152.71 13020.71 -2219.08 167.85 13232.00 13100,00 -2t79.84 2315.33 lq 375.93 2277.45 lq 367.27 2237.99 lq 358.30 2197.69 N 349.69 2159.27 N 341.64 0.44 0.26 0.29 0.53 0.80 3 14470.72 27.29 ^Station Types: 3 (Anadrill [c}98 NCIUB2D 3.9-C 168.38 8:32 A~ D) 13317.77 13185,77 -2136,20 2116.55 N 332,65 0.70 NCIU-B2 R~CORD OF SURVEY (Calculated from a tie-in station at 8930 MD) S MEASURED INCLN DIRECTION VERTI CAL-DEPTKS SECTION COORDINATES-FROM T DEPTH ~NGLE AZ IMUTH TVD SUB- SEA DEPART WELLHEAD J 14537.00 27.72 168.7~ 13376.56 132~4.56 -2105.61 19 Mar 1998 DL/ 100 2086.55 N 326.58 W 0.69 ^Station Types: J/PROJECTED Pinal closure from wellhead: 2112.0 FEET at 351.10 {Anadrill {e)98 NCIUB2D 3.2C B:32 AM D) < L'f'4 ;'1~,, rt, ~:~:-] i:_,: [:-] J Anaddll SURVEY REPORT Client: Phillips Petroleum Company Field: North Cook Inlet Well Name: SF-3A (P-12) APl number: 50-883-20090 Job number: 40001828 Rig: UNOCAL 428 County: Kenai State: AK Survey Calculations Calc method for positi¢ Minimum Curvature Calc method for DLS: Mason & Taylor Depth references Permanent datum Depth reference GL above Permanent KB above Permanent DF above Permanent Vertical section origin Latidude (+N/S-): Departure (+E/W-): Azim from rotary table to target: MSL DF 0 FT -130 FT 132 FT 132 FT 0 FT 0 FT 166,7 degrees Schlumberger ANADRILL Survey Report Spud Date: Last survey date: Total accepted surveys: MD of first survey: MD of last survey: 29-N°v-97 66 893O FT 1447O.72 FT GeomagneUc data Magnetic Model: MagneUc Date: Magnetic field strength: Magnetic dec (+E/W-): Magnetic Dip: BGGM 1996 Version 19-Nov-97 1109.63 HCNT 22.25 degrees 73.88 degrees MWD Survey Reference Criteria Reference G: 1002.05 milliG Reference H: 1008.92 HCNT Reference Dip: 76.86 degrees Tolerance G: 4 milliG Tolerance H: 6 HCNT Tolerance Dip: 0.3 degrees CorrecUon Magnetic dec (+E/W-): Grid convergence (+E/W-): Total az corr (+E/W-): 22.22 degrees 0 degrees 22.22 degrees Seq Measured Incl Azimuth Course TVD Vertical Displacement # Depth angle angle length depth section +N/S- +E/W- (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) Total at Azm D LS Srvy Tool displacement (deg/ tool quality (ft) (deg) 100f) type type 1 8930.00 25.70 347.8 0.00 8142.10 2 8967.26 25.09 349.9 37.30 8175.80 3 8998.38 23.98 350.1 31.10 8204.09 4 9029.62 23.62 350.1 31.20 8232.63 5 9060.18 23.38 349.5 30.60 8260.70 6 9156.42 22.83 351.1 96.20 8349.18 7 9248.17 22.01 350.7 91.80 8434.04 8 9342.87 19.15 352.5 94.70 8522.69 9 9433.99 16.96 354.0 91.10 8609.30 10 9530.51 15.99 351.5 96.50 8701.84 11 9624.06 13.91 352.6 12 9717.25 12.07 350.6 13 9810.50 10.49 351.1 14 9904.51 8.25 350.5 15 9992.26 6.56 354.9 16 10085.40 3.68 13.8 17 10179.23 2.08 74.7 18 10274.65 3.97 117.1 19 10377.98 6.57 132.4 20 10472.97 8.76 139.8 -3360.34 3291.80 -682.00 3361.71 348.30 -3376.32 3307.49 -685.11 3377.70 348.30 -3389.21 3320.20 -687.36 3390.61 348.30 -3401.78 3332.61 -689.53 3403.19 348.31 -3413.97 3344.62 -691.69 3415.39 348.32 -3451.64 3381.82 -698.05 3453.12 348.34 -3486.55 3416.39 -703.59 3488.09 348.36 -3519.71 3449.31 -708.49 3521.32 348.39 -3547.76 3477.35 -711.83 3549.45 348.43 -3574.97 3504.49 -715.28 3576.74 348.46 93.60 8792.26 -3599.01 3528.39 -718.66 3600.84 348.49 93.10 8882.98 -3619.85 3549.10 -721.69 3621.73 348.51 93.30 8974.47 -3638.05 3567.11 -724.60 3639.96 348.52 94.00 9067.21 -3653.31 3582.22 -727.04 3655.25 348.53 87.80 9154.28 -3664.56 3593.43 -728.52 3666.53 348.54 93.10 93.80 95.40 103.40 95.00 9247.01 9340.70 9435.98 9538.93 9633.08 13672.49 3601.63 -3675.22 3605.00 -3673.14 3603.95 -3665.93 3598.33 -3654.98 3589.14 Page 1 -728.28 -725.92 -721.31 -713.76 -705.07 3674.52 3677.36 3675.43 3668.44 3657.74 0.00 TIP 2.82 MWD_M 3.59 MWD_M 1.15 MWD_M 1.11 MWD_M 0.87 MWD_M 0.91 MWD_M 3.09 MWD_M 2.46 MWD_M 1.26 MWD_M 2.25 MWD_M - 2.03 MWD_M 1.70 MWD_M - 2.39 MWD_M - 2.03 MWD 6-axis 348.57 3.54 MWD 61axis 348.61 3.44 MWD 6-axis 348.68 2.94 MWD 6-axis 348.78 2.84 MWD 6-axis 348 89 _2.52__~.~ MWD · -6-axis Schlumberger ANADRILL Survey Report Seq Measured Incl Azimuth Course TVD Ve~ical Displacement Total at Azm DLS Srvy Tool # Depth angle angle leng~ dep~ section +N/S- +E/W- displacement (deg/ tool qu~i~ (ft) /deg) /deg) (ft) (ft) (ft) (ft) (ft) (ft) (deg) lOOf) ~pe ~pe 21 10565.29 10.74 142.1 92.30 9724.04 -3640.89 3576.99 -695.25 3643.93 349.00 2.19 MWD 6-axis 22 10659.12 12.36 142.9 93.80 9815.94 -3623.75 3562.08 -683.83 3627.13 349.13 1.74 MWD 6-axis 23 10754.19 14.64 144.4 95.10 9908.41 -3603.31 3544.19 -670.69 3607.09 349.28 2.43 MWD 6-axis 24 10850.89 16.82 147.7 96.70 10001.48 -3578.76 3522.42 -656.10 3583.01 349.45 2.44 MWD 6-axis 25 10944.83 18.52 150.8 93.90 10090.95 -3551.57 3497.92 -641.56 3556.27 349.61 2.07 MWD 6-axis 26 11020.03 19.89 153.0 75.20 10161.97 -3527.65 3476.10 -629.93 3532.71 349.73 2.06 MWD_M 27 11114.84 21.00 155.5 94.80 10250.79 -3495.31 3446.27 -615.56 3500.81 349.87 1.49 MWD 5-axis 28 11208.03 21.70 160.6 93.20 10337.61 -3461.79 3414.82 -602.91 3467.63 349.99 2.13 MWD 6-axis 29 11284.32 23.02 164.2 76.30 10408.17 -3432.85 3387.16 -594.16 3438.87 350.05 2.49 MWD 6-axis 30 11349.49 22.71 165.1 65.20 10468.25 -3407.54 3362.73 -587.45 3413.65 350.09 0.72 MWD 6-axis 31 11396.42 22.99 165.0 46.90 10511.47 -3389.33 3345.13 -582.76 3395.51 350.12 0.60 MWD 6-axis 32 11492.92 22.44 165.8 96.50 10600.48 -3352.08 3309.07 -573.36 3358.38 350.17 0.65 MWD 6-axis 33 11586.13 22.84 166.6 93.20 10686.50 -3316.20 3274.23 -564.81 3322.59 350.21 0.54 MWD 6-axis 34 11650.91 23.87 167.6 64.80 10745.99 -3290.52 3249.19 -559.08 3296.94 350.24 1.70 MWD 6-axis 35 11679.09 23.63 167.6 28.20 10771.80 -3279.16 3238.10 -556.64 3285.59 350.25 0.85 MWD 6-axis 36 11737.46 23.33 168.2 58.40 10825.37 -3255.90 3215.35 -551.76 3262.35 350.26 0.66 MWD 6-axis 37 11772.70 23.48 168.1 35.20 10857.67 -3241.92 3201.66 -548.89 3248.37 350.27 0.44 MWD 6-axis 38 11862.40 23.43 168.5 89.70 10939.96 -3206.23 3166.71 -541.62 3212.69 350.29 0.14 MWD_M 39 11958.29 22.85 168.4 95.90 11028.14 -3168.56 3129.79 -534.04 3175.03 350.32 0.60 MWD 6-axis 40 12051.44 22.74 168.5 93.10 11113.97 -3132.51 3094.45 -526.82 3138.98 350.34 0.13 MWD 6-axis 41 12146.84 22.66 168.7 95.40 11201.98 -3095.71 3058.36 -519.54 3102.18 350.36 0.12 MWD 6-axis 42 12237.33 22.35 168.4 90.50 11285.59 -3061.09 3024.41 -512.66 3067.55 350.38 0.37 MWD 6-axis 43 12331.90 22.82 168.9 94.60 11372.93 -3024.78 2988.79 -505.51 3031.24 350.40 0.54 MWD 6-axis 44 12424.28 23.49 169.6 92.40 11457.89 -2988.49 2953.10 -498.74 2994.92 350.41 0.78 MWD 6-axis 45 12518.50 23.66 169.6 94.20 11544.23 -2950.86 2916.04 -491.94 2957.24 350.42 0.18 MWD 6-axis 46 12611.99 23.99 169.7 93.50 11629.76 -2913.15 2878.89 -485.15 2919.48 350.43 0.36 MWD 6-axis 47 12706.21 24.04 169.7 94.20 11715.81 -2874.86 2841.17 -478.30 2881.14 350.44 0.05 MWD 6-axis 48 12792.74 24.40 169.8 86.50 11794.69 -2839.43 2806.25 -471.99 2845.66 350.45 0.42 MWD 6-axis 49 12887.73 24.21 170.1 95.00 11881.27 -2800.39 2767.74 -465.16 2806.56 350.46 0.24 MWD 6-axis 50 12982.42 24.15 169.7 94.70 11967.66 -2761.66 2729.56 -458.36 2767.77 350.47 0.18 MWD 6-axis 51 13076.83 24.38 169.2 94.4 12053.72 -2722.92 2691.42 -451.26 2728.99 350.48 0.33 MWD 6-axis 52 13170.67 24.21 169.4 93.9 12139.31 -2684.32 2653.46 -444.08 2690.36 350.50 0.20 MWD 6-axis 53 13264.53 24.09 169.1 93.8 12224.90 -2645.99 2615.75 -436.92 2651.99 350.52 0.18 MWD 6-axis 54 13357.74 23.94 169.0 93.2 12310.03 -2608.09 2578.51 -429.72 2614.08 350.54 0.17 MWD 6-axis 55 13452.27 23.97 169.2 94.6 12396.48 -2569.72 2540.8 -422.46 2575.68 350.56 0.09 MWD 6-axis 56 13544.95 23.96 168.6 92.6 12481.1 -2532.13 2503.89 -415.22 2538.08 350.58 0.26 MWD 6-axis 57 13636.82 23.99 168.5 91.9 12565.07 -2494.81 2467.29 -407.8 2500.77 350.61 0.05 MWD 6-axis 58 13730.18 24.22 168.6 93.4 12650.33 -2456.69 2429.9 -400.23 2462.65 350.65 0.25 MWD_M 59 13823.65 24.65 168.4 93.5 12735.45 -2418.03 2392 -392.52 2424 350.68 0.47 MWD_M 60 13915.10 25.08 167.6 91.4 12818.38 -2379.61 2354.41 -384.53 2385.61 350.72 0.60 MWD_M 61 14008.75 25.45 167.2 93.6 12903.03 -2339.66 2315.43 -375.81 2345.73 350.78 0.44 MWD_M 62 14098.80 25.67 167.0 90.1 12984.31 -2300.79 2277.53 -367.13 2306.94 350.84 0.26 MWD_M 63 14191.82 25.90 167.4 93 13068.05 -2260.34 2238.09 -358.17 2266.56 350.91 0.31 MWD_M 64 14286.00 26.01 168.5 94.2 13152.75 -2219.12 2197.77 -349.56 2225.39 350.96 0.52 MWD_M 65 14378.48 26.66 167.9 92.5 13235.65 -2178.1 2157.61 -341.14 2184.41 351.02 0.78 MWD_M 66 14470.72 27.29 168.4 92.2 13317.82 -2136.29 2116.69 -332.51 2142.64 351.07 0.74 MWD_M Page 2 ! SIDEWALL CORE DESCRIPTIONS NCIU-B-2 JAN. 6, 1998 DEPTH CORE RECVRY MILLIPORE PERM DESCRIPTION md. 13,647 0.5" brkn 0.46 Fine-gr Sandstone, si. carb., poor vis. porosity, scattered white fluor, poor milky white cut fluor. 13,655 0.25" brkn 0.19 Fine-gr Sandstone, si. carb., poor vis. porosity, scattered white fluor., poor milky white cut fluor. 13,720 1.75" 180.67 Course-v course gr Sandstone, si carb.,fair vis porosity, bright white fluor., strong milky white cut fluor. 13,731 0.25" brkn no data Fn-med. gr Sandstone, poor-fair vis. porosity, si. carb., scattered white fluor., slow streaming milky white cut fluor. 13,822 0.75" brkn 0.24 Fn-med. gr Sandstone, poor vis. porosity, si. carb., scattered dull white fluor., slow streaming milky white cut fluor. 13,828 2" 0.79 Fn. gr. Sandstone, fair vis. porosity, white to It. blue fluor, weak milky white cut fluor. 13,838 1.5" no data Fn gr. Sandstone, mod. vis. porosity, It. green fluor., fast streaming blooming milky white cut fluor. 13,845 2" 52.87 Course-v course gr Sandstone, si carb. poor to fair vis porosity, bright white fluor., strong milky white cut fluor, scattered light brown oil stain. 13,850 1" 90.23 Fine-med. gr. Sandstone,si. carb., friable, good ,vis porosity, white flour, milky white cut fluor. 13,883 2" 50.55 V. Coarse gr to granule Sandstone, si. carb., poor to fair vis. porosity, bright white fluor., weak milky white cut fluor. 13,908 ' 2" brkn 1.01 ~ned. gr Sandstone, no vis. porosity, quartz cement, no fluor, or cut fluor. 13,912 1.5" brkn 5.05, med. to coarse gr. Sandstone, si carbonaceous, fair vis. porosity, It. green fluor, no cut fluor. 13,920 2" 1.07 med. gr. Sandstone, carbonaceous, no vis. porosity, no fluor or cut fluor 13,946 1.5" 2.81 med. gr. Sandstone, si. carbonaceous, no vis. porosity, no fluor, or cut fluor 13,956 2" no data pebble conglomerate with coal, no vis. porosity, no fluor, or cut fluor CORE LABORATORIES Company · PHILUPS PETROLEUM We/I · NCIU No. B-2 Fmld ' Stale · Alaska CL Fiie No: 57151-18668 Date- 14-,Jan-1998 Analysts: WeirlKosler ROTARY SIDEWALL - DEAN STARK FLUID SATURATIONS '- S~mpl, Depth Poro~'ity " Pern,~abil~ly ' _ ' Sa~r,tion " Grab Number Kli_.n.k, enberg ..J _Kelt Oil J Weter Density fl ... % md .,. % pOre-Volume glcm3 5 13828.00 6.3 0.070 O, ~04 36.9 62.3 2.66 6 13845,00 15.1 35.0 41.0 64.7 23.3 2.64 9 13908,00 0,7 <0.01 <0,01 15.2 58.1 2.62 11 13920,00 11.9 0.275 0.373 55.6 39.2 2.67 12 ! 3946,00 11.2 0,575 0.759 58.8 35.2 2.66 13 13956.00 7.6 2.040 2.550 65.6 32.2 2.65 p:\atyonek\b2\perfs 23jan98 NCIU B-2 PERFORATIONS Depth reference is quad-combo run of 5 Jan 98 approx deviation 24.2 24 24.2 24.6 25.1 25.3 SUNFISH delta h, ft 13,110 13,170 60 tbg-conveyed, 4 5/8 in, 12 SPF 600 psi underbalance NORTH FORELANDS fi-MD 13,652 13,686 34 13,718 13,736 18 13,818 13,856 38 13,901 13,920 19 13,944 13,966 22 through-tubing, 2 1/8 in phased Enerjet 6 SPF 131 fi:l-VD 12,085 12,140 (gross sand interval is 13110 to 13184 md or 12085 to 12153 tvd) ft-TVD 12,580 12,611 12,640 12,656 12,730 12,765 12,806 12,823 12,845 12,864 delta h, fl 55 31 16 35 17 19 118 0311911998^ SCAN & MANUAL WELL TEST REPORTS PHILLIPS PETROLEUM COMPANY WELL: TYONEK B-2 TYONEK PLATFORM NORTH COOK INLET SUNFISH SAND (SHORT STRING) Production Test # 1 & 2 NORTH FORELANDS SAND (LONG STRING) FEBRUARY 3rd - 9th, 1998 M CROF L HAI_LIBURTON HALLIBURTON EN E R(~Y SERVICES DISCLAIMER The calculations in this report are based on certain data, assumptions and applied mathematical methods. Inaccurate well data, changing well conditions, tolerance variations of mechanical components, mechanical malfunctions and other factors may affect these calculations. Halliburton Energy Services, Alaska makes no warranty, express or implied, as to the accuracy of the data, calculations or opinions expressed herein, or of merchantability or fitness for a particular purpose. User agrees by its purpose thereof that user will release, indemnify and costs related there to adsing out of or in conjunction with such use and incurred by user or third parties, whether due to negligence or otherwise. OHALLIBURTON ENERCY SERVICES TABLE OF CONTENTS PHILUPS PETROLEUM TYONEK B-2 SECTION I ...................................................... WELL TEST OVERALL JOB LOG & EQUIPMENT LIST SUNFISH SAND (SHORT STRING) SECTION II ..................................................... PRODUCTION TEST #1 MANUAL DATA SECTION III .................................................... PRODUCTION TEST #1 SCAN DATA NORTH FORELANDS SAND (LONG STRING) SECTION IV ................................................... PRODUCTION TEST #1 MANUAL DATA SECTION V .................................................... PRODUCTION TEST #1 SCAN DATA SUNFISH SAND (SHORT STRING) SECTION VI., .................................................. PRODUCTION TEST #2 MANUAL DATA iml SEQUENCE OF OPERATIONS ! I I II COMPANY: Phillips Petroleum WELL: B-2 LEASE: Tyopek · FIELD: Cook Inlet ' TICKET# 693321 I I I I I I II · . . 29-Jan-98 13:30 c KREISER, R HINDE, D JONES TO KENAI TO COORDINATE LOADOUT 30-Jan-S8 10:00 RHINDE, D JONES I~oM KENAI AIR T'(~ TYoNEK~' Si~OT EQUIPMENT 31-Jan-98 06:00 COLUNS, ZEDmES,TUCKER,STEVENS FLIGHT TO"~ENAI ' 10:00 coLLINs,KREISER,STEVENS FRoM KI~N/[,i'AiR TO TYONEK '" i~:30 ALLABOVE " SPOTTING f~N'I;(S ...... 43:00 ZEDDIES', TUCKER FROM KEN/~,I AIR TO TYONEK 15:30 S:I'A~tT SHIFT WORK I JONES, HINDE, STEVENS, ZEDDIES TO BED ' '~S:3~ !COLLINS, KREISEI~, TucKER STAR1: I~J~ING FLARE LINES'AND RELI~=F FOR P-TANK ......... MovE Misc. EQUIPMENT 6-UT oF THE W~( 20:00 BOAT ON LOCATION UNLOAD AND SPOT EQUIPMENT 21:00 CREWCHAN(~E CONTINUE[ TO OFFLOAD AND'SPOT EQUIPMENT '" 1-Feb-S8 06i(~0 START RI:JN~I'NG HilLC~'O~Si OIL, AND RELII~F LINES ~' 06:00 CREWCHANGE " CONTINUE WITH LINES .......... 1'1 :l~b ' TEST P::I:AI~'K'/~ND'~ET GAS SKID CONTROLLER 15:00 ~ET UP VESSEL SAFE~I'Y SYS~EMS,'~ONTROLLERS, AND METERS 48:00 NK~HT CREW ON TOWER I~[J~ LIQUII~ i'INES'FROM OIL SKID TO MANIFOLD TO TANKS :~2:00 DAY CREW oFF ' . i:iE' IN Hi)LO GAS Y0 BOOM .......... 2-Feb-98 ~0:00 ' TIE IN RELIEF LINES TO B~OM " ~;~i00 RUN SAFE'r~ s~"STEM"To ALI~'COMPONENTS ~l~:00 CREW ClJAN(~E DRAIN"0FF ~ANKS FROM DRiLLI~(~' ACTIVITIES 11:01~ ' RbN'FLdw LINE FR'OM"UN'i'~'To HEATER TO CHOKE MANIFOLD 15:00 P. TEST UNITS TO ~000 PSI i~:00 CREWCflANGE CONTINOE W/SAMiE ..... ~O:0~ ....... FiEI' i'iEATER w~'W~TER 22:OO FiLL i'iEATER t~) FUEL'" ~:~:00 " 'I~'E'AYER WiLL klOf'"FIRE GET RIG ELEC. "" 3-Feb-98 ~6i00 MECH FIRED Up HEATER ..... 01:00 GO THROUGH SYSTEI~ ~OUBLE CHECK EVERYTHING 03:00 S'A'FE'TY'MEETI~I~' WIT~I coM'I~ANy MAN AND KEY PERSONEL Page 1 SEQUEN(~E OF OPERATIONS I I ! I I I I COMPANY: Phillips petroleum WELL: B-2 .. LEASE: Tyonek · · FIELD: Cook Inlet TICKET# 693321 I II Ill I I I I .,, 05:05 OPEN WELL ' " SEE JOB 'I~ESULTS 4-Feb-98 04:56 " ESI~ PUL~ED DuE TO SPILL FROM TANK ' ' ' ' b5:O0 " CLEAN UP S~'ILL .......... 07:00 AREA ~LEA'I~IEd " GAUGES RUN IN HOLE, LOST IN HOLE STAND B~; FOR NEXT TEST ' ?-Feb-98 13:30 !PSI TE~'T-TO' 8000 LBS ' · ~S:10 ...... SAFETY M'EE~II~G .... iS:l~ " oPEN W~L " SEE JOB RESULTS '"8.Feb.98' 04:24 ~H'~T'iN WELL AT MANIFOLD MONITER BUILDUP ......... ~3:45 END BUII~b UP .......................................... -8-Feb-98 i7:'~5 OP[~ ~U~FI~H WELL' FLOW 1 TUBING VOLUME. "' lS:lS" Sh'UT IN ~E£L .............. '" ;~:1~0 E~'0W LI~J'Es 'DOWN START RIG' DOWN 9-Feb-98 00:00 CONTINUE TO RIG DOWN " ' ;~2:00 'BROWN,FAERES !SCAN PERSONi~'L ~:0 BEACH ...... CONTINUE TO RiG 'DdWN ' 13:00 DRAIN TANKS ...... ~5:00 ' TALK WI COMPANY REP GO oVER'RIG DOWN ~8:00 ~;~oPPER D~.[J~,YE'D ................. ~}:00 ....... FLIGHT OFF TY~NEK LEAVE ZEDDIES AND STEVENS ..... ~:~0 FINALIZE CLI~AN U'F; FROM ~I'G DOWN ..... 21:00 COLUNS, ~UCKER, HINDE'J01NER FLIGHT BAcK TO ANCH ............. !0..Feb-It8 00:00 LbAD b~-:l",W_l '~cIUI~i~IE~T 08:bO ZE, DDIE$ $~'VEN$ bLEAN UP AFTER TANK MATS MOVED .......... RESIDUAL OIL LEFT F~OM ~l~l£L ..... Page 2 SEQUENCE OF OPERATIONS ' I I I I I I COMPANY: Phillips Petroleum WELL: B-2 .. LEASE: Tyonek .. FIELD: Cook Inlet TICKET# 693321 ! II I I 17:00 ZEDDIES, STEVENS FLIGHT TO KENAI , , ,,,, , ,,,,,, , , ..... , , , , ,, ,,, ,, .... ,,, ,,,, ,, ..... , ,, ...... · ,,, Page 3 SUNFISH SAND TEST 1 MANUAL WELL TEST REPORT FIELD READINGS FIELD READINGS Date , ' .... Time , C~mments , Wellhead Choke Gas Meterln[[ ,, Fluid Tank Me~rin~ Tubng Well Mnfld Diff Static Gas Meter Orlf. Meter Oil Oil Press Temp Dla Press Press ~Temp H2S CO2 N: SG Run Dia ReadingTeml: Grav BSW Day-Mo-,,Y,r-Hr:Min:Sec pst~l F 64th Inh2o psl~ F ppm % % in in bbl F APl60 % 03-Feb-98 05:05:00 0,0 03-Feb-98 ' 05:10:00 ' ' 18,4 100.0 . "03-'15eb-98 ' 05:15:00 30.9 100.0 03-1~eb-98 05:30:00 ' ' ' 30.9 ' 100.0 03-Feb-98 05:45:00 ' ....... 31.7 100,0 03-Feb'-98 06:00:00' ' ' 46,8 .~., 100.0 03-Feb-98' 0~:15:00,,, ' ., , " , ,, , 48,4 100.0 03-Fe1~'98 06:35:00 Start out of hoie w/CT,' could, ,not ~let thru ~las lift mandrel .. "~)3'-~:eb-98 "0'~':10:00 C/T start In hole to 8000' · '03-'F'eb-98' 08:45:00 .... 48.4 100,0 03-Feb-98 09:15:00 '" 48.4 ' 100,0 03-Feb-98 09:45:00 ....... 48,4 100.b 03-~=eb-98 10:06:00 Start pumping (~ 500 s, cf/m ' , ,, ,' ' , , , 48,4 100.0 03-~=eb.98 10:30:00 48.4! 100,0 03-Feb-98 .... 10:45:00 ' ' 48,4 100.0 03-Feb-98 ' 10:50:00 Start geffing returns ................ 03-Feb-98 11:00:00 75.1 100.0 '03-Feb-98 11:30:00 ....... 75,1 " 100.0 03-Feb-98 '11:45:00 ' ,, ,' ,,' ....... , ....... 75,t 100.0 03~J=~b"98 '12:00:00 76.0 43.4 99,0 ' 03-Feb-98 12:15:00 ........... 77.7 43,4 99.0 03-Feb-98 12:30:00 ............. 88,5 43,4 99.0 '03-Feb-98 12:45:00 .................... 92,7 43,4 99.0 ' 03-'~eb-98 '1'3:00:00 " ' 64 " ' 94.'3 43.4 99,0 "03-Feb-98 13:15:00 ' 85 64 ...... 40 ...... 99,4 43.4 94.5 03-Feb-98 13:30:00 135 66 40 108,4 43.4 96.5 03-Feb98 ...... 1~:45:b0 ...... 96 67 40 " ' 110,9 ' "43.4 80.9 03-Feb-98 "14:00:00 .... 96 ~6 40 ' 11~i~'[' 43.4 94.7 03-Feb~§a 14:15:00 ' ' 68 68 ' 4'~ ...... 12l~i(~r 43.4 89.5 03-Feb-98 "14:30:00 ........ 446 .... 68 " 40 ...... 130.9 ' ' ~,3.4 79.5 '03-Feb-98 14:45:00 .......... 294 ' 108 '40 ..... 136,7 43.4 74,5 03-Feb-98 15:00:00 .............. 211 66 '" 40 .......... ,, i"42,5 43,4"'73.0 03-Feb-{}8 15:15:00 ......... 140 67 40 ........ 142,5 '~,3.4 73.0 03-Feb-98 15':30:00 ............ 220 67 40 .... 142.5 43,4 73,0 ,, 03-Feb'ge '"15:45:00 , ' ' ,' , ........ 250 67 40 ' I .... 142,5, 43,4 54,5 03-Feb-98 ..... 16:00:00 170 67 40 142,5 43,4 54,5 03-Feb-98 16:15:00 " ' 220' 67 40 ....... 156',~ 43,4 54.0 '03-'1~eb-98''' ~6:30:00 ........ 330 ' ' 67 "' 40 .... 156,7 43,4 55.0 03-Feb-ii8 ' i6:45:00 ' ' 450 ' 67 35 175','§ 43.4 50,0 , ,,,, ' 03-Feb-98 't?i"00:00 ' ' 145 67 45 .......... 175,9 03-Feb-98 ' 17:15:00 Turn'welllntoseparato,r, , , 200 67 ,, 45 175.9 03-~=eb-98 17:30:00 ....... 5'95 67 45 64 50 100 0,~98 5.~61' 2.25 '188,4 109 43,4 69,0 03'F'eb-9e "17:45:0oi ....... 300 "' ~'1 45 ' '62' "50 100 0,998 5,761 2.25 20117 109 '43.4 69,0 03-F'eb-98 i8:00:00 ...... bOO ~ 45 62 50 100.' 0.998 5,761 2.25 210.0 'i08 43.4 14,5 0:~-F'eb-98 '18:15:00' ...... ~05 '~ ...... 45 64 50 i00 '" 0,998 5,761 2,25 220'i'0 110 .... 43.4 9.5 03-F~b-98' 18:30:00' ............ 312 i 67 '" 45 64 50 i00 0,'{~'§85,761 2.25 233.0 112 43.4 "14,5 Page 1 of 2 FIELD READINGS Date Time ' ' Comments Wellhead, Choke Gas Meterinl] ' ' ,, ' Fh~i[! Tank Meterln~ Tubng Well Mnfld Diff Static Gas Meter Orif. Meter OII Oil Press Temp Dia Press Press Temp H25 CO2 N2 SG Run Dia ReadingTeml: Grav BSW Da~/-Mo-Yr-Hr:MIn:Sec ..... pS~l~ ' F 64th inh2o psig F ppm % % in in bbl F APIS0 % 03-1~eb-98 19:00:00,,,5! 67 45 64 50 100 '" 0.998 5.761 2.25 254.7 112 43.4 0.0 03-Feb-98 19:30:00 ' 300 67 45 76 60 100 0.998. 5.76i 2.25 2'76.7 i12 43.4 0.0: 03-Feb-98 20:00:00 300 67 45 51 60 100 0.998 5.76i 2.251 298.2 111 43.4 0.0' 03-Feb-98 20:30:00 320. 67 45 7'~ 50 100 ' 0.998 5'.761 2.25 '~325.0 112 43.4 "0.O 03-Feb-98 2i:00:00 ' 400 68 45 76 60 100 ' 0.998 5.761 3125 ~49.2 '112 43.4 0.0 , , 03-Feb-98 21:30:00 440 68 45 72 60 100 0.998 5.761 2.25 385.0 112 43.4 0.0 03-Feb-98 22:00:00 400 68 45 6~ 60 9~) 0.998 5.761 2.25 424.4 110 43.4 '0.0 03-Feb-98' 22:30:00 440 68 45 ~,' 85 94 0.998 5.761 2.25 ~63.4 110 43.4 0.0 03-Feb-98 23:00:00 ..... 450 70 45 101 85 94 0.998 5,761 ~,'25 5~5,0 111 ;/3.4 0.0 03-Feb-98 23:30:00 S~SV Shut-in .......... 04-Feb-98 00:45:00 open well on 45~64" ad~ chk , 45 04-Feb-98 '01:00:00 450 72 45 100 80 92 0,94 5','761 2,25 5'50.9 110 ~3,4 0,0 " 04-Feb-98 01:30:00 ' " 450 72 45 10(~ 85 92 0,94 5.¥6i 2,25 594.6 i10 43,4 0,0 04-Feb-98 02:00:00 450 75! 45 107 90 99 " 0,94 5.761 ~-i'25 652.4 i10 43,4 0,0 04-Feb-98 02:30:00 .... 475' 7t~ 45 106 90 99 0.94 5,761 2,25 694.5 110 43,4 '0.0 04-Feb-98 03:00:00 ' 500 78 ~45 109 ' 90 95 0.94 5~'761 2.25 743.1 110 ;42,4 0.0 04-Feb-98 03:30:00 ' 500 78 45 110 90 94 0,94 5.761 ~.'25 793,7 'il0 42.4 0.0 04-Feb-98 04':00:00 ' 50{) 78 45 107 90 9~, .0.94 5'1761 2,25 845,3 110 ;4214 '-0.0 04-Feb'98 04:30:00 ' ' 500 78 45 107 90 94 0,94 5".'761 ~.'25 8~518 110 42.4 0.0 ,04-Feb-98 , 04:56:00 ESD Shut-in,, End ~3f test ..... , ",' ',' 'i ....... , , ' .......... , , "i' " , ' ,i,, Page 2 of 2 CALCULATIONS CALCULATIONS Date Tir~e DTime Gas Flow Oil Flow Water Gas Oil Water GOR OGR BS&W Rate FlowRate FlowRate Volume Volume Volume Day. Mo. Yr. Hr.'Min Hr rnmscfd bpd .bpd mm. scf bbl bbl scf/bbl bbl/rnscf 03-Feb-98 05:05 0.00 '03-Feb-98 05:10 0.08 ' ~3-Feb-98 05:15 0.17 " '" ~3.Feb.98 05:30 0,42 ' 03-Feb-98 05:45 0.67 03-Feb-98 06ih0 0.92 ' b3-Feb-98 06:15 1.17 ' 03-Feb-98 06:35 1.50 ' , 03-Feb-98 08:10 3.08 03-Feb-98 08:45 3.67 ' 03-'Feb-98 09:15 4.17 ' " 03-'Feb-98 09:45 4.67 ' ' ' b3-Feb-98 10:00 4.92 ' 03-Feb-98 10:30 5.42 b3-Feb-98 10:45 5.67 ....... 03-F~'b-98 10:50 5.75 ' 03-Feb-98 11:00 5.92 ' 03-Feb-98 11:30 6.42 ' ' , , , 03-Feb-98 11:45 6.67 0.00 0,00 100,0 03'Feb-98 12:00 6.92 0,81 '79,83 ' 0.01 0',83 ' ' 99,0 "'~'~-1580'-98 12:15 '7.17 .... :1,6{~ 1~8,7~ '" 0.03 2,48 " 99.0 03-Feb'98 12:30 ' 7.42 ' 10,43 1032.13 0.13 13'.24 ......... 99.0 03-Feb-98 12:45 7.67 4,01 397.27 0.18 17.37 99.0 03-Feb-98 13:00 7.9;~ ....... 1.58 '156.~ " 0.19 19.01 " 99,0 b3-Feb-98 13:'15 8.'17 26.61 45~.23 ' ' ' b.47 23,77 ' ' ' 94,5 03-Feb-9S 13::~b 8.42 ' 30,14 831,11 ' 0,'78 ' 32,43 .... 96,5 03-Feb-98 13:45 8.67 ' '~,5,84 194,1'6 ...... 1,26 34,45 " 80.9 '~3-Feb;98 14:00 '8.92 29,71 530.89 ' 1,57 39,9'8 ...... 94,7 O'{~-Feb-ga 'j4:15 9.17 ' 33,57 .... 286,16 1,92 42.96" ' 89,5 03-Feb-9a 14:30 ' 9.42 " 213,33 8~7.31 4,14 51.58 ~'g,5 03-Feb-98 14:45 §.67 142.72 416.98 5,63 ' 55,92 ' 74,5 "~3-Feb-98 15:00 '9,92 ' 151.37 409.27 ...... 7.21 60.19 73.0 03.Feb.98 15:15 ' i0.17 ' 0,00 0,00 ' 7.21 60.19 ' 03-Feb-'98 15:30 10.42 0,00 0.00 ' 7.21 60.19 ...... 03.Feb.98 15:45' '.{0.67 , b,O0 ' , 0,00 7.21 SOil'9 ,, "b3.Feb.98 16:00 10.92 '" 0,00 '0,00 .... 7,21 60.19 .... ..... 0'3-'Feb-98 16:15 1'1.17 ' ' 625.,75 734,57 ' 13,72 67,~4 ' ' ' 54'.0 03-Feb-98 16i30 1'~,42 " 0,00 0,00 13.72' 67,84 .... ' '03-Feb.-98""16i45" 11.67 92d.16 920.1~ 23.31 77.42 ....... 50,0: 03-Fe098 17:00 11.92 '" 0.00, 0.00 23.31 77,42 ' ' 03-Feb-98 17:15 12.17 0.001 0.00 '0,00 23,31 77,42 " 03-Feb~98 17:30 12.~.2 1,58 "'372,00 828.00 0,02 27,18 86,05 4235,58 ' ' 0.24, 69,0 03-Feb-'98 17:~.5 12.'~7 1.55 396.70 882.98 0.03 31.32 95.25 3908,51 0.26 69.0 ' b~,-F~b-98 18:00 12,92 1.55 68i,26 li 5.,~4 0.05 38.'41 96.45 22~'5.93 0.~;4 14.5 03'Feb-98 '18:15 13.17 115'8 868,80, §i'.20 ' 0.07 47.46 97.40 1813,58 0,55 ' '9,5 ' b~,-I~eb-98 18:30 " 13,42 ' 1,58 1067.041 180.96 O,~Ja 58.58 99',28 147~.64 0.68 "'14,5 03-F~b-98 19:00 13.92 1.5.8 1040,161 0.00 ' '0,111 80.25 '99,28 i 5.14,80 0.66 0.0 Page 1 of 2 CALCULATIONS ,,, Date Time DTime Gas Flow Oil Flow Water Gas Oil Water GOR OGR BS&W Rate FlowRate FlowRate Volume Volume Volume Day-Mo- Yr-Hr.'Min Hr mrnscfd bpd bpd rnrnscf bbl bbl scf/bb/ bb//rnscf ,% 03-Feb-98 19:30 14.42 1,85 1056.001 0.00 0.15 102.25 99,28 1750.79 0.57 0.0 , 03-Feb-98 20:00 14.92 1,51 1035.36 0.00 0.18 123.82 99,28 1459.61 0.69 0.0 03-Feb-98 20:30 15,42 1.67 1284,48 0.00 0.22 ~ 50,5§ 99.28 1302.14 0.77 0.0 03-Feb-98' 21:00 15.92 1.85 1161.60 b.do 0.26 174.78 99.28 i 591.63 0.63 0.0 03-Feb-98 21:30 16.42 1.80 1718.40 0.00 0.30 '210.58 99.28 1046.84 0.96 0.0 b3-Feb-98 22:00 16.92 1.76 1891.20 0.00 0.33 249.98 99.28 933.15 1.07 0.0 03-Feb-98 22:30 17.42 2.13 1872.00 0.00 0.:~8 288.98 99.28 1136.27 0.88 0.0 03-Feb-98 23:00 17.92 2.49 2476.80 0.00 0.43 340.58 99.28 1005.18 0.99 0.0 03-Feb-98 23:30 18.42 0.00 0.00 0.4'3 340.58 99.28 ' , 04-Feb-98 00:45 'I 19.6~' 0.00 0.00 0.43 340.58 99.28 04-Feb-98 01:00 19.92 2.49 430.80 '0.00 0.45 376.48 99.28 5770.10 ' 0.17~ 0.0 04-Feb-98 01:30 20.42 2.55 2097.60 0.00 0.51 420.18 99.28 1216.63 0.82 ' 0.0 04-Feb-98 02:00' 20.92 2.69 2774.40 0.00 0.56 ~77.98 99.28 969.26 1.03 0.0 - 04-Feb-98 02:30 21.42 2.68 2020.80 0.00 0.6~ 520.08 '99.28 1324.40 0.76 ' ' '0.0 04-Feb-98 03:00 21.