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206-013
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: 08/13/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250813 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# KBU 24-06RD 50133204990100 206013 4/2/2025 YELLOWJACKET GPT-PERF MPB-24 50029226420000 196009 7/9/2025 READ CaliperSurvey MPB-34 50029235690000 216139 7/7/2025 READ CaliperSurvey MPF-45 50029225560000 195058 7/30/2025 READ CaliperSurvey ODSK-41 50703205850000 208147 8/9/2025 READ CaliperSurvey ODSN-25 50703206560000 212030 6/22/2025 READ CaliperSurvey ODSN-31 50703205650000 208003 8/11/2025 READ CaliperSurvey PBU 06-11A 50029204280100 225042 7/13/2025 BAKER MRPM PBU 13-19 50029206900000 181180 6/4/2025 HALLIBURTON WFL-TMD3D PBU 14-18C 50029205510300 225040 6/24/2025 BAKER MRPM PBU 14-43A 50029222960100 225041 7/30/2025 BAKER MRPM PBU C-01B 50029201210200 212053 7/19/2025 BAKER MRPM SD-07 50133205940000 211050 7/27/2025 YELLOWJACKET SCBL SP 12-S3 50629235130000 214067 7/18/2025 YELLOWJACKET PERF Please include current contact information if different from above. T40771 T40772 T40773 T40774 T40775 T40776 T40777 T40778 T40779 T40780 T40781 T40782 T40783 T40784 KBU 24-06RD 50133204990100 206013 4/2/2025 YELLOWJACKET GPT-PERF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.08.15 10:11:56 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 6 Township: 4N Range: 11W Meridian: Seward Drilling Rig: N/A Rig Elevation: N/A Total Depth: 7830 ft MD Lease No.: FEDA028142 Operator Rep: Suspend: P&A: X Conductor: 20" O.D. Shoe@ 107 Feet Csg Cut@ Feet Surface: 13-3/8" O.D. Shoe@ 1518 Feet Csg Cut@ Feet Intermediate: 9-5/8" O.D. Shoe@ 3768 Feet Csg Cut@ Feet Production: 3-1/2" O.D. Shoe@ 7812 Feet Csg Cut@ Feet Liner: O.D. Shoe@ Feet Csg Cut@ Feet Tubing: O.D. Tail@ Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Bridge plug 3,830 ft 3,811 ft Wireline tag Initial 15 min 30 min 45 min Result Tubing IA OA Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: EXCAPE completion. This tag was witnessed after a 72-hour nitrogen MIT for the purpose of dry hole perforations. Wireline dump bailed 19 ft of cement on a CIBP (minimum required per approved Sundry was 15 ft). April 1, 2025 Sully Sullivan Well Bore Plug & Abandonment KBU 24-06RD Hilcorp Alaska LLC PTD 2060130; Sundry 325-113 none Test Data: Casing Removal: Wade Hudgens Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2025-0401_Plug_Verification_KBU_24-06RD_ss 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.05.06 12:28:25 -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: 5/29/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250529 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 5/10/2025 AK E-LINE GPT/CIBP/Perf HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL IRU 241-01 50283201840000 221076 5/7/2025 AK E-LINE Plug/Perf KBU 22-06Y 50133206500000 215044 5/6/2025 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 5/7/2025 AK E-LINE Perf KBU 24-06RD 50133204990100 206013 4/8/2025 YELLOWJACKET GPT-PLUG MPI 1-61 50029225200000 194142 5/10/2025 AK E-LINE Perf MPU E-42 50029236350000 219082 5/3/2025 AK E-LINE Patch MPU S-55 50029238130000 225006 5/13/2025 AK E-LINE CBL OP16-03 50029234420000 211017 4/25/2025 READ LeakDetect PAXTON 13 50133207330000 225021 4/29/2025 YELLOWJACKET SCBL PBU 01-12B 50029202690200 223090 4/8/2025 HALLIBURTON RBT PBU D-08B 50029203720200 225007 3/22/2025 BAKER MRPM PBU H-17B (REVISION)50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG PBU J-25B 50029217410200 224134 3/10/2025 BAKER MRPM PBU K-19C (REVISION)50029225310300 224004 3/27/2025 BAKER MRPM PBU K-19C 50029225310300 224004 3/27/2025 HALLIBURTON RBT SRU 241-33B 50133206960000 221053 3/12/2025 YELLOWJACKET PERF Revision Explanation: Both wells had wrong side stack well name and API#/PTD on previous upload H-17b was marked as H-17A and K-19C was marked as K-19B. Well name now reflets correct sidetrack and has correct SPI# and PTD. T40489 T40490 T40491 T40492 T40492 T40493 T40494 T40495 T40496 T40497 T40498 T40499 T40500 T40501 T40502 T40503 T40503 T40504 KBU 24-06RD 50133204990100 206013 4/8/2025 YELLOWJACKET GPT-PLUG Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.29 14:33:01 -08'00' 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: N2 Development Exploratory 3. Address: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 7,830 feet See Schematic feet true vertical 7,626 feet 7,744 feet Effective Depth measured 3,744 feet N/A feet true vertical 3,659 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)N/A; N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 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: Stefan Reed, Operations Engineer 325-113 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 N/A stefan.reed@hilcorp.com 206-518-0400 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 0 Size 107' 0 00 0 00 0 9-5/8" 3-1/2" Intermediate 20" 13-3/8" 86' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 206-013 50-133-20499-01-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028142 Kenai Gas Field - Sterling Gas Pool 3 & Sterling Gas Pool 4 Kenai Bleluga Unit (KBU) 24-06RD Production Liner 3,661' 7,791' Casing Structural 3,682' 7,608' 3,768' 7,812' 107'Conductor Surface 1,463' TVD measured Packer Plugs Junk measured Length 3,090psi 10,530psi 3,450psi 5,750psi 10,160psi 1,518'1,518' Burst Collapse 1,859psi measured true vertical p k ft t Fra O s 6. A G L PG , 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 9:09 am, May 07, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.05.06 17:09:17 - 08'00' Noel Nocas (4361) RBDMS JSB 051525 BJM 6/26/25 DSR-5/8/25 Page 1/2 Well Name: KEU KBU 24-06RD Report Printed: 4/23/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20499-01-00 Field Name:Kenai Gas Field State/Province:ALASKA Permit to Drill (PTD) #:206-013 Sundry #:325-113 Rig Name/No: Jobs Actual Start Date:2/26/2025 End Date: Report Number 1 Report Start Date 3/25/2025 Report End Date 3/26/2025 Last 24hr Summary YJ EL PJSM and PTW. MIRU. PT PCE to 250/3500 psi. RIH w/ 1-11/16" Cable head, 2" WB, 1-11/16" GPT, 2.80" GR Junk basket. OAL 22.3'. T/I/O 40/0/100 psi. Fluid level @ 3674'. Tag @ 3823' MD. Target depth for CIBP 3830'. RIH w/ 1-3/4" spangs and 2.50" x 13' pump bailer. Bail thru bridge to 3839' MD. POH. RBIH w/ 1 -11/16" GPT, 2.80" GR Junk basket. Fluid level @ 3674'. Tag @ 3834'. PU to 3500'. Cool Down N2 and PT to 3500 psi. Pressure up Tbg to 3500 psi (4000 psi @ tool) SD @ 63K SCF away. RIH w/ GPT. FL unchanged @ 3674'. POH. PT N2 pump to 4500 psi. Pressure up Tbg to 4000 psi. No break-over. 73K SCF away. SD to see if fluid will depress overnight. Witness waived by Jim Regg. Report Number 2 Report Start Date 3/26/2025 Report End Date 3/27/2025 Last 24hr Summary PTW, JSA with crew. WHP (N2 pressure) 3900 psi. 100 psi drop from 4000 psi applied 12 hours prior to push fluids away. Make up lubricator. RIH with GPT. Fluid level 3684'. Tagged 3829'. MU 2.75" OD (3.5" CIBP). RIH WHP 3900 psi. Stack weight 3827' End of tool string. Need to set CIBP at 3830'. 3' to shallow. POOH discuss with town engineer. Bleed 3900 psi of N2 off to bleed tank. RIH wtih 2.5" bailer. Tagged fill at 3828'. Work bailer down to 3836' . PIck up is sticky 500-800 lbs ove pull. POOH to check bailer. Bailer body 3/4 full. Fine silt/sand and sludge. RIH wtih 2.75' CIBP Set at 3830'. Pick up off plug and tag top of CIBP. Good set. POOH. Make up cement dump bailer. Make 2 cement dump runs total of 5.5 gallons. 5.5 gallons = 15' of cement inside 3.5" tubing. Cool down N2 pump. Pressure up tubing, CIBP and 15' of cement to 2000 psi. Start 72 hr. clock with crystal guage recording. Test criteria: less than 2% drop in 72 hrs. Jim Regg updated on delay of test start orignally submitted for 3/25/25 when witness was waived. Report Number 3 Report Start Date 3/28/2025 Report End Date 3/29/2025 Last 24hr Summary Pressure drop on MIT higher than expected. Leak found on wellhead fitting going to the crystal gauge. Tighetend fitting to stop leak. Discovered that IA was not recording, hooked up IA to crystal gauge and confirmed recording. Restart 72 hour N2 test @ 18:07 T/I/O = 2443/0.8/72 psi. Report Number 4 Report Start Date 3/29/2025 Report End Date 3/29/2025 Last 24hr Summary Update cost Report Number 5 Report Start Date 3/31/2025 Report End Date 3/31/2025 Last 24hr Summary 72 hour MIT completed @ 18:07 T/I/O = 2429/1.2/72 psi PASSED. Leave gauge and pressure on well for scheduled witness 4/1/2025 @ 12:00 Report Number 6 Report Start Date 4/1/2025 Report End Date 4/1/2025 Last 24hr Summary PTW/PJSM, SITP 2400psi. R/u pollard SL, PT Lubricator 250-2500psi. RIH w/2.79" gauge ring and tag TOC at 3,811KB. POOH. Tag witness by AOGCC Inspector Sean Sullivan. Download 72hr MIT, good test. Bled tbg to 0psi. Swabbed well dry, recovering ~40gals. RDMO SL. Report Number 7 Report Start Date 4/2/2025 Report End Date 4/2/2025 Last 24hr Summary PTW, JSA with Yellow Jacket E-line services. MIRU E-line unit with 9/32" wire. Make up lubricator and WIreline valves. Production pressure up well to 130 psi. Stab on well with lubricator and 30' gun. Pressure test 250 low 2500 hgih. Good test. POp off well. Lay down gun and hook up GPT. RIH no indication of fluid. Sent log to town. Tagged TOC at 3805'. Previous tag from slick line was 3811'. Make up 2 3/8" Gun loaded with Razor charges 11 grams. 60* phasing. 30'. for shooting A11 sands from 3772'-3802.' RIH pull correlation pass and send to town. on depth. Park CCL at 3762' WHP 130 psi. ON depth 700 lbs line weight. Shot gun. Gun blew up hole. Stuck at 3660' roughly 100' above shot depth. Work line up to max pull 5000 lbs. Called out pollard for Kinley cutter. Dropped first kinley cutter. NO action. Attempt to work line. Call out second cutter and drop. NO intial cut. WOrk line and cut while overpulling 3000 lbs. POOH with wire. tagged up at 1065' from surfac. Close wire line valves. FOund 2nd cutter bar 1065' from surface. Strip wire and pull thorugh grease tubres. Spool OOH. Tagged up. E-line toolstring and one cutter bar remain in hole. RDMO SLick line and .160 wire to fish in the am. Report Number 8 Report Start Date 4/3/2025 Report End Date 4/3/2025 Last 24hr Summary Bail fill from 3580' to 3585'kb no sign of wire marks on bottom witness by AOGCC Inspector,pp, Sean Sullivan. Download 72hr MIT, good test. 2 cement dump runs total of 5.5 gallons. 5.5 gallons = 15' of cement inside 3.5" tubing Sy 72 hour MIT completed @ 18:07 T/I/O = 2429/1.2/72 psi PASSED. RIH wtih 2.75' CIBP Set at 3830'. Shot gun. Gun blew up hole Page 2/2 Well Name: KEU KBU 24-06RD Report Printed: 4/23/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 9 Report Start Date 4/4/2025 Report End Date 4/4/2025 Last 24hr Summary Bail doewn to fish, fish E-Line and Kinley Cutter Report Number 10 Report Start Date 4/8/2025 Report End Date 4/9/2025 Last 24hr Summary PTW, JSA with YJES. Rig up E-line unit Stab on well. PT stack 250/3500 psi. RIH with GPT for fluid level and tag. Found fluid 120' from surface. Tagged sand/fill at 3746'. Pressured up Tubing with N2. 3000 psi. NO break over. GPT still showing fluid 120'. RU CIBP. RIH pulll correlation log and send to town. ON depth. Set plug at 3744'. RDMO. Report Number 11 Report Start Date 4/14/2025 Report End Date 4/14/2025 Last 24hr Summary SL MIRU. PT Lub 250/2500psi. Swabbed fluid from 60'KB to 3710'KB Report Number 12 Report Start Date 4/16/2025 Report End Date 4/17/2025 Last 24hr Summary PTW/PJSM, MIRU YJ Eline, PT 250/2500. Perforated Sterling A-10 from 3718'-3738'Perforated Sterling A-10 from 3718'-3738' Set plug at 3744'. _____________________________________________________________________________________ Updated by DMA 05-01-25 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Kenai Gas Field Well: KBU 24-6RD Completion as of 6/15/15 API: 50-133-20499-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surface 107' 13-3/8"Surface 68 / K-55 / BTC 12.415 Surface 1,518' 9-5/8"Intermediate 40 / L-80 / BTC-MOD 8.835 Surface 3,768’ 3-1/2"Production 9.3 / L-80 / EUE 8rd 2.992 Surface 7,812' EXCAPE SYSTEM DETAILS -13 Conventional modules -Red control line fired modules 8 thru 13. -Yellow control line fires top 8 modules. -Green line for BHP monitoring. - Ceramic flapper valves below each module except Module 1. CEMENTING DETAIL Casing Detail 13-38"17 1/2" hole Cmt w/ 608 sks, Class G 9-5/8"12-1/4" hole Cmt w/ 1,005 sks of Class G 8-1/2"8-1/2" hole Cmt w/ 267 sks (102 bbls) of 12.7 ppg, Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail Module Top (MD)Btm (MD)Top (TVD)Btm (TVD)Zone 13 5,520'5,530'5,328'5,338'Beluga 12 5,570'5,580'5,377'5,387'Beluga 11 5,746'5,756'5,547'5,557'Beluga 10 5,788'5,798'5,588'5,598'Beluga 9 5,929'5,939'5,727'5,737'Beluga 8 6,200'6,210'5,996'6,006'Beluga 7 6,308'6,318'6,104'6,114'Beluga 6 6,360'6,370'6,156'6,166'Beluga 5 6,572'6,582'6,368'6,378'Beluga 4 6,700'6,710'6,496'6,506'Beluga 3 6,860'6,870'6,656'6,666'Beluga 2 7,028'7,038'6,824'6,834'Beluga 1 7,466'7,476'6,997'7,007'Tyonek Flapper Depth (MD) Detail No.Depth Item 13 5,545'Conventional Module 12 5,595'Conventional Module 11 5,771'Conventional Module 10 5,813'Conventional Module 9 5,954'Conventional Module 8 6,225'Conventional Module 7 6,333'Conventional Module 6 6,385'Conventional Module 5 6,597'Conventional Module 4 6,726'Conventional Module 3 6,885'Conventional Module 2 7,053'Conventional Module 1 Unknown Conventional Module - No Flapper Sidetrack Window: Milled From 3,752' MD to 3,768' MD Max Inclination 22.2° @ 3,964’ PERFORATION DATA Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Ftg Date Status Notes A10 3,718’3,738’3,635’3,653’20 4/16/25 Open 2-3/8” Razor HC A11 3,772'3,802'3,685’3,713’30 4/2/25 Isolated 2-3/8” Razor HC B1 3,836’3,846’3,746’3,755’43 4/22/20 Isolated 2-3/8” Razor HC UB_3 4,995’5,020’4,830’ 4,854’25 1/10/20 Isolated 2-3/8” Razor HC UB_5A 5,186’5,194’5,010’ 5,018’8 1/3/20 Isolated 2-3/8 Geo HC UB5 5,217’5,247’5,040’ 5,068’30 6/15/15 Isolated 2-1/2” ConneX UB_7 5,282’5,289’5,101’ 5,108’7 1/3/20 Isolated 2-3/8 Geo HC UB_7A 5,325’5,337’5,142’ 5,154’12 1/3/20 Isolated 2-3/8 Geo HC 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 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): 7,830'7,744' Casing Collapse Structural Conductor Surface 1,950 psi Intermediate 3,090 psi Production 10,530 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 AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: 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 stefan.reed@hilcorp.com 206-518-0400 Noel Nocas, Operations Manager 907-564-5278 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 Stefan Reed, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 206-013 50-133-20499-01-00 Hilcorp Alaska, LLC Proposed Pools: N/A TVD Burst N/A 10,160 psi 1,484' Size 86' 9-5/8"3,661' 1,463' MD See Attached Schematic 5,750 psi 3,450 psi 107' 3,682' 107' 1,518' March 11, 2025 N/A 7,812' Perforation Depth MD (ft): 3,768' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Beluga Unit (KBU) 24-06RDCO 510C Sterling 3 Gas Pool 7,608'3-1/2" ~ 1,189 psi 7,791' 4,965' Length N/A; N/A N/A; N/A 7,626'4,930'4,768' Kenai Sterling 3 & 4 Gas Pools 20" 13-3/8" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-113 By Gavin Gluyas at 10:27 am, Feb 28, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.02.28 10:11:47 - 09'00' Noel Nocas (4361) BJM 3/21/25 DSR-2/28/25A.Dewhurst 03MAR25 10-404 X Variance to 20 AAC 25.112(c)(1)(e) conditionally approved. Conditions of approval are: 1. Dump bail a minimum of 15 feet of cement on top of CIBP. 2. Verify plug integrity by testing with Nitrogen to 2000 psi for 72 hrs with <2% pressure drop. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.24 10:07:55 -08'00'03/24/25 RBDMS JSB 032525 Adperf Rev.2 Well: KBU 24-06RD Date: 2/14/2025 Well Name: KBU 24-06RD API Number: 50-133-20499-01-00 Current Status: Shut-In Gas Well Permit to Drill Number: 206-013 First Call Engineer: Stefan Reed (206) 518-0400 Second Call Engineer: Chad Helgeson (907) 229-4824 Maximum Expected BHP: ~1549 psi @ 3,603’ TVD (Based on 0.43psi/ft gradient) Max. Potential Surface Pressure: ~ 1,189 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.52psi/ft using 10ppg EMW FIT at the ST window 2/25/2006 Shallowest Potential Perf TVD: 1189 psi/(0.52-0.1) =2831’ TVD Top of Pools per CO 510C: Kenai Sterling Gas Pool 3: 3199’ MD, 3149’ TVD Brief Well Summary Kenai Beluga Unit #24-06RD was drilled as a sidetrack EXCAPE completion in 2006 to target gas sands in the Beluga formations. The initial EXCAPE modules were placed on production in May 2006. A capillary string was installed in August 2009, the depth was adjusted in November 2009 and pulled in October 2012. The well loaded up in April 2014 and has been unable to sustain flow. In 2015, the existing EXCAPE perforations were plugged back and the UB-5 was perforated. In January 2020 the UB5A and UB3 were shot and watered out the well. In 2020 the lower UB perforations were isolated and the B1 sands were perforated. The well came online strong and produced ~600-700mscfd until it watered out in 2022. The purpose of this work is to isolate the B1(Pool 4) sands and perforate the A11 and A10 (Pool 3) sands. Hilcorp request a waiver from regulation 20 AAC 25.112(c)(1)(E) to dump bail less than 25’ of cement. The distance between the top of the existing perforations and the bottom of proposed perforations is 28’ MD. Dumping less cement will allow some tolerance in plug set depth and final cement top to proposed perforations. Notes Regarding Wellbore Condition x Last intervention slickline drifted w/ 2.84” GR, tagged fill @ 3850’ Slickline/Eline Procedure 1. MIRU, Pressure test PCE 250psi low / 2500 psi High. 2. Drift to TD w/ 2.80” GR. Look for fluid level and confirm tag depth is below proposed perforations a. If adequate depth is not reached discuss with OE and bail fill as needed. E-Line Procedure 1. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 2. Run GPT to confirm fluid level and use gas/N2 to push away as needed. 3. RIH and set 3-1/2” CIBP @ ~3,380’. 4. Dump bail 10’ (~4gals) of cement on plug 5. RIH tag TOC and pressure test w/ nitrogen to 2000psi. a. Using a chart recorder or digital crystal gauge monitor the pressure for a minimum of 2hrs. Set at 3830' MD per Stefan Reed. -bjm 72 hrs. -bjm Adperf Rev.2 Well: KBU 24-06RD Date: 2/14/2025 b. Criteria for passing test being a time of 2 hours showing stabilization and less than 10% drop of the maximum test pressure over the 2 hour test period. c. 2-hr test will start once pressure stabilizes. d. Provide minimum 24hr notice to AOGCC to witness tag and test. 6. PU 2-3/8” perf guns and perforate proposed intervals bottoms up, testing each sand as desired by RE/GEO. Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Sterling A10 (Pool 3) +3,698' +3,738' +3,529' +3,567' 40’ Sterling A11 (Pool 3) +3,778' +3,808' +3,603’ +3,632’ 30' 7. Make correlation pass and send log in to operations engineer, reservoir engineer and geologist. a. Record initial 5/10/15 minute tubing pressures after firing. b. Above perfs will be shot in the Kenai Sterling Gas Pool 3 governed by CO 510C 8. Reperf zones at RE/GEO discretion. 9. POOH 10. RD E-Line. 11. Turn well over to production. Eline Procedure (Contingency) If any zone produces sand and/or water or needs to be isolated: 12. MIRU Eline 13. Pressure test equipment 250psi low/3,500psi High 14. Run GPT to find fluid level 15. RU N2 or use gas and push fluid below perfs (verify fluid depth w/ GPT) 16. Set 3-1/2” CIBP to isolate zone. Attachments 1. Actual Schematic 2. Proposed Schematic 3. CBL Log Header/Section 4. Neo Cement Calculation 5. Standard Well Procedure – N2 Operations 72-hr test Criteria for passing test is <2% pressure drop in 72 hrs. -bjm _____________________________________________________________________________________ Updated by DMA 05-14-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Kenai Gas Field Well: KBU 24-6RD Completion as of 6/15/15 API: 50-133-20499-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surface 107' 13-3/8"Surface 68 / K-55 / BTC 12.415 Surface 1,518' 9-5/8"Intermediate 40 / L-80 / BTC-MOD 8.835 Surface 5,489' 3-1/2"Production 9.3 / L-80 / EUE 8rd 2.992 Surface 7,812' EXCAPE SYSTEM DETAILS -13 Conventional modules -Red control line fired modules 8 thru 13. -Yellow control line fires top 8 modules. -Green line for BHP monitoring. - Ceramic flapper valves below each module except Module 1. CEMENTING DETAIL Casing Detail 13-38"17 1/2" hole Cmt w/ 608 sks, Class G 9-5/8"12-1/4" hole Cmt w/ 1,005 sks of Class G 8-1/2"8-1/2" hole Cmt w/ 267 sks (102 bbls) of 12.7 ppg, Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail Module Top (MD)Btm (MD)Top (TVD)Btm (TVD)Zone 13 5,520'5,530'5,328'5,338'Beluga 12 5,570'5,580'5,377'5,387'Beluga 11 5,746'5,756'5,547'5,557'Beluga 10 5,788'5,798'5,588'5,598'Beluga 9 5,929'5,939'5,727'5,737'Beluga 8 6,200'6,210'5,996'6,006'Beluga 7 6,308'6,318'6,104'6,114'Beluga 6 6,360'6,370'6,156'6,166'Beluga 5 6,572'6,582'6,368'6,378'Beluga 4 6,700'6,710'6,496'6,506'Beluga 3 6,860'6,870'6,656'6,666'Beluga 2 7,028'7,038'6,824'6,834'Beluga 1 7,466'7,476'6,997'7,007'Tyonek Flapper Depth (MD) Detail No.Depth Item 13 5,545'Conventional Module 12 5,595'Conventional Module 11 5,771'Conventional Module 10 5,813'Conventional Module 9 5,954'Conventional Module 8 6,225'Conventional Module 7 6,333'Conventional Module 6 6,385'Conventional Module 5 6,597'Conventional Module 4 6,726'Conventional Module 3 6,885'Conventional Module 2 7,053'Conventional Module 1 Unknown Conventional Module - No Flapper Sidetrack Window: Milled From 3,752' MD to 3,768' MD Max Inclination 22.2° @ 3,964’ PERFORATION DATA Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Ftg Date Status Notes B1 3,836’3,846’3,746’3,755’43 4/22/20 Open 2-3/8” Razor HC UB_3 4,995’5,020’4,830’ 4,854’25 1/10/20 Isolated 2-3/8” Razor HC UB_5A 5,186’5,194’5,010’ 5,018’8 1/3/20 Isolated 2-3/8 Geo HC UB5 5,217’5,247’5,040’ 5,068’30 6/15/15 Isolated 2-1/2” ConneX UB_7 5,282’5,289’5,101’ 5,108’7 1/3/20 Isolated 2-3/8 Geo HC UB_7A 5,325’5,337’5,142’ 5,154’12 1/3/20 Isolated 2-3/8 Geo HC _____________________________________________________________________________________ Updated by SAR 02-21-25 PROPOSED Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Kenai Gas Field Well: KBU 24-6RD Completion as of 6/15/15 API: 50-133-20499-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surface 107' 13-3/8"Surface 68 / K-55 / BTC 12.415 Surface 1,518' 9-5/8"Intermediate 40 / L-80 / BTC-MOD 8.835 Surface 5,489' 3-1/2"Production 9.3 / L-80 / EUE 8rd 2.992 Surface 7,812' EXCAPE SYSTEM DETAILS -13 Conventional modules -Red control line fired modules 8 thru 13. -Yellow control line fires top 8 modules. -Green line for BHP monitoring. - Ceramic flapper valves below each module except Module 1. CEMENTING DETAIL Casing Detail 13-38"17 1/2" hole Cmt w/ 608 sks, Class G 9-5/8"12-1/4" hole Cmt w/ 1,005 sks of Class G 8-1/2"8-1/2" hole Cmt w/ 267 sks (102 bbls) of 12.7 ppg, Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail Module Top (MD)Btm (MD)Top (TVD)Btm (TVD)Zone 13 5,520'5,530'5,328'5,338'Beluga 12 5,570'5,580'5,377'5,387'Beluga 11 5,746'5,756'5,547'5,557'Beluga 10 5,788'5,798'5,588'5,598'Beluga 9 5,929'5,939'5,727'5,737'Beluga 8 6,200'6,210'5,996'6,006'Beluga 7 6,308'6,318'6,104'6,114'Beluga 6 6,360'6,370'6,156'6,166'Beluga 5 6,572'6,582'6,368'6,378'Beluga 4 6,700'6,710'6,496'6,506'Beluga 3 6,860'6,870'6,656'6,666'Beluga 2 7,028'7,038'6,824'6,834'Beluga 1 7,466'7,476'6,997'7,007'Tyonek Flapper Depth (MD) Detail No.Depth Item 13 5,545'Conventional Module 12 5,595'Conventional Module 11 5,771'Conventional Module 10 5,813'Conventional Module 9 5,954'Conventional Module 8 6,225'Conventional Module 7 6,333'Conventional Module 6 6,385'Conventional Module 5 6,597'Conventional Module 4 6,726'Conventional Module 3 6,885'Conventional Module 2 7,053'Conventional Module 1 Unknown Conventional Module - No Flapper Sidetrack Window: Milled From 3,752' MD to 3,768' MD Max Inclination 22.2° @ 3,964’ PERFORATION DATA Zone Top(MD)Btm(MD)Top(TVD)Btm(TVD)Ftg Date Status Notes A10 +3,698'+3,738'+3,529'+3,567'40 TBD TBD TBD A11 +3,778'+3,808'+3,603’+3,632’30 TBD TBD TBD B1 3,836’3,846’3,746’3,755’43 4/22/20 Isolated 2-3/8” Razor HC UB_3 4,995’5,020’4,830’ 4,854’25 1/10/20 Isolated 2-3/8” Razor HC UB_5A 5,186’5,194’5,010’ 5,018’8 1/3/20 Isolated 2-3/8 Geo HC UB5 5,217’5,247’5,040’ 5,068’30 6/15/15 Isolated 2-1/2” ConneX UB_7 5,282’5,289’5,101’ 5,108’7 1/3/20 Isolated 2-3/8 Geo HC UB_7A 5,325’5,337’5,142’ 5,154’12 1/3/20 Isolated 2-3/8 Geo HC 3-1/2” CIBP @ ~3,380’ w/ 10’ of cement CIBP @ 3830' md -bjm NeoProducts Plug Length Calculations Inputs Differential Pressure 5200 psi CSG Size 3.5 in CSG Weight 9.3 lb/ft Well Deviation 20 ° Bailer Length 20 ft Bailer Size 2 in Temperature Range 70-99 °F Cement Type Gray Lid Outputs ~I.D. 2.974 in Volume of Cement 3.6 gal Cement Kits 1 kits Number of Runs 2 runs Cement Plug Length 10.11 ft 2/21/2025, 1:50:15 PM 2/21/25, 1:50 PM NeoProducts Plug Length Calculations about:blank 1/1 STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 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: N2 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 7,830 feet 5,260 feet true vertical 7,626 feet 7,744 feet Effective Depth measured 5,260 feet N/A feet true vertical 5,080 feet N/A feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)N/A; N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 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: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 10,160psi 107' 1,484' 3,682' 7,608' 5,750psi 3,450psi Collapse 1,859psi 3,090psi 10,530psi Casing Structural 20" 13-3/8" 9-5/8" Length 86' 1,463' 3,661' 7,791' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 36 Casing Pressure Liner 561 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-134 79 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 32 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 206-013 50-133-20499-01-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 00 Kenai Bleluga Unit (KBU) 24-06RD N/A FEDA028142 3,768' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Gas Field - Sterling Gas Pool 3 & Sterling Gas Pool 4N/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 3-1/2"7,812' WINJ WAG 0 Water-Bbl MD 107' 1,518' 0 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 8:57 am, May 26, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.05.22 17:03:53 -08'00' Taylor Wellman Plug Perforations RBDMS HEW 5/26/2020 Perforate New Pool DSR-5/26/2020gls 5/27/20 N2 561 Rig Start Date End Date E-Line 4/20/20 4/22/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 24-06RD 50-133-20499-01-00 206-013 04/20/2020 - Monday Sign in. Mobe to location. PTW, JSA and SIMOPS with AKE-Line and SLB N2. Rig up lubricator and N2 hard lines. N2 truck ruptured a rubber seal and had to replace. PT hard lines and lubricator to 250 psi low and 3,000 psi high. Opened well to let lubricator N2 go down well but pressure just dropped to 2,900 psi. I figured we had an ice plug. Bled tubing down to 1,300 psi and stopped. Bled lubricator to 0 psi and opened well back up and it went back to 1,300 psi. Decided to run tools and check for ice plug and fluid level. RIH w/GPT tool found fluid level at 494'. Slickline found it at 2,550' when they were bailing in Jan of this year. It had 750 psi on tubing then and today it had 20 psi on tubing. Decided to go down and see where we tag at. We correlated to Jan 2020 perf log and tagged at 4,966'. That is 29' higher than top of open perf at 4,995'. Ran a correlation log and send to town. Town said it was on depth. POOH. Had a discussion with town and decision was made to go ahead and set plug/dump 35' of cement. Then have slickline come out and swab fluid out of well. RIH w/CCL/GR, 2.74" CIBP and tie into GPT log. Tag at 4,966' and run correlation log. Pick up to 4,965' and attempt to set plug. Didn't see any weight change or the detonator break. Waited 15 min to be sure and pulled out of hole. Trouble shot plug and found the detonator show open circuit. Checked everything else and replace detonator RIH w/CCL/GR, 2.74" CIBP and tie into GPT log. Tag at 4,966' and run correlation log. Pick up to 4,965' and set plug with 600 psi on tubing. Lost 150 lbs of line tension when plug set. Pick up 30' and go back and tag plug. POOH. Setting tool look good. Good set. RIH w/ 2.5" x 30' Dump bailer (Dumps 17.5' of 16 lb cement in 3-1/2" tubing) and CCL. Tie into GPT log and tag plug at 4,965', Pick up to 4,946' and dump bail 17.5' of 16 lb cement on top of plug. Saw weight drop off. POOH. Good dump RIH w/ 2.5" x 30' dump bailer (Dumps 17.5' of 16 lb cement in 3-1/2" tubing) and CCL. Tie into GPT log. Dump bail 17.5' of 16 lb cement on top of cement already dumped at 4,947.5' . Saw weight drop off. POOH. Good dump. Est TOC - 4,930'. CIP - 2200 hrs. Rig down equipment and secure well. Slickline will be here at 0700 hrs. We will be moving the E-Line equipment out of the way. Will be perforating KBU 41-07 with this equipment tomorrow morning showing up at 0900 hrs. E-Line has about 30 min of work at their shop before they can go home for some sleep. 04/22/2020 - Wednesday PTW, JSA and SIMOPS w/AKE-line and SLB N2. Spot and rig up hard lines and lubricator. PT to 250 psi low and 3,000 psi high. 0 psi on tubing, RIH w/ 2-3/8" x 10' Razor HC, 6 spf and 60 deg phase and tie into OHL. Pressure tubing up to 1,000 psi with N2. Run correlation strip and send to town.- Get ok to perf from 3,836' to 3,846' with 980 psi on tubing. Spotted and fired gun and pressure immediately started dropping. After 5 min - 845.3 psi, 10 min - 710.2 psi and 15 min - 608.4 psi. POOH. All shots fired and gun was dry. Rig down lubricator and turn well over to field. Daily Operations: IA (3.5" x 9.625")was tested to 1500 psi before and after perforating the B1 sand. gls RIH w/GPT tool found fluid level at 494'. Slickline f H w/ 2.5" x 30' Dump bailer (Dumps 17.5' of 16 lb cement in 3-1/2" tubing) and CCL. f RIH w/CCL/GR, 2.74" CIBP and tie into GPT log. T o perf from 3,836' to 3,846' CIBP AT 4965 FT Est TOC - 4,930' k up to 4,965' _____________________________________________________________________________________ Updated by DMA 05-14-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Kenai Gas Field Well: KBU 24-6RD Completion as of 6/15/15 API: 50-133-20499-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133 / K-55 / N/A 18.73 Surface 107' 13-3/8" Surface 68 / K-55 / BTC 12.415 Surface 1,518' 9-5/8" Intermediate 40 / L-80 / BTC-MOD 8.835 Surface 5,489' 3-1/2" Production 9.3 / L-80 / EUE 8rd 2.992 Surface 7,812' EXCAPE SYSTEM DETAILS -13 Conventional modules - Red control line fired modules 8 thru 13. - Yellow control line fires top 8 modules. - Green line for BHP monitoring. - Ceramic flapper valves below each module except Module 1. CEMENTING DETAIL Casing Detail 13-38" 17 1/2" hole Cmt w/ 608 sks, Class G 9-5/8" 12-1/4" hole Cmt w/ 1,005 sks of Class G 8-1/2" 8-1/2" hole Cmt w/ 267 sks (102 bbls) of 12.7 ppg, Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail Module Top (MD) Btm (MD) Top (TVD) Btm (TVD) Zone 13 5,520' 5,530' 5,328' 5,338' Beluga 12 5,570' 5,580' 5,377' 5,387' Beluga 11 5,746' 5,756' 5,547' 5,557' Beluga 10 5,788' 5,798' 5,588' 5,598' Beluga 9 5,929' 5,939' 5,727' 5,737' Beluga 8 6,200' 6,210' 5,996' 6,006' Beluga 7 6,308' 6,318' 6,104' 6,114' Beluga 6 6,360' 6,370' 6,156' 6,166' Beluga 5 6,572' 6,582' 6,368' 6,378' Beluga 4 6,700' 6,710' 6,496' 6,506' Beluga 3 6,860' 6,870' 6,656' 6,666' Beluga 2 7,028' 7,038' 6,824' 6,834' Beluga 1 7,466' 7,476' 6,997' 7,007' Tyonek Flapper Depth (MD) Detail No. Depth Item 13 5,545' Conventional Module 12 5,595' Conventional Module 11 5,771' Conventional Module 10 5,813' Conventional Module 9 5,954' Conventional Module 8 6,225' Conventional Module 7 6,333' Conventional Module 6 6,385' Conventional Module 5 6,597' Conventional Module 4 6,726' Conventional Module 3 6,885' Conventional Module 2 7,053' Conventional Module 1 Unknown Conventional Module - No Flapper Sidetrack Window: Milled From 3,752' MD to 3,768' MD Max Inclination 22.2° @ 3,964’ PERFORATION DATA Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Ftg Date Status Notes B1 3,836’ 3,846’ 3,746’ 3,755’ 43 4/22/20 Open 2-3/8” Razor HC UB_3 4,995’ 5,020’ 4,830’ 4,854’ 25 1/10/20 Isolated 2-3/8” Razor HC UB_5A 5,186’ 5,194’ 5,010’ 5,018’ 8 1/3/20 Isolated 2-3/8 Geo HC UB5 5,217’ 5,247’ 5,040’ 5,068’ 30 6/15/15 Isolated 2-1/2” ConneX UB_7 5,282’ 5,289’ 5,101’ 5,108’ 7 1/3/20 Isolated 2-3/8 Geo HC UB_7A 5,325’ 5,337’ 5,142’ 5,154’ 12 1/3/20 Isolated 2-3/8 Geo HC NOTE: MIT-IA to 1500 psi pre/post perfs. Zone Top(MD) Btm(MD)Top(TVD)Btm(TVD) Ftg Date Status Notes B1 3,836’ 3,846’3,746’3,755’43 4/22/20 Open 2-3/8” Razor HC 1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7,830'7,744' Casing Collapse Structural Conductor Surface 1,950 psi Intermediate 3,090 psi Production 10,530 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 Taylor Wellman 777-8449 Contact Name: Christina Twogood Operations Manager Contact Email: Contact Phone: 777-8443 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 ctwogood@hilcorp.com 7,626'5,260'5,080'~ 892 psi 5,260' N/A; N/A N/A;, N/A Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 206-013 50-133-20499-01-00 Kenai Beluga Unit (KBU) 24-06RD Length Size CO 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 Kenai Gas Field Sterling Gas Pool 3 & Sterling Gas Pool 4 PRESENT WELL CONDITION SUMMARY N/A TVD Burst N/A 10,160 psi MD 5,750 psi 3,450 psi 107' 1,484' 3,682' 107' 1,518' 7,608'3-1/2" 20" 13-3/8" 86' 9-5/8"3,661' 1,463' 7,812' Perforation Depth MD (ft): 3,768' See Attached Schematic 7,791' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: April 8, 2020 N/A m n P t 66 Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.03.25 18:55:54 -05'00' Taylor Wellman By Jody Colombie at 4:27 pm, Mar 25, 2020 320-134 SDF 4/2/2020 SFD 4/2/20 DSR-3/25/2020 X DLB 03/26/20 10-404 x gls 4/2/20 MIT-IA to 1500 psi before and after upper A11 perforations are added. Required? Yes No Comm. 4/6/2020 dts 4/2/2020 JLC 4/6/2020 Well Prognosis Well: KBU 24-06RD Date: 3/24/2020 Well Name: KBU 24-06RD API Number: 50-133-20499-01-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: April 8th, 2020 Rig: E-Line Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-013 First Call Engineer: Christina Twogood (907)777-8443 (O)(907)378-7323 (M) Second Call Engineer: Ted Kramer (907)777-8420 (O)(985)867-0665 (M) AFE Number: Current BHP: ~ 300 psi @ 3,770’ TVD (Based on 2017 offset well RFT data) Max. Expected BHP: ~ 1,423 psi @ 5,328’ TVD (Based on 2017 offset well RFT data) Max. Allowable Surface Pressure: ~ 892 psi (Based on expected BHP and gas gradient to surface (0.10psi/ft)) Brief Well Summary Kenai Beluga Unit #24-06RD was drilled as a sidetrack EXCAPE completion in 2006 to target gas sands in the Beluga formations. The initial EXCAPE modules were placed on production in May 2006. A capillary string was installed in August 2009, the depth was adjusted in November 2009 and pulled in October 2012. The well loaded up in April 2014 and has been unable to sustain flow. In 2015, the existing EXCAPE perforations were plugged back and the UB-5 was perforated. In January 2020 the UB5A and UB3 were shot and watered out the well. The purpose of this work/sundry is to perforate the Sterling A11 and B1 sands. Notes Regarding Wellbore Condition x The well is currently producing 650 MCFD. x Last tag at 5,428’ RKB on 07/03/15 with a 1.87” GR. 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 nitrogen during this job). x Ensure all crews are aware of stop job authority. E-Line Procedure 1.MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 1,500 psi High. 2.RIH with GPT tool and find fluid level. If fluid level is over the depth of the new perfs, discuss using Nitrogen with the Operations Engineer. 3.If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 4.RIH with 3-1/2” CIBP and set at +4,975’. Dump bail 35’ cement on top. POOH. The purpose of this work/sundry is to perforate the Sterling A11 and B1 sands. NOTE: plug perfs MIT-IA to 1500 psi before and after adding perforations to verify no channel to top set of A-11 perfs. ( notify AOGCC of results) Well Prognosis Well: KBU 24-06RD Date: 3/24/2020 5.RU perf guns. 6.RIH and perforate the following intervals: Zone Sand Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Sterling A11 (Pool 3) +3,785'+3,807'+3,699'+3,718'22' Sterling B1 (Pool 4) +3,836'+3,879'+3,746'+3,786'43' a.Pressure up well to 1,000 psi before perforating. b.Proposed perfs also shown on the proposed schematic in red font. c.Final Perfs tie-in sheet will be provided in the field for exact perf intervals. d.Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer and Geologist for confirmation. a.There is a CBL Log dated 4/02/06 (CBL Tie-in log) that may be used if requested by Reservoir Engineer and/or Geologist. e.Use Gamma/CCL/ to correlate. f.Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g.All perforations in table above are located in the Sterling Gas Pool 3 and Sterling Gas Pool 4 based on Conservation Order No. 510A. h.A 3-1/2” Casing Patch or CIBP will be set to isolate the perforations in Pool 4 from the perforations in Pool 3 prior to perforating Pool 3. 7. POOH. 8.RD E-Line. 9.Turn well over to production. (Test SSV within 5 days of stable production on well – notify AOGCC 24 hours before testing). E-Line Procedure (Contingency) 1.If the zone in Pool 3 produces sand and/or water or needs isolated: 2.MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 1,500 psi High. 3.RIH and set 3-1/2” Casing Patch or set 3-1/2” CIBP above the zone and dump 35’ of cement on top of the plug. Attachments 1.Actual Schematic 2.Proposed Schematic 3.Standard Well Procedure – N2 Operations All perforations in table above are located in the Sterling Gas Pool 3 and Sterling Gas Pool 4 based on Conservation Order No. 510A. _____________________________________________________________________________________ Updated by DMA 01-20-20 SCHEMATIC Cook Inlet Basin, Alaska Middl G d Sh l Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform ______________ Kenai Gas Field Well: KBU 24-6RDCook Inlet BasinCook Inlet Basin Completion as of 6/15/15 Middle Ground Shoal Middle Ground Shoal CAPI: 50Last Last Oil WelOil Wel -133ComCom >Wat>Wat-pp20pletplet er iner in 4tete jee99ed: ed: ctorctor-0102-02- >G>G-0028-128-1 as pas p TD = 7,830’ MD/ 7,626’ TVD PBTD = 5,443’ MD / 5,255’ TVD RKB=87’/21’AGL 2 3 11 9-5/8” Window 6 7 8 9 10 12 13-3/8” Tagged 7,744’ CTMD w/ 1-1/2” Coil 2/24/2014. 4 5 20” 13 TOC @3,630’ MD -122’ above top of window opening -1,859’ above 9-5/8” casing shoe. UB-5A TOC 5,443’ CIPB 5,470’ UB-3 UB-5 UB-7 UB-7A CIPB 5,260’ 1/10/20 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surface 107' 13-3/8"Surface 68 / K-55 / BTC 12.415 Surface 1,518' 9-5/8"Intermediate 40 /L-80 / BTC-MOD 8.835 Surface 5,489' 3-1/2"Production9.3 / L-80 / EUE 8rd 2.992 Surface 7,812' EXCAPE SYSTEM DETAILS -13 Conventional modules - Red control line fired modules 8 thru 13. - Yellow control line fires top 8 modules. - Green line for BHP monitoring. - Ceramic flapper valves below each module except Module 1. CEMENTING DETAIL Casing Detail 13-38"17 1/2" hole Cmt w/ 608 sks, Class G 9-5/8"12-1/4" hole Cmt w/ 1,005 sks of Class G 8-1/2"8-1/2" hole Cmt w/ 267 sks (102 bbls) of 12.7 ppg, Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail Module Top (MD) Btm (MD) Top (TVD) Btm (TVD) Zone 13 5,520'5,530'5,328'5,338'Beluga 12 5,570'5,580'5,377'5,387'Beluga 11 5,746'5,756'5,547'5,557'Beluga 10 5,788'5,798'5,588'5,598'Beluga 9 5,929'5,939'5,727'5,737'Beluga 8 6,200'6,210'5,996'6,006'Beluga 7 6,308'6,318'6,104'6,114'Beluga 6 6,360'6,370'6,156'6,166'Beluga 5 6,572'6,582'6,368'6,378'Beluga 4 6,700'6,710'6,496'6,506'Beluga 3 6,860'6,870'6,656'6,666'Beluga 2 7,028'7,038'6,824'6,834'Beluga 1 7,466'7,476'6,997'7,007'Tyonek Flapper Depth (MD) Detail No. Depth Item 13 5,545'Conventional Module 12 5,595'Conventional Module 11 5,771'Conventional Module 10 5,813'Conventional Module 9 5,954'Conventional Module 8 6,225'Conventional Module 7 6,333'Conventional Module 6 6,385'Conventional Module 5 6,597'Conventional Module 4 6,726'Conventional Module 3 6,885'Conventional Module 2 7,053'Conventional Module 1 Unknown Conventional Module -No Flapper Sidetrack Window: Milled From 3,752' MD to 3,768' MD Max Inclination 22.2° @ 3,964’PERFORATION DATA Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Ftg Date Status Notes UB_3 4,995’ 5,020’4,830’ 4,854’25 1/10/20 Open 2-3/8” Razor HC UB_5A 5,186’ 5,194’ 5,010’ 5,018’8 1/3/20 Open 2-3/8 Geo HC UB5 5,217’ 5,247’ 5,040’ 5,068’30 6/15/15 Open 2-1/2” ConneX UB_7 5,282’ 5,289’ 5,101’ 5,108’7 1/3/20 Isolated 2-3/8 Geo HC UB_7A 5,325’ 5,337’ 5,142’ 5,154’12 1/3/20 Isolated 2-3/8 Geo HC _____________________________________________________________________________________ Updated by CMT 03-25-2020 PROPOSED SCHEMATIC Cook Inlet Basin, Alaska Middl G d Sh l Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform ______________ Kenai Gas Field Well: KBU 24-6RDCook Inlet BasinCook Inlet Basin Completion as of 6/15/15 Middle Ground Shoal Middle Ground Shoal CAPI: 50Last Last Oil WelOil Wel -133ComCom >Wat>Wat-pp20499pleted: pleted: er injectorer injector -0102-02- >G>G-0028-128-1 as pas p TD =7,830’00 MD / D 7,626’ TVD PBTD = 5,443’ MD / 5,255’ TVD RKB=87’/21’AGL 2 3 11 9-5/8//”Window 6 7 8 9 10 12 13-3/8” Tagged 7,744’ CTMD w/ 1-1/2” Coil 2/24/2014. 4 5 20” 13 TOC @3,630’ MD -122’ above top of window opening -1,859’ above 9-5/8” casing shoe. UB-5A TOC 5,443’ CIPB 5,470’ UB-3 UB-5 UB-7 UB-7A CIPB 5,260’ 1/10/20 A11 B1 CIBP +3,815’ (Proposed) CIBP +4,975’ w/ 35’ cement (Proposed) 1 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133 / K-55 / N/A 18.73 Surface 107' 13-3/8"Surface 68 / K-55 / BTC 12.415 Surface 1,518' 9-5/8"Intermediate 40 / L-80 / BTC-MOD 8.835 Surface 5,489' 3-1/2"Production9.3 / L-80 / EUE 8rd 2.992 Surface 7,812' EXCAPE SYSTEM DETAILS -13 Conventional modules - Red control line fired modules 8 thru 13. - Yellow control line fires top 8 modules. - Green line for BHP monitoring. - Ceramic flapper valves below each module except Module 1. CEMENTING DETAIL Casing Detail 13-38"17 1/2" hole Cmt w/ 608 sks, Class G 9-5/8"12-1/4" hole Cmt w/ 1,005 sks of Class G 8-1/2"8-1/2" hole Cmt w/ 267 sks (102 bbls) of 12.7 ppg, Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail Module Top (MD) Btm (MD) Top (TVD) Btm (TVD) Zone 13 5,520'5,530'5,328'5,338'Beluga 12 5,570'5,580'5,377'5,387'Beluga 11 5,746'5,756'5,547'5,557'Beluga 10 5,788'5,798'5,588'5,598'Beluga 9 5,929'5,939'5,727'5,737'Beluga 8 6,200'6,210'5,996'6,006'Beluga 7 6,308'6,318'6,104'6,114'Beluga 6 6,360'6,370'6,156'6,166'Beluga 5 6,572'6,582'6,368'6,378'Beluga 4 6,700'6,710'6,496'6,506'Beluga 3 6,860'6,870'6,656'6,666'Beluga 2 7,028'7,038'6,824'6,834'Beluga 1 7,466'7,476'6,997'7,007'Tyonek Flapper Depth (MD) Detail No. Depth Item 13 5,545'Conventional Module 12 5,595'Conventional Module 11 5,771'Conventional Module 10 5,813'Conventional Module 9 5,954'Conventional Module 8 6,225'Conventional Module 7 6,333'Conventional Module 6 6,385'Conventional Module 5 6,597'Conventional Module 4 6,726'Conventional Module 3 6,885'Conventional Module 2 7,053'Conventional Module 1 Unknown Conventional Module -No Flapper Sidetrack Window: Milled From 3,752' MD to 3,768' MD Max Inclination 22.2° @ 3,964’ PERFORATION DATA Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Ftg Date Status Notes A11 +3,785’+3,807’+3,699’+3,718’22 TBD Proposed TBD B1 +3,836’+3,879’+3,746’+3,786’ 43 TBD Proposed TBD UB_3 4,995’ 5,020’ 4,830’ 4,854’25 1/10/20 Isolated 2-3/8” Razor HC UB_5A 5,186’ 5,194’ 5,010’ 5,018’8 1/3/20 Isolated 2-3/8 Geo HC UB5 5,217’ 5,247’ 5,040’ 5,068’30 6/15/15 Isolated 2-1/2” ConneX UB_7 5,282’ 5,289’ 5,101’ 5,108’7 1/3/20 Isolated 2-3/8 Geo HC UB_7A 5,325’ 5,337’ 5,142’ 5,154’12 1/3/20 Isolated 2-3/8 Geo HC STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1 Carlisle, Samantha J (CED) From:Schwartz, Guy L (CED) Sent:Thursday, April 2, 2020 4:36 PM To:Christina Twogood - (C) Cc:Davies, Stephen F (DOA) (steve.davies@alaska.gov) Subject:KBU 24-06RD perfs (PTD 206-013) Christina, Wantedtoupdateyouonsundryforperfingthewell.IamrequiringaMIToftheIAbeforeandafterperforatingthe upperzones.TheupperzoneisveryclosetheloggedTOC(cementpackercompletion)sothereissomeconcernthat therecouldbeachannelormigrationpathoncetheuppersetofperfsareshot. Givemeacallifyouhaveanyquestions. 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). 1 Davies, Stephen F (CED) From:Christina Twogood - (C) <ctwogood@hilcorp.com> Sent:Friday, March 27, 2020 3:13 PM To:Davies, Stephen F (CED) Subject:RE: [EXTERNAL] KBU 24-06RD (PTD 206-013; Sundry 320-134) - Question Ijustnoticedthesundryshowsthewellisproducing650MCFD.Iapologizeforthisoversight. ThewellisactuallyofflineandwewillisolatethecurrentpoolandmoveuptotestPool4,andthenPool3afterthe intervalinPool4hasbeenexhaustedprovideditsuccessfullyproduces. ChristinaTwogood OperationsEngineer KenaiAssetTeam,HilcorpAlaska 3800CenterpointDr.,Anchorage,AK99503 (w)907Ͳ777Ͳ8443 (c)907Ͳ378Ͳ7323 From:ChristinaTwogoodͲ(C) Sent:Friday,March27,20203:07PM To:'Davies,StephenF(CED)'<steve.davies@alaska.gov> Subject:RE:[EXTERNAL]KBU24Ͳ06RD(PTD206Ͳ013;Sundry320Ͳ134)ͲQuestion HiSteve, Sofarsogood.Ihopeyouandyoursarealsodoingwell. Youarecorrect,wewillbeproducingfromPool3now,nottheUpperTyonek/Beluga. B1isinPool4andA11isinPool3,sowehavetohaveisolationbetweenthoseperfsaswellwhenwearereadyto perforateA11. ChristinaTwogood OperationsEngineer KenaiAssetTeam,HilcorpAlaska 3800CenterpointDr.,Anchorage,AK99503 (w)907Ͳ777Ͳ8443 (c)907Ͳ378Ͳ7323 From:Davies,StephenF(CED)[mailto:steve.davies@alaska.gov] Sent:Friday,March27,20209:18AM To:ChristinaTwogoodͲ(C)<ctwogood@hilcorp.com> Subject:[EXTERNAL]KBU24Ͳ06RD(PTD206Ͳ013;Sundry320Ͳ134)ͲQuestion HiChristina, 2 Hopeyouarewell. Question:Won’tHilcorp’sproposedperforationsinKBU24Ͳ06RDbeopeninganewpool(Sterling3)?Accordingto AOGCC’sdatabase,previousproductionfromthiswellhasbeenreportedagainsttheBelugaͲUpperTyonekGasPool.Or haveImissedsomething? Thanksforyourhelp, SteveDavies AlaskaOilandGasConservationCommission(AOGCC) CONFIDENTIALITYNOTICE:ThiseͲmailmessage,includinganyattachments,containsinformationfromtheAlaskaOilandGasConservationCommission (AOGCC),StateofAlaskaandisforthesoleuseoftheintendedrecipient(s).Itmaycontainconfidentialand/orprivilegedinformation.Theunauthorizedreview,use ordisclosureofsuchinformationmayviolatestateorfederallaw.IfyouareanunintendedrecipientofthiseͲmail,pleasedeleteit,withoutfirstsavingorforwarding it,and,sothattheAOGCCisawareofthemistakeinsendingittoyou,contactSteveDaviesat907Ͳ793Ͳ1224orsteve.davies@alaska.gov. The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS s E..o rs V L . Ld JAN 21 2020 ®(i('Ill f` 1. Operations Abandon Plug Perforations Ll Fracture Stimulate LJ Pull Tubing Li Operations shutdown Li Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casing. ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: N2 Q 2. Operator Hilcorp Alaska, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development Q Exploratory ❑ 206-013 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6. API Number: AK 99503 50-133-20499-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: FEDA028142 Kenai Beluga Unit (KBU) 24-06RD 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Kenai Field - Beluga/Upper Tyonek Gas Pool 11. Present Well Condition Summary: Total Depth measured 7,830 feet Plugs measured 5443 feet true vertical 7,626 feet Junk measured 7,744 (Fill) feet Effective Depth measured 5,443 feet Packer measured N/A feet true vertical 5,255 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 86' 20" 107' 107' Surface 1,463' 13-3/8" 1,518' 1,484' 3,450psi 1,950psi Intermediate 3,661' 9-5/8" 3,768' 3,682' 5,750psi 3,090psi Production 7,791' 3-1/2" 7,812' 7,608' 10,160psi 10,530psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth) N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13, Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 588 0 15 85 Subsequent to operation: 0 0 0 15 636 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations ❑� Exploratory❑ Development p ❑ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas WDSPL Printed and 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: 319557 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramerCa)hilcoro.com Authorized Signature:. Dale: Z 11';" 1-b2a Contact Phone: 777-8420 Form 10-40"evised 4/20171 / /- A-�. 14) RBDMS _�"` JAN 2 3 2020g Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 24-06RD E -Line 1 50-133-20499-01-00 206-013 1/3/20 1 1/11/20 Daily Operations: 01/03/2020 - Friday Sign in. Mobe to location. PTW and JSA. Spot and rig up lubricator. Pressure test lubricator to 250 psi low and 1,500 psi. Cold weather is slowing things down. RIH w/GPT tool with well flowing 550K at 69 psi and tie into perf log dated 6-15-15. Found fluid level at 5 250' and tagged at 5,423. Ran correlation log and send to town. POOH. Determined could not pert the bottom UB -8 zone. RIH w/ 2-3/8" x 12' GEO HC, 6 spf, 60 deg phase and tie into GPT log. Run correlation log and send to town. Get ok to perforate the UB 7A sand from 5,325' to 5,337'. Spot and fire gun with well flow 559K at 71 psi. After 5 min - 370K at 67 psi, 10 min - 442K at 91 psi and 15 min - 558k at 87 psi. POOH All shots fired. RIH w/ 2-3/8" x 7' GEO HC, 6 spf, 60 deg phase and tie into GPT log. Run correlation log and send to town. Get ok to perforate the UB 7 sand from 5,282' to 5,289'. Spot and fire gun with well flow 342K at 72 psi. After 5 min - 357K at 72 psi, 10 min - 328K at 70 psi and 15 min - 214k at 68 psi. POOH All shots fired. RIH w/ 2-3/8" x 8' GEO HC, 6 spf, 60 deg phase and tie into GPT log. Run correlation log and send to town. Get ok to perforate the UB 5A sand from 5186' to5194'. Spot and fire gun with well flow 460.8K at 72.2 psi. After 5 min - 341'.2K at 71.7 psi, 10 min - 248.3K at 69.1 psi. Then between 10 min and 15 min it drop 271K at 70 psi and then to zero flow at 69.5 psi. After about 2 min it jumped up to 347K at 88 psi then went to 709K at 85.6 psi and then down to 500K at 83.6. Up in lubricator with gun. Well flow 385K at 73 psi. All shots fired. Rig down lubricator and equipment. Turn well back over to field. 01/10/2020 - Friday Sign in. Mobe to location. PTW and JSA. Spot and rig up equipment. GPT tool is not working. Troubleshoot but couldn't fix. Bring another one from shop. PT lubricator to 250 psi low and 1,500 psi high.TP - 25 psi. Shut well in. RIH w/GPT tool and tie into OHL. Tag at 5,413'. Ran correlation log and found fluid level at 5,290' and soapy/gas cut fluid to 3,750'. POOH. Send log to town. RIH w/2.75" OD CIBP and tie into GPT log. Run correlation log and send to town. Get ok to set plug at 5,260'w/25 psi on tubing. Spotted and set plug. Lost 100 Ib line tension. Pick up 30' and go back and tag plug. POOH and tools looked ok. RIH w/ 2-3/8" x 25' Razor HC, 5 spf, 60 deg phase and tie into the plug log. Run correlation log and send to town. Get ok to perf from 4,995' tp 5,020' with 25 psi on tubing. Spotted at fired gun and lost 300 Ib of line tension. Started out of hole and took a few seconds to get full wt of tools. Acted like it blew tools up hole a little ways. POOH and had small tight spot around 350' and the line got stuck at 290'. Acts like kink in line at the grease tubes. Called town and talked it over with engr and also AKE-line owner and decided it would be safer to wait in the morning when it isn't so dark and cold to strip and cut line. AKE-line will have a man out here on watch and will have another man to relieve him later. Also when we fired gun with 23.6 psi on tubing after 5 min - 240.5 psi, 10 min - 368 psi and 15 min - 447.2 psi. Trying to get wire out of hole without strip and cut. Also attempting to bleed lubricator down after closing bop rams. Putting heater truck in well house. Pumping methanol on rams. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 24-06RD E -Line I 50-133-20499-01-00 206-013 1/3/20 1/11/20 Daily Operations: — -- 01/11/2020-Saturday PTW and JSA. Tried to get wireline valve to hold but was leaking pressure by some. TP - 1,030 psi. Blow the grease out of grease head return line and pump methanol thru grease head to make sure it wasn't iced up. Pumped grease into wireline valve to help seal off pressure. Called town and discussed a pop and drop lubricator procedure. Did a pop and drop on lubricator and found that not much pressure was leaking and it was safe to cut and strip line. We had another JSA on what everybodyjob was. AKE-Line then proceeded to make 9 cuts and strip approx 335' of line from well. Also pulled tool string from well. All shots had fired and didn't leave any wire or tools in well. Rig down all equipment and turn well over to field. TP was 760 psi when we got off well., ITilcoro Alaekry LLC 20• d 23-3/8" To' @363Y iYD h ->zrav«mad Wntiv+iapeilrg 59'abe45/a' ' m %shoe. 9-51rwMwi Max '= Inclination 22.2° @ 3,964' i no SCHEMATIC CASING DFTAII Kenai Gas Field Well: KBU 24-6RD Completion as of 6/15/15 API: 50-133-20499-01-00 Size Type Wt/Grade/Conn ID TopI 2 20" Conductor 133/K-55/N/A 18.73 Surfa PBTD=5,443' MD/5,25V TVD 13-3/8" Surface 68/K-55/BTC 12.415 Surfa entional Module 9-5/8" Intermediate 40/L-80/BTC-MOD 8.835 Surfa entional Module 3-1/2" Production 9.3/L-80/EUE8rd 2.992 Surfa Conventional Module Sidetrack Window: Milled From 3,752' MD to 3,768' MD Flanner Denth fMnl Detail No. Uf f.3 Top(TVD) f t 2 Tagged 7,744'CSMD ¢''. i t 2/24/2014. .. 11 TD = 7,830 IvD/ 7,626 TVD PBTD=5,443' MD/5,25V TVD Flanner Denth fMnl Detail No. Depth Btm(MD) Top(TVD) 5,545' entional Module 12 5,595' entional Module 11 5,771' r1tem13 entional Module 10 5,813' entional Module 9 5,954' entional Module 8 6,225' entional Module 7 6,333' entional Module 6 6,385' Conventional Module 5 6,597' Conventional Module 4 6,726' Conventional Module 3 6,885' Conventional Module 2 7,053' Conventional Module 1 Unknown Conventional Module - No Flapper DFRLr1GATInA1 rIATA Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD)A306/15/15 Btm (TVD) Zone Status Notes UB_3 4,995' 5,020' 4,830' 4,854' 5,377' 5,387' Open 2-3/8" Razor HC UB 5A 5,186' 5,194' 5,010' 5,018' 5,798' 51588' Open 2-3/8 Geo HC UB5 5,217' 5,247' 5,040' 5,068' 8 6,200' 6,210' Open 2-1/2" ConneX UB7 5,2825,289' 6,318' 5,101' 5,108' Isolated 2-3/8 Geo HC UB7A 5,325' 5,337' 5,142' 5154' 6,378' Isolated 2-3/8 Geo HC EXCAPE SYSTEM DETAILS -13 Conventional modules - Red control line fired modules 8 thru 13. - control line fires top 8 modules. - Green line for BHP monitoring. - Ceramic flapper valves below each module except Module 1. I Detail Module Top (MD) Btm (MD) Top (TVD) Btm (TVD) Zone 13 5,520' 5,530' 5,328' 5,338' Beluga 12 5,570' 5,580' 5,377' 5,387' Beluga 11 5,746' 5,756' 5,547' 5,557' Beluga 30 5,788' 5,798' 51588' 5,598' Beluga 9 5,929' 5,939' 5,727' 5,737' Beluga 8 6,200' 6,210' 5,996' 6,006' 7 6,308' 6,318' 6,104' 61114' 6 6,360' 6,370' 6,156' 6,166' 5 6,572' 6,582' 6,368' 6,378' lBeluga 4 6,700' 6,710' 6,496' 6,506' 3 6,860' 6,870' 6,656' 6,666' 2 7,028' 7,038' 6,824' 6,834' 1 7,466' 7,476' 6,997 7,007' Tyonek CEMENTING DFTAII Casing I Detail 13-38" 17 1/2" hole Cmt w/ 608 sks, Class G 9-5/8" 12-1/4" hole Cmt w/ 1,005 sks of Class G 8-1/2" 8-1/2"hole Cmt w/ 267 sks (102 bbls) of 12.7 ppg, Class G Lead & 878 sks (181 bbls) of 15.8 Flog Tail Updated by DMA 03-20-20 THE STATE OIALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, K 3U 24-06RD Permit to Drill Number: 206-013 Sundry Number: 319-557 Dear Mr. York: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.acgcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, �v J Price Chair DATED this day of December, 2019. RBDMSKI'� DEC 1 12019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS on a C oc oon ri-CIV DEC - 6 2�019 AOGCC /' g 1. Type of Request: Abandon El Plug Perforations ❑ `Fracture Stimulate 0 Repair Well E1 Operations shutdown ❑ Suspend ❑ Perforate Q Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: N2 ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q 206-013 3. Address: 3800 Centerpoint Dr, Suite 1400 Stratigraphic ❑ Service ❑ . 6. API Number: / Anchorage Alaska 99503 50-133-20499-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 510a Will planned perforations require a spacing exception? Yes Q No Q Kenai Beluga Unit (KBU) 24-06RD 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028142 Kenai Gas Field / Beluga/Upper Tyonek Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7,830' 7,626' 5,443' 5,255' -907 5,443' 7,744' Casing Length Size MD TVD Burst Collapse Structural Conductor 86' 20" 107' 107' Surface 1,463' 13-3/8" 1,518' 1,484' 3,450 psi 1,950 psi Intermediate 3,661' 9-5/8" 3,768' 3,682' 5,750 psi 3,090 psi Production 7,791' 3-1/2" 7,812' 7,608' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A; N/A N/A;, N/A 12. Attachments: Proposal Summary v Wellbore schematic r 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch © Exploratory I-] Stratigraphic ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: December 17th, 2019 ❑ WINJ OIL ❑ WDSPL ❑ Suspended ❑ GAS ❑✓ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 777-8345 Contact Name: Christina Twogood Authorized Title: Operations Manager Contact Email: CtWO o da-hilcorio.corn i Authorized SignatuPit J t % Contact Phone: 777-8443 r Date: 2 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test Q Mechanical Integrity Test ❑ Location Clearance Q Other: 4BDMS�"' DEC 1 12019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: / _ L1 a ( APPROVED BY ^ � Approved by: - COMMISSIONER THE COMMISSION Date: ,� t � O12�I �%I(C1 I�'/�/'�y Submit Form and F r A Ap vetl application is valid for 12 month rom a ate of a pr vol. _Attachrr�em. in Duplicate "ltl� — i_ I -- H llilcorp Alaska, M Well Prognosis Well: KBU 24-06RD Date:12/5/2019 Well Name: KBU 24-06RD API Number: 50-133-20499-01 Current Status: Shut -In Gas Well Leg: N/A Estimated Start Date: December 17th, 2019 Rig: E -Line Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-013 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: Max. Expected BHP: Max. Allowable Surface Pressure: Brief Well Summary - 1,423 psi @ 5,328' TVD — 907 psi (Based on offset well RFT data from 2017) (Based on expected BHP and gas gradient to surface (0.10psi/ft)) Kenai Beluga Unit #24-06RD was drilled as a sidetrack EXCAPE completion in 2006 to target gas sands in the Beluga formations. The initial EXCAPE modules were placed on production in May 2006. A capillary string was installed in August 2009, the depth was adjusted in November 2009 and pulled in October 2012. The well loaded up in April 2014 and has been unable to sustain flow. In 2015, the existing EXCAPE perforations were plugged back and the UB -5 was perforated. The purpose of this work/sundry is to add 7 perforations in the Upper Beluga sands UB1X — UBB. , Notes Regarding Wellbore Condition • The well is currently producing 650 MCFD. • Last tag at 5,428' RKB on 07/03/15 with a 1.87" GR. Safety Concerns • Discuss nitrogen asohvxiation concerns and identify any areas where nitrogen could collect and people could enter. • Consider tank placement based on wind direction and current weather forecast (venting nitrogen during this job). • Ensure all crews are aware of stop job authority. E -Line Procedure 1. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low/ 1,500 psi High. V/ 2. RIH with GPT tool and find fluid level. If fluid level is over the depth of the new perfs, discuss using Nitrogen with the Operations Engineer. 3. If needed, RU Nitrogen Truck, pressure up on well and push water back into formation. Use GPT tool to confirm water level is below interval to perf. 4. RU perf guns. 0 }iikoru Alaska. LL, 5. RIH and perforate the following intervals: Well Prognosis Well: KBU 24-06RD Date:12/5/2019 Zone Sand Top (MD) Btm (MD) Top (TVD) Stm (TVD) FT Upper Beluga UB_1X +4,825' +4,830' +4,670' +4,675' S' Upper Beluga UB_iX +4,840' +4,860' +4,683' +4,703' 20' Upper Beluga UB_3 +4,995' +5,030' +4,830' +4,863' 35' Upper Beluga UB 5A +5,186' +5,194' +5,010' +5,018' 8' Upper Beluga UB_7 ±5,282' ±51289' ±5,101' ±5,108' 7' Upper Beluga UB_7A +5,325' +5,337' +5,142' +5,154' 12' Upper Beluga UB_8 +5,419' +5,429' 1 +5,232' +5,242' 10' a. Well maybe shot flowing. b. Proposed perfs also shown on the proposed schematic in red font. c. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. d. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer and Geologist for confirmation. a. There is a CBL Log dated 4/02/06 (CBL Tie-in log) that may be used if requested by Reservoir Engineer and/or Geologist. e. Use Gamma/CCL/ to correlate. f. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. g. All perforations in table above are located in the Beluga/Upper Tyonek Gas Pool based' on Conservation Order No. 510A. 6. POOH. 7. RD E -Line. 8. Turn well over to production. (Test SSV within S days of stable production on well—notify AOGCC 24 hours before testing). E -Line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low/ 1,500 psi High. 3. RIH and set 3-1/2" Casing Patch or set 3-1/2" CIBP above the zone and dump 35' of cement on top of the plug. Attachments 1. Actual Schematic 2. Proposed Schematic 3. Standard Well Procedure — N2 Operations tlilcorp Alaeku. LLC 2W 19-'-/g' TOC @3,634 M) W"d"„opzure -1,859'6ve95/r r CWi� hce. �e 9-5/8"4Nndw, - I Max Inclination 22.2° @ 3,964' Taged 7)44' CrND w/ 1-1/Y'Cdl - ACTUAL SCHEMATIC CASING DETAIL Kenai Gas Field Well: KBU 24-6RD Completion as of 6/15/15 API: 50-133-20499-01-00 Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 133 / K-55 / N/A 18.73 Surface 107' 13-3/8" Surface 68/K-55/BTC 12.415 Surface 1,518' 9-5/8" Intermediate 40/L-80/BTC-MOD 8.835 Surface 5,489' 3-1/2" Production 9.3 / L-80/ EUE 8rd 2.992 Surface 7,812' Sidetrack Window: Milled From 3,752' MD to 3,768' MD 3' ..ti 7i U&5' ycapped YJ 27 ce nent 5,479 r �i9 (Plug) j.3 5.443' :hitt (Cernxt) "4 it -3 P i 2 TD=7,834 MD/ PBT) =7,744'MD Flannpr npnth front npt.it No. Depth Item 13 5,545' Conventional Module 12 5,595' Conventional Module 11 5,771' Conventional Module 10 5,813' Conventional Module 9 5,954' Conventional Module 8 6,225' Conventional Module 7 6,333' Conventional Module 6=Conventilona1111111 Beluga nventional Module 5nventional 6,006' Module 4ventional 6,104' Module 3ventional 6 6,360' Module 2ventional Beluga Module 1 6,378' ventional Module - No Flapper PERFORATION EXCAPE SYSTEM DETAILS -13 Conventional modules - Red control line fired modules 8 thru 13. - control line fires top 8 modules. - Green line for BHP monitoring. - Ceramic flapper valves below each module except Module 1. Detail D) Top (TVD) Btm (TVD) Zone 0'' 5,328' 5,338' Beluga '' 5,377' 5,387' Belug'' &ModuleTop(MD)D)N6,3X 5,547' 5,557' Beluga 8'' 5,588' 5,598' Beluga ' ' 5,727' 5,737' Beluga ' ' 5,996' 6,006' Beluga ' ' 6,104' 6,114' Beluga 6 6,360' 6,156' 6,166' Beluga 5 6,572' 6,368' 6,378' Beluga 4 6,700' 6,496' 6,506' Beluga 3 6,860' 6,870' 6,656' 6,666' Beluga 2 7,028' 7,038' 6,824' 6,834' Beluga 1 7,466' 7,476' 1 6,997' 1 7,007' 1 Tyonek CEMENTING DETAIL. Casing Detail 13-38" 1 171/2" hole Cmt w/ 608 sks, Class G 9-5/8" 12-1/4" hole Cmt w/ 1,005 sks of Class G 8-1/2"hole Cmt w/ 267 sks (102 6615) of 12.7 ppg, Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail Downhole Revised: 6/15/15 Revised By: CMT 12-5-2019 ff Hilcoro Aloeka, LLC 20" TOC @13,630 ASU {• -vz aeoemud �"mwwen�B avngshoe , 950wtndov . -1 Max Inclination 22.2' @ 3,964' , 9 a 7 Tagged 7,744 CnVV W/ 1-11rwl - 2/24/2014. ...__. PROPOSED SCHEMATIC CASING DETAIL Kenai Gas Field Well: KBU 24-6RD Completion as of 6/15/15 API: 50-133-20499-01-00 Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 133/K-55/N/A 18.73 Surface 107' 13-3/8" Surface 68/ K-55 / BTC 12.415 Surface 1,518' 9-5/8" Intermediate 40/L-80/BTC-MOD 8.835 Surface 5,489' 3-1/2" Production 9.3 / L-80/ EUE 8rd 2.992 surface 7,812' F etrack Window:led From 3,752' MD 3,768' MD iu 3 uss UBdA', UB -7 6ige PRg Capped 27 carer[ 5,470 (per 5,443 (Cement) TD = 7,83(7 MD/ PBTD=7,744' MD FIaDDer Deoth (MD) Detail No. Depth Item 13 5,545' Conventional Module 12 5,595' Conventional Module 11 5,771' Conventional Module 10 5,813' Conventional Module 9 5,954' Conventional Module 8 6,225' Conventional Module 7 6,333' Conventional Module 6 6,385' Conventional Module 5 6,597' Conventional Module 4 6,726' Conventional Module 3 6,885' Conventional Module 2 7,053' Conventional Module 1 Unknown Conventional Module -No Flapper PFRFrIRATIr1N nATA Zone Top(MD) I(MD) Top(TVD) Btm(TVD) Ftg Date Notes UB ix ±4,825' ±4,830' ±4,670' ±4,675' 5 TBD d UB ix ±4,840' ±4,860' ±4,683' ±4,703' 20 TBD d US -3 ±4,995' ±5,030' ±4,830' ±4,863' 35 TBD d U85 5,217' 5,247' 5,040' 5,068' 6 6/15/152-1/2'ConneX UP UB SA ±5,186' ±5,194' ±5,010' ±5,018' 8 TBD d UB_7 15,282' ±5,289' ±5,101' ±5,108' 7 TBD UB -7A ±5,325' ±5,337' ±5,142' ±5,154' 12 TBD 7,038' UB8 ±5,419' ±5,429' ±5,232' ±5,242' 10 TBD EXCAPE SYSTEM DETAIL -13 Conventional modules - Red control line fired modules 8 thru 13. - control line fires top 8 modules. - Green line for BHP monitoring. - Ceramic flapper valves below each module except Module 1. Detail Module Top (MD) Btm (MD) Top (TVD) Btm (TVD) Zone 13 5,520' 5,530' 5,328' 5,338' Beluga 12 5,570' 5,580' 5,377' 5,387' Beluga 11 5,746' 5,756' 5,547' 5,557' Beluga 10 5,788' 5,798' 5,588' 5,598' Beluga 9 5,929' 5,939' 5,727' 5,737' Beluga 8 6,200' 6,210' 5,996' 6,006' Beluga 7 6,308' 6,318' 6,104' 6,114' Beluga 6 6,360' 6,370' 6,156' 6,166' Beluga 5 6,572' 6,582' 6,368' 6,378' Beluga 4 6,700' 6,710' 6,496' 6,506' Beluga 3 6,860' 6,870' 6,656' 6,666' Beluga 2 7,028' 7,038' 6,824' 6,834' Beluga 1 7,466' 7,476' 6,997' 7,007' Tyonek CEMENTING DFTAII Casing Detail 13-38" 1 171/2" hole Cmt w/ 608 sks, Class G hole Cmt w/ 1,005 sks of Class G 8-1/2" 8-1/2"hole Cmt w/ 267 sks (102 bbls) of 12.7 ppg, Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail Revised By: CMT 12-5-2019 STANDARD WELL PROCEDURE ►►aeorp UaAa,►.►.►. NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 STATE OF ALASKA RECEIVED AL . KA OIL AND GAS CONSERVATION COM,...SSION REPORT OF SUNDRY WELL OPERATIONS JUL 0 1 2015 I1.Operations Abandon LI El ❑�Plug Perforations U Fracture Stimulate U Pull Tubing LJ ra r+ h' n H Performed: Suspend Perforate Other Stimulate ❑ Alter Casing El A06 Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Coil N2 Q 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑✓ Exploratory ❑ 206-013 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-13320499-01-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028142 Kenai Beluga Unit 24-O6RD 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai Field-Beluga/Upper Tyonek Gas Pool 11.Present Well Condition Summary: Total Depth measured 7,830 feet Plugs measured N/A feet true vertical 7,626 feet Junk measured 7,744(Fill) feet Effective Depth measured 7,744 feet Packer measured N/A feet true vertical 7,540 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 86' 20" 107' 107' Surface 1,463' 13-3/8" 1,518' 1,484' 3,450psi 1,950psi Intermediate 3,661' 9-5/8" 3,768' 3,682' 5,750psi 3,090psi Production 7,791' 3-1/2" 7,812' 7,608' 10,160psi 10,530psi Liner Perforation depth Measured depth See Attached Schematic SCANNE .JUL0 9 v U 15 True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) N/A N/A N/A N/A Packers and SSSV(type,measured and true vertical depth) N/A N/A N/A N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 22 Subsequent to operation: 0 1167 0 0 263 14.Attachments(required per 20 AAC 25 070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 2 Exploratory❑ Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-305 Contact Stan Porhola Email sporholaAhiIcorp.com Printed Name Stan Porhola Title Operations Engineer Signature .-per Phone 907-777-8412 Date 4 0 j //5' �,� 5— RBDMS JUL - 1 2015 Form 10-404 Revised 5/2015 Pr18l�� Submit Original Only Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 24-6RD 50-133-20499-01-00 206-013 6/6/15 6/15/15 Daily Operations: 06/06/2015 -Saturday RU slickline. PT lubricator to 3,000 psi-test OK. RIH w/2.5" GR to 6,401' and tag fill. RIH w/2.5" blindbox to 6,401' and tag fill. Could not identify fluid level. RIH w/ press/temp tools to 6,385'. POOH. RD Slickline. Move to KBU 34-06. 06/11/2015 -Thursday RU slickline. PT lubricator to 2,000 psi-test OK. RIH w/2.75" swedge to 5,965' and tag fill. RIH w/3-1/2" AD-2 stop, packoff, and A stop and set top of plu�at 5,470' RIH w/2.5" dump bailer(8 runs) and dump 9.3 gals cement.TOC est at 5,442'. POOH. RD Slickline. Move to KBU 34-06. 06/14/2015 -Sunday RU slickline. PT lubricator to 2,000 psi-test OK. RIH w/2.50" DD bailer to 5,443' and tag cement. Good tag, hard cement (27' cement). RD Slickline. Move to KBU 34-06. RU Pump Truck. PT lines to 2,000 psi -test OK. Test plug/tubing to 1,800 psi for 30 min -test OK. RD Pump Truck. 06/15/2015 - Monday PTW and JSA. Mobe to location and spot equipment. Rig up lubricator, pressure test to 250 psi low and 2,200 psi high. Bleed TP down to 350 psi. RIH with 2-1/2" x 20' Connex HC, 3 spf, 60 deg phase and tie into CBL log sent by Ops Engineer. Run correlation log and send to town. Get ok to perf. Spot gun from 5,227' to 5,247'. Fire gun with 332 psi on tubing. Pressure went to 360 psi after 5 min. POOH. All shots fired. Gun was dry. RIH with second 2-1/2" x 20' Connex HC, 3 spf, 60 deg phase and tie into correlation log Gun 1. Run correlation log and send to town. Bleed pressure from 560 psi to 480 psi. Get ok to perf. Spot gun from 5,227' to 5,247'. Fire gun with 480 psi on tubing. Pressure went to 495 psi after 5 min. POOH. All shots fired. Gun was dry. Tried to flow well with starting pressure at 515 psi and vented N2 until pressure got to 350 psi. Went down pretty quick. Did not get all N2 out of well. Decided to continue with perforating. RIH with 2-1/2" x 10' Connex HC, 3 spf, 60 deg phase and tie into correlation log Gun 1. Run correlation log and send to town. Get ok to perf. Spot gun from 5,227' to 5,217'. Fire gun with 529 psi on tubing. Pressure went to 532 psi after 5 min. POOH. All shots fired. Gun was dry. RIH with second 2-1/2" x 10' Connex HC, 3 spf, 60 deg phase and tie into correlation log Gun 1. Run correlation log and send to town. Get ok to perf. Spot gun from 5,227' to 5,217'. Fire gun with 535.5 psi on tubing. Pressure went to 536 psi after 5 min. POOH. All shots fired. Gun was dry. Rig down lubricator and turn well over to field.TP - 536 psi. Kenai Gas Field Well: KBU 24-6RD II ACTUAL SCHEMATIC Completion as of 6/15/15 tti(curp Alaska,LLC API: 50-133-20499-01-00 CASING DETAIL RKB=87'/21'AGLSize Type Wt/Grade/Conn ID Top Btm '.,?. L 20" Conductor 133/K-55/N/A 18.73 Surface 107' 13-3/8" Surface 68/K-55/BTC 12.415 Surface 1,518' i„.. 20' 9-5/8" Intermediate 40/L-80/BTC-MOD 8.835 Surface 5,489' 3-1/2" Production 9.3/L-80/EUE 8rd 2.992 Surface 7,812' Flapper Depth (MD) Detail 13-3/8"I 16 No. Depth Item ,• 13 5,545' Conventional Module ' 0 12 5,595' Conventional Module •.. 11 5,771' Conventional Module TOC@3,630'MD ..�4 10 5,813' Conventional Module -127 above top of , 9 5,954' Conventional Module window opening ' j. -1,859'above 9-5/8" ' + 8 6,225' Conventional Module casing shoe. "•••••••,...b. '' 7 6,333' Conventional Module 6 6,385' Conventional Module Sidetrack Window: 5 6,597' Conventional Module 9-s/8"Wndow Milled From 3,752'MD 4 6,726' Conventional Module to 3,768'MD _3 6,885' Conventional Module T ' 2 7,053' Conventional Module Max .;. 1 Unknown Conventional Module-No Flapper Inclination 22.2°@ 3,964' 1. PERFORATION DATA -i Zone Top(MD) Btm(MD) Top(TVD) Btm(TBVD) SPF Date Status Notes + U85 5,217' 5,247' 5,040' 5,068' 6 6/15/15 Open 2-1/2"ConneX v . UB-5 vv 27'cement k' 5,470 ?�:13 (Plug) I .. �+h^. 5• EXCAPE SYSTEM DETAILS 1.11 '12 O -13 Conventional modules -Red control line fired modules 8 thru 13. '; control line fires top 8 modules. 'i -Green line for BHP monitoring. ` 10 -Ceramic flapper valves below each module except Module 1. Di >`' 9 Module Top(MD) Btm(MD) Top(TVD) Btm(TVD) Zone ei ' le". 8 13 5,520' 5,530' 5,328' 5,338' Beluga �`7 12 5,570' 5,580' 5,377' 5,387' Beluga 11 5,746' 5,756' 5,547' 5,557' Beluga Di 6 10 5,788' 5,798' 5,588' 5,598' Beluga 9 5,929' 5,939' 5,727' 5,737' Beluga • DI s 8 6,200' 6,210' 5,996' 6,006' Beluga 7 6,308' 6,318' 6,104' 6,114' Beluga Dj 4 6 6,360' 6,370' 6,156' 6,166' Beluga Di 3 5 6,572' 6,582' 6,368' 6,378' Beluga 4 6,700' 6,710' 6,496' 6,506' Beluga Di 2 3 6,860' 6,870' 6,656' 6,666' Beluga '? 2 7,028' 7,038' 6,824' 6,834' Beluga '!,' m I *11 1 7,466' 7,476' 6,997' 7,007' Tyonek Tagged 7,744'03/0 ti' ' + w/ 1-1/2"Cod -.1."--1. , , 2/24/2014. hl ''1r CEMENTING DETAIL If jl Casing Detail 13-38" 17 1/2"hole Cmt w/608 sks,Class G 9-5/8" 12-1/4"hole Cmt w/ 1,005 sks of Class G TD=7,830'MD/PBTD=7,774'MD 8-1/2" 8-1/2"hole Cmt w/267 sks(102 bbls)of 12.7 ppg,Class G Lead&878 sks(181 bbls)of 15.8 ppg Tail Downhole Revised:6/15/15 Revised By:STP 6/17/15 o /77 \� s THE STATE Alaska Oil and Gas • ofA L1 SIKA Conservation Commission u tt- .