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192-122
1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _0 Service Stratigraphic Test 2. Operator Name:6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address:7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section):8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:9. Ref Elevations: KB: 17. Field / Pool(s): Beaver Creek Unit GL: 160.4' BF: N/A Total Depth:10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27):11. Total Depth MD/TVD: 19. DNR Approval Number: Surface:x- y- Zone- 4 TPI:x- y- Zone- 12. SSSV Depth MD/TVD:20. Thickness of Permafrost MD/TVD: Total Depth:x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22.Logs Obtained: 23. BOTTOM 13-3/8"K-55 116' 9-5/8"N-80 1,794' 7" N-80 2,843' 24. Open to production or injection?Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production:Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press.24-Hour Rate Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl:Water-Bbl:Flow Tubing Choke Size: Surface Per 20 AAC 25.283 (i)(2) attach electronic information 3,075' (TOW)Surface 61#116' Water-Bbl: PRODUCTION TEST N/A Date of Test:Oil-Bbl: N/A Gas-Oil Ratio: Surface Surface 700 sx Conductor SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 47#Surface 1,858'Surface 12-1/4" N/A 3,075' MD / 2,834' TVD N/A 8,881' MD / 8,496' TVD 3,075' MD / 2,834' TVD N/A 2792' FSL, 1259' FWL, Sec 27, T7N, R10W, SM, AK AMOUNT PULLED 317052 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. GRADE CEMENTING RECORDSETTING DEPTH TVD 2432405 TOP HOLE SIZEBOTTOMCASINGWT. PER FT. 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 317379 2434004 50-133-20445-00-00July 28, 1994 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 10/12/2024 192-122 / 324-501 N/A BCU 09August 27, 19941188' FNL, 1567' FWL, Sec 34, T7N, R10W, SM, AK 178.4' Sterling Undefined Gas A028083 ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 565 sx8-1/2" TUBING RECORD Driven N/A PACKER SET (MD/TVD) 29# N/A G s d 1 0 p d B P L s (att Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 2:44 pm, Jan 09, 2025 Abandoned 1/9/2025 JSB RBDMS JSB 012725 xGBJM 5/7/25 DSR-4/7/25 in 9A SFD SFD 3/27/2025 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval N/A N/A ~8594' ~8260' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Digital Signature with Date:Contact Email:cdinger@hilcorp.com Contact Phone: 907-777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Formation Name at TD: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. 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). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Beluga 30 Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 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. TPI (Top of Producing Interval). Authorized Name and Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. INSTRUCTIONS P&A Reports, P&A Schematic Authorized Title: Drilling Manager If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered)FORMATION TESTS N Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.01.09 12:18:36 - 09'00' Sean McLaughlin (4311) Size Type Wt Grade Conn. ID Top Btm 13-3/8" Conductor 61 K-55 Surf 116 9-5/8" Surf Csg 47 N-80 BTC 8.681" Surf 1,853 7" Prod Csg 29 N-80 BTC 6.184" Surf 5,950 3-1/2" Liner 9.2 L-80 IBT AB- Mod 2.992" 5,814 8,881 1 2 3-1/2" Tubing 9.2 L-80 IBT AB- Mod 2.992" 3,290 5,430 D1X 3 4 5 No. Depth ID 3075 6 13130 23220 33289 B3B 44487 5 5324 3.00" 6 5339 2.813" Sands Top (MD)Btm (MD)Top (TVD) Btm (TVD) Length (ft)Date D1X 3235 3240 2972 2976 5 8/20/20 5468 5498 5087 5117 30 7/5/20 5468 5498 5087 5117 30 8/15/19 5483 5486 5102 5105 3 8/12/19 B3L 5533 5553 5152 5172 20 3/5/14 B4 5629 5637 5248 5256 8 June-98 PBTD 3,075' MD TD 8,881' MD Isolated 9/9/24 Status PERFORATION DETAIL 3-1/2" Liner 6" Hole: 500sxs. Cement from liner top back to surface. 90' of cement. TOC = 3130' (9/9/24) Item JEWLRY DETAIL 7" CIBP above cut tubing stub w/ 27' cement- TOC is 3262 (9/8/24)' DV tool in 7" casing DLH Hydraulic set packer (46k release) X-nipple. Plug installed 8/19/20 capped with 57' cement. ToC = 5,282' MD 7" CIBP (9/9/24) Whipstock CASING DETAIL CEMENT DETAIL 9-5/8"12-1/4" Hole: 700sxs 7" 8-1/2" Hole: Bottom stage was 90sxs (22bbls) 13# lead, and 125sxs (26.4bbls) 15.5# Class G tail. Upper stage was 350sxs (85 bbls) 13# through DV tool at 4,487' MD. Full returns durring job. 8/30/94 VDL shows ToC above 2800' MD (stopped logging there). B3B Isolated 8/19/20 Isolated 8/19/20 Isolated 8/19/20 Isolated Isolated 8/12/19 Additional perfs on p2 2,834' TVD 8,500' TVD Updated By CJD 1-9-25 Additional jewlry on p2 BC-9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M.Permit #:192-122API #:50-133-20445-00-00 Property Des:FEDA - 028083KB Elevation:23' AGL) TD Reached:8/26/1994 Tree cxn: 6-1/2" Otis P&A SCHEMATIC w/ ~58' of cement on top. -bjm Sands Top (MD) Btm (MD)Top (TVD)Btm (TVD) Length (ft)Date B4 6429 6459 6048 6078 30 1/12/04 B16 7,420 7460 7039 7079 40 10/2/96 B17 7,534 7574 7153 7193 40 9/30/96 B18 7,640 7660 7259 7279 20 9/28/96 7,705 7725 7324 7344 20 9/26/96 7,725 7755 7344 7374 30 9/25/96 7,762 7812 7381 7431 50 8/13/96 7,812 7842 7431 7461 30 8/9/96 7,852 7882 7471 7501 30 8/7/96 B21 7,893 7933 7512 7552 40 8/5/96 7,980 8030 7599 7649 50 9/25/94 8,036 8054 7655 7673 18 9/24/94 8,072 8098 7691 7717 26 9/24/94 B24 8,167 8187 7786 7806 20 9/18/94 8,241 8246 7860 7865 5 9/16/94 8,254 8261 7873 7880 7 9/16/94 8,276 8292 7895 7911 16 9/16/94 8,399 8409 8018 8028 10 9/15/94 8,432 8452 8051 8071 20 9/15/94 No. Depth ID 5348 5350 5358 5438 5520 5549 5615 5620 5739 5823 2.813" 5828 8808 Isolated Isolated Isolated Isolated Isolated Isolated Isolated Isolated Isolated Isolated ADDITIONAL JEWLRY DETAIL Item Top of gravel pack sand behind screens (7/8/20) Bottom of Gravel Pack assembly CIBP with 36' cement on top (8/12/19) B20 ADDITIONAL PERFORATION DETAIL Status Squeezed 7/28/07 Isolated Isolated Isolated Isolated Isolated Isolated Model N Bridge Plug Overshot (swallowed 2' of hook up nipple) Hook up nipple 4 joints of 4-1/2" screens / blank pipe CIBP Cut 3-1/2" tubing PX plug CMU Sliding Sleeve Model H Liner Top packer B19 B23 B25 B27 Isolated Isolated Page 1/1 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:9/6/2024 End Date:9/10/2024 Report Number 1 Report Start Date 9/7/2024 Report End Date 9/8/2024 Last 24hr Summary MIRU 401 rig package on liner to well center, Spot and RU AUX equipment, Bullhead 65 BBLS dn TBG, bleed off IA Set BPV NU BOPE, torque and function test same, RU choke and kill lines, RU work floor, perform shell test to 2,500 PSI, perform BOPE test according to procedure, 250/3000 good. witness waived by Jim Regg. Tested Gas alarms. Report Number 2 Report Start Date 9/8/2024 Report End Date 9/9/2024 Last 24hr Summary Pulled BPV,bullhead 35 bbls dwn tbg, BOLDS, pull up hanger to 75k,RU eline w/ 2.5” jet cutter cut tbg @ 3290’ good cut, pump hole volume w/ no returns, bullhead 90 BBL down IA, pul hanger to floor, swap tongs to mccoy, POOH w/ completion detailed in time log, RU&RIH w/ eline set 7” CIBP @ 3289' tag to verify. dump bail 25' cement on 7" CIBP @3289', Verify TOC @ 3262', PU & MU #2 7" CIBP RIH Report Number 3 Report Start Date 9/9/2024 Report End Date 9/10/2024 Last 24hr Summary RIH w/ 7" CIBP, correlate & log onto depth, set@3220', 5' above perfs showing @ 3225', Tag plug on depth, good, Fill hole, Break Circulation w/3 bbls water,good,shut in PT t/2200psi good, pump 3.3bbls 15.3PPG cmt slurry, drop wiper ball & chase with 27bbls water. monitor tubing on vac, POOH above ETOC @3130, Rev circ 2x BU and recover wiper ball, Ld 3 ½” IBT completion string, RD handeling equip, Rd floor, ND BOPE, NU 7" blank flange, RD AUX equip, sco pe down and lay over mast. remove equipment from liner, slide liner from BCU-09, spot equipment on liner, stand up rig mast and tie down same Field: Beaver Creek Sundry #: 324-501 State: ALASKA Rig/Service: N2Permit to Drill (PTD) #:224-113Permit to Drill (PTD) #:192-122 Wellbore API/UWI:50-133-20445-00-00 Page 1/2 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Well Operations Summary Jobs Actual Start Date:10/3/2024 End Date:10/23/2024 Report Number 5 Report Start Date 10/7/2024 Report End Date 10/8/2024 Operation Crews meet at CCI Yard, begin rigging down modules for move, CCI offload rig move equipment from barge, crew travel to Beaver Creek, Lay felt liner and set mats, off load equipment as it arrives on trucks, split apart rig stage for transport and P/U rig mats ship to beaver creek. Continue laying rig mats as arrive, pull sub and draw works down and stage on trucks, transport to beaver creek, continue hauling modules and staging in beaver creek, transport cranes to beaver creek and spot in, set sub on pony subs and center over well, set draw works and derrick on sub and pin, set doghouse/water tank, raise doghouse and pin in drilling position, rest crews for the night break tours. Rest crews, break tours. Report Number 6 Report Start Date 10/8/2024 Report End Date 10/9/2024 Operation Crews arrive on location, rig movers transporting equipment from yard, begin riggin up modules, spot crane set derrick board wind walls, prep to raise mast, spot in pit modules and pump skids. Continue rigging up modules, prep and raise mast, set in gen shed and top drive HPU, spot boiler complexes, continue rigging up rig modules. R/U tool pushers trailer and sleeper shack Hook up Pason . Hook up electric, water, fuel and started on steam lines. Installed vent line and raised poor boy degasser. Install hand rails. Installed and hooked up lights. Spotted and hooked up gen 3. Spotted 3rd party shacks. Cont. installing steam lines. Spool drill line and prep to scope derrick. Scope derrick. Report Number 7 Report Start Date 10/9/2024 Report End Date 10/10/2024 Operation Continue R/U modules, P/U T and secure torque tube R/U and P/U top dive in cradle , secure to blocks remove cradle, P/U torque bushing, and M/U to top drive and torque tube, hook up top drive and service loop, rig smart still installing system Install IBOP and saver sub on topdrive, spot in fuel tank continue rigging up rig systems, install gas alarm system and function test, set in fuel tank and fuel rig, trouble shoot top drive function, dress shakers, fill rig tank with water get it going around rig, fill boiler and begin staging up boiler.. Repair 37 pin on top drive. Dress rig floor. R/U moneky board and install pull back ropes. Weight indicator stuck at 52k- trouble shoot. Will have zack with Quadco take a look. Meanwhile installed one of teh old weight indicators. R/U iron roughneck and dress with dies. Hooked up rig smart. R/U pits and mud pumps. Hooked up centrifuge mud lines and vacuum degassser. Run water through pits and function test pit volume alarms. Clean and rinse pits. Remove shipping beams. Install DSA on BOP and stab onto wellhead. Connect kill and choke line. Stage up boilers to full pressure. Change oil and filter on rig loader. Fill pits with water. Report Number 8 Report Start Date 10/10/2024 Report End Date 10/11/2024 Operation Tighten bolts on stack, install choke and kill lines, install flow box and riser , install bell nipple, secure stack. Quadco calibrate weight indicator and all gauges on choke accumulator and drillers console, install swivel packing on top drive. Install Test plug and tighten lock down as per vault rep, charge accumulator and function test BOP Stack, install test jt and R/U for testing. R/U and test BOP's w/ 4.5'' test jt t/ 250 low for 5 min and 5000 high f/ 10 min state and BLM inspectors witnessing. attempt first test tighten leaks on annular cap and choke manifold flanges, bleeed and retest good, test number 2 HCR kill leaking grease and retest then door seal leaking had to change and retest, re flood stack and purge air continue testing. Replaced test hose fitting. Reflooded, purged air. and re-test, pulled test joint reflooded stack, function rams, reinstalled test joint purged air and re-tested-pass. Test #3-UPR, TIW valve, inside kill, CM-valve- #4,5,6-Pass Test #4-UPR, TIW valve, inside kill, CM-valve-#1,2,3-Pass Test #5-UPR, TIW, Inside kill, choke HCR-fail. Grease choke and