§2 ' ' 2.73 2332'.80 0.00 0.68 ,~68.68 99.28 1168.29 0.86 ' 0.0 04-Feb-98 03:30 22.42 2.74 2428.80 ~}.00 '(~.7:~ 619.28' 99.28 1128.46 0.89 0.0 04-Feb-98 04:00 " 22.92 2.70 2476.80 ' 0.00 0.79 670.88 99.28 " 1091.18 0.92 0.0 04-Feb-9S ' 04:30 23.42 2.70 1464.00 0.00 0.85 701.38 '99.28 1846.06 0.54 04-Feb-98 ,04:56 23,85 , ' ....... 0,00 '0.0~ 0;85 ,7,0,1.38 , 99.28 .... 0.0 Page 2 of 2 CHARTS Well Test Report Phillips Petroleum Co. Well B-2 Sunfish Sand Tyonek Platform Job #1 Well Test Ticket # 693231 !:-.,~--Gas Rate (mscf/d) ,~, Time ~RTO N Well Test Report Phillips Petroleum Co. Well B-2 Sunfish Sand Tyonek Platform Job #1 Well Test Ticket # 693231 · Bill lB A · Time · Gas Rate (mscfld) AOil Rate (bbl/d) REPORT i TO N Phillips Petroleum Co. Job #1 Well B-2 Sunfish Sand Well Test Tyonek Platform Ticket # 693231 Date Time WHP Choke Static ' Gas ' -~il ' 'Water Gas OII Water GOR '" Gas S.~. 011 'Co'm~e~s ............ Day-Mo-Yr-Hr.'Min F 64th psig mmscfd , bpd bpd mscf bbl bbl scf/bbl , APl60 , , 03-Feb-98 05:05 03-Feb-98 05:10 03-Feb-98 05:15 03-Feb-98 05:30 ..... 1' 03-Feb-98 05:45 03-Feb-98 06:00 03-Feb-98 06:15 03-Feb-98 06:35 Start out of hole w/CT, could not get thru gas lift mandrel 03-Feb-98 08:10; ....... c/T ~tart In hole to 8000' 03-Feb-98 08:45 03-Feb-98 09:1~ ..................... 03-Feb-98 09:45 03-Feb-98 lO:Ob ' , ....... "" ,," , ' " .. ,,',, ',, ' ..... ,S.tart pumping ~ 500 sCrim 03-Feb-98 10:30 , ,,I ...................... 03-Feb-98 10:45 03-Feb-98 10:50 ' ' ,' i', i ', ,. ',' ", ' ', ' '," ,' , ..... ' "'Start geffinl~ return= 03-Feb-98 11:00 03-Feb-98 11:30 03-Feb-98 11:45 ...... 0,5 " 0,0 ............ 03-Feb-98 12:0,0 , ,' 0.81,:', ,, '79,83 ..... ',"'"'0:0 "' 0,6 ,, ' :, ' '"4~.4 ......., .......... ' , ' 03-Feb-98 12:1,5 .... 1.60 158,.72i 0,0 ,, 2.5 ...... 43.,4 ..... 03-Feb-98 12:30 10.43 1032.13 0.1 13.2 43.4 03-Feb.98 12:45 ........ 4.0'1 "39.7.27 0.2 ..... 17.4 ...... 43,4 ............. 03.Feb-9~ 13:00 ", 1.58 15~l'.82, "', 0.:~ " 19,0 .... 43.4 ............ 03-Feb-98 13:15 '85 40,0 ' 26.6,.~ 457.23 0.5 23:~ ........ 43:4: ............ 03-Feb.9~l 13:30 13~ 40,0 .... ~0.1~ 8'~1.11 ....... ~.8 32.4 " 43.4i ............ 03-Feb-9~' 13:45 96 40.0 ' 45.84 194.16 1.3 34.{~ ' " 43.4 ........ 03-Feb-9~ 14:00 g'~ 40.0 '' '29.71 '530.89 " '1.8 40.(j ...... 43.;4, ......... 03-Feb-98 14:15 68 40.0 ..... 33.57 286.16 1.9 ~:~.0 43.4: ' 03.Feb.98 14:30 446 40,0 .... ~13.3'3 ' 82~.31 . " 4.1 ~1 6, ' ..... 43.4 .......... 03-Feb-9~ 14145 294 40,0 , .142'72 416.98 .... 5.6 ,' 55.9, i ',i ,., 4;~'4 " , ,,,i' ,,. ", 03-Feb-98 15:00 211 40.0 , 151.37 ,, 409.27 7,2; , 60.2 ..... 43;4 .... 03-Feb.98 15:15 140 40,0 0.00 0.00 7.2 60.21 , , 43.4 03-Feb-98 15:30 220! 40.0 0,00 0.00 .... 7..2 .,,., 60,2, 43,4 03-Feb-98 15:45; 250 40.0 ' 0,00 '0.00 7.2 60,2 .... 43.4 03-Feb-98 16:00 170 40.0 0.00 0.00 7.2 60.2 43.4 03-Feb-98 16:1~i 220 40.0 " , 625.75 734.57 "i;~.7 67.~ ............... 43~4 .... 03-Feb-9S 16:30 330 40.0 ' 0.00 0.00 ' ';i 3'.7 .... ¢~,.8 ' 43.4 ........... 03-Feb-98 16:45 450 35.0 ' , 920.16 92{~.i6 23.3 ' 77,4 ....... 43.4 ..... 03-Feb-98 17:'00 145 45.0 ' , , 01b0 0,00 ...... 23.3 " 77.4 ............. 03-~=eb-98 17:i5 200 45~0 ,,, I,," ' , 0.00, ,0,00 ',',,0,000 ~23.3 ,77.4, ' ,,, ' " ,, 'i ', ', ...... ", , Tu,rnwe, lllntoseparat°r Page 1 of 2 Well Test Report TO N Phillips Petroleum Co. Job #1 Well B-2 Sunfish Sand Well Test Tyonek Platform Ticket # 693231 Date Time WHP Choke Static Gas Oii ,L water Gas' ' Oil '" water G~)R ...... Gaa"~,Gi 'O~ Comments .............. Day-Mo-Yr-Hr:Min F 64th psig mmacfd bpd .. bpd mscf bbl bbl scf/bbl APl60 03-Feb-98 17:30 295 45.0 50 1.58 372.00 828.00 16.41 :~ 27.2 86.0 4236 0.9981 43.4 ...... 03-Feb-98 17:45 300 45.0 50 1.55 396.70 882.98 32.564 31.3 95.2 3909 0.998 43.4 03-Feb-98 18:00 300 45.0 5'0 1.55 ' 681.~6 115.54 48.71'~ 38.4 96.4 22'~6 0.998 43.4 " , ~ , 03-Feb-98 18:15 305 45.0 50 1.58 868.~i0 91.20 65.128 47.5 97.4 " 1814 0.998 '~,3.4 , ~ '03-Feb-98 18i30 312 45.0 ' 50 " 1.58 ' 1067.04 180.96 81.541 '58.6 99.3 1477 0.998 43.4 ' ' 03-Feb-98 19:00 315 45.0 50 1.58 1040.16 0.00 114.367 80.2 99.3 1515 0.998 43.4 03-Feb-98 19:30 300 45.0 60 1.85 1056.00 0.00 152.884 102.2 99.3 1751 0,998 43.4 03-Feb-98 20:00 300 45.0 60 ' 1.51 1035.36 0.00 184.368 123.8 99.3 ' 1460 0.998 43.4 '" 03-Feb-98 20:30 320 45.0 50 1.67 1284.48 0.00 2191213 150,6 99.3 1302 0.998 43.4 03-Feb"-98 21:00 400 45.0 60 1.85 1161.60 0.00 257.730 174'.8 '99.3 1592 0.998 43.4 ....... 03-Feb-98 21:30 440 45.0 60 1.80 1718.40 0.00 295.207 210'.~ 99.3 " 1047 0.998 "~,3.4 03-Feb-98 22:00 400 45.0 60! 1.~'6 '1891.20 '" 0.00 331.973 250.0 99.3 933 0.9~8 43.4 ...... 03-Feb-9a 22:30 440 45.0 85 '2.13 ' 1872.00 '0.00 376.28~ 289.0 99.3 1136 b.998 4'3.'4 03-Feb-98 23:00 450 45.0 85 2.49 2476.80 0.00 428.155 340.6 99.3 1005 0,998 43.4 03-Feb-98 23:30 ...... 0.00 0.00 428.155 3401'~ 9I~.3 '0 ......... SCSSV Shut-In 04-Feb-98 00:45 45.0 ' 0.b0 0.00 428,155 340.6 '99.3 0 ......... Open wail on 45164" adj ~hk 04-Feb-98 01:00 4501 45,0 80 2.49 430.80 0.00 454.049 376.5 99.3 57~0 0.94d "43.4 ..... ,04-Feb-98 01:30 450 45.0 ' "8~ '2.~5 "2097.~0 0.00 ,' ~07.2i5 420,2 99.3, 1217 ',' 0,940 43.4 , '"' , ..... ' 04-Feb-98 02:00 450 45.0 90 2.69 2774140 0.00 563.239 478.~ 99.3 969 0,§40 43.4 04-Feb-98 02:30 475 45.0 I~0 '2.68 2020.80 'i,' 0.0,0 '6i8.996, 52011 '9~i3 ".1.~24 0.940 '~,'3.4 ......... 04-Feb-9803:00 500 45.0 90 ~.73 2332.80 0.00 675.775 568.7 99.3 1168 0.§40 42.4 .......... "04.Fab. Be 03:30 500 45.0 90 2,74 2428.80 '0.00 732.876 619.3 ...... 99.~ 1128 0.940 42,4 ..... 04-Feb'98 04:00 500 45.0 90 2.f0 '2476.80 .... d.00' 789.180 670.§ 99.3 1091 ' 0.940 42.'4 ................. 04-Feb-98 04:30 500 45.0 90 2,~'0 1464.00 "0.00 '845.484: 70i.4 ' 99.3 i845 ' 0.~40 42.4 ....... "04-Feb-98 04:56 " 0..'.0p '0.00i 845.484. 701.4 9,9,3 , 0 ' ', ...... ' , ' , ' ESD ,S,h,ut-ln, End oftaa! Page 2 of 2 SUNFISH SAND TEST 1 SCAN WELL TEST REPORT FIELD READINGS FIELD READINGS Da~' Time Comments Wellhead Gas Metering ,0!1Meterinl~ Tubng Well Chk Diff Static Gas Meter Orif, Meter OII Oil Oil Line Press Temp Dla Press Press Ternp H25 CO2 N= SG Run Dla ReadlngTemp Grav BSW Day-M,o-Yr-HriMin:Se.c, psi~ F 64th inh2o psi~ F ppm % % in in bbl F APl60 % 03-Feb-98 05:05:00 Berlin Test 45.58 ,62'01 0,22 15.47 60,39 '~0 03-Feb-98 05:10:00 46.33 63.90 0.28 15.46 60.51 60 03-Feb-98 "~)5:15:00 ' ' 44,13 65.89 0,13 15,47 60,55 60 .... 03.Feb.98 05:30:00 .... 34,25 62.'55 0,12 15,57 "61116 62 ' 03-Feb-98 '05:45:00 33.55 60.42 0.10 15.59 61'.78 ' ' '63 , , 03-Feb-98 06:00:00 292.25 69.49 0.09 15.49 62.28 64 03-Feb-98 06:15:00 117.15 59.55 0.08 15.53 61.77 64 ' 03-Feb-98 06:35:00 Start in hole w/coilt, could 62.80 56.87 0.04 15.49 61.93 ' 65 ~,, ~ 03-Feb-98 08:10:00 CTHhtoSO00' 3§.00 .47.37: 0.00 15.54 65.12 69 03-Feb-98 08:45:00 40.20 45.291 0.00 15.60 66.99 71 03-F~3-98 09:1'5:00 39.48 44.79 0.00 i'5.60 67.81 71 " 03-Feb-98 09:45:00 ' 39.75 '45.19 0.00 15.57 68.84 " 72 03-Fe~)-98 lO:O0:OOStartpumpin~l~5oOscft 1i2.10 " 45.03 O.Ob 15.54 68.88 ,,, ' , 72 , 03-Feb-98 10:30:00 38.53 47.79: 0.00 15.47 65.56 67 03-Feb-98 101'45:00 37.08 47.06 0.01 15.47 63.85 ' 65 03-Feb-98 10:50:00 Start ~e,tti. n~ re~,rns 41.25 47.12 0.04 15.55 63.49 65 03-Feb-98 11:00:00 46.98 60.55 0.06 i5.57 63.40 " 66 " ' 03-Feb-98 11:30:00 304.00 60.92 0.10 15.51 62.94 63 03-Feb'98 11:45:00 55.10 59.47 0.13 15.4'~ 62.65 ..... 62 99.9 03-Feb-98 12:00:00 ~ 42.90 61.~'1 0.13 15.45 62.i'8 ...... 61 99.9 b3'Feb-g8' i~:15:0b ' " 68.35 ;62.'i"5 '" 0.15 15.44 61.5'0 .... 60 §9.9 03~Feb-98' 12:~0:00 ......... 322.00 '85.83 ' ' 0;i7 15.43 '~i0.85 " ' 59 99:9 03:1~e~.9~J 12:45:00 ' 69.98 62.41 0.i8 15.42 60.48 .... 58 99.9 '03:Feb-98 i3:'00:00 ' " 54.1'5 61.53 0.19 15.49 60.32 ..... 60 ' ' 99.9 '03-Fe~3:§1~ "i3:15':{)0 ..... 99.33 65.01 0.15 i5.53 60.75 ....... 62 94.5 "O~-Feb-9a 'i3:30:00 .... ' 1;~8.20 66.60 ..... 0.1i 'i'5.50 8i.31 63 96.5 03-Feb-ga 13':'45':(~0 ...... 1~1.03 66.54 '" 0.1'(~ "'i'5.45 81.89 63 80.9 03-Feb-§S'14:00:O0 ' ' ' 109.~§ 66.87 0.10 151~,'8 62.43 ' '63 94.Y 03-Feb-98 14:15:00 80.~8 '65.9~' 0.09 '15.41 '63.'14 ' ' ' 63 ' 89.5 03-Feb-98 14:30:00 107.t3 "'66.61 ' 0.1"3 "~"5.38 631i6 ' ' ' 62 79.5 "03-Feb-ge .... i4:45:00 ' 3b'{~.50 "' 66.12 0.15 i'5.39 62.76 " 61 74.5 '03-Feb-§'8 ' 15:'00:'~0 ........ 2~'6.38 6~.11 ' '0.1~ "15.39 '62.03 ..... ' 6'0 73 '"03-Feb-98 15:15:00 " ' 189.68 67.09 '0.19 15.38 '61.31 ...... 5'9 73 · 03-Feb-98 15:30:00 241.60 67.31 0.20 15.39 60.88 59 73 03-Feb-g8 .... 1.~i'~.5:00.......... 248.10 '67.03 0.20 "~5.40 60.64 .... 59 54..5 03-Feb-~§S 16':'00100 ' '190.33'66.05 0.20 15.42 60.45 ' 59 "54.5 03-Feb-98'16i15:O0 223.15 66.97 0.20 ~5.41 60.~,6 ' 59 54 O~-Feb-98 "16:~b:00 ' 250.23 67.51 ' 0'.20 i5.40 60.38 ...... 59 .... 03-Feb-98 16:45:00 .... 306.0'0 67.43 0.21 15.39 60.45 .... 58 50 , 03.F,eb;§,8 ,. 11'i00:00 ' , 159.80 67.20 ' 'b121 16i.20 f2.61 .... 64 · 03.Feb.§8 ' 17:15:00 Turn well In:to eepa,r,ator 352.50 66.93 "0.21 221.13 i0o169 ..... 95 ' 03-F'~b-§8 "'~'7:30:00 ' 333.75 67.43 '45.0 64.00 93.8'i' iog.§e ' 0.998 5.761 2.2~ ' 113 43.4 69 03-F~b-98 'i7:45:00 ' 311.50 "67.68 4~.0 64.00 7'3.31 107.46 " 0.998 '5.761 !' 2.25 112 43.4 69 03-Feb-98 18:00:00 308.00 66.67 45.0 62.00 '7"i.'3'5 i'09.i'7 0'.9~8 5.761 2.25 114 43.4 14.5 O:~Feb~98 18:15:00 ' '3~9.50 66.49 45.0 62.00 71.72 110.60 '0.998 '5.761 2.25 ' ' 116 43.4 9.5 03'Feb;§8 18:30:00 ' '325.75 66.50 45.0 64.00 73.46 108.'~7 '' ' 0.998 5.761 2.25 .... 11'4 4'3.4 14.5 Page 1 of 2 FIELD READINGS Date , Time Comments Wellhead Gas Meterinl~ Oil Met,erin,, Tt~l~ng Well Chk Diff Static Gas Meter' Orlf. Meter Oil OII OII Line Press Temp Dia Press Press Temp H:S CO2 N: SG Run Dia Reading!Ternp Grav BSW Day-Mo-Yr-Hr:MIn:Se,c , psll~ F 64th inh2o psig F ppm % % in in bbl F APl60 % 03-Feb-98 19:00:00 327.25 66.77 45.0 64.00 68.20 110.69 0.998 5.761! 2.25 115 43.4 0 03-Feb-98 19:30:00 353.75 67.16 45.0' 76.00 ~4.31 109.95 0.998 5.761= 2,25 113" 43.4 0 03-Feb-98 20:00:00 232.73 66.44 45.0 50.00 51.~5 i13.43 0.998 5.761 2.25 113 4~.4 0 03-Feb-98 20:30:00 359.251'68.42 45.0 84.00 72.31 110.16 0.998 5.'~1 2.25 110 43,4 0 , ,03-Feb-98 21:00:00 414.75 68.22 45.0 100.00 76.75 114.77 0.998 5.761 2.25 i14 " 43.4 0 03-Feb-98 21:30:00 4,~2.00' 70.82 45.0' 104.00 72.25 100.95 0.998 5.761 2.25 100 ~3.4 0 03-Feb-98 22:00:00 331.00 71.55 45.0 82.00 67.50 103,58 0,998 5.~.61 2.25 ' 102 43.4 0 03-Feb-98 22:30:00 ' ' ' 462.00 '72.91 45.0 56.00 74.21 99.67 0.998 5.761 2.25 99 43.4 0 03-Fei~-98 23:00:00 4~.bd 74.09 45.0 51~,00 101.58 104.50 0,998 5,761 2.25 104'43.4 0 ' 03-Feb-9~ 23:30:00 SCSSVshutain ' 233.23 ' 75.32 0.0 62,00 100.59 105.29 0.9§{1 5,761 2,25 105 43,4 0 .... 0~,-~=eb-98 00:45:00 Open well on 45164" chk 2639.76 73.94 45.0 0.00 15.3'6 70.861 ,. 0,998 5,761 2.25 77 43.4 ' 0 04-Feb-98 01:00:00 486.25 72,10 45.0 0.00 100.44 97.85 0.9§4 5.761 2.25 '{17 43,4 0 04-Feb-98 01:30:00 , ' , ' 469.50 74.03 45.0 62.00 10010~ 104'.99i 0.994 5.761 "2.25 105 43.4 '0 '04-Feb'98 02:00:00 ...... 516.50 74.70 45.0 60.78 107.12 104.94 0.994 5.761 2.25 .... 105 43.4 0 04-Feb-98 02:30:00 525.00 75.45 45.0 60.5.6 106.56 104.98!" b.994 5.761 2.25 ' 104 4~.4' 0 04-F'~b-98 03:00:00 ' 532.75 75,57 45.0 62.01 109.31 104,97 ' ' 0.994 5.761 2,25 104 43.4 0 04-Feb-98 03:30:00 '"528.25 76.68 45.0 62.19 109185 105.38 0,994 5.f~1 '2.25 105 43.4 0 04-Feb-98 04i00:00 514.50 77.15 45.0 60.54 106164 104,351 '0.994 5.761 2,25 " 103 43.4' 0 ' d;t-F'eb-ga 04130:00 ' 511.00 77.85 45.0 60.53 107.00 105.89' 0,994 5.761 '2.25 105 43.4 0 04-Feb-98 04:,5,6:00 ESD Shut,i,n~ EndofteSt 2'1i.88 78.50 ,,45.0 61.04 107199 'i07.3,7 ...... 107 43,4 , ,0 Page 2 of 2 CALCULATIONS CALCULATIONS Date Time DTime Gas Flow': Oil Flow Water Gas Oil Water GOR Rate FlowRate FlowRate Volume Volume Volume Day-Mo- Yr-Hr:Min Hr rnrnscfd ,bpd bpd rnmscf bbl bbl scf/bbl 03-Feb-98 17:30 19.50 0,00 0.00 0.00 0.00 0.00 03-Feb-98 17:45 19.75 0.00 1118.34 0,00 67.8~ 0.00 03-Feb-98 18:00 20.00 0.00 1081,97 0,00 68.57 0.00 , 03-Feb-98 18:15 20.25 0,00 1026.78 0.00 69.56 0.00 , 03-Feb-98 18:30 20.50 2.10 1081.47 20.32 70.67 1943.88 03-Feb-98 19:00 21,00 2,02 1092.49 63,66 72.87 1851.16 03-Feb-98 19:30 21.50 2.11 1268.10 107.01 79.18 1665.61 03-Feb-98 20:00 ~2.00 1.75' 789.39 148.14 81.38, 2215.84 03-Feb-98 20:30 22,50 2.08 1150.79 189.66 '84.03 1810.25 03'-Feb-98 21:00 23.00 2.14 1291,95 232,40 86,36 1654.23 03-Feb-98,,. ,21:30 23.50 1.64 1991.11 26.9,33, i 90.23 , 825.30 03-Feb-98 22:00 24.00 1.58 1596.98 303,08 94,19 991.71 03-Feb-98 22:30 24.50 1.67 2078.76 " '337128 98,50 802.26 03-Feb-98 23:00 25,00' 1.95 2181,34 ' 3~'7,43i 102,98 .... 89~,,33 03-Feb-98 23:30 25.50 1.94 2198.32 418.13 107.58 '~181.34 04-FeJ~-98' 00:45 26.75 '0.79 0.00 460.19 107.75 0.00 O;4-Feb-98 01:bO 27100 1.95 2151.87 47'8.71 110.28 " 906.16 04-Feb-98 01:30 27.50' 1.93 20~,4.35 " 518,78 127.20 945.25 04.Feb-98 02:00 28,00' 1.98 2263,78 ',559.26 172.51 875.48 04-Feb-98 02:30 28.50 1.97 2313,83 600.49 219.82 ' 852,61 04-'Feb-98 03:00 29,00 2.02 2355,73 642,34 268.46 858.72 04~Feb-98 03:30 29.50 ' 2.03' 2327.88 684.79 317.50 .... 872.1'2 04-Feb-98 04:00 30.O0 1'.97 2248.55 ' 726.09 364.49 878.12 04-Feb-98' 04:30 30.50 " 2,09 221~.21' 767,82 411.50 942.61 ' ",04-Feb-98' 0,4:56 ,30,93 2,11 , 2248.2,9,,1 ..... ' 805,~1 ,451,68 936,56 Page 1 of 1 CHARTS RTON Well Test Report Phillips Petroleum Co. Well B-2 Sunfish Sand Tyonek Platform Job #1 Well Test Ticket # 693231 3000.00 2500.00 ........................................................ 2000.00 1500.00 +WHP (psi) ~Gas Rate (mscf/d) ~ OII Rate (bbl/d) 1000.00 500.00 0.00 17:45 18:15 19:00 20:00 21:00 22:00 23:00 0:45 1:30 2:30 3:30 4:30 Time 5:45 RTON Well Test Report Phillips Petroleum Co. Well B-2 Sunfish Sand Tyonek Platform Job #1 Well Test Ticket # 693231 3000.00 2500.00 2000.00 1500.00 1000,00 500,00 · & · & & · · · [] & · .............. m .............................. ,~ m m ....... -m--m .... ·-'m'- · · · · · · · · Bi & · · · B 0,00 .... i .... ] I ~ ] ) I I ) ..... ) .~ ..... I I ) I ..... 17:45 18:15 19:00 20:00 21:00 22:00 23:00 0:45 1:30 2:30 3:30 4:30 5:45 Time ~,WHP (psi) IGas Rate (mscf/d) &Oil Rate (bbl/d) REPORT TO NPhillips Petroleum Co. Job #1 Well B-2 Sunfish Sand Well Test Tyonek Platform Ticket # 693231 Date Time ' WHP Choke Static -Gas Oil Gas Oil GOR "'(~s' 011' Commenl~ ................ Day-Mo-Yr-Hr:Min F 641~ psig mmscfd bpd . mscf bbl scf/bbi S.G. AP.160 03-Feb 05:05 46 'Begin Test , , , 03-Feb 05:10 46 03-Feb 05:15 44 03-Feb 05:30 34 i , , 03-Feb 05:45 34 , 03-Feb 06:00 292 03-Feb 06:15 117 03-Feb 06:35 63 .... ' , . , ' ' Star"In hole w/¢oiltt coUld not ~et In .... ' 03-Feb 08:10 39 CT rlh to 8000' b3-Feb 08:45 40 ...... 03-Feb 09:15 39 03-Feb 09:45 40 ...... 03-Feb 10:00 112 ', ,, ' Sta~ pumping ~ '~00 scflm , , 03-Feb 10:30 39 03-Feb 10:45 37 03-Feb 10:50 41 , . ' ' ' . " , , , ,sta~ ~effin~ re~ ...... " ' 03-Feb 11:00 47 03-Feb 11:30 304 03-Feb 11:45 55 03-Feb 12:00 43 ~............. 03.Feb 12:15 ~8 '" 03-Feb 12:30 322 03-Feb 12:45 70 i 03-Feb 13:00 54 03-Feb 13:15 99 03-Feb 13:30 148 03-Feb 13:45 111 03-F~b 14:00' 110 ......... 03-Feb 14:15 81 03-Feb 14:30 107 03-Feb 14:45 310 03-Feb 15:00 226 ~ ..... 03-Feb 15:15 190 ....................... 03-Feb 15:30 242 03-Feb 15:45 248 03-Feb 16:00 190 i i i ~ i i i i i ~ i 03-Feb 16:15 223 03-Feb '16:30 250 " ' ~" ~ ..... 03-Feb 16:45 306 ....................... i ,,1, ,i i, i i i , i , , i i i i 03-Feb 17:00 160 03-Feb 17:15 353 ,' , , ' "' 2 ' Tu~w~lnto~p~rai~r" ' , ' ', O$-F~b ~:$0 ~$4 45.0 0.00 0.0 Well Test Report TO NPhillips Petroleum Co. Job #1 Well B-2 Sunfish Sand Well Test Tyonek Platform Ticket # 693231 Date Time WHP Choke Static Gas Oil Gas Oil GOR Ga~' ' ' Oil'rCOmments , Da¥-Mo-Yr-Hr:Min F 64th psig, mmscfd bpd mscf bbl scflbbl S.G. APl60 , 03-Feb 17:45 312 45.0 1118.34 67.9 43.4 , , ~ 03-Feb 18:00 308 45.0 1081.97 68.6 43.4 , , ~ 03-Feb 18:15 320 45.0 1026.78 0.000 69.6 43.4 03-Feb 18:30 326 45.0 73 2.10 1081.47 20.320 70.7 1944 1,00 43.4 , , 03-Feb 19:00 327 45.0 68 2.02 1092.49 63.660 72.9 1851 0,998 43.4 03-Feb 19:30 354 45.0 74 2.11 1268.10 107.010 79.2 1666 0.998 43.4 03-Feb 20:00 233 45.0 51 1.75 789.3§ ' 148.140 81.4 2216 0.998 43.4 ' ' 03-Feb 20:30 359 45.0 72 2.08 1150.79 '189.660 84.0 1810 0.998 43.4 ' 03-Feb 21:00 415 45.0 77 2.1~, ' 1291.95 232.400 86.4 1654 ' 0.998 43.4 03-Feb 21:30 452 45,0 72 1.64 1991.1i 26~'.330 90.2 825 0,998 43.4 ' ' 03-Feb 22:00 331 ' 45,0 68 " 1.58 ' 1596,98 303.080 94.2 992 0.998 4:~.4 03-Feb 22:30 462 45.0 74 1.67 2078.76 337,280 98.5 802 0,998 43.4 03-Feb 23:00 477 45.0 102 1.95 '~i81.34 '37~;'.430 103.0 893 0.998 43.4 ' ' 03-Feb 23:30' 233 0.0 ~'01 1.9,~'" 2198.32 418.'~30 ' 107.6 881 0.998' 43.4 SCSSVehUtsin 04-Feb 00:45 2640 45.0 15 0.79 0,00 460,'190 ' ! 07.8 " 0 ' ' 43 4 OPen well on 45164" 43.4 chk 04-Feb 01:00 486 45.0 100 1.95 2151.87 478,710 !,10,3 906 0.940 ....... 04-Feb 01:30 470 45.0 100 1,93' 2044.35 518,780 127,2 945 0.940 43.,~ 04-Feb 02:00 517 45,0 ~'~7 1,98 2263,78 559.260 172.5 ~75 0.9~0 43.4 ' .... 0,~.Feb 02:30 525 45.0 107 ' 1.97 231:3.83 600.490 219.8 853 0.940 '43.4 ,,, .04.Feb 03:00 533 45,0 109 ' 2.02 ' ,2355.73 642.340 "268,5 859 0,940 '4~.4 .... '04-Feb 03:30 528 45.0 i~0 2.03 ' 232~'.88 684,790 317.5 872 0,940 43,4 ' ' 04-Feb 04:00 515 45.0' 107' 1.97 ~" 2248.55 726,090 " 364.5 '878' "0,940 43.4 ' 04-Feb 04:30 511 45.0 107' 2.09 2217.21 "7~7,820 411.5 §~3 '0,940 43,4 ' ' ' 04-Feb 04:56 212 45.0 108 2.11 2248:29 , ,8'05,610 '451.,7 937 ',0,940 i', 43.4 ESDShut-in, End0ftest ,, · NORTH FORELANDS SAND TEST 1 MANUAL WELL TEST REPORT FIELD READINGS FIELD READINGS Date Time Comments Wellhead Choke' Gas Mete~in[ .... Oil Metei~m~ Tubng Csng Well Mnfld Htr Diff Static Gas Meter Orif. Meter Oil Oii' Oil Line Press Press Temp Dia Dia Press Press Temp H2S CO2 N2' SG Run Dia ReadingTeml: Grav BSW Day-Mo-YrTHr:Min:Sec , PS!~ P,.s.i,g,.,F 64th 64th inh2o psig F ppm % % in in ,,,bbl, F APl60 % Pressure test to front of choke to 07-Feb-98 13:30:00 8k psi .... Pressure test to front of choke to 07-Feb-98 14:40:00 8k psi 07-Feb-98 15:10:00 Safety Meetin~l on test procedure, 3019 58 , , , 07-Feb-98 16:04:00 Ope,,n Well on 8164" ad~ c, hk 2926 56 8 0.00 65 07-Feb-§S 16:10:00 Adi chk ,clog~in; .... 2802 ' 59 8 ........ ',, 07-Feb-98 16:16:00 On b. ypass 2925 60 07-Feb-§8 1'6:17:00 Shut-in well,' ,ch~)ke full of debris' 2935 .... 60 .......... 07-Feb-98 16:32:00 Open Well on 12164" adj chi< 2671 '~1 12 ...... 0~-Feb-98 16:34:00 Increase to 16/64" ad~ chk 2702 62 16 '07-Feb-9'8 '16~35:00 Increase to 20164" ,ad~ chk 2709 61 20 .. ,, ' ' 07-Feb-98 16:37:00 I~luid attank ' 2710 62 20 07-Feb-98 16:40:00 Increase to 3~64-ad~ chk 2577 , , 62 '32 , ,, ,,,, L ~, ,, ' 8.33 65 ' 400.0 07-Feb,9'8 16:45:00; Increase to 39/64" ,,a, dj chk' 2200 59 39 0'7-Feb-9S 16:5,~(~' D~c~:ease to 32/64" adi chk 2640 66 32 ...... ' 07'Feb-98 16:56:00 Decrease to 25~64" ad~,,chk , 2650 66 25 .... ' 07-Feb-98 17:bo:b'o '" 2700 .... 66 25 i6.67 6'5 ' i00.0 '07-F~b-98 '17:b3:00 Decrease to 20164"' ad~ (~hk 2830 ', " 67 20 ' , '", .... ' ' ',", ........... 07-Feb-9'8 17:~5:00 " 2954 67 '20 ' '25.01 65 ' i00.0 07-Feb-98 17:22:0'~ In(~r~a~e'to~4/64"a,d~ chk, 3071 67 24 , , , "' ',' , ....... ',i , ,," 07-Fe1~-98 17:30:00 3170 68 24 07-Feb-98 "17:45:00 ........ 3301 ..... 69 24 ............... :~9.'17 ' ' 65 100.0 07-Feb-98 18:00:~0 ' 3419 ' '69 24 ......... 45.00 6'5 ....... ~00~0 07-Feb-9'8 '18:15:00 ........... 3~12 ' 68 ~4 ' ' "'50.00 65 .... "' 100,0 07-Feb-98 18:30:{~'0 .... 3670 .......69 24 ............. . 55.00 65! ' "1(~0,0 ' 07.Feb.98 18:39:00 increase to 28164" adj chk' 3687 ...... 69 28 ............ 07-Feb-98 18:45:00 3625 70 28 60.00 65 100.0 , ' 07-Fe1~'98 19:00:00 ...... 3862 ' 70 '28 ....... 65.83 6'5 100.0 ' 07-F~b-98 19:06:~0 Increase to 32/64" adi chk' 3903 ' '~;1 32 ' ' ~ , "', ............. 07-Feb-9'~ 19:,12:0'0 D~crease to"20164".ad~ chk 3980 , 71 20 ......... 07-Feb-9'~ '19:15:00 4008 "' 71 20 69.99 65 100.0 07.F~b.98 'i9:2~ :00 In~'ease to 32/64" adi ~hk ' , '3~,57 ' 71 32 .............. 07-F~b-98 19:30:00 ........... 382~ ~ 72 .... 321 ...... 75.82' 65 39.5 99.9 07-Feb-98 19:38:00 D~crease to 28'164" pos chk 3~,~0 73 28 .............. b7-Feb-!~S 'i91~5:00 ' 2939 77 '28 ' ..... 103.32 65' '39.5 '75.0 07-Feb-98 19:47:(~0 Decrease to 20164",pos chk ' '3930: 78 2~' ', .... ~ ' .......... 07-Feb-98' 19:57:00 T'um well into seperator. , '" 394'0 .... '78, ' '20 ,, , ' " 01-F~b-98 20:00:00 ..... 3966 77 '20 ' '80 90 79 0,884 5','~61 '2.25 123.32 68 39.5 73,'0 07-Feb-98 20:'i 1:00 Increase to 28164" adi ~hk 37'33 78 28 .................... 07-F~b-98 '~'0:15:0Ochangeto1.S"0rifice '" 3078 .... 81 '2e ...... 80 90 90 d.884 $,761 1.5 138.32, 11'0 39,5 Page 1 of 2 FIELD READINGS Date T/me Comments Wellhead Ch~l~e Ga's 'Meterin~ 011Metertn~' Tubng Csng Well Mnfld" Htr Diff Static Gas Meter 0rif. Meter Oil Oil Oil Line Press Press Temp Did Did Press Press :Temp '~t.~SCO: N2 SG Run Did Reading Temp Gray BSW Day-Mo-Yr-Hr:Min:Sec psig , psig F 64th 64th inh2o psig F ppm % % in in bbl F APl60 % 07-Feb-98 20:25:00 Decrease to 20/64", adj chk 3640 82 20 07-Feb-98 20:30:00 3233 85 20 80 80 95 0.884 5.761 1.5 166.60 111 "39.5 70.0 07-Feb-98 20:34:00 swa~ to 20/64,,,pos,' chk, 3689 85 20 ..... 07-Feb-98 20:41:00 Increase to 26/64" pos chk 2696 85 26 07-Feb~98 20:45:00 2562 87 26 90 90 102 0.884 5.761 1.5 199.90 111 39.5 73.0 07-Feb-98 21:00:00 Gas,~lra,vity !s .884 25081 '" 93 26 105 90 103 0.884 5.76~ 1.5 249.90 108 39.5 73.0 07-Feb-98 21:15:00 2512, 97 26 ~05 90 107 0,884 5.761 1.5 295.70 111 39.5 73.0 07-Feb-98 21:30:00 2484" ' 99 26' ~07 95 112 0.884 5.761 1.5 342.30 114 39.5 " 70.0 07-Feb-98 21:~,5:d0 2495' 103 26 'i~5 100 114 0.884, 5.761 i.~i 31~9.80 116 39.5 73.0 07-Feb-98 22:00:00 " 2493 106 26 104 110 118 0.884 5.761 1.5 422.30 120 39.5 50.0 07-F~b-98 22:15:00 " 2487 ' 109 26 107 150 120 0.884, 5.761 1.5 478.9'0 122 39.5 50.0 07-Feb-98 22:30:00 Change to 1" orifice '2499 ' , 111 26 ' 107 100 130 0,884 5,761 1 537.24 126 39.5 50.0 07-F~b-98 '22:45:{)'0 2500 115 26 113 410 124 0'.884' 5.761 1 592.25 129 39.5 '75.0 07-Fdb-98 23:00:00' ' ' 2513 " 118 26 ' 92 410 125 0.884: 5.761 1 641.30 130 39.5 70.0 07-Feb-98 23:15:00 ...... 2501 '" 120' 26 98 '390 128 '0.884 5.761 1 667.90 '1:~'3 39.5 60.0! 07.Fei).9'8 "'23:30:00 , . 2528 122 26 98 390 128 0,884 5.761 1 712.90 134 39.~) 65,0~ 07-Feb-98 23:45:00, ' ' 2495 124 26 'i0~) '390 132 0.884 5,761 1 768.70 137 39.'5 73.0 08-Feb-~'8 00:00:i3(J; ' 2495 127 26 '100 '~90 133 0,884 5.76i "1 824.50 138 39.5 '" 70.0 08-Feb-98 00:15:00 ....... 2470 130 26 46 170 134 "' 0,884 5.761 1 867.80 138 39.5 75.0 08-F~!~-98 00:30:00 ' 2450 .... i32 26 46 170 '137 0,884 5.761 i 901.10 139 '39.5 75.0 0'~-'F~b-96 00:39:00 Decrea~ t~ 8/6,4" a,di chk' , 4063 " , 134 -8 ...... 08-F~b-98 0013,5:00 ..... 4451 'i32 8 :~ 80 122 '0,884 5.761 1 '' '08-Feb-98 01:00:00!Roc,ktheadiCh.k., 4540 ~'24 , 8 , ' 6 .... 20 127 ' ,, 0:~84 '5,:76'1 1 '" 0S-Feb-98 '01:15:00 4401 118 S 6 20 138 0,884 5,761 1 ' 08-Feb-98 01:30:00 4430 1-16 8 " 6 20 140 0.884 5.76'1 ~ 956.90 145 3915 73,0 '08-Feb-9'8 01:4~i00 ....... 4429' 11':~ 8 1 501 140:' 0.884 5.761 1 960.20 146 3§'.~ 7310 08-Feb-9'8 02:00:00 ..... 4396 112' 8 1 ' 50 '142 0.884 5.76'1 "' i '963,50 146 39.5' 73.0 08-Feb-98 02:15:00 ..... 4367 ........... 1,1~; , 8 i 50 142: ' ...... 0,884 5.761 " 1 '" .i ,,, 08-'F~b-98 '0~:3~:00 4334 112 8 !', , 5~, ,, 142; , '01884 5,761 1 0S-F~b-98 02:45:0d ......... 4300 ' 110 6 1 50 142: 0.884 5.761 ~' §76.00 ' 146 39.5 73.0 08-Feb-98 03:d4:00Walkadichkupto2al64' 3318 110 28 , ' ........... ,, '" , ",' '' ,,,0.b'0 146 {3'9.5 i3.0 08-F~b-98 03:12:00 Cha,n~e to 34164" p,ositive ~hk 1734 116 34 08-Feb-9e 03:15:00 O, na, dic, hl(,,',T:P, tolow ' '1692 ' 119 20 4 "50 ' 1'37 ' o.a84 5'.76~ 1 8.30 135 39.5, 73.0 '08-Feb-98 03:20:00 Chan~le to 30164" adj ~'h'k 1670 ' 120 30; , ' ...... 08-F~b-98 03:30:'b0 3120 126 30 36 90 131 01884 5.761 1.2~ 681~0 139 39.5'73.0 0~-Feb-98 03:34:00 Cha~{let, o 3~016,4: p~sitiv~ chk ",,, , 30 .............. ,' ,, ' ......... 08-Feb-98 '03:36:00 Chlorides = 13,000 ppm 08-Feb-98 03:45:00 Bottoms' up, no sand 1999 129 30 130 185 '136 0,884 5.~61 ' '~.25 106.6'0 ' 13'6 "39.5 75.0 0~-Feb-98 04:00:00 No sand 1974 131 30 120 260 1:~9 " 0,884 5,761 t,25 i62.'~3 '139 39.5 75.'0 '08-'Fe1~-98' 04:lS:00N0sand ........ 2045 '134: 30 112 255 13~9 0.860 5.761 1.25 215187 '14~1 39.5 70.0 08-Feb-9'8 04:22:d0G,';S,~lravityis.860' ' 21~4'9" ' 13'6' 3'0 112 255 141 0,860 5,761 1.25 266.53 141' 39.5 ' 70.0 08-Feb-98 04:24:00 Shut in well ~ manifold. ' 2063 136 _ ' ...... 283.20 141 39.5 '70.'0 08-Fe, b:gS 04:25:00 ',B, dginbuildup. 4034 136 ',i ...... ' ...... i' ii'i 08-Feb-98 '04:~0:00 4478 136 08-Feb-9'8 05:00:00 Mon~torb'uil,dup;,, ' ' ,, '4695 ,' 129 ' " , ,, ' ........... ,', ,, ' ....... .. ,0,,87,F,,e,b-9,8 06:00:0,'0,' Monitor buildup. ,, , , 47,80 1!6 .............. i Page 2 of 2 CALCULATIONS CALCULATIONS Date Time ,D~irn~ Gas Flow 0il Flow Water Gas Oil Water GOR WCT Fluid Rate FlowRate FlowRate Volume Volume Volume l Rate Day-Mo-Yr-Hr:Min Hr mmscfd bpd bpd mmscf bbl bb/ scf/bbl % 07-Feb-98 16:15 2.75 0.00 0.00 100 0.00 07-Feb-§'8 16:45 3.25 0.00 399.84 8.33 100 399.84 , 07-Feb-98 17:00 3.5 0.00 800.64 16.67, 100 800.64 07-F~b-98 17:15 3.75 0.00 800.64 25.01 100 800.64 0~'-Feb-98 17:45 4,25 0.00 679.68 39.17 100 679.68 07-Feb--98 18:00 4.5 0.00 559.68 45.00 100 559.68 07-Feb-98 18:15 4.75 0.00 480.00 50.00 100 480.00 , , , , 07-Feb-98 18:30 5 0.00 480.00 55.00 100 480.00 07-Feb-98 18:45 5.25 0.00 480.00 ' ' ' 60.00 100 480.00 "' 0~-Feb-98 19:00 5.5 0.00 559.68 65.83 100 559.68 O~'-Feb-98 19:15 5.75 0.00 ' 399.36 ' 69199 99.9; 399.36 "O'S-Feb-98 19:30 6 '0.00 559.12 0.00 75181 75 559.12 07-Feb-98 19:45 6.25 660.00 1980.00 0.00 6.88 '96144 ' 73 2640.00 'O~-Feb-98 20:0~ 6.5 2.44 518.40 1401.60 25.39 32.26 '11i.04 4701.58 73 1920.00 'O'S-Feb-98 20:1~ 6.75 1.06 " 388.80 1051.20 36.40 43.27 1:~1.99 2718.61, 70 1440.00 07-Feb-98 20:30 7 814.46 1900.42 11.01 43.27 141.79 0.00, 73 2714.68 07-Feb-98 20:45 7.25 1.11 863.14 2333.66 11.55 54.82 166.09 i284.43 '73 3196.80 07-Feb-98 21:00 ' 7,5 1.20 1296.00 " 3504.00 24.02 67,30 202,59 9;~4..00 73 4800.00 ' O~-Feb-98 21:15 7.75 1.19 11~'7'.14 32{)9.66 ':~4.90 79.72 236.03 10{)'4.84 70 4396.80 07-Feb-98 2~:30 S 1.23 1:~42.