>t2=_ _ 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 04t Fax: 907.276.7542 ALAS�� i v‘ www.aogcc.alaska.gov Stan Porhola O ak Operations Engineer /' O Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, (KBU) 24-06RD Sundry Number: 315-305 Dear Mr. Porhola: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P Foerster -LAY Chair DATED this 'day of May, 2015 Encl. RECEIVED STATE OF ALASKA MAY 18 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION / 7—S S / -?/15 APPLICATION FOR SUNDRY APPROVALS AOGCC 20 MC 25.280 1.Type of Request: Abandon E Plug Perforations ❑, . Fracture Stimulate ❑ PuN Tubing ❑ Operations shutdown E Suspend❑ Perforate Q. Other Stimulate 0 Aker Casing ❑ Change Approved Program ❑ Plug for Redrill 0 Perforate New Pool 0 Repair WeN 0 Re-enter Susp WeN ❑ Other: Coil N2❑✓ 2.Operator Name: Hilcorp Alaska,LLC 4.Current WeN Class: 5.Permit to DIN r. Numbe Exploratory ❑ Development 0 - 206-013 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service El6.API Number. Anchorage,Alaska 99503 50-133-20499-01 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 510a ' Kenai Beluga Unit(KBU)24-O6RD . Will planned perforations require a spacing exception? Yes 0 No ❑✓ 9.Property Designation(Lease Number): 10.Field/Pool(s): e���eI 4 u ' ��•..zj� *o ar�� A-028142 * Kenai Gas Field/Beluga'&4y/e.--We--e' ols cl 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 7,830 ' 7,626 ' 7,774 • 7,570 • N/A N/A Casing Length Size MD ND Burst Collapse - Structural Conductor 86' 20" 107' 107' Surface 1,463' 13-3/8" 1,518' 1,484' 3,450 psi 1,950 psi Intermediate 3,661' 9-5/8" 3,768' 3,682' 5,750 psi 3,090 psi Production 7,791' 3-1/2" 7,812' 7,608' 10,160 psi 10,530 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80 7,812 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): N/A;N/A N/A;N/A 12.Attachments: Description Summary of Proposal Q 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: 6/1/2015 Commencing Operations: OIL 0 WINJ 0 WDSPL 0 Suspended ❑ 16.Verbal Approval: Date: GAS ❑r WAG ❑ GSTOR 0 SPLUG ❑ Commission Representative: GINJ 0 Op Shutdown 0 Abandoned ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Email sporhola@hilcorp.com Printed Name Stan Porhola Title Operations Engineer Signature _�� ' :1/4--- Phone 907-777-8412 Date / `10 //> COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3‘5 - 308 Plug Integrity ❑ BOP Test 0 Mechanical Integrity Test ❑ Location Clearance 0 Other: Spacing Exception Required? Yes 0 No L'?J Subsequent Form Required: /0 - -I G t APPROVED BY Approved by: ...1( 2.1,r 20.4.41.....— COMMISSIONER THE COMMISSION Date:5.Z7_ / 5- .5--11-11- -f'-IoRieGINAL Submit Form and Form 10-403 R sed 5/2015 r(}f for 12 mon . m the date of approval. Attachments iupiicate RBDMSA\ �;�,Y 2 8 2015 aqi�- sl'`r, Well Prognosis Well: KBU 24-06RD Masora Alaska,LU Date:5/18/2015 Well Name: KBU 24-06RD API Number: 50-133-20499-01 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: June 1st, 2015 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-013 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: Current Bottom Hole Pressure: — 800 psi @ 5,328' TVD (Based on PT Survey on 10/15/12) Maximum Expected BHP: — 800 psi @ 5,328' TVD (Based on PT Survey on 10/15/12) Max. Allowable Surface Pressure: - 267 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft) Brief Well Summary Kenai Beluga Unit #24-06RD was drilled as a sidetrack EXCAPE completion in 2006 to target gas sands in the Beluga formations. The initial EXCAPE modules were placed on production in May 2006. A capillary string was installed in August 2009, the depth was adjusted in November 2009 and pulled in October 2012. The well loaded up in April 2014 and has been unable to sustain flow. The purpose of this work/sundry is to plugback and add perforations in the Upper Beluga. Notes Regarding Wellbore Condition • Well is SI, unable to sustain flow, built up with fluid. Current SITP is 30 psi. Slickline Procedure: 1. MIRU Slickline, PT Lubricator to 1,500 psi Hi 250 Low. 2. RU 2.5"gauge ring, RIH and tag fill at+/-7,744'. 3. RIH and set bridge plug at 5,470'. 4. Dump bail 25' of cement on top of bridge plug (9.2 gallons of cement). 5. Wait on cement for 24 hours. 6. RU 2.50" bailer and tag top of cement. a. Dump additional cement if cement top is below 5,445'. 7. Fill well with lease water. Pressure test plug to 1,500 psi for 30 min. 8. RD Slickline. Coiled Tubing Procedure: 9. MIRU Coiled Tubing, PT BOPE to 4,500 psi Hi 250 Low. 10. RIH w/ 1.75" coil to 5,445' MD and tag top of cement. 11. Displace well fluids with Nitrogen. a. Estimated volume of displaced produced water is 48 bbl. 12. Leave well with 400 psi Nitrogen SITP. 13. POOH w/coil. 14. RD Coiled Tubing. 15. Turn well over to production. . H Well Prognosis Well: KBU 24-06RD Hilcorp Alaska,LL Date: 5/18/2015 E-line Procedure: 16. MIRU E-line, PT lubricator to 1,500 psi Hi 250 Low. a. Tree connection is 6.5" OTIS. b. SITP will be 400 psi (Nitrogen Pressure). 17. RU 2-1/2" 6 spf Connex HC wireline guns. 18. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) FT SPF Upper Beluga UB5 5,217' 5,247' 30' 6 a. Bleed tubing pressure to 400 psi before perforating. b. Proposed perfs shown on the proposed schematic in red font. c. Correlate using CBL Log dated 4/02/06 (CBL Tie-in log). d. Use Gamma/CCL/to correlate. e. Record tubing pressures before and after each perforating run. f. Proposed intervals are in the Beluga/Upper Tyonek Gas Pool. g. Distance to nearest well open in same sands= 1,733'to KBU 31-07RD. h. Spacing allowance is based CO 510a; no wells within 1,500'of property border. 19. RD E-line. 20. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Coil BOPE Schematic Kenai Gas Field Well: KBU 24-6RD SC E MATI C Last Completed: 4/27/2006 uileoru Alaska,LLC API: 50-133-20499-01-00 CASING DETAIL RKB=87'/21'AGL Size Type Wt/Grade/Conn ID Top Btm 20"J II, 13 20" Conductor 133/K-55/N/A 18.73 Surface 107' -3/8" Surface 68/K-55/BTC 12.415 Surface 1,518' 9-5/8" Intermediate 40/L-80/BTC-MOD 8.835 Surface _ 5,489' 3-1/2" Production 9.3/L-80/EUE 8rd 2.992 Surface 7,812' Flapper Depth (MD) Detail 13-3/8"I L No. Depth Item 13 5,545' Conventional Module 12 5,595' Conventional Module 4 11 5,771' Conventional Module TOC @3,6311 NO !.. 10 5,813' Conventional Module -122 above top of .P 9 5,954' Conventional Module window opining •,:. -1,859'above 9-5/8" * 8 6,225' Conventional Module casing shoe. •-••••••.,;....6.', 6,333' Conventional Module •f# 6 6,385' Conventional Module �, ti Sidetrack Window: 5 6,597' Conventional Module 9-5/8"Wndaw r' Milled From 3,752'MD 4 6,726' Conventional Module :. to 3,768'MD 3 6,885' Conventional Module tw! 2 7,053' Conventional Module Max 1 Unknown Conventional Module-No Flapper tiff Inclination " 22.2°@ 3,964' EXCAPE SYSTEM DETAILS 4 -13 Conventional modules -Red control line fired modules 8 thru 13. control line fires top 8 modules. • + -Green line for BHP monitoring. 6 -Ceramic flapper valves below each module except Module 1. Module Top(MD) Btm(MD) Top(TVD) Btm(TVD) Zone lilt 13 5,520' 5,530' 5,328' 5,338' Beluga r'- 12 5,570' 5,580' 5,377' 5,387' Beluga 1! Di• 13 t11 5,746' 5,756' 5,547' 5,557' Beluga ,..w • r ) : u 10 5,788' 5,798' 5,588' 5,598' Beluga f ^11) , 12 9 5,929' 5,939' 5,727' 5,737' Beluga :• •, 11 8 6,200' 6,210' 5,996' 6,006' Beluga - J 7 6,308' 6,318' 6,104' - 6,114' Beluga %' i) :'+ 1� 6 6,360' 6,370' 6,156' 6,166' Beluga 5 6,572' 6,582' 6,368' 6,378' Beluga 10 9 4 6,700' 6,710' 6,496' 6,506' Beluga ) 3 6,860' 6,870' 6,656' 6,666' Beluga , ; 19 8 2 7,028' 7,038' 6,824' 1 6,834' Beluga �) ., 1 7,466' 7,476' 6,997' 7,007' Tyonek 7 Dt 6 CEMENTING DETAIL i�)t s' Casing Detail Di C 5 13-38" 17 1/2"hole Cmt w/608 sks,Class G n fny.)[ {/ 9-5/8" 12-1/4"hole Cmt w/ 1,005 sks of Class G Ui 4 8-1/2" 8-1/2"hole Cmt w/267 sks(102 bbls)of 12.7 ppg,Class G Lead&878 sks(181 bbls)of 15.8 ppg Tail Di ,•' 3 .' B1) i f 2 , , t it i Tagged 7,744'CTM) !, w/ 1-1/2"Coil -' ® 2/24/2014. IE it TD=7,830'MD/PBTD=7,774'MD Revised By:TDF 3-12-2013 Kenai Gas Field Well: KBU 24-6RD • li PROPOSED SCHEMATIC Proposed Completion Hilcorp Alaska,LLC API: 50-133-20499-01-00 CASING DETAIL RKB=87/21'AGL Size Type Wt/Grade/Conn ID Top _ Btm 20" Conductor 133/K-55/N/A 18.73 Surface 107' . 13-3/8" Surface 68/K-55/BTC 12.415 Surface 1,518' 'a" 9-5/8" Intermediate 40/L-80/BTC-MOD 8.835 Surface _ 5,489' 3-1/2" Production 9.3/L-80/EUE 8rd 2.992 Surface 7,812' Flapper Depth(MD) Detail 13-3/8"I L No. Depth Item 13 5,545' Conventional Module ' 12 5,595' Conventional Module 11 5,771' Conventional Module TCC@3,63o'MD 10 5,813' Conventional Module 12Yabavetop O' 9 5,954' Conventional Module window c enmg -1,859'above 9-5/8" ° 8 6,225' Conventional Module casmgshoe �3. 7 6,333' Conventional Module 6 6,385' Conventional Module Sidetrack Window: 5 6,597' Conventional Module 9-5/8 Window Milled From 3,752'MD 4 6,726' Conventional Module Y to 3,768'MD 3 6,885' Conventional Module 2 7,053' Conventional Module Max • 1 Unknown Conventional Module-No Flapper Inclination . 22.2°@ 3,964' W-1, • PERFORATION DATA • % Zone Top(MD) Btm(MD) Top(TVD) Btm(TBVD) SPF Date Condition Notes I, UB5 ±5,217' ±5,247' ±5,040' ±5,068' 6 Proposed }') ;rt UB-5 - Bilge � Capped.�- uv '-1 25'cement 5,470' 11 "13 ', ) , EXCAPE SYSTEM DETAILS 4; B) '12 -13 Conventional modules �:..., illi1 - 6u control line fired modules 8 thru 13. ` '11 control line fires top 8 modules. -n) r 10 -Green line for BHP monitoring. ) -Ceramic flapper valves below each module except Module 1. 9 ll �) Module Top(MD) Btm(MD) Top(TVD) Btm(TVD) Zone il) 8 13 5,520' 5,530' 5,328' 5,338' Beluga ', ) 12 5,570' 5,580' 5,377' 5,387' Beluga 1? it'P7 11 5,746' 5,756' 5,547' 5,557' Beluga i°# D)i6 10 5,788' 5,798' 5,588' 5,598' Beluga ) 9 5,929' 5,939' 5,727' 5,737' Beluga �)t 5 _8 6,200' 6,210' 5,996' 6,006' Beluga �y) 7 6,308' 6,318' 6,104' 6,114' Beluga iJ) 4 6 6,360' 6,370' 6,156' 6,166' Beluga DletI 5 6,572' 6,582' 6,368' 6,378' Beluga L) 3 4 6,700' 6,710' 6,496' 6,506' Beluga 11i 2 3 6,860' 6,870' 6,656' 6,666' Beluga 2 7,028' 7,038' 6,824' 6,834' Beluga '' fl) 1 1 7,466' 7,476' 6,997' 7,007' Tyonek Tagged 7,744'CMD '-- )r 3 w/ 1- 1/Y'cod - * CEMENTING DETAIL 2/24/2014. ID te to 1'.. Casing Detail • 13-38" 17 1/2"hole Cmt w/608 sks,Class G 9-5/8" 12-1/4"hole Cmt w/ 1,005 sks of Class G TD=7830'Np/PBTD=7774'MD 8-1/2" 8-1/2"hole Cmt w/267 sks(102 bbls)of 12.7 ppg,Class G Lead&878 sks(181 bbls)of 15.8 ppg Tail Downhole Proposed Revised By:STP 5-18-2015 Kenai Gas Field KBU 24-06RD 5/18/2015 H iIrori. .la•l(s.1.11.(. Kenai Beluga Unit 24-06RD 20 X 13 3/8 X 9 5/8 x 3 1/2 Coil Tubing BOP Lubricator to injection head 1.75"Tandem Stripper 1 1ii 0 •lilt Blind/Shear 41/161061 Blind/Shear -___1 1 •1111 Blind/Shear Blind/Shear lilt i • * `'ILL _Slip I r J _ Pipe C I Pipe ,I.'' I • .. .. . MudCross uI ul i - 41/16 10M X4 1/1610M 'Sid a info )41.10-iK 0 9111 0 11w Outlet sou_..,s, w/2-2 1/16 10M full opening FMC valves Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M 2 1/16 10M 2 1/16 10M Crossover spool 4 1/16 10M X 3 1/8 5M J� Z4 +, ,5'i�o- Valve,Swab,VG-300, 11114A moo,Q"` O 3 1/1610M FE,HWO, ,0 � \,e 6,y O4�� \tico ti0 J��� DD trim U Ja N. O ,51 fie.+�Q <ck. I:•wTi -. '5 OSP` J'°��P /- PAINsr , I 1-- � � ��1% O A Valve,Upper Master, ti.....„%s VG 300,3 1/16 10M FE, HWO,DD trim16%7 ' 1 L'ql 1, d Iy Valve,Master,VG-300, twAlor.-3 1/1610M FE,HWO, © os DD trim V r • Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~C2 ~ - 1.1 ~ 3 Well History File Identifier Organ%Zing (done) RE CAN Color Items: ^ Greyscale Items: ^ Poor Quality Originals: ^ Other: NOTES: BY: Maria ` Project Proofing BY: Maria Scanning Pr~epar~ation BY: M( aria i~ ~ _~ x 30 = + =TOTAL PAGES (Count does not include cover sh- - Date: 17 /a..I~ $ /s/ Y Production Scanning ' ' , IIIIIIIIIIIIII IIIII Stage 1 Page Count from Scanned File; ~ (Count does include cove sheet) Page Count Matches Number in Scanning Preparation: YES NO BY: Maria Date: /~1 a ~ lsl /// Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. III II'I II I II () I (III ReScanned III IIIIIIIIIII IIIII BY: Maria Date: /s/ Comments about this file: ~,wos,~a iuuiumiuiuu DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: ae~~~aea~ iiiuiiiiAUUUii OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: Date: Date ~bg . o~~e, YvGP dog IIIIIIIIIIIIIIIIII ~p a~,~„~~~~ iuuiuiiuuiui 10!6!2005 Well History File Cover Page.doc f • • KBU 24 -06RD Tubing Patch Install Jeremy Mardambek 907 - 777 -8388 ; P� _z_0(,,,0 13 2/5/2013 Well History: KBU 24 -06 is a producing Escape well drilled in 2006 as a slot recovery of the KBU 24 -06 which was abandoned due to casing deformation above the perfs. Water production has been an issue since the beginning of production in 2006. In 9/2009 a cap string was installed to mitigate the well from loading up but this did not effectively unload the . The well has not produced above its unloading rate since late 2008. Two PLT logs independently show most of the water production is coming from the second set of perfs from the top (Module 12). The spinner logs ran during A drift on 9/18/2012 showed the well has sand bridges but a 1.5" gauge ring was able to drift to 7061. Justification: The water production from the top module is cutting off the gas flow from the other 11 modules due to liquid loading. The well has not flowed above the unloading rate (1.2 MMSCFD @ 60 psi FTP) since early 2009. Isolating this set of perfs behind a patch will cut off water production and allow the well to unload. Recommendation: Brush and flush +/- 20' above and below 5570' -5580' to clean the well bore and ensure a good patch setting. Set a lower straddle packer, spacer pipe, and upper packer to isolate the pert interval from 5570' — 5580'. Use the CCL and GR PLT log ran on 8/10/2009 to tie into the depths located here....O: \Alaska \Fields \Kenai Gas Field \Well ,e Work Requests \KBU 24 -06RD Patch Install \KBU 24 -6rd PL Survey 7 -23 -2009 Risks: List of Figures: SCANNED APR 0 9 2011 Wellbore Schematic Directional Survey dT /dMD plot showing temperature anomalies from two PLT surveys Critical velocity for 3.5" Escape completion with deviation List of well tests Temperature, Capacitance, and Spinner logs across Module 12 HEC 1 Document located at O: \Alaska \Fields \Kenai Gas Field \Well Work Requests \KBU 24 -06RD Patch 1 Install e • KBU 24 -6RD Marathon Oil Permit #: 206, .013 r Pad 14.6 Alaska Production l,L.C.. API #: 50. 133.20499.01 -00 3 16' FSL, 1,255' FWL, Sec. 6, Prop. Des: A- 028142 K8 elevation: 87 (21' AGL) T4N, R11 W, S.M. Conductor Latitude: 60° 27' 37.172" N 20" K -55 133 ppf f :_ Longitude: 151°15' 43.822" W -- Top Bottom Spud: 2,2112006 MO 0' 107' TD: 3,22006 TVD Cr 107' Rig Released 3 /12,06, 1200his Surface Casing 13.318" K -55 68 ppf BTC Top Bottom MD 0' 1,518' ND 0' 1,518' Top of Cement 17-1/2" hole Cmt w /608 sks. Class 0 @ 3,630' MD ' 122' above top of window opening * 1,859' above 9 -518" casing shoe Intermediate Casing 40 ppf BTC Top Bottom M0 0' 5,489' Production 1: ., O 0' 5,299' ppt - -1:2" L-80 9.3 EUE Sidetrack windowmilledtrom Top Bottom 8rd T o 3,752' MD - 3.788' MD. MD 0' 7,812' 12. 114" hole Cmt w11,005 sks ofCIasG ND 0' 7,608' 8-1/2" hole Cmt w/267 sks (102 bbls) of 12.7 ppg Class G Lead 4 878 sks (181 bblsjof15.8ppgTail `` Excape System Details: - 13 Conventional Modules - Mod. 1- no flapper - Ceramic flapper valves below each module as follows: Flappers MD 02)(0): Module 13 - 5,539' r _ / N Module 12 - 5,589' Module 11 - 5,765' E'. ape System Details May: In: 20 3 Module 10 - 5,807' - 13 Ex( ape modules placed ,degree= Module 9 - 5,948' - Red control line tired modules8 thru 13 ( Module 8 - 6,219' control lrnestiredmoduls2 thru 7 Module 7 - 6,327' • control line fired module 1 Module 6 - 6,379' - Ceramicflappenialvesbelow�eachmodule - Module 5 - 6,591' excepttor module 1 i Module 4 - 6,719' Perfs Perfs C. Modules MD Tvo Zones I Module 3 .6,$79' 13 5,520'- 5,530' 5.328'- 5,338' (Beluga) Module 2 - 7,047' i 12 5.570'•5,580' 5,377'•5,386' (Beluga) t 11 5.746'•5.758' 5,547'•5 557' (Beluga) Capolar; String 10 5,788'•5,798' 5,588' -5,598' (Beluga) :. t i 3/8" «0f, `Sainleas Steel 9 5,929'- 5,939' 5.727'- 5,737' (Beluga) I Top Bottom 8 6,200' - 6.210' 5.996'•6,006' (Beluga) MD f 7 it >4' 7 8.308'•8,318' 6.104'- 8,114' (Beluga) ND Surf E•. :E2f; 6 6,360'- 8,370' 6,158' - 6,168' (Beluga) C (rndalled8 /111200'8i 5 8.572' - 8.582' 6,368%6.378' (Beluga) (adjusted 11/24)20031 4 6.700%6.710' 8.498'•6.506' (beluga) � (Inspected 5,02010 3 6.860'- 6.870' 6.658' - 6.866' (Beluga) 2 7,028' - 7.03 ^8' 6,824- 6,834' (Beluga) ' — __- _. -__ -- 1 7,466'- 7.476' 6.99T-7.007' (Tyonelr) Tagged i;9! 7,405' (1125109) with 318" Dynacoil TO EBTD BMA= 1 15" EC ° 2 5 "centr,lrzers ;: =:ii ?AD 7 774' MD 7,62E' T:ti 7.570' Tv0 Well Name :_: Number Kenai Beluga Unit 24 Lease: Kenai Gas Field Mirror:loamy Kenai Peninsula Borough State Alaska 1 Corntr•; I USA pet t!'rats m:: i MD). 5,520' - 7,476' Per t i T".-D) 5,329' - 7,001' .4rq " r?3' KOP 8 Depth: 20.3° , ;R! 3,752' MD 1 .'1r -i7 i An -:lc- , Pert= 15.5° — 2.5° Date Completed 7/142009 C rn,rrd Le'del 66' (AMSL) 1 F.I'.E 1 21' (AGL) . F'e iz b Keuin Skiba F'e•:r_l rr Date 8 - - 2011 Wellbore Schematic HEC 1 Document located at O: \Alaska \Fields \Kenai Gas Field \Well Work Requests \KBU 24 -06RD Patch Install • • MD Angle Azimuth TvD (ft) ( ( °) (ft) 0 0 0 0 346.00 0.79 294.8 345.99 586.00 1.23 264.2 585.95 827.00 1.93 274.4 826.86 954.00 1.14 284.6 953.81 1,269.00 1.93 276.5 1,268.70 1,397.00 0.7 293.7 1,396.66 1,471.00 0.53 7.5 1,470.66 1,538.00 0.58 58.8 1,537.66 1,640.00 1.9 47.5 1,639.63 1,704.00 2.59 54.2 1,703.58 1,801.00 4.2 58.3 1,800.41 1.890.00 5.3 65.1 1,889.10 1,985.00 7 69.2 1,983.55 2,077.00 8.78 69.4 2,074.68 2,170.00 10.18 74.3 2,166.41 2,266.00 11.72 76.8 2,260.66 2,328.00 12.72 76.1 2,321.25 2,392.00 13.83 76.3 2,383.54 2,517.00 15.84 75.1 2,504.37 2,614.00 17.37 75.4 2,597.32 2,710.00 18.8 75.8 2,688.57 2,835.00 19.96 74.1 2,806.49 2,962.00 19.67 74.4 2,925.97 3,183.00 20.31 76.9 3,133.54 3,342.00 20.07 74.7 3,282.48 3,470.00 20.91 74 3,402.26 3,723.00 20.39 74.6 3,639.42 3,752.00 20.37 74.4 3,666.61 3,964.00 22.2 32.5 3,865.25 4,029.00 21.8 17 3,925.57 4,092.00 21.5 7.8 3,984.14 4,155.00 21.4 3.1 4,042.78 4,218.00 21.4 2.4 4,101.44 4,282.00 21 356 4,161.12 4,345.00 20.8 352.5 4,219.97 4,408.00 20.9 352.4 4,278.85 4,471.00 21 352.5 4,337.68 4,534.00 21 352.2 4,396.50 4,597.00 20.7 351.6 4,455.37 4,661.00 20.3 351.4 4,515.32 4,723.00 19.9 352.1 4,573.54 4,786.00 19.8 351.5 4,632.80 4,850.00 19.6 351.1 4,693.06 4,913.00 19.4 350.7 4,752.44 4,975.00 19 350.5 4,810.99 5,039.00 19.1 350.9 4,871.49 5,102.00 19 350.9 4,931.04 5,166.00 18.8 350.9 4,991.59 5,229.00 18.6 351 5,051.26 5,292.00 18.2 350.4 5,111.04 5,355.00 18 346.8 5,170.92 5,418.00 17.9 345.9 5,230.86 5,480.00 16.6 346.1 5,290.07 5,541.00 15.7 346.7 5,348.66 5,605.00 15.3 347.4 5,410.33 5,669.00 13.9 349.4 5,472.26 5,732.00 12.5 347.9 5,533.60 5,794.00 10.8 345.9 5,594.32 5,857.00 9.5 344.2 5,656.33 5,921.00 8.2 340.8 5,719.57 5,984.00 7.7 341.6 5,781.96 6,047.00 7.7 344.2 5,844.40 6,108.00 6.8 344.4 5,904.91 6,172.00 5.7 349.4 5,968.53 6,236.00 4.4 354.7 6,032.28 6,298.00 2 17.3 6,094.18 6,361.00 1.3 60 6,157.15 6,422.00 1.3 62.3 6,218.14 6,486.00 1.3 55.6 6,282.12 6,549.00 0.5 22.8 6,345.11 6,612.00 0.4 335.1 6,408.11 6,674.00 0.5 338 6,470.11 6,737.00 0.5 316.4 6,533.11 6,862.00 0.4 286.2 6,658.10 6,989.00 0.4 271.8 6,785.10 7,116.00 0.6 253.6 6,912.10 7,241.00 0.5 224.1 7,037.09 7,367.00 0.8 185.3 7,163.08 7,450.00 0.8 180.2 7,246.08 7,492.00 0.7 181.2 7,288.07 7,554.00 0.7 160.1 7,350.07 7,649.00 0.9 155.1 7,445.06 7,774.00 0.9 146.3 7,570.04 7,830.00 0.9 146.3 7,626.04 KBU 24-06RD Deviation Survey HEC f Document located at O: \Alaska \Fields \Kenai Gas Field \Well Work Requests \KBU 24 -06RD Patch 3 Install i KBU 24 -06RD dT /dMD from 7/23/2009 -0.075 0.025 0.425 ♦ *HO. M N • N * ♦♦ 5700 — — 5900 Warming temperature anomaly indicating water production • dT /d M D III Top of Perfs Bottom of Perfs 6700 , P1 dTemp /dMD from PLT log ran on 7/23/2009 HEC 1 Document located at O: \Alaska \Fields \Kenai Gas Field \Well Work Requests \KBU 24 -O6RD Patch - Install • KBU 24-06RD dT/d MD from 8/9/2008 7 * .* * Warming temperature anomaly indicating 1. water production *dT/dMD *Top of Perfs 6200.1 A.Bottom of Perfs 6:i; •M dTemp/dMD from PLT log ran on 8/9/2008 HEC 1 Document located at 0:\Alaska\Fields\Kenai Gas Field\Well Work Requests\KBU 24-06RD Patch Install • • • NBU 24 06R HBU 24 06RD 252013 NBU 24AERD 2 5 -2013 Reserver Data T&gm prs gad 67 (g1000 msctpd Pressure • 145000 psis 05 Feb - 1317.x.41 kb• 171700 V43 De001 * 6000 SW • 5000 N9Pres (Para) • 6000 0 iutrrg ID • 2 992 (s1) t VelGas Hydraulics ease VG98 -L Hyrauks ease 1000 - 2000 vrri L 4 A 4 00 U a-{ F 5100 f l l 7000 1 n p 30 40 so 70 Gas Velocity ( /sec) Pink line = Velocity in (ft/sec) at 1MMSCFD and 60 psi Tan line = Unloading velocity in (ft/sec) at 1MMSCFD and 60 psi When the pink line is to the left of the tan line, the well is below the unloading rate. This indicates the well needs to be above 1.2 MMSCFD to remain unloaded. HEC 1 Document located at 0: \Alaska \Fields \Kenai Gas Field \Well Work Requests \KBU 24 -06RD Patch x `µ Install • • Well Date Gas(MSCFD) Water (BWPD) FTP (psi) 24 -06RD KBU 12/11/2008 1141.6 24 74 24 -06RD KBU 2/12/2009 1080 19.2 80 24 -06RD KBU 3/1/2009 922.7 15.6 67 24 -06RD KBU 4/9/2009 1050 22.3 66 24 -06RD KBU 5/6/2009 1088 19.6 68 24 -06RD KBU 6/24/2009 594.4 50.3 79 24 -06RD KBU 7/8/2009 793.3 28 102 24 -06RD KBU 8/17/2009 1102.6 13.4 109 24 -06RD KBU 9/9/2009 1135.8 16.2 218 < -Cap string installed 24 -06RD KBU 11/30/2009 1015.9 45 98 24 -06RD KBU 12/10/2009 1120.7 19.5 143 24 -06RD KBU 1/18/2010 883 15.4 224 24 -06RD KBU 2/18/2010 1098.8 16.7 169 24 -06RD KBU 2/23/2010 0 0 167 24 -06RD KBU 3/4/2010 978 17 127 24 -06RD KBU 4/3/2010 877.4 10 149 24 -06RD KBU 5/26/2010 827.4 0.3 95 24 -06RD KBU 6/17/2010 816 11.4 238 24 -06RD KBU 7/6/2010 684.7 14.2 83 24 -06RD KBU 8/12/2010 795 14.8 133 24 -06RD KBU 9/12/2010 641.5 15 242 24 -06RD KBU 10/13/2010 675.8 14.5 196 24 -06RD KBU 11/10/2010 814.9 12.5 141 24 -06RD KBU 12/9/2010 698 13.9 202 24 -06RD KBU 3/28/2011 957.8 20 90 24 -06RD KBU 4/7/2011 870 17 89 24 -06RD KBU 5/23/2011 810 11.4 88 24 -06RD KBU 6/16/2011 754.35 21.34 105 24 -06RD KBU 7/14/2011 388 18.6 105 List of well tests Nr HEC 1 Document located at 0: \Alaska \Fields \Kenai Gas Field \Well Work Requests \KBU 24 -06RD Patch ,--:W,,;' ^g.k ;; Install �<a"` • • • 95 Capacitance 30' /min Down 115 100 Temperature 30' /min Down (degF) 120 95 Capacitance 90' /min Down 115 100 Temperature 90' /min Down (degF) 120 95 Capacitance 60' /min Down 115 100 Temperature 607min Down (degF) _ 120 __.. JJVV _ 1 - - , _- - - r 3 _ _ - _. _ ___ __,_ : - 4--- I M12 odule + { -4 -.-- ! ''k i F I - t I a— A i – . — _, – !1 - 4 _,, , ___, -4 4- ■ )1 i 41, ,:- - 4 - t 5600 / ___ , . i i Capacitance and Temperature spike at water producing perfs. -150 Line Speed 30' /min Down 150 -50 Spinner 307min Down (rps) 50 -150 Line Speed 907min Down 150 -50 Spinner 90' /min Down (rps) 50 -150 Line Speed 60' /min Down 150 -50 Spinner 60' /min Down (rps) 50 --euA 5550 — 1 . , __-1 II -1. < M -4- a TM 16 1 1= – ' -'-" 11==E H- • ....ii EMI= 1 Module 12 � _ i E _ .itr .. _ - 7 . islis Iiimir- _aism�: -- mmul'i 5 600 k- _... — t _ T Spinner shows approximately 10% of flow from Module 12 0% flow 100% flow Unsure of composition but likely water due to temperature and capacitance anomalies HEC I Document located at O: \Alaska \Fields \Kenai Gas Field \Well Work Requests \KBU 24 -06RD Patch 8 Install i _~ ,§ ~~, ~~ ~. *.. .~ ~ i ~-J ~~ MICROFILMED 6/30/2010 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE C:\temp\Temporary Internet Files\OLK9\Nticrofilm_Marker.doc Maropon Alaska Production LLC Marathon Alaska Asset Team P.O. Box 1949 M .Alaska Production LLC Kenai, AK 99611 Telephone 907/283 -1371 Fax 907/283 -1350 December 9, 2009 R ECEIVED Mr. Winton Aubert DEC 1 1 2009 Alaska Oil & Gas Conservation Commission Alaska Oil & Gas Cons. Commissial) 333 W 7 Ave Are€ hnrege Anchorage, Alaska 99501 0 ®I Reference: 10 -404 Report of Sundry Well Operations --- - Field: Kenai Gas Field Well: Kenai Beluga Unit 24 -6RD z ANNE DES. 2 1 2005 Dear Mr. Aubert: Attached for your records is the10 -404 Report of Sundry Well Operations for KBU 24 -6RD well. This report covers the work performed to adjust the capillary string setting depth. The 3/8" capillary string was moved up -hole 375' and reset at a depth of 7,030' MD. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Sincerely, 4 ,�, - - 5 Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10 -404 Report of Sundry Well Operations cc: Houston Well File Operations Summary Kenai Well File Well Schematic KJS KM;ItI V CU STATE OF ALASKA DEC I 1 7009 ALASKA AND GAS CONSERVATION COMMIS REPORT OF SUNDRY WELL OP E RATION SAlaska Gil & Gas Cons. Commission Ant +, ,Trgnt? 1. Operations Abandon Ll Repair Well Ll Plug Perforations L StimulateL Other d Install Capillary Performed: Alter Casing ❑ Pull Tubing❑ Perforate New Pool ❑ Waiver❑ Time Extension ❑ String Change Approved Program ❑ Operat. Shutdown❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator Marathon Alaska 4. Well Class Before Work: Permit to Drill Number: Name: Production LLC Development ❑✓ Exploratory 1 206 -013 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ API Number: Kenai Alaska, 99611 -1949 50- 133 - 20499 -01 -00 B Elevation (ft): . Well Name and Number: 87' 21 AG L) Kenai Beluga Unit 24 -6RD Property Designation: 0. Field /Pool(s): A - 028142 Kenai Gas Field / Beluga & Tyonek Pools 11. Present Well Condition Summary: Total Depth measured 7,830' feet Plugs (measured) NA true vertical 7,626' feet Junk (measured) NA Effective Depth measured 7,774' feet true vertical 7,570' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 86' 20" 107' 107' 3,060 psi 1,500 psi Surface 1,463' 13 -3/8" 1,518' 1,484' 3,450 psi 1,950 psi Intermediate 3,661' 9 -5/8" 3,768' 3,682' 5,750 psi 3,090 psi Production 7,791' 3 -1/2" 7,812' 7,608' 10,160 psi 10,530 psi Liner Perforation depth: Measured depth: 5,520'- 7,476' True Vertical depth: 5,329'- 7,272' Excape Tubing 3 -1/2" L -80 7,812' Tubing: (size, grade, and MD) Capillary String 3/8" 22 Stainless Ste el 7,030' Packers and SSSV (type and measured depth) NA NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): The 3/8" capillary string was raised up hole 375' and set at 7,030' MD. Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1,135 16 25 58 Subsequent to operation: 0 1,015 45 25 102 14. Attachments: . Well Class after work: Copies of Logs and Surveys Run Exploratory ❑ Development Service ❑ Daily Report of Well Operations X Well Status after work: Oil ❑ Gas WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: NA Contact Kevin Skiba (90 283 - Printed Name Kevin J. Skiba Title Regulatory Compliance Technician Signature Phone (907) 283 -1371 Date December 9, 2009 V V /A I 61 Form 10 -404 Revised 04/2006 � Submit Original Only � �` A Oil C Marathon Operations Summary Report by Job , omPanY Well Name: KENAI BELUGA UNIT 24 -6 I Report Date: 1124/1009 Job Cate o : R &M MAINTENANCE 24 Hr Summary Held PJSM w/ BJ Dynacoil, ASRC, and UOSS. Shut down for high winds. op s Trouble Start Time End Time Dur his O s Code Activity Code Status Code Comment 09:00 10:00 1.00 SAFETY MTG AF Held PJSM w/ BJ Dynacoil, ASRC, and UOSS. Discussed windy conditions, working with manlifts, and handling chemicals. Obtained safe work permit. 10: 20.00 WAITON WTHR Shut down due to windy conditions for operating cranes and manlift. Report Date: 11252009 Job Cate o : R &M MAINTENANCE 24 Hr bummary Pull well house and MIRU BJ Dynacoil. Pull capillary string free and tag fill @ 7,405' MD RKB. Spot 1 gal foamer @ 6,576' and 7,030'. Blow well down and bring back water and foam after 1 hour. Set capillary string @ 7,030' (Module 2) and RDMO BJ Dynacoil. Flow well to atmosphere overnight and turn to production. CICM pump set @ 3 gal /day. ops Trouble Start Time End Tim. Dur hrs Ci sCode Activity Code Status Code Comment 09:00 10:00 1.00 SAFETY MTG AF Held PJSM w/ BJ Dynacoil, ASRC, and UOSS. Discussed windy conditions, working with manlifts, and handling chemicals. Obtained safe work permit. 10:00 10:30 0.50 WAITON EOIP AF Move wellhouse wl ASRC crane. 10:30 13:00 2.50 RURD COIL AF Spot Dynacoil equipment, load spool on truck, split injector, and land on wellhead. 13:00 14:30 1.50 RUNPUL COIL AF PU on capillary string 1600# overpull and would not move. Work string f/ 10 min. Set down 300# less than string weight and pulled free. Appeared to be stuck in packoff. POOH 600' and RIH to tag @ 7405' MD RKB. POOH t/ 6575'. 14:30 14:45 0.25 PUMP TRET AF Fill string w/ foamer (9 gals) and spot 1 gal foamer. RIH t/ 7030' and spot 1 gal foamer. 14:45 16:00 1.25 FLOW BACK AF Blow down well from 1080 psi to 0 psi. Water to surface after 1 hour. Made approx. 30 bbls water in 2 hrs and switched to heavy foam production. 16:00 18:00 2.00 RURD COIL AF Hang off capillary string @ 7030' (Module 2). RD injector head and spool excess tubing. Connect to CICM and set at 3 gal /day. Sign out, turn in safe work permit, and leave location. www.peloton.com Page 1/1 Report Printed: 12/92009 f KBU 24 -6RD M Permit #: 206 -013 Pad 14 -6 API #: 50- 133 - 20499 -01 -00 MARATHON Prop. Des: A- 028142 316 FSL, 1,255' FWL, Sec. 6, KB elevation: 87' (21' AGL) T4N, R11 W, S.M. Conductor Latitude: 60° 27' 37.172" N 20" K -55 133 ppf Longitude: 151 15' 43.822" W Top Bottom Spud: 2/21/2006 MD 0' 1 TVD 0' 1077' TD: 3/2/2006 Rig Released: 3/12/06 @ 12:00 hrs Surface Casing 13 -3/8" K -55 68 ppf BTC Top Bottom MD 0' 1,518' TVD 0' 1,518' 17 -1/2" hole Cmt w/ 608 sks, Class G I i Top of Cement Intermediate Casing @ 3,630' MD 9 -5/8" L -80 40 ppf BTC Top Bottom * 122' above top of window opening MD 0. 5,489' 1,859' above 9 -5/8" casing shoe TVD 0' 5,299' Sidetrack window milled from 3,752' MD - 3,768' MD. 12 -1/4" hole Cmt w/ 1,005 sks of Clas G i Production Casing Excape, System Details: 3 -1/2" L -80 9.3 ppf ELIE - Ceramic flapper valves below Top Bottom 8rd each module as follows: MD 0' 7,812' TVD 0' 7,608' 8 -1/2" hole Cmt w/ 267 sks (102 bbls) Flappers MD (RKB1: of 12.7 ppg Class G Lead & 878 sks Module 13 5,545' (181 bbls) of 15.8 ppg Tail Module 12 5,595' Module 11 - 5,771' Module 10 - 5,813' Excape System Details Module 9 5,954' 13 Excape modules placed control line fired modules 8 thru 13 Module 8 6,225' Max Inc 20.9 control lines fired modules 2 thru 7 Module 7 - 6,333' degrees control line fired module 1 Module 6 - 6,385' Ceramic flapper valves below each module Module 5 - 6,597' except for module 1 Module 4 - 6,726' Module 3 - 6,885' Perfs MD (RKB)Beluga & Tyonek Zones): Module 2 - 7,053' Module 13 - 5,520'- 5,530' (Beluga) Module 1 - NA Module 12 5,570'- 5,580' (Beluga) Module 11 - 5,746' - 5,756' (Beluga) Module 10 5,788'- 5,798' (Beluga) Module 9 - 5,929' - 5,939' (Beluga) t Module 8 6,200'- 6,210' (Beluga) Tagged @ 7,405' (11/25/09) Module 7 - 6,308'- 6,318' (Beluga) with 3/8" Dynacoil D Module 6 - 6,360'- 6,370' (Beluga) BHA = 1.25" FCV & 2.25" centralizers D Module 5 6,572'- 6,582' (Beluga) Module 4 - 6,700'- 6,710' (Beluga) r[ Module 3 - 6,860'- 6,870' (Beluga) Capillary String D ir Module 2 - 7,028'- 7,038' (Beluga) 3/8" 2205 Stainless Steel Module 1 - 7,466'- 7,476' (Tyonek) Top Bottom MD Surf 7,030' TVD Surf 6,826' (installed 8/11/2009) (adjusted 11/24/2009) TD PBTD 7,830' MD 7,774 MD 7,626' TVD 7,570' TVD Well Name & Number: Kenai Beluga Unit 24 -6RD Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska I Country: USA Perforations (MD): 5,520' - 7,476' Perf (TVD): 5,329' - 7,007' Angle @ KOP & Depth: 20.3° @ 3,752' MD (window) Angle @ Perfs: 15.5° 2.5° Date Completed: 7/14/2009 Ground Level: 66' (AMSL) I RKB: 21' (AGL) Revised by: Kevin Skiba Revision Date: 12/9/2009 ~ ~ Marathon IMARAiHON Ataska Produc#ian LL~ ~ September 1, 2009 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field Well: Kenai Beluga Unit 24-6RD Dear Mr. Aubert: M~athon Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 1~EC~~V~~ s~P o ~ ~ao~ Alas~Ca Oi1 ~ Gas Co~1s. COmittis~iA~ ~nchoFaBe ~~~_ ~ ~ 3 Attached for your records is the10-404 Report of Sundry Well Operations for KBU 24-6RD well. This report covers the capillary string installation work performed under Sundry #309-246. The 3/8" capillary string was installed on 8/10/2009 and set at a depth of 7,405' MD. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ~ ` ~ ..~~`1~`'~'a ' Kevin J. Skiba Regulatory Compliance Technician '~i~ ~~`~" ,~ ~ x ,~~1%.`_; `~-' ~ ~'4: ~~ °t~,..~_r _ ~ Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Operations Summary Kenai Well File Well Schematic KJS STATE OF ALASKA ALAS~IL AND GAS CONSERVATION COMMI~N REPORT OF SUNDRY WELL OPERATIONS ~G~ 9~og~Zoof RE~.~r~~ ^.`... SEP 0 ~ t~,~;~ 1. Operations Abandon Repair Well Plug Perforations Stimulate t}~e~ I~tstall Ca~i~lary ~It~t S GUfi'r ' ~ ~ ~ ~ s~~ ~ ~~~~ . ~ ,, = Performed: Alter Casing ~ Pull Tubing^ Perforate New Pool ~ Waiver~ i ension String Change Approved Program ^ Operat. Shutdown0 Perforate ~ Re-enter Suspended Well hOFB~@ 2. Operator Marathon Alaska 4. Well Class Before Work: 5. Permit to Drill Number: Name: p~oduCtlon LLC Development ~ Exploratory^ 206-013 / 3. Address: p0 BoX 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20499-01-00 ~ 7. KB Elevation (ft): 9. Well Name and Number: 87' 21' AGL Kenai Belu a Unit 24-6RD ~ 8. Property Designation: 10. Field/Pool(s): A- 028142 ~ Kenai Gas Field / Beluga 8~ Tyonek Pools 11. Present Well Condition Summary: Total Depth measured 7,g3p~ feet Plugs (measured) NA true vertical 7,g2g' feet Junk (measured) Nq Effective Oepth measured 7,774' feet true vertical 7,57p' feet Casing Length Size MD TVD Burst Collapse ~ Structural Conductor g6' 20" 107' 107' 3,060 psi 1,500 psi Surface 1,463' 13-3/8" 1,518' 1,484' 3,450 psi 1,950 psi Intermediate 3,661' 9-5/8" 3,768' 3,682' 5,750 psi 3,090 psi Production 7,791' 3-1/2" 7,812' 7,608' 10,160 psi 10,530 psi Liner Perforation depth: Measured depth: 5,520' - 7,476' ~ True Vertical depth: 5,329' - 7,272' Excape Tubing 3-1/2" L-80 7,812' Tubing: (size, grade, and MD) Capillary String 3/8" 2205 Stainless Steel 7,405' Packers and SSSV (type and measured depth) NA NA 1-~ o k v ~ 12. Stimulation or cement squeeze summary: Intervals treated (measured): A 3/8" stainless steel capillary string was installed at a setting depth of 7,405' MD. Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas- f Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 ,100 ;• 3 93 25 Subsequent to operation: 0 790,.` 28 r' 111 25 14. Attachments: 15. Well~iass afterwork: °~ Copies of Logs and Surveys Run Exploratory [] Development ^~ Service [] Daily Report of Well Operations X 16. Well Status after work: Oil ^ Gas ~ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 309-246 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba y; Title Regulatory Compliance Technician ~ ~ Signature i Phone (907) 283-1371 Date September 1, 2009 Form 10-404 Revised 04/2006 ~ '~. . ~ ~ ~~ ` ~' ;~ ~` ~~~~ Submit Original Only 'j Marathon ~ ~perations Summary Report ~ ,,,,~ Q~~ C~Y Vlfell Name: KENAI BELUGA UNIT 24-6 Re ort Date: 7242009 Job Cate a: R&M MAINTENANCE 24 Hr Summary MIRU Expro wireline to perform flowing PL survey for cap string install. RIH w/ 2.25" centralizer & 1" swage and tag @ 7,472' RKB. RIH wl PL string and perfom flowing PL @ 60, 90, 120 fpm. RDMO Expro. Start Time End Time Dur hrs 0 s Code Activi Code Ops Status Trouble Code Comment 07:30 08:30 1 00 SAFETY MTG AF Held PJSM w! Expro and operator. Discussed emergency operations, smoking/muster areas, emergency lights, and crane operations. Obtained safe work permit. 08:30 09:30 1 00 RURD ELEC AF RU wireline truck and PU lubricator and tool strin . 09:30 09:45 0.25 TEST EQIP AF PT lubricator to 2500 psi. Good test. 09:45 11:15 1 50 RUNPUL ELEC AF RIH w! 2.25" centralizer and 1" swage. Tag solid PBTD @ 7,472'. POOH. 11:15 16:00 4 75 LOG PROD AF RIH w/ PL and spinner tool string as follows: Air: 15.2 psia and ~7.7 degF 5 min bench at surface: start: 130.4 psia and 57.8 degF end: 129.1 psia and 51.8 degF RIH and suroey 30fpm down Q 5300'RKB Spinner quit @ 7000' WT and spinner free, PU hole RIH @ 60fpm from 5300' Spinner quit @ 6600', WT and PU hole RIH @ 90fpm from 5300' Spinner quit @ 6200', continue RIH logging t/7460'. Log up pass @ 90fpm to 5300'. POOH. 16:00 17:00 1.00 RURD ELEC AF RD wireline truck and luhricator. Sign out, turn in permit, and leave location. Daily Operations Re ort Date: 8/112009 Job Cate o: R&M MAtNTENANCE 24 Hr Summary Rig up BJ Chemical DynaCoil unit. Run into hole with 3l8" coil. Tag bottom at 7411' MD. Set coil at 7405' MD. Maximum OD of Bottom Hole Assembly fins - ~.19" measured. Set initial pump rate at 1 GPD foamer. Ops Trouble Start Timz Er~d Time Dur hrs 0 s Coda Activi Cod¢ Status Codo Commant 08:00 08:45 0.75 SAFETY MTG AF PJSM - held in conjunction with simultaneous operations of ASRC crane operations and ASRC Arctic Iron install of sand buster and gas buster. Topics discussed - JSA assignments ofjobs, pinch points, working under suspended loads, hand safety, active gas production pad, red lights for fre, hlue lights for gas emission, sirens for audible, muster area will be at southern edge of pad on road entrance from 41-7 pad, hunters and hunting season, emergency vehicles, emergency numbers etc. 08:45 12:15 3 50 RURD COIL AF Rig up coiled tuhing unit. Calibrate Fluid Control valve - 3140#. Pull test Control valve. 