function re-test-pass Test #6- Accumulator draw down test-Pass Test #6- Blind rams, inside choke-Fail/Pass. Inside choke failed on high, greased and functioned, re-test DSA failed on low tig htened flange, re-test. Test fitting failed on high, changed fitting. Test #8- Manual choke, pressured up to 2000psi hold, bled off to 1500psi caught pressure and hold-Pass Test #9- Electric choke-Fail/Pass. Choke would not hold pressure. Disassembled and found choke was not put together properly. Re-assmeble. and test. R/D test equipment and blow down surface lines and choke manifold. Report Number 9 Report Start Date 10/11/2024 Report End Date 10/12/2024 Operation R/D test equipment, pull test plug set wear ring, blow down lines, load pipe on racks and prep to P/U Comission Rig Smart system, trouble shoot system not working correctly work on rig smart system, test mud lines w/ new test pump, replace leaking 4'' valve on Rack strap and tally 4.75" spiral drill collars. Mob clean out components to rig floor. M/U BHA #1., bit, scraper, mill and drill collars. P/U and RIH w/ 16 joints of 4.5" HWDP t/684'. RIH w/ 4.5" DP singles from cat walk f/684' t/1662'. Pason crashed multiple times. Trouble shooting with Pason tech support. Report Number 10 Report Start Date 10/12/2024 Report End Date 10/13/2024 Operation Continue wiating on Pason to fix their rig sytem. Field: Beaver Creek Sundry #: State: ALASKA Rig/Service: HEC 169Permit to Drill (PTD) #:224-113 Wellbore API/UWI:50-133-20445-01-00 Page 2/2 Well Name: BCU-009A Report Printed: 1/7/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Continue RIH w/ clean out assembly P/U DP single f/ 1662' t/ 3128' tag cement, dress off Displace well t/ 8.9pp g 6% KCL polymer mud system. Work on rig smart system POOH f/ 3168' t/ BHA Rack back and L/D BHA bit mills and crossover Level derrick and service rig recalibrate draw works encoder M/U WIS mill assembly on bottom of 4" HWDP singleas per WIS rep. M/U Sperry directional tools on top of HWDP and perform offset. P/U and M/U whipstock on bottom of mill asembly. RIH w/ 6 4.75" spiral drill collars and and 8 stands of 4.5" HWDP. t/ 765'. TIH out of derrick f/765' t/1541'. P/U-43K, S/O-40K. Disp: Calc-22.9bbl, Act-23bbl. Cont. to RIH f/1541' t/3085' Orient Whipstock to 34L TF. RIH t/3128' and trip anchor w/ 8K. P/U 3' and set down 5k to ensure anchor tripped. P/U t/ 3094' (TOW 3075'). S/O and observe shear w/ 28k. P/U-73K, S/O 60K. Begin milling at 3075'. 234GPM=965PSI, 60RPM=5.5-8.9k TQ. P/U-73K, S/O-58K, ROT-66K. While milling hydraulic oil began leaking out of hard line on the derrick for the Top Drive. Field: Beaver Creek Sundry #: State: ALASKA Rig/Service: HEC 169 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Brooks, Phoebe L (OGC) To:Harold Soule Cc:Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: HAK 401 9-3-24 & 9-8-24 Date:Tuesday, October 29, 2024 4:34:08 PM Attachments:Hilcorp 401 09-08-24 Revised.xlsx Hilcorp 401 09-03-24 revised.xlsx Thank you. I’ve attached revised reports to include 250 for the low test pressure and changing the finish date to 9/8/24 on the 9/8/24 report. Please update your copies or let me know if you disagree. Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Harold Soule <hsoule@hilcorp.com> Sent: Tuesday, October 29, 2024 3:58 PM To: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] RE: HAK 401 9-3-24 & 9-8-24 Sorry about that, here are the revised reports Thanks Harold Soule Cell 907-227-9400 From: Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Sent: Tuesday, October 29, 2024 3:30 PM To: Harold Soule <hsoule@hilcorp.com> Subject: [EXTERNAL] RE: HAK 401 9-3-24 & 9-8-24 Harold, %HDYHU&UHHN8QLW 37' revised reports CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. The Valve sizes are missing from both reports; please advise. Thank you, Phoebe Phoebe Brooks Research Analyst Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Harold Soule - (C) <hsoule@hilcorp.com> Sent: Thursday, September 5, 2024 2:22 PM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: HAK 401 9-3-24 Thanks Harold Soule Cell 907-227-9400 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSub m it to :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:401 DATE: 9/8/24 Rig Rep.: Jason Strand Rig Email: jasonstrandiws@gmail.com Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #11921220 Sundry #324-501 Operation: Drilling: Workover: X Explor.: Test: Initial: X Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:250/2500 Valves:250/3000 MASP:1011 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NA Permit On Location P Hazard Sec.NA Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 1P Test Fluid Water Inside BOP 1P FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 0NATrip Tank NA NA Annular Preventer 1 7 1/16" 5M P Pit Level Indicators PP #1 Rams 1 1/16"5M 2 3/8x3 1/P Flow Indicator NA NA #2 Rams 1 Blind P Meth Gas Detector PP #3 Rams 0NAH2S Gas Detector PP #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 1 2 1/16" 5M P Time/Pressure Test Result HCR Valves 1 2 1/16" 5M P System Pressure (psi)3025 P Kill Line Valves 2 2 1/16" 5M P Pressure After Closure (psi)2475 P Check Valve 0NA200 psi Attained (sec)16 P BOP Misc 0NAFull Pressure Attained (sec)36 P Blind Switch Covers: All stations Yes CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.): 6@1700 P No. Valves 8FP ACC Misc 0NA Manual Chokes 2P Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 6 P #1 Rams 7 P Coiled Tubing Only:#2 Rams 4 P Inside Reel valves 0NA #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:3.5 HCR Choke 2 P Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice Yes Date/Time 9-7-24 6:07AM Waived By Test Start Date/Time:9/8/2024 2:30 (date) (time)Witness Test Finish Date/Time:9/8/2024 6:00 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Hilcorp 3.5" test joint used for all tests.Cyle C-10 and retest for passing test, Will Ragsdale/Harold Soule Hilcorp Alaska BCU 09 Test Pressure (psi): Will.Ragsdale@hilcorp.com Form 10-424 (Revised 08/2022)2024-0908_BOP_Hilcorp401_BCU-9 -5HJJ From:McLellan, Bryan J (OGC) To:Scott Warner Subject:RE: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application Date:Monday, September 9, 2024 9:21:00 AM Scott, Hilcorp has approval to set the 2nd plug at 3220’ MD and place 90 feet of cement on top. This plan complies with the regulations which require the plug to be set within 50’ of top perf and dump bail at least 25’ of cement on top. Hilcorp has approval to modify plug set depth within these parameters. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Monday, September 9, 2024 9:16 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application Yes we have that was completed yesterday. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, September 9, 2024 9:15 AM CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. To: Scott Warner <Scott.Warner@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application Scott, Have you already set the plug at 3290’ MD and dump bailed cement on top? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Sunday, September 8, 2024 9:41 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Re: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application Bryan, The procedure had us setting a plug at 3230' but it was very sticky and indicated ratty pipe while logging through that area. We are requesting permission to set the plug at 3220 and pump 90' of cement on top for an estimated toc of 3130'. Kick off point for the rig is 3110' and the whip stock is 20' long. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Cell: (907) 830-8863 Image From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Friday, September 6, 2024 1:59:11 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; jim.regg <jim.regg@alaska.gov> Subject: Re: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application Thank you Bryan. We are finishing up on bc-25 today and will be moving over to bcu-09 starting tomorrow most likely. Thanks again. Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 Image From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, September 6, 2024 1:19 PM To: Scott Warner <Scott.Warner@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application Scott, Hilcorp has verbal conditional approval to begin the work scope included in the sundry submitted on 9/5/24 for this well. Conditions of approval are as follows: BOP test to 3000 psi. Annular test to 2500 psi. Provide 24 hrs notice for witness of CMIT to 3000 psi after setting 2nd CIBP. Provide 24 hrs notice for opportunity to witness cement plug TOC tag. Tag must verify minimum 25' of cement on top of tubing stub. Sundry number is 324-501. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Thursday, September 5, 2024 12:35 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application Bryan, As mentioned on the phone this morning the BCU-09 Sundry was resubmitted. It includes the plan to set two plugs rather than dump bail 155’ of cement. The first plug is requesting a variance since the plug is >50’ above top of perf. We are still working to get a passing pressure test on the plug we set in BCU-25 but as of now we were hoping to move the rig to BCU-09 when complete on 25, pending Sundry approval. Thanks, Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 CAUTION: This email originated from outside the State of Alaska mail system. Do not CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Thursday, September 5, 2024 9:11 AM To: Scott Warner <Scott.Warner@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Cc: Noel Nocas <Noel.Nocas@hilcorp.com> Subject: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application This application has been received for processing. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 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 Grace Christianson at (907-793-1230) or (grace.christianson@alaska.gov). From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Wednesday, September 4, 2024 3:54 PM To: Donna Ambruz <dambruz@hilcorp.com>; AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Noel Nocas <Noel.Nocas@hilcorp.com>; Scott Warner <Scott.Warner@hilcorp.com> Subject: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application click links or open attachments unless you recognize the sender and know the content is safe. Application for Sundry Approval Thank you. Scott Warner Kenai – Operations Engineer Office: (907) 564-4506 Cell: (907) 830-8863 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,881'N/A Casing Collapse Structural Conductor Surface 4,760 psi Intermediate 7,020 psi Production Liner 10,160psi 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 DLH Hydraulic Pkr; N/A 5,410' MD / 5,029' TVD 8,496'5,282'4,901' Beaver Creek Sterling Undefined Gas 13-3/8" 9-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Beaver Creek Unit (BCU) 0920 AAC 25.055 Same ~1011 psi 5,513 & 5,615 Length September 6, 2024 8,881'3,067' 3-1/2" 8,496' Perforation Depth MD (ft): 5,950' 3-1/2" See Attached Schematic 8,160 psi 6,870 psi 116' 5,569' 116' 1,853' Size 116' 7"5,950' 1,853' MD Hilcorp Alaska, LLC Proposed Pools: L-80 TVD Burst 5,430' 1,790' 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 FEDA028083 192-122 50-133-20445-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Warner, Operations Engineer AOGCC USE ONLY 10,530psi Tubing Grade: scott.warner@hilcorp.com 907-564-4506 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): 5,282'; 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior writte n approval. Authorized Name and Digital Signature with Date: 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 By Grace Christianson at 8:59 am, Sep 05, 2024 Noel Nocas (4361) Digitally signed by Noel Nocas (4361) Date: 2024.09.04 15:44:06 -08'00' 324-501 10-407 SFD 9/6/2024BJM 9/6/24 BOP test to 3000 psi. Annular test to 2500 psi. Provide 24 hrs notice for witness of CMIT to 3000 psi after setting 2nd CIBP. Provide 24 hrs notice for opportunity to witness cement plug TOC tag. Tag must verify minimum 25' of cement on top of tubing stub. X Variance to 20 AAC 25.112(c)(1)(e) approved to set 1st cement plug >50' above