{)8 '3131.52 25.21 ' '92.5' 268.65 9'~4.53 73 4473.60 O~-Feb-98 21:45' 8.25 1.24 1231.20 332''8.80 '" '25.71 105.44 303.32 1008.i6 50 4560.00 07-Feb-98 22:00 8.5 1.28 ' 1560.b0" i''560.00 '26.31 ile.81 319.57 823.22 50' 3120.00 'O'S-Feb'98 22:15 8.75 1.50 '2716.80 2716.80 ' 29.01 134.4.5 347.87 '552.33 50 5433.60 07-Feb-98 22:30' ' 9 ' 0.55 2800.32 280{).32: 211~,3 140.14 377.04 195.31 ~5 5600.64 07-Feb-98' 22:45 9.25 ' ' '~.'13 1320.2'4 3960.72 ' 17.49 'i51.93 418.30 857.42 ~'0 52~0.96 07-Feb-98 23:00 "9.5 1.02 1'412.64 32§6.1'6 ,2;~.41 162.56 '452.64 7~21.86 60 4708.80i '"07-Feb-98 2'3115 9.75 1.02 1021.44 1532.16 21.25 173."~9 468.60 999.28 65 2553.60 O~'-Feb-98 :~3:30 10 1.02 1512.00 2808.00 21.26 i83.82 497.85 675.07" '~3 '4320.00, O~'-Feb-98 23:4.~ 10.25 '1.03 .... 1446.343910.46 21.32 194.51 538.58 709.52 "70 5356.80 '"OS-Feb-S8 00:00 10.5 1.03 1607.{)4 "374.9176 21.37 '205.19 577.~, 637.82 75 5356.80 .08-Feb-§~00:15 10.75 ,'i, 0.46 1039.20 31'J7.60 ' '1.~142 209.93 610.11 438.13 75 4156180 08-Feb-98 00:30 11 {).45 799.20 2397.60 ' 9.47 "' 214.66 635.09 5681{)6 73 3196.80 08-Feb-98 01:30 12 0.07 361.58 ' 977.62" '7.64 ',, 217.5;7 675.82' 192.94 73 1339.20 08-Feb-980i:45 12.25 0104 85.541,,, 2,31.26' 3.31 217.97 678.23 456.57 73 316.80 08-Feb-98 02:00 12.5 0.04 " 85.54 231.26 0.81 218.38 680.64 455.76 '7~ ' 316.80 08-Feb-98 02:15 12.7~) "0'.0~. 108.00 292'.00 ' 0.81 '~18.¥9 689.7~' '360.98 ' 400.00 OS-Feb-S8 02:30 13 . 0.04 0.81 219.19 O.Ob 73 0.{)'0 '01~-Feb-98 03:15 "13175 0.08 215,'i'4 581.66 2.85 221.63 6.06 363.29 73 '796.80 08-Feb-ga 03:30' "14 '0.47 1555,20 ,{204.80 ~.35 226,54, 49,86 303.06 75 5760,00 08-Feb-98 03:45 14.2~, 1.25 919~'0 2757.60 1~',91 ' 239,'55 78.58 1358.'26 75 '3676.80 08'-F~-9804:00 14.{~ 1.41 1342.32' '4'026.96 '2~,74! 254.28 120,53' 1'053157' ~0"5369.28 08-Feb-98 04:15 1~'.75 ' 1.37 1536.19 3584'.4.5 , ,28.991 '268,54 '157,87 890.97 .... 70 '5120,64 "' 08-Feb-98 04:24 14.9 ' 1211~94 2827,86 14.26 268,~4. 205,00 .... 0100 70 4039,80 Page 1 of 1 CHARTS RTON Well Test Report Phillips Petroleum Co. 6 Feb - 8 Feb, 1998 Well B-2 North Forelands Production Well Test # 2 T¥onek Platform Ticket #: 693231 5000.0 1600 4500.0 4000.0 3500,0 3000,0 2500.0 2000,0 1500,0 1000,0 500.0 I n-nnnnnnn Ad ii ' ' ali' · · &&&&& I · II , · in ,it, IdII ..~__________B_.n__.En A 14:30 16:54 19:18 21:42 00.:06 02:30 o4:3o 1400 1200 1000 6OO 400 · &AAA · / "L 200 A ~A~AA,,e ' 4, Time R Well Test Report TO N Phillips Petroleum Co. 6 Feb - 8 Feb, 1998 Well B-2 North Forelands Production Well Test # 2 T¥onek Platform Ticket #: 693231 5000,0 1600 4500.0 4000,0 3500.0 3000.0 2500,0 "" 2000.0 1500.0 1000,0 500.0 0.0 0 14:30 16:54 19:18 21:42 00:06 02:30 04:30 Time 1400 1200 1000 800 600 400 2OO REPORT TO N Phillips Petroleum Co. Job #2 Well B-2 North Forelands Well Test Tvonek Platform Ticket # 693231 I I I Date & Time WH~ WHT Choke Static SepGas Gas Oil Water · GOI~ Gas S.G. OII Comment~ ' , psig F 64th psig F mmscfd bpd bpd scf/bbl APl60 07-Feb'-98 13:3d:00 ...... Pressure test to fron~'of choke to 8kid)si 07,-Feb-98 14:40:00 ....... Pressure t,est to fron~',~)f c~oke to 8k. psl 07-Feb-98 15:10:00 3019 ,58 , Safety M,eetin~ o,n te, st procedure 07-Feb-98 16:04:00 2926 56 8.0 ...... Open Well on 8/64" adJ c, hk · 0~-Feb-98 '16:10:00 2802 59 8.0 .... i , ,, ' A.dj c.hk clol~l~ing ., ' " 07-Feb-98 16:15:00 29:~5 60 ....... On bypas,,s, , 07,-FebT98 16:17:00 2935 60 ............... Shut-In w,e!lr choke f~li of rubber deb. rls' , 07-Feb-98 16:32:00 2671 61 12.0 Open Well On 12164" adJ chk 07-Feb-98 16:34:00 270'2 ~2 16,~1 ............. Increase t0 16184" ad] chk " ' 07-Feb-98 16:35:00 2709 61 20.0 .I ......... Increase to 2.0/64" ad] ch,k ......,. , 07-Feb-98 16:37:00 2710 62 20.0 Fluid at tank ,07-Feb-98 '16:4d:00 2577 62 32.0 '. ' ., , ' ..... . .... Incre;'se,t~ 32/64" ad, j chk' ' i,i, 07-Feb-98 16:45:00 2200 59 39,0 399.84 Increase to 39/64" adJ chk 07-Feb:98 16:55:00 " 2640 66 32.D ' ' ' , .... " :,,' Decrease"to 32?64" adJ Chk .... 07-Feb-98 i6:56:00 2650. 66 25,,0 , , " ,,,Decrease to 25~/6,4," adJ chk , '0f:1%b~98 17:00':00 2700 66 25.0 ' " 800'.~4 ' 07-Feb-98 17:03:00 2830 67 20.~) ' ,, ,, ' ,, '" ........ , ,,,Decrease, .,,t° ~84" a,~lJ chk ~:"," ' d7-Feb-98 17:15,:00 2954 '67 20,0 , 800.64., ' ....... , ,'. ,07-Feb-98 ,'i'?:22:0,0 3071 67 24.0 , - .... in~:re'as'et(~24/64"a~J'chl( .......... 07-Feb-98 17:30:00 3170 68 24.~) .............. 07-Feb-98 17:45:00 3301 89 24.0 ' ' ' 6~9,68 .............. 07'Feb.98 '18:00:00 " 3419 69 24.b ' , 559.68 .............................. 07-Feb.98 18:i5':'d0 3812 66 24.0 , 480.00 ........................ 07-Feb-98 18:3(~:00 3870 89 24.~ ....... 480.00 ....... ' .... ' 07-Feb-98 i8:39:00 3687 '8{;t ,28.~I ',' " ~ ' ........... increase to 28/6~",adJ chk ......... i 07-Feb-98 18:45:00 3625 70 28.0 480.00 ................ 07-Feb-98 19:00:00 3862 70 28.~ ' , 55'9.68 ....................... 07-Feb-98 19:06:00 3903 ~1 32.0 i', ,' '.,, , " :,' " .., ': " increaset0 32/64"a~ichk' ' ' ,07:Feb-98 19:12:00 3980 71 20.0 , ' Decrease ........... to 20/64" a.,d] chk " .... 07,Feb-98 19:15:00 4008 71 20.0 ' ' 39.9.~6 ....................... ' 07-Feb-98 19:21:00 345'7 71 32.0 ...... increase t~ 32/6~;~ adj chk ...... 07-Feb-98 19:30:00 382.,.4 72 32.~ ,, ' 0.00 55'9.i2 ..... 3.9.5 ..... 07-F,b-98 19:38:0,0 3850 73 28.l~ , ' ......... Dec"ease to 28~,'~t" pos cl~J< .: .... .: ..... 07-Feb.98 19:45:00 2939 ~7 ,28.0 ,, 660,00" 1980.001 0.0,i' , ""'0 ...... 39.5" 07-1~eb-'9~ '~§:47:00 3930 78 20,0 ............... ', D,eCr~'~se {o 20i~,4" pos chk , . ':',,', ' ~ 07-Feb-98 19:5~;:00 3940 78 20.0 ,,Turn well,into seperat,,or. , ...... " 07'-Feb-98 20:00.:,0,0 3966 77 20.0 §0 79 2.44 518.40 1401.80'0.0 470~, ", 0,'.66 '" 39.5 ' 07~Feb-98 2,0:11,:00 3733 78 28.0 ,,, Increa..se to 28/64" adj'chk ' ' 07-Feb-98 20:15:00 3078 81 28.0 §0 90' 1.06' 388.80" 1051.20 i"'0,0' '2726 .... 0.88 39.5 C,hanl~e to 1.5" orlfl% 07..Feb-98 20:25:00 3640 82 20.0 , Decrease to 20/64" adj ohk 07-Feb-98 20:30:00 3233 85 20.0 .8,0 , 95 1.20 814.46. 19,00,,42, O.0i 1470 0.,,,88: 3,~,5 .... ',': ..... ',',,: .... . 07-Feb-98 20:34:00 3689 85 ,, 20.0 ................. Swap to 20/6~" j3os ,chk ............ Page 1 of 2 T© r,,IPhillios Petroleum Co. Job #2 Well B-2 North Forelands Well Test Tvonek Platform Ticket # 693231 "' Date & Time WHP WHT Choke Static SepGas 'Gas ' Oil Water GOR Gas S.G. Oil Comments " ' ,, pslg F 64th psig F mmscfd , bpd bpd scf/bbl APl60 07-Feb-98 20:41:00 2696 85 ,26,0 ' , . increase to 2,6/64','. pos chk .... 07"Feb-9~ 20:45:00 2562 87 26.0 90 '102 1.11 863.14 2333.66 1286 0.88 39,5 07-Feb-98 21:00:00 2508= 93 26.0 " 90 103 1,20 1296.00 3504.00 '926 0',8~ 39,5 ~asgravityls.88~ 07-Feb-98 21:15:00 2512 97 26.0 90 1~'~ 1.19 1187.14 3209.66' 1002 0188 39,5 ......... 07-Feb-98 21::~0:00 2484 99 26.0 95 112 1,23 ,,, 13,42.08 '3i31.52 916' 0',88 39.5 ' 07-Feb-98 21:45:00 2495 103 26.0. 100 .1!~ ,, ':1.24 12,31.20 3328.80 " 1007 0.88 39.5 ..... ' ' , ......... 07-Feb-98 22:00:00 2493 106 26.0 110 118 1.28 1560.00 1560,00 821 0.88 39.5 07:1~eb.98 22::15:00 ~487 '10§ 26.0 I' 150 120 , ,1.50 2716,80 2716.80 552 0188 39.5 ........ 07-Feb-98 2:~:30:00 2499 11!, 26.0 100 130 0.55 2~0.3~ 2800,32 ' ,196 0:88 "' 39.5 dhangetol"oriflce ........ 07-Feb-98 22:45:00 2500 115 26.0 410' 124 1,13 1320.24 3960.7')' ' 856" 0.88 ' ~9'.5 ...... 07-Feb-98 23:00:00 2513 118 ~.0 '410 125 1.02 ' 1~.i2.64 3296.16 722 ' 0.88 39.5 ........... 07-~eb-98 23:15:00 2501 120 26.0 " 390 128 1,02' 1021.44 15~2.16 999 ' ~,88 39.5 ........... ' 07-Feb-98 23:30:00 2528 122 26.0 390 128 "~,02 1512.00 2608100 ' '675 ' 0,88 39.5 .................. ,07-Feb-98 23:45:0,0 2495 124 26.0 '390 132 ' .1.03' 1446,.34 39'i0~,48, .... 712' , 0,88, 39;5 , '"' 08-Feb-98 00:00:00 2495 127 26.0 390 133 1,03 1607.04 3749.78 641 0,88 39.5 0a-Feb-98 00:15:00 ~470 130 26.0 '1'70' 134 0.46' 1039.20 31~7.60" 443' 0,'~8 3915 ................... 08-Feb-98 00:30:00 2450 132 26.0 170 137 0,45 799.20 2397,60 563 0,88 39.5 08-Feb-98 00:;~9:00 4063 13~, 8.0 .......................... ,, ' Decrease to 8164"'Sdj Ch, k ...... 08-Feb-98 00:45:00 4451 13~ 8,0 80 122 ' 0.08 ...... 0,88 .... ' ...... 08.Feb-98 0! :00:00 4540 124 8,0 20 127 0.47 0.88 Rock the adJ chk 08-Feb-98 01:15:00 4401 118 8,0' 20'" 138 0,07 0,88 .......... 08-1~eb.9~ 0i:30:00 ~.~,30 116 8,0 "20 140 .....b,04 361.58 97~',62 ..... 111' i,,' 0,~ 39,5 ........... ' 08-keb-98 01:45:00 4429 1i3 8.0 50 14~J'' 0,04 86,00' 231,26 ' 465 '0,88 39.5 ......... 08-Feb.98 02:00:00 4396 112 8,0 50 "142 0,04 8'5.54' 231',28 468' 0,88 39.5 ............. ...... ;'" 0,88 ...................... 08-Feb-98 02:15:00 4367 112 8.0 50 142 0.04 108.00 292.00 370 08-Feb-98 02:30:00 4334 112 8,0 50 ' ,142 0,04 ....... 0.88 ................ 08.Feb-ga O:~'iiS:00 ,4,300 110 8,0 "' 50 142 0,04 ............ 0,88 :. 39.5 ...... 08.~eb.9a 03:04:00 3318 110 28.0' , '" , .... , ...... 39.5 Walk'adJ chkuPio 28/6,i," 08.Feb-98 03:12:00 1734 116 34.0 ' change to 34/64" positive chk ' ' 08-Feb.98 03:15:00 1692 119 20.0 .... 50 'i37 0,04 2'15.14 58'1.66 ...... i86 '" 0.88 39.5 OnadJchk~T.P. tolow ...... :08-Feb-9,8 0~i~0:00 .1,670 12(J 30.0 .... ' ....... , ....... change to 3~64" adJ ~hl~ ..... ,08-Feb-98 03:30:00 3120 126 30.0 90: .... ,131 0.47 ~' 1555.20 4204,80 3,02, , 0,~,88 ,,39,,5 , , "' 08-Fab-98 03:34:00 30.0 , , Cl~'a~ge tO 30164: p, osltlv~' chk 08-Feb-98 0~:36:00 ............... Chlorides · 13~000 ppm ....... 08-Feb-98 03:45:00 1999 129 30.0 185 ' :136 ~ i,25 ' 919.20" 2~57.60 'i360 ' 0,88 39.~'" Bo{toms:,,u,p, ~o sand ..... 08-Feb-98 04:00:00 1974 131 30,0 260 139 1,41 1342,32 4026.96 1050 0,88 39,5 No sand 08-Feb-98 04:15:0'D 2045 134 30,0 255 139 1.37 1536.19 3584,'45 89~' 0.8~' 39,5 No aand ' ' "08.Feb.98 0~.':;~2:00 2049 136 30'.0' ,. ' ...... , .... i', , 39,5 'G~'s gravl'ty Is'.860 ........... 08-Feb-98 04:24:00 ~063 136 12il.94 '2827,86 39.5 Shut in well (~ ma~'lfold.' ...... ", '08-~eb-98 Oi:2S:(J~ 4034 136 .... ,, ' ..... l, ' ..... 'Be~'gln buiJdup. ' ' 08-Feb-98 04:30:00 4478 136 ................................. 08-F,b-98 05:00:00 4695 129 .... ,", ..... : ',:, ' ,,_, _ " :', ' :: ...... M,o,,n,ltor',b,,uilduP. "" , ....... '"", .... Page 2 of 2 NORTH FORELANDS SAND TEST 1 SCAN WELL TEST REPORT FIELD READINGS FIELD READINGS Date Time Comments Wellhead Choke Gas Metering' ' 6i'l Met~rin~ " '" Tubng Well' Mnf~ H;a' Diff Static Gas Meter O~. Meter Oil Oii ~3ilLine Press Temp Dia Dia Press Press Temp tizS CO= N=i SG Run Die Reading Temp Grav BSW ~ayTMo-Yr-Hr:_M. in:..S, ec .p. si~ F . .64~ 64th inh2o psig F ppm; % % in in bbl .E. APl60 % 7-Feb-98 13:30 Pressure te~t lines to 8k 7-Feb-98 i4:00 Begin Test 28.3 50.4 .... " ' 7.Feb.98 14:1,~ 26.2 '50.0 ............ 7-F~b-~e ~:30 ....... 25.4 '50.b .............. 7-Feb-98 14:45 PreSSUre test lines to 81~' 33.9 54.3 '" , ,, .... ,, ,, ,, , 7-Feb-98 15:00 7816.3 58.0 7-Feb-98 i5:10 Safety meetin~l 7900.0 58.0 .............. "7.Feb.§8 15:1'~ 8010.3 '58.1 ........................... '7.Feb.98 15::~0 .... 2975.8 56.7 .... 7-Feb-98 15:45 2974.0 55~5 7-Feb-98 16:00 2975.0 55.6 ' 7.Feb.~8 ~6:04. bi'e. well on...8/64" adi 2926.0 56.~ 8 ........ 7-Feb-98 16:10 Ad~i chk clog~!.n~ 2802.0 59.b ......... " ..~.1580,98 16:15 On bypass 2925.8 60.3 ......... 7-Feb-9'e '~6:1"~ Shut-in well,'chk .full ;3f debris 2935.0 "'60.b .... . ..... ' ..... . ........ i... ". ' . .... ' 7-Feb-98 16:30 2962.5 60.7 7-Feb-98 16:32 Open, well on 12/64".ad~.c.'hk , 2671.0 61.0 12 ....... 7-Feb-98 16:34. Increase to 1616..4" a,d~ chk. 2702.0 62.0 ~'6 ....... '.'" ' . ...... '" ' . '7-Feb-{)8 16:35 Increase to 20/64" adj chk 2709.0 61.0 20 ' 7.Feb.§8 16!3~ Fluid attank 2710,0 62.b ' 20 ............... 7-Feb-98 i6:40 Increase to 32/64" ad~ chk .'.,. 2577.0 "'. 62.'0 32 i'. .......... .... '." ' _.. 7-Feb-98 16:45= Increase .,t.o .39,/64" ad~ chk 259~.8 58.3 39 ' 100.0 7-Feb-98 16:5~ Decrease to 32/64" adj chk " 2640.0 66.0 32 ......... '7-F'~b-9s i6:5~ 'Decreese to :~5/64,'~di chk 2650.0 66.0 25 .............. 7-F~b-!~8 1'7:0~1 ' ' ' 2780.5. 66.8 2'5 ...... ~ 100.0 7-Feb-9e ~7:d~ .Decrease t~'2'01~t".adj chl~ ' 2830.0 67.0 20 ............ '7-Feb-§8'i7:15 .... 2§69.5 "' 66.9' ' 20 ........ 100.0 7-Feb-§8 17:22 In(~r~se to ~.4164" a.d.i Chk 3071.0 67.0 24 .................. ' 7'F'~b-98 17:30 3173.3 67.6 24 ......... 100.0 7-Feb-98 17:45 3300.8 67.9 24 ..... ~ ~ 00.0 7-Feb-§8 i8:00 ........ 3~i'9.3 68.4 24 .................... 100.0 7-Feb-§8 18:1'5 ' ' ' ~5i2.5 68.9 2-~ ....... 100.0 7-Feb-98 18:30 3670.8 69.1 24 100.0 .... 7-Feb-98 18:39 Ir~'crease'to 28/64" ad~ chk.'... 3687.0 69.0 '" 2~ ...... . ' . .... .' '. ........ 7-Feb-98 18:4~) 3625.5 69.5 28 ........... ' ~ 00.0 7-1~eb-98 19:00 3862.3 70.4 28 100.0 ~Z-Feb-§8 19:06 Incre~se t9 ,3~64" a.d~ ,chk ',' ," 3903.0 71.0 '32 ....... ... ' ' ': . ' .... 7-Feb-98 19:12 Decrease to 20164",,adi chk ..... :~980.0 71.0 20 ' ' ' 7-Feb-§8 19:1~) 400~.3 71.2 20i ............. 100.0 7-Feb-§8 19:~1 Increase'to 32/64" adj (~hk 3457.0 71.0 ", 32 ..... "' 7-Feb-98 19i30 ...... 3824.3" '71.9 ;~Z:.............. 99.9 Page 1 of 3 FIELD READINGS l~ale ¥ime Comments Wellhead Choke Gas M~l~rtn~ .... 011 ~ubng Well Mnfld Htr Diff Static Gas Meter Orif. Meter Oil Oil Oil Line Press Temp Dia Dia Press Press Temp H25 C02 N'~ SG Run Dia Reading Temp Grav BSW Day.-Mo-Yr-Hr:Min:Sec psi~ F 64th 64th inh2o psig. F pp.m % % in in bbl F APl60 % ~-Feb-98 19:381 D~crease to 28/64" adj chk 3850.0 73.0 '28 ,. 7-Feb-98 1.9:45~ ' 2939.3 77.3 28 ...... 75.0 , 7-Feb-98 19:4~ D~crease t(~ 20/~4" pos chk 393~.0 78.0 20 .......... ' 7-Feb-98 19:57 Tum well into separator 3940.0 78.0 20 7-Feb-9820:00 " 3~965.5 ' '77.4 20 " 73.0 " 7-Feb-98 20:11 Increase to 28/64" ad~ chk 3733.0 78.0. 28 , , 7-Feb-98 20:15 Change to 1.5: orifice 3078.0 ' '80.5 28 , , .. 1.5! ' ' 73.0 7-Feb-98 20:25 Decrease to 20/64" adi chk , ~640.0 82.0 20 .... 7-Feb-98 20:30 ~233.5 85.0 20 1.5 70.0 ,, 7'Feb.98 20:34 Swap t~. 20/64" pos chk 3689.0 85.0 20 ' 7-Feb-98 20:~41 Increase to 26164" pos chk 269~6.0 85.0 26 , ' ....... 7-Feb-98.20:45 2562.5 86.6 26 87.8 106.1' 102.0 0.884 5.761 1.5 110.9 43.4 70.0 7-Feb-9821'.00 2523.3 93.;~' 26 97.5 115.5 103.6 " 0.884 5.~61 1.5 i08.4 43.4 70.0 1-Feb-9821:15 " ;~'~26.8 .... 96.~ 26 120.0 130.0 107.5 0.8~4 5.761 1.5 111.1 43.4 '~0.0 7-Feb-9821:30 ' ' ' 28{99.3 '99.5! 26 174.9 146.7 112.1 0.884 5.~61 1.5 114'.3 43.4 " 70.0 ' 7-FebZ9821:45 2509.8 103.0 26 101.21 144.9 114.4 0.884 5.761. 1.5 ' " 116.7 43.4 73.0 '~'-Feb-98.22100" , 2506.8 1061'~' 26 ,116~3= 156.0 117.7 ~ 0.884 5.761 1.5 ,' .... 119.6 43.4 .... 50.0 7-Feb-ge22:15 2502.5 109.1 26 119.9! 155.2 120.6 0.884 5.761 1.5 'i22.6 43.4 50.0 ", 7-Feb-98 22:30 Chan~e to1" orifice , ' ~51'~.5 111.7 26_ i 14.1 422.6 130.8 - 0.884 5.76':~ 1.0 i..i , , 126.3 43.4 ' 50.0 7-Feb-9822:45 251i.8' i15.0 26 83.9 447.9 123.6 0.884 5.761 1.0 129~4 43.4 75.0 7-Feb-9~2~3:00 2527.8 118.2 26 .97.8: 425.4 124.9 0.88~, 5.761 1,0 13~).2 43.4' '70.0 7'-Feb-9823:~5 .......... 2516.5 121.0 '26 92.3 428~0 127.9 0.884 5.761 1.0 "¥33.1 '43.4 ~0.0 ~'-Feb-98~23:30 .... ~'541.8 '1'22.9 26 ' 85.1 412.5 128.4 ......... 0.88'4 5.761 1~0 " 134.2 "'43.4 65.0 7ZFeb-9823:45 2507.8 124.9 ~6 i04.6 419.4 132.9 .... 0.884 5.761 1.0 13~5 43.4' 73.0 ,,, 8-Feb-9800:00 " 2509.3' 'i27.8 '" 26 "28~.5' 388.6 133.3 ..... 0.8~4 5.761 1.0 ' ' 1'38.5 43.4i 70.0 8-J:eb-98 00:15 .... 2485.3 ~30.1 26 "0.4 200.1 134.9 0.884 5.761 1.0 ...... 13~'?1 43.4 75~0 ' ~'-'Feb-g~ 0bi30 ..... ~464,8 132.4 26 43.{)!' 2~)0~5 137.2 ' 0.884 5.76'1 1~0 .... 139.3 ' 43.4 75.0 8-F~b-98 00139 Decrease t° 6164" a.dj Ci~k' ' ~063.0 132.5 ~i ............ ' ' 8'-'1~i~-98 00:45 , ,. ,~456.3 ' i33.0 8 ' ' ' 2.9 41,6 122.7 [ .. 0.884' 5.761 1.0 ........ 131.5 43.4 75,0 8-Feb-98'01:00. Rock adi chk , ~,~)61.5 12418 " 8 2.3 22.9 127.5 '" 0.S84 5.761 1'10 . . 12'6.0 43.4 75.0 "' 8-Feb-9§"01:15 ~,415.8 118.3 8 "7.6 64.8 138.7 01884 5.761 1.0 139.9 43.4 75.0 8-F~b-9~ 01:30 "' 4444.5, 116~0 '8 ..... 6.1 63.2 140.1 ' 0.884 5.761 1.0 '" 145.2 "43.4 '~.0 " 8-Feb-9802:00 ' ' 4410.8 112.1 ' 8 ' 0.~ 58.3 1~,2.3 ' 0.884 5.761 1,0 i46.0 43,4 73.0 8-Feb-9802:15 ~ ' ' 4381.5 111~9 8 0.t 57~8 142.2 0.884 5.761 1.0 146.0 43.4 73.0 8-Feb-9802:30 ' ' 434'7.3 111.1 8 0.4 62.2 141.5 "~ 0.884 5.761 1'.0 145.7 43.4 73;0 8-Feb-9~02:45 ' '~ 431'5.0 " ~'10.1 ' 8 ' " 0.3 61.1 141.2 0.884 5.761 1.0 14~.4 ' 43.4' ~3.0 ' , 8-Feb-9S03:00,,,,,, ,, ' ' 4~12.5, 10911,., "8 , 0.1 56.8 141.2 0.884,; 5.761 !.0 ' ,. '~'46,5' 4,3,4 ' 73.0 8-Feb-98 03:04 Walk adi chk to 28/64" ,- 3318.2 110.0 28 j .... 8-Feb-9~ 03:12 Chanile to 34164" po.s chk 1734.0 116.0 ~ ......... 8-Feb-9803:15 0nadjchk, T.P. tolow 1692.3 119.2 ' 34 0.2 210.2 137.6 0.884 5.76~ 1.0 ' ' ¥34.9"43.4 ' 73.0 , ~ , 8.Feb.98 03:20 Chan~e t.o. 30/64'i'adj chk ' ~670.0 120.0 ~0 .................... 8-Fe1~'9~'03:30 .... 3091.0 126.'1 ..... 30 32.1 103.a 131.7 " 0.8841 5.761 i.0 ' 139.a 43.4 73.0 . 8-Feb-98 03:34 Chan,tle to 30/64,,",,po~, c...hk , , 30 ...... , 8-Feb:98 03:36 C,h10rides, =13,000 ppm ...... '8-Feb-9803:45B0ttomsuP, nosand .... 201'"~.3 .... i'29.4 30 "139.'4 217.0 135.3 0.884 5.761 1~3 .", ' 1'35.9: 4:~.4 75.0 ' 8-Feb-9~ 04:00 No sand i98~16 131.6i 30 I 138.2 289.7 137.9 .... 01884. 5.761 1.3 '138.7 .... 43'.4 '" 75.0 Page 2 of 3 FIELD READINGS Date ' Tinge Comment, , Wellhea'd Choke Gas Metering: Oil Metering Tubng Well' Mnfld Htr Diff Static Gas' ' Meter Orif. Meter Oil Oil]Oil Line Press Temp Dia Dia Press Press Temp H2S CO= N= SG Run Dia Reading Temp Grav BSW .Day-Mo-Yr-Hr:Min:Sec. psig F 64th 641h inh2o psig F ppm % % in in bbl F APl60 % 8-Feb-9804:15 Nosand 2060.3 ~35.0 30 107.5 277.8 139~:~ 0.884 5.761 1.3 141.8 43.4 70.0 8-Feb-~804:22 Gas ~lravity is .860 2049.0 136.'0 ' ' 3.0 . ' . 8-Feb-980:4:24 Shut-in well (~ manifold 2063.0 136.0 ..... '.8-Feb-9804:25 Berlin build-up .... 8-Feb-9804:3b ' . I "40:~44478.8.0 136.1136'0 "~-Feb-~)S b5:00 46~5.31 129.2 ..... 8-Feb-9805:15 ' 4728.0 125.8 ..... ' 8_Feb.98 '05:30 '. 4751.3 " 122.8 ...... ' 8_Feb.9805:45 ..... 4771.5' 119.8 ....... 8-Feb-9806:00 4780.8: 116.8 8-Feb-9806:1 ~ .... 4791.3 114.3 ' ' 8-Feb-9806:30 ............. 4800.8 112.0 " - 8-FebL9806:45 4809.0 109.4 8-Feb-9807:00 ' ..... 4815.8 " 107.~ ' " ' 8_Feb.9'807:15 ' . 4836.3 105.2 .......... e-Feb-9807:30 4825.0 103;2 ..... "8-Feb-9807:45 - 4827.5 101 ~2 ....... , ,,,, , , , , , , , . , ,, 8-Feb-9808:00 4829.8 99.3 8-Feb-9808:15 ...... 4831.3 96.'6 ............... .......... , 8-Feb-9808:30 4834.8 95.0 ..... 8.Feb.9808:45 ...... 4836.3 92.1 ....... 8-Feb-9809:00 4836.5 89.8 , , 8.Feb.9809:15 ' 4838.0 ..... 87.8 ......... '" 8-Feb-9809:30 ...... 4838.8 85.~ ............ 8-Feb-9809:4.~ ' ' ' 4839:3 83.2 ................. ..... ' 8-Feb-§810:00 .... 4840.3 8111 ............ 8-Feb-9810:15 4842.8 79.3 8-Feb-~ 10:30 ...... 4e45.5 7715 ............... 'a-Feb-ge 10:45 4850.5 7617 ........ 8.Feb.9a ~'1':00 ..... 4854.3 " 7512 ......... ' 8:Fab. ge 11:15 ' 4856.8 73,9 .......... r. . .8:l~eb.{811:30 ..... 4859.3 72.9 ............. 8-Feb-9811:45 ........ 486i 15 71.8 ....... 8-Feb-9812:00 4862.5 70.7 8-Feb-9812:15 ' . , 48~1.3 ' 69.6 ...... i .............. '8-Feb-ga 12:30 ....... 4e~8.0 . 68:~ ....... 8-Feb-9812:45 4864.8 67.9 a-Feb-9813:00 '~865.5 67.0 8-Feb-9813:15 ...... 4866.0 66.1 ..... 8.Feb.l~813:30 ....... 4866.5 ' 65.~' .................. ' -8.Feb.9813:45 End test ' . 4867.3 64.3 ......... Page 3 of 3 CALCULATIONS CALCULATIONS Da~e 'Time DTime Gas Flow Oil Flow 'Water Gas Oil Water GOR OGR BS&W Rate FlowRate FlowRate Volume Volume Volume Day-Mo- Yr-Hr:Min Hr mmscfd bpd bpd rnrnscf bbl bbl scf/bbl bbl/mscf % 07-Feb-98 19:45 5.75 0.00 0.00 0.00 0.00 0.00 75 , , ,, , 07-Feb-98 20:00 6.00 575.79 1556.76 0.00 1.56 4.22 73 07-Feb-98 20:15 6.25 " 1271.51 '3437.79 0.00 10.18 27'.52 73 07-Feb-98 20:30 6.50 122~.51 2864.19 0.00 20.70 48.30 70 07-Feb-98 20:45 6.75 1.18 1567.13 3656.64 0.01 32.31 75.39 '751.80 ~.33 7'0 07-Feb-98 21:00 7.00 1,29 1516.31 3538.05 0.03 48.59 113'.38 849.95 1.18 ' 70 07-Feb-98 21:15 7.25 1.51 1'626.78 3795.82 0.04 64.98 ~ 51.62 92~.50 1.08 70 07-Feb-98 21:30 7.50 1.92 1439.81 3359.56 0.06 '80.56 187.97 1333.15 0.75 ' 70 07-Feb-98 21:45 7.75" 1.44 1447.37 3913.26 0.08 95.91 259.'31 997.18 1.00 73 07-Feb-98 22:00 8.00 1.g0 1604.38 1604.38 0.09 112.05 112.05 996.09 1.00 50 07-Feb-98 "22:15 8.25 1'.61 1559.59 '1559.59 0.11 127.72 127.72 1035.14 0.97 50 07-Feb-98 22:30 8.50 d.40 1212.35 1212.35 0.11 143.47 "i43.47 331.89 3.01 "' 50 .... 07-1~eb-98 '22:45 ' 8.75 1 '.02 1559.41 4678.22 0.12 160.30 480.90 656.5~ 1.52 ' 75 07-Feb-98 23:00 9.00 1.07 1490.96 3478.90 0.14 176.20 411.13 71~.50 1.39 '70 07-Feb-98 23:15 ' 9.25 i.04 1599.00 2398.51 0'.15 192.37 288.56 651.36 1.54 60 07-Feb-98 23:30 9.50 0.98 1504.36 2793.81 0.16 "20¥.59 385.52 651.20 1.54 ....... 65 07-Feb-98 23:45 9.75 1.09 1440.22 3893.9:~ 0.17 223.21 603.49 ' ~5~.10 1.32 ~3 08-Feb-98 00:00 "' 10.00 " 1.74 1612.50 3762.49 ' 0.19 239.16 558.04 1077.67 0.93 70 08-Feb-98 00:1'5 10.25 ' 0.04 1482.00 ' 4446.01 0.19 254.31 762.93 29.87 33147 75 08-Feb-98 00:30 10.50 0.48 1531.77 4595.32 ' 0.19 269.40 808.20 313.51 3.19 75 08-Feb-98 00:45 10.75 0.06 '82.39 247.16 '1~.'19 279.18 837.51 762.70 1.31 ' ' 75 08-Feb-98 01:00 11.00 0.05 0.00 0.00 ' 0.19 279.65 ' 75 08-1~eb-98 01':15 11.25 0.12 166.85 ' 500.54 0.1'§i 280.96 842,87 715.73 'i.40 ' 75 '' 08"1~eb-~801:30 11.50 01'~1 132'.76 358.94 0.20 283.05 765128 '795172 1.26' ' 73 08-Feb-§8 02:00 '~2~00 0.02 106.00 286.5'9 ' 0.20 287.89 778.35 ~75.52 ~.70! ~3 0S-Feb-g8 02:15 12.25 0'.01 260.14 70'3.34 0.20, 291.0e i87.00 '35'.85 27.89 73 08-Feb-'98 02:30 12.50 0.03 162.26 "438.71 0.2~' 293.45'793.41 166.25 6.02 73 08-Fe~-98 02:4'5 12.75 0.02 215.71 583.22 " 0.20 29'5.98 800.24 11~.81 8.86 ' ' 73 08_Feb.98 03:00 13.00 0.01 ~64.52 '715.18 0.20' 298.96 808.30 54.06 18.50'~ 73 08-Feb-9803:15 13.25 01'03 1838.81 4971.60 0.2~ 308.89 835.15 18.56 53.881 '~3 08-Feb-98 '03:30 13.50 0.'30 1159.33 ' 3134.48 ' 0.20 323,9i' 875.76 261.33 3.83 ' ' 73 08-Feb-98 03:45 13.75 1.40 1717.35 5152.04 0.21 341.39 1024.17 814.7'6 1.23 ' 75 0S-Feb-98 04:00" '14.00 ' 1.61 178~.83 5369.50 ' 0.23 359.80 1079.40[ 897.39 1.11 75 '" 08-Feb-9804:15 ~4.25 1.38 1874.75 4374.42 0.'25 378.50 883.17 737.91 .... 1.36 " '70 Page 1 of 1 REPORT T N Phillli~)s Petroleum Co. Job #2 Well B-2 North Forelands Well Test Tyonek Platform Ticket # 693231 Date Time WHP WHT- i-~pG~'- --Static C-h'bk~ Gas "' Oil W,~er gas' -Oil--"~/~- --~'&W .... (~-- ..... Oil .... Day-Mo-Yr-Hr:Min psi F F psi 64th mscfd bpd bpd mscf .. bbl bbl % . .SG APIa0 07-Feb-98 14:00 28.3 50.4 07-Feb-98 14:15 26.2 50~0 ....... 07-Feb-98 14:30 25.4 50.0 ............ 07-Feb-98 14:45 33.9 54.3 07-Feb-98 15:00 78i6.3' 58.0 ..... 07-Feb-98 15:15 8010.3 58.1 "' bf-i=el~:§8 'i5:3b 2975.8 56.7 ...... 0~-Feb-98 15:45 2974.0 "~5.5 ......... 0~.'l~eb.9e "i6:00 29-~5.0 55.6 ................... 07-Feb:98 16:15 2925.8 60.3 ................ 07_Feb_98 '16:30 2962.5 60.7 ...................... 07-Feb-98 16:45 2597.8 58.3 39 ........... 100.0 " 07-Feb-98 17:00 2780.5 66.8 ......... 25 ...... 100.0 07-Feb-98 17:1~ 29~9.5 66.9 20 ....... 100.0 ........ 07-Feb-98 i7:30 3173.3 67.6 .... 24 ........... '..i. .i .... , 100,0 ' .... 0~-Feb-98 17:45 3300.8 67.9 24 100,0 ' 07-Feb-98 18:00 3419.3 68.4 - . 2.4- .............. 100.0 ......... 07-Feb-98 18:15 3512.5 68.9 ........ 2j, .............. 100.0 '' 07-Feb-98 18:30 3670.8 69.1 .... 24 ................ ~00.0 07-Feb-98 18:4~ ' '3625.5 '69.5 ....... 28 .............. 100.0 07-Feb-9S '~'9:00 3862.3 70.4 ' 28 ............ 100.0 07'Feb-g8 i9':1,~ 4008.3 71.2 ' '' 20 ............. '"' ~00.0 07-Fe1~'-98 19:30 "'3824.3 71.9 ' ' '3~ ...... 99.9 " 07"Feb-g8 19:4~ 2939.3 77.3 ......... 28' 0.00 0100 0.00 0.00 0.00 0.'00" 75.0 07-Feb-ge' ;20:00 39~.5 7'7.4 ........ 20 0.00 575.'79 i556.76 ' '0.00" 1.56 4.22 73.0 07'-'Feb-98 20:15 3078.0 80.5 ' 28 0.00 1~71.51 "343f'.19 0.00 10.18 27.52 73.0 '" .- , ............. 07-Feb-98 20:30 3233.5 85.0 20 0,00 .1227.51 2864,19 0.00 20.70 48.30 7010 ......... ._ 07-Feb-98 20:45 2562.5 86.6 102.0 106.1 2(~ ...... 1178.16 1567,13 3656,64 12.27 32.31 75.39 "' ~0.0 ~).88~"' 43.4 07-Feb-g8 21:00 2523.3 93.3 103.6'- 115.'5' 26. 1288'.'79 1516.31 3538.05 25.70 .... 48.59 113.38 70.0' (~.884' 43.4 07-Feb'§~;~1:15 2526.8 96.6 107.5 "130.0 26 1505',58' 1626.78 3795'~2 41.38.. 6.4.98. 15.1.62 ~;0.0 '~884' 43.4 I.. 07.".feb'98 21:30 24§~.3 99.5 112.1 146.7 "26 1919'.48' 1439.8~ 3359.56 ~1~38 80.56 187.97 70.0 0.884 43.4 07-Feb-98 21:45 2509.8 103.0 1i4.4. 144.9 26 1443,29 i447.37 3913.26 76.41 '" 95.91 259.31' 73.0 01a84 43.4 07-Feb'98 22:00 "2506.8 106.i '1i,,7.7' '156;,0 2~' 1598.11' 1604.38 ~'604.3e 93.06' 11'2.05 112.05 50.0 I 0.8e4 43.4 07-Feb-98 22:15 2502.5 109.1 ,,120.6 155.2 "'26' 161~,.40 1559.59 1559,59 109.87..'.'.i' 127.72 127.72 50.0 0.884 43.4 07-Feb-98 22:30 2512.5 111.7 1:~0.8 .... 