12:15 12:45 0 50 TEST WLHD AF Pressure test wellhead and coiled tubing packoff to 1500#- test successful. 12:45 14:30 1 75 RUNPUL COIL AF Run DynaCoil into hole. Set down at 7411' MD. Pull up and set at 7405' MD. Packoff coil in tree. 14:30 15:45 1 2~ RURD COIL AF rig down DynaCoil unit. Hook up injection skid to coil and wellhouse power to injection skid. 15:45 16:30 0.75 PUMP TRET AF Pump foamer into coil to load well. Set injection skid pump to 1 BPD. 16:30 16:45 0 25 SECURE WELL AF Secure wellhead, hang signs on swab valve and upper 1 lower master valves warning about coil across tree valves. Turn in work permit. sign out and leave location www.peloton.com Report Printed: 827/2009 ~ 50-133-20499-01-00 >: A- 028142 tion: 87' (21' AGL) 60° 27' 37.172" N e: 151° 2/27/2C 3/2/20i ~sed: 3 KBU 24-6RD Pad 14-6 316' FSL, 1,255' FWL, Sec. 6, T4N, R11W, S.M. J C " 122' above * 1,859' abo Excape Systen - Ceramic flapp each module Flappers MD (f Module 13 - : Module 12 - : Module 11 - : Module 10 - : Module 9 - : Module 8 - f Module 7 - E Module 6 - E Module 5 - E Module 4 - E Module 3 - E Module 2 - ' Module 1 - Tac with a 1."e ~ M w~w-n~oN Conductor 20" K-55 133 ppf Top Bottom MD 0' 107' TVD 0' 107' SurFace Casinp 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,518' TVD 0' 1,518' 17-112" hole Cmt w/ 608 sks, Class G itermediate Casina 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' S,489' TVD 0' S,299' Sidetrack window milled from 3,752' MD - 3,768' MD. -1/4" hole Cmt wl 1,005 sks of Clas G 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 7,812' TVD 0' 7,608' 8-1/2" hoie Cmt w/ 267 sks (102 bbls) of 12.7 ppg Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail 3 Excape modules piaced d control line fired modules 8 thru 13 control lines fired modules 2 thru 7 control line fired module 1 ramic flapper valves below each modulE cept for module 1 ~ule 13 - 5,520'-5,530' (Beluga) ~ule 12 - 5,570'-5,580' (Beluga) ~ule 11 - 5,746'-5,756' (Beluga) ~ule 10 - 5,788'-5,798' (Beluga) ~ule 9 - 5,929'-5,939' (Beluga) ~ule 8 - 6,200'-6,210' (Beluga) jule 7 - 6,308'-6,318' (Beiuga) ~ule 6 - 6,360'-6,370' (Beluga) jule 5 - 6,572'-6,582' (Beluga) ~ule 4 - 6,700'-6,710' (Beluga) ~ule 3 - 6,860'-6,870' (Beluga) jule 2 - 7,028'-7,038' (Beluga) jule 1 - 7,466'-7,476' (Tyonek) Well Name & Number: Kenai Beluga Unit 24-6RD Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 5,520' - 7,476' Perf (ND): 5,329' - 7,007' Angle @ KOP & Depth: 20.3° @ 3,752' MD (window) Angle @ Perfs: 15.5° ~ 2.5° Date Completed: 7/14/2009 Ground Level: 66' (AMSL) RKB: 21' (AGL) Revised by: Kevin Skiba Revision Date: Aug. 31, 2009 ~ t ~ an ~ ~ ~ Y ~ ~ ~ a ~ 4 ~~ ~;~~ ~ ~,. ~,, ~~ ~ ~,~~, ~~s ~`~b P~.~ , 4 fµ~ I W ~ ~ I ~~ t ~ ft S t..3 b ' '_ ~ ~ ;~ ~{ ~ ~~t k ~ M ~~ pd~ ~,~ ~q ' ' F t ;, ~ ~ ~ ! ~ F .~. T_ 4.- ~ .__. ~~..r~' ,~€ ~ r. ~ tm`~ "_vA~ ! ~ a ~ ~~e~ t~ Sp ~ ~.~ k f ~ ~ ~_u §~ ~ @ F.~, 4~ ALASSA ~u A1~D G ~ COI~TSERQAti.`IO1~T COMI~IIS51O1~T Mr. Kevin J. Skiba Regulatory Compliance Technician Marathon Oil Company P.O. Box 1949 Kenai, Alaska 99611-1949 Re: Kenai Gas Field, Beluga 8v 'I~onek Pools, Kenai Beluga Unit 24-6RD Sundry Number: 309-246 ~ SARAH PALIN, GOVERNOR 333 W. 7thAVENUE, SUITE 100 ANCHORAGE,ALASKA 99501-3539 PfiONE (907) 279-1433 FAX (907) 276-7542 n~3 ,~ i ~O :, ~ ~;:~~*~~,~ .~~s ~;~ ~~ ~.~ ~~l~i 3 Dear Mr. Skiba: 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). 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 rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seamount, Jr. ~ Chair r DATED thisZ3 day of July, 2009 Encl. ~ ~ M Marathon MARATHON O~I Company ~~ Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 f~GCE~VGD July 15, 2009 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-403 Application for Sundry Approvals Field: Kenai Gas Field Well: Kenai Beluga Unit 24-6RD Dear Mr. Aubert: Alaska Qii 8~ Gas Cons. CommissiQn Anchara~e Marathon proposes to run a 3/8" capillary string in KBU 24-6RD to assist with water loading mitigation. The target setting depth for this capillary string is 7,030' MD. Please call me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ..~ ° v Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10-403 Application for Sundry Approvals cc: AOGCC Current Well Schematic Houston Well File Detailed Operations Program Kenai Well File KJS JUL ~ 7 2009 g ~ STATE OF ALASKA 1 vi~ ALAS~OIL AND GAS CONSERVATION COMMI~N APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ~ECEIVEt?~~~ JUL 1 '7 200~0~ ~~„9 ~laska qil & Gas Gons. Cammissinn 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown^ Perforate ^ Waiver ~~~~~~~~ Other ^~ Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ~ Install Capillary Change approved program ~ Pull Tubing ~ Perforate New Pool ^ Re-enter Suspended Well ~ String 2. Operator Name: Marathon Oil Company 4. Current Well Class: 5. Permit to Drill Number: Development ~ Exploratory ~ 206-013 - 3. Address: p0 Box 1949 Stratigraphic ~ Service ~ 6. API Number: Kenai Alaska, 99611-1949 50-133-20499-01-00 ' 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: ~ ^ Kenai Beluga Unit 24-6RD- Spacing Exception Required? Yes No 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): A- 028142 - 87' -(21' AGL) Kenai Gas Field / Beluga & Tyonek Pools ~Z• PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 7,830' - 7,626' - 7,774' . 7,570' - NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor g6' 20" 107' 107' 3,060 psi 1,500 psi SurFace 1,463' 13-3/8" 1,518' 1,484' 3,450 psi 1,950 psi Intermediate 3,661' 9-5/8" 3,768' 3,682' S,750 psi 3,090 psi Production 7,791' 3-1/2" 7,812' 7,608' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 5,520' - 7,476' 5,329' - 7,272' Excape 3-1/2" L-80 7,812' Capillary Packers and SSSV Type: Packers and SSSV MD (ft): NA NA 13. Attachments: Description Summary of Proposal ~ 14. Well Class after proposed work: Detailed Operations Program Q BOP Sketch ~ Exploratory ^ Development Q- Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: August 1, 2009 ~ Oil ~ Gas ^~ _ Plugged ~ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ~ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Technician Signature hon (g07) 283-9371 Date July 15, 2009 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~~~ ~~~ Plug Integrity ^ BOP Test ~ Mechanical Integrity Test ^ Location Clearance ^ Other: Subsequent Form Required: ~O - 40 4• APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 7 Z3 Form 10- 03 Revised 06/2006 0 R I G I N A L Submit in Duplicate 2008 Capillary String Installation• ~ AAT KBU 24-6RD Dyna-Coil Capillary Installation Pad 14-6 WBS: W0.09.requested.CAP.001 Obiective Install capillary string (3/8" 2205 0.049" WT) into well for delivering foamer to alleviate liquid loading. Procedure Capstring Set Depth: 7030' (6826' TVD) Coil length: 8000' M~ OD of BHA: 2.250" centralizer Min OD of 3.5" Excape: 2.992" Depth/OD of last tag: 2.00" tag 6903' (2/14/08), 1.75" tag 7080' (8/10/09) Installation Procedure: Disconnect power to wellhouse (call electrician) MI crane, manlift. Remove wellhouse. On site: 8,000' spool, long-style Well Head Adapter (WHA), Sundry, Work Permit, Well Control Standards Sheet. Install Capillary String (JSA~: 1. MIRU BJ Dyna-Coil unit. Place liner around wellhead and truck. 2. Shut swab valve. Pull tree-cap flange. Replace OTIS blanking plug with WHA (note o-rin~). MU flange. 3. Pressure test 1.Sx SIWHP. Watch for leaking swab valve. 4. P/U Dyna-Coil injector with crane. Run capstring through injector and pack-of£ Iinsert support pi , 5. Set Fluid Control Valve pressure =(setting TVD 6,826')(0.433 psi/ft H20)(1.036 foamer SG) 3,064~psi (the CICM surface pump pressure will then equal BHP). --'~ 6. Run the 3/8" string through pack-off. Insert injector head pin to support the pack-off. 7. Attach BHA. Perform "pull test" on BHA to ensure it is held tight. 8. Pull pin, lower and thread pack-off assembly into 2-7/8" female connection (metal-to-metal seal; a wrench or chain tong may be needed to prevent the adapter from turning). 9. Lower injector head carefully on the pack-off (line up slot with the %"x4" nipple & valve). 10. Wrap wellhead with absorbents to catch drips. 11. Cap surface capstring end (if line is not preloaded, configure to pump foamer downhole during job). 12. Ensure rattiguns are set to running position. 13. Pressure hydraulic rams (top seal) pack-off to 3000 psi. 14. Open swab valve. Watch for leaks at pack-of£ Adjust Rattiguns and pressure on pack-off as needed. 15. RIH to setting depth of 7,030'. ~ 16. Set slips. Set Rattiguns. Release pressure on upper hydraulic seal. Watch for leaks. Lift injector head. 17. Place 1.5 times SIWHP on hydraulic pack-off. 18. Pull tubing excess through injector. 19. Cap tubing with a Swagelok cap and valve, pressure gauge, and filter. Connect to line from CICM. 20. Lockout Swab, Upper Master, and Lower Master as per Capstring Lockout Procedure. 21. Hookup injection line to CICM. NOTE: Start foamer at 1 gpd. 22. RDMO. Cleanup site. Sign-out. 23. Replace well house NOTE: When replacing well house, be careful of the tubing "bend" as it goes back inside if it extends through the roof. • ~ 206-013 50-133-20499-01-00 A- 028142 ion: 87' (21' AGL) 60° 27' 37.172" N *122'a * 1,855 M ~-nioM 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' S,489' ND 0' S,299' Sidetrack window milled from 3,752' MD - 3,768' MD. 12-1/4" hole Cmt w/ 1,005 sks of Cias G 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 7,812' ND 0' 7,608' 8-1/2" hole Cmt w/ 267 sks (102 bbls) of 12.7 ppg Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail Excape Svstem Details - 13 Excape modules placed -;~e~ control line fired modul es 8 thru 13 - control lines fired modules 2 thru 7 - Gruc . control line fired module 1 - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB)Beluqa & Tyonek Zones): Module 13 - 5,520'-5,530' (Beluga) Module 12 - 5,570'-5,580' (Beluga) Module 11 - 5,746'-5,756' (Beluga) Module 10 - 5,788'-5,798' (Beluga) Module 9 - 5,929'-5,939' (Beluga) Module 8 - 6,200'-6,210' (Beluga) Module 7 - 6,308'-6,318' (Beluga) Module 6 - 6,360'-6,370' (Beluga) Module 5 - 6,572'-6,582' (Beluga) Module 4 - 6,700'-6,710' (Beluga) Module 3 - 6,860'-6,870' (Beluga) Module 2 - 7,028'-7,038' (Beluga) Module 1 - 7,466'-7,476' (Tyonek) Conductor 20" K-55 133 ppf Top Bottom MD 0' 107' ND 0' 107' Surface Casing 13318" K-55 68 ppf BTC Top Bottom MD 0' 1,518' TVD 0' 1,518' 17-1/2" hole Cmt wl 608 sks, Class G TD PBTD 7,830' MD 7,774' MD 7,626' ND 7,570' ND Well Name & Number: Kenai Beluga Unit 24-6RD Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA PerForations (MD): 5,520' - 7,476' Perf (TVD): 5,329' - 7,007' Angle @ KOP & Depth: 20.3° 3,752' MD (window) Angle @ Perfs: 15.5° -- 2.5° Date Completed: 7114I2009 Ground Level: 66' (AMSL) RKB: 21' (AGL) Revised by: Kevin Skiba Revision Date: 7/1512009 KBU 24-6RD Pad 14-6 316' FSL, 1,255' FWL, Sec. 6, T4N, R11W, S.M. a ~ ~~ DATA SUBMITTAL COMPLIANCE REPORT 5/20/2008 Permit to Drill 2060130 Well Name/No. KENAI BELUGA UNIT 24-06RD Operator MARATHON OIL CO API No. 50-133-20499-01-00 MD 7830 TVD 7626 Completion Date 4/27/2006 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes DATA INFORMATION Types Electric or Other Log s Run: GR-SP-Newtron Pososity-Compensated Density-Sonic-Resistivity-Cali (data taken from Logs Portion of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments D C Las 13927 -__ Directional Sunreyv 0 7900 Open --- - - 3/21/2006 Precision Energy Services C Las 13927 / Induction/Resistivity / 3504 7820 Open 3/21/2006 Precision Energy Services GR SP POR DENS NEAR,MEDIUM, & DEEP Induction BHCS Pius Graphics Well Cores/Samples Information: Interval Name Start Stop ADDITIONAL INFORMATION Well Cored? Y~ Chips Received? ~~ = Analysis ~, Y / N Received? Comments: Sample Set Sent Received Number Comments Daily History Received? ~/ N Formation Tops ~ N ___ __ _ __ _ -_ Compliance Reviewed By: Date. ~ ~ ~_ ~.P r FRANK H. MURKOWSKl, GOVERNOR 333 W. T" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 August 22, 2006 Mr. Ben Schoffmann Operations Superintendent Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Dear Mr. Schoffmann: ~~~ °~' Attached please find the May 2006 Facility Report of Produced Gas Disposition, Form 10-422 ("Gas Disposition Report") for the Kenai Gas Field. The Commission has authorized the venting of 1,471 Mcf of gas, the volume released during the unloading and cleanup of Well KBU 24- 6RD following fracture stimulation. This volume is listed on the revised Gas Disposition Report as flared or vented more than 1 hour. Venting of gas during the post fracture unloading and cleanup was authorized for up to 24 hours and not to exceed 2,000 Mcf (refer to sundry approval 306-122). Actual venting occurred over 41 hours due to vti~eaker than expected well performance. Marathon is reminded of the need to <,,:*~. ro,-.,-~;* ^^nditions. When not ::;w~:blP or an adjustment is warranted, it is the comply __. r.,~....~ ,,;,_ operator's responsibility to contact the Commission before deviating from the requirement. The Commission has staff available to address regulatory variances 24 hours a day, either by contacting our North Slope inspector at 907-659-2714 (pager gf17-659-3607) or the after hours duty engineer at 907-244-1467. Should you have any questions, please contact Jim Regg at 907-793-1236. Sincerely. ~~ James B. Regg Petroleum Engineer Attachment STATE OF ALASKA ALASKA OIL AI\ D GAS CONSERVATION COMMISSION FACILITY REPORT OF PRODUCED GAS DISPOSITION I. Facility Number [330000012 2 Facility Name KENAI 3. Field KENAI 4 Operator Marathon Oil Company 5 Montit/Year of Disnosrtion - -- -- Mav-U6 Disposition Volume MCF 20. Forproducrionf-om multiple pools Gs( conu'iburion o/eorh ool 6- SOId , p us ~~ percent o/ i014i VOidnVe. ~t SVV / q~5 Pool Name Pool Code P 7. Reinjected 0 'fYONEK BELUGA 448571 ercent 81.53 KENAI UNDEFINED WDSP G&t 448036 OAO 8. Flared or vented 1 hour or less 6"' ~VC` 38 KENAA UNDEFINED WDSP 448057 0.00 _ ' STERLING POOL 5.1 448564 0 0(1 9. Flared or vented more than I hour (sec instr.) ~ ~ P t C ~~ ,. 1471 ~~ TERL[NG POOL 6 448568 . 0.00 - ` ' 4~ " ~ STERLING POOL•3 448560 3 3G IU Pilot and Purge ~~~~ -"~- U STERLING POOL-4 448562 . 9.07 TYONEK POOL q I 448570 6 04 I I l lsul Itx Icase oper<ruuns (specify in Remarks) 60532 , IZ Other (sec inslrucuons) ~ L..tx J~ t 1 ~ ~ J ~L 3 n ~ V 3 3 y t$ y y Authorization > I hr. S f 13 `T'OTAL VOLUME (ITEMS 6-12) a ety I t~~ ~~~ l MCF . 1902815 Lease Use MCF 14 NGL Gas E uivalent c 0 C ti I5 Pwc;hascd gas 0 onserva on MCI Waste: MCF 16 "R~anslerred front 381526 . ~~ IZ "Transferred to: (Express as a negative ii) 0 ommissioner Dale 18. Remarks. Gas volume trom Canne[y loop for sale .__ _____ mcf. l hereby certify that the foregoing is Uue and correct to the best of my knowledge. //~~/~~ Signature. ~Q~~ ~LULGtJiRr Printed Name: Randy Jindra "Title: Accountant Phone: 918-925-7098 Date: July 25, 2006 Note All vohtrrles must be corrected !n pressure of /4.65 ps'tct and to u temperature: of 60o F. Aut~loriry 20 A,9L~25.235. F 01'111 10-42? W_:i Marathon Oil Company , Gas Flare /Vent Incident Report Facility Name: Kenai Gas Field May 2oas Time Total Flare / Start Date Well # or Planned Reason Mitigation Start Stop Duration Vent Facility Y/N MCF Jim Thompson received approval in the sundry ` 5/20/2006 notice to vent for 24 hours and no more than 2 Any questions let me know. Thanks W thru 13:30 08:30 41 hrs 1471 KBU 24-6 Y mmcf. As shown my total vent time was more, 713-296-2730; M: 713-232-9347; Fax: 713- 5/23/2006 at 41 hours due to weaker than expected well 513-6019 `rt - t`"- erformance Total: 1471 ~ 4 °/~'_~ ~~.~~ tU,~ ~,`Q G `' i • • C'\DOCUME-1\jindrarw\LOCALS-1\Temp\notesC9812B\2006 May -Kenai Gas Field -Vent Incident Report.xls Originator: Jaci Stasak, MOC M Marathon MARATHON Oil Company August 11, 2006 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West 7t" Ave., Suite 100 Anchorage, Alaska 99501 Reference: Completion Report 10-407 for Permit 206-013 Field: Kenai Gas Field /Beluga /Upper Tyonek Well: KBU 24-6RD Dear Mr. Aubert: • Alaska Business Unit Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 DECEIVED AUG 1 5 2006 Alaska Oil & Gas Cons. Commission Anchorage Enclosed please find the Well Completion Report with associated attachments for Kenai Beluga Unit Well No. 24-6RD. This well has been completed cased hole with a 3.5" Excape monobore production string to surface. I apologize for the delay in getting this completion notice to you. Should you require further information, I can be reached at 713-232-9347 or 713-296-2730 or by email at JRThompson@MarathonOil.com. Sincerely, James R. Thompson Sr. Completions Engineer Enclosures: AOGCC Form 10-407 Directional Survey Wellbore Diagram Operations Summary STATE OF ALASKA Q(JG Y 5 ZOO6 ALASKK~ AND GAS CONSERVATION COMMIS~I Alask it WELL COMPLETION OR RECOMPLETION REPORT AN~ L&ons. CO~--ission 1 a. Well Status: Oil^ Gas Q Plugged ^ Abandoned ^ 20AAC 25.105 GINJ ^ WINJ ^ WDSPL ^ No. of Completions Suspended ^ WAG ^ 2oaa,c 2s.~ ~o 1 Other 1 b. Well Class: ~ Development Q Exploratory ^ Service ^ Stratigraphic Test ^ 2. Operator Name: Marathon Oil company 5. Date Comp., Susp., or Aband.: May 27, 2006 12. Permit to Drill Number: 206-013 3. Address: P.O. Box 196168, Anchorage, AK. 99519-6168 6. Date Spudded: February 20, 2006 13. API Number: ~, a•{ ~ 9 50-133-?1l'8J9-01 4a. Location of Well (Governmental Section): Surface: 316' FSL, 1255' FWL, Sec. 6, T4N, R11W, S.M. 7. Date TD Reached: March 2, 2006 14. Well Name and Number: KBU 24-6RD Top of Productive Horizon: 817' FSL, 1806' FWL, Sec. 6, T4N, R11 W, S.M. 8. KB Elevation (ft): 87' RKB / 21' AGL 15. Field/Pool(s): Kenai Gas Field Total Depth: 1156' FSL, 1738' FWL, Sec. 6, T4N, R11 W, S.M. 9. Plug Back Depth(MD+TVD) 7774' MD / 7570' TVD : Beluga / Upper Tyonek Pool 4b. Location of Well (State Base Plane Coordinates): Surface: x- 272174.29 y- 2362360.67 Zone- 4 10. Total Depth (MD + TVD): 7830' MD / 7626' TVD 16. Property Designation: A-028142 TPI: x- 272735.04 y- 2362851.19 Zone- 4 Total Depth: x- 272673.50 y- 2363191.68 Zone- 4 11. Depth Where SSSV Set: NA 17. Land Use Permit: NA 18. Directional Survey: Yes 0 No ^ 19. Water Depth, if Offshore: NA feet MSL 20. Thickness of Permafrost: NA 21. Logs Run: GR-SP-Neutron Pososity-Compensated Density-Sonic-Resistivity-Caliper 22. CASING, LINER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT TOP BOTTOM TOP BOTTOM PULLED 20" 133 K-55 0 86 0 86 Driven NA NA 13-3/8" 68 K-55 0 1518 0 1518 17-1/2" 608 sx Class G NA 9-5/8" 40 L-80 0 3752 0 3667 12-1/4" 1005 sx Class G NA 3-1/2" 9.3 L-80 0 7812 0 7608 8-1/2" 267sx 12.7 L / 878sx 15.8 T 55000 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) MD: 7466-7476, 7028-7038, 6860-6870, 6700-6710, 6572-6582, 3-1 /2" 7812' NA 6360-637 6308-6 6i 59; 5788-575 574E 5570 5520-5530 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. TVD: 7262-7272, 6824-6834, 6656-6666, 6496-6506, 6368-6378, DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 6156-61 E 6104-6 55 57:5588-555 554 ~ 5377 5328-5338 See No. 23 16665 to 33408 lbs. 20/40 Ottawa 26. PRODUCTION TEST Date First Production: May 21, 2006 Method of Operation (Flowing, gas lift, etc.): FIOWIII Date of Test: 5/27/2006 Hours Tested: 24 Production for Test Period Oil-Bbl: NA Gas-MCF: 1830 Water-Bbl: 167 Choke Size: 128/64th Gas-Oil Ratio: NA Flow Tubing Press. 295 Casing Press: 0 Calculated 24-Hour Rate ~ Oil-Bbl: NA Gas-MCF: 1830 Water-Bbl: 167 Oil Gravity -API (corr): NA 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". None co~~pl.~rlon[ Rif[Qp S BFI Qua ~ ~ Zoos Form 10-407 Revised 12/203 (~ ~ (~ ~ ~ A CONTINUED ON REVERSE 28. GEOLOGIC MARKER 29. ~ORMATION TESTS NAME M TVD Include and briefly su ze test results. List intervals tested, and attach Beluga 4822 4667 detailed supporting data as necessary. If no tests were conducted, state Uipper Tyonek 7421 7217 "None". None 30. List of Attachments: Directional Survey, Wellbore diagram, Operations Summary 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Printed Name: James Thompson Title: Sr. Completions Engineer Signature: ~~ ~ .i'~~-~Phone:713-296-27301713-232-9347 Date: 8/11/2006 V INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for 1 njection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: If no cores taken. indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 M MARATHON Actual Wellpath Report Wellpath: MWD <3964-7830> Page 1 of 6 ~~~ BAKER ~~It~MES INTEQ ';Operator ,. ~ ~ MARATHON Oil Company Slot Slot# KBU24-6 ;Area Cook Inlet, Alaska (Kenai Penninsula) Well KBU24-6Rd :Field Kenai Gas Field Wellbore KBU24-6Rd Facility Pad 14-6 Sidetrack from KBU24-6 at 3752.00 MD '~ 1 Calculation method Minimum curvature Glacier 1 (RKB) to Facility Vertical Datum 87.00 feet _. Horizontal Reference Pt Slot Glacier 1 (RKB) to mean sea level 87.00 feet Vertical Reference Pt Glacier 1 (RKB) Facility Vertical Datum to Mud Line 0.00 feet MD Reference Pt Glacier 1 (RKB) Section Origin N 0.00,E 0.00 ft Field Vertical Reference mean sea level Section Azimuth 346.32° MARATHON Actual Wellpath Report Wellpath: MWD <3964-7830> Page 2 of 6 ri~~ BAKER I~IV6NES INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot Slot# KBU24-6 Area Cook Inlet, Alaska (Kenai Penninsula) Well KBU24-6Rd Field Kenai Gas Field Wellbore KBU24-6Rd Facility Pad 14-6 Sidetrack from KBU24-6 at 3752.00 MD ~LPATH DATA (86 MD feet) Inclination I°t 0.00 0.( 346.00 0. ; 586.00 I."< 827.00 l .~ 954.00 1.1 1269.00 L~ Azimuth l°] TVD Ifeetl Vert Sect [feet] North Ifeet] East Ifeetl Grid East lus survey feet] Grid North (us survey feet] DLS I°/100ft1 0.000 0.00 0.00 0.00 0.00 272174.29 2362360.67 0.00 294.800 345.99 1.48 1.00 -2.17 272172.14 2362361.72 0.23 264.200 585.95 2.87 1.43 -6.23 272168.09 2362362.23 0.28 274.400 826.86 4.48 1.48 -12.85 272161.47 2362362.40 0.31 284.600 953.81 5.74 1.97 -16.20 272158.13 2362362.95 0.66 276.500 1268.70 9.06 3.36 -24.51 272149.85 236364.50 0?6 Build Rate ~ "Turn Rate 0.181 -12.7 1397.00 0.700 293.700 1396.66 10.28 3.92 -27.37 272147.01 2362365.11 1.00 -0.96 13.44 1471.00 0.530 7.500 1470.66 10.87 4.44 -27.73 272146.65 2362 365.64 1.01 -0.23 99.73 1538.00 0.580 58.800 1537.66 11.26 4.92 -27.40 272146.99 2362366.12 0.72 0.07 76.57 1640.00 1.900 47.500 1639.63 12.23 6.33 -25.72 272148.70 2362367.49 1.31 1.29 -11.08 1704.00 2.590 54.200 1703.58 13.29 7.89 -23.76 272150.69 2362369.02 L l5 1.08 10.47 1801.00 4.200 58.300 1800.41 15.21 11.04 -18.96 272155.54 2362372.08 1.68 1.66 4.23 1890.00 5.300 65.100 1889.10 17.02 14.48 -12.46 272162.11 2362375.39 ~ 1.39 1.24 7.64 1985.00 7.000 69.200 1983.55 18.59 18.39 -3.07 272171.58 2362379.12 1.85 1.79 4.32 2077.00 8.780 69.400 2074.68 20.13 22.85 8.75 272183.47 2362383.35 1.94 1.93 0.2:~ 2170.00 10.180 74.300 2166.41 21.28 27.57 23.30 272198.12 2362387.79 1.74 1.51 5.27 2266.00 11.720 76.800 2260.66 21.49 32.09 40.96 272215.86 2362391.97 1.68 1.60 2.60 2328.00 12.720 76.100 2321.25 21.47 35.17 53.72 272228.67 2362394.81 1.63 1.61 -1.13 MARATHON Actual Wellpath Report Wellpath: MWD <3964-7830> Page 3 of 6 r~.~ BAKER I~IY6I~IES INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot ,~: __ Slot# KBU24-6 Area Cook Inlet, Alaska (Kenai Penninsula) Well KBU24-6Rd Field Kenai Gas Field Wellbore KBU24-6Rd Facility Pad 14-6 Sidetrack from KBU24-6 at 3752.00 MD ELLPATH DATA (86 stations) MD (feet lndination I°J Azimuth (°J TVD [feet] Vert Sect Ifeet] North IfeetJ East Ifeetl Grid East lus survey feet) Grid North lus survey feet] DLS I°/100ft1 Build Rate I°/100ft1 Turn Rate I°/IOOftI 3183.00 20.070 74.700 3133.54 26.10 102.23 309.66 272485.84 2362456.95 0.83 -0.25 -2.29 3342.00 20.910 74.000 3282.48 28.02 117.25 363.25 272539.70 2362470.94 0.55 0.53 -0.44 3470.00 20.390 74.600 3402.26 29.61 129.47 406.70 272583.38 2 362482.32 0.44 -0.41 0.47 3723.00 20.370 74.300 3639.42 32.49 153.09 491.58 272668.70 2 362504.31 0.04 -0.01 -0.12 3752.00 20.392 74.441 3666.61 32.83 155.81 501.31 272678.47 _ 2362506.84 0.19 0.08 0.49 396-1.00 22?00 32.500 3865.25 61.94 199.75 558.74 272736.73 _ 2362549.67 7.09 0.85 -19.78 4029.00 21.800 17.000 3925.57 80.84 221.67 568.88 272747.28 2362571.39 8.93 -0.62 -23.85 4092.00 21.500 7.800 3984.14 101.65 244.30 573.87 272752.71 2362593.92 5.40 -0.48 _ -14.60 4155.00 21.400 3.100 4042.78 12 3.40 267.21 576.05 272755.33 2362616.79 2.73 -0.16 -7.46 4218.00 21.400 2.400 4101.44 145.45 290.17 577.16 272756.88 2362639.72 0.41 0.00 -1.11 4282.00 21.000 356.000 4161.11 16797 313.28 576.85 272757.01 2362662.83 3.67 -0.62 -10.00 4345.00 20.800 352.500 4219.97 190.22 335.63 574.60 272755.19 2362685.22 2.01 -0.32 -5.5~~: 4408.00 20.900 352.400 4278.84 212.52 357.86 571.65 272752.67 2362707.50 0.17 0.16 -0. I ~~ 4471.00 21.00 0_ 352.500 4337.68 234.91 380.19 568.69 272750.14 2362729.88 0.17 0.16 U I ~~ 4534.00 21.000 352.200 4396.50 257.37 402.57 ~ 565.69 272747.56 2362752.31 0.17 0.00 -0.4 4597.00 20.700 351.600 4455.37 X79.68 424.77 562.53 272744.83 2362774.57 0.58 -0.48 -0.95 4661.00 20.300 _ 351.400 4515.32 302.00 446.94 559.22 272741.94 2362796.79 0.63 -0.63 -0.31 4723.00 19.900 352.100 4573.54 323.21 468.02 556.16 272739.29 2362817.93 0.75 -0.65 1.13 4786.00 19.800 351.500 4632.80 344.51 489.20 553.11 272736.64 2362839.16 0.36 -0.16 -0.95 4850.00 19.600 351.100 4693.05 366.00 510.52 549.84 272733.79 2362860.54 0.38 -0.31 -0.62 4913.00 19.400 350.700 4752.44 386.96 531.29 546.52 272730.86 2362881.37 0.38 -0.32 -0.63 4975.00 19.000 350.500 __ 4810.99 407.30 551.40 543.19 272727.92 2362901.54 0.65 -0.65 -0.32 5039.00 19.100 350.900 487 L48 428.12 572.02 539.81 272724.94 2362922.22 0.26 0.16 0.62 S 102.00 19.000 _ 350.900 _ 4931.03 448.62 ___592.32 5 X6.56 272722.08 _ _236294_2.58 _ 0.16 -0.16 0.00 5166.00 18.800 350.900 4991.58 ~ 469.29 ~ 612.79 533.28 272719.19 ~ 2362963.11 0.31 -0.31 0.00 MARATHON Actual Wellpath Report Wellpath: MWD <3964-7830> Page 4 of 6 INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot Slot# KBU24-6 Area Cook Inlet, Alaska (Kenai Penninsula) Well KBU24-6Rd Field Kenai Gas Field Wellbore KBU24-6Rd Facility Pad 14-6 Sidetrack froth KBU24-6 at 3752.00 MD ELLPATH DATA (86 stations) MD [feet) Inclination 1°] Azimuth 1°] TVD lfeetJ Vert Sect IfeetJ North Ifeetl Fast Ifeetl Grid Fast lus survey feed Grid North lus survey feet] DLS 1°/100R] Build Rate I°/100tt1 Turn Rate I°/]OOttJ 5229.00 18.600 351.000 5051.26 489.42 632.74 530.10 272716.40 2362983.11 0.32 -0.32 0.16 5292.00 18.200 350.400 5111.04 509.25 652.36 526.89 272713.56 2363002.79 0.70 -0.63 -0.95 $;55.00 18.000 346.800 5170.92 528.79 671.54 523.03 272710.07 2363022.04 1.80 -0.32 -5.71 5418.00 17.900 345900 5230.85 548.21 690.41 518.45 272705.85 236304099 0.47 -0.16 -1.43 5480.00 16.600 346.100 5290.06 566.59 708.25 514.00 272701.74 2363058.91 2.10 -2.10 0.32 55=11.00 15.700 _ 3-16.700 5348.66 583.56 724.74 510.01 272698.07 2363075.47 1.50 -1.48 0.98 5605.00 ____ 15.300 _ 347.400 5410.33 _ 600.66 __ _ 741.40 __ 506.17 272694.55 2363092.21 0.69 -0.62 1.09 5669.00 13.900 349.400 5472.26 616.78 757.20 502.92 272691.60 2363108.07 2.32 -2.19 3.13 5732.00 12.500 3-17.900 5533.60 631.15 771.31 500.09 272689.05 2363122?2 _ 2.39 -2.22 -2.38 5794.00 10.800 345.900 5594.32 643.67 783.50 497.27 272686.46 2363134.47 2.82 -2.74 -3.23 5857.00 9.500 __ 344.200 5656.33 654.77 794.23 494.42 272683.82 2363145.25 2.12 -2.06 -2.70 5921.00 8.200 340.800 5719.57 664.59 803.62 491.48 272681.06 2363154.70 2.19 -2.03 S 31 5984.00 7.700 341.600 5781.96 673.27 8 11.87 488.67 272678.41 2363163.00 0.8 I -0.79 . 6047.00 7.700 344.200 5844.39 681.69 819.94 486.19 272676.08 2363171.11 0.55 0.0 04.1 6108.00 6.800 344.400 5904.90 689.39 827.35 484.10 272674.14 2363178.56 1.48 -1.48 0.3 6172.00 5.700 349.400 5968.52 696.35 834.12 482.50 272672.67 2363185.36 192 -1.72 7.8 I 6236.00 4.400 354.700 6032.27 701.95 839.69 481.69 272671.96 2363190.94 2.16 -2.03 8.28 6298.00 2.000 17.300 6094.17 705.23 843.09 481.79 272672.13 2363194.34 4.30 -3.87 36.4.5 6361.00 1.300 60.000 6157.15 706.37 844.50 482.74 272673.10 2363195.73 2.17 -l.ll 67.78 6422.00 1.300 62.300 6218.13 706.74 845.17 483.95 272674.33 _ 2363196.37 ~ 0.09 ~ 0.00 3.77 6486.00 1.300 55.600 _____6282.12 707.17 845.91 485.19 272675.58 2363197.10 0.24 0.00 -10.47 6549.00 0.500 22.800 6345.11 707.64 _ 846.57 485.89 272676.29 _ 2363197.74 1.46 -1.27 -52.06 6612.00 0.400 335.100 6408.11 708.08 847.02 485.90 272676.31 2363198.19 0.60 -0.16 -75.71 6674.00 0.500 338.000 6470.11 708.56 847.47 485.71 272676.13 2363198.64 0.17 0.16 4.68 6737.00 0.50 0 3]6.40 06533.10 709.07 __ ~ 847.92 485.42 272675.84 _ ~- 2363199.10 0.30 0.00 -34.29 MARATHON Actual Wellpath Report Wellpath: MWD <3964-7830> Page 5 of 6 r~.r BAKER FIVGMES INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot Slot# KBU24-G Area Cook Inlet, Alaska (Kenai Penninsula) Well KBU24-6Rd Field Kenai Gas Field Wellbore KBU24-6Rd Facility Pad 14-6 Sidetrack from KBU24-6 at 3752.00 MD ELLPATH DATA (86 stations) ~ MD Ifeet] Inclination I°] ~~zimuth 1°] TVD Ifeetl Vert Sect Ifeetl North IfeetJ East Ifeetl Grid East lus survey feet) Grid North lus survey feet) DLS I°/100ft] Build Rate I°/100ft1 Turn Rate I°/100ft] 6862.00 0.400 286.200 6658.10 709.76 848.44 484.62 272675.06 2363199.64 0.20 -0.08 -24.16 6989.00 0.400 271.800 6785.10 710.10 848.58 483.75 272674.19 2363199.79 0.08 0.00 -11.34 7116.00 0.600 253.600 6912.09 710.19 848.41 482.67 272673.11 2363199.64 0.20 0.16 -14.33 7241.00 0.500 ___ ~~-1.100 7017.09 709.86 847.83 -381.66 272672.09 2363199.08 0?4 -0.08 -23.60 7367.00 0.800 185.300 7163.08 708.74 846.56 481.20 272671.60 2363197.82 0.41 0.24 -30.79 7450.00 ~ 0.800 180 200 7246.07 707.63 845.40 -181.14 272671.5; 2;63196.66 0.09 0.00 -6.14 7492.00 0.700 181.200 7288.07 707.10 844.85 481.14 272671.51 2363196.11 0.24 -0.24 2.38 7554.00 0.700 160.100 7350.06 706.35 844.12 48126 27267L62 2363195.38 0.41 0.00 -34.03 7649.00 0.900 155.100 7445.05 705.05 812.89 -181.77 272672.10 2363194.14 0.22 0.21 -5.26 7774.00 0.900 146.30 0 7570.04 703.16 841.19 482.73 272673.03 2363192.42 0.11 0.00 -7.04 7830.00 0.900 146.100 7626.01 702.13 840.46 38322 272673.50 216119L68 0.00 0.00 0.00 HOLE & CASING SECTIONS Ref Wellbore: KBU24-6Rd Ref Wellpath: MWD <3964-7830> String/Diameter Start NID IfeetJ End MD Ifeetl Interval Ifeetl Start TVD Ifeetl End TVD Ifeetl Start N/S Ifeetl Start E/W IfeetJ End N/S [feet) End E/1~ [feet] 20in Casing 0.00 86.00 86.00 0.00 86.00 0.00 0.00 0.06 -0. i 13.375in Casing Surface 0.00 1518.00 1518.00 0.00 1517.66 0.00 0.00 4.80 -27.5 9.625in Casing Intermediate 0.00 3752.00 3752.00 0.00 3666.61 0.00 0.00 155.81 501.31 3.Sin Liner 0.00 3752.00 3752.00 0.00 3666.61 0.00 0.00 155.81 501.31 8.Sin Open Hole 3752.00 7830.00 4078.00 3666.61 7626.03 155.81 501.31 840.46 483.22 3.Sin Liner 0.00 7830.00 7830.00 0.00 7626.03 0.00 0.00 840.46 483.22 :~ TARGETS Name MD [feet[ T~'D [feet[ North [feet[ East [feet[ Grid East [us survey feed Grid North [us survey feet[ Latitude [°[ Longitude [°l Shape KBU24 6RD M/B l 11/21/05 5312.00 799.00 495.51 272685.00 2363150.00 60 27 45.040N 151 15 33.940W circle - - e uga - Migrated from Director on 03/02/2006 KBU24 6RD TD 11/21/05 7587.00 799.00 495.51 272685.00 2363150.00 60 27 45.040N 151 IS 33.940W circle - - - Migrated from Director on 03/02/2006 ELLPATH COMPOSITIO N Ref Wellbore: KBU24-6R d Ref Wellpath: MWD <3964-7830> Start MD (feet) End MD [feet] "1'001 Type Positional Uncertainty Nfodel Log Name/Comment Wellbore 0.00 3752.00 ISCWSA MWD ISCWSA MWD (Standard) MWD <0-7500> KBU24-6 3752.00 4029.00 NaviTrak NaviTrak (Standard) MWD <3964-4029> KBU24-6Rd 4029.00 7830.00 NaviTrak NaviTrak (Magcorrl) MWD <4092-7830> KBU24-6Rd C J Actual Wellpath Report BAKER ~ E Wellpath: MWD <3964-7830> HVQrNES MARATHON Page 6 of 6 INTEQ API: 50-133-20499-01 RT-GL: 21.00' RT-THF: 21.70' 316' FSL, 1255' FWL, Sec. 6, T4N, R11 W, S.M. Tree cxn = 4-3/4" Otis TOC (est.) - 500' above 9-5/8" shoe Ceramic flapper valves below ach module as follows: Module 1 - NA Module 2 - 7053' (broken 5/20/06) Module 3 - 6885' (broken 6/19/06) Module 4 - 6726' (broken 6/19/06) Module 5 - 6597' (broken 6/19/06) Module 6 - 6385' (broken 5/20/06) Module 7 - 6333' (broken 5/20/06) Module 8 - 6225' Module 9 - 5954' (broken 5/20/06) Module 10 - 5813' Module 11 - 5771' Module 12 - 5595' (broken 5/20/06) Module 13 - 5545' KBU 24-6RD ~ M nnwlla;wTMOw Drive Pipe: 20", 133 ppf, K-55 to 86 ' Surface Casing: 13-3/8", 68 ppf, K-55, BTC @ 1518' Cmt w/ 608 sx of class G Intermediate Casing: 9-5/8", 40 ppf, L-80, BTC @ 3752" Cmt original well w/ 1005 sx of class G. Milled Sidetrack window f/3752- 3768' MD Prod. Casing: 3-112", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 7812' Cmt w/ 267 sx of class G Lead at 12.7 ppg. Tailed with 878 sx calss G at 15.8 ppg - 13 Excape modules placed - Green control line fired module 1 - Yellow control lines fired modules 2 thru 7 - Red control line fired modules 8 thru 13 -Ceramic flapper valves below each module except for module 1 Module 1 - 7466-7476' (Tyonek) Module 2 - 7028-7038' (Beluga) Module 3 - 6860-6870' (Beluga) Module 4 - 6700-6710' (Beluga) Module 5 - 6572-6582' (Beluga) Module 6 - 6360-6370' (Beluga)(Frac'd w/7) Module 7 - 6308-6318' (Beluga) Module 8 - 6200-6210' (Beluga) Module 9 - 5929-5939' (Beluga) Module 10 - 5788-5798' (Beluga) Module 11 - 5746-5756' (Beluga) Module 12 - 5570-5580' (Beluga) Module 13 - 5520-5530' (Beluga) Well Name 8 Number: KBU 24-6RD Lease: Kenai Gas Field County or Parish: Kenai State/Prov. Alaska Country: USA Perforations (MD) See Above (TVD) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completion Fluid: 6% KCL Dated Completed: 4/7/2006 Prepared By: J. R. Thompson Last Revison Date: 6/20/2006 TD - 7830' PBTD - 7774' • • .:Marathon Oil Company Page 1 of 9 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Spud Date: 2/18/2001 Event Name: RE-ENTRY Start: 12/30/2005 End: 3/12/2006 Contractor Name: GLACIER DRILLING Rig Release: 3/9/2001 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Description of Operations 12/31/2005 06:00 - 12:00 6.00 RURD_ RIG_ RDMO Accept rig F/GO#4 @ 06:OOhrs 12/30/2005. 12:00 - 00:00 ~ 12.00 ~ RURD_ RIG_ MIRU 00:00 - 06:00 6.00 ~ RURD_ RIG_ ~ MIRU 1/1/2006 ~ 06:00 - 12:00 ~ 6.00 RURD_ RIG_ ~ MIRU 12:00 - 00:00 ~ 12.001 RURD_ RIG_ MIRU 00:00 - 06:00 6.00 ~ RURD_ RIG_ ~ MIRU 1/2/2006 106:00 - 12:00 ~ 6.001 RURD_ RIG_ ~ MIRU 12:00 - 00:00 ~ 12.001 RURD_ RIG_ MIRU 2/14/2006 ~ 00:00 - 06:00 6.00 ~ RURD_ RIG_ ~ MIRU 2/15/2006 06:00 - 06:00 24.00 RURD RIG_ MIRU 2/16/2006 06:00 - 07:00 1.00 RURD_ RIG_ MIRU 07:00 - 09:00 2.00 RURD ELEC PLUGAB 09:00 - 10:00 1.00 RUNPUL ELEC PLUGAB Move sub base off of well and lower. Prep to be moved. Finish pulling wires. R/D walk way. Load out parts trailer, mechanics shop, generator house, boiler houses, welding shop, pit room and pump room. R/D camp and load trailers. Move rig. PJSM. Raise and set sub base. Set mud boat, carrier ramp and pit and pump rooms. Pull pit and pump room together. Set generator and boiler houses. Set water tank, mecanic and parts trailer. Pull wires, prepe derrick to be raised. R/U camp buildings. Set carrier, unload trailers. Change out boiler feed valve and check valve. PJSM with crane operator. R/U Carrier landing and stairs, derrick house, front windwalls and dog house. PJSM. Crane work. Set outriggers, choke house, flow line, stairs for BOP connex and fuel tank. R/U Dresser sleeves, poor boy degasser and u-tube. Install trip tank. Pull wires. Remove lights from derrick and replace. Unload trailers. Install traps around carrier. Hook up gai-tropics. Install lights on dog house and choke house. remove man-way hatch from water tank. PJSM. Spot and R/U Hanson tank and cuttings tank, #3 mud pump, shok hoses, panic line. R/U lower standpipe and cement line. R/U choke lines to gas buster and flow line. Install cellear scafolding and grafting. Unload trailers. Clean dirt out of water tank. Set up oil producrts, R/U welding shop. Purge fuel to generators. PJSM. Thaw out water well and fill water tank. Spot catwalk. Fabricate and install new staem line for dog house. Bleed fuel tank on carrier and pump#3. Fire boiler. Repair hydraulic leak on barrel crusher. Band GD#1 subs to pallet to be sent in for inspection. Unload trailers. Load trailer w/DP to be sent for inspection. Repair hanles on tuggers. Clean mud ends on pumps for inspection and repair. Run steam around rig. replace return hose for choke house. PJSM. R/U catwalk, beaver slise, conex stairs. Change oil and filters. Grease fork lift. R/U snub post and rebuild swab heads. hook up panic line to catwalk. Hook up choke line and run to cellar. Run koomey lines to sub base. R/U exhaust fan in pits. P/U and organize boiler house and BOP connex. Organize rig and welding shop. Rig released to maintenance OO:OOhrs 1/02/2006. Accept rig from maintenance and commence R/U@OO:OOhrs 02/14/2006. PJSM; Install cellar Doors, Set Grating In Pump Room, Install New Tail Shaft On #2 Carrier Dennison Hyd Pump. PJSM; Unload Weatherford Tools, Move Welding & Mechanic Shop. Flush Out Mud Pits And Clean. Set Berm For MI Mix Tank Test All L/P Lines Pits And Rig. Set Epoch Unit & Trip Tank R/U # 3 Mud Pump. R/U Top Drive And Service Loops. Fill Pits W /Water and Mix Mud. PJSM; Complete T/D R/U PJSM; Conduct General Safety Meeting, R/U Expro E- Line, Test Lubricator To 500 psi RIH W 2.80" Hole Gague On Wire Line, Log For Depth Control To 5500' POH Printed: 8/11/2006 2:29:06 PM • • Marathon Oil Company Page 2 of s Operations Summary Reporf Legal Well Name: KENAI B ELUGA UNIT 24-6 Common W ell Name: KENAI B ELUGA UNIT 24-6 Spud Date: 2/18/2001 Event Nam e: RE-ENT RY Start: 12/30/2005 End: 3/12/2006 Contractor Name: GLACIE R DRILL ING Rig Release: 3/9/2001 Group: Rig Name: GLACIE R DRILL ING Rig Number: 1 Date From - To Hours Gode Cad Phase Description. of Operations e 2/16/2006 10:00 - 10:30 0.50 SAFETY MTG_ PLUGAB PJSM; Hold Explosives Safety Meeting W Crew And Expro Personal 10:30 - 12:00 1.50 RUNPUL ELEC PLUGAB RIH W/ 2.75 Owen CIBP On E- Line, Correlate Plug On Depth & Set At 5467' POH W/ E- Line, R/D Setting Tool 12:00 - 12:30 0.50 TEST_ PLUG PLUGAB PJSM; Test 3 1/2 Csg. To 2000 psi F- 15 Min, Test Good 12:30 - 13:30 1.00 DUMPB CMT_ PLUGAB R/U Dump Bailer To Run On E- Line/ Mix Cement ,Clean Cement From Rig Floor. 13:30 - 14:00 0.50 DUMPB CMT_ PLUGAB Rlh W/ Dump Bailer#1 On E-Line ,Dump Cement On Plug At 5467 Poh. 14:00 - 14:30 0.50 DUMPB CMT_ PLUGAB Prep Dump Bailer #2, High Pressure Gas Alarm In Production Unit Sounded, Secure Rig And Report To Muster Area W/ Rig ~ Personal. 14:30 - 15:00 0.50 DUMPB CMT_ PLUGAB Resume Mixing Cement F/ Dump Bailer#2 15:00 - 15:30 0.50 DUMPB CMT_ PLUGAB RIH W/ Dump Bailer#2, Dump Cement, POH 15:30 - 16:00 0.50 DUMPB CMT_ PLUGAB Prep Dump Bailer#3 Mix Cement 16:00 - 17:00 1.00 DUMPB CMT_ PLUGAB RIH W Dump Bailer # 3 & Dump Cement At 5440', POH Total Of 35' Cement On Top Of Plug @ 5467' 17:00 - 17:30 0.50 RURD_ ELEC PLUGAB Lay Down E-Line Tools And R/D Expro 17:30 - 18:30 1.00 NUND TREE PLUGAB PJSM ; Ck. Void For pressure, N/D Tree 18:30 - 06:00 11.50 NUND BOPE PLUGAB PJSM ;N/U BOPE, Mud Cross, Inside Choke& HCR Valves. N/U Kill Line Valves. Instal Double Gate Rams & Annular Preventor. R/U Choke & Kill Lines. 2/17/2006 06:00 - 07:00 1.00 NUND BOPE PLUGAB Continue N/U BOPE. 07:00 - 12:00 5.00 TEST_ BOPE PLUGAB R/U test equipment. Test annular, 2 7/8" X 5 1/2" variable rams, CMV-1,2,5,6,7,8,9,11,12, inside and outside kill line valves, upper and lower top drive valves, manual choke line valve and HCR to 250/2000psi 10min. 12:00 - 13:00 1.00 TEST_ BOPE PLUGAB PJSM. Test blind rams and CMV3 and 4 to 250/2000psi 10min. Perform accumulator performance test. R/D test equipment. 13:00 - 14:00 1.00 NUND BOPE PLUGAB N/D choke line and N/U to 9 5/8" X 3 1/2" annulus. 14:00 - 15:00 1.00 CUT_ CSG_ PLUGAB R/U APRS. PJSM. Test lubicator to 750psi. 15:00 - CUT_ CSG_ PLUGAB Arm perforating gun. RIH w/1 11/16" pert gun. CCL quit. POOH. C/O CCL. RIH and correlate. Pressure up CSG to 700psi w/annulus open. Shoot holes F/3860-3866 23 holes 4SPF 0 deg phase. Lost 200psi. Attempt to circ w/max 700psi. No success. POOH. 2/18/2006 06:00 - 07:30 1.50 NUND BOPE PLUGAB N/D BOP. N/U circ. head. 07:30 - 08:00 0.50 SAFETY MTG_ PLUGAB PJSM for lifting and working under the stack. 08:00 - 11:30 3.50 NUND BOPE PLUGAB Lift stack and pull Vetco pack-off w/tugger lines. M/U Double spear assy and one joint 5" HWDP. Spear 3 1/2" CSG stub. P/U on 3 1/2" CSG. Pulled 40k over to pull CSG free(slips did not come out of bowl). Pull slips with first coupling. Control lines pulled with first band. Cut control lines just above first band. 11:30 - 12:30 1.00 LAYDW CSG_ PLUGAB Release spear and L/D. B/O and UD cut joint of CSG. 12:30 - 16:00 3.50 NUND BOPE PLUGAB N/U BOP. N/U choke line. N/U circulation housing and bell nipple. Set mousehole. 16:00 - 17:00 1.00 RURD_ OTHR PLUGAB Attempt to dig out cellar for mousehole. Pump dry job. 17:00 - 18:30 1.50 RURD_ OTHR PLUGAB Pull mousehole and cut off 6". R/U Pollard W/LSpooler To Recover Control Lines And Promore E-line 18:30 - 04:30 10.00 LAYDW CSG_ PLUGAB PJSM:/ POH UD 3 1/2 Csg W/ 2x Control Lines &.Promore E -Line For A Total Of 120Jt Of 3 1/2 Csg, And 3.85' Of Shot Joint Note; Recovered 3795' Of Control Line And Promore E-Line No SS Bands Lost In Hole. Top Of Shot Jt @ 3798.85' 04:30 - 05:30 1.00 RURD_ CSG_ PLUGAB R/D Weatherford Csg. Tools & Pollard W/L. Clean Rig Floor 05:30 - 06:00 0.50 TEST_ BOPE PLUGAB M/U Test Joint Set Test Plug Printed: 8/11/2006 2:29:06 PM • • Marathon Oil Company. Page 3 of 9 Operations. Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Spud Date: 2/18/2001 Event Name: RE-ENTRY Start: 12/30/2005 End: 3/12/2006 Contractor Name: GLACIER DRILLING Rig Release: 3/9/2001 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From- To Hours Code Code Phase Description of Operations 2/19/2006 06:00 - 07:00 1.00 TEST_ BOPE PLUGAB 07:00 - 11:00 4.00 TEST BOPE PLUGAB 11:00 - 11:30 0.50 TEST_ BOPE PLUGAB 11:30 - 12:00 0.50 RUNPUL WBSH PLUGAB 12:00 - 13:30 1.50 PULD_ BHA_ PLUGAB 13:30 - 17:00 3.50 PULD_ DP_ PLUGAB 17:00 - 18:00 1.00 CIRC_ MUD_ PLUGAB 18:00 - 20:00 2.00 TRIP DP PLUGAB 20:00 - 21:00 1.00 RURD_ ELEC PLUGAB 21:00 - 22:30 1.50 RUNPUL ELEC PLUGAB 22:30 - 00:00 1,50 TRIP_ BHA_ PLUGAB 00:00 - 02:30 2.50 TRIP_ DP_ PLUGAB 02:30 - 03:30 1.00 CIRC MUD PLUGAB 03:30 - 04:00 0.50 MIX_ PILL PLUGAB 04:00 - 06:00 2.00 TRIP_ DP_ PLUGAB 2/20/2006 06:00 - 07:00 1.00 TRIP_ BHA_ PLUGAB 07:00 - 08:30 1.50 LOG_ CSG_ PLUGAB 08:30 - 10:30 2.00 LOG CSG PLUGAB 10:30 - 11:30 1.00 TEST_ CSG_ PLUGAB 11:30 - 19:30 8.00 PULD DP SIDET 19:30 - 23:00 3.50 ~ TRIP_ ~ BHA_ ~ SIDET 23:00 - 00:30 1.50 TRIP_ DP_ SIDET 00:30 - 01:00 0.50 SERVIC RIG_ SIDET 01:00 - 04:30 3.50 TRIP DP SIDET 04:30 - 06:00 1.50 TRIP_ DP_ SIDET 2/21/2006 06:00 - 09:00 3.00 SETREL TOOL PLUGAB 09:00 - 15:00 6.00 MILL_ WNDW SIDET 15:00 - 17:00 2.00 MILL_ SECT SIDET 17:00 - 19:00 2.00 MILL WNDW SIDET 19:00 - 00:30 5.50 MILL_ WNDW SIDET 00:30 - 01:00 0.50 MILL_ WNDW SIDET 01:00 - 02:00 1.00 CIRC_ MUD_ SIDET 02:00 - 03:00 1.00 TEST LOT SIDET 03:00 - 03:30 0.50 TRIP_ DP_ SIDET 03:30 - 04:30 1.00 TRIP_ DP_ SIDET 04:30 - 06:00 1.50 TRIP BHA SIDET R/U to test BOPE. ' Test Annular, 2 7/8"X5 1/2" variable rams, CMV1-12, blind rams, upper and lower top drive valves, inside and outside manual kill line vales, kill line check valves, manual choke line valve, HCR valve to 250/3000psi 5min. R/D test equipment. Install wear bushing. PJSM. P/U 8.5" mill tooth bit, 9 5/8" scraper and BHA. P/U 5" DP while RIH. Tag @ 3795'. Circ. clean(CBUX4, 452gpm,470psi). POH SLM / W Scraper F-3795' & L/D No Correction On SLM PJSM; R/U Expro E-Line/ Safety Meeting RIH W/Gauge Ring Junk Basket On E- Line. Tag Up At 3762', (36' From Top Of Cut Joint @ 3798'.) Attempt To Work Gauge Ring Past 3762' No Go. Poh & R/D Expro E-Line. M/U 8 1/2 Mill & 8 1/2 WS Mill ,Rih W/ HWDP. Continue Rih W 5' D/P To 3750' Circulate/ Rotate And Clean Out 9 5/8 Csg. F-3750' To 3798'. Tag Top Of 3 1/2 Csg Cut Jt..@ 3798' Circ @ 200 spm 375psi 383 gpm Monitor Well/ Mix & Pump Dry Job POH F- 3798' W/ Drillpipe POOH w/BHA L/D jars. cont. POOH and L/D Baker mill assy. R/U Expro and run 8.0" gauge ring to 3798'. POOH. PJSM. RIH and set 9 5/8" EZ Drill bridge plug@3777'. POOH. R/D Expro. Test 9 5/8" CSG to 1500psi. P/U 5" DP. P/U, Drift And Rih W/ 5"DP Singles (70 jts), Poh & Set Back 35 Stds, P/U, Drift &Rih W/ 5' D/P Singles (70 jts) Poh & Set Back. 35 Stds. PJSM: P/U & M/U Mill Assy, MWD And 1- 6" Drill collar Pulse Test and Stand Back. M/U Bottom trip Whipstock Anchor To Starter Mill. Orientate. P/U 7- 6 1/4" SDC & 20 HWDP. Rih PJSM; TIH W/ 5 D/P At 2 Min Per Stand/ Running Whipstock /Window Mill. Service Rig. T/D, Carrier,Draworks, Blocks And Crown. Trouble Shoot Top Drive (Unable To Adjust Rotary Speed) Change Out Motor Pot Board & Driver Card. Continue TIH Whipstock/ Window Mill @ 2 Min per Stand. RIH wn~pstcok while troubleshoot problem w/top drive. Orient whipstock and Tag@3775'. Set whipstock@37deg left of highside. Mill window F/3752' to 3768' Mill/ Drill Formation F- 3768' T-3777' P/U And Work Mill's Through Window F - 3768' To 3752', Back Ream , Dress And Clean Up. Mill/ Drill Formation F- 3777' To 3798' P/U And Work Mill's Through Window F 3798' To 3752' Displace Hole W/ 9 ppg.Flo-Pro Mud @ 220 Spm 475 psi 450 Gpm. Attempt To Peform FIT Test, Formation Leak Off At 200 psi LOT To 10ppg EMW (200psi 9 ppg M W ) Monitor Well, Pump Dry Job POH W/ 5" Drill Pipe F- 3798' POH W/ BHA L/D 6 1/4 Drill collars No Gain/ Loss To Hole Printed: 8/11/2006 2:29:06 PM • ~ Marathon Oil Company Page 4 of 9 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Event Name: RE-ENTRY Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours Code ~ Code Phase Spud Date: 2/18/2001 Start: 12/30/2005 End: 3/12/2006 Rig Release: 3/9/2001 Group: Rig Number: 1 Description of Operations 2/22/2006 06:00 - 07:00 1.00 TRIP_ BHA_ SIDET 07:00 - 08:00 1.00 SERVIC RIG_ SIDET 08:00 - 10:30 2.50 TRIP_ BHA_ PR1 DRL 10:30 - 12:30 2.00 TRIP_ BHA_ PRIDRL 12:30 - 13:00 0.50 REAM_ OH_ PRIDRL 13:00 - 21:30 8.50 DRILL_ ROT_ PR1 DRL 21:30 - 23:00 1.50 CIRC_ MUD_ PRIDRL 23:00 - 23:30 0.50 CIRC_ MUD_ PRIDRL 23:30 - 00:00 0.50 DRILL_ ROT_ PR1DRL 00:00 - 01:00 1.00 CIRC MUD PR1 DRL 01:00 - 02:00 1.00 TRIP_ DP_ PR1 DRL 02:00 - 05:00 3.00 TRIP_ DP_ PR1 DRL 05:00 - 06:00 1.00 TRIP_ BHA_ PR1 DRL 2/23/2006 06:00 - 08:00 2.00 RURD_ OTHR PR1 DRL 08:00 - 10:00 2.00 TRIP_ BHA_ PR1 DRL 10:00 - 10:30 0.50 RURD_ OTHR PR1 DRL 10:30 - 13:00 2.50 TRIP_ DP_ PR1 DRL 13:00 - 14:00 1.00 CIRC_ MUD_ PR1 DRL 14:00 - 16:00 2.00 SPOT PILL PRIDRL 16:00 - 17:00 1.00 TRIP_ DP_ PR1 DRL 17:00-18:00 1.00 CIRC_ MUD_ PRIDRL 18:00 - 22:30 4.50 SOUEZE OTHR PR1 DRL 22:30 - 00:00 1.50 TRIP_ DP_ PR1 DRL 00:00 - 01:00 1.00 RURD_ OTHR PR1 DRL 01:00 - 02:30 1.50 TRIP_ BHA_ PR1 DRL 02:30 - 03:00 0.50 RURD_ OTHR PR1 DRL 03:00 - 05:00 2.00 TRIP BHA PR1 DRL 05:00 - 06:00 1.00 TRIP_ DP_ PR1 DRL 2/24/2006 06:00 - 07:30 1.50 CUT WIRE PR1 DRL 07:30 - 08:00 0.50 SERVIC RIG_ PR1 DRL 08:00 - 12:30 4.50 TRIP DP PR1DRL 12:30 - 13:00 ~ 0.50 CIRC_ ~ MUD_ PR1 DRL 13:00 - 13:30 0.50 TEST LOT_ PR1 DRL 13:30 - 14:30 1.00 MIX_ PILL PR1 DRL 14:30 - 16:30 2.00 TRIP_ DP_ PR1 DRL 16:30 - 17:30 1.00 TRIP_ BHA_ PR1 DRL Cont. UD BHA. Service rig and trouble shoot top drive controls. PJSM. P/U 8.5" PDC bit and Dir. BHA. Test MWD. Cont. RIH w/HWDP. Ream F/3789' to 3798'. Dir drill and survey F/3798' to 4454'(ART=3.9hrs AST=3.2hrs). Circ. samples for Geologist(CBUX2, 510GPM,1100psi, 90RPM). Circ. carbide(indicated 20%washout). Dir drill and survey F/4454' to 4485'(ART=.3hrs). Circ. clean(CBUX1, 493GPM, 90RPM, 1100psi). Pump Carbide(indicated 20% washout). Observe well(static). Note: Mud Loss To Hole Section F-3798' T- 4485' 200 bbls. W/ 9ppg M/W & 9.5 ECD. No Fluid Loss W/ Hole Statio. POOH to 3700'(wet) Pump dry job. POOH w/DP POOH w/BHA.& UD PJSM; C/O Elevators R/U Weatherford Tubing Tongs M/U 2 7/8 Mule Shoe & P/U 39 Jts 2 7/8 Tubing RIH R/D Weatherford Tongs & C/O Elevators RIH To 4480' (Hold PJSM W/ Day Light Crew) M/U Circ Head, Circ. B/U At 4480' W/ 146 spm 280gpm 510psi Switch To BJ Pump 2 bbl. Water Test Lines T-2000 psi. Set Balanced Plug/ Pump 10 bbl 9.5 ppg Spacer Followed By 78 bbl Formaset Pill Pump 2 bbl 9.5ppg Spacer, Displace W 55 bbl 9ppg Flow Pro Mud. R/D Circ. Pump Formaset At A Rate Of 1.5 bpm 425psi max. Unable to Pump At Higher rate Due To Hvy Vis Of Formaset Poh At Reduced Hoisting Rate To 3139' Circ B/U At 3139' 146 spm 280gpm 510 psi Close Annular, Squeeze 12 bbl Mud/Formaset. Initial Sq Pressure 150psi Final Squeeze psi 182. Shut In And Hold Pressure On Annulus. Initial Holding Pressure 115psi Final Psi 20. After4 Hours. Fluid Level In Annulus Static. POH F-3134' T 1200' C/O Elevators R/U Weatherford Tubing Tongs Poh And UD 39 Jts. 2 7/8 Tubing Monitor Fluid Level In Hole, No Losses C/O Elevators, Rig Down Weatherford Tongs PJSM; M/U Drctnl Bha, Set AKO 1.3 Orient Mwd M/U Bit P/U Jars, Test Mwd RIH. RIH To 2900' Break Circ. PJSM: Slip And Cut Drilling Line, Ck Crown & Set Crown O Matic Service Rig, Adjust Brakes And Adjust Linkage RIH To 3127' Wash Down To 3640, Exit Window Wash And Ream F- 3698' T- 4485. Clean Up Formaset Stringers F- 3698' To 4485' Hvy Returns Over Shakers W Sheets Of Formaset. 2 bbls Loss To Hole. Circ. Pump Sweep. AT 4485' 210Stks 410 gpm 475psi Sweep Returned 10 bbls Past Caculated Volume. Increase in Formaset Sheets Over Shakers Peform FIT W 9.1 ppg (100psi = 9.5 EMW) Attempt FIT Test At Increased Pump Rate( 18 spm) No Success Mix Pump Dry Job POH F- 4485' W/ 5" Drillpipe, Correct Hole Fill No Loss To Hole POH Stand Back Bha.Note: Bit Had Broken Teeth On Taper Area And Printed: 8/11/2006 2:29:06 PM • • Marathon Oil Company Page 5 of 9 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Spud Date: 2/18/2001 Event Name: RE-ENTRY Start: 12/30/2005 End: 3/12/2006 Contractor Name: GLACIER DRILLING Rig Release: 3/9/2001 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date .,:From - To Hours Code Code. Phase Description of Operations 2/24/2006 16:30 - 17:30 1.00 TRIP_ BHA_ PR1 DRL Chipped Teeth On Shoulder. 17:30 - 19:30 2.00 TRIP_ DP_ PR1 DRL M/U Mule Shoe TIH W 5' D/P TO 3640' No Gain Loss/ 19:30 - 21:30 2.00 MIX_ PILL PR1 DRL Wait On M/I Swaco To Set Up And Mix Formaset Fluid 21:30 - 22:30 1.00 TRIP_ DP_ PR1 DRL RIH TO 4480'/ R/U Cement Line To BJ Services 22:30 - 00:00 1.50 MIX_ PILL PR1 DRL PJSM: Pump 2 bbl Water, Test Lines To 2000psi. Pump 10 bbl Spacer Followed By 95 bbl Form-a-set Pill Followed By 30 bbl 10.7 ppg Flow Vis Mud Spacer. Able To Pump At 4.5 BPM And Max Pressure Of 560psi. Total Pumping Time Of 6Min For Spacer, 23 Min For Form-A-Set And 7 Min For Weighted Spacer 00:00 - 01:00 1.00 TRIP_ DP_ PR1 DRL R/D Cmt Line Pooh At Reduced Hoisting Rate To 3070.' 01:00 - 01:30 0.50 SQUEZE OTHR PR1 DRL Close Hydril/ Squeeze 20 bbls 9.2ppg Mud. Start Psi 50psi Final Psi 160. Max Pressure During Squeeze 200psi. Shut Down Pump. Annulus Holding 160psi For 5 Min. Bleed Annulus Off. 01:30 - 02:30 1.00 CIRC_ MUD_ PR1 DRL Circ. Displace Drill Pipe And Annulus, Small Amount Form-A- Set Returned Over Shakers. Circ 1X BTTMS Up. No Fluid Loss To Hole. 02:30 - 04:30 2.00 TRIP_ DP_ PR1 DRL POH W/ 5" Drill Pipe L/D Mule Shoe. Hole Static No Mud Loss 04:30 - 05:30 1.00 TRIP_ BHA_ PR1 DRL M/U Drctnl BHA RIH 05:30 - 06:00 0.50 TRIP_ DP_ PR1 DRL RIH W/ 5' Drill Pipe To 2000' 2/25/2006 06:00 - 07:30 1.50 SERVIC RIG_ PR1 DRL Service Rig, Top Drive, Troubleshoot TD. Note Wait On Formaset To Set Up 07:30 - 08:00 0.50 TRIP_ DP_ PR1 DRL RIH F- 2000' To 2870' 08:00 - 11:00 3.00 TRIP_ DP_ PR1 DRL Wash From 2870' To 3752' Orient And Enter Window F-3752 To 3768' Wash And Clean Out To 3788' No Gain Or Fluid Losses To Hole. Pull Up To 3752' 11:00 - 12:00 1.00 CIRC_ MUD_ PR1 DRL Circ B/U For FIT Test 12:00 - 13:00 1.00 REPAIR RIG_ PR1 DRL Thaw Out Choke Line 13:00 - 13:30 0.50 TEST_ LOT_ PR1 DRL Fit Test At 3752' 9.15ppg MW (155psi = 10ppg EMW At 3670 TVD) 13:30 - 14:00 0.50 MIX_ PILL PR1 DRL Blow Down Mud lines Monitor Well, Pump Dry Job 14:00 - 16:30 2.50 TRIP_ DP_ PR1 DRL POH W 5" Drillpipe And BHA, Hole Static No Fluid Loss To Hole, 16:30 - 18:30 2.00 TRIP_ DP_ PR1 DRL M/U Mule Shoe RIH W/ Drillpipe To 3752' 18:30 - 20:00 1.50 MIX_ PILL PR1 DRL R/u Circ. Line, Mix Formaset Pill W/O BJ 20:00 - 21:30 1.50 SPOT_ PILL PR1 DRL PJSM, Pump 2bbls H2O Test Lines To 2000 psi Pump 5bbls 9.5 ppg Spacer, 30 bbls 9.5ppg Formaset Spacer Followed By 15 bbls 10.6ppg Weighted Spacer, Displace W 41 bbls 9.1 Flow Pro Mud. R/D Cement Line 21:30 - 22:30 1.00 TRIP_ DP_ PR1 DRL POH T/3200' At Reduced Hoisting Rate 22:30 - 23:30 1.00 SQUEZE OTHR PR1 DRL Close Hydril/ Squeeze 24bbls Of 9.5ppg Formaset At 1 bbls per Min 285 psi At Pump/ 20Apsi on annulus After 5bbls Pumped 180 psi on annulus, 22bbls Squeezed annulus 130 psi, 24 bbls squeezed 130psi on annulus. Shut Down Pump Hold Pressure On annulus 5 Min pressure Decreased To 100psi Bleed psi Off. 23:30 - 00:30 1.00 CIRC_ MUD_ PR1 DRL Circ. Hole And Dp Volume. Monitor Returns For Excess Formaset. Small Trace Returned To Surface. Well Remains Static No Fluid Loss To Formation 00:30 - 02:00 1.50 TRIP_ DP_ PR1 DRL POH W 5" Drillpipe UD Mule Shoe 02:00 - 03:00 1.00 WAITON TRET PR1 DRL Wait On Formaset To Set Up /Troubleshoot Top Drive 03:00 - 03:30 0.50 TRIP_ BHA_ PR1 DRL M/U/ Drctnl BHA /RIH (rest Mwd 03:30 - 05:00 1.50 TRIP_ DP_ PR1 DRL RIH W 5" Drillpipe To 3200' 05:00 - 06:00 1.00 TRIP_ DP_ PR1 DRL Wash Clean Out F- 3200' To 3400' 2/26/2006 06:00 - 06:30 0.50 TRIP_ DP_ PR1 DRL RIH Wash/ Clean Out Excess Form-A-Set F-3250' T-3752' No Fluid Loss To Hole 06:30 - 07:00 0.50 CIRC_ MUD_ PR1 DRL Circulate B/U At 3752' 07:00 - 08:00 1.00 TEST_ LOT_ PR1 DRL Peform Fit Test W/ 9.2 ppg MW (165psi = 10ppg EMW) At 3670' TVD. 08:00 - 08:30 0.50 MIX, PILL PR1 DRL Monitor/ Well Pump Dry Job Printed: 8/11/2006 2:29:06 PM • • Marathon.. Oil Company Page 6 0# 9 Operations Summery Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Event Name: RE-ENTRY Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To -Hours Code Code Phase 2/26!2006 08:30 - 09:30 1.00 TRIP_ DP_ PR1 DRL 09:30 - 10:00 0.50 REPAIR RIG_ PR1 DRL 10:00 - 11:00 1.00 TRIP_ DP_ PRIDRL 11:00 - 12:00 1.00 TRIP_ BHA_ PR1 DRL 12:00 - 12:30 0.50 CLEAN_ RIG_ PR1 DRL 12:30 - 14:00 1.50 TRIP DP PR1 DRL 14:00 - 16:00 2.00 CIRC_ MUD_ PR1 DRL 16:00 - 17:00 1.00 SPOT_ PILL PR1 DRL 17:00 - 17:30 0.50 TRIP_ DP_ PR1 DRL 17:30 - 18:30 1.00 SOUEZE OTHR PR1 DRL 18:30 - 19:00 0.501 CIRC CFLD PR1 DRL 19:00 - 21:00 2.00 TRIP_ DP_ PR1 DRL 21:00 - 21:30 0.50 CLEAN_ RIG_ PR1 DRL 21:30 - 00:00 2.50 WAITON TRET PR1 DRL 00:00 - 01:00 1.00 TRIP_ BHA_ PR1 DRL 01:00 - 02:00 1.00 TRIP_ DP_ PR1 DRL 02:00 - 03:00 1.00 TRIP_ DP_ PR1 DRL 03:00 - 03:30 0.50 TRIP_ DP_ PR1 DRL 03:30 - 05:30 2.00 WAITON TRET PR1 DRL 05:30 - 06:00 0.50 TRIP_ DP_ PR1DRL 2/27/2006 06:00 - 06:30 0.50 TRIP_ DP_ PR1 DRL 06:30 - 07:00 0.50 CIRC MUD PR1DRL 07:00 - 08:00 1.00 TEST_ LOT_ PR1 DRL 08:00 - 10:30 2.50 TRIP DP PR1 DRL 10:30-12:30 2.00 CIRC_ MUD_ PR1DRL 12:30 - 13:00 0.50 TRIP_ DP_ PR1 DRL 13:00 - 14:00 1.00 TEST_ LOT_ PR1 DRL 14:00 - 14:30 0.50 TRIP_ DP_ PR1 DRL 14:30 - 18:00 3.50 DRILL_ ROT_ PR1 DRL 18:00 - 20:00 2.00 CIRC MUD PR1 DRL 20:00 - 22:30 2.50 TRIP_ DP_ PR1 DRL 22:30 - 23:00 0.50 TRIP_ BHA_ PR1 DRL 23:00 - 23:30 0.50 CLEAN_ RIG_ PR1 DRL 23:30 - 00:00 0.50 TRIP_ DP_ PR1 DRL 00:00 - 02:30 2.50 TRIP_ DP_ PR1 DRL 02:30 - 03:30 1.00 CIRC_ MUD_ PR1 DRL 03:30 - 04:30 1.00 SPOT PILL PR1 DRL 04:30 - 05:30 ~ 1.00 TRIP_ DP_ ~ PR1 DRL Spud Date: 2/18/2001 Start: 12/30/2005 End: 3/12/2006 Rig Release: 3/9/2001 Group: Rig Number: 1 Description of Operations Poh W 5" Drillpipe T/ 2500' Hole Taking Correct Displacement. No Fluid Loss. Troubleshoot Top Drive (Rotary Control) Poh F- 2500' T- 791' Poh Set Back BHA. Clean Rig Floor Thaw Out # 1 Carrier Air Compressor M/U Mule Shoe TIH W/ 5" Drill T-3752' Correct Hole Displacement./ No Fluid Loss Circ. & Cond Mud/ At 3752' Run Centerfuge Van Initinal Mud Wt. 9.2+ Final Mud Wt. 9.0+ Surface volume And Hole Volume PJSM: Pump 2 bbls H2O Test B/J, & Rig Cmt. Lines To 2000psi, Pump 5bbl 9.5 ppg pacer,Then 30bbls Form-a-Set Followed By 10.6 ppg Weighted Spacer Displace W/ 34 bbls 9.1 ppg Flow Pro Mud. POH At Reduced Hoisting Rate To 3200', Shut In And Squeeze 20bbls Of Form-A- Set Initinal Squeeze Pressure 200Psi At .95bbls Per Min Final Pressure 155psi. Hold For 10 Min. Bleed Off. Circulate B/U Clear Drillpipe & Hole Of Excess Formaset None Returned To Surface. (Circ At 224spm 429gpm 320psi POH W 5" Drillpipe F- 3200 Clean Floor, Blow Down Mud Lines Wait On Form-A-Set/ Troubleshoot Top Drive PJSM; M/U RIH W/ BHA. Test MWD Blow Down Mud Lines TIH F- 791' To 3100' No Fluid Loss To Hole TIH F- 3100'/ Wash Down To 3600' POH To 3450'/ Form-A-Set Not Set Up In Surface Sample Wait On Surface Sample Form-A-Set To Set Up Trouble Shoot Top Drive Rotary Problem RIH To 3740' Cont RIH W/ 5" Drillpipe T 3740' No Gain/ Loss Circ./Condition Mud For Fit Test. CBU. 120spm 380psi GPM. At 3740' Peform FIT/ 9.0 ppg MW At 3670' TVD (315psi= 10.65 EMW ) RIH, Wash And Clean Out Excess Form-A-Set F- 3740' T/4485'. Decrease Pump Rate To 200 Gpm Due To Hvy. Flow Of Forma-Set- Over Shakers Circ And Clean Up Hole At 4485' POH To 3750' Peform FIT Test 9.1 ppg MW At 3670' TVD (205psi= 10.23 EMW) TIH W/ 5" Dp To 4485' Drill & Survey F- 4485' To 4750' (2.9 ART) No Fluid Loss To Hole Circ. Pump Sweep At 4785' Sweep Returned At Caculated Hole Volume. 200Spm 380 Gpm 360 psi POH W 5" D/P F-3750' No Gain Loss POH & Stand Back BHA Clean Rig Floor/ M/U Mule Shoe/ Have Change Out With New Crew PJSM: TIH TO 4780' No Gain /Loss To hole R/U Cmt. Line/Circ Hold PJSM W/ B/J And Crews Pump 2 bbls H2O, Test Lines To 2000psi. PumplObbl 9.5ppg W/ 6%KCI 2ppb Flo Vis Spacer Followed By 42bbls Of Form-A-SeU Pump 20bbls/ 10.6ppg Mud. Displace W/ 51 bbls 9.1 Flow Pro Mud. R/D Cmt Line POH To 3752' At Reduced Hoisting Rate. Printed: 8/11/2006 2:29:06 PM • • Marathon Oil Company Page 7 of 9 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Event Name: RE-ENTRY Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours Code Code Phase 2/27/2006 105:30 - 06:00 0.501 SOUEZE OTHR PR1 DRL 2/28/2006 06:00 - 07:30 1.50 CIRC MUD PR1 DRL 07:30 - 10:00 2.50 TRIP_ DP_ PR1 DRL 10:00 - 11:30 1.50 SERVIC RIG PR1 DRL 11:30 - 12:00 0.50 TRIP BHA_ PR1 DRL 12:00 - 14:00 2.00 TRIP DP PR1 DRL 14:00 - 15:00 1.00 TEST LOT_ PR1 DRL 15:00 - 15:30 0.50 TRIP_ DP_ PR1 DRL 15:30 - 20:00 4.50 REAM OH PR1 DRL 20:00 - 21:30 1.50 CIRC MUD PR1 DRL 21:30 - 22:00 0.50 TEST_ LOT_ PR1 DRL 22:00 - 06:00 8.00 DRILL_ SLID PR1 DRL 3/1 /2006 ~ 06:00 - 02:00 20.00 ~ DRILL_ ~ ROT_ ~ PR1 DRL 02:00 - 03:30 1.50 ~ CIRC_ ~ MUD_ ~ PR1 DRL 03:30 - 04:00 0.50 MIX_ PILL PRIDRL 04:00 - 05:00 1.00 TRIP WIPR PR1 DRL 05:00 - 06:00 1.00 SERVIC RIG_ PR1 DRL 3/2/2006 06:00 - 07:00 1.00 TRIP_ DP_ PR1DRL 07:00 - 02:30 19.50 DRILL_ ROT_ PR1 DRL 02:30 - 05:00 ~ 2.501 CIRC_ MUD_ ~ PR1 DRL 05:00 - 06:00 1.00 DRILL_ ROT_ PR1 DRL 3/3/2006 06:00 - 06:30 0.50 DRILL ROT PR1 DRL 06:30 - 09:30 3.00 CIRC_ MUD_ PR1 DRL 09:30 - 10:30 1.00 DRILL ROT PR1 DRL 10:30 - 12:00 1.50 CIRC_ MUD_ PR1 DRL 12:00 - 14:00 2.00 DRILL ROT PR1 DRL 14:00 - 17:00 3.00 CIRC_ MUD_ PR1 DRL Spud Date: 2/18/2001 Start: 12/30/2005 End: 3/12/2006 Rig Release: 3/9/2001 Group: Rig Number: 1 Description of Operations R/U CMT Line, Squeeze 12.5 bbls Formaset/ W initinal Pressure Of 210psi Increased to Max Of 280 psi./ Final Pressure 180psi. Shut Down Pump. Bleed Off Circ B/U At 3700' No Excess Form-A-Set Returned To Shakers. Circ At 130spm 250 gpm 350psi. No Fluid Loss To Hole. PJSM:POH F-3700' W/ 5" D/P 3bbl Fluid Loss To Hole. PJSM ;Service Rig, Top Drive, Blocks& Carrier. Trouble Shoot Top Drive Replace Line To Turbo # 1 Carrier Motor. M/U 8 1/2 Drctnl BHA,RIH, Test Mwd RIH To 3740' At Reduced Rate (Form-A- Set Surface Sample Not Set Up. No Fluid Loss To Hole Perform precautionary FIT/ Test @ 3740' MD 3670 ND W/ 9.15 MW 205psi= 10.2 EMW ) Orient Thru Window F-3752 To 3788' Wash And Ream C/O F/ 3788' To 4785', Wash Uncured Form-A-Set F- 4100' To 4785' Reduce Circulating Rate F- 250 gpm To 120gpm Due To Mud Loss Over Shakers. Recover Mud From Cuttings Tank And Circ Back Over Shakers. Circ. And Condition Mud. Increase Circ. Rate To 140 spm 260 gpm 450 psi. Condition Mud. Shakers Cleand Up No Mud Loss At Flow Rate. Peform Open Hole Precautionary FIT Test At 4750 M/D W/ 9.15ppm 240psi=10.15 EMW At 4632' ND Drill And Survey F- 4785' To 5320' (AST=.30 ART= 3.10) ADT =3.40/ Fluid Loss To Hole 1 to 2 bbl Per Hr. Normal Tq/ Drag. Pump Rate 450gpm /236spm/1160psi Max Gas 333 Units. PTSM;Drctnl. Drill Survey F/ 5320' T/ 6218' (AST= 5.70hr. ART= 6.70hr. ADT=12.40hr. Pump Sweeps At 5540', 5850' Max Gas 484 Units Circ Pump Sweep At 6218' 195spm 374gpm 1100psi Increase In Cuttings Over hakers. Up Weight Prior To Sweep 170k TO 2400-3000 After Sweep Passed. Up Wt 167/ TO 2200-2700 Monitor Well, Pump Dry Job Fill Trip Tank PJSM;POH Wiper Trip F- 6218' T-4785' Normal Drag Hole Slick No Tight Spots / No Fluid Loss To Hole Service Rig, Top Drive, Blocks, Crown And Carrier TIH F-4785' T- 6218' No Fill/ Gain/ Loss/ Well Bore In Good Cond. Drctnl Drill, Survey F-6218' T- 7500' (ART= 9.90 AST= 1.30 ADT= 11.20.) Loss To Hole 5bbl Per Hr. No Gains/ Max Gas 1000 Units Pump Hi Vis Sweeps To Maintain Hole Cleaning. Circ. B/U Samples For Final TD. MOC GEO. DEPT. confirmed that the hole needs to go to at least 7650' - As Per Jennifer Enos @ 0500hr. The well is permitted and budgeted to go to 7819'. Note Lost 17bbls In 2hr. Drctnl. Drill & Survey F- 7500' To 7580" ART=.60 Drill ahead 8 1/2 hole dretnl 7580 - 7600 Rot = .5 hrs, AST = 0 hrs No gain, 1.5 bbl loss Circ samples as per MOC Geo dept Drill ahead 8 1/2 hole dretnl 7600 - 7700 Rot = 1 hr, AST = 0 hrs No gain / loss Note gas (background / conn) increasing with depth. Commence wt up to 9.6 ppg while drill / circ Circ samples as per MOC Geo dept Drill ahead 8 1/2 hole dretnl 7700 - 7830 Rot = 2 hrs, AST = 0 hrs No gain, 5 bbl loss Circ samples as per MOC Geo dept Increasing gas levels (2650 units Printed: 8/11/2006 2:29:06 PM • • Marathon Oil Company Page 8 of 9 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Event Name: RE-ENTRY Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From..- To Hours Code Code Phase 3/3/2006 14:00 - 17:00 17:00 - 02:00 3.00 CIRC_ MUD_ PR1DRL 9.00 CIRC_ MUD_ PR1DRL 02:00 - 06:00 3/4/2006 06:00 - 07:30 4.00 ~ TRIP_ ~ WIPR PR1 DRL 1.50 ~ TRIP_ ~ DP_ ~ PR1 DRL 07:30 - 09:30 2.00 REPAIR RIG_ PR1 DRL 09:30 - 10:00 0.50 TRIP_ DP_ PR1 DRL 10:00 - 10:30 0.50 CIRC_ MUD_ PR1 DRL 10:30 - 11:00 0.50 TRIP_ DP_ PR1 DRL 11:00 - 11:30 0.50 TRIP_ DP_ PR1 DRL 11:30 - 13:00 1.50 PUMP LCM PR1 DRL 13:00-18:00 5.OO~PUMP_LCM_ ~PR1DRL 18:00 - 20:00 2.00 TRIP_ DP_ PR1 DRL 20:00 - 22:30 2.50 PULD_ BHA_ PR1 DRL 22:30 - 00:00 1.50 PULD BHA_ PR1 DRL 00:00 - 06:00 6.00 _ TRIP DP PR1 DRL 3/5/2006 06:00 - 08:00 2.00 TRIP_ DP_ PR1DRL 08:00 - 10:30 2.50 CIRC_ MUD_ PR1DRL 10:30 - 15:00 4.50 TRIP_ DP_ PR1DRL 15:00 - 16:00 1.00 CIRC MUD_ PR1DRL 16:00 - 17:00 1.00 CIRC_ MUD_ PR1DRL 17:00 - 21:30 4.50 PUMP_ LCM_ PR1 DRL 21:30 - 00:30 3.00 TRIP_ DP_ PR1 DRL 00:30 - 01:30 1.00 PULD_ BHA_ PR1 DRL 01:30 - 06:00 4.50 TEST BOPE PR1 DRL 3/6/2006 06:00 - 07:00 1.00 TEST_ BOPE PR1 DRL 07:00 - 10:00 3.00 SERVIC RIG_ PR1 DRL 10:00 - 12:30 2.50 TRIP_ DP_ PR1 DRL 12:30 - 16:00 3.50 CIRC MUD PR1 DRL 16:00 - 17:00 1.00 CIRC MUD_ PR1 DRL 17:00 - 18:00 1.00 SLPCUT DLIN PRIDRL 18:00 - 19:30 1.50 TRIP_ DP_ PR1DRL 19:30 - 21:00 1.50 CIRC MUD PR1DRL 21:00 - 22:30 1.50 TRIP_ DP_ PR1DRL 22:30 - 04:00 5.50 CIRC_ MUD_ PR1 DRL Spud Date: 2/18/2001 Start: 12/30/2005 End: 3/12/2006 Rig Release: 3/9/2001 Group: Rig Number: 1 Description of Operations peak, with flowline increase) Cont increase mud wt 9.7 ppg. Cont increase mud wt /monitor well. Final mud wt 10.1 ppg. Flow check, fluid static. Pump wt pill for wiper trip. Flow check, POH wiper trip. No gain /loss, correct hole fill. Tight 6875 - 6350, 25 - 35K overpull, work free various intervals. 5300 ft at 0600 hrs. Cont POH 5" DP (wiper trip) to shoe 3780 ft. No gain /loss /swab, correct hole fill. Repair top drive valves. PJSM, flow check, RIH 5" DP to 3930 ft. Circ /test top drive valves for leaks RIH to 4900, no displacement returns, flow check, no visual fluid column. PJSM, POH 5" DP to shoe 3690 ft. Mx /pump Ca Carb LCM pill (100 ppb / 70% coarse, 30% med) at 3690 ft, clear motor assy with pill, allow drop /settle to lost zone. Build surface volume, fill hole through kill line. Fill volume = 560 ft to fluid column. Monitor well, static losses 5 - 10 bph. POH 5" DP to surface for BHA. Flow check, approx 5 bph static losses, LD dretnl assy. MU 8 1/2 tri cone bit, RIH same. Flow check, follow BHA with 5" DP to 5100 ft at 0600 hrs. Slow going, fill pipe, surge precautions due to losses. Cont RIH 5" DP to tag at 7706 ft (fill) Attempt circ, approx 5 bbls return, lose all returns, total loss. PJSM, flow check (3 - 5 bph static loss), POH 5" DP to shoe at 3730 ft. Slight sticking off slips all stands to 4550 ft, freeing up to shoe. No swab / gain. Continued 5 bph static loss. Circ btms up, 250 gpm / 650 psi. Gas 500 units, no attending flow. Initial loss 3 bph decreasing to 0 bph. RIH to 3880 ft open hole, attempt circ, immediate total loss, no returns. Pull into shoe, mix /pump 100 bbls LCM MI seal (50 bbl, 20 pbb fine, 20 ppb med, 30 ppb coarse) (50 bbl, 20 ppb fine, 20 ppb med, 50 ppb coarse) Spot over loss zone, pull above pill, 0 bbl static losses. 200 psi squeeze press / 10 min, no loss. PJSM, POH for BOP test, correct hole fill, no gain /loss. Flow check, stand bk BHA. RU /test BOPE all components 250 1 3000 / 5 min. Test successful, 1 re-test kill line check. Witness waived Mr Jeff Jones. Complete test BOPE, RD floor, set wear ring, prepare RIH Ser rig, run in top drv, dble check all conn's, PJSM, flow check (well static), RIH 8 1/2 bit on 5" DP to 3700 ft. Circ at shoe (3700 ft) while build fluid volume. 100% returns. Max gas 585 units. RIH, circ at 3880 ft (btm thief zone) 100% returns 250 gpm / 175 psi. Gas 150 units. Slip / cut drlg line Flow check, RIH 5" DP to 5800 ft, no bridge / do drag /losses Circ at 5800 ft, 250 gpm / 350 psi, 100% returns, no losses Max gas 2100 units. Flow check, RIH 5" DP to 7605 ft, precaution wash to 7830 ft Circ at 7830 ft, 100% returns. Max gas 3100 units, decreasing to 2000 units (2 hrs circ time), further decreasing to 125 units and stable. Pump hi vis sweep / wt pill (25% increase cuttings) No gain /loss. Note: Add 3% tube to fluids (No sticking off slips) Printed: 8/11/2006 2:29:06 PM L` Marathon Oil Company Page 9 of 9` Operations Summary .Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Spud Date: 2/18/2001 Event Name: RE-ENTRY Start: 12/30/2005 End: 3/12/2006 Contractor Name: GLACIER DRILLING Rig Release: 3/9/2001 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From= To Hours Code Code Phase Description of Operations 3/6/2006 04:00 - 06:00 2.00 TRIP_ DP_ PR1DRL Flow check, PJSM, POH 5" DP for E-logs Correct hole fill, no up drag, no gain /loss 5800 ft at 0600 hrs. 3/7/2006 06:00 - 11:00 5.00 TRIP_ DP_ PR1 DRL Cont POH to surface for E-logs, no drag /gain /loss. 11:00 - 12:00 1.00 RURD_ ELEC PR1 EVL PJSM, R/U E-log equip 12:00 - 14:00 2.00 RURD_ ELEC PR1 EVL Place /seat Quad Combo E-log tool in 3 1/2 DP, Load source, re-seat, confirm seated. 14:00 - 19:00 5.00 TRIP_ DP_ PR1 EVL PJSM, follow 3 1/2 DP with 5" DP to 3700 ft, break circ (Max gas 1200 units, stop pump, flow check, well static) RIH 5800 ft. 19:00 - 21:00 2.00 CIRC_ MUD_ PR1 EVL Break circ 5800 ft, cont circ out gas, max 1512 units. 21:00 - 23:00 2.00 TRIP_ DP_ PR1 EVL Flow check, well static, RIH 5" DP to 7830 ft, no fill. POH to 7717 ft. 23:00 - 02:00 3.00 CIRC_ MUD_ PR1 EVL Circ / cond fluids, trace LCM /cuttings to surface. Max gas 2700 units, no increased flow with gas. 02:00 - 03:00 1.00 LOG_ OH_ PR1 EVL Pump /deploy messenger tool, confirm deployed. 03:00 - 06:00 3.00 LOG_ OH_ PR1 EVL Commence log up 7821 - 4575 with Quad Combo. No drag /swab /flow. Correct hole fill. 3/8/2006 06:00 - 09:00 3.00 LOG_ OH_ PR1 EVL Cont E-logs, quad combo /shuttle, 4575 - 3700 ft (window) 09:00 - 10:00 1.00 TRIP_ DP_ PR1 EVL PJSM, flow check, POH 5" DP with Log tools. No gain /loss, correct hole fill. 10:00 - 11:00 1.00 LOG_ OH_ PR1 EVL PJSM, RD log equip, release unit. Printed: 8/11/2006 2:29:06 PM • • Marathon Oil Company Page 1 of 2 Opera#ions Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Spud Date: 2/18/2001 Event Name: ORIGINAL COMPLETION Start: 3/8/2006 End: 3/13/2006 Contractor Name: GLACIER DRILLING Rig Release: 3/9/2001 Group: Rig Name: GLACIER DRILLING Rig Number: 1 .Date From - To Hours Code ~ d Phase Description of Operations oe 3/8/2006 11:00-13:00 2.00 TRIP_ DP_ PRICSG 13:00-14:00 1.00 CIRC_ MUD_ PR1CSG 14:00-15:00 1.00 TRIP_ DP_ PRICSG 15:00-17:00 2.00 CIRC_ MUD_ PRICSG 17:00-18:00 1.00 TRIP_ DP_ PRICSG 18:00 - 00:00 6.00 CIRC MUD PR1 CSG 00:00 - 02:30 2.50 TRIP_ WIPR PR1 CSG 02:30 - 03:00 0.50 SERVIC RIG_ PR1 CSG 03:00 - 05:00 2.00 WAITON ORDR PR1 CSG 05:00 - 06:00 1.00 TRIP_ WIPR PR1CSG 3/9/2006 06:00 - 07:30 1.50 TRIP_ DP_ PRICSG 07:30 - 10:00 2.50 CIRC_ MUD_ PRICSG 10:00 - 10:30 0.50 CIRC_ MUD_ PR1CSG 10:30 - 19:00 8.50 PULD_ DP_ PRICSG 19:00 - 19:30 0.50 PULL_ EQIP PR1CSG 19:30 - 22:30 3.00 RURD_ OTHR PRICSG 22:30 - 23:30 1.00 RURD CSG PR1CSG 23:30 - 00:00 0.50 RURD_ OTHR PR1CSG 00:00 - 06:00 6.00 RUN_ CSG_ PR1CSG 3/10/2006 06:00 - 07:30 1.50 RUN_ CSG_ PR1 CSG 07:30 - 08:30 1.00 CIRC_ MUD_ PR1 CSG 08:30 - 11:00 2.50 RUN_ CSG_ PR1 CSG 11:00 - 12:00 1.00 CIRC_ MUD_ PRICSG 12:00 - 17:30 5.50 RUN_ CSG_ PR1 CSG 17:30 - 19:30 2.00 CIRC_ MUD_ PR1 CSG 19:30 - 23:30 4.00 RUN CSG PR1 CSG 23:30 - 03:30 4.00 CIRC_ MUD_ PR1 CSG 03:30 - 06:00 2.50 LOG_ OTHR PR1CSG 3/11/2006 06:00 - 06:30 0.50 LOG_ CSG_ PRICSG 06:30 - 09:00 2.50 CIRC_ MUD_ PR1 CSG 09:00 - 10:00 1.00 CIRC_ MUD_ PR1 CSG 10:00 - 10:30 0.50 RUN_ CSG_ PR1 CSG 10:30 - 11:00 0.50 PUMP_ CMT_ PR1CSG 11:00 - 14:00 3.00 PUMP CMT PR1CSG 14:00 - 14:30 0.50 PUMP_ CMT_ PR1CSG 14:30 - 01:00 10.50 WAITON CMT_ PR1 CSG PJSM, flow check, RIH bit on 5" DP to window at 3700 ft Circ btms up at 3700, max gas 710 units. Flow check, RIH to 5800 ft Circ btms up at 5800 ft, max gas 2100 units Flow check, RIH to 7830 ft, no fill Circ / cond fluids, max gas 2250 units, no attending increase inflow with gas. All circulations 250 gpm. PJSM, flow check, POH wiper trip to shoe 3700 ft. Service rig Circ at shoe while wait on orders MOC Geo Dept PJSM, flow check, RIH 5" DP to 5700 ft at 0600 hrs. Receive module pick points MOC Geo Dept at 0530 hrs. RIH w/5" DP. Wash last stand down(4' fill). Circ. clean at reduced rate(CBUX2, 184gpm, 320psi, 18RPM, Max gas 3232units) Flow check(well taking less than 1 bbl/hr). Pump KCL dry job. POOH. L/D 5" DP. No Gain/ Loss To Hole Pull Wear Bushing R/D Tongs & Spinners. Clear Floor Of Rotary Tools C/O Bails PJSM: R/U Weatherford Csg. Tools. (Monitor Well During R/U with Returns To Trip Tank (3bbl loss 13 hr.) PJSM; R/U Expro Control Lines And Sacrfical Cable PJSM; M/U Shoe Joint And Float Collar, Ck Floats. Run 3 112 Excape System As Per MOC Program. 9 Modules, 3 Control Lines And 1 Sacrfical Cable To '1900 @ O600hr. Cont. RIH w/Excape modules to 2350'(total 13 modules). Circ. 3.5" CSG(190GPM, 320psi, max 1030units gas).. Cont. RIH w/3.5" csg. to 3700'. Circ. 3.5" CSG(196GPM, 420psi, max 2300 units gas). Cont. RIH w/3.5" CSG to 5860'. Circ. 3.5" CSG At 5854' (196gpm 520psi Max 1675 units Gas. Cont. RIH W/ 3 1/2 Csg. F- 5860' T-7812'( Total of 226 Jts Run W/ 3 Control Lines ,1 Saf.Cable And 13 Modules) No Gain/ loss Normal Drag Up Wt 100K Dn Wt. 75 Circ 3.5 Csg. At 7812' (167gpm 525psi Max B/U Gas 2346Units) 2 X B/U To Circ Gas Out Of Well bore PJSM; R/U Expro WLS & Run G/R Correlation Log Confirm Setting Depth Of Excape Modules. R/D Expro E/L. Circ. 3 1/2"CSG(196GPM,698psi, max gas 2565psi). Spot 210bb1s of inhibited mud ahead of cement. Space out CSG string and R/U BJ cement head. Thaw out cement line. Pump 5bbls water ahead. Test cement lines to 3500psi. Mix and pump 26bbls 10.2ppg spacer. Mix and pump 267sxs Gass"G" cement w/10%BA-90, 2.5%BA-56, .5%EC-1, .1 %ASA-301, .75%SMS and 1 GPHS FP-61 to yield 102bb1s 12.7ppg slurry. Tail in with 878sxs class"G" cement w/1.2%BA-56, .5%EC-1, .05%R-3, .2%SMS, .2%CD-32, and 1 GPHS FP-6L to yield 181 bbls 15.8ppg slurry. Wash lines to slop tank. Displace w/68.5bbls 6%KCL. Bump plug w/500psi over last displacement pressure. 