the top of the Sterling Gas Pool perfs. X Plug to be set 2208' MD above top perf, but below the Sterling Und Gas Perfs. DSR-9/5/24 Yes 9/6/24 Bryan McLellan JLC 9/6/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.09.06 16:32:01 -08'00' 09/06/24 RBDMS JSB 091024 Well Prognosis Well: BCU-09 02/01/2022 Well Name: BCU-09 API Number: 50-133-20445-00-00 Current Status: Shut in Gas Well Permit to Drill Number: 192-122 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP: 1308 psi @ 2972’ TVD Based on 0.44 psi/ft Max. Potential Surface Pressure: 1011 psi Based on 0.1 psi/ft gas gradient to surface Applicable Frac Gradient: 0.62 psi/ft using 12 ppg EMW FIT at the 9-5/8” surface casing shoe Well Status: Shut in gas producer since September 2021 Brief Well Summary BCU-09 was drilled and completed in 1994 targeting the Beluga formation. In the summer of 1998, the Sterling B4 was perfed, allowing the well to flow up the annulus. Additional Beluga sands were added in the Upper Beluga in 2003. This zone watered out and was squeezed off in 2007. The Beluga was isolated in 2013 with a PX plug. In March of 2014 the Sterling B4 loaded up with sand and water. In March of 2014, a rig workover cut and pulled tbg, isolated the Sterling B4, RIH with new 3-1/2” completion string with packer set at 5,410’ MD. The Sterling B3 Lower sand was added. The well came online making 10 MMCFD declining rapidly until it watered out in June 2015. The sterling B3 cum’d just under 3 BCF. In August of 2019, the B3 perfs were isolated and the B3B sand was perforated. The B3B sand produced at rates up to 1-2 MMCFD but also produced water and a large amount of sand. A workover in June 2020 pulled the current packer and gravel packed the B3B sand with a circulating type gravel pack. The well was put online and was making 1500-2000 bwpd with 100-200 mcfd until it finally quit giving up gas and only water after a few weeks. The Sterling D1X sand was perforated in August 2020 which came on strong initially at ~3 mmscfd but watered out over the course of a year before dropping below unloading rate. The purpose of this sundry is to prepare the well for sidetrack now that the well has no further utility in its current state. Notes Regarding Wellbore Condition x Inclination o Max deviation of 32° @ 3,126’ MD o Max DLS of 4.3°/100’ @ 1,147’ MD x Recent Tags o 7/26/24: SL RIH w/ 2.74” GR to 3295’ KB Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low /2,500 psi high 3. RIH and cut tubing at ~3290’ a. Tubing cut right at/above recent slickline tag at 3295’ 4. RDMO EL 5. MIRU 401 workover rig 6. Install TWC, ND tree, NU BOP 7. Test BOPE Well Prognosis Well: BCU-09 02/01/2022 ¾ Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. (Notify AOGCC 24 hours in advance of test to allow them to witness test). ¾ If the BOP is used to shut in on the well in a well control situation or if BOP equipment could be compromised, ALL BOP components utilized for well control or compromised must be tested prior to the next trip into the wellbore. ¾ BOPs will be closed as needed to circulate the well during this workover. 8. Pull TWC 9. Pick up on hanger with short joint 10. Circulate well prior to pulling packer @ 3209’. Bullhead fluid to ensure well is dead 11. Release DLH hydraulic set packer- estimated 46k release 12. Circulate well upon packer release 13. Pull and lay down tubing 14. RU Eline 15. RIH and set 7” CIBP at ~3290’, top of tubing cut 16. Dump bail 25’ of cement on top of 7” CIBP, estimated TOC @ 3265’ a. Variance is being requested to set plug >50’ above top of B3B perforations at 5468’ 17. RIH and set 7” CIBP at 3230’, 5’ above top of D1X perforations 18. RDMO Eline 19. MIT casing and plug to 3000 psi 20. ND BOP, NU dry hole tree 21. RDMO Rig 401 22. RU Eline 23. Dump bail 100’ of cement on top of 7” CIBP, estimated TOC @ 3130’ a. KOP for Sidetrack is planned for ~3110’ 24. RDMO Eline Attachments: 1) Actual Schematic. 2) Proposed Schematic 3) Rig 401 BOP Diagram 7-1/16” 4) AOGCC RWO Change Form Variance approved. -bjm Provide 24 hrs notice for AOGCC opportunity to witness pressure test. -bjm Tag cement to verify TOC. TOC must be at least 25' above plug. Can be done with the rig or wireline. -bjm 1 Size Type Wt Grade Conn. ID Top Btm 13-3/8" Conductor 61 K-55 Surf 116 2 9-5/8" Surf Csg 47 N-80 BTC 8.681" Surf 1,853 7" Prod Csg 29 N-80 BTC 6.184" Surf 5,950 3-1/2" Liner 9.2 L-80 IBT AB- Mod 2.992" 5,814 8,881 3 4 3-1/2" Tubing 9.2 L-80 IBT AB- Mod 2.992" Surf 5,430 D1X Fill Tagged at 3295' 5 No. Depth ID 6 1 1200 2.992" 2 1455 2.992" 7 3 3096 2.992" 4 3209 3.00" B3B 54487 6 5324 3.00" 7 5339 2.813" Sands Top (MD)Btm (MD)Top (TVD) Btm (TVD) Length (ft)Date D1X 3235 3240 2972 2976 5 8/20/20 5468 5498 5087 5117 30 7/5/20 5468 5498 5087 5117 30 8/15/19 5483 5486 5102 5105 3 8/12/19 B3L 5533 5553 5152 5172 20 3/5/14 B4 5629 5637 5248 5256 8 June-98 PBTD 5,282' MD TD 8,881' MD Open Status PERFORATION DETAIL 3-1/2" Liner 6" Hole: 500sxs. Cement from liner top back to surface. GLM #1: Assumed DGLV Chemical injection mandrel Item JEWLRY DETAIL DLH Hydraulic set packer (46k release) DV tool in 7" casing DLH Hydraulic set packer (46k release) X-nipple. Plug installed 8/19/20 capped with 57' cement. ToC = 5,282' MD GLM #2: Assumed DGLV CASING DETAIL CEMENT DETAIL 9-5/8"12-1/4" Hole: 700sxs 7" 8-1/2" Hole: Bottom stage was 90sxs (22bbls) 13# lead, and 125sxs (26.4bbls) 15.5# Class G tail. Upper stage was 350sxs (85 bbls) 13# through DV tool at 4,487' MD. Full returns durring job. 8/30/94 VDL shows ToC above 2800' MD (stopped logging there). B3B Isolated 8/19/20 Isolated 8/19/20 Isolated 8/19/20 Isolated Isolated 8/12/19 Additional perfs on p2 Updated by SRW 09-03-04 4,901' TVD 8,500' TVD Additional jewlry on p2 BC-9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M.Permit #:192-122API #:50-133-20445-00-00 Property Des:FEDA - 028083KB Elevation:23' AGL) TD Reached:8/26/1994 Tree cxn: 6-1/2" Otis SCHEMATIC Sands Top (MD) Btm (MD)Top (TVD)Btm (TVD) Length (ft)Date B4 6429 6459 6048 6078 30 1/12/04 B16 7,420 7460 7039 7079 40 10/2/96 B17 7,534 7574 7153 7193 40 9/30/96 B18 7,640 7660 7259 7279 20 9/28/96 7,705 7725 7324 7344 20 9/26/96 7,725 7755 7344 7374 30 9/25/96 7,762 7812 7381 7431 50 8/13/96 7,812 7842 7431 7461 30 8/9/96 7,852 7882 7471 7501 30 8/7/96 B21 7,893 7933 7512 7552 40 8/5/96 7,980 8030 7599 7649 50 9/25/94 8,036 8054 7655 7673 18 9/24/94 8,072 8098 7691 7717 26 9/24/94 B24 8,167 8187 7786 7806 20 9/18/94 8,241 8246 7860 7865 5 9/16/94 8,254 8261 7873 7880 7 9/16/94 8,276 8292 7895 7911 16 9/16/94 8,399 8409 8018 8028 10 9/15/94 8,432 8452 8051 8071 20 9/15/94 No. Depth ID 5348 5350 5358 5438 5520 5549 5615 5620 5739 5823 2.813" 5828 8808 Isolated Isolated Isolated Isolated Isolated Isolated Isolated Isolated Isolated Isolated ADDITIONAL JEWLRY DETAIL Item Top of gravel pack sand behind screens (7/8/20) Bottom of Gravel Pack assembly CIBP with 36' cement on top (8/12/19) B20 ADDITIONAL PERFORATION DETAIL Status Squeezed 7/28/07 Isolated Isolated Isolated Isolated Isolated Isolated Model N Bridge Plug Overshot (swallowed 2' of hook up nipple) Hook up nipple 4 joints of 4-1/2" screens / blank pipe CIBP Cut 3-1/2" tubing PX plug CMU Sliding Sleeve Model H Liner Top packer B19 B23 B25 B27 Isolated Isolated Size Type Wt Grade Conn. ID Top Btm 13-3/8" Conductor 61 K-55 Surf 116 9-5/8" Surf Csg 47 N-80 BTC 8.681" Surf 1,853 7" Prod Csg 29 N-80 BTC 6.184" Surf 5,950 3-1/2" Liner 9.2 L-80 IBT AB- Mod 2.992" 5,814 8,881 1 2 3-1/2" Tubing 9.2 L-80 IBT AB- Mod 2.992" Surf 5,430 D1X 3 4 5 No. Depth ID 6 13130 23230 33290 B3B 44487 5 5324 3.00" 6 5339 2.813" Sands Top (MD)Btm (MD)Top (TVD) Btm (TVD) Length (ft)Date D1X 3235 3240 2972 2976 5 8/20/20 5468 5498 5087 5117 30 7/5/20 5468 5498 5087 5117 30 8/15/19 5483 5486 5102 5105 3 8/12/19 B3L 5533 5553 5152 5172 20 3/5/14 B4 5629 5637 5248 5256 8 June-98 PBTD 5,282' MD TD 8,881' MD Additional jewlry on p2 4,901' TVD 8,500' TVD Updated by SRW 09-04-24 B3B Isolated 8/19/20 Isolated 8/19/20 Isolated 8/19/20 Isolated Isolated 8/12/19 Additional perfs on p2 CASING DETAIL CEMENT DETAIL 9-5/8"12-1/4" Hole: 700sxs 7" 8-1/2" Hole: Bottom stage was 90sxs (22bbls) 13# lead, and 125sxs (26.4bbls) 15.5# Class G tail. Upper stage was 350sxs (85 bbls) 13# through DV tool at 4,487' MD. Full returns durring job. 8/30/94 VDL shows ToC above 2800' MD (stopped logging there). Isolated TBD Status PERFORATION DETAIL 3-1/2" Liner 6" Hole: 500sxs. Cement from liner top back to surface. 100' of cement. Est TOC = 3130' Item JEWLRY DETAIL CIBP above cut tubing stub w/ 25' cement- Est TOC is 3265' DV tool in 7" casing DLH Hydraulic set packer (46k release) X-nipple. Plug installed 8/19/20 capped with 57' cement. ToC = 5,282' MD CIBP BC-9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M.Permit #:192-122API #:50-133-20445-00-00 Property Des:FEDA - 028083KB Elevation:23' AGL) TD Reached:8/26/1994 Tree cxn: 6-1/2" Otis PROPOSED Sands Top (MD) Btm (MD)Top (TVD)Btm (TVD) Length (ft)Date B4 6429 6459 6048 6078 30 1/12/04 B16 7,420 7460 7039 7079 40 10/2/96 B17 7,534 7574 7153 7193 40 9/30/96 B18 7,640 7660 7259 7279 20 9/28/96 7,705 7725 7324 7344 20 9/26/96 7,725 7755 7344 7374 30 9/25/96 7,762 7812 7381 7431 50 8/13/96 7,812 7842 7431 7461 30 8/9/96 7,852 7882 7471 7501 30 8/7/96 B21 7,893 7933 7512 7552 40 8/5/96 7,980 8030 7599 7649 50 9/25/94 8,036 8054 7655 7673 18 9/24/94 8,072 8098 7691 7717 26 9/24/94 B24 8,167 8187 7786 7806 20 9/18/94 8,241 8246 7860 7865 5 9/16/94 8,254 8261 7873 7880 7 9/16/94 8,276 8292 7895 7911 16 9/16/94 8,399 8409 8018 8028 10 9/15/94 8,432 8452 8051 8071 20 9/15/94 No. Depth ID 5348 5350 5358 5438 5520 5549 5615 5620 5739 5823 2.813" 5828 8808 Model N Bridge Plug Overshot (swallowed 2' of hook up nipple) Hook up nipple 4 joints of 4-1/2" screens / blank pipe CIBP Cut 3-1/2" tubing PX plug CMU Sliding Sleeve Model H Liner Top packer B19 B23 B25 B27 Isolated IsolatedB20 ADDITIONAL PERFORATION DETAIL Status Squeezed 7/28/07 Isolated Isolated Isolated Isolated Isolated Isolated ADDITIONAL JEWLRY DETAIL Item Top of gravel pack sand behind screens (7/8/20) Bottom of Gravel Pack assembly CIBP with 36' cement on top (8/12/19) Isolated Isolated Isolated Isolated Isolated Isolated Isolated Isolated Isolated Isolated 2-1/16" 5M HCR 0.61 0.52 HEIGHT DATA AND WEIGHT DATA 7-1/16" 5M ANNULAR 3.21 4.57 7-1/16" 5M RAMS (PER SET) 1.3 1.3 OPEN AND CLOSE DATA OPEN CLOSE EQUIPMENT HEIGHT 99.09" ADDITION FOR RING GASKETS TOTAL STACK HEIGHT 2 each @ 0.50" 99.59" ϳͲϭͬϭϲΗϱDEEh>Z^,&& Z ^dz> , /',d͗ϯϬ͘ϵΗ t /',d͗ϯϬϰϮ>^ ϳͲϭͬϭϲΗϱDdzW hKW , /',d͗ϰϰ͘ϭϵΗ t /',d͗ϲϰϬϬ>^ ϳͲϭͬϭϲΗϱDdzW h^d< ϳͲϭͬϭϲΗϱDZ/>>/E' ^WKK> , /',d͗ϮϰΗ t /',d͗ϭϲϬϬ>^ </>>^/ ͗Ϯ ,ϮͲϭͬϭϲΗϱDD's ,K< ^/ ͗ϭ ,ϮͲϭͬϭϲΗϱDD's Eϭ ,ϮͲϭͬϭϲΗϱD,Z Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well BCU-09 (PTD 192-122) Sundry #: XXX-XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date Sundry Application Well Name______________________________ (PTD _________; Sundry _________) Plug for Re-drill Well Workflow This process is used to identify wells that are suspended for a very short time prior to being re-drilled. Those wells that are not re-drilled immediately are identified every 6 months and assigned a current status of "Suspended." Step Task Responsible 1 The initial reviewer will check to ensure that the "Plug for Redrill" box in the upper left corner of Form 10-403 is checked. If the "Abandon" or "Suspend" boxes are also checked, cross out that erroneous entry and initial it on the Form 10-403. Geologist 2 If the “Abandon” box is checked in Box 15 (Well Status after proposed work) the initial reviewer will cross out that checkbox and instead, check the "Suspended" box and initial those changes. Geologist The drilling engineer will serve as quality control for steps 1 and 2. Petroleum Engineer (QC) 3 When the RA2 receives a Form 10-403 with a check in the "Plug for Redrill" box, they will enter the Typ_Work code "IPBRD" into the History tab for the well in RBDMS. This code automatically generates a comment in the well history that states "Intent: Plug for Redrill." Research Analyst 2 4 When the RA2 receives Form 10-407, they will check the History tab in RBDMS for the IPBRD code. If IPBRD is present and there is no evidence that a subsequent re-drill has been completed, the RA2 will assign a status of SUSPENDED to the well bore in RBDMS. The RA2 will update the status on the 10-407 form to SUSPENDED, and date and initial this change. If the RA2 does not see the "Intent: Plug for Redrill" comment or code, they will enter the status listed on the Form 10-407 into RBDMS. Research Analyst 2 5 When the Form 10-407 for the redrill is received, the RA2 will change the original well's status from SUSPENDED to ABANDONED. Research Analyst 2 6 The first week of every January and July, the RA2 and a Geologist or Reservoir Engineer will check the "Well by Type Work Outstanding" user query in RBDMS to ensure that all Plug for Redrill sundried wells have been updated to reflect current status. At this same time, they will also review the list of suspended wells for accuracy and assign expiration dates as needed. Research Analyst 2 Geologist or Reservoir Engineer 324-501 SFD 9/6/2024 SFD 9/6/2024 192-122 BEAVER CK UNIT 09 1 Christianson, Grace K (OGC) From:McLellan, Bryan J (OGC) Sent:Friday, September 6, 2024 1:19 PM To:Scott Warner Cc:Donna Ambruz; Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application Scott, Hilcorp has verbal conditional approval to begin the work scope included in the sundry submitted on 9/5/24 for this well. Conditions of approval are as follows: BOP test to 3000 psi. Annular test to 2500 psi. Provide 24 hrs notice for witness of CMIT to 3000 psi after setting 2nd CIBP. Provide 24 hrs notice for opportunity to witness cement plug TOC tag. Tag must verify minimum 25' of cement on top of tubing stub. Sundry number is 324-501. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Thursday, September 5, 2024 12:35 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application Bryan, As mentioned on the phone this morning the BCU-09 Sundry was resubmitted. It includes the plan to set two plugs rather than dump bail 155’ of cement. The first plug is requesting a variance since the plug is >50’ above top of perf. We are still working to get a passing pressure test on the plug we set in BCU-25 but as of now we were hoping to move the rig to BCU-09 when complete on 25, pending Sundry approval. Thanks, ScoƩ Warner 2 Kenai – OperaƟons Engineer Oĸce: (907) 564-4506 Cell: (907) 830-8863 To help protect your priv acy, Microsoft Office prevented automatic download of this picture from the Internet. From: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Sent: Thursday, September 5, 2024 9:11 AM To: Scott Warner <Scott.Warner@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Cc: Noel Nocas <Noel.Nocas@hilcorp.com> Subject: [EXTERNAL] RE: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application This application has been received for processing. Thank you, Grace Christianson Executive Assistant, Alaska Oil & Gas Conservation Commission (907) 793-1230 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 conƱdential 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 Ʊrst saving or forwarding it, and so that the AOGCC is aware of the mistake in sending it to you, contact Grace Christianson at (907-793-1230) or (grace.christianson@alaska.gov). From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Wednesday, September 4, 2024 3:54 PM To: Donna Ambruz <dambruz@hilcorp.com>; AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Noel Nocas <Noel.Nocas@hilcorp.com>; Scott Warner <Scott.Warner@hilcorp.com> Subject: BCU-09 AOGCC 10-403 PTD 192-122 Submitted 09-04-24 - Sundry Application Application for Sundry Approval Thank you. ScoƩ Warner CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 3 Kenai – OperaƟons Engineer Oĸce: (907) 564-4506 Cell: (907) 830-8863 To help protect your priv acy, Microsoft Office prevented automatic download of this picture from the Internet. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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 Displace Fluid 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: 5339, Total Depth measured 8,881 feet 5513 & 5615 feet true vertical 8,500 feet N/A feet Effective Depth measured 5,282 feet 5,410 feet true vertical 4,901 feet 5,029 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2# / L-80 5,430' MD 5,049' TVD Packers and SSSV (type, measured and true vertical depth)DLH Hydraulic Pkr N/A; N/A 5,410' MD 5,029' TVD 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:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 WINJ WAG 0 Water-Bbl MD 116' 1,853' 0 Oil-Bbl measured true vertical Packer 5,569' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Beaver Creek / Sterling Undefined Gas PoolN/A measured TVD Tubing Pressure 3750 Beaver Creek Unit (BCU) 09 N/A FEDA028083 5,950' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 192-122 50-133-20445-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-318 915 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 690 Authorized Signature with date: Authorized Name: 800 Casing Pressure Liner 2,597 0 Representative Daily Average Production or Injection Data 116' 1,853' 5,950' Conductor Surface Intermediate Production Casing Structural 13-3/8" 9-5/8" 7" Length 8,160psi 6,870psi Collapse 4,760psi 7,020psi todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 116' 1,790' t Fra O 6. A G L PG , R d Form 10-404 Revised 3/2020 Submit Within 30 days of Operations Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.09.11 14:11:48 -08'00' Taylor Wellman HEW RBDMS HEW 9/14/2020 DSR-9/15/2020gls 9/16/20 Rig Start Date End Date E-Line 8/19/20 8/20/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-09 50-133-20445-00-00 192-122 08/19/2020 - Wednesday ARRIVE AT BEAVER CREEK, PJSM, PERMIT, SIMOPS W/ E-LINE. ARRIVE AT LOCATION, SPOT EQUIPMENT, RU. PT TO 250 PSI LOW, 2,000 PSI HIGH. TEST GOOD AKE-Line spotted equipment also. RIH W/ 2.5" DD BAILER TO 5,536' KB. W/T, POOH AND had a little water, no solids. RIH W/ 2.70" SWEDGE TO 5,240' KB. FL SEEN AT 4,470' KB. POOH. RIH W/ 3- 1/2" XX PLUG TO 5,353' KB. SET PLUG. POOH there WAS 1400 PSI ON TUBING WHEN PLUG WAS SET. RD, DEPART FIELD. ARRIVE PWL SHOP. STARTED RIG UP AT 1200 HRS. Rig up lubricator and fix the riser leaks when we tried to PT. PT lubricator to 250 psi low and 2,000 psi high. Pressure up lubricator with 1,200 psi before we opened valves each time. MU 2-1/2" x 20' dump bailer and fill up with 17 ppg cement and go down and tag Plug at 5,353' KB. Pick up 14' and dump bail cement on top of plug (13.5' Of Cement per bailer). POOH. Good Dump. 1,400 psi on tubing. Make two more bailer runs 2-1/2" X 20' Bailer filled with 17 ppg cement and dump on top of the first dump. POOH on each dump and both dumps were good. Cement in Place at 1800 hrs and estimated top of cement at 5,313' (40' of cement on top of plug.) 1,400 psi on tubing. Rig down off well and lay lubricator down. Secure Well. Will be back in the morning at 0800 hrs. That should give cement time to cure for at least 13 to 14 hrs before we are ready to pull the trigger. Also will look cement samples over real good. Another good thing in our favor is we are quite away from TOC and where we are going to perf. 08/20/2020 - Thursday Sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT lubricator to 250 psi low and 2,000 psi high. TP - 1,350 psi. Samples 3/4" cured. RIH w/ 2-3/8" x 7' w/HC Razor, 5 spf, 60 deg phase tie into AKE-Line CCL/GR log dated 7/4/20 and tagged TOC at 5,282'. (54' cmt on top of plug). Ran correlation log and send to town. Was told to add 2' to my correlation log. Added 2' tp lop,. bled tubing down to 1,014 psi and spotted gun from 3,235' to 3,240' and fired gun. After 5 min - 1,062 psi, 10 min - 1,087 psi and 15 min - 1,107 psi. POOH. All guns fired and gun was wet. Rig down lubricator and turn well over to field. Daily Operations: Lease: State/Prov:Alaska Country:USA 0º 160' 23' 8/21/2020 8/31/2020Revised By:Donna Ambruz Downhole Revision Date:Schematic Revision Date: Angle @KOP and Depth:Maximum Deviation:32º @ 2,500'Angle/Perfs:8.0º @ 1,000' Date Completed:07/10/20 Ground Level (above MSL):RKB (above GL): Well Name & Number:Beaver Creek Unit #9 A - 028083 County or Parish:Kenai Peninsula Borough Production Seal Unit CMU Sliding Sleeve @ 5,823' MD 2.813" ID Beluga 6,429'-6,459' MD (30') 1/13/2004 Cmt Squeezed Wet Upper Beluga with 10 bbl, 15.8 ppg, 68 sks, of Class G 2,500 psig squeeze 7/28/2007 Model N Bridge Plug @ 8,808' MD BC-9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M.Permit #:192-122 API #:50-133-20445-00-00 Property Des:FEDA - 028083 KB Elevation:183' (23' AGL)Spud Date:7/26/1994 TD Reached:8/26/1994Rig Released:9/5/1994 X:317,605Y:2,434,000Lat:60°39' 30.34" N Long:151°01' 04.48" W Conductor 13-3/8" K-55 61 ppf Top Bottom MD 0' 116' TVD 0' 116' Surface Casing 9-5/8" N-80 47 ppf BTC Top Bottom MD 0' 1,853' TVD 0' 1,790' 12-1/4" hole Cmt w/ 700 sks Intermediate Casing 7" N-80 29 ppf BTC Top Bottom MD 0' 5,950' TVD 0' 5,569' 8-1/2" hole Cmt w/ 565 sks, in two stages w/ DV tool @ 4,487' MD Liner 3-1/2" N-80 9.2 ppf AB-Mod IBT Top Bottom MD 5,814' 8,881' TVD 5,433' 8,496' 6" hole Cmt w/ 500 sks, 150 sks to surface TD 8,881' MD 8,500' TVD PBTD 5,282' MD 4,901' TVD Tubing 3-1/2" L-80 9.2 ppf IBT AB-Mod Top Bottom MD 0' 5,430' TVD 0' 5,049' Model H liner hanger packer @ 5,828' MD D1X B3B B3B B3B B3L B4 B4 B16 B17 B18 B19 B20 B21 B23 B24 B25 B27 Date 8/20/20 7/5/20 8/15/19 8/12/19 3/05/14 (6/?/98) Date (1/12/04) (7/28/07) (10/2/96) (9/30/96) (9/28/96) (9/26/96) (9/25/96) (8/13/96) (8/9/96) (8/7/96) (8/5/96) (9/25/94) (9/24/94) (9/24/94) (9/18/94) (9/16/94) (9/16/94) (9/16/94) (9/15/94) (9/15/94) Gun Type 2-3/8" HC, 6 SPF 3-3/8" HC, 6 SPF 2-3/8" HC, 6 SPF 2-3/8" HC, 6 SPF 2-1/2" HC, 12 SPF2" Scallop, 6 SPF Gun Type 2-3/8", 60º, 4 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF TVD 2,972' - 2,976' 5,087' - 5,117' 5,087' - 5,117' 5,102' - 5,105' 5,152' - 5,172' 5,248' -5,256’ TVD 6,048'-6,078' (Cement squeezed) 7,039'-7,079' 7,153'-7,193' 7,259'-7,279' 7,324'-7,344' 7,344'-7,374' 7,381'-7,431' 7,431'-7,461' 7,471'-7,501' 7,512'-7,552' 7,599'-7,649' (Fracture Treated) 7,655'-7,673' (Fracture Treated) 7,691'-7,717' 7,786'-7,806' 7,860'-7,865' 7,873'-7,880' 7,895'-7,911' 8,018'-8,028' 8,051'-8,071' ft 5' 30' 30' 3' 20' 12' ft 30' 40' 40' 20' 20' 30' 50' 30' 30' 40' 50' 18' 26' 20' 5' 7' 16' 10' 20' MD 3,235' - 3,240' 5,468' - 5,498' 5,468' - 5,498' 5,483 -5,486' 5,533'-5,553' 5,629'-5,637’ MD 6,429'-6,459' 7,420'-7,460' 7,534'-7,574' 7,640'-7,660' 7,705'-7,725' 7,725'-7,755' 7,762'-7,812' 7,812'-7,842' 7,852'-7,882' 7,893'-7,933' 7,980'-8,030' 8,036'-8,054' 8,072'-8,098' 8,167' -8,187' 8,241'- 8,446' 8,254'-8,261' 8,276'-8,292' 8,399'-8,409' 8,432'-8,452' Sterling Perforations: Beluga Perforations: Tree cxn: 6-1/2" Otis SCHEMATIC PX Plug @ 5,739' MD Tag Fill @ 5,703' MD on 2/18/14Cut Tubing @ 5,620' MD Completion Assembly 07/10/20 Includes: 1 - #2 Gaslift Mandrel 1,200' MD 2 - Chemical Injection Mandrel 1,455' MD (Valve 3/1/14) 3 - #1 Gaslift Mandrel 3,096' MD 4 - DLH Hydraulic Packer 3,209' MD 5 - DLH Hydraulic Packer 5,324' MD 6 - X Landing Nipple 5,339' MD (XX Plug Installed 8/19/2020) w/ ±57' of cement 7 - GP Screens 5,438' MD 8 - GP Bull Plugs 5,519' MD 9 - Bridge Plug 5,549' MD 7/23/19 w/ 36' of cement (TOC 5,513') 8/12/19 10 - Bridge Plug 5,615' MD B4 B3L 2 3 5 6 7 10 B3B 9 8 Top of Gravel @ 5,438' MD 07/08/20 4 1 D1X Top of Cement @ 5,282' MD 08/20/2020 new perfs 3235-40' y - X Landing Nipple 5,339' MD (XX Plug Installed 8/19/2020)n g3 9gpp , ( g // )gpp w/ ±57' of cement5 7/5/20/8 HC, 6 SPF2-3// 3 3/8" HC 6 SPF/ ,, 7'5,087' - 5,1177 ate 8/20/20Gun Type /8" HC 6 SPF23//62,972 -2,97662 972' 2 976'62 972' 2 976' 7) 6 8 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: Gravel Pack Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 8,881 feet 5513 & 5615 feet true vertical 8,500 feet N/A feet Effective Depth measured 5,513 feet 5,410 feet true vertical 5,132 feet 5,029 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2# / L-80 5,430' MD 5,049' TVD Packers and SSSV (type, measured and true vertical depth)DLH Hydraulic Pkr N/A; N/A 5,410' MD 5,029' TVD 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 WINJ WAG 0 Water-Bbl MD 116' 1,853' 0 Oil-Bbl measured true vertical Packer 5,569' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Beaver Creek / Beluga - Sterling GasN/A measured TVD Tubing Pressure 2000 Beaver Creek Unit (BCU) 09 N/A FEDA028083 5,950' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 192-122 50-133-20445-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-208 169 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 1,600 Authorized Signature with date: Authorized Name: 700 Casing Pressure Liner 632 0 Representative Daily Average Production or Injection Data 116' 1,853' 5,950' Conductor Surface Intermediate Production Casing Structural 13-3/8" 9-5/8" 7" Length 8,160psi 6,870psi Collapse 4,760psi 7,020psi tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 116' 1,790' 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 2:23 pm, Jul 31, 2020 ggDigitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.07.31 14:16:35 -08'00' Taylor Wellman RBDMS HEW 8/3/2020 DSR-8/3/2020 SFD 7/31/2020 Gravel Pack gls gls Rig Start Date End Date Rig 401 6/27/20 7/12/20 06/30/2020 - Tuesday Open well, SITP = 0 PSI, SICP = 0 PSI. IA had slight blow then static. Tbg was on a vacuum. Fill tbg with 10 bbls of kcl, hook up to IA & fill annulus with 4 bbls. Both on vacuum. Set bpv same. N/D production tree, P/U & N/U 7" x 13" adaptor spool, mud cross, 13" double ram bop, & 13" annular, torque all flanges same. N/U choke & kill lines, lay out & hook up Koomey lines, pressurize Koomey system & function bop. R/U rig floor, hand rails, & stairs. P/U & land 2-7/8" test joint assembly. Test Annular to 250 low/3,500 high, Test vbr rams with 2-7/8" tbg, test choke manifold, hcr & manual valves all to 250/3,500 on chart for 5 minutes each test. Pull 2-7/8" test joint. Test blind rams to 250/3,500, held same. Perform Koomey draw down test. 200 psi attained in 19 seconds, full recovery in 95 seconds. Attempt to land 3.5" test joint assembly, unable to pass blind rams. Drain bop stack & found that off driller blind ram block stuck in closed position. Function blind rams twice, unable to open off driller side ram block. Call out Weatherford bop rep to be out in morning. Close blind rams & lock in same. 06/27/2020 - Saturday 06/29/2020 - Monday Open well, Tubing on slight vac, IA @900 PSI. attempt to bleed off IA, pressure came up to 1,300 PSI. Shut in IA, tubing slightly blowing. shut well in and discuss w/ engineer. Decision made to have Pollard pull orifice valve. R/U Pollard wireline. RIH w/ 2.73 gauge ring t/ 5,430'. POOH. P/U and RIH w/ 2.73 orifice catcher cage and set at 5,396'. POOH w/ same. P/U 1.24" JDS running tool and RIH t/ 5,381' latch and jar 1 time. Tool came free, POOH found JDS sheared pin. Re- pinned tool and RIH t/ 5,381', latch orifice, work and jar free. POOH w/ orifice recovery. RIH, retrieve orifice catcher cage @ 5,396'. POOH w/ same, R/D Pollard, equalize to well, pump down tbg at 2bbl/min catching returns up IA through the choke, water/gas returns. Total of 262BBLs pumped, clean fluid returns. shut in well, monitor. Shut in csg and tbg pressure @ 230psi and falling @1800hrs. Secure well, allow to stabilize over night. Hold PJSM. Cont. Nipple up tree and set test plug. Test tree to 5,000 psi. Test good. Load 401 Carrier on trailer and prep rig components for rig move. Clean up pad and mobilize to BCU-09. Lay pit liner, spot sub and carrier in place. Level carrier on base beam. Chain was used to hold stomper beam stable while spotting rig by wrapping around beam and A- frame cross member. The chain was not removed before leveling and caused minor damage to cross member. Notified town and Hilcorp inspector Phil Pihjan. Secure rig for the night. Phil came out and looked at damage and gave permission to continue on. 06/28/2020 - Sunday Perform derrick pre lift inspection, raise & fully scope derrick. Secure guy wires, R/U electrical wiring, pump lines, fill active pit with 300 bbls of water & blend clay stab to make 6% kcl, hook up gas sensors & pvt system, R/U choke line & gas buster lines, finish building containment. Open well, sitp = 700 psi, IA pressure = 1,700 psi. N/U 3-1/16" x 2" 1502 flange to production tree, R/U pump lines to tbg & csg. Equalize pump line to IA & open same, pump 86 bbls of 6% kcl down annulus until full. Shut IA in with 2,000 psi on casing. Equalize to tbg & open same, fill & bullhead total of 60 bbls, final injection rate of 2 bpm @ 2,050 psi. Monitor tbg for 15 minutes, pressure fell to 1100 psi & dropping. SICP = 2,250. Secure well & rest crew. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-09 50-133-20445-00-00 192-122 y. Test Annular to 250 low/3,500 high, Test vbr rams with 2-7/8" tbg, test choke manifold, hcr & manual valves all to 250/3,500 on chart for 5 minutes each test. Pull 2-7/8"test joint. Test blind rams to 250/3,500, held same. kill well by circulating BOP test Equalize pump line to IA & open same, pump 86 bbls of 6% kcl down annulus until full. Shut IA in with 2,000 psi on casing. Equalize to tbg & open same, fill & bullhead total of 60 bbls, final injection rate of 2 bpm @ 2,050 psi. Monitor tbg for 15 minutes, pressure fell to 1100 Decision made to have Pollard pull orifice o well, pump down tbg at 2bbl/min catching returns up IA through the choke, water/gas returns. Total of 262BBLs pumped, clean fluid return Rig Start Date End Date Rig 401 6/27/20 7/12/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-09 50-133-20445-00-00 192-122 07/01/2020 - Wednesday Hold prejob meeting with Weatherford rep & rig crew. Open off driller side blind ram bonnet. Found male hydraulic fitting damaged on inside of bonnet door. Repaired & closed bonnet door. Function tested blind rams in the open/closed position several times with no further issues. Retest blind rams to 250 low/3,500 held same, P/U 3.5" test jt assembly & M/U into hanger. Test VBR to 250 low/3,500 high. Held same. Install landing joint, back out hold down pins, P/U on tbg, hanger off tbg spool @ 42k, pull to 62k & packer come free. Close annular & circulate 200 bbls down tbg & up annulus pumping 3.5 bpm @200 psi. Clean bottoms up, no gas returns. Pull hanger to rig floor & L/D same R/U foster tongs, P/U short bails to L/D tbg & prep rig floor to POOH laying down 3.5" IBT tbg POOH with 20 jts of 3.5" production tbg dragging packer 5 - 15k over string weight up hole., Foster tongs unable to break connections. R/D foster tongs & R/U McCoy tongs. Continue POOH with 3.5" IBT tbg & spooling 1/4" chemical injection line. Lost over pull after 33 jts. L/D total of 70 jts, (1) GLV, (1) chemical injection mandrel. Secure well & rest crew. EOT depth @ 1800 hrs = 3,059'. 07/02/2020 - Thursday Hold PTSM & review jsa's w/personnel Open well, well on vacuum. Continue POOH with 3.5" IBT tbg to surface. Break & L/D packer assembly. Total of 172 jts, (2) GLV'S), (1) Chemical injection mandrel, & (1) packer POOH. R/D Mccoy tongs & R/U Foster tongs, Change slip dyes from 3.5" to 2-7/8". Load pipe racks with 2-7/8" work string, slm same. Change out elevators, handling tools, & tiw to 2-7/8". Release rental filter pod & replace with Hilcorp owned filter pod. R/U 3" filter lines P/U 6-1/8" Varel mill tooth bit with casing scraper, TIH picking up & drifting 2-7/8" ph-6 work string to 5,339'. Secure well & rest crew for night. 07/03/2020 - Friday Held PTSM & review jsa's w/personnel Open well, well on vacuum. TIH picking up 2-7/8" ph-6 tbg & tag @ 5,473' KB measurements. R/U to wash, fill hole with 17 bbls, break circulation & wash from 5,473' to 5,474'. Tagging solid @ 5,474'. Unable to make hole. Discuss with management. Decision made to circulate hole clean & POOH. Circulate 200 bbls pumping down tbg & taking returns up annulus. Clear clean returns after 175 bbls pumped. R/D Kelly hose & prepare to POOH. POOH F/5,474' KB measurements to surface. Total of 90 stds racked in derrick. Break & L/D bit & scraper. Secure well, AK E-line to be on location @ 0530 hrs to perforate. 07/04/2020 - Saturday Held PTSM & review jsa's w/personnel Spot & R/U AK E-line unit & lubricator. P/U CCL/GAMMA combo, test lubricator to 250/2,500 psi. RIH & tag @ 5,469' (corrected depth per Ben Sikes). Log 500', POOH to surface. R/D AK E-line P/U 6- 1/8" Varel mill tooth bit, 7" csg scraper, & 2-7/8" pup jt. BHA lengh = 15.52'. TIH with 2-7/8" ph-6 work string to 5,474'. Tag same. L/D tag joint R/D Foster tongs, l/d elevators, hook up stiff lines, P/U power swivel, R/U manual BJ tongs, M/U 3.5" IF x 2-7/8" x-o to power swivel. Mix 300 bbls of 6% kcl, M/U tag joint to power swivel Pump10 bbls & establish circulation. Increase pump rate to 3 bpm. Drill bridge F/5,474' T/5,475', pumping 3 bpm @ 825 psi, 65 rpm with 1k - 1500k torque, 2-4k ob bit. Broke through bridge and wash/ream sand F/5,475' T/5,490' KB measurements. Circulate (1) surface to surface. Gas returns on bottoms up. P/U to 5,460'. Scale & sand inside of return pan. Secure well & rest crew. Pull hanger to rig floor & L/D same R/U foster t Rig Start Date End Date Rig 401 6/27/20 7/12/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-09 50-133-20445-00-00 192-122 07/05/2020 - Sunday Held PTSM & review jsa's w/personnel Open well, well on vacuum. Pump 14 bbls of fluid to break circulation. RIH to 5,577' & tag bridge, wash through same. Continue washing & reaming to 5,520' KB measurements (46' from original tag). Tag cmt same. Circulate 1.5 hole volumes (300 bbls) pumping 3 bpm @ 670 psi, clean returns. R/D power swivel & prepare to POOH. POOH with 2-7/8" ph-6 tbg slowly & using continuous fill not to swab in sand. L/D bit & scraper. Spot & R/U AK E-line, N/U 13-5/8" X 7-1/16" adaptor with shooting flange. P/U lubricator & make up gun assembly #1 Test lubricator to 250/2,500, open well & RIH with 3-3/8" perf guns loaded with 6 spf by 20' of guns .74 hole diameter & 60 degree phasing T/5,516', tag same. Log to 5,200', tie in & send to Ben Siks to confirm. Wireline on depth. Lower guns & perforate from 5,478' to 5,498'. POOH & L/D spent guns. P/U Gun #2, 10' of 3-3/8" perf guns loaded 6 spf, 60 degree phasing, .74 hole diameter. RIH & log on depth. Attempt to perforate from 5,468' to 5,478'. Guns misfired. No current to guns. POOH same. Repair broken wire in firing head. RIH same with gun #2, run #2. Log on depth. Attempt to fire guns with no success. POOH to surface. Break down gamma, ccl, & detonator tools. check current in all. All checked good. Make up tools same. RUN #3 with gun assembly #2. RIH & log on depth, attempt to fire guns with no success. POOH, surface test tools layed on ground, test good, P/U tools in air & test, tested good. L/D tool assembly. Order out new tool assembly from cable head down. Secure well & rest crew. 07/06/2020 - Monday Held PTSM &review JSA'S w/personnel. P/U gun assembly #2 Run #4. 