422.6 ' 26 '~02136 1212.35 12i2'i~5 .111.4.06 .... 143.47 143.47" 50.0 0.884 , ........ 07-Feb-98 22:45 2511.8 115.0 . 123.6 447.9 26 1023.78 1559.41 4678~.2 124.73 160.30 480.90 75.0 0.884 43.4 07-Feb-98 23:00 2527.8 118.2 ,.124.9.,' 425.4 26 1.072~.75 .1490.9~.' 3478.90 135.90 176,20 411.13 70.0 0,884 43.4 07-Feb-9823:1~ 2516.5 121.0 127.9. 428,'[J 26 1041.52 1599.00 2398.51 146.75 192.37 288.56 60.0 (J'.~84' 4314 ..07-1~eb'§8 23:30 2541.8 122.9 .' 12~.4 412.'5 26 979.'65' "i504136 2793.81 156.96" 207159 385.52 65.0 d'1884" '43.~ 07-Feb-ge 23:45 2507.8 124.9 132.9 419.4 26 1090.39 1440.22 3893.93 168.32 22'3.21 603.49 73.0 0.884 43.4 0a-Feb-ge 00:00 2509.3 127.8 133.3 '388.6 ..... 26 173~.75 ....1612.50 3762.49 186.42 239.16 55'~'.04 70.0 d~884 43.4 '08'Feb-98 00:15 '2485.3 130.1 134.9 200.1 '"26 '44.'~ '"1482.00 4446'.'01 la6.88 254.31 762.93 .....75.0 o.e84 43.4 , ................. Page 1 of 3 TO NPhillliDs Petroleum Co. Job #2 Well B-2 North Forelands Well Test Tyonek Platform Ticket # 693231 Da-~' -~ime WHP r~WFIT-'-~pGas Stab~ Choke. G~ --~-~" '~'"av~r ........ G~ ..... -Oi-i .... W~'f~-F~-I~W-'---G~,~ ..... ~-il-- Day-Mo- Yr-Hr.'Min psi F F p~ 64th mscfd bpd bP..d mscf bbl bbl % SG APl60 OS-Feb-ge 00:30 2464.8 132.4 13~'.2' 2,0,0.5 26 480.22 i531.7,7, 4595.32 i91,.88"'2~69.40 808.20 75.0 0.884 4.,3..4 0e-Feb-98 00:4~ 4456.3 13'3.0 122.7 41.6 8 62.84 82.39 24'7.16 , 192.53 ,279.;!8, 83,7.,51 '75.0 , 0.884 43.4 08-Feb-98 01:00 456'1.5 124.8 12~.5 22.9 8 45.01 0.00 0.00 193.00 279.65 ..... 75.0 0.884 43.4 08-1~eb-98 01:15 4415.8 118.3 138.7 64.8 8 119.42 166.85 500.54 194.25 280,96 842.87 75.0'' '0.884 ~'~.4 08-Feb-98 01:30 4444.5 116.0 14~.1" 63.2 8 165.~, !32,'.7(j 358.9,4 1'95...35.'..! 2.83..05 765.28 73.0 0.88~, 43'~4 0e-Feb-ge 02:00 441b.8 112.1 142.3 58.3 8 18.6i 106.00, 286.59 !.95.74. 287.89 778.35... .~3.0 ' (~,88.4 .. 43.4 08-Feb-98 02:15 4381.5 111.9 .142.2 57.8 8 9.33 260114 703.34 195.83 291.08 787.00 73.0 0,884 43.4 0e-Feb-98' 02:30 434'~.3 111.1 141.5 62.2 8 26.98 162.26 438.71 196.11 293.45 7~3.41 73.0 ' 0.884 ' 4~.~ 0S-Feb-ge 02:45 4315.0 110.1 141.2 61.1 ,.,8 24.33 215.71 583.22 196.37 2..9,5.98'800:24 73.0 (~.884 ~43[4 08-Feb-98 03:00 431~i~ 109.1 141.2 56.8 8 14.30 264.52 715.18 196.52 298.96 808.30 73.0 01884 43.4" '08-Feb-98 03:15 1692.3 "11~.2 137.6 210.2 34 34.13 1838.81 49~;:1.60 196,87 '308.89 835.15 ' 73.0 0.884 '"43.4 08-Feb-98 03:30 3091.0 126.1 131.7 103.8 30 302.97 1159,33 3134.48 200.03 323.91 875.76 73.0 0.884 43.4 OS-Feb-ge 03:45 201~.3 129.4 135'.3" ' 21~.0 30 1399.23 1717.35' .... ~5'2.04 '214.60 3~,1.39 11j~4,17 75.0 0.884 43.4 0~-Feb-ge 04:00' ' 1'988.8 131.6 137.9 289.7 30 1606.18 178~i~3 5369.50 231,33 ,359.80 i079,'~0~ 75.0 0.884 .... ~3.4 08-F'~b-98' 04:15'. 2060.3 135.0 139,3 27718 30 -1383.40 1874.75 4374.42 245.74 !37e,50 883.17 7'0.~ 0.884 "'43,4 08-Feb-98 04:30 4478.8 136.1 ............... 08-Feb-98 05:00 469~.3 '129.2 ..................................... 0e-Feb,98 05i'15' 4728.0 125.8 " .......................... 08-Feb-98 05:30 4751.3 122.8 08.Feb.'g8 05:45' 4'~7i'.5 'i19.8 08-Feb-98 06:00" [ 4780.8 ' 11~;'.8 .......................... 08-Feb-ge 06:15 ' 4791.3 114.31 ...................................... O8-Feb'§e 06130 4'80d.8 112.0i ................. 08-Feb'98 06:45 4809.0 109'.4 - ,. . . i ".. "'. '. .... ' ........... 08-Feb-§8 '07:00 4815.8 107.51 .... 08-Feb-98 07:15 4836.3 105.2. ' ' ........... 08-Feb-98 07:~0 4825.0 103.2 0~-Feb'98 07:45 482'~.5 101.2 ............. .,. ' ' " 08-Feb-ge '08:b0 .... 4829.8 99'.3 08-Feb-98 08:15 4831.3 96.6 08-Feb-§8 08:30 4834.8 95.0 ' , 'O~-Feb-98 b8:45 4836.3 92.1 ..................... 08-Feb-§8 09:00 ...... 4836,5 89.8 .................... 08-Feb-98 '09:15 4838.0~'' '87.8 ................. 08-Feb-98 09:30 4838.8 85.3 ...................... _ ................... 08-Feb-98 09:45 ' 483~.3 83.2 08-Feb-98 lO:bO 4840.3 " '81.1 ................ ' O~-Fe'b.9'8 10:15 4842.8 79.3 ............................ 08-Feb-98 '10::~0 4845.~ ..... 77.5 ......... o~-F~b-98 10:45 4850.5 ' '76.7 ....... ' O~.Feb_98 11:00 4854.3 75.2 ......... 08-Feb-98 11:15 ' 4~56.8 '"73.9 " ' ............... Page 2 of 3 TO N Philllios Petroleum Co. Job #2 Well B-2 North Forelands Well Test Tyonek Platform Ticket # 693231 Time .... W----H-P-- WFi-T-- -SepGas S-'t~tic --C~k~ Gas 'O-il ..... VV~[,~---' '---G-~ ....... ~i~ ..... W~-~e~- -']~-s-&~- .... ~-a~, -O]l-- Day-Mo-Yr-Hr:Min psi F F psi 64th mscfd bpd bpd m,scf bbl ,bbl % SG APl60 08-Feb-98 11:30 4859.3 72.9 , ,. 08'Feb-98 11:45 4861.5 71.8 08-Feb-98 12:00 4862.5 70.7 ,. 08-Feb-98 12:15 4871.3 69.6 08-Feb-98 12:30 4878.0 68.7 08-Feb-§~ 12:45 4864.8 67.9 .... 08-Feb-§8 13:00 4865.5 67.0 ............... 08-Feb-98 13:15 4866.0 66.1 ......... 08-Feb-98 13:30 4866.5 65.2 08-Feb-98 13:45 4867.3 64.3 Page 3 of 3 CHARTS RTO N Well Test Report Philllips Petroleum Co. Well B-2 North Forelands Tyonek Platform Job #2 Well Test Ticket # 693231 5000.0 4500.0 ............................................... ~,--e'-~,'~ · · · · · 4000.0 ' ' ' "Ct ........................................................................... 3500.0 ................................................................................ 3000.0 ' Il, .............................................................................. 2500.0 .......... .~..·. ·. ¢~' '~ - ·- ~- .~' -·- ·..~..·. ·- ~ '· - · .................................. 2000.0 ......................................................................... ·' ·' '·' ' · · & & ~ [] I. .,I, '~ & · 1500.0 .......... ~ -&- ·- ~- '1~ ...... & .... &' & .... &' & .................................. looo.o ............................. m..m. m -m- .m .......................................... 500.0 ',- (Xl ~ ~ C~ 04 ~ ('NI 0,1 (Xl ~ ~ ~ {",,I ~ 0 0 CD 0 CD 0 ~ 0 0 0 0 0 0 0 0 CD CD 0 Time · WHP (psi) · Gas Rate (mscf/d) &Oil Rate (bbl/d) RTON Well Test Report Philllips Petroleum Co. Well B-2 North Forelands T¥onek Platform Job #2 Well Test Ticket # 693231 ~WHP (psi) --~--Gas Rate (mscf/d) ~Oil Rate (bbl/d) CD 0 C~, 0 CD' 0 0 0 0 0 CD Time 0 0 0 CD 0 SUNFISH SAND TEST 2 MANUAL WELL TEST REPORT FIELD READINGS FIELD READINGS Date Time :Comments Wellhead Choke Gas Metering 011Meterlhl[ ' ' ' Tubng csng Well Mnfld Htr Diff Static Gas Meter Orif, Meter Oil OII Oil Line Press Press Temp Dis Dis Press Press Temp H2S C~); N2 SG Run Dis Reading Teml: Grsv BSW [D.a.y-Mo-yr-Hr:Min:Sec psi~ psig F 64th 64th inh2o psig F pp.m % % in in bbl F A,.PI60 % 08-Feb-98 17:15:00 Openwell on i4/64"adi .... 08-15eb-98 17:19:00 14 ,, , , , 08-Feb-98 17:20:00 Increaseto 18/64" adi 18 ....... 08-Feb-98 17:25:00 Increase to 20~64" ad~ , , 20 , 0.00 0 08-Feb-98' 17:30100 I~creas,e to 22164" ad~ 22 52 240 70 , ,. 0.884 5.7~1 1.25 4,17 ~ 110 43,4 100 08-1~eb-98 17:45:00 Increase to 28164" ad~ 790 28 52 240 83 0.884 ~5.761 1,25 14.17 110 43,4 100 08-Feb-98 18:00:00 ' 790 ' '28 ' 52 240 96 0.884 5.76'1 1,25 21.67 110 43,4 ' 95 08-'Feb-98 18:15:00 ' 800 "' 28 '42 240 '107 '' 0.~184 5.761 1.25 32.50 110 "~,3,4, 50 08-JS~b-98 18:30:00 810 28 50 210 '110 0.884 5.761 1.25 43.34 110, 43.4 30 08'Feb-98' 18:45:00 880 28 ' ' 52 2i0 111 0,884 5,761 1,~5 50,84 ~10 43.4 5 08-1~eb-98 19:00100 ' " 910 '' 28 50 215 . 115 0.884 5,761 1,25 60,84 110 43,4 0 08-Feb-98 19:15:00 §hut-inwell ' 28' 50 215 ' i15 0,884 5,761~ 1,25 70,00 i10 43.4 "' 0 Page 1 of 1 CALCULATIONS CALCULATIONS Date Time DTime G~s FI(~W Oil Flow Water Gas Oil Water (}OR O'QR BS&W Rate FlowRate FlowRate Volume Volume Volume Day-Mo- Yr-Hr.'Min Hr mmscfd bpd bpd, mmscf bbl bbl scf/bbl bbl/mscf % 08-Feb-98 17:20 0.08 0,00 0,00 0.00 0.00 0.00 08-Feb-§8 17:25 0.17 0.00 0.00 0.00 0.00 0.00 08-Feb-98 17:30 0.2~5 0.97 (J,'00 400.32 0.00 0.00 4.17 ' 100 b8-Feb-98 17:45 0.50 0.95 0.00 960.00 0.01 0.00 10.00~ '" 100 08-Fe~-98 18:00 0.75 0.94 ' 3~.00 68~.i00 0.02 0.38 7.13 25977.08 0.04 95 08-Fe~3-9~ 18:15 1.00 0.83 519.84 519.84 ' 0.03 5.42 5.42 159~.'15 0.63 50 08-Feb-98 18:30 1.25 0.84 728.45 312.19 0.04 ~'.59 3.25! 1158.45 0.8~ 30 08-Feb-98 18:4,~ 1.50 0.86 684.00 36.00 0.05 7.13 0.38 1256.88 0.80 5 08-Fei3-98 19:00 1,75 0.85 960.00 0.00 " 0.06 10.00 0.00 884.66 1.13 O 08-F~b-98 19:15 2.00 0.8,~ 879.36 0.00 0.07 §'.16 " 0.00 965.79 1.04 0 Page 1 of 1 CHARTS RTON Well Test Report PHILLIPS PETROLEUM CO. 8 Feb, 1998 B-2 Sunfish Sand Production Well Test # 2 Tyonek Platform Ticket #: 693231 1coo 900 -~ ......... 800 7OO 6OO 5OO 4OO 300 200 lO0 0 17:30 17:45 18:00 18:15 18:30 18:45 19:00 19:15 19:30 Time ~Gas Rate (mscfld) I RTON Well Test Report PHILLIPS PETROLEUM CO. 8 Feb, 1998 B-2 Sunfish Sand Production Well Test # 2 Tyonek Platform Ticket #: 693231 lOOO 900 800 700 600 500 4OO 300 20O 100 0 17:30 [] & [] i i i i 17:45 18:00 18:15 18:30 18:45 19:00 19:15 19:30 Time []Gas Rate (mscf/d) &Oil Rate (bbl/d) REPORT RTO N Philli~)s Petroleum Co. Well B-2 Sunfish Sand Tvonek Platform Well Test Report Job 2 Well Test Ticket # 693231 8-Feb-17:1 8-Feb-17:19 8-Feb-17:20 8-Feb-17:25 8-Feb-17:30 8-Feb-17:45 8-Feb-18:00 8-Feb-18:15 8-Feb-18:30 8-Feb-18:45 8-Feb-19:00 8-Feb- 19:15 0.884 0.884 0.884 0.884 0.884 0.884 0.884 0.884 43.4 43.4 43.4 43.4 43.4 43.4 )en well on 14/64" ad Increase to 18/64" ad Increase to 20/64" Increase to 22/64" ad Increase to 28/64" ad 8hut-In well Page 1 of 1 DATE: .. July 8, 1998 OPERATOR: PHILLIPS PETROLEUM COMPANY FIELD: North Cook Inlet WELL NAME: NClU B #2 COUNTY: Kenai STATE: Alaska SECTION: 6 TWNSP: 11N RANGE: 9W APl NUMBER: 50-883-20090-01 DISTRIBUTION LIST ARCO Alaska, Inc. Alaska Dept of Natural Resources Alaska O&G Conservation Comm LOGGING DEPTH # OF # OF # OF ROLLED TYPE LOG' DATE SCALE LOGGED ORIG. PRINTS FILMS VELLUM OTHER MATERIALS: Well Summary Report (drilling report) ~ Gas Cons. 0omm!$sion Anchorage Should you have any questions, please contact: Donna Hole Phillips Petroleum Company P.O. Box 1967, Houston, TX 77251-1967 713-669-3722 DATE: May 19, 1998 OPERATOR: PHILLIPS PETROLEUM COMPANY FIELD: North Cook Inlet WELL NAME: NCIU B #2 COUNTY: Kenai STATE: Alaska SECTION: 6 TWNSP: 11N RANGE: 9W APl NUMBER: 50-883-20090-01 DISTRIBUTION LIST Well Records-Bartlesville (;1;) Technical Records-B-2, Bellaire (;1) Well File-Il41, Bellaire (1) ARCO Alaska, Inc. Alaska Dept of Natural Resources Alaska O&G Conservation Comm LOGGING DEPTH # OF # OF # OF ROLLED TYPE LOG DATE SCALE LOGGED ORIG. PRINTS FILMS VELLUM ER ~ MATERIALS: copies - Scan & Manual Well Test Reports (notebook): Sunfish Sand (short string) Production ~_~.~ , Test #1 & 2; North Forelands Sand (Ion~l stdn(.,I), Feb 3-9, 1998 Should you have any-questions, please contact: Donna Hole Phillips Petroleum Company P.O. Box 1967, Houston, TX 77251-1967' 713-669-3722 SCHLUMBERGER WELL SERVICES A DIVISION OF SCHLUMBERGER TECNOLOGY CORPORATION HOUSTON, TEXAS 77251-2175 PLEASE REPLY TO: MAR 2 3 1998 Phillips Petroleum Company 6330 West Loop S., Texas Commerce Bank Buildin~l, P.O. Box 1647 Houston, TX 77401 ATTENTION: Schlumberger Well Services HC01, Box 337 Kenai, AK 99611 Attn: Shelley Ramsey Enclosed are Company Well 8 BL/2 films of the GR/CCL, Run 1, 1/23/98 Phillips Petroleum Company North Cook Inlet Unit "B" No. 2 on: Field North Cook Inlet Additional prints are being sent to: 2-BL prints Alaska Oil & Gas Conservation Corhmission 3001 Porcupine Drive Anchorage, AK 99501 Attn: Blair E. Wondzell County Kenai State Alaska prints prints prints prints prints PLEASE SIGN AND RETURN ONE COPY OF THIS TRANSMITTAL TO THE ADDRESS INDICATED ABOVE. THANK YOU. prints The film is returned to Phillips Petroleum We appreciate the privilege of serving ; c% Received by: Date: Very truly yours, Schlumberger Well Services Rachel Walsh Engineer in Charge SCHLUMBERGER WELL SERVICES A DIVISION OF SCHLUMBERGER TECNOLOGY CORPORATION HOUSTON, TEXAS 77251-2175 MAR 2 3 1998 Phillips Petroleum Company 6330 West Loop S., Texas Commerce Bank Building], P.O. Box 1647 Houston, TX 77401 ATTENTION: PLEASE REPLY TO: Schlumberger Well Services HC01, Box 337 Kenai, AK 99611 Attn: Shelley Ramsey Enclosed are Company Well 8 BL/2 films of the AIT/SDT/CNL-LDT/MSCT, Run 1, 1/4/98 Phillips Petroleum Company North Cook Inlet Unit "B" No. 2 on: Field North Cook Inlet Additional prints are being sent to: "~,laska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 ...' Attn: Blair E. Wondzell_.~-~' prints County Kenai State Alaska prints prints prints prints prints prints PLEASE SIGN AND RETURN ONE COPY OF THIS TRANSMITTAL TO THE ADDRESS INDICATED ABOVE. THANK YOU. The film is returned to Phillips Petroleum We appreciate the privilege of serving you. Received by: Date: Very truly yours, Schlumberger Well Services Rachel Walsh Engineer in Charge SCHLUMBERGER WELL SERVICES A DIVISION OF SCHLUMBERGER TECNOLOGY CORPORATION HOUSTON, TEXAS 77251-2175 1§98 Phillips Petroleum Company 6330 West Loop S., Texas Commerce Bank Building, P.O. Box 1647 Houston, TX 77401 8 BL/2 films Phillips Petroleum Company PLEASE REPLY TO: Schlumberger Well Services HC01, Box 337 Kenai, AK 99611 Attn: Shelley Ramsey North Cook Inlet Unit "B" No. 2 ATTENTION: Enclosed are Company Well of the GR/CCL Perforation Record, Run 1,~ on: Field North Cook Inlet Additional pdntsare being sent to: 2 BE prints Alaska Oil & Gas Conservation Commission 3001. Porcupine Drive Anchorage, AK 99501 Attn: Blair E. WondzCJ--~ prints County Kenai State Alaska prints prints prints prints prints PLEASE SIGN AND RETURN ONE COPY OF THIS TRANSMITTAL TO THE ADDRESS INDICATED ABOVE. THANK YOU. prints The film is returned to Phillips Petroleum We appreciate the privilege of serving you. Received by: Date: Very truly yours, Schlumberger Well Services Rachel Walsh Engineer in Charge Anadrill 1111 East 80th Avenue Anchorage, Alaska 99518-3304 Telephone (907) 349-4511 Main FAX (907) 349-2487 DPC FAX (907) 344-2160 FAX MESSA GE Anadrill- The Geosteer~ng c.-ompany MWD/LWD Directional Drilling The only company with: fully retrievable slim survey/GR · retrievable nuclear source · Measurement atthe bit · sonic while drillin9 Date: Receiving FAX Number: Attention: Company/Department: From: Subject .' comme'~ts: " Laurie, 23 March, 1998 .(9_0 7) 276-7542 Total pages (including this page) 5 Laurie Taylor AOAGCC Neil Ramjit NCIU-B2D These are the actual directional surveys for NCiU-B2. If you have any questions, you can contact me at the telephone #'s on this cover sheet, Neii RECEIVED ~AR 2 5 1998, Gas Cons; C0mmisst0~ Anchorage ii ... I I fill .. iiii . i · _ ~, THERE ARE ANY. QUESTIONS OR PROBLE~fS REGARDi~G THIS FAX, PLEASE C¢)~TACT US AT YOUR CON. VEN[ENCF var 2.0 9 F,*b 96 ............... Anadrill 111lEast 80th Avenue Anchorage. Alaska 995 i 8-3304 (907) 349-451 i (907/349-2487 (fax l State of Alaska Alaska Oil & Gas Conservation committee. Attn: Howard Oldand 3001 Porcupine Drive Anchorage, Alaska 99501 Howard. Enclose are copies of Logs and Surveys for well NCIIJ - B2 drilled by Unocal Rig 428 under contract to Phillips Petroleum on the Tvonek Platform. Phillips have asked that I include the DNR in the distribution of this data. Regards. Craig Brown. Alaska District- Field Service Manager OPERATOR: PETROLEUM COMPANY FIELD: North Cook Inlet WELL NAME: NCIU B #2 CNTY/PRSH/STATE: Kenai, Alaska APl NUMBER: 50-883-20090 SECTION: 6 TWNSP: 11N RANGE: 9W 1cc: Well File 1cc: Bartlesville File 1cc: Tony Kratochvil DISTRIBUTION LIST 1cc: Arco 1cc: Alaska O&G Cons Comm. 1cc: Dept of Nat'l Resources Alaska DEPTH # OF # OF # OF ROLLED DATE DATE TYPE LOG RUN # DATE SCALE LOGGED ORIG. PRINTS FILMS VELLUM REC'D DIST. NOTES MUD LOGS: 'Formation Evaluation Log 2" MD ~ 1/4/98 2" 14537 7 1 1 2/20/98 2/20/98 MWD Integrated Formation Evaluation Log 2" MD~'~ 1/4/98 2" 14537 7 1 1 2/20/98 2/20/98 Drillin~g Data Log DDL 2" M DE 1/4/98 2" 14537 7 I 1 2/20/98 2/20/98 MWD Inegrated Formation Evaluation Log 2" TVD '-/' 1/4/98 2" 13377 7 I I 2/20/98 2/20/98 Formation Evaluation Log 2" TVD '-"' 1/4/98 2" 13377 7 1 1 2/20/98 2/20/98 p:\excel\logins\nciu\NCIU B #2a.xls/dpo 02/20/98 4:07 PM MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: THRU: David Johnst .o~, Chairman ~ Blair Wondzell, P. I. Supervisor ~/~l~/(t FROM' Lou Grimaldi~ SUBJECT: Petroleum Inspector DATE: FILE NO: January 10, 1998 AX9JAIFE.DOC BOP Test, rig #428 Phillips Tyonek platform North Cook Inlet Unit PTD # 97-210 Friday, January 9,1998; I witnessed the weekly BOP test on rig #428 drilling over well #B-2 in the North Cook Inlet Unit. I arrived to find the rig not ready to test. I made a cursory tour of the rig and its surrounding area and found all to be in good shape. I observed the rig crew installing the 7" rams in the upper pipe ram slots. The test, once started went fairly well with all BOPE being tested and no failures observed. The rig crew did an outstanding job testing the BOPE and I found Rick Brumley's (toolpusher) procedure to insure a methodical test of the BOP equipment. The rig was in Good shape and showed evidence of regular maintenance and was situated to allow for easy access. The rig although using oil based mud was very clean and it seemed as the crew was doing a good job of containing the mud to the rig and pit's area SUMMARY: The weekly BOPE test I witnessed on rig # revealed the following; Test h_~.~~3, No Failures. Attachments: AX9JAIFE.XLS CC; Walt Carrico Phillip's drilling manager. NON-CONFIDENTIAL STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: Drlg Contractor: Operator: Well Name: Casing Size: Test: Initial X Wo rkov e r: DATE: 1/9/98 Pool Rig No. 428 PTD# 97-2f0 Rig Ph.# 770-60f3 Phillips Petroleum Rep.: Danny Simington NCIU B-2 Rig Rep.: Rick Brumley Set(~ Location: Sec. 6 T. ¢IN R. 09VV Meridian Seward Weekly X Other Test MISC. INSPECTIONS: Location Gen.: P Housekeeping: P (Gen) PTD On Location P Standing Order Posted P Well Sign P Drl. Rig P Hazard Sec. P · FLOOR SAFETY VALVES: Upper Kelly /IBOP Lower Kelly / IBOP Ball Type Inside BOP Quan. Pressure P/F ~ 250/5, 000 P 250/5,000 P 250/5,000 P 25O/5, OOO P BOP STACK: Annular Preventer Pipe Rams Lower Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve Quan. Test Press. P/F ~ 250/2500 P I 250/5,000 P ~ 250/5,000 P I 250/5,000 P f 250/5,000 P 2 250/5, 000 P f 250/5,000 P N/A 250/5,000 N/A MUD SYSTEM: Visual Alarm Trip Tank P P Pit Level Indicators P P Flow Indicator P P Meth Gas Detector P P - H2S Gas Detector P P · CHOKE MANIFOLD: No. Valves 14 No. Flanges Manual Chokes Hydraulic Chokes 2 Test Pressure P/F 250/5,000 P 32 250/5,000 P f P Functioned Functioned ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure 0 System Pressure Attained Blind Switch Covers: Master: Nitgn. Btl's: Twelve Bottles 3,050 P f , 800 P minutes 2~ sec. minutes 20 sec. P Remote: P 2050 average Psig. Equipment will be made within N/A days. otify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 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 procedure and results. Rig in good shape. Distribution: orig-Well File c - Oper./Rig c - Database c- Trip Rpt File c- Inspector STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Witnessed By: Louis R. Grimaldi FI-021L (Rev.12/94) Ax9jaife.xls PHILLIPS PETROLEUM HOUSTON, TEXAS 77251-1967 BOX 1967 NORTH AMERICA EXPLORATION AND PRODUCTION COMPANY October 20, 1997 BELLAIRE, TEXAS 6330 WEST LOOP SOUTH PHILLIPS BUILDING North Cook Inlet Unit "B" No. 2 (Formerly Sunfish No. 3) PPCo. Tyonek Platform North Cook Inlet Unit, Alaska Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Attn: Mr. Blair Wondzell Gentlemen: Enclosed for your consideration and approval are three copies of Form 10-401 (Application for Permit to Drill). The referenced well will be re-entered, plugged back and sidetracked from the existing casing to test the extent of the Sunfish and North Forelands reservoirs discovered by the ARCO-Phillips Sunfish No. 1 and the PPCo. Sunfish No. 3. Phillips plans to continue the use of the Unocal owned Rig No. 428, which will be operated by the crews of Pool Artic Alaska. In addition to this Application for the Permit to Drill is a request to continue the use of the Cuttings Injection System that was set up on the offset well, NCIU "B" No. 1. The cuttings injection is required to continue use of the oil base mud system that was so successful in the drilling of the NCIU "B" No. 1. Enclosed with the application are the following support documents: 1) Check for $ 100.00 to the State of Alaska, Department of Revenue. 2) A plat showing the referenced property, leaseholds, surface and proposed target and bottom hole locations. 3) The proposed casing and cementing program. 4) Schematic diagrams of the existing wellhead and proposed BOP equipment. 5) Proposed drilling fluid program with supplementary documentation as follows: a) b) c) d) Anticipated Mud Weight / Casing Point Plot Anticipated Surface Pressure Calculations Solids Control Program Schematic Diagrams of Rig 428 and Tyonek Platform Mud Systems. 7) 8) 9) 10) 11) 12) Predicted geo-pressured strata are described in detail in the drilling fluid program and supporting documentation. A copy of the proposed drilling program. The well will be sidetracked from a depth of approximately 11,500' MD (10,400' TVD) and intentionally deviated to reach from the Tyonek Platform to the bottom hole location northwest of the platform as illustrated on the proposed directional plan. Projected Time versus Depth Plot. Hydrogen Sulfide gas has not been encountered in any of the referenced offset wells drilled from or near the Tyonek Platform, nor is it anticipated in the North Cook Inlet Unit B No. 1. It is PPCo's. intent to monitor for the presence of hydrogen sulfide while drilling the entire well. Should H2S be detected, the AOGCC will be notified and contingency equipment installed immediately. The referenced well is scheduled to be spud approximately November 15, 1997, or as close thereafter as possible. AOGCC is requested to keep this application and the attachments confidential. Should you have any questions or require any additional information, please contact Paul R. Dean at (713) 669-3502. Regards, N. P. Omsberg North America Drilling Manager enc: cc: J. W. Konst (w/o enc) W. L. Carrico " J. R. Soybel " P. R. Dean (w/eric) TONY KNOWLE$, GOVEFINOFI ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 November 24, 1997 Paul R. Dean Senior Drilling Engineeer Spec. Phillips Petroleum Company P O Box 1967 Houston, TX 77251-1967 Re: North Cook Inlet Unit B No. 2 Phillips Petroleum Company Permit No. 97-210 Sur Loc: Tyonik Platform, Leg 1, Slot 6, 1249'FNL, 980'FWL, Sec 6, T11N, R9W, SM Btmhole Loc: 623'FSL, 600'FWL, Sec. 31, T12N, R9W, SM Dear Mr. Dean: Enclosed is the approved revised application for permit to drill the above referenced well. The provisions of the original approved permit dated November 14, 1997, are in effect for this revision. David W Ic;hnston Chairman ~ BY ORDER OF THE COMMISSION dlf/Enclosures cc; Department of Fish & Game. Habitat Section W/o encl Department of Environmental Conservation w/o encl ~TATE OF ALASKA ?'i , A', ~ 'A OIL AND GA~ CONSERVATION COMMISSION~/,,q,,U~4 20 ~C 25,~ iiii la. TypeofWork Ddll_._ Reddll_X_ llb. Type ofwell Expiorato~j_X_ Stratigraphic Test~ Oevei°~'~nt Oil__ ......... Re-Entr~ Deepen JService , Develoj~ment Gas Sing[e_ ZOnr.e' ..................... Multiple Zone 2, Name of Operator: 5, Datum Elevation (DF or KB) 10, Field and Pool Phillil~s Petroleum C,.o,. 182 feet Nodh Cool< Inlet Unit Field 3. Address: 3. Property Designation Exploratory 8330 W. Loop Southl Bellalre~ TX 77401 ADL-17589 J 4. Location of well at surface: Tyonek PlatForm Leg 1 Slot 6 7. U'nit or Property Name 11. Type-i~l~d (cEE 1249' FNL & 980' F'WL SEC 6-T 11N,R09W North Cook Inlet Unit "B" Statewide At top of productive interval: ~. Weft Number Number 1110'FSL& 600'FVVL SEC31-T12N-R09W No. 2 4'1-0-524 At total depth: 9. Approximate spud date Amount 823' FSL & 600' FWL SEC 31-T 12N-R0gW 1 t/20/97 $200)000 12.Distance to nearest t 3. D~stance to nearest well 14. No. of acres in property 15, F~r~posed depth (MD and TVD) property line Surface: 8' 9920 approx. 600 feet _N....C_!~..B.-.! ........... 15000 MD, 13750 TVD feet l t~'~;T-~ I~e completed for deviated wells 17, Anticipated pressure (~ ~o ~,~c ~.o~ (k;koffdepth; 81909 tt Maximum here an,clio 43 de~rees ..Maximum surface 7707 psi.q At total depth (TVD) .... 9650 p$ig. Casin~ pro, ram Settir~ DeFth size Specincat!ons Top Bottom Quanti~ of cemen!,,, Hole Casb,,q Wei.qht Grade Couplln.q Length MD TVD MD 'i'VD (include sta~e data~ ...... 'Driven 30" Drive, 3, ,,.68' 55 5,,5 , 407' 40~ EXISTING 24" 20'.' 169 C-70 DHI-Qulp 2~43' ~{S 5~ 2602' 2534'. ............ - .... 'E~(iSTING 17-1/Z' 13-3/8" 72 ~-8,o~P,;,!,,~C ,.B,T&C' ,,.88..4g'~ ..... 55. ............ 5.5 .......... _ .6~__..9'8123' EXI_$_T..I_NG . 12-114" 9-s/8" s3..~ p-~o BT&C 12000' 55 55 12000' 11000' 500 sx Cia .~s...'.'.,G." * Additives 8-1/~' 7" 32 ~ BT&C 3300' 11700' ~0775' 15000' 13732' 700 sx Class "G" * Additive~ ,, . Note: Well to be sidetracked from 13 3/8" casing ~ 8,g09' after cutting ancl pulling g ~/8" casing from 9,200',, 19, To be completed for Reddli, Re-entry, and Deepen Operations. 1) 58 sx below retainer ~ 13,9t6' w 12 sX above. 70 sx x ~- Present well condition summary 2) 50 sx below retainer ~ 13,464' w 8 sx above. 58 sx 3) 58 sx below re{airier ~ 12,375' w 10 sx above. 68 sx ~'~ Total depth: measured 14705' feet Plugs (measured) 4) 68 sx 11,950'. 