100% returns during cement job. PJSM; Flush Mud Lines, Stack, Choke& Mud Pumps. Clean Pits. WOC Printed: 8/11/2006 2:30:46 PM • • Marathon Oil Company Page 2 of 2 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common W Event Name Contractor Rig Name: Date ell Name: : Name: From - To KENAI B ORIGINA GLACIE GLACIE Hours ELUGA L COM R DRILL R DRILL Code:. UNIT 2 PLETI ING ING .:Code 4-6 ON Phase Spud Date: 2/18/2001 Start: 3/8/2006 End: 3/13/2006 Rig Release: 3/9/2001 Group: Rig Number: 1 Description of Operations 3/11/2006 14:30-01:00 10.50 WAITON CMT_ PR1CSG 12hr.) Monitor Fluid Level In Annulus, 5.5 bbl Loss F- 14:30hrs To 22:OOhrs. No Loss F- 22:00 To 0300hrs. 01:00 - 03:00 2.00 NUND BOPE PR1 CSG PJSM; N/D Drip Pan Flow Lines, Kill & Choke Lines. Clean Cellar N/D BOP Stack 03:00 - 06:00 3.00 NUND WLHD PRICSG PJSM: Set CSG slips w/55K/Rough Cut Csg and move out BOP from sub. 3/12/2006 06:00 - 11:00 5.00 NUND TREE PR1 CSG Dress gaulded threads in wellhead for lockdown bolts. Clean pits. Prep rig floor for R/D. 11:00 - 14:00 3.00 NUND TREE PR1CSG Continue to R/D rig while make final cut and dress 3 1/2" CSG stub. Set Vetco 3 1 /2" X 13 5/8" Packoff. 14:00 - 16:30 2.50 NUND TREE PR1CSG Install 13 5/8" 5M X 3 1/8" 5M tubing head adapter and 3 1/8" 5M tree. 16:30 - 18:00 1.50 TEST_ TREE PR1 CSG Test void to 5000psi/10min. Load tree w/diesel test tree 5000psi/10min. Pull TWC and install BPV. 18:00 - 00:00 6.00 RURD_ RIG_ RDMO PJSM: R/D Top drive torque tube turn buckles. Prep derrick to scope down. C/O motor fan above shakers. L/D top drive torque tube. Remove tarps from carrier. Prep to split pits. 00:00 - 03:30 3.50 RURD_ RIG_ RDMO Remove derrick tarps. R/D driller console. Power down boiler. R/D flow line adapter. R/D flowline. 03:30 - 06:00 2.50 RURD_ RIG_ RDMO PJSM w/crane operator. Crane down stairs and fuel tank. 3/13/2006 06:00 - 09:30 3.50 RURD_ RIG_ RDMO Crane down dog house, windwalls, flow line, stairs, beaver slide. R/D catwalk, mud pump lines. 09:30 - 12:00 2.50 RURD_ RIG_ RDMO PJSM w/truck drivers. Split pits and pump room. Pull wires. Complete crane work. Prep to move rig. Rig released from KBU 24-6RD and accepted on KU 21-7X @ 12:OOhrs 03/12/2006. Final Report KBU 24-6RD Printed: 8/11/2006 2:30:46 PM • • Marathon Oil Company Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours: Code Code Phase Page 1 of 5 Spud Date: 2/18/2001 End: 6/23/2006 Group: Description of Operations 4/2!2006 10:00 - 10:45 0.75 RURD_ ELEC PR1CSG MI spot up equipment, uptain work permit and held PJSM 10:45 - 11:30 0.75 LOG_ OTHR PR1 CSG RU wire line unit. Open well run in hole with CCL, gammy ray and CBL tool 11:30 - 14:20 2.83 LOG_ OTHR PR1 CSG Made repeat log accross section 7750' to 7500' KBD (depth from field log). Drop down to PBTD at 7735'. 14:20 - 16:20 16:20 - 16:45 16:45 - 18:00 5/17/2006 06:00 - 18:00 5/19/2006 07:00 - 07:30 07:30 - 14:00 14:00 - 17:00 17:00 - 18:30 18:30 - 19:00 19:00 - 20:00 20:00 - 22:00 22:00 - 23:00 5/20/2006 06:00 - 07:00 07:00 - 08:00 (PBTD Notes: According to the pipe tally for the Excape string the top of the float collar for the string is at 7775' RKB. The wireline measure showed getting down to 7735' for this work. The loggers showed 7750'. On 5/20/06 the coil tubing reaches 7767' CTM.) 2.00 LOG_ OTHR PR1 CSG Made main logging pass from 7750' KB to 3300' KBD. Found top of cement at 3630' KBD. 0.42 LOG_ OTHR PR1 CSG Good cement accoss all modules. OOH with logging tools. Secured well. 1.25 RURD_ ELEC PR1 CSG Rig down wire line unit. Expro left lease 12.00 RURD_ STIM CMPSTM MIRU tanks, flow back iron, fluid tanks, PWS equiimpent 0.50 SAFETY MTG_ CMPSTM Hold PJSM. Discussed frac and CTU RU operations around frac tanks containing methanol. Established red and yellow workzones, and proper PPE. 6.50 RURD_ STIM CMPSTM RU frac trucks and lines to well. RU CTU equipment and lines. RU well testers lines. 3.00 PERF_ CSG_ CMPSTM RU to perforate module 1 at 7466 - 7476'. Filled and pressure tested green line. Attempt to fire module 1, green line immediately pressured up after only two pump strokes. Check for closed surface valves, pumped through line. All clear. Attempt to pressure up green line to fire gun and pressure immediately climbed to 5000 psi. Shut down and called Vetco. Inspected tree termination on green line and replaced ferrule on control line. Repressured again to 10000 psig immediately. Bled off pressure and ran bailing wire through green line. Hit what appeared to be crimped/pinched control line +/- 18" below tree flange. Switch over to both yellow and red lines to confirm integrity. On both lines pumped normal volume of fluid prior to catching pressure. Yellow and Red lines appear ok. Call for wireline perfoating. 1.50 RURD_ COIL CMPSTM Finished RU CTU. Pressure tested all lines and BOP to 4500 psig. Pressure tested well testers and flow back iron to 4500 psig. All good. 0.50 SAFETY MTG_ CMPSTM Expro arrive KGF and obtained work permit. Held PJSM and proceeded to well location 1.00 RURD_ ELEC CMPSTM RU expro truck and lubricator. Post safety area warning signs and ensure communication blackout. Arm 10' 2-1 /8"gun and MU lubricator to CTU BOP. 2.00 RUNPUL ELEC CMPSTM RIH with 10' perforating gun loaded at 6 spf 60 deg. phasing to PBTD of 7735'. Log up for CCL strip and tie in same to CBL/OHL. Perforate module 1 from 7466 - 7476'. No pressure indication at surface. POOH with gun. (PBTD Notes: According to the pipe tally for the Excape string the top of the float collar for the string is at 7775' RKB. The wireline measure showed getting down to 7735' for the CBL. The field log of the CBL shows 7750'. On 5/20/06 the coil string reaches 7767' CTM.) 1.00 RURD_ ELEC CMPSTM Shut well in. RD lubricator. Inspect gun. All shots fired. RD expro and SDFN. 1.00 INSPCT EOIP CMPSTM Arrive location. Obtain work permit. Perform site /equipment inspection and audit. 1.00 SAFETY MTG_ CMPSTM Hold PJSM. Discuss methanol hazards and frac pump operations, PPE, Start: 4/2/2006 Rig Release: 3/9/2001 Rig Number: 1 Printed: 8/11/2006 2:31:25 PM • Marathon Oil Company Page 2 of 5 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Spud Date: 2/18/2001 Event Name: ORIGINAL COMPLETION Start: 4/2/2006 End: 6/23/2006 Contractor Name: GLACIER DRILLING Rig Release: 3/9/2001 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code. Code. Phase Description of Operations 5/20/2006 ~ 07:00 - 08:00 1.00 SAFETY MTG CMPSTM red and yellow work zones, production alarms, frac tracing, emergency 08:00 - 09:30 09:30 - 10:30 10:30 - 11:15 11:15 - 12:15 12:15 - 13:00 13:00 - 13:45 13:45 - 14:15 14:15 - 15:00 response, etc. 1.50 TEST_ EOIP CMPSTM Attempt to pressure test frac lines and trucks to 9500 psig. Repaired numerous little leaks. Obtained good pressure test to 9500 psig. 1.00 PUMP_ FRAC CMPSTM Flush test water out of lines and gel up 4% KCL water containing 25% methanol. Perform QA/OC checks on fluid 0.75 PUMP_ FRAC CMPSTM Frac mod 1 perfs at 7466-7476' w/ BJ Medallion Hybrid 2500 wtr/Methanol based system at 15 BPM at max TP = 4765 psi. Ramp 1.0 - 8.0 ppa. Place 29345 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 288 bbl. Tagged w/ ProTechnics CFT 1100 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 288 bbls) Strap all chemical tanks and verify inventory. 1.00 PUMP_ FRAC CMPSTM Pressure up on yellow line and perforate Module 2 at 7028-7038' .Very weak indication of gun firing. Had to pressure up above moduel firing range. Appears that module 2 is perforated. Frac mod 2 perfs w/ BJ Medallion Hybrid 2500 wtr/Methanol based system at 15 BPM at max TP = 3800 psi. Ramp 1.0 - 8.0 ppa. Place 29263 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 235 bbl. Tagged w/ ProTechnics CFT 1200 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 523 bbls) Strap all chemical tanks and verify inventory. (Note: Later -the assumption is that module 2 was perforated, but not frac'd.) 0.75 PUMP_ FRAC CMPSTM Pressure up on yellow line and perforate Module 3 at 6860 -6870' .Better indication fo gun firing, yet still weak. frac mod 3 perfs w/ BJ Medallion Hybrid 2500 wtr/Methanol based system at 15 BPM at max TP = 3800 psi. Ramp 1.0 - 8.0 ppa. Place 28218 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 240 bbl. Tagged w/ ProTechnics CFT 1400 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 763 bbls) Strap all chemical tanks and verify inventory. 0.75 PUMP_ FRAC CMPSTM Pressure up on yellow line and perforate Module 4 at 6700 -6710' .Better indication fo gun firing. frac mod 4 perfs w/ BJ Medallion Hybrid 2500 wtrlMethanol based system at 15 BPM at max TP = 3588 psi. Ramp 1.0 - 8.0 ppa. Place 29376 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 235 bbl. Tagged w/ ProTechnics CFT 1500 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 998 bbls) Strap all chemical tanks and verify inventory. 0.50 PUMP_ FRAC CMPSTM Pressure up on yellow line and perforate Module 5 at 6572 -6582' .Better indication fo gun firing. frac mod 5 perfs w/ BJ Medallion Hybrid 2500 wtr/Methanol based system at 15 BPM at max TP = 3495 psi. Ramp 2.0 - 8.0 ppa. Place 32973 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 230 bbl. Tagged w/ ProTechnics CFT 1600 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1228 bbls) Strap all chemical tanks and verify inventory. 0.75 PUMP_ FRAC CMPSTM Pressure up on yellow line and attempt to perforate Module 6 at 6360 -6370' .Gun fired but also vented indicating module 7 perforated at 6308 - 6318. Assume module 2 not treated, but perforated. Previous modules treated are 1, 3, 4, 5, 6 and not 1,2,3,4,5. Future GR will be definitive answer. frac mod 7 perfs w/ BJ Medallion Hybrid 2500 wtr/Methanol Printed: 8/11/2006 2:31:25 PM • • Marathon Oil Company Page 3 of s Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours Code Code Phase Spud Date: 2/18/2001 Start: 4/2/2006 End: 6/23/2006 Rig Release: 3/9/2001 Group: Rig Number: 1 Description of Operations 5!20/2006 14:15 - 15:00 0.75 PUMP_ FRAC CMPSTM based system at 15 BPM at max TP = 5300 psi. Ramp 1.0 - 8.0 ppa. Place 25548 Ibs prop (87.5 %.20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 226 bbl. Tagged w/ ProTechnics CFT 1700 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1454 bbls) Strap all chemical tanks and verify inventory. 15:00 - 15:30 0.50 PUMP_ FRAC CMPSTM Pressure up on red line and perforate Module 8 at 6200 -6210' .Good indication of gun firing as pinned. Frac mod 8 perfs w/ BJ Medallion Hybrid 2500 wtr/Methanol based system at 15 BPM at max TP = 3200 psi. Ramp 1.0 - 8.0 ppa. Place 33408 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 250 bbl. Tagged w/ ProTechnics CFT 2000 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1704 bbls) Strap all chemical tanks and verify inventory. 15:30 - 16:00 0.50 PUMP_ FRAC CMPSTM Pressure up on red line and perforate Module 9 at 5930 - 5940' .Good indication of gun firing as pinned. Frac mod 9 perfs w/ BJ Medallion Hybrid 2500 wtr/Methanol based system at 15 BPM at max TP = 4781 psi. Ramp 1.0 - 8.0 ppa. Place 29962 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 237 bbl. Tagged w/ ProTechnics CFT 2100 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1941 bbls) Strap all chemical tanks and verify inventory. 16:00 - 16:30 0.50 PUMP_ FRAC CMPSTM Pressure up on red line and perforate Module 10 at 5788 - 5798' .Good indication of gun firing as pinned. Frac mod 10 perfs w/ BJ Medallion Hybrid 2500 wtr/Methanol based system at 15 BPM at max TP = 3068 psi. Ramp 1.0 - 8.0 ppa. Placed 29470 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 228 bbl. Tagged w/ ProTechnics CFT 2200 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 2169 bbls) Strap all chemical tanks and verify inventory. 16:30 - 17:00 0.50 PUMP_ FRAC CMPSTM Pressure up on red line and perforate Module 11 at 5746 - 5756' .Good indication of gun firing as pinned. Frac mod 11 perfs w/ BJ Medallion Hybrid 2500 wtr/Methanol based system at 15 BPM at max TP = 2850 psi. Ramp 1.0 - 8.0 ppa. Placed 26742 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 218 bbl. Tagged w/ ProTechnics CFT 2400 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 2387 bbls) Strap all chemical tanks and verify inventory. 17:00 - 17:30 0.50 PUMP_ FRAC CMPSTM Pressure up on red line and perforate Module 12 at 5570 - 5580' .Good indication of gun firing as pinned. Frac mod 12 perfs w/ BJ Medallion Hybrid 2500 wtr/Methanol based system at 15 BPM at max TP = 2707 psi. Ramp 1.0 - 8.0 ppa. Placed 28648 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 224 bbl. Tagged w/ ProTechnics CFT 2500 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 2611 bbls) Strap all chemical tanks and verify inventory. 17:30 - 18:00 0.50 PUMP_ FRAC CMPSTM Pressure up on red line and perforate Module 13 at 5520 - 5530' .Good indication of gun firing as pinned. Frac mod 13 perfs w/ BJ Medallion Hybrid 2500 wtrlMethanol based system at 15 BPM at max TP = 2797 psi. Ramp 2.0 - 8.0 ppa. Placed 16665 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 154 bbl. Tagged w/ ProTechnics CFT 1000 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 2765 bbls) Strap all chemical tanks and verify inventory. Printed: 8/11/2006 2:31:25 PM Marathon Oil Company Page 4 of 5 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Spud Date: 2/18/2001 Event Name: ORIGINAL COMPLETION Start: 4/2/2006 End: 6/23/2006 Contractor Name: GLACIER DRILLING Rig Release: 3/9/2001 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase 5/20/2006 18:00 - 21:00 3.00 RURD OTHR CMPSTM 21:00 - 22:30 1.50 FLOW BACK CMPSTM 22:30 - 01:00 2.50 RUNPUL COIL CMPSTM 01:00 - 01:30 0.50 CIRC_ CFLD CMPSTM 01:30 - 03:00 1.50 RUNPUL COIL CMPSTM 03:00 - 04:30 1.50 JET_ N2_ CMPSTM 04:30 - 06:00 1.50 JET_ N2_ CMPSTM 5/21/2006 06:00 - 09:30 3.50 JET_ N2_ CMPSTM 09:30 - 10:30 1.00 JET_ N2_ CMPSTM 10:30 - 12:30 2.00 JET_ N2_ CMPSTM 12:30 - 13:30 1.00 RUNPUL COIL CMPSTM 13:30 - 15:00 1.50 RURD COIL CMPSTM 15:00 - 06:00 15.00 FLOW BACK CMPFLW 5/22/2006 06:00 - 06:00 24.00 FLOW TEST CMPFLW 5/23/2006 06:00 - 15:30 9.50 FLOW TEST CMPFLW 15:30 - 06:00 14.50 FLOW BACK CMPFLW Description of Operations:.: Hold PJSM for RD operations. RD frac lines and trucks. Clean up location. RD expro firing lines. Transfer remaining fluid to CTU supply tank. RU CTU. Opened well up to see if well would unload. Unloaded 1 bbl in 1.5 hours. RIH with CT at min fluid rate of 0.5 bpm. Increase rate to 1.75 bpm at 5400' and check PU wt. Continue in hole and broke flappers in modules 9 and 7, at 5953' and 6333' CTM respectively. Did not find any other flappers. RIH to PBTD at 7767' CTM CBUx2 POOH to module 2 flapper. Shutdown pumps and locate flapper at 7053' CTM and break same. POOH to module 3 flapper. Shutdown pumps, did not locate flapper. POOH to module 4 flapper. Shutdown pumps, did not locate flapper. POOH to module 5 flapper and shutdown pumps. Located module 5 flapper at 6592' CTM but could not break. POOH to module 6 flapper, shutdown pumps. Located module 6 flapper at 6383' CTM and broke same. POOH to module 8 flapper and shustdown pumps. Could not locate flapper. POOH to module 10 adn 11 flappers. Shutdown pumps. Located module 11 flapper at 5766' CTM, but could not break. (no shot at module 10). POOH to module 12 flapper. Located module 12 flapper at 5593' CTM. Broke same. POOH to module 13 flapper. Could not locate flapper. POOH to 5500' CTM. Bring fluid pump on at 1 bpm and start Nitrogen at 500 scfm. Shutdown fluid once Nitrogen turned corner. Jet well with 500 scfm nitrogen at 5500' CTM. Increase Nitrogen to 750 scfm and start RIH to below module 1 at 7500' CTM. Cut Nitrogen to 500 scfm and jet below perfs. Cumm recovery = 54 bbls. Jet well with 500 scfm nitrogen at 7500' CTM. FTP = 180 psig BWPD unload rate = 512 bpd Cumm Rec = 145 bbls or 5.2% of total frac load of 2765 bbls Increase nitrogen to 750 scfm FTP = 300 psig Est BHP = 1470 psig BWPD = 598 bpd Cumm recovery = 166 bbls (6% of total frac load of 2765 bbls) Open second flowline to flowback tank. FTP decreased from 300 psig to 185 psig. EST BHP from 1539 psig. Continue jetting below module 1 with 750 scfm nitrogen. Out of nitrogen. Cumm Rec = 213 bbls or 8% of frac load POOH with CT. Isolate injector head and take well through flowline for monitoring. Blow down CT and RD injector head. RD CT lines while monitoring well production. Send CT crew home for rest. Will decide on more nitrogen based upon well monitoring. Monitor well for flow. FTP increased from 25 psig to 150 psig. BWPD from 85 to 513. Est BHP from 1658 to 1379 psig. Cumm Rec at 0600 = 454 bb{s or 16.4% of frac Toad) Flow test well. Well making 1.1 mmcfd and 400 bwpd on an open choke with WHP = 225 psig. Cumm water recovery = 707 bbls or 25.6% of total frac load of 2765 bbls. Place well into LP sales system at 0330 hrs 5/22/06 Flow test well. Gas = 1.33 mmcfd, FTP = 245 psig, Est. BHP = 1266 psig, Water = 372 bwpd. Cumm Rec = 791 bbls or 28.6% of frac load Take well back to gas buster to blowdown to atmosphere. Well unloading fluid as of 0600 hours at 342 bwpd with aWHP = 205 pisg and Est. BHP Printed. 8111(2006 2.3125 PM • • Marathon Oil Company Page 5 of 5 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 24-6 Common Well Name: KENAI BELUGA UNIT 24-6 Spud Date: 2/18/2001 Event Name: ORIGINAL COMPLETION Start: 4/2/2006 End: 6/23/2006 Contractor Name: GLACIER DRILLING Rig Release: 3/9/2001 Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To . Phase Hours Code Cod Description of Operations e 5/23/2006 15:30 - 06:00 14.50 FLOW BACK CMPFLW = 485 psig. 5/24/2006 06:00 - 08:30 2.50 FLOW BACK CMPFLW Continued to blow well down. FTP = 205 psig water = 128 bwpd. 08:30 - 06:00 21.50 FLOW_ TEST CMPFLW Place well back to LP sales through testers. As of 0600 hours 5/24/06 well making 1.6 mmcfd FTP = 285 psig, Est. BHP = 545 psig, Water = 176 bwpd on an open choke. Test separator pressure full open with well riding LP suction pressure. Cumm rec = 1046 bbls or 37.8% of frac load. 5/25/2006 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW Continued to flow teset well. As of 0600 hours 5/25/2006 Gas = 1.74 mmcfd, water = 174 bwpd, FTP = 300 psig, Est. BHP = 560 psig on an open choke riding LP sucction pressure. Cumm fluid rec = 1193 bbls or 43% of total frac load of 2765 bbls. 5/26/2006 06:00 - 06:00 24.00 FLOW TEST CMPFLW Flow tested well. As of 0600 hours 5/26/2006 gas = 1.83 mmcfd, water-- 146 bpd, FTP = 300 psig, est. BHP = 544 psig. Cumm rec = 1317 bbls or 47.6% of total frac load of 2765 bbls. Final Post frac test report 6/21/2006 13:30 - 14:15 0.75 RURD_ SLIK CLNOUT Arrive KGF office. Obtain work permit and hold PJSM. P/U wireline truck an dmove to Pad 14-6 14:15 - 15:00 0.75 RURD_ SLIK CLNOUT RU 1-3/4" tool string with 2.35" swedge. PU same into lubricator. M/U lubricator and pressure test same. 15:00 - 16:00 1.00 RUNPUL SLIK CLNOUT RIH with swedge. Tagged up flapper housing in module 6 at 6385'. Continied in hole and broke falppers in modules 5, 4, and 3, at 6597', 6726', 6885', respectively. Continued RIH and Tagged PBTD at 7670' approximately 200' below module 1. Made several passes through modules. Same clean and clear of obstructions. POOH. 16:00 - 16:45 0.75 RURD_ SLIK CLNOUT Isolat Lubricator from well and blowdown same. RD lubricator and tool string. RD wireline truck. Turned in work permit and signed out. 6/22/2006 08:00 - 08:45 0.75 SAFETY MTG_ PR1 EVL Arrive KGF office. Sign in, obtain work permit, and hold PJSM. 08:45 - 10:00 1.25 RURD_ ELEC PR1 EVL MU PLT string adn equipment. Perform surface test on same. MU and PT lubricator to wellhead. 10:00 - 16:30 6.50 LOG CSG_ PR1 EVL Obtain pressure and temp data at surface. RIH and POOH from 5470 to 7530' making PLT logging passes at 30, 60, and 90 FPM. No obstructions, all logging went well. 16:30 - 18:30 2.00 LOG_ OTHR PR1 EVL RIH to 7260'. POOH making 5 minute stops at 7260', 6950', 6790', 6650', 6480', 6340', 6260', 6075, 5870', 5780', 5670', and 5560'. Discovered 30 fpm PLT log pass data was lost along with stop data. 18:30 - 21:30 3.00 LOG_ CSG_ PR1 EVL RIH making 30 fpm down pass to 7530'. POOH at 30 fpm to 5470'. 21:30 - 23:30 2.00 RUNPUL ELEC PR1 EVL POOH. RD lubricator and PLT string. Turn in work permit and sign out. Will re run stops tomorrow. 6/23/2006 08:45 - 09:30 0.75 SAFETY MTG_ PR1 EVL Arrive KGF and sign in. Obtain work permit and hold PJSM. 09:30 - 10:00 0.50 RURD_ ELEC PR1 EVL RU tool string into lubricator and MU lubricator to well and pressure test same. 10:00 - 12:45 2.75 LOG_ CSG_ PR1 EVL Open well and obtain 10 minute surface stop P/T. RIH and obtain 5 minute P/T stop data at 7260'(10 min), 6950', 6790', 6650', 6480', 6340', 6260', 6075', 5870', 5780', 5670', and 5560'. POOH 12:45 - 13:30 0.75 RURD_ ELEC PR1 EVL Isolate Lubricator. BD same. RD lubricator and tool string. RD truck 13:30 - 14:00 0.50 RURD_ ELEC PR1 EVL Leave location, Turn in permit and sign out. Printed: 8/11/2006 2:31:25 PM 1 7CD .00- oCS KBU 24 -6RD Marathon Oil Permit #: 206 -013 Pad 14 -6 Alaska Production LLC . API #: 50 -133- 20499 -01 -00 316' FSL, 1,255' FWL, Sec. 6, Prop. Des: A- 028142 KB elevation: 87' (21' AGL) T4N, R11 W, S.M. Conductor Latitude: 60 27' 37.172" N - .__...___. 20" K - 55 133 ppf Longitude: 151° 15' 43.822" W r ___. Top Bottom Spud: 2/21/2006 MD 0' 107' TD: 3/2/2006 TVD 0' 10T Rig Released: 3/12/06 @ 12:00 hrs Surface Casing 13 -3/8" K -55 68 ppf BTC Top Bottom L MD 0' 1,518' TVD 1,518' Top of Cement 17 -112 °' hole Cmt w/ 608 sks, Class G @ 3,630' MD AMMO JUN 1 21"L * 122' above top of window opening * 1,859' above 9 -5/8" casing shoe Intermediate Casing 9 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,489' Production Casing TVD 0' 5,299' 3 -1/2" L -80 9.3 ppf EUE Sidetrack window milled from Top Bottom 8rd 3,752' MD - 3,768' MD, MD 0' 7,812' _ 12 -1/4" hole Cmt wl 1,005 sks of Clas G TVD 0' 7,608' 8 -1/2" hole Cmt w/ 267 sks (102 bbls) of 12.7 ppg Class G Lead & 878 sks (181 bbls) of 15.8 ppg Tail Excape System Details: - 13 Conventional Modules - Mod. 1- no flapper - Ceramic flapper valves below each module as follows: ,� Flappers MD (RKB): Module 13 - 5,539' // Module 12 - 5,589' Module 11 - 5,765' Module 10 - 5,807' Excape System Details Max Inc 20,9 Module 9 - 5,948' - 13 Excape modules placed de Di . Module 8 - 6,219' - Red control line fired modules 8 thru 13 tt Module 7 - 6,327' - control lines fired modules 2 thru 7 Di t Module 6 6,379' - Green control line fired module 1 Di t Module 5 - 6,591' - Ceramic flapper valves below each module Ili Module 4 - 6,719' except for module 1 D Module 3 - 6,879° Perfs Perfs r Module 2 - 7,047' Modules MD TVD Zones 11 t Module 1 - NA 13 5,520'- 5,530' 5,328' - 5,338' (Beluga) flq 12 5,570' - 5,580' 5,377'- 5,386' (Beluga) . 11 5,746' - 5,756' 5,547' - 5,557' (Beluga) D) Cap3 / 8ry String 10 5,788' - 5,798' 5,588' - 5,598' (Beluga) DI I 318" 2205 Stainless Steel 9 5,929'- 5,939' 5,727' -5,737 (Beluga) D > ` Top Bottom 8 6,200'- 6,210' 5,996'- 6,006' (Beluga) i MD Surf 7,030' 7 6,308'- 6,318° 6,104'- 6,114' (Beluga) 1 I li L / TVD Surf 6,826' 6 6,360'- 6,370' 6,156' - 6,166' (Beluga) Di . (installed 8 /11/2009) 5 6,572'- 6,582' 6,368'- 6,378' (Beluga) (adjusted 11/24/2009) 4 6,700'- 6,710' 6,496' - 6,506' (Beluga) D! ( 9/9/2010) 3 6,860'- 6,870' 6,656'- 6,666' (Beluga) 2 7,028' - 7,038' 6,824'- 6,834' (Beluga) ` 1 7,466'- 7,476' 6,997'-7,007' (Tyonek) - Nt Tagged @ 7,405' (11/25/09) with 3/8" Dynacoil TD PBTD I BHA= 1.25" FCV & 2.25" centralizers 7,830' MD 7,774' MD 7,626' TVD 7,570' TVD Well Name & Number: Kenai Beluga Unit 24 -6RD Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska 1 Country: USA Perforations MD : 5 520' - 7 476' Pelf TVD : 5 329' - 7 007' Angle A KOP & Depth: 20.3° @ 3,752' MD (window) Angle @ Perfs: 15.5 ° - > 2.5° Date Completed: 7/14/2009 Ground Level: 66' (AMSL) 1 RKB:I 21' (AGL) Revised by: Kevin Skiba Revision Date: 8 - - 2011 • • James Thompson FAX (907) 27&7542 Sr. Completions Engineer Marathon Oil Company ` PO Box 196168 ~~ Anchorage, AK 99519-6168 Re: Kenai Gas Field, Beluga/ Upper Tyonek Oil Pool, Kenai Beluga Unit 24-6RD Sundry Number: 306-122 Dear Mr. Thompson: 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). 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 rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DATED this~~ day of March, 2006 Encl. • t~ Marathon MARATHON Oil Company March 29, 2006 R/ L 3~j° o-ri 330 ~ (~ 0 ~ D ~ Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 ~EIV~ Winton Aubert MAR 3 Q 2006 Alaska Oil & Gas Conservation Commission 333 West 7t" Ave, Suite 100 ~,lssk~ Oil & Gas Cons. Commission Anchorage, AK 99501 Anchorage Reference: Application for Sundry Report 10-403 for permit 206-013 Field: Kenai Gas Field /Beluga & Tyonek Well: KBU 24-6RD Dear Mr. Aubert, Enclosed please find an Application for Sundry Approvals form 10-403 for Kenai Gas Field well KBU 24-6RD and associated attachments. This well has been completed cased hole with a 3.5" Excape monobore production string to surface. Request for approval is being made to perforate, fracture stimulate the 13 Excape modules placed in the well, and vent gas during the initial post fracture treatment fowback period. ~ Should you require further information, I can be reached at 713-232-9347 / 713-296- 2730, or by a-mail at JRThompson@MarathonOil.com. Sincerely, ~[r- ~J James R. Thompson Sr. Completions Engineer Enclosures: AOGCC Form 10-403 Well bore Diagram Proposed Operational Procedure JRT ~`~ 3~3J~~ ~' 3/s o ~ STATE OF ALASKA AL~ OIL AND GAS CONSERVATION COM ION MAR 3 0 2006 APPLICATION FOR SUNDRY APPROVAL~~aska Oil & Gas Cons. Commission 20 AAC 25.280 nnrhnratle 1. Type of Request: Abandon Suspend Operational shutdown Perforate ~ Waiver Other ~ Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate^ Time Extension ^ Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: / MARATHON OIL COMPANY Development ~ Exploratory ^ 206-013 3. Address: Stratigraphic ^ Service ^ 6. API Number: P.O. BOX 196168, ANCHORAGE ,AK 99519-6168 50-133-20499-01 7. KB Elevation (ft): 9. Well Name and Number: 87'KB / 21' AGL KENAI BELUGA UNIT 24-6RD 8. Property Designation: 10. Field/Pools(s): A-028142 KENAI GAS FIELD, BELUGA /UPPER TYONEK POOL 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): 7830 7626 7774 7570 NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 86 20" 86 86 3060 1500 Surface 1518 13 3/8" 1518 1518 3450 1950 Intermediate 3752 9 5/8" 3752 3690 5750 3090 Production 7812 31/2" 7812 7608 10160 10530 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): Thirteen int. 5520'-7476'. Thirteen int. 5328'-7272'. N/A N/A N/A Packers and SSSV Type: N/A Packers and SSSV MD (ft): N/A 12. Attachments: Description Summary of Proposal 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ^ Exploratory ^ Development ^~ Service ^ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: /7/ O6 Oil ^ Gas ^~ Plugged ^ Abandoned ^ 16. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name James R. Thompson Title Sr. Completions Engineer Signature Phone 713-232-9347 Date 3/29/2006 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~ ~ - ~ ~--- Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: Subsequent Form Required: ~ (7 ~ ¢~ /~/ ' APPROVED BY ~ / ~ ~ Approved by: j/ / ~ COMMISSIONER THE COMMISSION Date: C./ ~/ ~ ~,/ ~-~ Form 10-403 Revised 07/2005 ;. 2046 tea,. Submit in uplicate Request for Approval to Vent Gas KBU 24-6RD Fracture Stimulation KBU 24-6RD was drilled and cased as a 3.5" Monobore Excape completion containing thirteen Excape perforating modules. Each module will complete a different production interval with ten feet of perforations followed by individual fracture stimulations in each interval. Due to the nature of fracture stimulations, large amounts of water will be injected, along with the fracture proppant, that will have to be unloaded and cleaned up during the post fracture flowback period. This unloading, or cleaning up period, requires the well to be vented to atmosphere until enough gas volume is achieved to flow the well into the low pressure sales gas system. The duration of this venting operation can last as little as a few minutes up to 24 hours based upon reservoir pressures, permeability, and fracture placement success. For Marathon's gas well operations in the Kenai Gas Field, typical vent times are less than nine hours. Due to the uncertainty of exactly how long KBU 24-6RD will be required to vent to atmosphere, this request is for a maximum vent period of 24 hours with a maximum vent volume during that period of 2 MMCF of methane gas. This volume is minimized due to the utilization of the Excape completion process which enables all intervals of interest to be fracture treated on the same day and 3~3~~~ unloaded together one time, instead of multiple frac days with multiple flowback periods each requiring the venting of gas. If you have any questions regarding this gas venting request, please get in touch with the contact person indicated on the Form 403. I: 50-133-20499-01 -GL: 21.00' -THF: 21.70' 3' FSL, 1255' FWL, Sec. 6, N, R11W, S.M. ae cxn = 4-3/4" Otis TOC (est.) - 500' above 9-5/8" shoe Ceramic flapper valves below ach module as follows: ule 1 - NA ule 2 - 7053' ule 3 - 6885' ule 4 - 6726' ule 5 - 6597' ule 6 - 6385' ule 7 - 6333' ule 8 - 6225' ule 9 - 5954' ule 10 - 5813' ule 11 - 5771' ule 12 - 5595' ule 13 - 5545' KBU 24-6RD ~ M ~ Mww-TMOw Drive Pipe: 20", 133 ppf, K-55 to 86 ' Surface Casing: 13-3l8", 68 ppf, K-55, BTC @ 1518' Cmt w/ 608 sx of class G Intermediate Casing: 9-5/8", 40 ppf, L-80, BTC @ 3752" Cmt original well w/ 1005 sx of class G. Milled Sidetrack window f/3752- 3768' MD Prod. Casing: 3-1/2", 9.3 ppf, L-80, EUE 8rd ~ with 6.25" OD control line protectors to 7812' Cmt w/ 267 sx of class G Lead at 12.7 ppg. Tailed with 878 sx calss G at 15.8 ppg 13 Excape modules placed / Green control line fired module 1 Yellow control lines fired modules 2 thru 7 Red control line fired modules 8 thru 13 Ceramic flapper valves below each module xcept for module 1 Module 1 - 7466-7476' (Tyonek) Module 2 - 7028-7038' (Beluga) Module 3 - 6860-6870' (Beluga) Module 4 - 6700-6710' (Beluga) Module 5 - 6572-6582' (Beluga) Module 6 - 6360-6370' (Beluga) Module 7 - 6308-6318' (Beluga) Module 8 - 6200-6210' (Beluga) Module 9 - 5929-5939' (Beluga) Module 10 - 5788-5798' (Beluga) Module 11 - 5746-5756' (Beluga) Module 12 - 5570-5580' (Beluga) Module 13 - 5520-5530' (Beluga) Well Name 8 Number: KBU 24-6RD Lease: Kenai Gas Field County or Parish: Kenai State/Prov. Alaska Country: USA Perforations (MD) See Above (ND) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completion Fluid: 6% KCL Dated Completed: 4/7/2006 Prepared By: J. R. Thompson Last Revison Date: 3/29/2006 TD - 7830' PBTD - 7774' • • KBU 24-6RD Post Rig Completion Procedure DD.05.13230.CAP.CMP.02 Objective Fracture stimulate 13 Excape modules in the KBU 24-6RD well. Perform post frac ~ Excape flapper and frac proppant cleanout with CTU to PBTD. Jet well in with Nitrogen via CT. Flow test well during post frac clean up. Procedure 1. Post rig demob - Vetco to install SSV actuator, grating level pressure gauges for 9-5/8"x3-1/2" and 13-3/8"x9-5/8" annulus monitoring, and will pull BPV. 2. CBL will be set up and run by Kenai production engineer responsible for well. Send copies of CBL to well files and Houston completion engineer. 3. Hold pre-frac pad meeting between BJ Services, PWS well testers, and MOC representatives at least two weeks prior to frac date. All will agree on frac equipment layout and timing of equipment mob and rig up. 4. MIRU frac eauipment. Equipment to consist of predetermined number of frac tanks, sand kings, pump trucks, frac lines, casing pop off relief valve, CTU, Stinger frac head, well test equipment with line heater, separator and flare stack, MOC sand buster, flowback tanks with gas busters, and flowback iron with choke manifold. 5. Perforate Module 1 and confirm exca e s stem ' to ~`i On day before frac date, RU Expro control line pump and pressure test to ,00 psig. Open up green line surface isolation valve and pressure up green cont line to predetermined pressure as indicated on the excape control line pinning sheet. Monitor firing of module 1 with Expro wellhead monitoring equipment. Confirm perforating of module 1 at 7466-7476' MD. 6. Pressure test all frac equipment and lines. On day before scheduled frac date, pressure test frac trucks and frac lines to 9500 psig ensuring all personnel are in safe locations prior to testing. Pressure test CT, flowback iron, and well tester lines to 4500 psig, also ensuring all personnel are in safe locations prior to testing. 7. Perform fracture stimulation treatments: Perforate each Excape module prior to each treatment by pressuring up on the appropriate excape control line to within the firing pressure range as shown on the excape pinning sheet. Fracture treatment pumping schedules are contained in powerpoint file containing GOHFER output. Frac volumes will be RA traced with two isotopes (one in pad volumes and another in all sand stages), and with chemical production tracers. • • 8. RD frac treating equipment. 9. RU CTU. Install CTU with 3-1/16", lOK BOP (dressed for 1-3/4" CT), and flow cross to top flange of Stinger frac head. ADD FRW-14 TREATMENT FLUID to 6% KCL at 1 GAL/1000 GAL. 10. Pig 1-3/4" CT. 11. Pickup infector and add wash nozzle. Nipple up infector to BOP. Toolstring will consist of 1-3/4" (WT = 0.125") dimple-on connector, 1-3/4" Double Flapper Check Valve, 1-3/4" BOSS and 2-5/8" Hammer Nozzle (Version #1). ..., 12. Function and pressure test BOP and Injector head WHA (2Q6%45~ ipsi). 13. RIH pumping fluid @ minimum rate per CIRCA runs to remove wellbore fluids (broken frac fluid). Continue RIH @ 60 - 70 ft/min monitoring surface returns for 1 to 1. (3-1/2", 9.3 ppf tubing capacity = 0.0087 bbl/ft) Increase fluid rate to 2.50 BPM @ 5450'. Maintain personnel on choke manifold to ensure that gas cut fluid returns do not exceed gas buster capacity and create spillage via misting out gas buster. r'f 14. RIH to Module 13 (+/-5500'). Pull Test CT and record pick up weight before entering Module 7. 15. RIH (a7 40-50 ft/min and break Module 13 ceramic flanner (a~ 5545'. If ceramic flapper does not break on initial attempt pickup CT 25' - 40' and TIH and set down/ harder. 2000 - 3000 lb. set downs are common to break the difficult flappers. If unable to locate flapper, work CT across flapper depth several times utilizing varying pump rates, etc. to try and locate flapper. 16. Continue RIH with CT and repeat STEP 10 for Modules 12-2 flappers located ~ at the following depths. Module 12 - 5595' Module 11 - 5771' Module 10 - 5813' Module 9 - 5954' Module 8 - 6225' Module 7 - 6333' Module 6 - 6385' Module 5 - 6597' Module 4 - 6726' Module 3 - 6885' Module 2 - 7053' 17. RIH to PBTD of 7774' RKB. Once the flapper at the bottom of Module 2 is removed the well bore is open through Module 1 to the PBTD @ 7774' MD. Wash to • • PBTD. Monitor returns for 1:1. If returns fall below 1:1 introduce N2 to treating fluids while reducing fluid rates. Circa model indicates that +/-350 SCFM of N2 will produce full returns with fluid rate at 1.75 BPM. Pull test and make swab trips as appropriate while breaking flappers and cleaning out wellbore sand and fluids. 18. Circulate bottoms up 2X. 19. Start pumping Nitrogen and POOH circulating to above Module 13 at +/- 5500'. Reduce fluid rate to 1-1.5 bpm and start N2 pump @ 500 SCFM. Pump N2 with fluid to displace CT. With N2 @ end of CT shut down fluid pumps. Jet with N2 until well can carry fluids. Adjust rate as necessary to assist BHP. 20. RIH as necessary to start well lifting on its own. May be desirable to jet from below perfs to just above top perforations. Jet well in as directed by onsite Marathon supervisor adjusting N2 rate as necessary. 