10' of 3-3/8" big hole guns, 6 spf, 60 degree phasing, (.74 hole diameter). RIH & log on depth. Perforate from 5,468' to 5,478'. Guns fired. POOH & R/D AK E-line. P/U 2-7/8" ph-6 mule shoe & TIH to 5,520'. Tag same, space out & set mule shoe on bottom @ 5,520'. Spot sand pods, R/U pump iron from primary & secondary pumps to sand pods, R/U pump hoses on down stream side. Test all pump lines to 2,500 psi. Prepare to flush tbg with sand sweep. Break circulation with 23 bbls, Pump 200 lbs of sand & displace down tbg with 28 bbls, pumping 2.5 bpm @ 325 psi. Reverse circulate sand from tbg pumping 2.5 bpm @ 360 psi, resturns @ 1.2 bbls. Increase pump rate to 3 bbls per minute, returns @ 1.8 bpm. Reverse circulate 63 bbls, clean returns. POOH to 5,383' & R/U Kelly hose. Establish injection rate. 1 BPM @ 200 PSI, 2 BPM @ 580 PSI. Pump 800 lbs of 20-40 sand pumping 2 bpm, final injection after sand to perf = 580 psi. Load sand pods with 800 lbs of 20-40 sand. Pump sand to perfs, Sand out pumping 2 bpm @1600 psi. All sand placed into perfs. Shut pump down & allow to bleed to 250 psi, Re- stress formation pumping 2 bpm, pump 12 bbls & pressure out @ 1,600 psi. Allow pressure to fall to 250 psi, pump 6 bbls @ 2 bpm & pressure out @ 1,600 psi. R/D Kelly hose. TIH & tag @5,469'. POOH to 5,383', Secure well & rest crews. perf well with bighole guns P/U lubricator & make up gun assembly #1 Test lubricator to 250/2,500, open well & RIH with 3-3/8" perf guns loaded with 6 spf by 20' of guns .74 hole diameter & 60 degree phasing T/5,516', tag same. Log to 5,200', tie in & send to Ben Siks to confirm. Wireline on depth. Lower guns & perforate from 5,478' to 5,498'. POOH & L/D spent guns. P/U Gun #2, 10' of 3-3/8" perf guns loaded 6 spf, 60 degree phasing, .74 hole diameter. RIH & log on depth. Attempt to perforate from 5,468' to 5,478'. Guns misfired. No current to Rig Start Date End Date Rig 401 6/27/20 7/12/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-09 50-133-20445-00-00 192-122 07/07/2020 - Tuesday Hold PTSM &review jsa's with personnel. Fill hole with 6.7 bbls to fill. break circulation pumping 2.5 bpm @360 psi down tbg taking returns up annulus. Wash from 5,469' to 5,475'. Break through bridge & continue washing to 5,520'. Reverse circulate @2.5 bpm &350 psi. Total of 375 bbls while waiting on storm packer, approximately 400 lbs of sand circulated out. POOH F/5,520' T/5,148', P/U Tripoint storm packer with check valve insert. TIH to 5,270', set packer & release same hanging tbg off @ 120' below tbg hanger. POOH with 2 stands of tbg. Test packer to 1,000 psi. held same Land test sub with 2-7/8" test joint, run in hold down pins, & prepare to test bope Test Annular to 250 low/2,500 high, Test vbr rams with 2-7/8" tbg, test choke manifold, hcr & manual valves all to 250/3,500 on chart for 5 minutes each test. Pull 2-7/8" test joint. Test blind rams to 250/3,500, held same. Perform Koomey draw down test,. 200 psi attained in 17 seconds, full recovery in 83 seconds. Attempt to land 3.5" test joint assembly, unable to pass vbr rams. Off driller side vbr ram cylinder not opening. Open ram door, hydraulic connection on inside of bonnet door not making connection with hydraulic fitting on main ram body. Weatherford tech repaired & re-sealed door. Test VBR rams with 3.5" tbg to 250/3,500 on chart for 5 minutes. Perform choke test. Back out hold down pins & pull test plug. Secure well & rest crews. 07/08/2020 - Wednesday Hold PTSM & review jsa's with personnel. Open well, TIH with 2 stds of 2-7/8" work string to top of packer, sting in & screw into top of packer opening bypass. Well on a vacuum. Unset packer & fill hole with 7.5 bbls of KCL. POOH to surface with packer & L/D same. TIH to 5,520' with no sand fill noted. POOH with 2-7/8" work string from 5,520' to surface using continuous hole fill to reduce sand fill. L/D muleshoe. L/D foster tongs, R/U McCoy tongs, change out handling equipment to P/U 4.5" gravel pack screens. P/U 80' of 4.5" ltc Delta Elite gravel pack screen, 80' of 4.5" ltc centralized blank pipe, 4.5" hookup nipple, 3.5" clutch joint, ball seat sub, lower circulating sub, 2-7/8" pup jt, 7" JS 29# gravel pack packer, upper circulation sub, seal sub, x-o sub, & 2-7/8" pup jt. Total bha = 192.74. Total screen & blank lengh = 161.84' Change handling tools to 2-7/8", L/D McCoy tongs, P/U Foster tongs, prepare to TIH with 2-7/8" work string. TIH with gravel pack screens on 2-7/8" 7.9# ph-6 work string, 1 minute/stand to 5,495' KB measurements. Tag same. Discuss options with upper management. Decision made to POOH & run bit, scraper, & string mill clean out run. POOH with 2-7/8" work string to 2,465'. Secure well & rest crew. insert. TIH to 5,270', set packer & release same TIH with gravel pack screens on 2-7/8" 7.9# ph-6 work string, prepare to TIH with 2-7/8" work P/U Tripoint storm packer with check valve Rig Start Date End Date Rig 401 6/27/20 7/12/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-09 50-133-20445-00-00 192-122 07/09/2020 - Thursday Hold PTSM & review jsa's with personnel. Open well, fill hole with 14 bbls of kcl, continue POOH with 2-7/8" tbg from 2,465' to screen assembly. R/D foster tongs, R/U McCoy tongs, change out handling tools to L/D screen assembly. L/D packer assembly, 1.5" wash pipe, blank & screen assembly. Found scarring on lower centralizers from tag. R/D McCoy tongs, R/U foster tongs, change out handling tools to TIH with 2-7/8" work string. P/U bha #3, 6-1/8" bit, 7" casing scraper, 6' pup, 6-1/16" string mill, & 10' pup jt. BHA lengh = 30.85'. TIH with 2-7/8" work string to 5,492'. Perforations rough. work casing scraper in/out of perfs until smooth slack off & pick up is obtained. Lower tubing & tag PBTD @ 5,520', no sand fill noted. Reverse circulate 77 bbls of kcl pumping 3 bpm with 400 psi, small metal pieces attached to magnet on bottoms up. POOH with 2-7/8" work string from 5,520' to surface using continuous fill to minimize sand fill. L/D bit, casing scraper, & string mill. Change out handling tools, clean box & pin ends of screens, L/D foster tongs & P/U McCoy tongs. P/U 80' of 4.5" ltc Delta Elite gravel pack screen, 80' of 4.5" ltc centralized blank pipe, 4.5" hookup nipple, 3.5" clutch joint, ball seat sub, lower circulating sub, 2-7/8" pup jt, 7" JS 29# gravel pack packer, upper circulation sub, seal sub, x-o sub, & 2-7/8" pup jt. Total bha = 192.74. Total screen & blank lengh = 161.84' TIH with gravel pack assembly on 2-7/8" ph-6 work string to 5,520'kb measurements. Tag same. Close clutch joint. Set packer & test to 1000 psi, Held same. Hold PJSM, Establish circulating rates, 1 bpm @ 90 psi, 2 bpm @330 psi. Load sand pods with 600 lbs of 20/40 sand, pump down hole @ 2 bpm, sand to screen with no pressure change, reload pod with 200 lbs of 20/40 sand, pump down @ 2 bpm, sand to screen. Achieve screen out 2 bpm @1450 psi. Restress pack (2) times allowing pressure to fall to 0 psi & pumping 1/2 bbl each stress to pressure up to 1,400 psi. Release packer & fully stroke clutch joint, Release from hook up nipple & strip out 1.5" wash pipe racking 2-7/8" tbg in derrick. Spot & R/U L/D machine, prepare to POOH laying down 2-7/8" work string. POOH laying down 2-7/8" work string. Depth @ 0530 hrs = 4,136'. 07/10/2020 - Friday Hold PTSM & review jsa's with personnel Continue POOH laying down 2-7/8" work string to gravel pack packer assembly. L/D packer assembly & 1.5" wash pipe . RIH with 8 stds of 2-7/8" work string from derrick, POOH & L/D same. Remove all gravel pack handling tools from rig floor, R/D power swivel, break x-o subs on power swivel, R/D gravel pack pods, hoses & transfer pump, load out same. P/U 3.5" completion handling tools, elevators, & M/U X-O for tiw valve. Lay out 3.5" completion string, mark make up diamonds on pin & slm same. P/U Tripoint lower production packer assembly, M /U to 3.5" IBT production tbg & RIH. Continue TIH with 3.5" tbg to 978'. Secure well & rest crew. P/U 3.5" completion handling tools, elevators, & M/U X-O for tiw valve. Lay out 3.5" completion string, mark make up diamonds on pin & slm same. P/U Tripoint lower production packer assembly, M /U to 3.5" IBT production tbg & RIH. Continue TIH with 3.5" tbg to 978'. Secure well & rest crew. Total bha = 192.74. Total screen & blank lengh = 161.84' TIH with gravel pack assembly on 2-7/8" ph-6 work string to 5,520'kb measurements. Tag same. Close clutch joint. S Rig Start Date End Date Rig 401 6/27/20 7/12/20 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name BCU-09 50-133-20445-00-00 192-122 07/11/2020 - Saturday Hold PTSM & review JSA'S with personnel. Continue picking up 3.5" IBT modified production tbg picking up (2) GLV'S & (1) Chemical injection mandrel. to top of hook up nipple @ 5,352', space out, tie in chemical injection line to tbg hanger & land out same swallowing 2' of hook up nipple. Run hold down pins in, drop bar, allow to fall, pressure up on tbg. to 3500 for 30min setting (2) Tripoint hydraulic set packers, bleed of same. perform MT-IA t/ 2,000psi and chart for 30min, held same. Chart in "O" drive Remove landing jt. install BPV, L/D elevators and bails, R/D hand rails, tongs, stairs and rig floor. Bleed down koomey unit, disconnect BOP hyd lines, N/D choke and kill lines. N/D hydril, double gate bop, and mud cross. L/D same N/U production tree, test void t/ 5,000psi, test production tree t/ 5,000psi. Pull BPV and secure well. 07/12/2020 - Sunday Hold PTSM & review JSA'S with personnel. Haul off 230 bbls of kcl to disposal, Clean sand from return tanks. R/D pumps & lines. R/D electrical, pvt, & gas detection system. Perform derrick inspection, scope in & lay down derrick onto carriage. Wrap cables & prep rig for road transport. Load out all connex & equipment onto trailers. Pick up herculiner & clean location. Transport loader to Frances 1 pad. Run hold down pins in, drop bar, allow to fall, pressure up on tbg. to 3500 for 30min setting (2) Tripoint hydraulic set packers, bleed of same. perform MT-IA t/ 2,000psi and chart for 30min, Pull BPV and secure well. Lease: State/Prov:Alaska Country:USA 0º 160' 23' 7/10/2020 7/24/2020 07/10/20 Ground Level (above MSL): RKB (above GL): Well Name & Number:Beaver Creek Unit #9 A - 028083 County or Parish:Kenai Peninsula Borough Revised By:Donna Ambruz Downhole Revision Date: Schematic Revision Date: Angle @KOP and Depth: Maximum Deviation:32º @ 2,500'Angle/Perfs:8.0º @ 1,000' Date Completed: Production Seal Unit CMU Sliding Sleeve @ 5,823' MD 2.813" ID Beluga 6,429'-6,459' MD (30') 1/13/2004 Cmt Squeezed Wet Upper Beluga with 10 bbl, 15.8 ppg, 68 sks, of Class G 2,500 psig squeeze 7/28/2007 Model N Bridge Plug @ 8,808' MD BC-9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M.Permit #: 192-122 API #: 50-133-20445-00-00 Property Des: FEDA - 028083 KB Elevation: 183' (23' AGL)Spud Date: 7/26/1994 TD Reached: 8/26/1994Rig Released: 9/5/1994 X: 317,605Y: 2,434,000Lat: 60° 39' 30.34" N Long: 151° 01' 04.48" W Conductor 13-3/8" K-55 61 ppfTop Bottom MD 0' 116' TVD 0' 116' Surface Casing 9-5/8" N-80 47 ppf BTC Top Bottom MD 0' 1,853' TVD 0' 1,790' 12-1/4" hole Cmt w/ 700 sks Intermediate Casing 7" N-80 29 ppf BTCTop Bottom MD 0' 5,950' TVD 0' 5,569' 8-1/2" hole Cmt w/ 565 sks, in two stages w/ DV tool @ 4,487' MD Liner 3-1/2" N-80 9.2 ppf AB-Mod IBT Top Bottom MD 5,814' 8,881' TVD 5,433' 8,496' 6" hole Cmt w/ 500 sks, 150 sks to surface TD 8,881' MD 8,496' TVD PBTD 5,513' MD 5,132' TVD Tubing 3-1/2" L-80 9.2 ppf IBT AB-Mod Top Bottom MD 0' 5,430' TVD 0' 5,049' Model H liner hanger packer @ 5,828' MD B3B B3B B3B B3L B4 B4 B16 B17 B18 B19 B20 B21 B23 B24 B25 B27 Date 7/5/20 8/15/19 8/12/19 3/05/14 (6/?/98) Date (1/12/04) (7/28/07) (10/2/96) (9/30/96) (9/28/96) (9/26/96) (9/25/96) (8/13/96) (8/9/96) (8/7/96) (8/5/96) (9/25/94) (9/24/94) (9/24/94) (9/18/94) (9/16/94) (9/16/94) (9/16/94) (9/15/94) (9/15/94) Gun Type 3-3/8" HC, 6 SPF 2-3/8" HC, 6 SPF 2-3/8" HC, 6 SPF 2-1/2" HC, 12 SPF2" Scallop, 6 SPF Gun Type 2-3/8", 60º, 4 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF TVD 5,087' - 5,117' 5,087' - 5,117' 5,102' - 5,105' 5,152' - 5,172' 5,248' - 5,256’ TVD 6,048'-6,078' (Cement squeezed) 7,039'-7,079' 7,153'-7,193' 7,259'-7,279' 7,324'-7,344' 7,344'-7,374' 7,381'-7,431' 7,431'-7,461' 7,471'-7,501' 7,512'-7,552' 7,599'-7,649' (Fracture Treated) 7,655'-7,673' (Fracture Treated) 7,691'-7,717' 7,786'-7,806' 7,860'-7,865' 7,873'-7,880' 7,895'-7,911' 8,018'-8,028' 8,051'-8,071' ft 30' 30' 3' 20' 12' ft 30' 40' 40' 20' 20' 30' 50' 30' 30' 40' 50' 18' 26' 20' 5' 7' 16' 10' 20' MD 5,468' - 5,498' 5,468' - 5,498' 5,483 -5,486' 5,533'-5,553' 5,629'-5,637’ MD 6,429'-6,459' 7,420'-7,460' 7,534'-7,574' 7,640'-7,660' 7,705'-7,725' 7,725'-7,755' 7,762'-7,812' 7,812'-7,842' 7,852'-7,882' 7,893'-7,933' 7,980'-8,030' 8,036'-8,054' 8,072'-8,098' 8,167' -8,187' 8,241'- 8,446' 8,254'-8,261' 8,276'-8,292' 8,399'-8,409' 8,432'-8,452' Sterling Perforations: Beluga Perforations: Tree cxn: 6-1/2" Otis SCHEMATIC PX Plug @ 5,739' MD Tag Fill @ 5,703' MD on 2/18/14Cut Tubing @ 5,620' MD Completion Assembly 07/10/20 Includes: 1 - #2 Gaslift Mandrel 1,200' MD 2 - Chemical Injection Mandrel 1,455' MD (Valve 3/1/14) 3 - #1 Gaslift Mandrel 3,096' MD 4 - DLH Hydraulic Packer 3,209' MD 5 - DLH Hydraulic Packer 5,324' MD 6 - X Landing Nipple 5,339' MD 7 - GP Screens 5,438' MD 8 - GP Bull Plugs 5,519' MD 9 - Bridge Plug 5,549' MD 7/23/19 w/ 36' of cement (TOC 5,513') 8/12/19 10 - Bridge Plug 5,615' MD B4 B3L 2 3 5 6 7 10 B3B 9 8 Top of Gravel @ 5,438' MD 07/08/20 4 1 Top of Gravelp @ 5,438' MD@, 07/08/20 