11,700'. true recital 13286' feet 5) 68 sx 300' - 500'. Effective depth: measured feet Junl~(measured) PaclCer&TCPGuns~ 13,482' and ~ Casing Length Size Cemented Measured depth True VertigaJ depth · Structural 368' 30" Driven 407` 407' ~ ~ NOV 21 199 ' Surface 884~' 13-3/8" Yes 8909' 81Z3' % ] V Intermediate 12080' ~-~,/,~ ~ ?~- Yes t2138' t 1024' ~rod. Lir~ ~-S04' ~"' Ye~ ~4Z t:S~? Alaska0il & Oas Cons. Commission Perforation depth; measured 12478'. 12536' OA: 13894' - 13706' OA ,~nchorago true ~rtical 11325' 12303' NOTE: This amanded Application for Permit is due to the requested change Jn BHL of the target Sunfish Sand interval and to revise the drifting procedure to cut and pull the exlstlng ~ 8/8' casing from below the 13 3/8" shoe, set a sidetrack plug and redrill the hole. ~, Attachments Filing fee ~ Property ptat_X. BOP sketch_X_ Diverter Sketch ~ Drilling program _X_ DfillJn~ fluid pm,qram X Time vs depth plot X Refraction analysis Seabed repo~ ,2o AAC 28.0~0 recluirame,nts (Directional 21, I hereby certify that the foregoing is true and correct to the best of my Imowledge ........ ,Commission U~e Only ' lsae cover letter '" Permit Number FPI Number Approwl Date I 97- 2t0--IS0- 883-20090-01 //_--_/~,~ "' '~,/ lfor other r__ _....eR. uirements CondJtJonsefApprovah Samples required .z~_Yes ~ No Mud Icg required,,~,~Yes- No Hydrogen sulfide measures ~ Yes .Z~ No Directional survey required ~ Yes ~ No Required working pressure for BOPE __ 2M __ 3M __ 5M _.~ 10M -.~ 15M Approved by d (~ ~,l haiti Sj_Re~g J~Y Commissioner the commission Date _ . ] L I Form 10.4Ol Rev, 12-1-85 z' ,~'W. J0hlR~5[Uil [; ct.~;, (J Submit in triplicate PHILLIPS PETROLEUM COMPANY P. O. Box 1967 Houston, Texas 77251-1967 6330 West Loop South Bellaire, Texas 77401 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 At-tn: Mr. Jack Hartz Gentlemen: November 21, 1997 North Cook Inlet Unit B No. 2 PPCo. Tyonek Platform North Cook Inlet Unit, Alaska APl No. 50-883-20090-01 AOGCC Permit No. 97-210 ORiGinAL Enclosed is an amended Form 10-401 (Application for Permit to Drill) and a copy of the proposed drilling program, which includes The property plat, BOP sketch, drilling fluid program, time vs depth plot and directional program. Included is a revised directional drilling proposal that will allow the target zone and the bottom hole location at total depth to be within the boundaries required for a legal location in Section 31-T12N-R09W. To attain the change in the bottom hole target, the casing program is revised to cut and pull the 9 518" casing from 9,200' (just below the intermedia[e shoe @ 8,909', set a cement sidetrack plug and drill directionally to the new target, setting 9 5/8" again at approximately 12,000' MD (11,000' TVD), then drill ahead to Total Depth. Please contact P_R. Dean at (713) 669-3502 should you have any questions or revisions to the proposed change. As discussed, the rig is positioned over the well slot and is preparing to install and test the BOP system. Thank you for your earliest oonsideration. PRD enc (2) Respectfully submitted, Paul R. Dean, Sr. Drilling Engineer;rig Spec. for Phillips Petroleum Co. RECEIVED NOV 2 t 199 Naska 011 & Gas Cons. Commission Anchorage 1'7_/q NOV 06 '~7 10:41 TOTRL P.01 P~6E.01 PHILLIPS PETROLEUM COMPANY NORTH AMERICA E & P O__RILLING OPERATIONS . WELL: North Cook Inlet Unit 'B" No. 2 (Formerly Sunfish No. 3) APl NO. FIELD: LOCATION: 50-883-20090-01 North Cook Inlet Field Surface: BHL 1,249' FNL & 980' FWL Leg No. 1; Slot No. 6 610' FSL & 623' FWL WORKING INTEREST: Phillips Petroleum Co: COUNTY, STATE: Kenai Bo. rough, Alaska Permit No. 97-:210 AREA: Kenai, Alaska Sec. 6-T11N-R09W Sec. 31-T12N-R09W 100.000000 % AFE: BUDGET ITEM: GROSS AUTHORIZATION: p-X121 2A $ 8,029,000 OBJECTIVE: Plug Back and Sidetrack the former Sunfish No. 3 to Test a 15,000' MD (13,73:2' I'VD} Exploration Appraisal Well. DRILLING SUPERINTENDENT_ DRILLING MANAGER DATE /I]e~v.~ [..~_;.!.~.__~ DATE DATE DATE DISTRIBUTION: J. W. KONST N. P. OMSBERG IR) CENTRAL FILES W. L. CARRICO . DEVELOPMENT SUPERVISOR (2) J. R. JACKSON IR) L,D. AIRINGTON L.G. JANSON W, B, VIA M. P. GATES POOL AR. TIC ALASKA - - J, W. SPENCER P. R. DEAN (ORIGINAL) ORIGINAL( ) REVISION (I) TIGHT HOL,.E: YES.( X ~) NO RECEIVED Nov 21 19 )Z Naska 0il & {]as cons~ Commission Anchorage DRILLING PROGRAM SUMMARY Well Name: North C~,~ Inlet Unit B 'No. 2 Field: North (~0k Inlet Unit AFE No. AFE. P-X121 Drill & Test Costs: Surface Location: 1,249' FNL & 980' FWL Sec. 6-T 11N-R09W Bottom Hole Loc. 610' FSL & 623'FWL Sec. 31-T12N-R09W Depth: 15,000' MD 13,732' TVD AFE Days: 73 Rig: Unocal Rig 428 with Pool ArtJc Alaska manpower Type: 2A $ 8,029,000 Leg 1' Slot OBJECTIVE- Plug Back and sidetrack the former Sunfish No. 3 to Test a 15,000' MD (13,732' ']'VD) Appraisal Structure 3000' SouthWest of the Original Exploration Well. CASING PROGRAM: '"' ' ' ' ........ ' '-urst ~lze Depth VVt lb/It Grade Corm MO (-I'VD) ........ -r' 30" 407' Ddve Pipe 20" 2~O~ (2534'} 133 K-55 8T&C 2860 1410 1700 13 3/8" 8909' (81Z3') 72 P-110; N- BT&C 4730 2520 1231 3800 g ~/8" 12000' (11000') 53.50 P-110 BT&C 6970 6250 921 5000 ,, 7" Ijne~ 15000' (1373~'} 32 P-110 BT&C 9960 10170 688 3.5" (Alt) 15000' 12,95 P-110 PH-6 14240 17470 232 8 000 .J ill Il i iiii I i ..... ~ , ,[, PROCEDURE SUMMARY MIRU Unocal Rig Ne. 4;28 over Leg No. 1, Slot No. 6. 2, Install riser and 13 5/8" t0M BOP and Choke Manifold. Test BOP to 5000 psi, Install PVT equip. , 4. 5. 6. Drill out cement plug at 300'- 500'. TIH and wash to 9,500'. Cut casing at 9200', Circulate, pull 9 5/8" casing. Set cement sidetrack plug. Sidetrack well. Take FIT test to 16. Ppg EMW. ~e.¢. II , Drill 1:2 1H" hole section with directional assembly to 12,000' MD. Log intermediate hole section. Run and cement 9 5/8" casing. Sec. Ill Sec,ly 10. 11. 12. 13. 14. Drill an 8 1/2" hole with directional assembly to 15000' MD. Circulate and condition hole for logs. Log well with DIL/GPJDen/Neutron as per Geological Prognosis, Run and c~ment 7" producl~on liner (or 3 1/'2" production monobore tubing ). Clean out production liner to PBTD. Completion testing program will be planned based upon log evaluation. LL! rr NORTH COOK INLET UNIT B No. 2 (SUNFISH PROGNOSED DRILLING CURVE 0 -5 -10 -15 -2O 25 50 75 100 125 150 175 DAYS -~SF 3 ACTUAL -~-SF 3 SIDETRACK ~NCIU B 1 Actual No. 3 SIDETRACK) 11/17/97 200 1. Location DRILLING PROSPECTUS Phillips Petroleum Company's Tyonek Platform located in the North Cook Inlet of Alaska. Drilling will be from Leg No. 1, slot No. 6 ( See attached survey and schematics). 2. Drilling Contract The ddlling contract is a bare boat charter directly from Unocal for the use of the Rig No. 428. Pool Attic Alaska will provide the manpower and rig crews to install and operate the rig. 3. Well Control '9. Well control procedures will be in accordance with Phillips Petroleum Company's Well Control Manual and State of Alaska Oil and Gas Conservation Commission, Govermentai Reporting Notify AOGCC (Blair Wondzell) @ (907) 279-1433 prior to moving rig and prior to spud. Special Considerations This section is intended to clar'rrry and discuss special drilling situations that may occur, Be alert for these potential problems and ready to implement the appropriate contingent actions, Oil Base Mud will be used for the entire sidetrack operation and drilling the new hole interval from 8,909' to total depth of 15,000' (13732' TVD). (Refer to Oil Based Mud Handling Procedures - attached in mud program). All precautions will be taken to insure that no runoff is allowed. Proximity to Other Wells The referenced well will be kicking off from the existing welibore at a depth of 9,035', Thero are no other weilbores within 2,800' ot~ this point, nor are any prognosed to be crossed at the planned trajectory. Shallow Gas There is no reason to expect a shallow gas hazard at the North Cook Inlet "B" No, 2, since the welt has been drilled and cased, All BOP equipment will be installed and tested prior to drilling any cement plugs, COAL SEAMS Stuck pipe due to coal beds has been a frequent occurrence in this and other fields in [he Cook Inlet, mainly when using WBM. Coal generally swells with WBM. These coals will be drilled throughout the well. The use of OBM with the use of the top drive has shown a reduction in the problems associated with coal, The coals may be fractured and have a tendency to cave into the well. A large chunk could result in mechanically sticking the ddllstring, Mud weight and soltex have been used with some success to stabil'~.e the coals, Raise mud weight as needed to control the coal seams. For OBM, gilsonite and/or Soltex should be used to lower HP/HT to 4 cc or less, 11. The penetration rate in the coals will be high. With the experience in the past well on drilling the coals with the oil base mud system, increased penetration rates can be beneficial. Using the driller's experience and the geologists input on mapping the coals, the hole can be drilled with minimal problems. In the event the pipe does become stuck, spoffing fluids have been successful in some cases in freeing the pipe where the mud was water based. The use of oil based mud should help in this regard. DIFFERENTIAL :STICKING There are several sands in the 8 1/2" hole section that are expected to be normally pressured and somewhat permeable, if mud weight has been raised t~ stabilize the coal seams then these sands will present a risk for differential ~cking. To minimize this, keep the pipe moving as much as possible and minimize stabilized spiral HWDP and spiral DC's in OBM. Use lost circulation additives such as Barafiber or Steel Seal to reduce seepage losses and to minimize the risk of differential sticking. 12. HIGH BACKGROUND GAS The formaticms that will be drilled are .gas saturated coal, sand, and silt. This will result in unusually high back,ground gas readings. Mud weight should not be increased to suppress the high background gas. RECEIVED 011 & Cae Cons. Commission Anchorage North Cook Inlet Unit N.C.I. Un. N. C.I. Un. N.C,I, Un. A-I* N,CJ, Leg ,3 N.C.I, Un. · / ; N.C~I. Un.A-2 · PHilLIPS PETROLEUM COMPANY .t_ ..... ' -~ ii __ _ _ NORTH COOK INLET TYON~K. PLATFORM .... ~0~ U~in~ PLATFORM NO~TN, Slol No.~ will ~ ~ht furthest D[atform N~rf~ alot In p~tf~m North- welt quodront of ~ny leg; Slot~ are nu~ered I th~ ~ In ~ ~ounter-cl~c~-w[ae d~reclion. N .L A, NYdlAIOD IAll'1390J::ll::ld Sdrl'llHd T M61:1 mm mmmmmmm mm mm~ mm' mmm mmmm -- L'I;'/_BL- 9 C]¥ · dSH · i ~ ~ Sdr191Hd j \ · anffi-Ha - 'lC]'g' ! ~BH J I, ?'~ 0L6BE:-'iC]'¢ Sd~l-llHd ! c~_ ,c'_ o 06SL ./ 6BS£L-9CI¥ I dBH Sd1991Hd I ODkl¥ I M01.11 - --d~H - EBOt, LE- '1C]¥ B6-LE-E Sdlq-liHd 'Ogl:J~ Ot~/..BL- 9a'v dBH Sdi'i'ilHd · mm mm __ Imm __ I I 9g01;,£~- 9(3¥ IB6- L~:- I~ ! SdlTIlHd Ogkl¥ I ARCO PHILLIPS 3- 31-98 ~DL-374056 3 -31 -98 ADL-374081 ARCO, PHILLIPS 3 -31 -98 ADL-369101 ___ ARCO PHi_4LIPS HBP ADL-37831 ADL- 7590 PHILLfPS HBP ADL-18740 R10W i AnCO i PHiLLiPS , PHILLIPS ' HBP '~ '"'"~ ~ --I HBP ADL-17589 ~' · ADL-18741 i __ .._m,mm--~ m m m ~m,l,m~ 4- - .L mm m m mm llli..,Jmmm m m m I RgW mlm,i i T 1 1 N PHILLIPS PETROLEUM · -- ---. ._ i -i' ii COMPANY COOK INLET BASIN .RECEIVED OIL & GAS LEASE OWNERSHIP MAP .!'~.C)V 21 199Z , ~. ~ "= = Naska0tl & Gas Cons. Commission S. CAI. t= {F~ET_4 ....... _ ,, .' ~m~,hm~.~m , __ I 6 I~- 7 U[G Ng. i LAT. 61~ 04' 36.38" LONG,150° 56' 55.63" X=. 331~995 FROM N.W, CO.R.' ~ZSO' SOUTH ~ ~75~ EAST, SCALE LEG N°-. 4, LEa N-g LAT, $1e 04' 36,e9" LAT, 61° 04' 35.83" LDN~ fSOA 55' 54,e5" LONG. 15~ ~Z~86~781 Y= 2~6,674 - - ' ~OM N,W. C~ FROM N.W,~R. hmga' ~UTH 8 ~j ~O~H 8 - 1,0~3' EAST. ' :1,018' · · · · . · ,. . ; . NOTE: Ph3! (]menOed 7 AUG.$8' ,fo show · revised te,g ri.umbering. -. · . I hereby certify that I am properly registered clnd licensed to practice land survo~ihg in ~e State of A la6ka 'and , that this plat represents ~ location sumy made by me orotherUnderdetailsmY areSUpe~visi°ncorrect, o~d that alt dimensions and NOTE The location of the platform legs w~s occomplishe~ by using triangulation stations BELUGA,TERRACE,and TYONEK wh{ch are all U.S.C. S G.S. stations. A{I coordinates are Alaska State Plane, Zone 4, NORTH COOK i NIn, ETUNIT PLATFORM PROCEDURE FOR DETERMINING MAXIMUM DOWNHOLE PRESSURE AND MAXI~ POTENTIAL SURFACE PRESSURE Maximum Downhole Pressure is determined from the pore pressure predictions of the interval to be drilled below the subject casing. The pore pressure predictions were made from offset well data and the seismic data. The maximum potential surface pressure is determined to be the lesser of the fracture pressure of the formation at the subject casing shoe less a fluid gradient to surface or the bottomhole pressure of. the intervals to be drilled less the gradient of the fluid produced from the formation. Drilling Below 13 3/8" Intermediate: Casing point @ 11,000' TVD (12,000 MD) Frac Pressure = 15.0 lb/gal from MW / Casing Point Chart @ $,909 (8'125' TVD) Max MW to Drill with = 12.0 lb/gal. BHP = MW * 0.052 * Depth Frac PSI @ Shoe = 15.0 lb/gal * 0.052 * 8125 BHP from Mud Weight 12.0 lb/gal * 0.052 * 8125 Max Surface PSI before Formation breaks down is Gas Gradimnt Alternative = 5070 psi2 \ ~ 1268 psi ~~ BHP ' 12 lb/gal * 0.052 * 11,000' TVD - 6864 psi Maximum Potential surface Pressure is determined based on the pressure that would result from BHP less a gas gradient back to surface. The mud weight will be at least 0.5 ~~_igher than the pore pressure gradient. ~CEIVED MPSP = BHP - (gas gradient)(TVO) NOV ~$, Drilling Below 9 5/8" Intermediate: Frac Pressure = 16.4 lb/gal from MW / Casing Point Chart @ 11,000 TVD Max MW to Drill with = 14.5 lb/gal. BHP = MW * 0.052 * Depth Frac PSI @ Shoe = 16.4 lb/gal * 0.052 * 11000 = 9380 ps BHP from Mud Weight 14.5 lb/gal * 0.052 * 11000 = 8294 Max Surface PSI before Formation breaks down is 1286 ~a~ ~radiant Alternative BHP ~ 9700 psi from DST of N. Forelands No. 1 Max MW = PP / 0.052 / Dd 9700 / 0.052 / 13282 Max MW ~ 14.0 lb/gal Maximum Potential Surface Pressure is determined based on the pressure that would result from BHP less a gas gradient back to surface. The mud weight will be at least 0.5 ppg higher than the pore pressure gradient. M~SP -- B~P - (gas gradient)(TVD) MPSP = 9700 - (0.15 psi/ft)(13282') --~ ~ NORTH COOK INLET UNIT "B" No. 2 (Sidetrack of SF3) MUD WEIGHT / CASING POINT / PRESSURE PLOT (TVB) Mud weight(ppg) ~PROPOSED ~-NCIU B 1 m --Sed~ 5 ~LEAK-OFFTEST -- -- =~ m --S'Fish 2 --S'Fish 3 .¢ MD Kill Li~e 13 ~. SM Aanuta¢ Preven~r Fill-up L~e 13 ~8" 5M x 1:3 ~$f&" 10M Adapter 13 5~8" 10M Pipe of Variable Lore Pipe Ram~ 13 ,~/~" 10M Blind Rams 13 6~a" t0M Drilling Spo~l Choke Line Pipe Rams I 13 $/8" 1OM · ~$ $/8 '* I~M R~er 13 ~1" 10M $pa¢¢~' Speol$ (If Required) 13S/8' 10M x 11" ¶OM DSA Adapter Flange 13,5/8" SM x 11" 10M TubingHead I 13 5/8" SM x 20 3/4" SM Gasing Spool FMC ,,,,, - ) 4~ska Oil & ~a~ Cons, C0n~rnj~ anoho,.ge i o~ No~ C~k tfllel Unit"B" No, 2 (Formerly Sunfish ~o. ~) I 20 3~4' :~M x 20" SOW Casing Head (FMC) RECEIVE f, Cook Inlet Sar Upper Beluga Lower Beluga Tyonek ~$v ~ 12375' Packer & TCP Guns 'C'Sand ~2478-12502 .12528.12536 EZSV @ 13464' Halco 8WD (~ 13482 13S94-13644 ; t3056,1370~ EZ~V@ 13~1~' 7" (~ 13.939' I::XISTIN(5 f,;A,'~IN~ & ~l-r-~.Ni IJIA~I,(~IVl ,B?.,V, .(~4a. ke,Ty pc. OD) Not Apl;licablc TblI. IlRr.(~,ke,TvF) Not Applicable ,~.,.au, mula; ' ,~.~zb/~,~,! m.a ~.....~., ~m_~' "' I~''~'~L-: ~.~ J0" ~[ '.071 ~STl~. I W. ld,d '1 .... 20" [ Sgl '" 2.6'~' '169. Ib/t~ I X-56 I Dril'Q-ui-~.l 13 3/8" [ 591 8,909 ?2.0 lb/fi, IN-80;P-li0[ BT~ I 4730{ 25201 76[ P~u~ ~ner; 7" [ . .l~S~l_ ~3,~4~ 3~lb/gI ~-~0 )r e~d~-"J ~eoJ__~.~ ~2~ CEMENTING SUMMARY 20" Coati, tier 11/25193 C~mented with 1070 ~x 17_1t lb/gal Class "G" with 0.25 gaVsx D-TT, 0.05 gaV~ ~7 and 0.28 gaV~ D-7~. ~i]~d wi~ 600 ~x CI~ "G" mlx~d ~ 15.8 I~ga[ wi~ 0.~ 8aVsx DO7 ~d 0.05 gaV~ D~7. Comet Cimulntcd to Su~a~. 13 3/8" latSta~ 12/1 Cemented with 900 m 12,5 Ib/g~l Cl~s "G" with 1.0 % plus 0,05 gal/.~ D-47 Tailed w;~ ~00 ~ CI~ "G" ~ lis lb/D,I 0.05 gnV~ D~7, 0,5% D.59, 0.15 g~V~ D-~01, 0.4% ~5.0.10% D-134, and 0.25% ~t. 2nd S~c Ccmcnt~l with 3700 sx 15,8 lb/gal Cl~s "O" with 0. t0 % D-65, DV tool ~ 73Bg 0,1 ~V~ ~?, 0.1% ~135,1.0 8aU~ D~0, ~d 0.3~ ~800 3rd$~8, C~ wi~1000~lS.g~/gal CI~"O"wi~0-~% D~5, pI~ ....... ~toot ~ 40~' o,I ~gm D-4?, O, 1% ~I3~, 1,0 ~V~ ~o. ~d 0.3% ~1. 9 ~/8" '-"~l~ wi~ 1000 ~ 13,8 lbl~l CI~ "O" w~ 0.1 gnV~ ~135, 01/16/~ 0, I gaI/~ ~47, 0.01 8aV~-% ~0g0, 1.0 ~V~ ~00, ~ 0,06 ~tim~cd TOC at [ 1.000' 7" Ccment~ with 674 sx I~,8 lb/gM CI~ "O" with 0.1 gal/sx D,47. plus I,:~ g~t/~ I~00, 0.1 8aV~.'% D-135, 0.07 gal/ax D-g, ~nd 0,03 gnl/.~x D-SOL. ABANDONMENT PLUGS 03/09/9a 7" 03/21t/94 7" 03/31/94 7" 03131/94 7" & 9 5/$' 04/0 !/94 9 5/8" $¢t EZSV Cement R~tain~r at 13,916'. Cem~md with 70 s~ Cla~s "O" Pm'np~ ~ 8 s,~ belcew ~taince, 12 sx o~ top of r~tainor, S~ EZSV Crm~at Retainer at 13,464'. Ccmcnt,d with 58 ~ Class "G" pumped 50 ~c b~low retainer, 8 sx (30"Jan top o£re~in~t, S~ EZSV C~mcnt Retainer' at 12,375'. Cem~ted wkh 6S ~x Cla~s "G" Pu~p~l 5g sx b~low r~tain~', t0 ex (I00~)on top of reUsing*. Spot 6g ~,x Clag "G" Cement pIu$ 11,950' - 11,700'. Spot 6S ,x Class "O" Cement plug 300' · 500'. Sunfish No, 5 ~va~ Tcmporarily Abandoned A0dl I. 1994. RECEIVED Ata,,l~ Oil & Oas Cons. '."., ~s to~mm-s~ Anchorage PBTD: Well: Locatlon: North Cook lnl¢l Unit "B" No, Z (fome~ $unfi~ No, ~ O~tob~ [ ~, 1997 ~onck Pla/fom~ Cook Inlet, AIm~ Ficl& No~h Cook Inlet ,,, P~ TD 14,705' Cook inlet Sands Upper Beluga DIAGRAM I I 3o- I Com~. [ Butut C~imz :Rrings: PPC~ Allowable Ratin 5~']' 2.~2~ 169. 16/fl[ .... X-56 ~ ~uip 2~6(){ 14XO[ 59,00 132,00 130. 17oo Lower I~luga 13 3/8v ~ 890'3' To~ of 9 5/8' stub @ 92o0' Tyonel~ EZ~V~12375' Packer & TCP Guns "C' ' ~ 247~. 12502 EZS'V~13464' Hal~o BWD ~[ 134a2' ,~un/l~h ~and ;135~4-13644 7' ~ 13,g3~ Upd_a~..d 1111 7/97 Production Liner= ?' ._1 ]xT°°l 13:oooI a:z~b/~ t,-xo CEMENTING SUMMARY [ I Conductor [ b'25/93 1070 ~ 12,$ Ib/.~ O.23.gaJ/~x 0,05 gaVs~ D-47 3~t 0.28 gai/~ I~75, t.~led with 600 ax i 2nd~zag.=. Ccm=nted wi~,3700sxlS.~,!,b/~t Cl~"G"wilh0,10% D..65, pI~ DV Too~ ~c~ 738~~ o. t_~.yr~ r~?, o. x~ v. t3s, 3rd ~ta~,,= Cemented with ~,0o~ ~-~ 1;5.$ [b/~[al Class "G" wi~ 0.20 % D-65, DV tool~ 404~' 0.1 g=I,'~ D.47, 0A% D-135, [.0 gaF.~ 0,600, 01/16J9a 10o0~ 15.8 lb/gal o 0,1 I~V~x D~7, 0.0! g,~'s~% D-0S0, 1.0 ga~/~x D-600, and 0.06 gal/~x D-g01. ~l[malcd TOC at I 7" Cemented with 67s ~ l$.g Ib~.~? CAms "G" with 0.1 $al/~ D-~7, plus 1,$ eal/~ D-600, 0. t .~X~ D-l?,r 0,07 faVa~ D-ST and 0.03 ~at/sx D-~Ol. Propose to: Cat 9 $/8' casing at 9200' and pull same, Set 300 sx cement sidotrack plug. drill out from 1~ 3/8' caSing and sidetrack th~ well to a n~w bottom hole location. Casing po/nt for the ~ ~/8' will be approximately 12,000' MO (11.000 TVD). The 9 5/6"' w~l be cemeMe~ for approximately 1000' above ~ shoo (400 sx Ciasa ,an 8 1/2' hole will be drilled fro~ 12,000' MD to a TD of 'lS,00ff, with a 7" liner set and cemerqed frern TD to $00' inside ~e 9 5/8" It is then proposed to DST ~he North Forelands Sand and the Sunfisl~ PBTD: Location: North Cook Inlet Unit "B" Ho. 2 ([ormer~ Sunfish bio, 3} ~ov~nbec 17, i997 Ty.onek Platform, G00R [hill Alaska ~old.' .North COOR Inlet PPJ~ DRILLING PROCEDURE SECTION I' CUT AND PULL THE EXISTING 9 Si8" CASING - DEPTH 12,000' MD (11,000' TVD-RKB). A. GENEI~L.REMARKS -__P_~EPARE WELL FOP,_$10ET. RACK,.O. pF-:RAT_!ONS 1, ~rjtent- Clean out 9 5/8" intermediate casing and cement plugs to proposed cut-off point at 9,200'. Cut casing at 9,200' and pull same. Install cement sidetrack plug 9200' - 8850'. Pressure test casing to 2000 psi. Drill out cement plug and sidetrack well, Take LOT test to 15,5 lb/gal. Change out water base mud system to oil based system. Drill ahead to § 5/8" casing point at 12,000 MD (11,000' TVD). 2. _W..ellhea~ Proqmm- FMC 13 5/8" SM × 11" 10M Tubing Head is installed. Remove d~y hole flange and tubing head, Instal[ 13 ~/8" laM BOP and riser system with 1 3 $/8" 5M x 13 $/8" laM adapter spOOl as necessary. 3. ~OPE Re(3uirements and Test ]P_r__e~sur_es 13 5/8" 10M BOPE will be u1~ized. Test pressures are as follow~; Initial Installation Weekly Rams: 5000 psi 2500 psi Annular; 3500 psi 2500 psi Casing Pres.s, gre Test ~, I=eak-(~ff Test Pressure test 13 3/8" c,~ng to 2000 psi after installing sidetrack cement plug, AY(er sidetrack is obtained, perform a Leak-Off Test as per the PPCo. Well Control Manual, Contact Drilling Superintendent if leak-off occurs before 15,0 ppg EMW, Special Dtillin~ l.n.s.tr_u.ctions A, Insure the following equipment is in place and fully operable pdor to beginning drilling operations; a. Pit level monitor with audio and visual warning system. b. Mud return indicator, c, Gas detector with audio and visual warning system. d. Mud volume measuring device (trip tank, otc). e, Both mud systems are tied together and shut down detectors are fully functional and operating. B. Utilize 5" drill pipe, 6 1/2" or 8" DC and 6 5/8" HWDP as necessary, TIH and drill out cement plug at 300'-500'. Continue in hole to 9500'. Circulate and condition mud at 9,500', prior to POOH for cuffing equipment. - · C. UtiliZe Baker Multi-String Cutter, TIH with tools to 9200', Lock brake in place, begin rotation of approximately 80-120 rpm, Increase pump pressure to 600-800 psi to engage knives. D. After casing is cut, POOH with cutting tools. Pick up 9 5/8" casing spear with packoff and engage casing stub~ Attempt to establish circulation after the cut, working the pipe to ascertain pipe is free, Pull 9 5/8" casing. NOTE: If unable to pull casing from below 13 3/8" shoe, a Weatherford whipstock will be used and a window milled in the 13 3/8" casing above the 9 5/8" casing stub. E~ TIH wffh 3 1/2" tubing stinger on drill pipe. Spot balanced cement sidetrack plug from 9200' - 8850'. Cement slurry to be as follows: Slurry : Slurry Weight Mix Water - Type Pumping Time Desired TOC Compressive StrengTh 300 sx Halliburton Premium Class "G" + 0.2.0 % CFR + 0.08 % HR-B 17.0 PPG 3.78 gal/sk. Fresh 3-4 hours 8850' 2~ Hours - ;2140 psi. F. TIH with directional drilling assembly (described in Section II), drill out cement plug and sidetrack wellbore. Take FIT test to 15 lb/gal, Install a wear bushing before drilling (after pulling g 5/8" casing) to prevent wear in the casing head. RECEIVED 0il & l~as Con. Cor~rn~lon Anchorage SECTION I1: 12 1/4" HOLE ( 9 5/8" CASING) - DEPTH 11,000' TVD (12,000' MD) RKB A. GENERAL REMARKS After removing existing 9 5/8" casing and obtaining a sidetrack of the existing wellbore, the well will be drilled ahead with a 12 1/4" bit to the 9 5/8" casing point. 1, Intent- Drill a 12. 1/4" hole to 12,OOO' MD-RKB ( I 1,000' TV[:)) , dropping angle and changing direction as per the directional plan to casing point. Log well as per geological prognosis, then set and cement g 5/8" casing. Wellhead Progra_.m_.- Casing Spool FMC 13 5/8" 5M x 20 1/4" 3M currently installed. Casing Head FMC :Z0 1/4" 3M x 20' SOW currently installed. 4, BOPE Re~_uirements a__n_d Test Pressures 13 5/8" 10M BOPE will be used, Test pressures are as follows: initial Installation Rams: §000 psi Annular: 3500 psi Cosine Preesure Teat.& Leak-off._T_e_st Weekly 2500 psi 2500 psi Pressure test 13 3/8" casing to 2000 psi. GIH with BHA. Drill out the cement plug and sidetrack the well. Perform a Leak-Off Test as per the PPCo. Well Control Manual. Contact Drilling Superintendent if leak-off occurs before 15.0 ppg EMW. 6. S_oecial Drilli n g.._l_n__str__u c ti OhS A. Install a wear bushing before drilling to prevent wear in the casing head. R. Drill out cement at 13 3/8" shoe and obtain sidetrack of well off the Iow side of the hole, using the Hycalog "Steering Wheel' PDC bit, motor and drilling assembly. Use minimum surface RPM while drilling out to obtain the sidetrack. ~ 7 I,l.o' ~"t, Displace mud system to oil base prior to drilling cement. Mud weight will be at 1 ~- lb/gal for the entire interval. D. l~ackream newly drilled hole on trips. E. The casing point is selected based on placing the Middle Ground Shoals sections'of The hole behind casing. B. DRILLING DETAIL,~.{12 1/4" HQL_E_T__O 11.000' TVD {1.2,000' MD-RKB) 1. 12 1/4" B/t, 9 5/8" Steerable Tandem XP Type Motor with 0.78- 1.15 degree AKO and 12 1/8" sleeve stab.; 11 3/4" upper stab., 8" pony DC, MWD, 2 -8" Non-Mag DC's, XO, 25 its 6 5/8" HWDP, Jars, 5 its. HWDP, DP. All BHA changes will be discussed and agreed with Houston office. 2. Bits. WOB. RP_M - PDC 20-45M, 60-150 For motor drilling, drill with 50-70% differential on motor; surface RPM should be run where torque is smooth (60- 110). . Hydraulics- Maintain adequate circulation rate to clean hole. Recommended Range: 750~1000 GPM Start with 6" liners. Run maximum flowrate limited by PDM and 80% liner pressure limitation. Switch To 5-1/2" when pump rate drops below 780 GPM. 4. .M__ud..Pr0gram Oil Based System Ratio .............. Fluid Loss 8,100' 11,000'- 112.$ 15.0 180/,~0 I- 35-~0 [15-;[O 13-6 tOilBase (9,O00-12,000' MD) 85/15 ............ lnvermul Obtain sidetrack with existing 14 lb/gal mud system, This mud weight is not required for pore pressure, but w. il[ assist in holding [he coal seams, Non progressive gels important. THESE ARE APPROX RHEOLOGICAL VALUES, and WILL VARY DEPENDING ON OWR & TYPE OF SUSP AGENTS. Survey Reouirements and Deviation Restrictions A, MWD Surveys: B. Deviation' Run one survey every 30' to insure well is tracking proposed wellpath. Once path is predictable, survey frequency may be increased to every 90'. Maximum 2. degrees per 100'. Samolino. Mud Loq.oJo[z.