21. With well flowing on own POOH to surface. Isolate CT from flow stream and RDMO CTU. Turn well over to well testers. Test well per production engineers direction. JRT/PR 3/29/2006 ~~~ ~LASSA OIL A11TD GAS COI~TSERQATIOIK CO1rIIrIISSI011T Willard Tank Advanced Senior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, TX ,~ FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kenai, KBU 24-6RD Marathon Oil Company Permit No: 206-013 Surface Location: 316' FSL, 1,255' FWL, Sec. 6, T4N, Rl 1W, S.M. Bottomhole Location: 1,209' FSL, 1,724' FWL, Sec. 6, T4N, R11W, S.M. Dear Mr. Tank: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). Sincerely, ./" ~1 / r - Daniel T. Seamount Commissioner DATED this ~~ day of January, 2006 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. • • M Marathon MARATHON Oil Company January 24, 2006 John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application - Re-drill KBU 24-6 Permit No: 200-188 Field: Kenai Gas Field Well: KBU 24-6RD Dear Mr. Norman Worldwide Drilling North America P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713-499-6737 Enclosed please find the PERMIT TO DRILL application, along with the associated attachments and filing fee of $100. The intent is tosidetrack-e~a#-ofithe existing well KBU 24- 6 and re-establish a viable EXCAPE completion in the Beluga /Upper Tyonek Pool in the Kenai Gas Field. No completion is desired in the Sterling pool. Please note that surface location differs slightly from the original PERMIT TO DRILL application submitted in October, 2000. Our records do not indicate that the well was re- surveyed after that application. We received the re-surveyed coordinates after the Sundry Notice was sent on January 12, 2006. If you require further information, I can be reached at 713-296-3273 or by a-mail at wjtankG marathonoil.com. Sincerely, ~~~~~ ~~~ Willard J. Tank Advanced Senior Drilling Engineer Enclosures tatGh-- t~~~ G 1~Q STATE OF ALASKA ALA.. OIL AND GAS CONSERVATION COMION PERMIT TO DRILL 20 AAC 25.005 ,I ~ N 2 5 2006 Alaska O+i & Gas Cons. Clxrrnisslon 1a. Type of Work: Drill Redrill ~ Re-entry ~ 1b. Current Well Class: Exploratory Development Oil ~ Stratigraphic Test ~ Service ~ Development Gas Q Single Zone 2. Operator Name: Marathon Oil Company 5. Bond: Blanket ~ Single Well Bond No. 5194234 11. Well Name and Number: KBU 24-6RD ~'2o/oG 3. Address: P.O. Box 3128, Houston, TX 77253 6. Proposed Depth: MD: 7,819 TVD: 7,587 12. Field/Pool(s): Kenai Gas Field 4a. Location of Well (Governmental Section): Surface: 316' FSL, 1,255' FWL, Sec. 6, T4N, R11W, S.M. ~ 7. Property Designation: A-028142 Beluga /Upper Tyonek Pool Top of Productive Horizon: 1,039' FSL, 1,765' FWL, Sec. 6, T4N, R11W, S.M. 8. Land Use Permit: 13. Approxima pud Date: Februa 15 006 Total Depth: 1,209' FSL, 1,724' FWL, Sec. 6, T4N, R11W, S.M. ~ 9. Acres in Property: 2,560 14. Distance o Nearest Property: 1,698 ft 4b. Location of Well (State Base Plane Coordinates): Surface: x - 272,174.29 y - 2,362,360.67 Zone - 4 10. KB Elevation (Height above GL): (21' AGL) 87 .feet 15. Distance to Nearest Well Within Pool: i,ssa ft. to KBU 33-6X 16. Deviated wells: Kickoff depth: 3,900 feet Maximum Hole Angle: 23.61 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 3,551 Surface: 2,792 ~ 18. Casing Program: Size Specifications Setting Depth Top Bottom Quantity of Cement c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 8 1/2" 3 1/2" 9.3 L-80 EUE 7,798' 0' 0' 7,819' i 7.,587' 915 sacks 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry O perations) Total Depth MD (ft): 7,500 Total Depth TVD (ft): 7,275 Plugs (measured): Effect. Depth MD (ft): 7,441 Effect. Depth TVD (ft): 7,216 Junk (measured): Casing Length Size Cement Volume MD TVD Structural Conductor 86' 20" Driven 106' 106' Surface 1,497' 133/8" 608 sacks 1,518' 1,518' Intermediate 5,468' 9 5/8" 1,005 sacks 5,489' 5,295' Production 7,420' 3 1/2" 1,082 sacks 7,441' 7,216' Liner Perforation Depth MD (ft): 5,517' - 7,302' Perforation Depth TVD (ft): 5,321' - 7,078' 20. Attachments: Filing Fee ~ BOP Sketch ~ Drilling Program ~ Time v. Depth Plot Shallow Hazard Analysis Property Plat Q Diverter Sketch Q Seabed Report ~ Drilling Fluid Program Q 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Willard J. Tank i Title Advanced Senior Drilling Engineer Signature \ Phone 713-296-3273 Date January 24, 2006 Commission Use Only Permit to Drill Number: „~06 _ ~j 3 API Number: 50- j3 3 ~ Z Q -O f Permit Approval Date: .- See cover letter for other requirements. Conditions of approval Samples required Yes ~ No ~ Mud log required Yes ~ No Hydrogen sulfide measures Yes ~ No ~ Directional survey required Yes ~] No Other: "~.~5't" ~j(J ~~ [ ~ p ~ 0d O ~0 ~` , APPROVED BY Approved by: ~ THE COMMISSION Date: ~ 27 Form 10-401 Revised 06/2004 ~ ~ ~ A Submit inDuplicate ~ • MARATHON MARATHON OIL COMPANY DRILLING PROGRAM Kenai Gas Field KBU 24-6RD Original 1 /24/06 Originator: W.J. Tank Drilling Superintendent: P.K. Berea North America Drilling Manager: B.J. Roy Page 1 of 13 • • Table of Contents General Well Data ...................................................................................................................................................................3 Geologic Program Summary ................................................................................................................................................. ..3 Summary of Potential Drilling Hazards .................................................................................................................................. ..4 Formation Evaluation Summary ............................................................................................................................................ ..4 Drilling Program Summary .................................................................................................................................................... ..5 Casing Program ..................................................................................................................................................................... ..6 Casing Design ....................................................................................................................................................................... ..6 Maximum Anticipated Surface Pressure ............................................................................................................................... ..6 BOPE Program ...................................................................................................................................................................... ..8 Wellhead Equipment Summary ............................................................................................................................................ ..9 Directional Program Summary .............................................................................................................................................. ..9 Directional Surveying Summary ............................................................................................................................................ 10 Drilling Fluid Program Summary ........................................................................................................................................... 10 Drilling Fluid Specifications .................................................................................................................................................... 11 Solids Control Equipment ...................................................................................................................................................... 11 Cement Program Summary ................................................................................................................................................... 12 Bit Summary .......................................................................................................................................................................... 12 Hydraulics Summary ............................................................................................................................................................. 12 Formation Integrity Test Procedure ....................................................................................................................................... 13 Page 2 of 13 • ~ General Well Data Weli Name KBU 24-6RD Lease/License Surface Location 316' FSL, 1,255' FW L, Sec. 6, T4N, R11W, S.M. WBS Code DD.05.13232.CAP.DRL SIoUPad Pad 14-6 Field Kenai Gas Field Spud Date 1 5/16 (est.) KB Elev. 87 County/Province Kenai Peninsula API No. Ground Level Elev. 66 State /Country Alaska Well Class Development Perm. Datum KB Total MD 7,819' Rig Contractor Glacier Drilling Water Depth N/A Total TVD 7,587 Rig Name #1 Water Protection Depth Comments: Geologic Program Summary Formation MD -RKB (ft) TVD -RKB (ft) Pore Pressure (psi) Pore Pressure (ppg) Lithology Possible Fluid Content Sterling A-8 (Not a Prod Target) 3,571 3,497 0.8 - 6.5 Sandstone Gas /Water Sterling A-9 (Not a Prod Target) 3,618 3,541 0.8 - 6.5 Sandstone Gas /Water Sterling A-10 (Not a Prod Target) 3,654 3,575 0.8 - 6.5 Sandstone Gas /Water Sterling A-11 (Not a Prod Target) 3,741 3,656 0.8 - 6.5 Sandstone Gas /Water Sterling B-1 (Not a Prod Target) 3,802 3,713 0.8 - 6.5 Sandstone Gas /Water Sterling B-2 (Not a Prod Target) 3,866 3,773 0.8 - 6.5 Sandstone Gas /Water Sterling B-3 (Not a Prod Target) 3,942 3,845 0.8 - 6.5 Sandstone Gas /Water Sterling B-4 (Not a Prod Target) 4,047 3,945 0.8 - 6.5 Sandstone Gas /Water Sterling B-5 (Not a Prod Target) 4,214 4,105 0.8 - 6.5 Sandstone Gas /Water Sterling C-1 (Not a Prod Target) 4,525 4,395 0.8 - 6.5 Sandstone Gas /Water Sterling C-2 (Not a Prod Target) 4,707 4,561 0.8 - 6.5 Sandstone Gas /Water Beluga (Not a Prod Target) 4,798 4,645 1.5 - 7.3 Sandstone Gas Middle Beluga (Primary Target) 5,524 5,312 3.8 - 8.8, Sandstone Gas Lower Beluga (Primary Target) 6,284 6,052 5. =~9.0 Sandstone Gas Tyonek (Primary Target) 7,439 7,207 5. - 9. Sandstone Gas Comments: Surface Location Coordinates From Lease/Block Lines 316' FSL, 1,255' FWL, Sec. 6, T4N, R11W, S.M. Latitude. 60° 27' 37.172" N Longitude 151 ° 15' 43.822" W UTM North (Y) 2,362,360.670' UTM East (x) 272,174.290' Tolerance Page 3 of 13 ~ • Horizontal Depth Dis lacemenf (ft) MD ND +N/-S +E/-W Tolerance Directional Target (ft) (ft) Location (Y) (X) (ft) Middle Beluga 5,524 5,312 1,039' FSL, 1,765' FWL, Sec. 6, T4N, R11W, S.M. 723 510 Circle 150' radius TD 7,819 7,587 1,209' FSL, 1,724' FWL, Sec. 6, T4N, R11W, S.M. 893 469 Circle 150' radius Comments: Summarv of Potential Drilling Hazards Hazard Event Discussion Lost Circulation in Low Pressure Sterling and Belu a sands Control losses by using sufficiently sized calcium carbonate type LCM. Comments: Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC or BLM inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No H2S is anticipated. ~ Gas sands will be encountered from +/- 3,900 MD (3,805' TVD) to total depth of the well. These sands will run from highly depleted to slightly above normal pressure. Lost circulation and differential sticking are potential hazards in some of the Sterling and Beluga sands. The Flo-Pro mud system that will be used to drill the well will help reduce these risks and lost circulation materials will be on location. Weighting material will available on location for proper well control.. Formation Evaluation Summarv Interval LWO Electric Logs Mud Logs Surface /Intermediate None None None (Existing) Sidetrack Production None Reeves Quad Combo with pressures Basic with GCA, shale density, temperature in and out, 3,900' - 7,819' MD through pipe. Pull GR-Neutron to tie into sample collection (10' samples). Intermediate run. Completion N/A GR, CCL N/A Coring Requirements: None Comments: Page 4 of 13 • • Drilling Program Summary WELLBORE PREPARTION: (Note see abandonment sundry procedure for more detail) 1. RU electric line unit. RIH and set bridge plug in 3 1/2" casing at 5,500' MD. Confirm plug is set. 2. RU and dump bail approximately 35' of cement on top of the bridge plug. Confirm cement top. 3. WOC and then test 3 1/2" casing to 2,000 psi. Check 9 5/8" x 3 1/2" annulus for pressure and bleed off if necessary. 4. MIRU drilling rig. ND tree, NU BOP stack and test to 250/2,000 psi (note that there is no place for a BPV in the head, only the tree). 5. ND BOP and suspend above the head. Spear 3 1/2" casing and pick up to pull slips. Set casing down and remove spear. 6. PU overshot and latch onto 3 1/2" casing. NU BOP stack. 7. RU wireline and run free point to confirm where casing is free (anticipated at 3,925' MD from CBL). POOH with log. 8. Run casing cutter and cut casing. Run a 2"d cutter and cut as close to the 15t cutter as possible (trying to confirm control lines are severed as well as the 3 1/2" casing). 9. POOH with 3 1/2" casing and controls, laying down. Test BOP's and choke manifold to 250/3,000 psi. 10. PU 9 5/8" bridge plug and TIH, setting at approximately 3,918' MD. and RIH with bottom trip whipstock. RU and run MWD to set whipstock for - 45° left of highside tool face orientation. Cut window and ensure that all mills are worked thru window. CBU and perform FIT at KOP to - 13.0 ppg ~ t ~~ l~ - dot r^'Prw~l~(. PRODUCTION: 1. PU 8 1/2" PDC bit and BHA. 2. Drill 8 1/2" hole to approximately 4,500' MD (4,372' TVD) per the directional program, controlling leakoff with sized calcium carbonate only. Stop drilling prior to entering the Sterling Pool 6 sand (final depth determination by Geology). f 3. POOH standing back BHA. TIH open ended drill pipe to 4,500' MD. Mix and spot Formaset AK polymer pill across the open hole section. Pull up above, circulate drill pipe clean, and wait on polymer to set (applying some squeeze pressure if well is not taking fluid). If fluid level drops after spotting polymer, shut in BOP's to prevent total loss of polymer. 4. After waiting on polymer to set (minimum 4 hours, but check surface samples), TOOH. PU directional BHA. TIH to 4,500' MD and wash out polymer. Test squeeze to an EMW of 11 ppg. 5. Drill 8 1/2" hole to approximately 4,900' MD (4,738' TVD) per the directional program, controlling leakoff with sized calcium carbonate only. Stop drilling prior to reaching any potential pay zones, but after drilling the entire Sterling Pool 6 sand (final depth determination by Geology). 6. POOH standing back BHA. TIH open ended drill pipe to 4,900' MD. Mix and spot Formaset AK polymer pill across the open ~ hole section. Pull up above, circulate drill pipe clean, and wait on polymer to set (applying some squeeze pressure if well is not taking fluid). If fluid level drops after spotting polymer, shut in BOP's to prevent total loss of polymer. 7. After waiting on polymer to set (minimum 4 hours, but check surface samples), TOOH. PU directional BHA. TIH to 4,900' MD and wash out polymer. Test squeeze to an EMW of 11 ppg. 8. Drill 8 1/2" hole to approximately 7,819' MD (7,587' TVD) per the directional program, short tripping as necessary (1,000' or 24 ''~ hours, but can be extended depending on hole conditions). 9. At TD circulate hole clean. Make wiper trip. TOOH. 10. RU Precision. Run open hole logs as per plan. RD logging company. 11. TIH w/ 8 1/2" bit to TD for wiper trip. TOOH to 9 5/8" window and circulate until log evaluation is complete for picking EXCAPE modules. After picks are made, trip to TD and circulate clean. TOOH and lay down BHA and drill pipe. Pull wear bushing. 12. RU and run 3 1/2" EXCAPE casing string. RU logging company to correlate EXCAPE modules to open hole logs. RD logging company. 13. Cement 3 1/2" casing. Bump plug with 500 psi over displacement pressure. WOC. ~ /. 14. PU 3 1/2" casing. PU BOP stack. Run control and electric lines out tubing head outlet. Set slips. Cut 3 1/2" casing. 15. LD BOP. Set 3 1/2" packoff. NU 13 5/8" 5M X 3 1/8" 5M tubing head adapter and 3 1!8" 5M tree. Test tree to 5,000 psi. 16. Rig down and move out drilling rig. Note: Drill all hole sections with 5" drillpipe. Perforating guns will be run on the outside of the 3 1/2" production casing with a ~ flapper valve just below each perforating gun. Guns to be activated by control line to surface. COMPLETION: Completion will be done without a rig. Page 5 of 13 • • Casino Program MD (ft) Connection API. Ratings .Casing Size (in) Top Bottom Weight (Ibs/ft) Grade Type O. D. (in) Makeup Torque (ft-Ibs) Hole Size (in) ~ m g- ~ ._ ~ a o ~ ,'xr, 13 3/8 Surface 1,518 68 L-80 BTC 14.375 N/A * 16 5,020 2,260 1,545 9 5/8 Surface 5,489 40 L-80 BTC 10.625 N/A * 12 1/4 5,750 3,090 979 31/2 Surface 7,819 9.3 L-80 8rd 4.5 3,200 81/2 10,160 10,530 207 Comments: * The make up of the buttress connection will be to the proper mark. Casing Design Casing Shoe SafetyFactors Casing Size (in) Weight (Ib/ft) Grade Setting Depth (TVD) Mud Wt When Set (Ib/gal) Frac. Grad (Ib/gal) Form Press (Ib/gal) Maximum Surface Pressure (psi) m ~, a U o 13 3/8 68 L-80 1,518 Existing Casing String 9 5/8 40 L-80 5,295 Existing Casing - WA 2,191 Existing Casing - N/A 31/2 9.3 L-80 7,587 10.0 15.0 9.0 2,792 1.16 2.68 1.30 Comments: The 13 3/8" and 9 5/8" are existing casings. A casing exit will be made in the 9 5/8". Max overpull on the 3 1/2" casing must be limited to 94,900 Ibs. Maximum Anticipated Surface Pressure Casing Size (in) Setting Depth TVD (ft) MAWP' (psi) MASP ** (psi) Mud/Gas .Ratio 133/8 1,518 Not applicable, 9 5/8" Intermediate is already in place. 9 5/8 5,295 3,946 2,191 0/100 31/2 7,587 6,954 2,792 ~ 0/100 * MAWP =Maximum allowable working pressure ** MASP =Maximum anticipated surface pressure Comments: Page 6 of 13 • • MASP /MAWP CALCULATIONS: Intermediate casing: 9 5/8" (3,900' MD, 3,805' TVD) MASPfrac =((Fracture gradient at shoe + S.F.) x .052 x TVDsnoe) -Hydrostatic pressure of gas column at the shoe. MASPfrac = (12.5 ppg + 0.5 ppg) x .052 x 3,805' - (.1 psi/ft x 3,805') MASPfrac = 2,572 psi - 381 psi MASPfrac = 2,191 psi. MASPbnP = BHPcpan nae td -Hydrostatic pressure of a gas column MASPbnP = (9.0 ppg x .052 x 7,587') - (0.1 psi/ft x 7,587') MASPbnP = 3,551 psi - 759 psi MASPbnP = 2,792 psi ~ MASP =MASPfrac = 2,191 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 5,750) - (10.0 - 9.6) x .052 x 3,805' MAWP = 4,025 psi - 79 psi = 3,946 psi Production casing: 3 1/2" (7,819' MD, 7,587' TVD) MASPfrac =((Fracture gradient at shoe + S.F.) x .052 x TVDsnoe) -Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg + 0.5 ppg) x .052 x 7,587' - (.1 psi/ft x 7,587') MASPfrac = 6,115 psi - 759 psi MASPfrac = 5,356 psi. MASPbnP = BHP~r,no~atd -Hydrostatic pressure of a gas column MASPbnP = (9.0 ppg x .052 x 7,587') - (0.1 psi/ft x 7,587') MASPbnP = 3,551 psi - 759 psi MASPbnP = 2,792 psi MASP =MASPbnP = 2,792 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAW P = (0.7 x 10,160) - (10.0 - 9.6) x .052 x 7,587' MAW P = 7,112 psi -158 psi = 6,954 psi Page 7 of 13 • • BOPE Program Casing Test Test Casing Test Fluid Pressure Size MAWP MASP press Density BOPS Low/High. Casing (in) (psi) (Psi) (Psi) (Ib/gaq Size & Rating (psi) (1) 13-5/8" 5M annular I (1) 13-5/8" 5M pipe ram '- Intermediate 9 5/8 3,946 2,191 3,000 9.5 (1) 13 5/8" 5M blind ram ? 250/3,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular ~ (1) 13-5/8" 5M pipe ram Z Production 3 1/2 6,954 2,792 3,000 10.0 (1) 13 5/8" 5M blind ram S 250/3,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets Comments: Blowout Preventers The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-1/8" x 5000 psi outlets. The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also /- included is a poor-boy gas buster, and avacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. Casing Test Pressures Casing test pressures are based on the lesser of (1) MASP, or (2) 70% of rated burst pressure of the casing adjusted for the mud weight used during the test less a 8.3 ppg back-up unless otherwise noted. Page 8 of 13 • • Wellhead Equipment Summarv Component Description Casing Hangar Type Casing Head 13-5/8" 3M X 13-3/8" Slip Loc W/ 2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL1, 13 5/8" x 9 5/8" Fluted PR1 Mandrel Tubing Head 13-5/8" 3M Studded Bottom X 13-5/8" 5M Flg Top, W/ 2, 2-1/16" 5M Studded Outlets, 13 5/8" x 3 1/2" Manual U,AA,PSLI,PR1 Slip Adapter Flange 13-5/8" 5M X 3-1/8" 5M W! Seal Pocket and 3" H BPV Threads - - Comments: Control lines and electric cable for the EXCAPE system will be routed through the tubing head side outlet. Directional Program Summarv Build Turn Coordinates Sea No. Description MD (ft) TVD (ft) Rate {°/100') Rate (°/100') Dogleg (°/100') .Inclination (deg) Azimuth (deg) +N/-S (ft) +E/-W (ft) VS (ft) 1 Tie On 3,900 3,805.28 0 0 0 20.50 75.16 169.37 551.21 34.20 2 KOP 3,900 3,805.28 0 0 0 20.50 75.16 169.37 551.21 34.20 3 Build/Turn Section 3.37 -14.62 6.00 75.16 4 End of Build/Turn 4,409.36 4,288.71 3.37 -14.62 6.00 23.61 346.32 294.30 614.83 140.55 5 Hold Section 0 0 0 23.61 346.32 6 End of Hold 5,348.71 5,149.42 0 0 0 23.61 346.32 659.86 525.86 516.77 7 Drop Section -2.00 0 2.00 346.31 8 End of Drop 6,529.23 6,296.82 -2.00 0 2.00 0.00 346.31 892.86 469.13 756.59 9 TD 7,819.42 7,587.00 0 0 0 0.00 346.31 892.86 469.13 756.59 Comments:. Vertical section calculated from a reference azimuth of 346.32° taken from surface location to bottom hole location. Potential Well Interference: Well Distance (ft) Depth (MD) KDU 1 389.93 7,819 KU 21-7 576.36 3,900 KU 14X-6 658.90 3,900 KU 31-7 759.04 3,900 No serious interference exists. See attached directional plan and anticollision analysis for more details. Page 9 of 13 ~ ~ o 1000 ---~-- ~~ - ~ I ~ _ -- - -- I~ ~ C 133/8 "--- 1 i 1000 KBU 24~6RD Middle Beluga _~- 2000 I ' , Y 3000 I I I i _ _ . - .-. I ~ f ' ~ N I '. 9 5/8" - - '. ~ ~ ~ KBU 24$RD TD 4 -; - .~ KBU 24-6RD 000 a m ,._.__ ' ~ ± 500 ~ - O ~ ~ KBU 248RD Middle Beluga C i v 5000 II - - --- - - - -- , . Z '~ ' ~ ~ ~ , r ~_ ' L ' 2 6000 _ _--. _ -- _ ~ __ - - ' ~ , \ H I I KBU 24 6 0 _ _ __ -- - - -- - -. _. . ---- - 1 7000 it j ~ ~ KBU 24~RD TD ~~ 31/2"---, , -- __, 8000 3000 •2000 -1000 0 1000 2000 3000 4000 0 500 1000 1500 Vertical Section at 27.72° (2500 ft/in) West(-)/Fast(+) (500 ft/in) Directional Surveyinp Summary Interval MWD Survey Magnetic Multishot Gyro Multishot Comments Use existing MWD surveys, set whipstock with 0 - 3,900' MWD tool. 3,900' - 7,819' X Comments: Drilling Fluid Program Summary Interval-TVD Minimum Inventory From To Density Gel (ft) (ft) (Ib/gal) Fluid Description Additives Viscosifier Barite 0 3,805 8.45 Milling Fluid Flo-Vis, Sodium Meta Bisulfate Flo-Vis, PolyPac Supreme UL, KCI, SafeCarb 3,805 7,587 9.0 10.0 6% Flo-Pro w/ Safecarb F&M, Barite, Caustic, Klagard, Conqor 404, Sodium Meta Bisulfate Comments: See mud prognosis for details and for specific information on the Formaset AK polymer plugs. Sized CaCO3 (SafeCarb) will be used to control leakoff. Page 10 of 13 Drillina Fluid Specifications • Interval - TVD LSRV From (ft) To (ft) Density (Ib/gal) Vis (sec/gt) 1 min (Ib./100ft2) PV (cP) YP (Ib/100 ft2) Fluid Loss (cc} pH Dri11 Solids (%) 0 3,805 8.45 30,000 + 12 - 18 N/A +/- 9.5 3,805 7,587 9.0 - 10.0 30,000 + 12 - 18 < 8 +/- 9.5 < 5 Comments: As a standard practice for long string completions, the drilling mud that will remain above the top of cement on the 3 ~/z" production casing will be treated with corrosion inhibitor (Congor 303A) at a concentration of 1 drum per 100 barrels of drilling fluid. See mud prognosis for details. Solids Control Equipment 0 ~ m m ® ~ ~ d p ~ Y ~ ~ ~ N ~ ~ ~ fA ~ N ~ ~ L N N ~ N > > ~ Interval. ~ ~ o ~ U U U N Comments 0 - 7,819' MD X X X X Closed Loop System, Full Containment Item Equipment Specifications (quantity, design type, brand, model, flow capacity, .etc) Shaker 2 -Derrick Model 2E48-90F-3TA Desander N/A Desilter 1 -Derrick Model 0522 Mud Cleaner N/A Centrifuge 2 - MI/Swaco units Cuttings Dryer N/A Cuttings Injection Marathon G&I Facility / Zero Discharge N/A Comments: The solids control equipment will consist of two flowline cleaners, a desilter, and the MI centrifuge van. Included will be equipment to de-water the underflow from the mud processing equipment to allow for disposal of the cuttings and solids by slurrification and injection into the disposal well at the KGF. Page 11 of 13 • Cement Program Summary • De pth Gauge Top of Cement Open Casing Hole Ann Vol Slurry WOC Hole Size MD TVD Size MD TVD To TOC Val Time Excess (in) (ft) (ft) (in) (ft) (ft3) (ft3) (hrs) ' (%) 31/2 7,819 7,587 81/2 ,40 3,337 1,462 1,976 N/A 40 i' Mix Water Compressive Casing Size Density Qty Yield Slurry Vol TOC MD Qty WL FW Strength (si) (in) Slurry Cement Description (Ib/gaq (s (ft3/sx) (ft3) (ft) (gaVsx) Type (cc) (%°) 12'hr 48 hr 3 1/2 Tail Class "G" 12.7 915 2.16 1,976 3,400 11.73 Fresh 24 0 500 1,142 Comments: See cement prognosis for details and spacer specifications. Bit Summarv .Interval - MD TYPe Recommended Estimated From (ft) To (ft) Size (in) Manufacturer Model No. IADC WOB (kips) RPM Rotating Hours ROP (ft/hr) 3,900 7,819 8 1/2 Christensen HCM605Z M323 Up to 25 Motor Comments: Back up bits for the 8'/z" hole section will consist of mill tooth and TCI tricone bits. See bit prognosis for additional information. Hydraulics Summarv Rig mud pumps available are shown below. Max Press ~ Displacement ~ Liner ID Stroke 90% WP 95% eff Max. Rate -Hole Sections Used Qry Make Model (in) (in) (psi) (gaUstroke) (spm/gpm} On 5 8 2,597 2.04 125 / 255 Surface 3 National Oil Well A600PT 5 8 2,597 2.04 125 / 255 Intermediate 5 8 2,597 2.04 125 / 255 Production Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. Page 12 of 13 • • Hole Standpipe Min Nozzle Depth-MD Size Pump Rate Pressure AV ECD Size (ft) (in) (gpm) (psi) (fpm) (Ib/gal) (32"s) Remarks 0 - 3,900 8 1/2 Abandonment Section -Pump rates will vary based on activity. 5,489 - 7,819 8 1/2 477 1,400 247 5 - 15's Actual Data from KBU 11-8X (~ 7,659' MD) Comments: See separate hydraulics calculations. Annular velocity in the 8'/z" hole was calculated using 5" drillpipe. 5" drillpipe should be used to drill all hole sections to maximize hole cleaning, while minimizing stand pipe pressure. Formation Intearitv Test Procedure Surface and Intermediate casing shoes will be tested to Leak-off. Prior to drilling out of casing strings, test BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak-off tests (LOT) are to be conducted as described below: Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. Pull drill string into the casing shoe and close ram preventer, and line up to the choke manifold with a closed choke. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Page 13 of 13 Marathon Oil Well KBU 24-6RD BOP Stack 13 5/8" 5M Cross • To Gas Buster X t 2 9/16" 10M Swaco Hydraulically Operated Choke °°~ I x X X ~ ~ 3" 5M Valves C7 Marathon Oil Well KBU 24-6RD Choke Manifold ~ To Blooey Line Bleed off Line to Shakers X I °°~ X I °°~ X ~, x x 0 °° ~ X X ° X 3 1/8" 5M Manually Adjustable Choke From BOP Stack C Surface Use Plan for Kenai Beluga Unit, well KBU 24-6RD Surface location: 316' FSL, 1,255' FWL, Sec. 6, T4N, R11W, S.M. 1) Existing Roads Existing roads which will be used for access to KBU 24-6RD are shown on the attached map. Kenai, Alaska is the nearest town to the site and is also shown on the map. 2) Access Roads to be Constructed or Reconstructed No new roads will be required to access KBU 24-6RD. 3) Location of existing wells Well KBU 24-6RD will be drilled on Kenai Gas Field (KGF) pad 14-6. A pad drawing is enclosed that shows existing wells and the proposed location of KBU 24-6RD. 4) Location of existing and/or proposed facilities The locations of existing production facilities in the KGF pad 14-6 are shown on the enclosed pad drawing. The existing flowline for KBU 24-6 will be utilized for KBU 24-6RD to connect to the existing line heater and separator. 5) Location of Water Supply A water supply well exists on the pad that KBU 24-6RD will be drilled from. This is shown on the pad drawing. 6) Construction Materials No construction is planned on the pad. The recent pad expansion has already been completed and is sufficient. 7) Methods of handling waste disposal; a) Mud and Cuttings Cuttings will be dewatered on location. The cuttings and excess mud will be hauled to Pad 41-18 of the Kenai Gas Field for disposal into Well KU 24-7, a Class II disposal well (AOGCC Disposal Injection Order No.9, Permit #81-176). b) Garbage All household and approved industrial garbage will be hauled to the Kenai Peninsula Borough Soldotna Landfill. c) Completion Fluids Clear fluids will be hauled to Pad 34-31 of the Kenai Gas field and injected in Well WD #1, an approved disposal well (AOGCC Permit #7-194). d) Chemicals ~ • Unused chemicals will be returned to the vendors that provided them. Efforts will be made to minimize the use of all chemicals. e) Sewage Sewage will be hauled to the Kenai sanitation facility. 8) Ancillary Facilities A minimal camp will be established on the pad to house various supervisory and service company personnel. Approximately four trailer house type structures will be required for this purpose. Bottled water will be used for human consumption. Potable water will be obtained from the existing water well on the pad. S & R will collect and transport sanitary wastes to their ADC approved disposal facility. No additional structures will be necessary. 9) Plans for reclamation of the surface KBU 24-6RD will be drilled from an existing pad. Reclamation of the pad will occur after the abandonment of KBU 24-6RD and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from CIRI Native Corporation prior to any reclamation work beginning. 10) Surface ownership The surface owner of the land in the Kenai Beluga Unit is the Salamatof Native Association. 11) Operator's Representative and Certification I hereby certify that I, or persons under my direct supervision, have inspected the proposed drill site and access route; that I am familiar with the conditions that currently exist; that the statements made in this plan are, to the best of my knowledge, true and correct; and that the work associated with operations proposed herein will be performed by Marathon Oil Company and its contractors and subcontractors in conformity with this plan and the terms and conditions under which it is approved. This statement is subject to the provisions of 18 U.S.C. 1001 for the filing of a false statement. Date: ~ f z I ~V~ Name and Title: ~i Willard J. Tank, A vanced Senior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, TX 77253 (713) 296-3273 J' ~ f I i ~ t„'t ~._ ~ ~~ ~j K.IJ. 1~X-C16 L•1"ATER L"u'E[.I. PRCJDUC;TICSN t`t'ELI. ~" CASING :^dELL i #UUSE r-1 X=272.:752.87 I ._ y.-Z 362,47 t .46 iil r t > K.U. 21-7 N ~ ~ 1G' O SILO ~ ~ x=271,s2ss4 K.U. 23-7 Y=2,362414.05 % 8' ~} SILO 1 X=2'72,Q19.41 ~I r 1255' FWL K.LI. 14-6 r'~~ 10° ~ vv>=~t. ~sc~U.~E ~."'/ X=271,8'76.24 Y=2,36z,306.5fr z PAD ELElIATlON=65.6` M.S.L. J Z O H U ~ ~~ K.U. 43-12 Ll.l ~ ~~.J 1~7.5'C~SELC.) ~ X=271,583.15 Y=2,:352.22x2.53 K.B.U. 23-D6X Pf20DUGTlC)N V11ELL 14 ', 1.lELL HOUSE ~~ X=272,1?2.20 `=~.-.-~ Y=2.362,337.41 K.B.U. 24-6 WELL HOUSE TEt_EPHC)NE. GABLE BOX 'JUITH 5'X5` GUARD PIPE H.2'X6.1" `~ ~~ ! 1~2 C:C)NC. c? REBOILER J LL CO M K.B.U. 31-7 ~~ ~ N+ELI. HC)USE °~ 16.3'~~ X=272.221.fl4 Y=2,362,4:23..56 K.U. 31-07X GAS INJECTION Y~lE( ~jELI HOUSE. X=272,247.95 Y=2.362.&73.05 1A.1' rj..:....W..~ii{t . t ~ -'f WELL K.B.U. 24-6 WELL LOCATION ASP ZONE 4 NAD27 N: 2362360.670 E: 272174.290 LAT: 60°27'37.172" N LONG: 151°15'43.822" W FWL = 1255' FSL = 316' ELEV = 65.65' (MSL) SECTIONS, TOWNSHIP 4N RANGE 11W, SM AK TOP~pAD ~ EDGE PAD FOOTPRINT CfJNTROL pT. CP-2 X=272.169.16 Y=2,362,2'13.75 ELEV.=65.67" 46.2, E f~• 3" O GUARD -~-~" „~ ,,....,r PIPE /f _,_ ~ ~ °"~ 3.0'X5.1' PIETAL _ '-'-- i 1 ~`8.0`XB.s?' PIRE COVER PLATE _~ .. ~7HOSE BLDG. _. { I j _. n ~.4 X1 ~.3' ;:Cl' PAID 3.0'X5.0' hAETA3.. i~ ~ I ~ SNl1Tf H GEAR 0 ~ ---~ CO1tEf2 PLAI"E ~I ) ! ~ , 1 ~-I°, °~.. 1 ~ ~~z ~ ~ 1 CENTAUR ~ _ ~ ~ ,~; CC)tv2PRESSC)R ~ j CC7NTAC7t?[a }} /1 4 BLDG. ' !~ ~ - '; BLDG, 1 «~ 42,?_` i- = 351DED3'X3' - tJ ~ GUARD PIPE f ~ ~ FOR C3UY ~R ~ `'~.,~ 57,4' ~ -I- -Yd WIRF I ~._ __ j ~ ~ ~ FILTERS ~_._ .~ ~ I j T ~,~ ,. i ~___--- OVERHEAD PIPE 54JPPt7RTS 1 6 I -~- --1~- .:.7~-:_=_,-~~ ~ _.... SECTION LINE _. NOTES 1. BASIS OF COORDINATES IS U.S.C. & G.S. TRI STATION AUDRY IN A.S.P. ZONE 4. (NAD 27) AVERAGE CONVERGENCE OF POINTS SHOWN:01°5'58". 2. AUDRY LOCATION: LAT: 60°30'50.559"N LONG: 151 °16'37.445"W NORTHING = 2,382,045.42 FASTING = 269,866.75 12.5'X3.0' GL.YCf~I HEAT EXCHAE*tGER PADS I I I L~ ~ NORTH SCALE 0 60 120 FEET ~~f~r T/~~ T PROJECT REVISION: 1 M ( ~iFil^V111V, KENAI GAS FIELD PAD 14-6 WELL K.B.U. 24-6 DATE: 7120/06 ~~ v~+~L'"~1\ 1 WELL AS-BUILT SURFACE LOCATION DRANTJBY: DME ARATHON • ~~ DIAGRAM SCALE: 1'=60' PROJECT NO. 063005 ENGINEERING (MAPPING /SURVEYING /TESTING BOOK NO. 05-09 COfI5UL~111Q I11C. p.0. BOX 468 SOIDOTNA, AK. 99669 LOCATION SHEET McLane VOICE: (907)2834218 PAx: t9o~)z63.az66 S6 T4N R11 W SEWARD MERIDIAN, ALASKA '' of 1 EMAIL: SAMCLANE(dMCLANECG.COM ~ s __ . _ _ __ _ _ -_ „1~,,,.,,..,~r, -, 60'30' I NORTH _ ,,~ • pipeline ~ -_-.u- .,.' -~ roc y ~» Pit ~: ~ .. {. ~F, 25 'bM II _' Pad 33-30 I~ '• U I ~` (' ~ ~. _ _ J 1 .~;PoPPY Lend iiok~ Yjy _i ,. ', I < • PHvatta•'~oed _~ ~~ / z3~oaoo 1 J~EEET .+ ,~ ~ ~ ` 1~I u S ' y ~ ~ ~: i._ Pad 43-32 ~ ~~~~' ~ °~~ --~ ~ '~L,raing AI '. Pad 3 4-.3 1 ] boas wells_ ~ _~ Strips j • ~~+nr<. KENAI GAS FIELD ~~ •li '~ t ~ ~ iy, t ~, S 4 ~ • • ~I , ~ Pits .' ~ I ~ I' W 1 I'~. ~:Paq 14-8 I I ,r l , jPad•33-t~ . - _._. _t.••I~. ~ •I Gas wens ^ . j 1:.;: I,,.. . ~ ~ ~ _ ,, I ~ Pad 41-7 i ~S Pad 1 4 - 4 Landing ,~~ ' • ~; Project Location ~ )~ ~ smv' ' a ~ Privatsu Road i• ` _ ii__.,...~, i. w Y N ® ~.. /t 4 ` _ • a Pad 41-1e J . .:pn . Echo • ~ ~ 1 I Al ~~~ ~ .~~ ::~, COOK INLET P4-18 ~ :~~_ ,5~,, `--,.~ Abandoned ~' ,~ _. - ,~ `~__ -, ~~..,~~`- ; ~:.~. _. 'r .f ~ -f~ ~ l I c.E w.s _ Landlag •. + Kenai Unit Boundary ~, ,~, • • Kalifoavky 1 ~ i ' ~ j' •'• i_ __ 1.~,.-~ {~~1j _ + •125 •. 1 M,, 1 1 • , _- .. 1 ~ 4 3F ~ J - ReJic~iEnL ~~ja ~t. 1 34 ~ 35 1 31 ~ .. _{~; Lake - - I Kaailof River .:-~~~ ~ ~> ~+ .+ -~ ~Errl ~ ~ ~ ~ ~~,' aJ . III I , 1 •,1 Source Map: USGS, 1951 Kensi, Alaska B-4, 1:83.380 SCALE 1'.63360 t 1 (~ i ! S ~ Mrrr C_1._L 1__L-:I-.L. 7 "i.__L .E - .._._ ~'--. __- .. 1.:. =..._ -. _' __:. .._. .::.-f--_ _.. _-.. _ _:-_'°„-1.-_ ... ' vxn itYn Irxl oppp !7pp0 IS000 iflIKIJ 17rRX! rll+ I 1 'r KILf7MEl(NS Marathon Oil Company Kenai Gas Field Area Map ~~ rll.~,•s+iF.~~r,nl.l~,t,.. • ~ T5N-R11'V11 - _- - _ z..«~ _- -- _ __ + ---- ~•~ UN iT ~ BOUNDARY. •-•r ~, + -~ ~~$. ~' ~ L.. ~~ ~ , ,, ~ ~ ~~;~ BeiugafUpper Tyonek ~, s ~$ ~ ~ Completion ; ~ ~ A KBU 24-6 Original Hak ~ f ~ '~ o ~.,~ o ~;.. ~ ~ BelugalUpper Tyanak V ~ 2005 Completion ~-1• i r•-•'J4-,~,.~-~~~~,~ FORb~1ATlON c.r ,oo• ~~ ~ ~ nni_[ M~+RaTH~ Ali (-AL ~J.~ik1='SIJi aLar.ati'EC,u:~r~ C ONFlDENTlAt KENAI FIELD iCBtJ 24-BRta Lvcatloln r•~c+/arrtlcf i~~IF~ Mvl lu~a GLACIER DRILLING RIG #1 ~- MUD PITS AND PUMP ROOM LAYOUT o_ 3600 I I 1= ~ 3800 a~ U cn aooo 4200 4400 asoo 4800 5000 ,~; 5200 ~ 5400 Q. ~ 5600 to V s8oo ~ 6000 H V 6200 6400 6600 6800 7000 7200 7400 7600 i riul~ uii ~;ompa~ny LOCatlOtl: Gook Inlet, Alaska (Kenai Penninsula) 51ot: SlotiF KBUZ4-6 ~~ Field: Kenai Gas Field Well: KBU24-6 ~ Installation: Pad 14-6 Wellbore: KBU24-6RD Ver 5 r ~I rn KOP MARATHON Scale 1 cm = 50 ftEaSt (feet) -> 17.43 16.04 200 300 400 500 600 700 800 900 DLS: 6.00 deg/100ft I ~ I I i i I i_ I ~ I I I -- 1100 ~' 19.36 ~ 23.21 End of Build/Turn 1000 ~ 900 KBU24-6RD - TD - 11/21/05 KBU24-6RD - M/Beluga - 11/21/05 I- 800 I d.~ 9 5/bin Intermediate casing ~~- 700 angent /~ Z End of Tangent ~ 600 ~ 3 20.58 KBU24-6RD - M/Beluga - 11/21/05 - 500 18.00 ,~.. .... 16.00 - 400 DLS: 2.00 deg/100ft - 12.00 nd of Build/Turn _ 300 10.00 KB„ZQb - 8.00 200 6.00 KOP - ~ li Lower Beluga ~ i KeU24-6 - 100 3 2.00 ~ ' I I cn 0 1, End of Drop p x WELL PROFILE DATA . ~ 3 1/tin Liner KBU24-6 KBU24-6RD - TD - 11/21/05 Polnl MD ~ Inc Azl li ND NoRh Easl degl100ft V. Sect KOP - _ 3900.00 20.50 L- 75.16 3805.28 - 169.37 551.21 0.00. 34.20 End of Build/Turn 4409.36 23.61 346.32 ~~i 4288.71 294.30 614.83 6.00 , /~ 140.55 End of Hold 5348.71 23.61 346.32 5149.42 659.86 525.86 0.00 516.77 Tyonek Top Target 5523.91 120.01 346.31 5312.00 723.23 510.43 2.00 581.99 d of Drop 6529.23 ~ 0.00 346.31 6296.82 892.86 469.13 2.00 756.59 T.D. 8 End of Hold 7819.42 ~, 0.00 346.31 7587.00 892.86 469.13 0.00 756.59 7800 ~', •• BAKER HUGHES -zoo -o zoo aoo soo 800 ,ooo ,zoo ,aoo ~ N ~ N;I(t scale, ~m=,oof~/ertical Section (feet) -> Azimuth 346.32 with reference 0.00 N, 0.00 E from Slot# KBU24-6 Date plotted : 23-Jan-2006 Plot reference is KBU24-6RD Ver 5. - Ref wellpath is KBU24-6RD Ver 5. Coordinates are in feet reference Slot# KBU24-6. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Planned Datum Rig Datum to mean sea level: 87.00 ft. Plot North is aligned to TRUE North. • MARATHON Oil Company,Slot# KBU24-6 ~~ Pad 14-6, MARATHON Kenai Gas Field,Cook Inlet, Alaska (Kenai Penninsula) PROPOSAL LISTING Page 1 Wellbore: KBU24-6RD Ver 5 Wellpath: KBU24-6RD Ver 5 Date Printed: 23-Jan-2006 ~/~~ uv1~~ Wellbore Name Created Last Revised KBU24-6RD Ver 5 __ ________________ 22-Nov-2005 _ 23-Jan-2 06 Well Name Government ID LastRevised KBU24-6 _ 12-Jan-2006 Slot Name Grid Northin Grid Eastin Latitude Lon itude North Ea t Slot# KBU24-6 2362360.6700 272174.2900 N60 27 37.1716 W151 15 43.8217 408.32N 1173.50E Installation Name Eastin Northin Coord S stem Name North AI' r-ment Pad 14-6 __ 270993.1910 2361975.0460 _ _ AK-4 on NORTH AMERICAN DATUM 1927 datum True Field Name __ Easting Northin _ Coord S steno Name North Alignment Kenai Gas Field 270993.1910 2361975.0460 AK-4 on NORTH AMERICAN DATUM 1927 datum True ',Created By_ All data is in Feet unless othen!uise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Planned Datum 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 346.32 degrees Bottom hole distance is 1008.60 Feet on azimuth 27.72 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON Oil Company,Slot# KBU24-6 Pad 14-6, MARATHON Kenai Gas Field,Cook Inlet, Alaska (Kenai Penninsulaj • PROPOSAL LISTING Page 2 Wellbore: KBU24-6RD Ver 5 Wellpath: KBU24-6RD Ver 5 Date Printed: 23-Jan-2006 ~~~ INTEQ Well ath G rid Re ort MD[ft] Inc[deg] Azi[deg] TVD[ftJ North[ft] East[ftJ Dogleg /100 Vertical S i ft Fasting Northing 3900.00 20.50 75.16 3805.28 169.37N 551.21E 0.00 34.20 272728.62 2362519.43 4000.00 17.43 ___59.21 3899.90 181.53N 581.03E 6.00 38.97 272758.67 2362531.02 4100.00 16.04 38.82 3995.75 199.98N 602.58E 6.00 51.80 272780.57 2362549.06 4200.00 _ 16.76 17.61 4091.76 224.51 N 615.62E 6.00 72.55 272794.07 2362573.33 4300.00 19.36 0.06 4186.90 254.86N 620.00E 6.00 _ 101.00 272799.04 2362603.59 4400.00 23.21 _ 347.30 4280.11 290.68N 615.68E 6.00 136.83 272795.41 2362639.49 4409.36 23.61 346.32 4288.71 294.30N 614.84E 6.00 140.55 _ 272794.63 2362643.12 4500.00 23.61 346.32 4371.76 329.57N 606.25E 0.00 176.85 272786.72 2362678.55 4600.00 23.61 346.32 4463.39 368.49N 596.78E 0.00 216.90 272777.99 2362717.64 4700.00 23.61 346.32 4555.01 __,_ 407.41 N __ ___. 587.30E __.__ 0.00 256.95 272769.27 2362756.73 4800.00 23.61 346.32 4646.64 446:32N 577.83E 0.00 297.00 272760.55 2362795.82 4900.00 23.61 346.32 4738.27 485.24N 568.36E 0.00 337.06 272751.82 2362834.91 5000.00 23.61 346.32 4829.90 524.15N 558.89E 0.00 377.11 272743.10 2362873.99 5100.00 23.61 346.32 4921.53 563.07N 549.42E 0.00 417.16 272734.37 2362913.08 5200.00 23.61 346.32 5013.16 601.99N 539.94E 0.00 457.21 272725.65 2362952.17 5300.00 23.61 346.32 5104.79 640.90N 530.47E 0.00 497.26 272716.92 2362991.2 5348.71_ 23.61 346.32 5149.42 65986N 525.86E 0.00 516.77 272712.68 2363010.30 5400.00 22.58 346.32 _ 5196.60 _. 679.41 N 521.10E 2.00 536.89 __ 272708.29 2 63029.94 5500.00 20.58 346.32 5289.58 715.15N 512.40E 2.00 573.68 272700.28 2363065.84 5529.23 ' 20.00 346.32 5317.00 _ 725.OON 510.00E 2.00 583.82 272698.07 2363075.73 5629.23 18.0 4 2 11.55 756.63N 2. OE 2.00 616.7 2726 0.97 3107. 0 5729.23 16.00 ___346.32 5507.17 785.04N 495.38E 2.00 645.61 272684.60 2363136.04 5829.23 14.00 346.32 5603.76 810.18N _ 489.26E __ _ 2.00 __ 671.49 272678.96 2363161.29 5929.23 12.00 346.32 5701.19 832.04N 483.94E 2.00 693.98 272674.06 2363183.25 6029.23 10.00 346.32 5799.35 850.58N 479.42E 2.00 713.06 272669.90 2363201.87 6129.23 8.00 346.32 5898.11 865.77N 475.72E 2.00 728.71 272666.50 2363217.13 6229.23_.. 6.00 _ 346.32 5997.36 877.62N 472.84E 2.00 740.89 ___ 272663.84 _ __ 2363229.02 6329.23 4.00 346.32 6096.98 886.08N 470.78E __. 2.00 749.61 272661.94 2363237.53 6429.23 2.00 346.32 6196.84 891.17N 469.54E 2.00 __ 754.84 272660.80 2363242.64 6529.23 0.00 346.32 6296.82 892.86N 469.13E 2.00 756.59 272660.42 2363244.34 6600.00 0.00 346.32 __ 6367.58 _ 892.86N _ 469.13E 0.00 756.59 272660.42 2363244.34 6700.00 0.00 346.32 6467.58 892.86N 469.13E 0.00 756.59 272660.42 2363244.34 6800.00 0.00 346.32 6567.58 892.86N 469.13E 0.00 756.59 272660.42 2363244.34 6900.00 0.00 346.32 6667.58 892.86N 469.13E 0.00 756.59 272660.42 2363244.34 7000.00 0.00 346.32 6767.58 892.86N 469.13E 0.00 756.59 272660.42 2363244.34 7100.00 0.00 346.32 6867.58 892.86N 469.13E 0.00 _ 756.59 272660.42 2363244.34 7200.00 0.00 346.32 6967.58 892.86N 469.13E 0.00 756.59 272660.42 2363244.34 7300.00 0.00 346.32 7067.58 892.86N 469 13E 0.00 756.59 272660.42 2363244.34 7400.00 _ _ 0.00 . _ 346.32 7167.58 892.86N __ ___ 469.13E ___ 0.00 756.59 272660.42 2363244.34 7500.00 0.00 346.32 7267.58 892.86N 469.13E 0.00 756.59 272660.42 2363244.34 7600.00 0.00 346.32 7367.58 892.86N 469.13E 0.00 756.59 272660.42 2363244.34 7700.00 0.00 346.32 7467.58 892.86N 469.13E 0.00 756.59 272660.42 2363244.34 7800.00 0.00 346.32 7567.58 892.86N 469.13E _ 0.00 756.59 _ 272660.42 2363244.34 _ 7819.42 0.00 346.32 7587.00 __ 892.8t_N__ 469.13E 0.00 _ 756.59 _ 272660.42 2363244.34 All data is in Feet unless othervvise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Planned Datum 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 346.32 degrees Bottom hole distance is 1008.60 Feet on azimuth 27.72 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON Oil Company,Slot# KBU24-6 '~ Pad 14-6, MARATHON Kenai Gas Field,Cook Inlet, Alaska (Kenai Penninsula) PROPOSAL LISTING Page 3 Wellbore: KBU24-6RD Ver 5 Wellpath: KBU24-6RD Ver 5 Date Printed: 23~Jan-2006 ~~~ INTEQ Comments MD ft TVD ft North ft East ft Comment 3900.00 3805.28 169.37N 551.21E _ KOP 4409.36 4288.71 294.30N 614.84E End. of Build/Tum 5348.71 5149.42 __ 659.86N 525.86E ____ ___ End of Tangent 6284.12 _ 6052.00 882.68N 471.61E _ _ Lower Beluoa 6529.23 6296.82 892.86N 469.13E End of Drop 7439.42__.__ __.__7207.00 892.86N 469.13E Tvonek Top_ __ Hole Sections Diameter in Start Start MD ft TVD ft start orth ft Start East ft End MD ft End TVD ft End North start East ft Wellbore 8 1/2 3900.00 ~ 3805.28 169.37N 551.21E 7819.42 7587.00 892.86N 469.13E KBU24-6RD Ver 5 Casin s Name Top MD ft Top TVD ft Top North ft Top Ea t ft Shoe MD ft Shoe TVD ft Shoe N rth ft Shoe E t ft Wellbore 20.000inCasin 0.00 0.00 O.OON 0.00E 86.00 86.00 0.06N 0.13W _ _ KBU24-6 13 3/bin Surface _ casin 0.00 0.00 _ __ O.OON 0.00E __ 1518.00 1517.66 __ 4.80N 27.56W KBU24-6 9 5/bin Intermediat casin 0.00 0.00 ___ O.OON _______ 0.00E ____ _ _ 5489.00 5294.59 315.91 N 1084.95E KBU24-6 3 1/tin Liner 0.00 0.00 O.OON 0.00E 7441.00 _ _ 7216.80 390.70N 1334.68E KBU24-6 3 1/tin Liner _ 0.00 0.00 O.OON 0.00E 7819.42 7587.00 892.86N 469.13E KBU24-6RD Ver 5 - ----_ Ta r ets Name North ft Eas ft TVD ft Latitude Lon nude Eastino __ Norhtin st R wised KBU24-6RD- 799.01N 495.51E 5312.00 N60 2745.04 W151 1533.93 272685.00 2363150.00 6-Oct-2005 M/Beluga - 11/21/05 KBU24-6RD-TD 799.01N 495.51E 7587.00 N60 2745.04 W151 1533.93 272685.00 2363150.00 6-Oct-2005 - 11/21/05 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Planned Datum 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 346.32 degrees Bottom hole distance is 1008.60 Feet on azimuth 27.72 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ~,,~ ~ MARATHON Oil Comp~iy BAKER LOCatIOn: Cook Inlet, Alaska (Kenai Penninsula) SIOt: Slot# KBU24-6 NV~ES Field: Kenai Gas Field Well: KBU24-s INTEQ Installation: Pad 1a-s Wellbore: KBU24-srt~yers MARATHON Scale 1 cm = 25 ft East (feet -> 200 250 300 350 400 450 500 550 60 650 700 750 800 850 900 950 1100 1100 1050 1050 1000 1000 950 950 900 900 850 850 800 800 750 750 700 700 ~ 650 650 ;~ ~ Z O v 600 600 3 t ~ ~ cD Z 550 550 ;~ ... 500 500 450 450 400 400 350 350 300 300 250 250 ~ ~ N 200 200 pnj I I ~ 150 150 ~ ~ u ~ N U ~ ~ 100 100 ~ 200 250 300 350 400 450 500 550 600 650 700 750 800 850 900 950 Scale 1 cm = 25 ft East (feet) -> --- - - - ~~,~ RATHON Oil Comp~y BAKER Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: Slot# KBU24-6 Nuc~Es Field: Kenai Gas Field Well: KBU24-6 INT~Q Installation: Pad 14-6 Wellbore: KBU24-6RD Ver 5 -Created by : Planner Date plotted : 20-Jan-2006 Plot reference is KBU24-6RD Ver 5. Ref wellpath is KBU24-6RD Ver 5. TRUE NORTH Coordinates are in feet reference Slot# KBU24-6. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Planned Datum Rig Datum to mean sea level: 87.00 ft. 350 0 10 Plot North is aligned to TRUE North. _ _ 340 20 400 290 280 270 260 250 70 80 90 100 110 zoo ~,~ 1so ~~, 1ao 00 ~~ Normal Plane Travelling Cylinder -Feet 170 1so All depths shown are Measured depths on Reference WE MARATHON Ir.~ MARATHON Oil Company ~~ KBU24-6RD Ver 5, KBU24-6RD Ver 5 MARATHON Slot# KBU24-6, Pad 14-6 Kenai Gas Field, Cook Inlet, Alaska (Kenai Penninsula) CLEARANCE SUMMARY Page 1 _ _ ~i_ r~ Date Printed: 20-Jan-2006 tiV~l ~~j Ellipse separations are reported ONLY if BOTH wells have uncertainty data Only Depth and Magnetic Reference Field error terms are correlated across tie points Cutoff is calculated on CENTRE to CENTRE distance Summary data uses Closest Approach clearance calculation for all minima Hole size/Casings are NOT included Hole size/Casings are NOT subtracted from Centre-Centre distance Ellipses scaled to 2.OOstandard deviations. Closing Factor Confidence limit of 99.80% Errors on Ref start at Slot Permanent Datum (0.00) Report uses Revised: (D-C)/E Factor Calculation We~lbore N me Created Last Revised KBU24-6RD Ver 5 22-Nov-2005 20-Jan-2006 ---- - r~e~) Name Government ID Last Revised KB 24-6 _____________ 12-Jan-20 6 n ___ ~ Field - Name _ - Eastin Northin -- Coord Svstem Name _ North Ali nment _ ~_ Kenai Gas Field 270993.191 ___ 2361975.046 AK-4 on NORTH AMERICAN DATUM 1927 datu True C! aeC! rance Summa Offset WeIlName Offset Wellbore _ Offset Slot Offset Structure Minimum Distance ft MD[ft] Diverging From[ft] Ellipse Separation ft Ellipse MD[ft] Clearance Factor Clearance MD[ft] KBU24-6 KBU24-6 Slot# KBU24-6 Pad 14-6 0.01 3900.OC 3900.0 -22.23 3900.0 0.00 3900.0 ___ KDU-1 KDU-1 slot #KDU 1 _ _ Pad 14-6 389.9 _____ 7819.4 7819.4 _ 319.71 7819.4 5.55 7819.4 KU21-7 KU21-7 slot #KU 21- Pad 14-6 576.3 3900.0 3900.0 546.8 3900.0 19.54 3900.0 KU14X-6 KU14X-6 slot #KDU 8 _ Pad 14-6 658.9 _ 3900.0 3900.0 __ 636.7 3900.0 24.02 5921.9 KU 31-7 KU 31-7 slot #KU 31- Pad 14-6 759.0 3900.0 3900.0 743.7 3900.0 49.59 3904.2 KBU31-7 KBU31-7 slot #KBU 31-7 Pad 14-6 824.2 3900.0 3900.0 794.9 3900.0 28.13 3900.0 All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned Datum 87.Oft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated • MARATHON O[I Company '~ KBU24-6RD Ver 5, KBU24-6RD Ver 5 MARATHON Slot# KBU24-6, Pad 14-6 Kenai Gas Field, Cook Inlet, Alaska (Kenai Penninsula) CLEARANCE SUMMARY Page 2 Date Printed: 20~1an-2006 ~-.^ INTEQ C~ara~n ce Su_rr~rn a!"Y_ _ ----- Offset Offset Offset Offset Minimum MD[ft] Diverging Ellipse Ellipse Clearance Clearance We1lName Wellbore Slot Structure Distance From[ft] Separation MD[ft] Factor MD[ft] ft ft KBU31-7 KBU31-7Rd slot #KBU Pad 14-6 824.24 3900.0 3900.0 794.9 3900.OC 28.13 3900.0 31-7 KU14-6 KU14-6 slot #KU 14-6 Pad 14-6 __ 855.21 3900.0 7819.4 850.7 _ 3900.OC 78.62 7819.4 _ KBU23X-6 _ KBU23X-6 slot #KBU Pad 14-6 _ 886.3 _____ 3900.0 5400.0 853.8 3900.OC 23.11 5757.8 23X-6 KBU 23-7 KBU 23-7 Slot #KBU Pad 14-6 1263.1 3900.0 3900.0 1246.0 3900.0 73.89 3900.0 23-7 KTU24-6H KTU24-6H slot #24-6 Pad 41-7 1293.1 7819.4 7819.4 1246.9 7819.4 27.9 7819.4 KBU11-7 KBU11-7 Slot# Pad 14-6 1310.4 3900.0 7819.4 _ 1287.2 3900.0 56. 3900.0 KBU11-7 KBU33-6X KBU33-6X Slot Pad 41-7 1522.8 7819.4 7819.4 1459.5 7819.4 24.0 7819.4 #KBU33-6X KBU33-6 KBU33-6 slot Pad 41-7 1613.9 7790.7 7790.7 #KBU33-6 KU13-6 KU13-6 slot #KU 13- Pad 14-6 1728.61 3900.0 3900.0 1691.6 3900.0 35.69 6102.3 KBU22-6 KBU22-6 Slot Pad 14-6 1914.6 3900.0 7819.4 1890.6 3900.0 56.5 7819.4 #KBU22-6 KTU43-6X KTU43-6X slot Pad 41-7 2098.6 4297.9 4297.9 2054.1 4314.3 25.0 7819.4 #KTU43-6X _ KTU43-6X KTU43-6XRd slot Pad 41-7 2098.64 4297.90 ___ 4297.9 2054.1 4314.3C 25.67 7250.6 #KTU43-6X _ KTU43-6X KTU43-6XRD2 slot _ __ Pad 41-7 _ 2098.6 4297.9 4297.9 2054.1 4314.3 25.67 7250.6 #KTU43-6X ___ KBU41-7X _ _ KBU41-7X slot _ Pad 41-7 _ 2127.5 _ 4275.5 4275.5 2109.2 4281.5 94.16 5610.2 #KBU41-7X KDU4 KDU4 slot #KDU 4 Pad 41-7 2262.9 3953.41 3953.41 2202.2 _ 3953.41 36.59 4199.4 __ KDU4Rd KDU4Rd slot #KDU 4 ___ _ Pad 41-7 __ 2262.9 3953.41 3953.41 2202.2 3953.41 36.7 4117.4 KTU24-6H KTU24-6H RD slot #24-6 Pad 41-7 2310.0 4215.8 7819.4 2294.5 4232.2 75.85 7819.4 KTU24-6H KTU24-6H slot #24-6 Pad 41-7 2310.0 4215.8 7819.4 2294.5 4232.2 90.34 7349.0 Pilot KU43-6 KU43-6Rd slot #KU 43- Pad 41-7 2316.7 5435.0 5435.0 2280.8 5446.1 63.76 5643. KU43-6 KU43-6 lot #KU 43- Pad 41-7 2401.9 4022.7 4022.7 2387.1 4035.4 82.43 6348.4 KTU32-7 KTU32-7 slot#32-7 Pad 41-7 2468.9 4029.1 4029.1 2442.2 4035.4 69.06 7819.4 KBU41-7 KBU41-7 slot #KBU Pad 41-7 2497.9 4215.8 7500.0 2471.4 4215.8 58.44 7545.9 41-7 KTU32-7H KTU32-7H slot Pad 41-7 2519.6 4232.2 7819.4 2505.4 4232.2 33.8 7819.4 #KTU32-7H __ _ _ _ - __ KU43-12 KU43-12 slot #KU _____ Pad 14-6 __-_ 2527.7 __.__ 3900.0 --_ 3900.0 2503.0 3900.0 75.94 7742.7 43.12 KBU 44-6 KBU 44-6 ___ slot Pad 41-7 2622.6 4150.2 7500.0 2605.8 4150.2 76.56 7660.7 #KBU44-6 KBU43-7X _ KBU43-7X Slot __.-__ Pad 41-7 2737.5 3900.0 7700.0 2710.4 3900.0 86.4 7819.4 #KBU43-7X - - - KU13-5 ---- KU13-5 slot ----- Pad 41-7 ------ 2789.4 - 4133.8 4133.8 2757.5 4150.2 50.58 7819.42 #KTU13-5 _ KU 43-6A --..___ KU43-6A slot #KU ____-- Pad 41-7 __-- 2858.8 4215.8 4215.8 2809.0 4215.8 42.36 5577.43 43-6A KBU41-6 ----_ KBU41-6 Slot ---- Pad 41-7 --- 2898.1 - 3900.0 7819.4 2870.0 3900.0 60.7 7808.4 #KBU41-6 All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig (Planned Datum 87.Oft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated • • MARATHON O[I Company CLEARANCE SUMMARY Page 3 ~~~ ~~ KBU24-6RD Ver 5, KBU24-6RD Ver 5 Date Printed: 20-Jan-2006 MARATHON Slot# KBU24-6, Pad 14-6 INTEQ Kenai Gas Field, Cook Inlet, Alaska (Kenai Penninsula) Gle~~rar~ee ~ur~~r~ary i Offset We1lName Offset Wellbore Offset Sbt Offset Structure Minimum Distance ft MD[ft] Diverging From[ftl Ellipse Separation ft Ellipse MD[ft] Clearance Factor Clearance MD[ftJ KBU42-6 KBU42-6 Slot #KBU42-6 Pad 41-7 2902.1 _ 3900.0 6329.2 2871.8 3904.2 48.8 7819.4 KBU42-7 KBU42-7 slot #KBU42-7 Pad 41-7 2991.3 3900.0 7500.0 2973.91 3900.0 102.5 7819.4 KBU11-8X KBU11-8X slot #KBU11-8X Pad 41-7 3202.0 3900.0 3900.0 3188.1 3900.0 104.8 7819.4 KU 43-7 KU 43-7 slot #KU 43- Pad 41-7 3386.9 3900.0 3900.0 3350.91 3900.0 80.7 7775.5 KBU 11-8Y KBU 11-8Y slot# KBU11-SY Pad 41-7 3531.1 3900.0 7819.4 3516.5 3900.0 121.5 7819.4 KU24-5 KU24-5 slot #KU 24- Pad 41-7 3591.4 3900.0 3900.0 3568.51 3900.0 88.8 7819.4 KU24-5 KU24-5Rd slot #KU 24- Pad 41-7 3591.4 3900.0 3900.0 3568.5 3900.0 95.0 5823.4 KU21-6 KU21-6 slot #KU21-6 Pad #? 3592.3 5889.11 5889.1 3546.1 5889.1 77.82 5839.9 KU11-8 KU11-8 slot #KU 11- Pad 41-7 3629.2 3900.0 3900.0 3612.41 3900.0 127.0 7700.0 KDU#2 KDU#2 slot #KDU 2 Pad 41-7 3647.1 __ 3900.0 3900.0 3625.8 3900.0 64.82 7819.4 KU21-6 KU21-6X slot #KU21-6 Pad #? 3756.0 5897.5 5897.5 3726.6 5905.5 127.2 60 5.9 KDUS KDU5 slot #KDU-5 Pad #? 3764.8 7819.4 7819.4 3657.6 7819.4 35.11 7819.4 KU11-6 KU11-6 slot #KU11-6 Pad #? 4079.6 ____ 5659.4 5659.4 4033.6 _ 5659.4 87.17 5134.51 KBU33-7 KBU33-7 slot #KBU33-7 Pad #41-18 4232.3 7246.1 7246.1 4150.5 7217.8 50.2 ' 6496.0 KU14-32 KU14-32 slot #KU 14-32 Pad #? _ ___ __ 5209.3 6003.9 6003.9 _ 5116.1 6003. 55.89 5954.7 KU34-31 ' KU34-31 slot #KU34-31 Pad #? 5217.9 6348.4 6348.4 _ _ KBU13-8 KBU13-8 Tem slot #KBU13-8 Pad #41-18 5412.2 ___ 4200.0 7819.4 5330.0 4215.8 50.2 7759.1 KU24-7 KU24-7 slot #KU24-7 Pad #41-18 5436.2 3986.2 3986.2 5407.0 3986.2 185.71 4199.4 KU24-7 KU24-7RD slot #KU24-7 Pad #41-18 5487.01 3900.0 3900.0 5460.3 3900.0 206.01 3986.2 WD-1 WD-1 slot #KU-W D-1 Pad #? 5647.8 5495.41 5495.41 5624.3 5495.4 239.2 5807.0 KDU6 KDU6 slot #KDU-6 Pad #? 6499.2 3900.0 5529.2 6479.3 3900.0 99.8 7 08.4 KU11-17 KU11-17 slot #KU11-17 Pad #41-18 7066.3 3904.2 3904.2 7019.6 3937.01 105.4 6692.91 KU41-18 KU41-18 Tem slot #KU41-18 Pad #41-18 7078.4 3937.01 7819.4 7015.9 3953.4 89.61 7819.4 ~ ~ All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig (Planned Datum 87.Oft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated • ~~ "I 'I vl '" 1 -_ 1 1 ~ ~ N ~ __ a ~ ~ °=i ~ '~ a x 7 ~° ~ t- o ~ O ~ U N o W y U N N pl J1 O N ~ O ~ ~ ~ U ~~yynyy ~ ~ i ~N m ~C M ~ _ H .~, . I ~ H ~ T ~ ~ 4 - ~: ?? T. +~ ~ N H U C .~ ~ O ...... ~ .0 u~ O 0 ~ ~ ~ ', a W~ ti .~ ~ , 'a 7 o w ~ ~ L~J ~ ~ ' Y ~ E --- ~ ~ ~ LL R i~ ~ ~ ~ ~ ~ C!1 .~ J q ', ~ W ~- Z w ~ S 61 s ~ ~~ a.' iJ ~~ ~y 1J -- ~i--o ~ M ~ S v m 4 `. r J ' s ~ 3 .~ i Q O O _..._. ~..~. W V ~ N ~ ~ ~ uM-, ~ s m ~ o z 0 ~~ ~. M ~: M ' ~: - o 1~ I ~ 07 i O o~ II m I E 3 N ~ O ~~y C d E 3 m E ~ I I q ~ ~ Y i ~. - '~ ;1_ ~! ~ ~ I ~ ~ -' L (.. v j LL fy ~ t,. ' U i 7 0 ~. r 4 I i ~ I I i O O N ~ {„ i ..- .N .~ q ~ N y ~ ~' ~~ ~ ~ - U / O L _. _~ ~,,, ' I L- c o ~ ~ U o `o o ~ y U (, ani • n~ • Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. INTEGRATED FLUIDS ENGINEERING PROJECT PLAN ~~ _ . _ . Prepared For: MARATHON OIL COMPANY Prepared by: Tony Tykalsky Reviewed by: Hal Martens Presented to: Will Tank January 6, 2006 ~~ Well KBU 24-6 RD Kenai Peninsula, Alaska • ~~ Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Will Tank Will: i Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Enclosed is the recommended drilling fluid program for the KBU 24-61tD well to be drill this year. The following is a brief synopsis of the program. Overview: KBU 24-6 RD is a sidetrack of an existing well. The plan is to kill and abandon the existing well, drill a 8-1/2" sidetrack to +/- 7819' MD, run and cement 3-1/2" EXCAPE completion. The major concern for this well is whole fluid losses in the Sterling and Upper Beluga sands. Form-A-Set AK pills will be squeezed into these zone in order to enhance completion and cementing of this well. Abandonment & Milling: The existing tubing pulled will be pulled and a whipstock will be set @ +/- 3900' MD. Flovis and drill water will be used for the milling fluid. Ditch magnets will be installed to capture metal cuttings. A LOT will be performed prior to drilling ahead. Sidetrack Interval: The milling fluid will be displaced to a new "Excape" FloPro fluid. Mud weights should be maintained as low as possible throughout the interval. A 3-1/2" EXCAPE completion will be run and cemented in place. FAS Pills: The depleted Sterling and Upper Beluga sands will be squeezed off with the application of at least two FAS pills. Plans are to drill to 4500' MD, spot and squeeze the first pill across the Sterling formation. At 4900' MD a second pill will be squeezed across the Upper Beluga formation. Additional pills may be required. ECD's and Running Speeds: All considerations will be made to maintain as low an ECD as possible and minimize any surge pressures through good drilling practices. A Virtual Hydraulics guideline will be posted with recommended GPM rates and suggested running speeds. Any changes to the recommendations should be made only after consultation with MOC supervisors. Completion: After logging, the 3-1/2" EXCAPE completion will be run and cemented. Corrosion control will be added to the packer fluid and the cement will be displaced with 6% KCl brine. Tony Tykalsky Project Engineer /M-I SWACO NOTE: This program is provided as a guide only. Well conditions will always dictate fluid properties required. t_~_- -a • Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Project Summary Casing Hole Casing Depth TVD Mud Mud Sum Interval Size Size Program System Weight Days Mud Cost (in) (in) (ft) (ft) Solids Control (ppg) 9-5/8" 12-1/4" 3900' 3805' Flovis for milling / 8.4 3 $13,833 Shale Shakers / ditch magnets 3-1/2" 8/1/2" 7819' 7587' Flo-Pro w/SafeCarb 9.0 - 10.0 10 $112,383 Shale Shakers / Desilter 3-1/2" 8-1/2" Formaset 4500' 4371' 63 bbl FAS Pill 9.5 1 $40,003 Pills (2) 4900' 4738' 42 bbl FAS pill 9.5 1 $27,475 N/A 3" Completion 7819' 7587' 6% KCl Brine 8.55 2 $5,807 - Insure magnets are in proper location prior to milling out of 9-5/8" casing. - Cost does not account for any losses of fluid to the formation. ~~ • r ,~ Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Offset Well History KBU 24-6 RD Offset Well History date I KBU 24-6 17.5 130 8.65 6 4 22.0 Build spud mud 1008 8.85 28 67 7.5 Spud in, P/U BHA, drill ahead 1525 8.65 12 26 11.4 drlg to csg point, condigion mud, run & cmt casing 1525 8.7 4 17 12.5 Test BOP's test csg, P/U BHA, drlg out cmt, LOT, displace to FloPro 12.25 1818 8.75 7 27 6.2 POH repair rig radiater, RIH, drlg ahead 3610 8.95 8 20 6.9 drlg to 3627' short trip, OK, drlg ahead 4011 9 8 16 7.8 drlg to 3877', POH for new motor, RIH drlg ahead 4532 8.9 8 22 8.2 drlg ahead 4645 9.6 9 20 7.8 Low ROP, high torque, add lubetex, increase PPG to 9.5 with barite 4982 9.7 9 22 10.0 Drlg ahead, 5213 9.8 11 27 8.0 POH remove near bit stab to reduce torque, fire up centrifuge van for solids removal 5505 9.6 12 17 9.8 Drlg to casing point, condition mud for running casing 5505 9.3 8 12 6.7 Run casing, lost returner at 3122', total losses 1289 bbls, cement casing 8.5 5673 9.3 7 14 7.8 Drlg out 8-1/2" hole, LOT? 6395 9.55 8 25 7.7 Drlg ahead, POH for BHA, tight in spots 6740 9.5 9 22 7.9 Drlg ahead 7420 9.6 9 27 7.5 Drlg ahead 7500 10.2 10 24 8.1 Drlg ahead, inc mud PPG to 10.0, POH for logs ~ 7500 10.4 13 32 6.4 Lot, Spot 16 PPG pill on bottom, run & cemtn completin assembly '~ ~ ~ • ~~ • Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Estimated Product Usage Summary PRQAUCT IVIiIIing sidetrack FAS Fills Cam- pletion Tatai Usage of 'Total Cast -~__~_ M-I Bar 0 412 105 0 517 2.08 Soda Ash 0 10 0 0 10 0.33 Caustic Soda 0 21 0 0 21 0.48 Conqor 404 0 5 0 0 5 3.38 Sodium Meta Bisulfate 7 21 0 5 33 1.16 Bicarb 0 10 0 0 10 0.10 Congor 303 0 0 0 5 5 1.28 F1oVis 55 124 25 0 204 22.59 FAS AK 0 0 94 0 94 25.06 FAS XL 0 0 10 0 10 6.09 FAS Ret 0 0 2 0 2 1.00 KCl 0 866 45 42 953 7.21 SafeCarb 10 0 82 0 0 82 0.84 SafeCarb 40 0 662 0 0 662 6.77 SafeCarb 250 0 82 0 0 62 0.84 Lubetex 0 16 0 0 16 6.29 K1aGard 0 19 0 0 19 7.07 Defoam X 0 11 0 11 0.52 Engineer Service 3 10 2 3 18 ~i~ ~~ • Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Interval Summary -Milling +/- 3900' Drilling Fluid System Milling Fluid .Key Products F1oVis / Sodium Meta Bisulfate Shale Shakers / Ditch Magnets Recommended shaker screens - 180/180/150 mesh Potential. Problems Birds Nests hole cleanin nterval Drilling Fluid Properties Depth Mud Plastic LSRV APt Metal .Interval Weight Viscosity l min .Fluid Loss MBT content (ft) (ppg) (cp.) (cps) (ml/30min) (%) +/-3900 8.45 12 - 18 +-/ 30,000 N/A 0 0 - Insure all pits are clean. - Mix 2 - 2.25 PPB Flovis in Drill water. Add +/- 0.5 PPB Sodium Meta Bisulfate to reduce DO to less than 3 PPM. - Fill hole with drill water as needed and cut completion string above cement (+/- 3925") MD. - Pull completion string, RIH Set whipstock and displace wellbore to milling fluid. - Insure ditch magnets are in place at shale shakers. - Mill out window and circulate hole clean. - Displace wellbore to drill-in fluid prior to POH. - Estimated volume usage for milling - 686 barrels. ~~ r ~ • ~~ • Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Interval Summary - 8-1/2" hole 3900 - 7819' Drilling Fluid System Flo-Pro Fluid Key Products F1oVis / Caustic Soda / MI Bar / Polypac Supreme UL / Conqor 404 Sodium Meta Bisulfate / KCl / K1aGard /SafeCarb Solids Control Shale Shakers / Desilter /Centrifuge Recommended shaker screens - 210 - 230 mesh Potential Problems Lost circulation /differential sticking /swab-surge /Loss of whole ud to depleted formations nterval Drilling Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (PPg) ~cp•) ~cPs) (ml/Mmin) (%) 3900 - 7819' 9.0 - 10.0 12 - 18 +-/ 30,000 < 8 < 8 < 5 - Build drill-in fluid according to the below formula. - NOTE: Use no LCM other than SafeCarb while drilling this interval. Some losses__to the formation are necessary in order to have a successful Form-A-Set application. - Maintain as low a mud weight and ECD as possible through the Sterling and Upper Beluga sands. - Drill to suggested MD (+/- 4500'), circulate hole clean, POH, P/U tail pipe and RIH to spot first Formaset AK pill (follow mixing and spotting procedures). - Drill to second suggested MD (+/- 4900'), and spot second Formaset AK pill using the above procedures. - Continue drilling to TD -keeping mud weight and ECD as low as possible. Minimize swab and sure pressures during all trio. Clean hole thoroughly before running EXCAPE completion. - Estimated volume usage 2016 barrels. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ~~ • '~ Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Fluid Formula- 8-1/2" Interval 8-/12" Interval from 3.900 - 7819' Input Descri tion KBU 24-6RD Mud Wei ht 9.0 - 9.5 Preh drated Gel No Wei ht Material Code MI BaR Preh drated Gel Conc. Wei ht Material SG 4.2 KCI Wt% 6 Out ut'• 1 bbl Order of Products Concentration Volume Product Addition field, Ib Lab, m Field, bbl. Lab, mf Usa e 1 Water 325.19 325.19 0.929 325.19 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 FloVis Plus 2.00 2.00 0.005 1.34 Viscosit 4 Pol ac Su reme UL 2.00 2.00 0.004 1.33 Fluid Loss Control 5 SafeCarb Medium 20.00 20.00 0.024 7.56 Brid in A ent 6 Potassium Chloride 20.76 20.76 0.025 8.68 Inhibition 7 CONQOR 404 2.00 2.00 0.004 1.43 Corrosion Control 8 Caustic Soda 0.50 0.50 0.001 0.23 H Control 9 Sodium Meta Bisulfate 0.50 0.25 0.001 0.25 Ox en Scaven er If slidin or hi h for ue becomes a roblem add 1 - 3% of the followin 10 Lubetex 7.00 7.00 0.021 7.00 Lubricit If sloughing coals become a roblem add 2 - 4 b of the followin 11 As hasol Su reme 2.00 2.00 0.004 1.33 Wellbore Stabilit Mix fluid in the order listed above. Total 380.1 380.1 Estimated Yalume Usa a 2061 Barrels Calculated Mud Wei ht 9.050 Total Chloride 29600 ~~ ~ ~ • ~~ Fluid Formula- First Form-A-Set Pill Form-A-Set AK Mixing Formulation FASware -version 04.1 Mixing chart for Form-A-Set AK - 25 Ib/sx Input data Design Properties Products Packing Desired pill weight 9.5 ppg Form-A-Set AK 25 Ib/sx Brine weight 13.6 ppg Form-A-Set RET gal/pail Weight material SG 4.2 SG Form-A-Set XL S@ Ib/sx Bottom hole temperature 1QT deg F Duovis 25 Ib/sx Desired pill volume 63 bbl Weight Material ~Ib/sx Mixing Formulation Form-A-Set AK Pill Formulation (products for mixing the desired pill volume) Form-A-Set RET Form-A-Set AK Duovis Weight Material Form-A-Set XL 56 bbl 0 Pails 56 sx 0 sx 65 sx ©sx 312.51 ml 0.0~ grams 22.32 grams 2.6$ grams 51.49 grams 4.63 grams Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Pilot Test Formulation 1 bbl equivalent (350 ml) Water Form-A-Set RET Form-A-Set AK Duovis Weight Material Form-A-Set XL Spotting & Squeezing Procedures ~~ ~ ~ • ~~ Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Fluid Formula- Second Form-A-Set Pill Form-A-Set AK Mixing Formulation FASware -version 04.1 Mixing chart for Form-A-Set AK - 25 Ib/sx Input data Design Properties Products Packing Desired pill weight 9.5 ppg Form-A-Set AK ~~ Ib/sx Brine weight 8.6 ppg Form-A-Set RET gal/pail Weight material SG 4.2 SG Form-A-Set XL ~Ib/sx Bottom hole temperature 113 deg F Duovis Ib/sx Desired pill volume 42 bbl Weight Material 5th Ib/sx Mixing Formulation Form-A-Set AK Pill Formulation Pilot Test Formulation (products for mixing the desired pill volume) 1 bbl equivalent (350 ml) Water 38 bbl Water 312.51 ml Form-A-Set RET pails Form-A-Set RET 0.72 grams Form-A-Set AK 38 sx Form-A-Set AK 22.32 grams Duovis Osx Duovis x.68 grams Weight Material 43 sx Weight Material 51 A9 grams Form-A-Set XL ®sx Form-A-Set XL 4.83 grams Spotting 8~ Squeezing Procedures ~~ ~.~' ~ ~~ • Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Recommended Form-A-Set Procedures 1. Drill to desired depth and circulate hole clean. 2. POH stand back BHA and pickup tail pipe. 3. RIH to spotting depth 4. Determine loss rate to the formation. Some loss rate is necessary in order to be able to squeeze the Form-A-Set pill into the sand zones without fracturing the formations. If the loss rate is zero due to wallcake buildup, discuss with town methods to remove some of the wallcake ahead of the Form-A-Set pill. (A spacer consisting of KCl brine and SafeSurf W may be applicable). 5. Mix a 20 barrel weighted high viscosity spacer consisting of the following. a. 20 bbls 6% KCl b. 2 PPB F1oVis c. MI Bar to 9.5 PPG 6. Mix the Form-A-Set pill in the MI mix tank. 7. Pump '/z (10 barrels) of the weighted spacer followed by the Form-A-Set pill down the drill string. 8. Follow the pill with the last 10 barrels of the weighted spacer. 9. Spot the Form-A-Set Pill as a balanced plug down hole. ~~ • ~~ Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Recommended Form-A-Set Procedures (continued) 10. Shut the pumps down and pull to above the calculated top of the pill (ad a two stand safety margin). 11. Circulate barrels of fluid down the drill string to clear any residual Form-A-Set. 12. Close the annular preventer. Apply and hold psi of pressure (if possible) with the rig pump while monitoring fluid volume. 13. Attempt to squeeze barrels of Form-A-Set into the theft zone. 14. After injecting barrels of Form-A-Set into the theft zone, drop the imposed pressure back to psi and hold for a total of four hours from the initiation of the squeezing process. 15. Monitor a sample of the Form-A-Set mix in a pan of heated water in the mud lab. (Have the water heated to the bottom hole temperature). 16. Once the four hours have elapsed and/or the sample mix has set up, continue with drilling/tripping operations. 17. Record loss rates before application of the Form-A-Set pill, after squeezing the pill, and after reaming out the pill. ~~ • ~~ Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Interval Summary -Completion Procedures Corrosion Control Additive in Casing x Tubing Annulus Well KBU 24-6 RD Volumes: Tubing Volume 3-1/2"Tubing ss.o2 barrels Annular Volume Casing x Tubii 239.19 barrels 3.50 x 2.992 x 7819 ft Open Hole x T 120.23 barrels 9.625 x 8.681 @ 3900 ft MD 8.500 x 3.50 @ 7819 ft MD Total Annular Volume 359.42 Tubing Volume ss.o2 Total Hole Volume 427.45 Treatment Procedures. 1. After the 3-1 /2" tubing is run and the drilling fluid is circulated and conditioned for the cement job, circa an additional 240 barrels of drilling fluid. 2. Add 1 drum of Conqor 303A and 1 sack of Sodium Meta Bisulfate for each 80 barrels of drilling fluid pumped (3 drums 8 3 sacks total) 3. After the 240 barrels of drilling fluid with treatment have been pumped downhole, begin the cement job. This procedure will place corrosion control in the 3-1/2" x 9-5/8" annulus. ~~ ~ - • • _l '~ Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. HSE Issues HANDLING OF DRILLING FLUID PRODUCTS HEALTH AND SAFETY 1. Drilling crews should be instructed in the proper procedures for handling fluid products. 2. Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab, and the office of the Drilling Forman. 3. PPE must be in good working order and be utilized as recommended by the PPE charts. 4. Product additions should be made with the intent to use complete unit amounts of products (sacks, drums, cans) as much as possible in order to minimize inventory of partial units. 5. Insure all MSDS sheets are up to date and readily available for workers to access for information. ENVIRONMENTAL 1. Insure that all product stored outside is protected from the weather. 2. Do not store partial units (sacks, etc) outside if possible. 3. Properly secure all products for shipment between job sites. 4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly secured. 5. When utilizing the centrifuge solids van, insure all hoses and connections between the van and the rig are secure. ~~ ~ ~ • Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS Product Function Health Flammabilit Reactivit PPE ASPHASOL SUPREME Shale Inhibitor 1 1 0 J BORAX Inorganic Borate 1 0 0 E CALCIUM CHLORIDE Densifier 1 0 0 E CIRTIC ACID pH Adjuster 1 0 0 E CONCOR 303A Corrosion Inhibitor 2 1 0 E CONCOR 404 Corrosion Inhibitor 1 1 0 J D-D CWT Fluids Additive 2 1 0 J DEFOAM X Defoamer 1 1 0 J DESCO CF Dispersant 1 1 0 E DUAL-FLO Fluids loss reducer 1 1 0 E FORM-A-SET AK Loss circulation Material 1 1 0 E FORM-A-SET XL Fluids Additive 2 1 0 E FORM-A-SET RET Loss circulation Material 1 1 0 J HEC-10 Viscosifier 1 1 0 E FLO-VIS PLUS Viscosifier 1 1 0 E STEEL LURE EP Oil well additive Lubricant 1 2 0 .1 SODIUM BICARB Alkalinity control 1 0 0 E SODIUM META Oxygen Scavenger 1 1 0 J SPERSENE CF Dispersant 1 1 0 E GELEX Bentonite Extender 1 0 0 E G-SEAL Graphite LCM 1 1 0 E KLAGARD Shale Control 0 1 0 J LUBETEX Lubricant 1 1 0 J MI BAR Weighting Agent *1 1 0 E MI GEL Viscosifiet *1 1 0 E MI SEAL F, M, C LCM *1 1 0 E ~~ • r'~~ • Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS MIX II F, M, C LCM *1 1 0 E NUT PLUG F, M, C LCM *1 1 0 E POLYPAC'S Fluid Loss Control *1 1 0 E Potassium Chloride Shale Inhibitor, Densifier 1 0 0 E SafeCarbs (all) Bridging * weighting agent *1 0 0 E SAFEKLEEN Surfactant 1 1 0 J SALT Densifier 1 0 0 E SAPP Dispersant *1 0 0 E SODA ASH Calcium precipitation 1 1 0 E DRILLZONE ROP Enhancer 1 1 0 J SCREENKLEEN Dispersant/Emulsifyer 1 1 0 J BIOBAN BP-PLUS Biocide 2 1 1 J GREENCIDE 25G Biocide 3 0 0 J CAUSTIC POTASH Alkalinity Control 3 0 1 X n~~~,-~i~r~+" r~„r.,,~ ~ 0 1 X HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS) HAZARD RATINGS 4 -Severe hazard 3 -Serious hazard 2 -Moderate hazard 1 -Slight hazard 0 -Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX A -Safety Glasses B -Safety Glasses, Gloves C -Safety Glasses, Gloves, Synthetic Apron D -Face Shield, Gloves, Synthetic Apron E -Safety Glasses, Gloves, Dust Respirator F -Safety Glasses, Gloves, Synthetic Apron, Dust Respirator G -Safety Glasses, Gloves, Vapor Respirator H -Splash Goggles, Gloves, Synthetic Apron, Vapor Respirator I -Safety Glasses, Gloves, Dust and Vapor Respirator J -Splash Goggles, Gloves, Synthetic Apron, Dust and Vapor Respirator K -Air Line Hood or Mask, Gloves, Full Suit, Boots X -Consult your supervisor for special handling directions 1~ • t~ Marathon Oil Company Well Name: KBU 24-6 RD Ver.2 Location: Kenai, Alaska. Contacts Contact Title a-mail Work Cellular Pete Berga Drilling pkberga@marathonoil.com 907 565-3032 907 231-0663 Marathon Superintendent Will Tank Drilling Engineer wjtank@marathonoil.com 713 296-3273 713 203-8398 Marathon Tony Tykalsky Project Engineer ttykalsky@miswaco.com 907 274-5011 907 227-2412 MI SWACO Bob Myles Warehouse Manager rmyles@miswaco.com 907 776-8680 907 252-4218 MI SWACO Michael Barry Senior Field barry.michael@att.net 907 260-4666 907 590-3636 MI SWACO Engineer (home) Locke Rooney Field Engineer rooneyl@alaska.net 907 235-0598 907 590-3636 MI SWACO (home) Roland Lawson /Dave Drilling Foremen RCLawson@ 907 283-1312 Morris/ John marathonoil.com Nicholson alaska_drilling Marathon marathonoil.com Responsibilities - MI Project Engineer and will coordinate daily between the Marathon office, rig, warehouse, and the M-I field engineers. - Well progress will be monitored to look for any changes, which will improve the efficiency of the operation or avert trouble. - Field Engineers will monitor and supervise product inventory to include re-palletizing any products for shipment to other locations at the end of the well. - Field Engineers will communicate with office personnel (Marathon & MI SWACO) for approval of any changes in the mud program (including introduction of new products). - Field Engineers will produce a recap at the end of the well based on daily activities. Recap should include any lessons learned that may be used to provide better service on future wells. Lessons learned can include changes in procedures, product additions, equipment usage, and/or utilization of any third parry service. Check No Check Date Bank Bank No Vendor N Marathon Oil Company g Hndl CCOUNTS PAYABLE DEPARTMENT P O B 22164 g 1206305 01/13!2006 NCBAS 7780 . . ox Accts Payable Contact Center 5001123 Tulsa, OK7412t-2t 64 HS phone' 918-925-6097 In~4iceN'~n4er '>. Invoke pate g4aumeni Pto '', FIQ(~}rt Gglpment - t=zrossAineunt ' Drscount lnuoiee/Pay Arnotint L 100.00 01 /13/2006 1900003516 100.00 100.0 TOTAL: 100.00 100.0 tru~u uN NtHroFiATION BELOW AND DETACH CHECK STUB BEFORE DEPOSITING) "., ~,, Giitv~. 1~E~1 uu -_ -_. __.. _ _. _. _-.- _-__-.._ ~. ~ ~~ ~ ~ ~ __~... ~ ~._-_~__ _. 7780 ACCOUNTS PAYABLE CHECK IVlarathon Oil Company P. O. Box 22164 Tulsa, OK 74121-2164 56-389/412 PAY TO THE ORDER OF. ALASKA OIL & G1~AS~CONSERVATION COMMISSION 333 WEST 7TH AVE STE 100 ANCHORAGE, AK 99501-3t^^ NATIONAL CITY BANK Ashland, Ohio CHECK DATE CHECK NUMBER Ol/13/2006 1206305 VOID AFTER 180 DAYS MATCH AMOUNT IN WORDS WITH NUMBERS _ _ _ - ~ ~B~iv ~~m~"-``~'~.=~;''~~1~61b~`~~~. ~f~1 F~`°i.'~'~''~"ti'k'@li e~'-,t;L~t`1'+1 ~~~~. ~`~~°'`~'I~IR ~n.,~. _ _. ., I~ _ 1~ ~..~~ ,~... .. _. ,~..~" ' 1~~a ~ aril" tl "i~d° ~a ~''~~l~' ~~~~"~~"1'~~~~c ..._ U.S. Funds 11'000 1 20 6 30 511' x:04 1 20 389 5: 0 L83484u^ • • TRANSMITTAL LETTER CHECKLIST WELL NAME ~~~~ 2. ~} ' b /C,D PTD# ,2~ - O~ ~ Development Service Exploratory Stratigraphic Test Circle Appropriate Letter /Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS TEXT FOR APPROVAL LETTER WHAT (OPTIONS) APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in permit No. ,API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - -_) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / infect is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be SAMPLE in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. 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