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): Beaver Creek / Sterling Undefined Gas Pool 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,881'N/A Casing Collapse Structural Conductor Surface 4,760 psi Intermediate 7,020 psi Production 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: Todd Sidoti 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 todd.sidoti@hilcorp.com 8,496'5,513'5,132'1,574 5,513 & 5,615 DLH Hydraulic packers 5410' MD (5029' TVD) 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 FEDA028083 192-122 50-133-20445-00-00 Beaver Creek Unit (BCU) 09 Length Size CO 237B Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY L-80 TVD Burst 5430' MD 8,160 psi 6,870 psi 116' 1,790' 5,569' 116' 1,853' 13-3/8" 9-5/8" 116' 7"5,950' 1,853' Perforation Depth MD (ft): 5,950' See Attached Schematic Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: August 15, 2020 3-1/2" m n P 1 6 5 6 t Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 1:50 pm, Jul 31, 2020 320-318 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.07.31 13:10:23 -08'00' Taylor Wellman Undefined SFD 7/31/2020 SFD 8/3/2020 X Perforate New Pool P DSR-83/2020 20 AAC 25.055 DSR-8/3/2020 X 10-404 displace fluid gls 8/11/20Comm. 8/13/2020 JLC 8/12/2020 RBDMS HEW 8/17/2020 Well Prognosis Well: BCU-09 Date: 7/31/2020 Well Name: BRU 232-26 API Number: 50-133-20445-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: 8/15/2020 Rig: EL Reg. Approval Req’d: 10-403 Sundry Number: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 192-122 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (907) 867-0665 (C) AFE Number 2021963 Maximum Expected BHP: ~ 1430 psi @ 2,972’ TVD (From offset BCU-07A) Max. Potential Surface Pressure: ~ 1135 psi with gas to surface Brief Well Summary: BCU-09 was drilled and completed in 1994 targeting the Beluga formation. In the summer of 1998, the Sterling B4 was perfed, allowing the well to flow up the annulus. Additional Beluga sands were added in the Upper Beluga in 2003. This zone watered out and was squeezed off in 2007. The Beluga was isolated in 2013 with a PX plug. In March of 2014 the Sterling B4 loaded up with sand and water. In March of 2014, a rig workover cut and pulled tbg, isolated the Sterling B4, RIH with new 3-1/2” completion string with packer set at 5,410’ MD. The Sterling B3 Lower sand was added. The well came online making 10 MMCFD declining rapidly until it watered out in June 2015. The sterling B3 cum’d just under 3 BCF. In August of 2019, the B3 perfs were isolated and the B3B sand was perforated. The B3B sand produced at rates up to 1-2 MMCFD but also produced water and a large amount of sand. A workover in June 2020 pulled the current packer and gravel packed the B3B sand with a circulating type gravel pack. The well was put online and was making 1500-2000 bwpd with 100-200 mcfd until it finally quit giving up gas and only water after a few weeks. BCU-07A was recently perfed in the Sterling D1X sand coming online 2.5 – 3.0 MMCFD – but starting loading up after just a few weeks in the 5-1/2” monobore completion. A 2-3/8” coil velocity string was run to help keep the water off the well, resulting in a steady 500 mcfd rate. Below is the analog data for the BCU-09 perforation add. However, with BCU-09, we are up-dip on top of structure. BCU-07A was recently perfed in the Sterling D1X sand c BCU-09SFD 7/31/2020 BCU 07A data for same zone. D1X Well Prognosis Well: BCU-09 Date: 7/31/2020 Objective Set a plug in the X nipple @ 5399’ and dump bail 35’ of cement to isolate lower perforations and perforate the Sterling D1X sand. Safety Concerns x Discuss nitrogen asphyxiation hazards and identify any potential areas where nitrogen could collect and workers could enter. x Consider wind direction and weather forecast when placing flowback tanks. x Remind crews that everyone has stop the job authority. Slickline 1. MIRU Slickline. 2. RIH with sample bailer and tag PBTD. If a sample of solids is recovered call Operations Engineer to discuss nature of sample. 3. If fluid level from previous run was not determined drift again with blind box. 4. If fluid is determined to be above new perf interval (3235’) rig up N2 and depress fluid level. 5. Set plug in nipple @ 5399’ MD. E-line Procedure 1. MIRU e-line and pressure control equipment. PT to 250 psi low and 2000 psi high. 2. RIH with positive displacement dump bailer and dump 35’ of cement on top of plug. 3. WOC 4. Pressure up WHP to 1000 psi. 5. Perforate with 2-1/2” 6 SPF 60 deg phased perf guns. a. Use GR/CCL to correlate to Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer (Trudi Hallett), and Geologist (Ben Siks) for confirmation. 6. RDMO e-line and turn well over to production. Proposed Perforation Intervals Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Sterling D1X ±3,235' ±3,240' 5' ±2,972' ±2,976' Sterling D1X sand. isolate lower perforations and perforate the Sterling D1X Perf D1X plug B3B Lease: State/Prov:Alaska Country:USA 0º 160' 23' 7/10/2020 7/24/2020 07/10/20 Ground Level (above MSL): RKB (above GL): Well Name & Number:Beaver Creek Unit #9 A - 028083 County or Parish:Kenai Peninsula Borough Revised By:Donna Ambruz Downhole Revision Date: Schematic Revision Date: Angle @KOP and Depth: Maximum Deviation:32º @ 2,500'Angle/Perfs:8.0º @ 1,000' Date Completed: Production Seal Unit CMU Sliding Sleeve @ 5,823' MD 2.813" ID Beluga 6,429'-6,459' MD (30') 1/13/2004 Cmt Squeezed Wet Upper Beluga with 10 bbl, 15.8 ppg, 68 sks, of Class G 2,500 psig squeeze 7/28/2007 Model N Bridge Plug @ 8,808' MD BC-9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M.Permit #: 192-122 API #: 50-133-20445-00-00 Property Des: FEDA - 028083 KB Elevation: 183' (23' AGL)Spud Date: 7/26/1994 TD Reached: 8/26/1994Rig Released: 9/5/1994 X: 317,605Y: 2,434,000Lat: 60° 39' 30.34" N Long: 151° 01' 04.48" W Conductor 13-3/8" K-55 61 ppfTop Bottom MD 0' 116' TVD 0' 116' Surface Casing 9-5/8" N-80 47 ppf BTC Top Bottom MD 0' 1,853' TVD 0' 1,790' 12-1/4" hole Cmt w/ 700 sks Intermediate Casing 7" N-80 29 ppf BTCTop Bottom MD 0' 5,950' TVD 0' 5,569' 8-1/2" hole Cmt w/ 565 sks, in two stages w/ DV tool @ 4,487' MD Liner 3-1/2" N-80 9.2 ppf AB-Mod IBT Top Bottom MD 5,814' 8,881' TVD 5,433' 8,496' 6" hole Cmt w/ 500 sks, 150 sks to surface TD 8,881' MD 8,496' TVD PBTD 5,513' MD 5,132' TVD Tubing 3-1/2" L-80 9.2 ppf IBT AB-Mod Top Bottom MD 0' 5,430' TVD 0' 5,049' Model H liner hanger packer @ 5,828' MD B3B B3B B3B B3L B4 B4 B16 B17 B18 B19 B20 B21 B23 B24 B25 B27 Date 7/5/20 8/15/19 8/12/19 3/05/14 (6/?/98) Date (1/12/04) (7/28/07) (10/2/96) (9/30/96) (9/28/96) (9/26/96) (9/25/96) (8/13/96) (8/9/96) (8/7/96) (8/5/96) (9/25/94) (9/24/94) (9/24/94) (9/18/94) (9/16/94) (9/16/94) (9/16/94) (9/15/94) (9/15/94) Gun Type 3-3/8" HC, 6 SPF 2-3/8" HC, 6 SPF 2-3/8" HC, 6 SPF 2-1/2" HC, 12 SPF2" Scallop, 6 SPF Gun Type 2-3/8", 60º, 4 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF TVD 5,087' - 5,117' 5,087' - 5,117' 5,102' - 5,105' 5,152' - 5,172' 5,248' - 5,256’ TVD 6,048'-6,078' (Cement squeezed) 7,039'-7,079' 7,153'-7,193' 7,259'-7,279' 7,324'-7,344' 7,344'-7,374' 7,381'-7,431' 7,431'-7,461' 7,471'-7,501' 7,512'-7,552' 7,599'-7,649' (Fracture Treated) 7,655'-7,673' (Fracture Treated) 7,691'-7,717' 7,786'-7,806' 7,860'-7,865' 7,873'-7,880' 7,895'-7,911' 8,018'-8,028' 8,051'-8,071' ft 30' 30' 3' 20' 12' ft 30' 40' 40' 20' 20' 30' 50' 30' 30' 40' 50' 18' 26' 20' 5' 7' 16' 10' 20' MD 5,468' - 5,498' 5,468' - 5,498' 5,483 -5,486' 5,533'-5,553' 5,629'-5,637’ MD 6,429'-6,459' 7,420'-7,460' 7,534'-7,574' 7,640'-7,660' 7,705'-7,725' 7,725'-7,755' 7,762'-7,812' 7,812'-7,842' 7,852'-7,882' 7,893'-7,933' 7,980'-8,030' 8,036'-8,054' 8,072'-8,098' 8,167' -8,187' 8,241'- 8,446' 8,254'-8,261' 8,276'-8,292' 8,399'-8,409' 8,432'-8,452' Sterling Perforations: Beluga Perforations: Tree cxn: 6-1/2" Otis SCHEMATIC PX Plug @ 5,739' MD Tag Fill @ 5,703' MD on 2/18/14Cut Tubing @ 5,620' MD Completion Assembly 07/10/20 Includes: 1 - #2 Gaslift Mandrel 1,200' MD 2 - Chemical Injection Mandrel 1,455' MD (Valve 3/1/14) 3 - #1 Gaslift Mandrel 3,096' MD 4 - DLH Hydraulic Packer 3,209' MD 5 - DLH Hydraulic Packer 5,324' MD 6 - X Landing Nipple 5,339' MD 7 - GP Screens 5,438' MD 8 - GP Bull Plugs 5,519' MD 9 - Bridge Plug 5,549' MD 7/23/19 w/ 36' of cement (TOC 5,513') 8/12/19 10 - Bridge Plug 5,615' MD B4 B3L 2 3 5 6 7 10 B3B 9 8 Top of Gravel @ 5,438' MD 07/08/20 4 1 Lease: State/Prov:Alaska Country:USA 0º 160' 23' 7/10/2020 7/24/2020 07/10/20 Ground Level (above MSL): RKB (above GL): Well Name & Number:Beaver Creek Unit #9 A - 028083 County or Parish:Kenai Peninsula Borough Revised By:Donna Ambruz Downhole Revision Date: Schematic Revision Date: Angle @KOP and Depth: Maximum Deviation:32º @ 2,500'Angle/Perfs:8.0º @ 1,000' Date Completed: Production Seal Unit CMU Sliding Sleeve @ 5,823' MD 2.813" ID Beluga 6,429'-6,459' MD (30') 1/13/2004 Cmt Squeezed Wet Upper Beluga with 10 bbl, 15.8 ppg, 68 sks, of Class G 2,500 psig squeeze 7/28/2007 Model N Bridge Plug @ 8,808' MD BC-9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M.Permit #: 192-122 API #: 50-133-20445-00-00 Property Des: FEDA - 028083 KB Elevation: 183' (23' AGL)Spud Date: 7/26/1994 TD Reached: 8/26/1994Rig Released: 9/5/1994 X: 317,605Y: 2,434,000Lat: 60° 39' 30.34" N Long: 151° 01' 04.48" W Conductor 13-3/8" K-55 61 ppfTop Bottom MD 0' 116' TVD 0' 116' Surface Casing 9-5/8" N-80 47 ppf BTC Top Bottom MD 0' 1,853' TVD 0' 1,790' 12-1/4" hole Cmt w/ 700 sks Intermediate Casing 7" N-80 29 ppf BTCTop Bottom MD 0' 5,950' TVD 0' 5,569' 8-1/2" hole Cmt w/ 565 sks, in two stages w/ DV tool @ 4,487' MD Liner 3-1/2" N-80 9.2 ppf AB-Mod IBT Top Bottom MD 5,814' 8,881' TVD 5,433' 8,496' 6" hole Cmt w/ 500 sks, 150 sks to surface TD 8,881' MD 8,496' TVD PBTD 5,513' MD 5,132' TVD Tubing 3-1/2" L-80 9.2 ppf IBT AB-Mod Top Bottom MD 0' 5,430' TVD 0' 5,049' Model H liner hanger packer @ 5,828' MD D1X B3B B3B B3B B3L B4 B4 B16 B17 B18 B19 B20 B21 B23 B24 B25 B27 Date TBD 7/5/20 8/15/19 8/12/19 3/05/14 (6/?/98) Date (1/12/04) (7/28/07) (10/2/96) (9/30/96) (9/28/96) (9/26/96) (9/25/96) (8/13/96) (8/9/96) (8/7/96) (8/5/96) (9/25/94) (9/24/94) (9/24/94) (9/18/94) (9/16/94) (9/16/94) (9/16/94) (9/15/94) (9/15/94) Gun Type TBD 3-3/8" HC, 6 SPF 2-3/8" HC, 6 SPF 2-3/8" HC, 6 SPF 2-1/2" HC, 12 SPF2" Scallop, 6 SPF Gun Type 2-3/8", 60º, 4 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF TVD ±2,972' - ±2,976' 5,087' - 5,117' 5,087' - 5,117' 5,102' - 5,105' 5,152' - 5,172' 5,248' - 5,256’ TVD 6,048'-6,078' (Cement squeezed) 7,039'-7,079' 7,153'-7,193' 7,259'-7,279' 7,324'-7,344' 7,344'-7,374' 7,381'-7,431' 7,431'-7,461' 7,471'-7,501' 7,512'-7,552' 7,599'-7,649' (Fracture Treated) 7,655'-7,673' (Fracture Treated) 7,691'-7,717' 7,786'-7,806' 7,860'-7,865' 7,873'-7,880' 7,895'-7,911' 8,018'-8,028' 8,051'-8,071' ft ±5' 30' 30' 3' 20' 12' ft 30' 40' 40' 20' 20' 30' 50' 30' 30' 40' 50' 18' 26' 20' 5' 7' 16' 10' 20' MD ±3,235' - ±3,240' 5,468' - 5,498' 5,468' - 5,498' 5,483 -5,486' 5,533'-5,553' 5,629'-5,637’ MD 6,429'-6,459' 7,420'-7,460' 7,534'-7,574' 7,640'-7,660' 7,705'-7,725' 7,725'-7,755' 7,762'-7,812' 7,812'-7,842' 7,852'-7,882' 7,893'-7,933' 7,980'-8,030' 8,036'-8,054' 8,072'-8,098' 8,167' -8,187' 8,241'- 8,446' 8,254'-8,261' 8,276'-8,292' 8,399'-8,409' 8,432'-8,452' Sterling Perforations: Beluga Perforations: Tree cxn: 6-1/2" Otis PROPOSED PX Plug @ 5,739' MD Tag Fill @ 5,703' MD on 2/18/14Cut Tubing @ 5,620' MD Completion Assembly 07/10/20 Includes: 1 - #2 Gaslift Mandrel 1,200' MD 2 - Chemical Injection Mandrel 1,455' MD (Valve 3/1/14) 3 - #1 Gaslift Mandrel 3,096' MD 4 - DLH Hydraulic Packer 3,209' MD 5 - DLH Hydraulic Packer 5,324' MD 6 - X Landing Nipple 5,339' MD (PX Plug Installed xx/xx/2020) 7 - GP Screens 5,438' MD 8 - GP Bull Plugs 5,519' MD 9 - Bridge Plug 5,549' MD 7/23/19 w/ 36' of cement (TOC 5,513') 8/12/19 10 - Bridge Plug 5,615' MD B4 B3L 2 3 5 6 7 10 B3B 9 8 Top of Gravel @ 5,438' MD 07/08/20 4 1 D1X Top of Cement @ 5,300' MD xx/xx/2020 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.