& El~ctdc Loqs Mud loggers On at 9,000', 30' samples, washed and dried (4 sets). Electric logging program: IND/Sonic/GR; Neu/Density/GR; RFT and Sidewall Cores Possible. Use Anadrill MWD/CDR Tool for GR and Resistivity logging while drilling. RECEIVED l;' o v 2 A]a~P,a 011 & O~s Cons. C~rnr~iss/on Anchorage C. _CASING AND C_EMENTING DETAILS, ,[9 5/8" CASING) AT 12;_O_O_0__MD { 11 ._000 TVD-RKB} 1. Casing Speci6cat{ons: (ToD to Bottom) PPCo Pw Torque ,. Depth, D,,..escription .... Burst Coil ........ Ten Opt ff,-!b fl/1 Driftt Surface - 12,000 9 5/8" 53,5 lb 8920 7480 1159 to triangle 8.53 ' MD P-110 BTC Note: Air weight for this casing string is 642,000 lbs. Float Shoe ' Float Collar & Loc ' W'ford Model 323 (PDC drillable). W'ford Model 402 Sure Seal - 1 joint above shoe, Centralizers : Connection Lock '. Cementing Plugs : Circ, Mix, Displace Rate : W'ford 1-7' above shoe; next 2 collars; every second collar for 1000'. Thread lock all connections on float shoe thru top of float collar. TOp Plug Only Maximum practical . Spacer : 50 bbls of Diesel / 50 bbl of HiVis FW (Flozan and barite) FV = 150. Mix at actual mud weight. Actual volume TBA Lead Cement Slurry Slurry Weight Mix Water - Type Pumping Time Desired TOC Compressive Strength Calc 375 sx Halliburton Premium + 0.20 % CFR-3 + 0.13 gal/ax Hatad 344L + 0.13 % HR-5 15.8 PPG 4.87 gal/sk. Fresh 3-4 hours 11000' (use 20% excess in open hole interval) 24 Hours - 2140 psi. NOTE: ACTUAL CEMENT TO BE USED MUST BE LAB TESTED PRIOR TO SENDING SAME TO THE LOCATION. SPECIAL INSTRUCTIONS A. Notify the AOGCC a minimum of 24 hours prior to the casing job, B. It is important that hole is not surged while running casing. The casing running speed shoul~ be 1 minute - per joint, or less. C, Run casing utilizing Weatherf0rd's fiilup tool. Circulate one annular volume prior to cementing, if losses are experienced, immediately s~art cementing. Cement casing. D, Use recommended spacer, Displace with OBM, Check slurry density with pressurized mud scales throughout the job. Catch samples of slurry and dry cement periodically while mixing, Displace cement with OBM, Bump plug with 500 psi over the final displacing pressure, £. Complete PPCO Casing and Cementing Report and send to the Houston Office. Section II1:8 112" Hole (7" Casing} to 13,732'TVD 15,000' MD-RKB A, .GENERAL_R_ EMARKS 1. Drill an 8 I/:Z' hole from 12,000' MD through the Sunfish end North Forelands Sands to 13,732' TVD (15,000' MD). Log well as per the Geological Prognosis, with revisions possible from Drilling Manager. If productive intervals are indicated, set and cement a 7" production liner. 2. Litholo~¥ and ~o_ti_c_iD_ated Problems Continuation office sand and shale with interbedded coal seanls is prognosed. There is a pressure transition that occurs ~ghtty below the Sunf~h Sands at +_. 12,000' TVD, +_ 14,300' MD,. Pore pressures may increase from 9.8 ppg to about 13.2 ppg during this transition. This abnormal pressure trend is expected to continue to TD, Actual mud weights could be as high as 14.5 ppg. 3. Wellhead Pro,tram Install the FMC 13 518" SM x 11" 10M Tubing Head after cementing the previous, casing stdng. Install 1 3 5/8" 1 OM BOP and riser system with adapter spools as necessary, 8__O_P_ E Re~ ui re m e D.ts. ~ nd Te,~ t Pr e 13 .6/8" 10 M BOPE is required, Test pressures are as follows: Initial Insta{iadon Rams: 7900 psi Annular: 3500 psi Casino Pres_%u.r_e_Test & Leak-off Test Weekly .~000 psi 2500 psi Perform a Formation Integrity Test as per well control manual to an EMW of 1 §-0 ppg. (anticipated L/0 = 16,5 ppg EMW), Maximum anticipated mud weight in this hole section will be 14.5 ppg. Consider squeezing the shoe if the leakoff is less than 15.0 ppg EMW. Contact Drilling Superintenden[ if FIT leak- off occurs before 1§.§ ppg EMW, Directip..o_ai Drilling Instrucl~ons- Follow directional drilling program. RIH w/8 1/2" PDC bit, steerable motor and BHA, including MWD. Drill the 8 1/'2" hole, following directional plan, from 12,000' MD to Total Depth of 15,000'. VV'rth the steerable motor, slide and rotate to attain the directional targets.. NOTE; BHA adjustments must be discussed with the Houston Office personnel. This directional plan is based on a maximum azimuth change of 2,5°/100 ft, Dog leg severity in excess of 5°/~ 00 It could cause both drillpipe fatigue and excessive torque and drag. To minimize the potential for these problems THE DOG LEG SEVERITY CAN NOT BE PERMITTED TO EXCEED 3°/100 FT. Take MWD surveys everY 30' throughout Build and until reactions are predictable. ! ~0ecial. D~illin~ Instructions Ao C. Install a wear bushing before drilling to. prevent wear in the casing head. Drill ahead with motor and steerable assembly, maintaining angle and direction ~o the targets, To prevent differential sticking, keep pipe moving as much as possible, especially while making connections, Drilling Jars should be used in this sec~{0n of the hole. At TD, circulate hole clean, C&CM for logging. RECEIVED B. DRILLING DETAILS { 8 112" HOLE TO 1_5,000 MD-RKB} 1, _B_0ttom Hole Assembly (Steerable Drilling Assembly) 8 1/2" PDC bit, Anadrill 6 3/4" 6 stage extended length performance motor, float sub, MWD/LWD equip., 2- 6 3/4" NMDC, :~5 its- 5 ' HWDP, Drlg. Jars, E; its. HWDP, Drill Pipe. BHA to be discussed and agreed with Houston office. 2. Bits. WOB. RPM IADC Bit Code: PDC Tvoe WOB'- 10 - 20 M RPM: 60 -150 Jets; 20-20-20-20 Hycalog DSS6 or DST.6 [or similar). As required for smooth drilling (drill on motor differential) 3. Hydraulics Maintain flowrate at 450 - 600 GPM. Maintain stable pump pressure.- 3600. 4000 psi (with motor}. Maintain good mud properties. Yield point should be as iow as possible lo keep the ECD as low as possible. Mud Program I I It Depth TVD ] Weight PPG I Oil/Wtr I~ YP HPHT Mud Type , J J I_Rati° Fluid Loss 11,000'-13,732' i12.6 -1B.O 180120 135~40 115-20 13-6 IOilBase ( 12,000 - 15,000' MD) 8E~/15 . Invermul Continue program from previous section. Mud weight will need to be brought up to 14.0 prior to drilling the North Forelands Sands. Non progressive gels important. THESE ARE APPROX RHEOLOGICAL VALUES, and WILL VARY DEPENDING ON OWR & TYPE OF SUSP AGENTS, ~urve..v Reauir_ements..and Deviation Re__s~r. ictiops A, Continue with directional plan, using MWD surveys for directional control, 6. Sam.Dlin_o. Mud Logging. and.FJ.e.ctric Logs A. Mud logging to continue from 12,000' MD to lB,000' MD, B, Fax reports every morning to (7131 669-3754 by 5:30 (ADT) and follow with phone report at 06:00 a.m. Openhole logs from 11,000'-TVD (12,000' MD) to 13,732' TVD (15,000' MD): Array Induction / Sonic with GR; Compensated Neutron / Uthe-Density with GR and Caliper; RFT 'T'ools, Possible sidewall cores. Circulate and condition hole for logs. NOTE: See Attached Geological Prognosis 7. Corir~ A. No cores will be taken_ Environmental A. Do not spill any Oil Mud. Insure that no mud escapes from platform area. If any accidents occur advise Houston Office Immediately. B, An SPCC plan is required on rig at all times. CASING AND CEMENTING DETAILS {7" CASING) AT 13,732 TVD (15,000 MD*RKB) 1. casing specifications: (Top to Bottom} TVD PPCo Pw Torque Depth Description Burs~ ~.1 T~ ........... .~p= ~- Drift 11,700 - 7" 32 lb/fl 10170 10150 685 6.0" 15,000' MD E-110 BT&C Note: Air weight for this casing (liner) string is 173,000 lbs. Float Shoe : Float Collar : Landing Collar & Loc Centralizers · Connection Lock · Cementing Plugs : Circ, Mix, Displace Rate : W'ford Model 323 IPD¢ drillable). W'ford Model 402 Sure Seal - I joint above shoe. Baker Type Ii - I joint above float collar, W'ford 1-7' above shoe; next 2 joints w/collar stops; every second col[er to 14,000'.; Every third joint to 11,500'. Use turbulator type (2 per joint) across N_ Forelands and Sunfish pay intervals, Do Not Thread Lock Float Equipment, in the event liner does not reach bottom and has to be retrieved, Drill pipe and Liner Wiper Plugs only Maximum practical Spacer · 10 bbls of Diesel/ 10 bbls HiVis FW (Flozan and barite) FV = 150, Mix at 14,5 ppg (actual mud weight)- Actual volume TBA First Stage Cml Slurry Slurry Weight Mix Water - Type Pumping Time Desired TOC Compressive Strength Cain 875 sx HalIiburton Premium ~- 0,?_0 % CFR-3 + 0.13 gal/ax Halad 344L + 0,13 % HR-5 16.8 PPG 4.87 gal/ak. Fresh 3-4 hours 11,200' (use t0% excess in open h01e interval) 24 Hours - 2.140 psi, NOTE: ACTUAL CEMENT TO BE USED MUST BE LAB TESTED PRIOR TO SENDING SAME TO THE LOCATION. SPECIAL LINER CEMENTING INSTRUCTIONS A. Check to verify that all equipment required is in place end inspected for operation. Drill pipe must be rabbit-ted to 3" ID on last trip out of the hole. Have the following equipment made up and ready prior to the liner leaving the cased hole: A) 10' - 15' drill pipe pup joints, B) TD (Top Drive) Swivel with Totco baffle plate installed in box and Halliburton valve 1 chicksan swivel made up on circulating port in closed position, C) TD plug dropping head with drill pipe dart installed, D) Flag sub E) Run liner on drill pipe only. Use DP for required set down weight to set packer. Make up above assembly with Ti3 unit to 20-2.2. K torque, then lay on pipe rack for quick access. B. Notify the AOGCC a minimum of 24 hours prior to the casing job. C. D. G, Ho J, K, L, N. O, Do Not Baker Lock the W'ford Float Shoe and Float Collar on the first joint of casing, Install the Baker Landing COllar I ball catcher sub on the top of the 2nd joint. Do Not Baker Look the Landing Collar. Make up third joint, then fill the casing with mud and pick up ,tO - 60' to operate the float valves. The fluid should fall, but not refill as pipe is lowered back to the floor. Record torque values required to make up the Buttress threads to the diamond. This torque value will be used when calculating final liner rotational torque allowed. It is important that hole is not surged while running casing. Continue to pick up and run casing, filling as required with the fill-up tool. Use the collar clamp until sufficient weight is reached_ The casing running speed should be 1 minute per joint, or less. Once the last joint is made up, change to DP elevators and pick UP liner hanger assembly, Make up to proper torque and lower through the BOP stack. Make up three stands of drill pipe, then circulate one volume of the liner. Observe liner weight and continue in the hole, filling drill pipe every 5 stands. With liner shoe still inside casing at the 9 5/8" window, record torque readings to initiate rotation at 1 O, 20 and 30 rpm, This torque value will be used when calculating final liner rotational torque allowed, Continue running in the hole, filling drill pipe as above. Keep liner moving as much as possible in the open hole to minimize the chances for differential sticking, tf necessary, the liner can be reamed into the hole, When liner is close to bottom, make up surface equipment and break circulation. Obtain good returns at 2-3 BPM, then slowly tag bottom. Pick up liner to setting depth (2.-3' off bottom), Drop setting ball and let it free-fall (or pump slowly to ball seat on landing collar, Once ball is on seat, pressure up drill pipe per Baker representative to set hanger (+/- 15-1800 psi), Maintain pressure and slack off liner weight plus 1 ~-20,000 lbs. Increase 15ressure on work string until HR Running Tool is released ( +/- 2100 psi). Pick up liner 4' and note loss of liner weight. If required, the HR running tool can be released manually by working left hand torque into the running tool. NOTE: Do not pick up more than Feet as the DOG sub will exit the PBR. Continue to pressure up to shear out ball seat ( =/- 2900 psi). Set down 20-30,000 lbs on liner, then slowly initiate rotation (Maximum Torque -- Casing Make-Up Torque + Torque of DP at shoe fram Steps "D" and "E" above). Establish circulation. Bring circulation rates on up to 5-6 BPM {cementing rates, per Baker representative). Continue circulating and conditioning mud to PV required for cementing, When hole is conditioned, pump spacer and cement lineras per program. Release drill pipe pump down plug and displace with rig pumps at maximum rate until plug catches cement. Slow rates and watch for latch-up of drill pipe dart and liner wiper plug. A slight pressure increase should be noted as wiper plug leaves setting tool. Check displacement calculations from this point. Stop rotation when plug is 10 bbls from the shoe. Do not overdisplace. If plug bumps, pressure up to 12.00 psi above circulation pressure. Hold for $ minute~,'then release pressure and 'test float equipment. If full circulation was maintained during the job, or cement is at least 1000' above the Sunfish Sand, pick up drill pipe to expose setting dog sub, then set back down with 60,000 lbs. Observe liner top packer shear, Hold weight for. 5-10 minutes, Circulate out excess cement at maximum rate conventionally, POOH and lay down setting tools. NOTE: A Top Job may be performed on the liner if lost circulation was experienced during cementing and cement calculations indicate the top of cement is not adequately above the Sunfish Sands. In this case, Do Not Set Packer. If cement losses were experienced, pick up and circulate until the hole is clean, POOH, then RIH with setting tool (Or RTTS tool). Perform liner top squeeze and set packer, P. Complete PPCO Casing and Cementing Report and send to the Houston Office, DRILLING FLUID PROGRAM ........... .. ,_atio ...... Loss _ · . 8200-11000 10.0-12,0 80/20 25-35 15-20 3 - 5 Oil-Base (12_000' MD) lnvermul Drill out wil:h 9.0 ppg mud, Use soltex for HTHP fluid loss control. Keep Iow gravity solids below 8 %. Increase mud weight as required below 9000', keeping a supply of Barofibre and Steelseal for potential seepage problems. It is very important to have flat gels, 10 for running pipe. (12000-1~000' MO) 15.0 89/15 .. lnvermul Continue program from previous section. Mud weight will need to be brought up to 13,O - 14.0 after corin9 the Sunfish Sands. Non progressive gels important. THESE ARE APPROX RH£OLOGICAL VALUES, and WILL VARY DEPENDING ON OWR & TYPE OF SUSP AGENTS. SOLIDS CONTROL PROGRAM Refer to Intermediate and Production Hole Sections Linear shakers - 3 Derrick Model 58 FID-Line Cleaners Desander Pioneer Model T-86 with 8-6" cones Mud Cleaner Derrick with 16-4" cones Degasser Drilco See-Flow OBM Cuttlnqs .L-landlina: Apollo Services will vacuum the drill cuttings to their catch tank. From there, the cuttings will be ground and disposed into the non-productive sands at a TVD of approximately .t300' TVD. l:)[sposa( will be down one of the two 2. 3/8" tubing strings in the North Cook Inlet Unit "B" No, 1. Add~tlonal Eauioment Needed: 1 ) A dedicated steam cleaner is needed at the shakers to allow for screen cleaning at any time, Coarse (e,g,, expanded metal) Cages will be installed over the pump intakes in the pits to prevent trash from fouling the valves. 3) A dedicated pump capable of pumping liquids out of the cuttings catch tank back over the shakers will be furnished by Apollo Services, 4) Use Pyramid Plus screens as the first 2 screens on the Derricks. The Plus feature is merely taller corrugations, which allows for more separation in the deep pool section of the shakers. NOTE: Ensure all equipment is fully operational before drilling ahead with oil base fluids. Install an operational pressure gauge on the hydroclone headers. Pressure should be 4 x MW in psi. Upgrade feed pump impeller if necessary. Be sure cones are clean and in spray discharge. Conductor arid Surface Hole: Use all rig solids control equipment. Run 210 mesh pyramids on the Derricks, Run desander and desilter on surface hole, IPterm~dJate Hole.: The goals during the OBM sections are to produce dry cuttings (to reduce cuttings slurry volumes), and yet keep Iow gravity solids (Igs) less than 8 vol% with existing rig equipment, in past wells, <8% Igs has been achieved using 21 O's on the Derricks. Again, the goal is to produce dry cuttings, even during upsets and startups with cold mud. During switch out to OBM, put coarse flat screens on Derricks (e.g. 80 mesh). After several circulations, start the Derricks with 140 mesh screens, Use Pyramid Plus screens on the first 2 screens, and a regular Pyramid on the last screen, Screen down to 21 O's in the same arrangement consistent with dry cuttings as soon as possible. A major goal is to produce dry cuttings. To prevent whole mud going over the shakers, it may be necessary to bypass the Derricks for the first half circulation after a trip into the hole. When the mud warms up, immediately switch back over the Derricks. Pump liquids that collect in the catch tanks back over the shakers. Lost circulation is possible at any time. It may be necessary to bypass the Derricks for a short time to allow bridging size LCM (e.g., sized calcium carbonate and Steel Seal) to build up in the mud to plug the problem zone. Return flow to the Derricks as soon as possible to prevent buildup of Igs, It is better to have to keep adding LCM than to le~ the Igs build up over 8 vol%. Production Hole: Continue with previous program- Lower pump rates may allow 250's on the Derricks. UNOCAL RIG 428 MUD SYSTEM LAYOUT C I FUTURE CUTTINGS CONVEYOR ~'~~-'~-~~~.-dzd_.--~m--~~~~i~' 255 BBL ~255 BBL 90 BBL VOL UIvlE/COMPLETIONVOL UME PIT SUCTION PiT -; L .......... /1 · i ~ ..~ I--.ii'.. .... ..' "" ','~ 90 BBL 90 BBL [~'.'..' - 'i'i"_k~' I, ~T ! ........ .:~ " ~_ PiT L_ . .~ · .... . I .. .. ~ ,,, , - '- · ' '-' ,__ ..... , .... r ,- - F - I- - ( PHILLIPS' TYONEK PLATFORM 'MUD SYSTEM LAYOUT Anadrill 1111 East BOth Avenue Anchorage, aJaske g9518-3304 Telephone (907) $49-4511 Main FAX (907~ 349-2467 DPC FAX (907) 344-2160 FAX MESSAGE Date ' _ Receivln~ F,~O~ Number: 7'~ 3-669-3754 Attention ' Company/Department From - Subject: CommentS: - Paul 12 November, 1997 Anadrill- The Geosteering Comgany Paul Dean · MWD/LWD · Directional Drilling The only company with: · fullyretrievabte slim survey/GR · retrievable nuc(e~r source · Measurement atthe b;t - sonic while ddMng Total pages (including this page) 8 Phillips Petroleum Nell Ramjit SF~3A (P12) I--- ' '' . ...... ,J. i i i~ . i ...... i ~ I have revised SF-3A Plan #11 to kick-off at 9035' MD, pass any suggestions or changes back to me. Thanks Neil Take a look at this SF-3A Plan #12 RECEIVED NOV 21 1997 Alaska Oil & Gas Cons. Commi~on Anchorage _IF.THERE_ARE ANY QUF~$_7*ION$__O_R PROBLEMS REGARD[IVQ THIS FAX. P~EASE CONTACT US AT ~UR GQNY~IE~ :~ Vor~O 9 F~ ~ ........ --' ~ Cook Inlet; 61.0J677553 LSD. 95876005 PRO~38RD iqBL,I,,, PROP £:L1~ ANADRILL AKA-DPC FEASIBILITY PLAN NOT APPROVED FOR. EXECUTION PLAN ~ elevation.; 132. {0 ft ~aver~nce, ,: -0.8~0437~8 Ti]8- iN 6URk',BY ~025,0d [.ODP/C-URVE 2.25/100 9055.00 9~, O0 ~LL~ X ~ PAC~ i 00 3335,90 N 690.~ W 3313~.31 25~075.66 124R l.lO - ( · ( ~800.00 8.61 355.73 B964.SL 9832,51 -3573,25 3559.L2 Il 727.62 ! 10500.00 7.$0 15~.67 9GG'2.07 9S30.02 ~O600.OO. 9.~2 LB$.~ ~7&~.91 9~28.91 1~8~0.~0 ~4.0T ]59.~9 99~6.6L 9824.~t ~0900.eO 16.~1 1~0.~6 lOOS~,li 992L.11 ~L200,~O ~3.04 16~.~9 L0335.4~ LO2G3.43 3540.~3 N 3(94.9~ ~ 3399-2~ K 3360-3~ ~ 116,77 ~ 3>t334,~3 2590321.98 LgR ~.25 . ~X1.56 ~ 3~t3~g. Sa 2SgOB12.1L 12R 2,25 67~.~5 . 3~L~78.~9 2~9~207.14 ~R 2.25 ' 609.3A ~ ~3k~3~.4~ 25900~/.~4 g~ 59q.4~ ~ 33145L.6~ 25899~2.29 ]R 2,25 5~8.?g ~ 331a$$.~T 2SR9909.&~ 3R 2,25 5~2.3i ~ 3~L4D~.L9 25eSO53.]~ 3R 16~.52 LL01O.gl ~0~78,9t -3004,~3 Z99~.77 ]4 ~6(.03 L1071,40 10940,40 -2951,~L 2~q1.~6 N 1~4,03 L1235.39 11103.~ -2805,22 2796.l~ N 470.47 ~ 3~L~69.4~ ~G9S3].BS ~71R O,O0 t260e.O0 34,15 166.4L k1~6~,95 11~)J.95 -2627.02 2GIO.SL N 331613.99 258~3S5-9'2 169R 3.Oa p~ 14, P£OPOBBDN~kb PKOP]~B ~2800.00 28,2? ~6~,?3 1~36.94 1:S04.~4 -2525,t7 2SL?.aL N 400.8~ ~ 33&634.~8 2S8g2S4.5[ 167R 3,00 }/iD J.~0/100 CUR~q8 ]3227,t5 25.~9 t78.8{ 12032.00 LL)O0.OO -Z$6{.3~ 2359.£2 H 37~.{0 ~ 33L553.73 2SBgO~S.S$ H~ 3.00 ~O 14V95.56 ].5.9S ~78.83 1373~,00 13¢00.00 -L~79.2~ t077.12 N .36).8¢ ~ 331656.62 258~6Oa.4~ ANADRILL AKA-DFC FEASIBiL}TY PLAN NOT APPROVED FOP-, EXECUTION PLAN #/,2 ~ .... I . PMILLIPS P TBOL O "'-' COMPANY ......... . ......... Il ~ .. I~'~l Il TIE-IN SURVEY TOP UK KOP/CU~VE ENO 2.25/~00 CURVE CURVE 3,00/100 ENO 3,00/~00 CURVE 9-5/B" CA$IN¢ PT NO 6KB 9029 823~ gO~O 8232 9035 8z~5 1~o83 11072 12307 ~1237 IdggG ~3732 SF-3A (P.I 2) V[FII tCAL SECTION SECTN INCLN -3348 ~5.80 -3348 -3350 -2~2 42.87 -2804 -a36e ~.99 -Z366 VIEW __. Section at: 178,83 TVD Scale,: ~ ~nch,= 2000 feet Oep Sca]e.: ~ inch = 2000 fe~t Drawn ..... ; ~ Nov 1997 -§ooo -4o0o -3ooo -2ooo -tODD o :~ooo ,~ooo 3000 4ooo Sect ion Departure . .,. m i i..u, ~ ..... ~ooo _ .[ t I Anadrj]] $ohYumberg£r ........... , mr! ,~_.. / .[ ~ .... . ., . ' o~ ........ ) ........... I _ ~¢~:~-E-=-. ~ ..... ~ -- - ...... . ........ ~ , v:-[ i ' ' PH'ILLIP - ' .... mu ~Jarker ~dent~f~c~tion NO GKB TIE-IN SURVEY 9029 623I END 2.25/100 CURVE 12083 ~t072 CU~v6 3,00/i00 ~2307 3i237 ENO 3.00/tO0 CURVE 13227 12032 TARGET.~ t3227 g-5/B" C~$ING PT t4§~6 13732 TO ~4996 $3732 S SECTN INCLN -3348 ~5,80 -3346 25.79 -3350 eS,TB -2952 ~2.87 -2804 42.8~ -2366 15,~B -e366 ~5.99 -~879 ~5,g~ PETROLEUN CO lP NY SF-3A VERTICAL SECTION ..... -- -,,,il ,~..~ .......... Section et: ~.78.83 TvD Scale,' i inch = ~OOO feet Oep $c81e.- ~ inch = ¢000 feet Drawn ..... ' ~l Nov Igg7 VIEW '"' I ~,/ [ ,4nadp ~ ] / Sch.tu~bePger ANADRILL · ~aoo -5500 -Sooo -,~500 -{0gO -3500 -3000 -aS00 -eO00 -~00 -t000 -500 0 500 ~OOO Sect ion Oeparture _ -- i~ ii i .... i i } I pl.:l T LL Zids iiii F~E-~N SURVEY 90~ 3334 N mp OF Wl~O0~ gO30 333~ N ENO 2,25/$00 CURV~ 12083 2942 N ENO 2.00/~00 CU~V~ 12~? 2~e N T~G~T.~.~ 13227 235g N ~-5/8" CASING pr ~gg~ 1872 N TO ~6 ~872 N PET -OLEUM t/~ 6~0 ~ 470 w 380 w 380 W 37O W . , SF-3A (Pi2) PLAN VIEW CLOSURE ' 2908 feet at Azimuth 348.82 DECLINATIDN,' +2~,I~7 (E) SCALE · ~ inch ~ 600 feet DRAWN · :ti Nov lgg7 /nad. Ci]] $cniu~tTerger, tOO 1800 ~500 ~00 9o0 BO0 $o0 0 3o0 600 ~oo <- wEST: EAST -~ , ~ _ ,i 1,,i _. imm ~cl~7 ~3~ 3.~.5 ~;:37 AM ~ i P'RILLZPS PE _ ) ! ~11 ..... i i .... i ii SF-3A (P 2) PLAN VIEW CLOS jRE ' ~90B feet at AZimuth 348.82 O~CL ;NAT]:ON.' ,2~.i27 {El , S6~L~ ....... : ~ ~nch = ~00 feet ORA~'I · 1~ Nov ~997 . i Anadrill $£hlu¢berger i .~ ..... ii i _. , -- .......... t. - -ROt" 'OM COMPANY ,,. - _-~;:.~_~-~ ~rker ~d~ntificat~on ~0 N/S E/~ ~) TI~-IN SU~Ef gong 333~ N 6gO w B) TOP OF WINDOW 80~0 3335 N 8gO~ ~ o) eNO ~.~/mO CURv~ ~0~3 ~4~ ~ ~ w C~vE ~.00/~00 ~23o7 ' ~795 N 470 W F) END 3.00/10o CURVE ~3227 2359 N 380 W G) 1ARGET~ ~3~7 ~33~ N 350 W H) 9-5/8' CASING PT t499B ~872 N 370 W I) lO 14gg~ ~87~ N 370 N 900 750 80o 450 300 I~0 o 150 300 450 <- wEST' E~ST -> m * I1~1 r .. -- TOTAL P. 40 ~' TONY KNOWL'E$, GOVERNOR ... ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 November 14. 1997 Paul Dean Senior Drlg. Engineer Spec. Phillips Petroleum Company 6330 W. Loop South Bellaire, TX 77401 Re: North Cook Inlet Unit B No. 2 Phillips Petroleum Company Permit No: 97-210 Sur. Loc. Tyonek Platform, Leg 1, Slot 6, 1249'FNL, 980'FWL, Sec. 6, T11N, R9W, SM Btmhole Loc. 4727'FSL, 1280'FEL, Sec. 36, T12N, R10W, SM Dear Mr. Dean' Enclosed is the approved application for permit to redrill the above referenced well. The permit to redrill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the Commission's internal use. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below-the surface casing shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission at 279-1433· · Chairman~,~ ~0 _ BY ORDER OF COM3/ISSION dlf/Enclosures CC: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALA~KA OIL AND GAS CONSERVATION COMMI..~SION PERMIT TO DRILL 20 AAC 25.005 Re-Entry Deepen JService · Deveiopme,nt Gas ,., SIn,~le, Z~3ne Multiple Zone ,, , 2. Name of Operator: 5. Datum Elevation (DF or KB) 10, F~eld and Po~l Phllli ,,Es Petroleum Co. 132 feet North Cook Inlet Unit Field 3~ Address: 8. Propeffy Designation Exploratnry 6330 W,~ Lm3p South, Elellairaa TX 77401 ,ADL-1758~, 4. Location of well at surface: Tyonel< Platform Leg I SIo( 5 ?.' Unit or Property Name 11. Typle Bond (s~_ 124.9' FNL & 980' FWL SEC 6-T 11N-R09W ~ No, rth C(x~k Inlet Unit "B" Statewide At top of productive Interval: B~ Well Number Number 4400' FSL & 670' FEL SEC 36-T 12N-R10W No. 2 41-O-~24 At total depth: ~)~ Approximate spud date !Amount , 47~7' FSL & 1260' FEL SEC 36-T,, t 2N-R10W,. , ,11/1 .~/97 $20~,z000 ,, 12. DIstance to near~st 113. Distance to nearest wet~ 14. ~o. of acres in property r15. Prop~=d depth (MD and TVD) property fine Surface: 4' 9920 a~prox. 600 feet ,N, CIU B-1 15800 MD 13750 TVD feet ..... , 16. To be completed for deviated W~lls 17. Anfl~'ipata~f pressure -7'$oO/,~., ~ ' ~,~c ~.~3s IKickeffdepth: 1,1~.~00 ff Maximum hole anF~le 60 de~, roes Ma~,imum aurf~,¢e 11 p total de, pth/TVD), , Casing program Setfinj), D~oth sizei speciQcatlens To~' i, Q, ottom O,uantiby of Hole _Caein_q Weii3ht Grade Coupfln_ql Length M,D TVD MD , TVD (includa~sta~qedata) , Driven 30" Drive 3o~ 5!~ 8S 407' 407' EXISTING al i [ i ii 24" 20" 1691 C~7.0 lOfll-.Quipj 2S43' SO 85 2802, 2534' EXIS'F'ING 17.1/2" , ,13-.3/8" 72 hl.8o;P-ll~ BT&c 8849' 55 , 55 8.909' 8123' .... EXIST,lNG ,, _.12-i/#' 9-sras97/8" s,3.5;~.a ,i,ao[Q-12.~ .BT,&C 1 ,2Q80' ,55 SS 12138' , 110~4' EXISTING, 8-,1/2" 7" 32 ,L..80 BT&C 45,56' 11200,,, 10155' 15756' 13732' ,700 sx Class "G" ! i ii Note: Well to be slde4~cked from 9 5/8" casing (~ 11,500'. 19. To be c~3mpleted for Redrlll, Ee-entPy, and Deepen Operations. 1) 58 sx below re~ner (~ 13,916' w 12 Sx above. 70 sx / Present w~ll condRion summary 2) 50 sx below retainer {~ 13,464' w 8 sx above. $8 sx 3) 58sxbelowre'miner ~.12,37~'w lOsxabove. 68sx Total depth: measured 14705' feet Plugs {measured) 4) 68 sx i 1,950' - 11,700'. ~'ueverflcal 13286' feet ~) 6~x 300'-500'. ,..~"'~ ? Effective depth; m~asured fee{ Junk (measured) Packe~ & TCP Guns {~ 13,482' and ~) 12,400'. trtle vertical Feat ~.'"'/Zz :" Casing Length Size Oemented Measured depth True Vertical clepth Structural 36'8' 3~ Driven 407' 407' __.~,/~.<.'! .i;// Surface 8849' 13,,3/8" Yes 8909' 8123' ~ '. :~ Inlsrmediate 12080' ~-s~&~)7/~. Yes 12138' 11024' Prod. Liner 2104' 7' Yes 13~2' 12597' ._ - Perforation depth: measured 12478' - 12536' DA: 13594' - 13706' DA trueverUcal 11325' 12'303' ~.i~?.?~,~;:..I ~ '...~j ~;:"_i ~G 20. Attachments Firing fee _X_ Property plat_X_ BOP sketch _X_ Dlverter Sketch ~ Drilling program ...X_ Drillin_q,fluld pro_~ram X~Time vs depth plot _X Eof_mc'don anal~is , Sea ,bed rer~art 20 AAC 25.050 mqul,,mments (DIr ,ectlenal Pro, ram) ,, 2t. I hereby certEy that the raregolng Is true and correct to the best of my' knowledge Oonditlons of Approval: Samples r~:lulred ~ Yes ---- No Mud log requir~t ~-- Ye~ ~ No Hydrogen sulfide measures ~ Yes ~ No Dir~ctional survey require,~-'~ Yes _-- No Required working pressure for BOPE 2M 3M ~ .SM ~ 10M ~ 15M Otb.r: Original Si g"~0 David W. Johnston ~o~e,'o~ /t ~ _Approved by , , Oomrnlsslo,n,er,, the cornmissior), ,,Bate I ~ Form 10.401 Rev. 12. I-85 Submit ln tlipiica{e PHILLIPS PETROLEUM COMPANY P. O. Box 1967 Houston, Texas 77251 · 1967 6330 Weet Loop South Bellalr®, Texas 77401 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage. Alaska 99501 Attn: Mr..l~.~ Gentlemen: November 06, 1997 North Cook Inlet Unit B No. 2 PPCo. Tyonek Platform North Cook Inlet Unit, Alaska Enclosed is an updated Form 10-401 (Application for Permit to Drill). Included is a revised directional drilling proposal that will allow the target zon~ and the bottom hole location at total depth to be within the boundaries required for a legal location. This fax copy will ba followed ~ original ~ of the Application as soon as possible. Thank you for your earliest consideration. PRD enc (2) Respectfully submitted, Paul R. Dean, Sr. Drilling Engineering Spec. for Phillips Petroleum Co. · · ,EXISTING CASING & C aENT DIAGRAM 3o "@ 407' BPV(Make, Type,OD) ]Tbg. Hgr.(Make,Type) Not Applicable IAnnulus Fluid: 13.6 lb/gal mud between cement plugs 20"@260~ Cook Inlet San Upper Beluga Not Applicable [TO(?: Casing Strings: 30 ,, ~ 551 4071 457 lb/f~ ] Welded ! 20" ! 59 2,602 169. lb/fi[ X-56 i Dril-Quipl 2860 133/8" i 591 8,909 72.01b/ft [N-80;P-1101 BT&C 4730 5/8 & 9 ?/i 571 12,138 !53.5 & 62.8 iN-80;Q-125 BT&C 7090 Production Liner: 7" I 118371 13,9411 32 lb/t't L-80 I BT&C 8160 20" Conductor 11/25/93 Lower Beluga 13 :t/8" @ 89o9' Tyonek Top of Liner @ 11837' 9 5/8" @ 12138' EZSV@12375' Packer & TCP Guns "C" Sand ~12478-12502 12526-12536 Halco BWD @ 1348:2 Sunfish Sand 13594-13644 13656-13706 13 3/8" lstStage 12/18/93 2nd Stage DV tool @ 7385' 3rd Stage DV tool @ 4045' 9 5/8" 01/16/94 [RKB-THF: RKB-BHF: 59.00i IRKB-MSL: 132.001 lWater Depth 130.00i Burst!::'::[ i': C611 : I Tensn 1 PPCo. Allowable Ratings 14101 1700 2520i 761 75001 921 CEMENTING SUMMARY 81~01 528 Cemented with 1070 sx 12.8 lb/gal Class "G" with 0.25 gal/sx D-77, 0.05 gal/sx I)-47 and 0.28 gal/sx D-75. tailed with 600 sx Class "G" mixed ~ 15.8 lb/gal with 0.25 gal/sx D-77 and 0.05 gal/sx D47. Cement Cimulated to Surface. EZSV @ 13916' 7 "@ 13,93ff Cemented with 900 sx 12.5 lb/gal Class "G" with 1.0 % D-6, plus 0.05 gal/sx 12)-47 Tailed with 700 sx Class "G" ~ 15.8 lb/gal with 0.05 gal/sx D-47, 0.5% D-59, 0.15 gal/sx D-801, 0.4% D-65, 0.10% D-134, and 0.25% S-1. 3700 sx 15.8 lb/gal Class "G" with 0.10 % D-65, plus 0.1% D-135, 1.0 gal/sx D-600, and 0.3% D-800 1000 sx 15.8 lb/gal Class "G" with 0.20 % D-65, plus 0.1% D-135, 1.0 gal/sx D-600, and 0.3% D-801. Cemented with 0.1 gal/sx D-47, Cemented with 0.1 gal/sx D-47, Cemented with 1000 sx 15.8 lb/gal Class "G" with 0.1 gal/sx D-135, 0.1 gal/sx D-47, 0.01 gal/ax% D-080, 1.0 gal/sx D-600, and 0.06 gai/sx D-801. Estimated TOC at 11,000' 7" Cemented with 674 sx 15.8 lb/gal Class "G" with 0.1 gal/sx D-47, plus 1.5 gal/sx D-600, 0.1 gal/sx% D-135, 0.07 gal/sx D-8, and 0.03 gal/sx 12)-801. 03/09/94 7" 03/28/94 7" ABANDONMENT PLUGS Set EZSV Cement Retainer at 13,916'. Cemented with 70 sx Class "G" Pumped 58 sx below retainer, 12 sx on top of retainer. Set EZSV Cement Retainer at 13,464'. Cemented with 58 sx Class "G" Pumped 50 sx below retainer, 8 sx (30')on top of retainer. Set EZSV Cement Retainer at 12,375'. Cemented with 68 sx Class "G" Pumped 58 sx below retainer, 10 sx (100')on top of retainer. Spot 68 sx Class "G" Cement plug 11,950' - 11,700'. Spot 68 sx Class "G" Cement plug 300' - 500'. 03/31/94 7" 03/31/94 7" 04/01/94 7" Sunfish No. 3 was Temporarily Abandoned April 1, 1994. 300' [Supv: iTbg Wt: North Cooklnlet Unit "B" No. 2 (formerly Sunfish No. ;h) Octobert 11, 1997 Field: North Cook Inlet PRD 14,705' Tsvonek Platform, Cook Inlet, Alaska PROPOSED SIDETRACks'DIaGRAM ' ' .,, BPV(Make, Type, O_l)) Not App~li~abla RKBA:,H T bg,Hgr,(Malm,l~,pe) Not Applicable -;L[C~BE Pmnalus Fluid_' 13,6 Ib/g~ m~d betwee~ cement plugs '- 19~K~8 f~.' ....... lw*,~, ~o.~' .... C~iag StHnlis: [4'~Co. AIl~,'fl'Gbl¢ l'~a~inll;~ ..... ~o ,' ~ ~6o2 t69. lb/~' x-s6 ~p -~8~o ~toi 17oo ~ &97~' 57 ]'j., ~3.3 & ~2. S~-~0;~{~ ~&C ' '7090 7500i 92I ........... 20 ,, Cond~ ~ ~ 1070 ~ 12.8 ~la. ,,Of.'~ 0,2~ gaU~_~7, ' 11~5/~ 0.05 ~V~ D~7 ~d 0,28 ~F~;~J'. ~iled with 600 ~ Ciasa "G" 13 3~ '" Ist S~ Cm~ ~ ~0 ~ 1 Z5 IWW{ CI~ "04 ~ 1.0 % D~6, ' .... .}~18~3 Fire 0.05 ~V~ D47"~ail~ wi~ 700 ~ Cl~ "O" ~ 15.8 ~g/gal wi~ ~ 0,~% S-I. ,, ~ S~8c ~d ~ 3700 ~ I5.8 Ib/~{ Cl~ '~"~ 0.10 % ~5, pl~ .... DV~I~SY . .0.1~7,0,1%~13~,1,0~~,a, d0,3%D-800 .,~ 3~ 8~m C~d ~ 1000 ~ 1~.8 {~l Cla~ '~" ~ 0.20 % D-65, pl~ DV ~1 ~ 40nj' 0.10V~'b~7, 0,1%D-135. L0 OV~ ~6b0r a.a 0.3% D-801, 01/16~4 0, l .~ ~7, 0.01 ~V~%D~80. 1.~ 8aV~ ~O0, and 0,06 ~ D-801. ~ma TOC at I{]000'.,,, 7" '~ ~ 6?4 ~ 1~,8 i~i CIa~ "G" ~ 0.1 ~ ~7, .... ......... _. ,.. ,. ........ .............. P~opose ~: · ~ sld~m~ ~ip~ in 9 5tB" ~sing at 11,5~', then mill a ~n~ In the 9 ~slng end e~ ~e allio a ~ b~om hole ~on. A~r I~gi~, 8 ~ liner ~11 ~ ~ a~ ~ented ~ appm~m~ 700 ~ Class "G" tempt lo the top M ~ liner, It ~ ~en pm~ed lo D~T the No~ Fo~anda ~ and ~e S~h Sand. . ,,, . _ ~ WeU: ~unfah No. 3 ]Da~: Oc~be~ 11, , 30 "@ 407' 2o "~ 2~oz Cook Inlet Sand~, Upper Beluga Lower Beluga 13 ~/8 ~ ~ T~ek ~ ~ 1~7~ ~t & ~P Gun,: ~ ~ 13~ H~ ~ ~ 1~ SuCh ~nd ~ 1~13~4 ~ ~ 1391~ TD t4,7~ No~ Fmelan~ = 1580~ TOTAL PAGE.03 ** Kill Line Flowline I HCRValve Gate Valve I I Fill-up Line 13 5/8" 5M Annular Preventer 13 5/8" 5M x 13 518" 10M Adapter 13 518" 10M Pipe or Variable Bore Pipe Rams 13 5/8" 10M Blind Rams '~0M Drilling Spool Choke Line Gate Valve HCRValve 13 5/8" 10M Pipe Rams 13 5/8" 10M Riser 9 5/8" Casing 13 5/8" 10M Spacer Spools (If Required) 135/8" 10M x 11" 10M DSA Adapter Flange 135/8" 5M x 11" 10M Tubing Head 13 5/8" 5M x 20 3/4" 3M Casing Spool FMC 20 3/4" 3M x 20" SOW Casing Head (FMC) 20" Casing 13 3/8" Casing 13 5/8" 10M BOP and Riser System Use During Sidetrack Operations prd / October 18~ 1997 PHILLIPS PETROLEUM COMPANY North Cook Inlet Unit "B" No. 2 (Formerly Sunfish No. 3) j/ ~/" lDpoo S? L N ' I NORTH COOK INLET UNIT "B" No. 2 (Sidetrack of SF3) MUD WEIGHT / CASING POINT / PRESSURE PLOT (TVD) Depth {-I'VD) ' I . .: .................... , ...... ;.e_ ~_ , ....... , ...... i i i i ! i i .......................... ' ............ 28'1ffi .... ' ...... .... ........... ' ' ' _ _ _'_ _-----~.u_~_~- , ,' : g~/l~'~110P.4 ~ 11,100' ............ , , , ., 8L,~IRSH , ..... · ~ ......................... ~ ...... r ........... ~ ...... ! ...... , , , , , ..... : ...... , .................. , ...... '_ ............ , ............ , , , , , I I I I 1 8 9 10 11 12 13 14 15 16 17 18 1584O Mud Weight(ppg) · 'PROPOSED ~NCIU B1 ~ --Series5 OLEAK-OFFTEST ~ ~ ~ -' --S'Fish 2 --S'Fish 3 PROCEDURE FOR DETERMINING MAXIMIIM DOWNHOLE PRESSURE AND MAXI~ POTENTIAL SUPdEACE PRESSURE Maximum Downhole Pressure is determined from the pore pressure predictions of the interval to be drilled below the subject casing. The pore pressure predictions were made from offset well data and the seismic data. The maximum potential surface pressure is determined to be the lesser of the fracture pressure of the formation at the subject casing shoe less a fluid gradient to surface or the bottomhole pressure of the intervals to be drilled less the gradient of the fluid produced from the formation. Drilling Below 9 5/8" Intermediate: Frac Pressure = 16.4 lb/gal from MW / Casing Point Chart @ 11,500 kick-off (10,427 TVD) Max MW to Drill with = 14.5 lb/gal. BHP = MW * 0.052 * Depth Frac PSI @ Window = 16.4 lb/gal * 0.052 * 10427 = 8892 psi BHP from Mud Weight 14.5 lb/gal * 0.052 * 10427 = 7862 psi Max Surface PSI before Formation breaks down is 1030 psi Gas Gradiant-ki-ternative BHP = 9700 psi from DST of N. Forelands No. 1 Max MW = PP / 0.052 / D~ 9700 / 0.052 / 13282 Max MW = 14.0 lb/gal Maximum Potential Surface Pressure is determined based on the pressure that would result from BHP less a gas gradient back to surface. The mud weight will be at least 0.5 ppg higher than the pore pressure gradient. MPSP = BHP - (gas gradient) (TVD) MPSP = 9700 - (0.15 psi/ft) (13282') = 7707 psi SOLIDS CONTROL PROGRAM Refer to Intermediate and Production Hole Sections Ri(~ Eoui0ment: Linear shakers - 3 Derrick Model 58 FIo-Line Cleaners Desander Pioneer Model T-86 with 8-6" cones Mud Cleaner Derrick with 16-4" cones Degasser Drilco See-Flow OBM Cuttings Handling: Apollo Services will vacuum the drill cuttings to their catch tank. From there, the cuttings will be ground and disposed into the non-productive sands at a TVD of approximately 3300' TVD. Disposal will be down one of the two 2 3/8" tubing strings in the North Cook Inlet Unit "B" No. 1. Additional E0ui0ment Needed: 1 ) A dedicated steam cleaner is needed at the shakers to allow for screen cleaning at any time. 2) Coarse (e.g., expanded metal) cages will be installed over the pump intakes in the pits to prevent trash from fouling the valves. A dedicated pump capable of pumping liquids out of the cuttings catch tank back over the shakers will be furnished by Apollo Services. 4) NOTE: Use Pyramid Plus screens as the first 2 screens on the Derricks. The Plus feature is merely taller corrugations, which allows for more separation in the deep pool section of the shakers. Ensure all equipment is fully operational before drilling ahead with oil base fluids. Install an operational pressure gauge on the hydroclone headers. Pressure should be 4 x MW in psi. Upgrade feed pump impeller if necessary. Be sure cones are clean and in spray discharge. Conductor and Surface Hole: Use all rig solids control equipment. Run 210 mesh pyramids on the Derricks. Run desander and desilter on surface hole. Intermediate Hole: The goals during the OBM sections are to produce dry cuttings (to reduce cuttings slurry volumes), and yet keep Iow gravity solids (Igs) less than 8 vol% with existing rig equipment. In past wells, <8% Igs has been achieved using 210's on the Derricks. Again, the goal is to produce dry cuttings, even during upsets and startups with cold mud. During switch out t-o OBM, put coarse flat screens on Derricks (e.g. 80 mesh). After several circulations, start the Derricks with 140 mesh screens. Use Pyramid Plus screens on the first 2 screens, and a regular Pyramid on the last screen. Screen down to 21 O's in the same arrangement consistent with dry cuttings as soon as possible. A major goal is to produce dry cuttings. To prevent whole mud going over the shakers, it may be necessary to bypass the Derricks for the first half circulation after a trip into the hole. When the mud warms up, immediately switch back over the Derricks. Pump liquids that collect in the catch tanks back over the shakers. Lost circulation is possible at any time. It may be necessary to bypass the Derricks for a short time to allow bridging size LCM (e.g., sized calcium carbonate and Steel Seal) to build up in the mud to plug the problem zone. Return flow to the Derricks as soon as possible to prevent buildup of Igs. It is better to have to keep adding LCM than to let the Igs build up over 8 vol%. production Hole: Continue with previous program. Lower pump rates may allow 250's on the Derricks. I SUCtiON Pit i ii CEIV~IFUGE PI~ 80 8~L ¢~TRIFUS~ UNITS ! i " I UNOCAL RIG 428 MUD SYSTEM LAYOUT "L_~::~-~'-'-~~~ Ik,.,'_~ .w_ . ~ ,.., FUTURE CUTTINGS CONVEYOR -, 255 BBL ~255 BBL 90 BBL' VOL UME//COMPLETION VOL UME PIT SUC TIOIV PIT ', PIT I . I 90 BBL 90 BBL'" '~ 85 BBL °,~ " '~1 90 BBL PILL ,, PHILLIPS' TYONEK PLATFORM I MUD SYSTEM LAYOUT PHILLIPS PETROLEUM COMPANY VERTICAL.,_ SECTION VIEW -- ~ Secti°n at: 29~.76 i iTvosca]e': ~ tnch=~6°° Feet ' ,. IOep Scale.: 1 inch = 1600 fee[ IOrawn ..... : 22 Oct 1997 [ -~nadrili $chjUmberger Marker Ioent~FJca~ion MO 8K8 SECTN INCLN A} TIE-IN SURVEY 11424 10359 2197 25.90 8) TOP OF W~NOOW 114~5 10423 2198 25.18 C) KOP/CUflVE 2,50/100 11500 10428 2198 ~5. ....... D) ENO 2.50/100 CURV[ 13928 12342 3358 58.51 E) SUNFISH rGT 14520 12552 3865 58.51 FE,~SIBILI~F PLaN NO'- AP,~RO'¢EDIFOR ,J EXECU7 ION , m 0 80o ~600 ~,~00 3200 4000 4800 s600 6,,,00 7~oo eooo 8800 9600 !04o0 Section Departure i . ., ' I - Icl 9? SF3AA7 3.0C ,~; ~ 1 PM PI 0CT-23-1997 10:48 907 344 2160 98X P.04 PHi-LLIPS PETROLEUM COMPANY Marker IdentiFication MO BK8 SECTM INCLN A] TIE-iN SURVEY 11424 to35g 2t97 25.90 BI TOP OF WINOOW lldg5 10423 2198 25.I8 C) KOP/CUnV5 2.50/t0o 115o0 10428 21@8 25.12 O] ENO 2.50/100 CuAVE 13926 12342 3358 58.5~ F1 TO i$587 13732 §G27 58.51 SF-3A (PO7) VERTICAL SECTION VIEN Section at: 294.76 TVD Scale.' ! inch = 600 feet Oep Scale.' 1 inch = 600 feet Drawn · 22 Oct ~997 A ~- ~nadr~ ] ] Sch]um/~srger ANA,DRILL AKA-~C FEAS BILl FY P_Ak N()T A PPR,DVE[) FOR E5 :ECL TioI q -- , ~ ,.~ i , , ,: . . ,m Section Oe~arture _ 0CT-23-1997 10:48 90? 344 21~0 97Z P.05 PH'ILLIPS PFTBOL UN COMPANY Marker IdentiFication A) TIE-IN SURVEY 8) fOP OF WINOOW C) KOP/CURVE 2.50/100 D) ENO 2.50/~00 CURVE E) SUNFISH TGf F] TO HO N/S E/W J(424 4379 N 400 w yk 11495 4407 N 388 W 11500 4409 N 387 13926 5430N llgd W 14520 5650 N 1650 W 16587 6416 N 3238 W SF-3A (PO7) PLAN VIEW , CLOSURE ..... : 7187 feet at Azimuth $33.21 OECLINATION.: +22.127 (E) SCALE ....... : 1 inch : 1000 feet ORAWN ....... : 22 Oct 1997 /lnadril] Schlumberger ' ! . 3500 3000 2500 2000 ~500 1000 500 0 500 tO00 1500 2000 2500 3000 j)500 <- WEST · E~ST -> (~n-~ari)l (~)97 ~1~2~J)7 3.0C 4:12 PM P) , , . i. ' : 0CT-23-1997 10:48 98? 344 2160 97~. P.86 PHILLIP'S PETROLEUM COIqPANY .Z] SF-3A (P07) PLAN VlE~ CLOSURE ..... : 7187 feet at Azimuth 333.22 OECLINATION.: +22.127 (E) SCALE ....... : 1 inch = 600 feet OBAWN ....... : 22 Oct 19§7 4nadrY ]] Schlumberger Marker Ic~enttf lcation MO N/S Al TIE-IN SURVEY 11.424 437g N §1 TOP OF WINOON 1J,195 4407 N C] KOP/CU~VE 2.50/100 JJ~00 4409 N O) ENO 2.50/100 CURVE 13926 5430 N El SUNFISH TGT 14520 5650 N F) TD 16587 64!6 N E/W ~°°~ 387 1650 3238 ]0 -- ~" F ~i ! ' -- ' ....... ~- '~ ' ~o I "~-- '-' so ~,. r~rget (point) I O0~ ' , - , oo ...... / , AK~k bPC I °° F~A,SIBIL. iTY PLA N ~OTAPP ~OV ~~DR / .. oo , ~XEC~TiON / ' 00 i --.~ ~~ I ,, 1 I , ~aorlll (c}97 SF]~7 3.0C 4:t5 eH t~1 0CT-23-1.997 ~0: 49 3600 3300 3000 2700 2400 2i00 1800 1500 t200 go0 600 300 0 300 !600 <- WEST' EAST-> . , 907 344 2160 97~ P.O? Anadr]_[[ Schlumberger Alaska District 1111 Hast 80th Avenue Anchorage, AK 995L8 {907) 349-4511 ~ax ]44-2160 D[HECTIONAI~ ~ELL PLAIi for PHILLIPS PHTROLELTM CC~IP~NY Well ......... : SP-SA (PO7) FieLd ........ : Cook InLet ComputatLoa..: bllnimum Curvature Surface Lat..: Surface Long.: 150.94876005 Legal Description Surface ...... : 1249 ~4L 980 ~HG S06 TllR R09W SM TarcSet ....... : 440~ F~L 670 ?Bi S36 T12N R£0W S~! B)~ .......... : 5166 ~SL 2258 ?Mb' S36 T12N R£OW SM, LOCATIONS - ALASKA Zone: 4 X-Coord Y-Coord ]][663.16 259~115.43 330431.45 2592404.27. 328855.28 2593193.28 Prepared ..... : 22 Oct ~997 Ve~ sect az.: 294.76 K~ eleYatioR.: 1_~2.00 fl Ma~ne[Lc Dc]n: +22.~27 (~) Scale PacCor.: 0.999932L~ Convergence..: -0.83043768 PRO~O~BD ~ELb PBOFIL~ ANADRILL AKA..DPC FEASIBILITY PLAN NOT APPROVED FOR EXECUTION PLAN [~I'AT[0N M:F.,A~D [NCLI9 DIRIi'CI'IO~ VERTICAL-DEP~(S SECTION fOORD[IIATEH-PROM ALASKA Zone 4 TOOh Db/ ]DEDTIF£CATIOII DEPTH A~IGL~ AZ[MU'TH TVD SUI~-SEA DEPART I'~IiLf~HEAD X V ~ACR 100 T£E-£)I SURVEY 11424.00 25.90 22.50 10359.01 10227.0l 2197.04 4379.06 N 399.66 ~ 331663.16 2SPillS.43 164R <T£E TOP O~ WINDO~ L1495.00 25.18 23.00 10423.07 10291.07 2198.~ 440~.29 N 3~7.82 W 3316~5.40 259LL43.4~ 163R 1.07 KOP/C~IR¥8 2.50/L00 LlSO0.00 25.L2 2~.04 30427.60 10295.60 2198.~6 4409.24 N 366.99 il600.00 24.71 17.19 10518.30 10386.30 220L.58 4448.75 N 372.50 8 331691.32 259LL84.?! 97L 2-50 11700.00 24.52 lL.20 1~609.23 L0477.23 2209.20 4489.08 N 362-30 N 331702.11 259L224-89 92L 2-50 ~'~;i:;ii~ff': 11800.00 24.58 5.18 30700.21 k0568.2L ~22£.04 4530.15 N 356.39 N ]31708.61 2591265.8~ 86b 2.50 ., ~ ~., ~ 11900.00 24.87 359.24 1079L.06 10659.06 2237.07 457L.89 N 354.79 N 3317L0.91 ~593307.57 81L 2.50 ~., ~ 12000.00 2~.39 353.48 10881.61 10749.61 2257-26 4614.22 ~ 357.51 W 331708.71 2591349.93 75L 2.50 [' [:f~l:'~"] 32100.00 26 12 347.97 10971.69 10839.69 228L.58 i65?.05 N 364.53 W 331702.31 2591392.06 70L 2.50 . .......... .. 12200.00 27.05 342.79 11061.13 10929.L3 2309.99 4700.3L )1 375.85 W 33~691.62 2591436.27 66L 2.50 ~.,~,~ 12300.00 28.26 337.95 LLL49.75 llOlS.V5 2342.39 4743 9L Ii 39l 44 W 33Lg76.6~ 2591490.09 625 2 50 ,, [,,...~.,,=,.~. . . . SF-SA (PO7) 22 Oct 1997 Pa~e 2 STATIOD £DSNT f FI CAT I ON PROPOSE~D [~RLL PROPIL~ MHASLTRHD INCL,N DIILRCPIOU VERTICAL-DEPTHS SHCT£ON DSPT~ ANGLE AZI[llfrH TVD SUB-SEA DEPART 12400.00 29.43 333.47 11237.40 lL105.40 2378.77 L2500-00 30.83 329.35 [L323.89 11191.89 2419.04 [2600.00 32.3& 325.57 [1409.08 t1277.08 2463.12 k2700.00 _ ~..~;99 322.k0 13492.79 £1360.79 2510.94 £2800.00 35.70 3£8-92 315~4.86 11442.86 2~62.40 COORDIIIATES-FRO~ AI~SKA Zone 4 ~E~LHSAD X Y 4787.76 N 4~].27 [~ 331659.49 2591524.2] 4831.80 N 435.31 ~ 331634.08 ~591568.60 4875.92 N 463.50 W 331606.5] 2591613.13 4920.06 ~ 495.80 W 33[574.89 2591657.72 4964.1£ H 532.L5 W 331539.17 2591702.30 ==m= ~m~ TOOL DL/ FACE £00 581 2.50 541 2.50 511 2.50 4~L 2.50 451 2.50 12900.00 37-50 3£6.00 116~5..LS ~1523.15 26L7.40 13000.00 39.~6 313.31 11733.49 11601.49 2675.e4 13100.00 41.28 3L0.8~ 11809.74 11677.74 2737.60 13200.00 43.24 308.54 11883.75 11751.75 2802.58 13300.00 45.25 306.41 ~1955.38 11823.38 9870.64 13400.00 47-30 304.42 1202.4.50 L1892.50 2941:65 13500.00 49-38 302.~6 L2090.97 LL958.97 3015.49 13600.00 51.%9 300.82 L2354.67 L2022.67 3092.01 13700.00 53.62 299.1T L221.S.~ £9083.47 317-1.06 13800.00 55.77 297.61 12273.27 12141.27 3252.49 5008.01 N 572.47 ~ 331499.49 259i74&.77 43L 2-50 505L.67 N 6L6.69 ~ 331455.91 259179£.06 41L 2-50 5094.99 N 664.73 W 331408.51 259L835.08 391 2-$O 5137.91 N 716.48 [9 331357.39 259L878.74 37L 2.50 5180.3& N 771.87 U 331302.63 259L92].96 36L 2.50 5222.~0 N 830.79 ~i 331244.35 2591964.66 3iL 2.50 5263.4~ N 893.07 W 33LL82.65 2592006.76 33L 2.50 5303.88 N 958.67 W 33LL17.65 2592048.L8 321, 2.50 5343.54 N 1027.42 ~ 33L049.48 2592088.84 311 2.50 5382.33 1! 1099.2L W 330978.26 2592128.66 30L 2.50 13900.00 57.9~ 296.13 12327.94 12195.9~ 3336./6 5420.L6 ~ 2.50/100 CURVE 13925,86 58.$L 295.76 1234L.56 12209.56 3358.13 5429.$8 SUNFISH 14520.09 58.5[ 295.76 12652.00 12520.00 3864,75 5650.00 SUNFISH TGT L4520.09 58.51 295.76 12652.00 12520.00 3864.75 5650.00 N PORLAND 15726.01 58.5£ 295.76 13282.00 13150.00 4892.86 609~.91 1173.90 W 330904.14 2592167.57 29h 2.50 1L93.67 ~ 330894.52 2592177.47 aS 2.50 I650.00 ~ 33043L.45 2592404.27 HS 0.00 t650.00 D 33043[.45 2592404.27 HS 0.00 2576.07 D 3295t2.02 2592864.53 RS 0.00 TD L6587.38 59_5L 295.76 13732.00 13600.00 5627.23 6416.13 N 3237.55 ~1 328855.28 2593L93.28 0.00 ANADRILL AKA-DPC FEASIBILITY PLAN NOT' APPROVED FOR EXECUTION PLAN 17 (Anadrill Icl~? SF3AP7 3.0C 5:06 ~ P) PHILLIPS PETROLEUM COMPANY NORTH AMERICA E & P DRILLING OPERATIONS WELL: APl NO. FIELD: LOCATION: North Cook Inlet Unit "B" No. 2 (Formerly Sunfish No. 3) Permit No. North Cook Inlet Field Surface: BHL : WORKING INTEREST: AFE: BUDGET. ITEM: GROSS AUTHORIZATION: OBJECTIVE: DRILLING ENGINEER DRILLING ENGR. DIRECTOR DRILLING SUPERINTENDENT DRILLING MANAGER 1,249' FNL & 980' FWL Leg No. 1; Slot No. 6 5,166' FSL & 2,258' FEL Phillips Petroleum Co: P-X121 2A $ 6,464,000 COUNTY, STATE: NCIU Alaska AREA: Kenai, Alaska Sec. 6-T11N-R09W Sec. 36-T12N-R1 OW 100.000000 % Plug Back and Sidetrack the former Sunfish No. 3 to Test a 16,600' MD (13,732' TVD) Exploration Appraisal Well.' DATE DATE DATE DISTRIBUTION: J. W. KONST N. P. OMSBERG (R) CENTRAL FILES W. L. CARRICO ; DEVELOPMENT SUPERVISOR (2) J. R. JACKSON (R) L.D. AIRINGTON L.G. JANSON W. B. VIA M. P. GATES POOL ARTIC ALASKA J. W. SPENCER P. R. DEAN (ORIGINAL) ORIGINAL( ) REVISION (I ) TIGHT HOLE: YES(X) NO ( ) DRILLING PROGRAM SUMMARY . Well Name: North Cook~lni'et Unit B No. 2 Field: North coOk Inlet unit AFE No. AFE P-X121 Drill & Test Costs: Surface Location: 1,249' FNL & 980' FWL Sec. 6-T 11N-RO9W Bottom Hole Loc. 5,166' FSL & 2,258' FEL Sec. 36-T12N-R10W Depth: 16,600' MD 13,732' TVD AFE Days: 62 Rig: Unocal Rig 428 with Pool Artic Alaska manpower Type: 2A $ 6,464,000 Leg 1; Slot6 OBJECTIVE- Plug Back and Sidetrack the former Sunfish No. 3 to Test a 16,600' MD (13,732' TVD) Appraisal Structure 2000' West of the Original Exploration Well. CASING PROGRAM: 30" 407' Drive Pipe 20" 2602' (2534') 133 K-55 BT&C 2860 1410 1700 13 3/8" 8909' (8123') 72 P-110; N- BT&C 4730 2520 1231 3800 80 9 5/8" / 12138' 53.50 / N-80 ; BT&C 6970 6250 921 5000 9 7/8" (11024') 62.8 Q-125 7" Liner 16600' 32 P-110 BT&C 9960 10170 688 5000 (13732') 3.5" (Alt) 16600' 12.95 P-110 PH-6 14240 17470 232 8000 i Sec. I Sec. II PROCEDURE SUMMARY 1. MIRU Unocal Rig No. 428 over Leg No. 1, Slot No. 6. 2. Install riser and 13 5/8" 10M BOP and Choke Manifold. Test BOP to 5000 psi. Install PVT equip. 3. Drill out cement plug at 300' - 500'. TIH and wash to 1 1,500'. Pressure test casing to 5000 psi. 4. Install Oriented Whipstock @ 1 1,500'.. Mill 8 1/2" window in 9 5/8" casing. 5. Take FIT test to 16. Ppg EMW. , , 9. 10. Drill an 8 1/2" hole with directional assembly to 16600' MD. Circulate and condition hole for logs. Log well with DIL/GR/Den/Neutron. as per Geological Prognosis. Run and cement 7" production liner (or 3 1/2" production casing ( 3 1/2" monobore tubing )). Clean out production liner to PBTD. Completion testing program will be planned based upon log evaluation. . . , . o . . . 9, DRILLING PROSPECTUS Location Phillips Petroleum Company's Tyonek Platform located in the North Cook Inlet of Alaska. Drilling will be from Leg No. 1, slot No. 6 ( See attached survey and schematics). Drilling Contract The drilling contract is a bare boat charter directly from Unocal for the use of the Rig No. 428. Pool Artic Alaska will provide the manpower and rig crews to install and operate the rig. Well Control Well control procedures will be in accordance with Phillips Petroleum Company's Well Control Manual and State of Alaska Oil and Gas Conservation Commission. Govermental Reporting Notify AOGCC (Blair Wondzell) @ (907) 279-1433 prior to moving rig and prior to spud. Special Considerations This section is intended to clarify and discuss special drilling Situations that may occur. Be alert for these potential problems and ready to implement the appropriate contingent actions. Oil Base Mud will be used for the entire sidetrack operation and drilling the new hole interval from 11,500' to total depth of 16,600' (13732' TVD). (Refer to Oil Based Mud Handling Procedures - attached in mud program). All precautions will be taken to insure that no runoff is allowed. Proximity to Other Wells The referenced well will be kicking off from the existing wellbore at a depth of 11,500'. There are no other wellbores within 2,800' of this point, nor are any prognosed to be crossed at the planned trajectory. Shallow Gas There is no reason to expect a shallow gas hazard at the North Cook Inlet "B" No. 2, since the well has been drilled and cased. All BOP equipment will be installed and tested prior to drilling any cement plugs. COAL SEAMS -. Stuck pipe due to coal beds has been a frequent occurrence in this and other fields in the Cook Inlet, mainly when using WBM. Coal generally swells with WBM. These coals will be drilled throughout the well. The use of OBM with the use of the top drive has shown a reduction in the problems associated with coal. The coals may be fractured and have a tendency to cave into the well. A large chunk could result in mechanically sticking the drillstring. Mud weight and soltex have been used with some success to stabilize the coals. Raise mud weight as needed to control the coal seams. For OBM, gelsonite and/or Soltex should be used to lower HP/HT to 4 co or less. 11. The penetration rate in the coals will be high. This can result in an attempt to drill a lot of fast hole. 'Experience in the Inlet shows that this fast hole may result in stuck pipe. The experience of the driller is important in avoiding this. The geologist and mud loggers can be helpful in predicting where coal seams may occur so the driller can be especially alert in areas where coal seams are about to' be drilled. Control drilling rate through coal and determine if reaming is necessary. Make sure there is a backreaming cutter on bit if available. In the event the pipe does become stuck, spotting fluids have been successful in some cases in freeing the pipe where the mud was water based. The use of oil based mud should help in this regard. DIFFERENTIAL STICKING There are several sands in the 8 1/2" hole section that are expected to be normally pressured and permeable. If mud weight has been raised to stabilize the coal seams then these sands will present a risk for differential sticking. To minimize this keep the pipe moving as much as possible and minimize stabilized spiral HWDP and spiral DC's in OBM. During a fishing job on the Sunfish No. 2, even spiral-wate drillpipe became differentially stuck. Efforts should be made to avoid directional corrections by sliding with a mud motor. Use lost circulation additives such as Barafiber or Steel Seal to reduce seepage losses and to minimize the risk of differential sticking. 12. HIGH BACKGROUND GAS The formations that will be drilled are gas saturated coal, sand, and silt. This will result in unusually high background gas readings. Mud weight should not be increased to suppress the high background gas. SECTION I: DRILLING PROCEDURE 5/8" CASING) - DEPTH 11,100' MD-RKB. A. GENERAL REMARKS - PREPARE WELL FOR SIDETRACK OPERATIONS 1. Intent- Clean out 9 5/8" intermediate casing and cement plug to proposed kick-off point at 11,500'. Pressure test casing to 5000 psi. Install Baker Windowmaster whipstock assembly. Change out water base mud system to oil based system. Mill an 8 1/2" window in the 9 5/8" casing @ 11,500'. 2. Wellhead Proaram- FMC 13 5/8" 5M x 11" 10M Tubing Head is installed. Install 13 5/8" 10M BOP and riser system with adapter spool as necessary. 3. BOPE Reauirements and Test Pressures 13 5/8" 10M BOPE is required. Test pressures are as follows: Initial Installation Rams: 7900 psi Annular: 3500 psi Weekly 5000 psi 2500 psi 4. Casina Pressure Test & Leak-off Test Pressure test 9 5~8"-casing to 5000 psi prior to installing whipstock. After window is milled, perform a Leak-Off Test as per the PPCo. Well Control Manual. Contact Drilling Superintendent if leak-off occurs before 15.0 ppg EMW. 5. Soecial Drillina Instructions A, Insure the following equipment is in place and fully operable prior to beginning drilling operations: a. b. c. d. e. Pit level monitor with audio and visual warning system. Mud return indicator. Gas detector with audio and visual warning system. Mud volume measuring device (trip tank, etc). Both mud systems are tied together and shut down detectors are full~/ functional and operating. B. Install a wear bushing before drilling to prevent wear in the casing head. 6. Whipstock Assembly- B. C. D. E. F. G. H. I. J. K. L. M. 9 5/8" Bottom Trip Anchor w / 4 1/2" IF Box. 9 5/8" Windowmaster Whipstock w / 4 1/2" IF Pin. Windowmaster Window Mill with 4 1/2" Regular Pin. Windowmaster Lower Watermelon Mill w ! 4 1/2" Reg. Box x 4 1/2" iF Pin. Windowmaster Flex Joint with 4 1/2" IF Box x Pin. Windowmaster Upper Watermelon Mill w / 4 1/2" IF. Box x Pin. 1 Joint 5" HWDP. 6 1/4" OD Bowen Lubricated Bumper Sub with 4 1/2" IF Box x Pin. 6 1/4" MWD w 4 1/2" IF Box x Pin. U.B.H.O. Wireline Orientation Sub with '4 1/2" IF Box x Pin. (12) 6 1/4" Drill Collars with 4 1/2" IF Box x Pin. (15) 5" Heviwate Drillpipe with 4 1/2" IF Box x Pin. Drill pipe to surface. SPECIAL INSTRUCTIONS After clean out to 11,500', make bit and scraper run to insure that no restrictions exist which may cause premature setting of Bottom Trip Anchor. Bo MIRU wireline unit. Make gauge ring run with 8.5" gauge ring. TIH with bridge plug and set +/- 2' below casing collar below kickoff joint. Window will begin 30' above this point, and will be 16' in length when finished. C. Make up Windowmaster Whipstock Assembly as above. Install the Anchor / Whipstock assembly to the Windowmaster milling assembly via the 45k whipstock shear bolt. Align the UBHO wireline orientation sub and MWD (scribe as required) with whipstock face. This should be witnessed by all relevant parties. The UBHO wireline orientation sub will be used only as a back-up in the event of MWD failure. e. Run in the hole with the full whipstock assembly. Take care running through BOP stack and wellhead. Run assembly at a maximum rate of 90 to 120 seconds per stand, taking care not to spud or catch the slips. At 45 feet above the setting depth, establish slack-off weight, pick-up weight, with and w/o circulation,. Take care during moving pipe to avoid sudden movements which may affect the whipstock shear mechanisms. Survey the whipstock face with the MWD and orient the whipstock to the requested kick-off direction. Take 3 surveys to insure correct orientation. With the correct orientation established, reciprocate the whipstock to confirm that the face'has not rotated. Lower to setting depth and re-check orientation. Correct orientation is 25 degrees to the left of high side. - S. Once orientation and depth have been verified, set down 15-20 k to shear the slip mechanism and set the bottom trip anchor. Check that the bottom trip anchor has set by pulling a maximum of 5k lbs above pick- up weight. H. Displace water based fluid with oil based mud ( milling fluid) at this time. With the anchor set, work the pipe from neutral weight to 45k lbs. Down to shear the whipstock bolt. If a positive shear is not seen at the surface, repeat the procedure four times. Do not overpull more than 15k lbs. Jo Pick up to neutral weight and establish circulation and rotal~ion. Start milling the window, lowering the milling assembly with 2-4k lbs WOB and 50-60 RPM for the first 1-2 feet. Increase the rotation as required to 100ol 35 RPM, with a maximum of 8-10k lbs WOB. A minimum annular velocity of 150 ft/min should be maintained. The yield point of the mud should be kept to a minimum of 40 to ensure optimum carrying capacity for milled cuttings. K, Continue milling until the upper watermelon mill is out in open hole. This should be approximately 38 feet. Once the depth has been established, ream the window until smooth, avoiding rotation if possible. Once all drag has been removed, POOH. Section Ih 8 1/2" Hole (7" Casin(~! to 13.26Z'TVD 15.800' MD-RKB A. GENERAL REMARKS 1. Intent Drill an 8 1/2" hole from sidetrack window in 9 5/8" casing through the Sunfish and North Forelands Sands to 13,732' TVD (16,600' MD). Take a 60' core of North Forelands Sands as requested by geologists. Log well as per the Geological Prognosis, with revision from Drilling Manager. If productive intervals are indicated, set and cement a 7" production liner. 2. Litholoov and Anticioated Problems Continuation of the sand and shale with interbedded coal seams is prognosed. There is a pressure transition that occurs slightly above the Sunfish Sands at_.+ 12,000' TVD,_.+ 14,300' MD,. Pore pressures may increase from 9.8 ppg to about 13.2 ppg during this transition. This abnormal pressure trend is expected to continue to TD. Actual mud weights could be as high as 14.5 ppg. 3. Wellhead Prooram FMC 13 5/8" 5M x 11" 10M Tubing Head is installed. Install 13 5/8" 10M BOP and riser system with adapter spool as necessary. ,, I~OPE Reouirements and Test Pressures 13 5/8" 10 M BOPE is required. Test pressures are continued frome previous section as follows: Initial Installation Weekly Rams: 7900 psi 5000 psi Annular: 3500 psi 2500 psi 5. Casino Pressure Test & Leak-off Test Perform a Formation Integrity Test as per well control manual to an EMW of 16.0 ppg. (anticipated L/O -- 16.5 ppg EMW). Maximum anticipated mud weight in this hole section will be 14.5 ppg. Consider squeezing the shoe if the leakoff is less than 15.0 ppg EMW. Contact Drilling Superintendent if FIT leak- off occurs before 15.5 ppg EMW. 6. Directional Drilling Instructions- Follow directional drilling' program. After window is prepared and wiped clean with the 8.5 "mill to clean up burrs and the hole displaced with OBM, RIH w/8 1/2" PDC bit, steerable motor and BHA, including MWD. Drill the 8 1/2" hole, following directional plan, from kick off point at 11,500' RKB. With the steerable motor, slide and rotate to attain the 2.5 deg/100' azimuth change to the west. NOTE: BHA adjustments-must be discussed with the Houston Office personnel. At kickoff point, begin sliding to kick well off per directional plan. Drill ahead, rotating and sliding as required to attain the proposed wellbore trajectory. This directional plan is based on a maximum azimuth change of 2.5°/100 ft. Dog leg severity in excess of 5°/100 ft could cause both drillpipe fatigue and excessive torque and drag. To minimize the potential for these problems THE DOG LEG SEVERITY CAN NOT BE PERMITTED TO EXCEED 3°/100 FT. Take MWD surveys every 30' throughout Build (azimuth angle change). 7. Special Drillina Instructions A! Bo Co Install a wear bushing before drilling to prevent wear in the casing head. Drill ahead with motor and steerable assembly, maintaining angle and direction to the targets. To prevent differential sticking, keep pipe moving as much as possible, especially while making connections. Drilling Jars should be used in this section of the hole. Core North Forelands Sands (60' core anticipated) as requested by geological and reservoir personnel and revised by Drilling Manager. At TD, circulate hole clean, C&CM for logging. B. DRILLING DETAILS ( :8 1/2" HOLE TO 16.600 MD-RKB) 1. Bottom Hole Assembly (Steerable Drilling Assembly) 8 1/2" PDC bit, Anadrill 6 3~4" 6 stage extended length performance motor, float sub, MWD/LWD equip., 2- 6 3/4" NMDC, 25 jts. 5" HWDP, Drlg. Jars, 5 jts. HWDP, Drill Pipe. BHA to be discussed and agreed with Houston office. 2. Bits. WOB. RPM IADC Bit Code: PDC Tv_De WOB.' 10-20 M RPM: 60 -150 Jets: 20-20-20-20 Hycalog DS66 or DS75 (or similar). As required for smooth drilling (drill on motor differential) 3. Hydraulics Maintain flowrate at 450 - 500 GPM. Maintain stable pump pressure.- 3600 - 4000 psi (with motor). Maintain good mud properties. Yield point should be as Iow as possible to keep the ECD as Iow as possible. 4. Mud Program Depth TVD Weight PPG Oil/Wtr PV YP HPHT Mud Type Ratio Fluid Loss - 15-20 3-6 Oil Base (11500-16600' MD) 85/15 Invermul Continue program from previous section. Mud weight will need to be brought up to 14.0 prior to coring the North Forelands Sands. Non progressive gels important. THESE ARE APPROX RHEOLOGICAL VALUES, and WILL VARY DEPENDING ON OWR & TYPE OF SUSP AGENTS. Survey Reauirements and Deviation Restrictions A. Continue with directional plan, using MWD surveys for directional control. . SamDlina. Mud Loaaina. and Electric Loas A. Mud logging to be from 11,500' MD to 16,600' MD. S. Fax reports every morning to (713) 669-3754 by 5:30 (PDT) and follow with phone report at 06:00 a.m. Openhole logs from 10,400'- TVD (11,500' MD) to 13,700' TVD (16,600' MD): Array Induction / GR; Compensated Neutron / Litho-Density with GR and Caliper; Dipole Array / Sonic with GR and Calil~er; MDT Tools, Dipmeter. Circulate and condition hole for logs. NOTE: See Attached Geological Prognosis 7. Corina A. Conventional 60' core to be taken from 13,280'-13,340' TVD. , I~nvironmental A. Do not spill any Oil Mud. Insure that no mud escapes from platform area. If any accidents occur advise Houston Office Immediately. B. An SPCC plan is required on rig at all times. ~i~:~"~ii_-'i :-'~~ ?~ CASING AND CEMENTING DETAILS (7" CASING) AT 13,732 TVD (16,600 MD-Ri(B) 1. Casing Specifications: (Top to Bottom) TVD PPCo Pw Torque Depth Description Burst Coll Ten Opt ft- Drift 11,200 - 7 "32 lb/ft 10270 10150 688 6.0" 16,600' MD P-110 BT&C Note: Air weight for this casing (liner) string is 173,000 lbs. . Float Shoe : Float Collar : Landing Collar & Loc : Centralizers : Connection Lock : Cementing Plugs : Circ, Mix, Displace Rate : W'ford Model 323 (PDC drillable). W'ford Model 402 Sure Seal - 1 joint above shoe. Baker Type II - 1 joint above float collar. W'ford 1-7' above shoe; next 2 joints w/collar stops; every second collar to 14,000'.; Every third joint to 11,500'. Use turbulator type (2 per joint) across N. Forelands and Sunfish pay intervals. Do Not Thread Lock Float Equipment, in the event liner does not reach bottom and has to be retrieved. Drill pipe and Liner Wiper Plugs only Maximum practical . Spacer : 10 bbls of Diesel/10 bbls HiVis FW (Flozan and barite) FV = 150. Mix at 14.5 ppg (actual mud weight). Actual volume TBA . First Stage Cmt Slurry Slurry Weight : Mix Water - Type : Pumping Time : Desired TOC : Compressive Strength : Calc 875 sx Halliburton Premium + 0.20 % CFR-3 + 0.13 gal/sx Halad 344L + 0.13 % HR-5 15.8 PPG 4.87 gal/sk. Fresh 3-4 hours 11,200' (use 20% excess in open hole interval) 24 Hours - 2140 psi. NOTE: ACTUAL CEMENT TO BE USED MUST BE LAB TESTED PRIOR TO SENDING SAME TO THE LOCATION. SPECIAL LINER CEMENTING INSTRUCTIONS A. Check to vei;ify that all equipment required is in place and inspected for operation. Drill pipe must be rabbitted to 3" ID on last trip out of the hole. Have the following equipment made up and ready prior to the liner leaving the cased hole: A) 10' - 15' drill pipe pup joints. B) TD (Top Drive) Swivel with Totco baffle plate installed in box and Halliburton valve / chicksan swivel made up on circulating port in closed position. C) TD plug dropping head with drill pipe dart installed. D) Flag sub E) Run liner on drill pipe only. Use DP for required set down weight to set packer. Make up above assembly with TD unit to 20-22 K torque, then lay on pipe rack for quick access. B. Notify the AOGCC a minimum of 24 hours prior to the casing job. C. D. Eo S. H. J. K. Lo N. Oo Do Not Baker Lock the W'ford Float Shoe and Float Collar on the first joint of casing. Install the Baker Landing Collar / ball catcher sub on the top of the 2nd joint. Do Not Baker Lock the Landing Collar. Make up third joint, then fill the casing with mud and pick up 40 - 60' to operate the float valves. The fluid should fall, but not refill as pipe is lowered back to the floor. Record torque values required to make up the Buttress threads to the diamond. This torque value will be used when calculating final liner rotational torque allowed. It is important that hole is not surged while running casing. Continue to pick up and run casing, filling as required with the fill-up tool. Use the collar clamp until sufficient weight is reached. The casing running speed should be 1 minute per joint, or less. Once the last proper torque volume of the joint is made up, change to DP elevators and pick up liner hanger assembly. Make up to and lower through the BOP stack. Make up three stands of drill pipe, then circulate one liner. Observe liner weight and continue in the hole, filling drill pipe every 5 stands. With liner shoe still inside casing at the 9 5/8" window, record torque readings to initiate rotation at 10, 20 and 30 rpm. This torque value will be used when calculating final liner rotational torque allowed. Continue running in the hole, filling drill pipe as above. Keep liner moving as much as possible in the open hole to minimize the chances for differential sticking. If necessary, the liner can be reamed into the hole. When liner is close to bottom, make up surface equipment and break circulation. Obtain good returns at 2-3 BPM, then slowly tag bottom. Pick up liner to setting, depth (2-3' off bottom). Drop setting ball and let it free-fall (or pump slowly to b-all seat on landing collar. Once ball is on seat, pressure up drill pipe per Baker representative to set hanger (+/- 15L1800 psi). Maintain pressure and slack off liner weight plus 15-20,000 lbs. Increase pressure on work string until HR Running Tool is released ( +/- 2100 psi). Pick up liner 4' and note loss of liner weight. If required, the HR running tool can be released manually by working left hand torque into the running tool. NOTE: Do not pick up more than Feet as the DOG sub will exit the PBR. Continue to pressure up to shear out ball seat ( =/- 2900 psi). Set down 20-30,000 lbs on liner, then slowly initiate rotation (Maximum Torque = Casing Make-Up Torque + Torque of DP at shoe from Steps "DA and "E" above). Establish circulation. Bring circulation rates on up to 5-6 BPM (cementing rates, per Baker representative). Continue circulating and conditioning mud to PV required for cementing. When hole is conditioned, pump spacer and cement lineras per program. Release drill pipe pump down plug and displace with rig pumps at maximum rate until plug catches cement. Slow rates and watch for latch-up of drill pipe dart and liner wiper plug. A slight pressure increase should be noted as wiper plug leaves setting tool. Check displacement calculations from this point. Stop rotation when plug is 10 bbls from the shoe. Do not overdisplace. If plug bump..s, pressure up to 1200 psi above circulation pressure. Hold for 5 minutes, then release pressure and-test float equipment. If full circulation was maintained during the job, or cement is at least 1000' above the Sunfish Sand, pick up drill pipe to expose setting dog sub, then set back down with 60,000 lbs. Observe liner top packer shear. Hold weight for 5-10 minutes. Circulate out excess cement at maximum rate conventionally. POOH and lay down setting tools. NOTE: A Top Job may be performed on the liner if lost circulation was experienced during cementing and cement calculations indicate the top of cement is not adequately above the Sunfish Sands. In-this case, Do Not Set Packer. If cement losses were experienced, pick up and circulate until the hole is clean. POOH, then RIH-with setting tool (Or RTTS tool). Perform liner top squeeze and set packer. P. Complete PPCO Casing and Cementing Report and send to the Houston Office. PRESSURE ANALYSIS Pore pressure predictions have been made based on the offset well information from other wells drilled in the area and the seismic data. The most important offset wells used in this analysis are the production wells on the platform for the shallow horizons, and the Shell North Cook Inlet State No. 1, Arco Sunfish No. 1, Arco-Phillips North Forelands State No. 1, and the Phillips-Arco Sunfish No's. 2 and 3 wells recently drilled. The interval above 7,800' TVD, _..+ 9,300 MD will be the Cook Inlet and Beluga sands that are produced at the platform. The pressures in these sands have declined to a 5 - 6 ppg equivalent mud weight. Based on the results from the Arco Sunfish No. 1, the Arco-Phillips North Forelands State No. 1, the Phillips-Arco Sunfish No's. 2 and 3'and the workovers on the North Cook Inlet Unit Wells A-1 thru the A-13, lost circulation is not expected to be a problem despite the Iow reservoir pressures. Due to the lenticular nature of the Beluga formation, there is the possibility of encountering a Beluga sand at virgin conditions. Virgin pressure in the Beluga interval was 8.5 - 9.5 ppg. The geologic interpretation for the interval below 7800' TVD is that the formations and pressures should be similar to those encountered in the Arco Sunfish No. I and the PPCo. NCIU No. A-12 (formerly Cherryville A-15). The interval between 7800' TVD and the proposed 9 5/8" casing point at 11900' TVD, 14,200' MD is essentially normally pressured. This is the Middle Ground Shoal section with the 10,700' Sand and t_he Tyonek C Sand. Mud weights of 10.5 to 11.5 ppg are anticipated and will be dictated by the coal seams throughout this interval. There is a pressure transition that occurs slightly above the Sunfish Sands at __+ 12,000' TVD, __+ 14,300' MD,. Pore pressure will increase from 9.8 ppg to about 13.2 ppg during this transition. This abnormal pressure trend is expected to continue to TD. Actual mud weights could be as high as 14.5 ppg. Oct 29, 1997 DESCRIPTION o.~o~.o, 0 0 0 7 9 0 State Of Alaska Dept Of Revenue C/O Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive " Anchorage, Alaska 99501 Charge Code P-X121 Purpose' Permit To Drill COMMODITY LEDGER LOC. EMPLOYEE NO. CE TAX ID NO. REPORTABLE 1099 CODE YES I NO THE ATTACHED CHECK IS IN FULL PAYMENT OF ITEMS STATED ABOVE. ENDORSEMENT MUST BE IDENTICAL WITH THE PAYEE DESIGNATED:- r')I::TA(';.H RI:FORE DEPOSITING AND' RETAIN FOR YOUR FILES. · WELL PERMIT CHECKLIST COMPANY FIELD & POOL (%.1 ~/~ INIT CLASS WELL NAME GEOL AREA ~ ~.~ PROGRAM: exp J~dev [] redrll I~serv [] wellbore seg E: ann. disposal para req [] UNIT# J I ~1 ~-C) ON/OFF SHORE ,~1~' ADMINISTRATION A~C.~ DATE 1. Permit fee attached ....................... y 2. Lease number appropriate ................... (~ N 3. Unique well name and number .................. ¢~,~N~, 4. Well located in a defined pool .................. Y 5. Well located proper distance from drilling unit boundary .... ~) N 6. Well located proper distance from other wells .......... 7. Sufficient acreage available in drilling unit ............ .,~ N 8. If deviated, is wellbore plat included ............... ~ N 9. Operator only affected party ................... (~ N 10. Operator has appropriate bond in force ............. (~ N 11. Permit can be issued without conservation order ........ 1~ N 12. Permit can be issued without administrative approval ...... ~ N 13. Can permit be approved before 15-day wait ........... N REMARKS ENGINEERING DATE GEOLOGY APPR DATE 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. Conductor string provided ................... Y N Surface casing protects all known USDWs ........... Y N CMT vol adequate to circulate on conductor & surf csg ..... Y N .., CMT vol adequate to tie-in long string to surf csg ........ Y N CMT will cover all known productive horizons .......... (~ .... " ' Casing designs adequate for C, T, B & permafrost ....... Adequate tankage or reserve pit ................. If a re-drill, has a 10-403 for abandonment been approved... Adequate wellbore separation proposed ............. ~(~ N /~j~ If diverter required, does it meet regulations .......... Drilling fluid program schematic & equip list adequate ..... ~ N BOPEs, do they meet regulation ..... ~r~ ......... BOPE press rating appropriate; test to ~;~ psig. Choke manifold complies w/APl RP-53 (May 84) ........ Work will occur without operation shutdown ........... Is presence of H2S gas probable ................. Y 30. Permit can be issued w/o hydrogen sulfide measures ..... (~ N 31. Data presented on potential overpressure zones ....... (~ N 32. Seismic analysis of shallow gas zones ............. Y/,~ ~ 33. Seabed condition survey (if off-shore) ............. ~ N,~ 34. Contact name/phone for we,ekly.progress repo, rts ....... ~ N ~exploramry onlyj lO t GEOLOGY: RPC ENGINEERING: COMMISSION: BEW DWJ~ JDH Ii.-' R N C_.,I~.~ ~ CO C~ Comments/Instructions: HOW/Ijt - A:\FORMS\cheklist rev 09/97 · . _ . [] redrll serv FIELD & POOL ~/, .~ INIT CLASS ~].],.~] ,,~__~/~,~ _~Z GEOL AREA _~ .~-_,'"'2 UNIT# ON/OFF SHORE ADMINISTRATION APPR . 2. 3. 4. 5. 6. 7. 8. 9. 10. 11 13. ENGINEERING Permit fee attached ....................... N -~ "'/~'~/5' ./,~- ,.~. ,~-/'¢j//~,.J.~.~,. ,,-~, ~ Lease number appropriate ................... N /'/ ~ ~~~,~ Unique well name and number .................. ~ ~ ~ ¢¢~/ ~/~ ~// ' ¢ ~ ~ Well located in a defined p~ol .................. Well located proper distance from drilling unit boundaw .... //~¢ ~, 3 ¢~ ~ Well located proper distance from other wells .......... ~ - ' - ' " Su~cient acreage available in drilling unit ............ N If deviated, is wellbore plat included ............... N Operator only affected pady ................... N Operator has appropriate bond in force ............. N Permit can be issued without conse~ation order. ~ ........ i Permit can be issued without administrative approval ...... ~ N Can permit be approved before 15-day wait ........... ~ N ~ D.A'i)E GEOLOGY 14. Conductor string provided ................... Y N 7 ~_~ 15. Surface casing protects all known USDWs ........... Y N 16. CMT vol adequate to circulate on conductor & surf csg ..... Y N 17. CMT vol adequate to tie-in long string to surf csg ........ Y N 18. CMT will cover all known productive horizons .......... 19. Casing designs adequate for C, T, B & permafrost ....... N 20. Adequate tankage or reserve pit ................. 21. If a re-drill, has a 10-403 for abandonment been approved... ..- 22. Adequate wellbore separation proposed ............. )N 23. If diverter required, does it meet regulations .......... ~~.,~ 24. Drilling fluid program schematic & equip list adequate ..... 25. BOPEs, do they meet regulation ..... 26. BOPE press rating appropriate; test to ~~' ' ' I~sigl N -- 27. Choke manifold complies w/APl RP-53 (May 84) ........ 28. Work will occur without operation shutdown ........... yfyfyf~(~ ~.X/.~~ ,~'~ .~/~ 29. Is presence of H2S gas probable ................. 31.30' Permit can be issued w/o hydrogen sulfide measureSData presented on potential zones ..... (~_N_~'7~_.., /,, ~.~ ~ 7~ overpressure ....... 32. Seismic analysis of shallow gas zones ............. Y.,,/4q ~-~ ~ ,,¢~. ~.~_~ ~_//~,~ / ~--~"'~~-- .~,~Z~ % ,~.~j 33. Seabed condition survey (if off-shore) ............. ,,~ 34. Contact name/phone for we,eklyprog, ress repqrts ....... Y N lexploratory omyJ GEOLOGY: ENGINEERING' COMMISSION: JDH ~,¢g~ RNC~ co 5~, Comments/Instructions: HOW/lit - A:\FORMS\cheklist rev 09~97