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: Gravel Pack 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): 8,881'N/A Casing Collapse Structural Conductor Surface 4,760 psi Intermediate 7,020 psi Production 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: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized 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: June 4, 2020 3-1/2" DLH Hydraulic Pkr Perforation Depth MD (ft): 5,950' See Attached Schematic 5,410' MD / 5,029' TVD 13-3/8" 9-5/8" 116' 7"5,950' 1,853' 116' 1,790' 5,569' 116' 1,853' 9.2# / L-80 TVD Burst 5,430' MD 8,160 psi 6,870 psi Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028083 192-122 50-133-20445-00-00 Beaver Creek Unit (BCU) 09 Beaver Creek / Beluga Gas - Sterling Gas CO 237B COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic tkramer@hilcorp.com 8,500'5,513'5,132'1,574 5,513 & 5,615 Perforation Depth TVD (ft):Tubing Size: Length Size m n P 66 t PaPaaaaaaaaaaaaaaaaaaaacck cccccccc Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:29 am, May 22, 2020 320-208 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.05.22 09:14:50 -08'00' Taylor Wellman *BOPE test to 3500 psi *Annular test to 2500 psi DSR-5/26/2020gls 5/27/20 X SFD 5/22/2020 10-404 Comm. 5/27/2020 dts 5/29/2020 RBDMS HEW 5/27/2020 Well Prognosis Well: BCU-09 Date: 5/21/2020 Well Name: BCU-09 API Number: 50-133-20445-00 Current Status: Shut In Gas Well Leg: N/A Estimated Start Date: June 4, 2020 Rig: 401 Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 192-122 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) Second Call Engineer: Christina Twogood (907) 777-8443 (O) (907) 378-7323 (C) AFE Number: Current Bottom Hole Pressure: ~ 2,100 psi @ 5,262’ TVD (Flowing survey August 2013 base perf 5,643’ MD) Maximum Expected BHP: ~ 2,100 psi @ 5,262’ TVD (Flowing survey August 2013 base perf 5,643’ MD) Max. Allowable Surface Pressure: ~ 1,574 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft)) Brief Well Summary Beaver Creek #9 was drilled as a grassroots gas well in 1994 to target the lower Beluga gas sands. This well was worked over in 1998 to include the Sterling B-4 zone and flow this zone up the annulus. Additional perforations were added in the Upper Beluga in 2003. This zone watered out shortly after coming online and was cement squeezed in 2007. The Beluga was isolated with a PX plug in March 2013. The Sterling B-4 zone flowed gas and water (up to 1,000 bwpd) until going offline in the summer of 2013 when it loaded up with fill. A rig workover in 2014 isolated the B4 and added the B3. The B3 initial production was 10 MMcfd but declined rapidly until it watered out in June 2015 after recovering almost 3 BCF of gas. In August of 2019 the B3 perfs were isolated and the B3B sand was perforated. The B3B sand produced at rates up to 1 MMscfd but also produced water and a large amount of sand. The purpose of this work/sundry is to pull the current packer and gravel pack the B3B sand with a circulating type gravel pack. Rig 401 Procedure 1. MIRU Rig 401. 2. Fill the 3-1/2” X 7” IA with 3% KCL and perform a well kill by bullheading 3% KCL down the tubing. 3. ND wellhead, NU BOP and test to 250 psi low & 3,500 psi high, annular to 250 psi low & 2,500 psi high. Record accumulator pre-charge pressures and chart tests. a. Perform Test. b. Test rams on 3-1/2” and 2-7/8” test joints. c. Submit completed form 10-424 to AOGCC within 5 days of BOPE test. 4. Insure well is dead pressure wise, if not repeat well Kill operation is Step #2. PU on 3-1/2” tubing string. Pull Tubing hanger to floor, lay down same. 5. PU on 3-1/2” tubing and release DLH Hydraulic packer @ 5,410’ (40K Shear release). 6. Circulate well with 3% KCL and ensure well is dead. 7. POOH with tubing string. Lay down packer. The purpose type gravel pack. of this work/sundry is to pull the current packer and gravel pack the B3B sand with a circulating o BOP test Well Prognosis Well: BCU-09 Date: 5/21/2020 8. PU Bit and scraper on 2-7/8” WS. RIH W/ same, cleaning out fill to TOC @ 5,513’. POOH W/ bit and scraper. Note: if the well will not circulate, a pump bailer may be needed to recover fill from well. 9. RU E-line. Pressure test Lubricator to 250 psi low/ 3,500 psi high. 10. PU RIH W/ perf guns loaded with Big Hole charges. Re-perforate the B3B interval From 5,468 – 5,498’ W/ 3-3/8” perf guns loaded 6 JSPF, 60 degree phasing. Log on depth and fire guns. POOH W/ same. Stand back E-line. 11. RIH W/ tubing open ended with ½ mule shoe for a guide. Tag for fill to 5,513’. If fill is encountered, reverse out until fluid is clean. 12. Pump sand sweep down tubing to within 3 bbls of EOT. Reverse out to clean pipe of any excess pipe dope and scale. Note: From here forward use minimal amount of pipe dope with a 2” paint brush. Remove dope brushes from rig floor. Discuss with rig crew how excessive pipe dope can damage the gravel pack and formation. 13. Filter completion fluid in the well and pits. 14. PU tubing to 5,360’ (+/-) (min. of 100’ above top perforation). Pre- Pack 15. Rig up sand injector. Establish circulation and record circulation rates at 1 and 2 BPM. 16. Close casing valve and establish injection rates at 1 and 2 BPM. 17. Spot to end of tubing and pump 20/40 Gravel pack sand @ 2-3 BPM until sand out of 800 – 1000 psi over injection rate. (Approximately 25# per foot of perforations) 18. After achieving sand out allow pressure to bleed to 0 psi. 19. Re-stress Gravel pack two more times (Pump to raise pressure to sand out pressure achieved in step #17) and bleed to 0 psi each time. 20. Reverse out 1-½ tubing volumes and monitor returns. 21. Lower tubing and reverse out down to the TOC @ 5,513 (+/-). 22. POOH W/ Tubing. Note: If the well will not circulate, then the Pre-pack step will be combined with the gravel pack step and both will be done together as stated in the Gravel Pack section. Gravel Pack 23. Pick-up and RIH W/ Gravel pack screen, hook-up nipple, clutch joint and JS-2 squeeze packer/crossover tool assembly. 24. Tag TOC @ 5,513’. 25. Pick up and space out work string to safe working height. 26. Slack off and land screen assembly on TOC (5,513’ +/-). 27. Set GP (JS-2) Packer @ 5,337’ (+/-) and test. Test backside W/ 500-1,000 PSI applied to annulus. 28. Rig up sand injector. 29. Establish circulation and record rates @ 1 & 2 BPM. Gravel Pack Pre- Pack Reperf Big hole (clean tubing - pre gravel pack) Well Prognosis Well: BCU-09 Date: 5/21/2020 30. Close casing valve and establish injection rates @ 1 & 2 BPM. 31. Spot to end of tubing and pump 20/40 Gravel pack sand @ 2-3 BPM until sand out of 800 – 1000 psi over injection rate. (Approximately 25# per foot of perforations) 32. After achieving sand out allow pressure to bleed to 0 psi. 33. Re-stress gravel pack two more times and bleed to zero each time. 34. Open Packer by pass and reverse out 1-1/2 tubing volumes and monitor returns. 35. Release clutch joint and POOH slowly to avoid swabbing the interval. 36. Lay down service tool assembly. 37. Pick up the following straddle packer assembly (2 Packers consisting of) on the production tubing: • 4-1/2” Production Overshot • 3-1/2” EUE Tubing Pup Joint • 3-1/2” EUE “X” Nipple • 3-1/2” EUE Tubing Pup Joint • 7” 26-32# DLH Retrievable Packer • 3-1/2” 9.3# L-80 EUE X/O Tubing Pup Joint (IBT-Mod Box x EUE Pin) • 3-1/2” 9.2# L-80 IBT-Mod Tubing, GLM’s and accessories. 38. RIH. Engage overshot over hook-up nipple @ 5,354.5’ and verify depths. 39. Pick up, space out and make up tubing hanger. 40. Slack off and engage hook-up nipple w/ overshot 41. Drop Pollard Bar/Ball and allow to fall. (Approx. 30’/second) 42. Pressure up on tubing to set the DLH packer as per Packer manufacturer’s setting procedure. 43. Release setting pressure and test the annulus as directed by Hilcorp. 44. ND BOP, NU wellhead and pressure test to 5,000 psi. 45. RDMO Rig 401 46. Turn well over to production to run GLV’s . Bring well on line W/ gas lift. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. BOP Stack Schematic 4. Wellhead Schematic (No Change) MT-IA 2000 psi (2nd DHL packer at 3200 ft ) (s) 2 packers Lease: State/Prov:Alaska Country:USA 0º 160' 23' 8/15/2019 9/19/2019Revised By:Donna Ambruz Downhole Revision Date: Schematic Revision Date: Angle @KOP and Depth: Maximum Deviation:32º @ 2,500'Angle/Perfs:8.0º @ 1,000' Date Completed:02/28/14 Ground Level (above MSL): RKB (above GL): Well Name & Number:Beaver Creek Unit #9 A - 028083 County or Parish:Kenai Peninsula Borough Production Seal Unit CMU Sliding Sleeve @ 5,823' MD 2.813" ID Beluga 6,429'-6,459' MD (30') 1/13/2004 Cmt Squeezed Wet Upper Beluga with 10 bbl, 15.8 ppg, 68 sks, of Class G 2,500 psig squeeze 7/28/2007 Model N Bridge Plug @ 8,808' MD BC-9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M.Permit #: 192-122 API #: 50-133-20445-00-00 Property Des: FEDA - 028083 KB Elevation: 183' (23' AGL) Spud Date: 7/26/1994 TD Reached: 8/26/1994 Rig Released: 9/5/1994 X: 317,605 Y: 2,434,000 Lat: 60° 39' 30.34" N Long: 151° 01' 04.48" W Conductor 13-3/8" K-55 61 ppf Top Bottom MD 0' 116' TVD 0' 116' Surface Casing 9-5/8" N-80 47 ppf BTC Top Bottom MD 0' 1,853' TVD 0' 1,790' 12-1/4" hole Cmt w/ 700 sks Intermediate Casing 7" N-80 29 ppf BTC Top Bottom MD 0' 5,950' TVD 0' 5,569' 8-1/2" hole Cmt w/ 565 sks, in two stages w/ DV tool @ 4,487' MD Liner 3-1/2" N-80 9.2 ppf AB-Mod IBT Top Bottom MD 5,814' 8,881' TVD 5,433' 8,496' 6" hole Cmt w/ 500 sks, 150 sks to surface TD 8,881' MD 8,496' TVD PBTD 5,513' MD 5,132' TVD Tubing 3-1/2" L-80 9.2 ppf IBT AB-Mod Top Bottom MD 0' 5,430' TVD 0' 5,049' Model H liner hanger packer @ 5,828' MD B3B B3B B3L B4 B4 B16 B17 B18 B19 B20 B21 B23 B24 B25 B27 Date 8/15/19 8/12/19 3/05/14 (6/?/98) Date (1/12/04) (7/28/07) (10/2/96) (9/30/96) (9/28/96) (9/26/96) (9/25/96) (8/13/96) (8/9/96) (8/7/96) (8/5/96) (9/25/94) (9/24/94) (9/24/94) (9/18/94) (9/16/94) (9/16/94) (9/16/94) (9/15/94) (9/15/94) Gun Type 2-3/8" HC, 6 SPF 2-3/8" HC, 6 SPF 2-1/2" HC, 12 SPF2" Scallop, 6 SPF Gun Type 2-3/8", 60º, 4 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF TVD 5,087' - 5,117' 5,102' - 5,105' 5,152' - 5,172' 5,248' - 5,256’ TVD 6,048'-6,078' (Cement squeezed) 7,039'-7,079' 7,153'-7,193' 7,259'-7,279' 7,324'-7,344' 7,344'-7,374' 7,381'-7,431' 7,431'-7,461' 7,471'-7,501' 7,512'-7,552' 7,599'-7,649' (Fracture Treated) 7,655'-7,673' (Fracture Treated) 7,691'-7,717' 7,786'-7,806' 7,860'-7,865' 7,873'-7,880' 7,895'-7,911' 8,018'-8,028' 8,051'-8,071' ft 30' 3' 20' 12' ft 30' 40' 40' 20' 20' 30' 50' 30' 30' 40' 50' 18' 26' 20' 5' 7' 16' 10' 20' MD 5,468' - 5,498' 5,483 -5,486' 5,533'-5,553' 5,629'-5,637’ MD 6,429'-6,459' 7,420'-7,460' 7,534'-7,574' 7,640'-7,660' 7,705'-7,725' 7,725'-7,755' 7,762'-7,812' 7,812'-7,842' 7,852'-7,882' 7,893'-7,933' 7,980'-8,030' 8,036'-8,054' 8,072'-8,098' 8,167' -8,187' 8,241'- 8,446' 8,254'-8,261' 8,276'-8,292' 8,399'-8,409' 8,432'-8,452' Sterling Perforations: Beluga Perforations: Tree cxn: 6-1/2" Otis SCHEMATIC PX Plug @ 5,739' MD Tag Fill @ 5,703' MD on 2/18/14 Cut Tubing @ 5,620' MD Completion Assembly Includes: 1 - Gaslift Mandrel, 992' MD (Dummy set 3/1/14) 2 - Chemical Injection Mandrel, 1,469' MD (Valve 3/1/14) 3 - Gaslift Mandrel, 5,366' MD (Orifice set 11/17/14) 4 - DLH Hydraulic Packer, 5,410' MD (40K Shear) 5 - X-Profile, 5,427' MD 6 - WLEG, 5,440' MD 7 - Bridge Plug, 5,549' MD 7/23/19 w/ 36' of cement (TOC 5,513') 8/12/19 8 - Bridge Plug, 5,615' MD B4 B3L 2 1 3 4 5 6 8Last Tag: @ 5,552' RKB on 04/10/15 w/ a 2" Bailer B3B 7 will gravel-pack B3B Lease: State/Prov:Alaska Country:USA 0º 160' 23' 8/15/2019 5/15/2020Revised By:Donna Ambruz Downhole Revision Date:Schematic Revision Date: Angle @KOP and Depth:Maximum Deviation:32º @ 2,500'Angle/Perfs:8.0º @ 1,000' Date Completed:02/28/14 Ground Level (above MSL):RKB (above GL): Well Name & Number:Beaver Creek Unit #9 A - 028083 County or Parish:Kenai Peninsula Borough Production Seal Unit CMU Sliding Sleeve @ 5,823' MD 2.813" ID Beluga 6,429'-6,459' MD (30') 1/13/2004 Cmt Squeezed Wet Upper Beluga with 10 bbl, 15.8 ppg, 68 sks, of Class G 2,500 psig squeeze 7/28/2007 Model N Bridge Plug @ 8,808' MD BC-9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M.Permit #:192-122 API #:50-133-20445-00-00 Property Des:FEDA - 028083 KB Elevation:183' (23' AGL)Spud Date:7/26/1994 TD Reached:8/26/1994Rig Released:9/5/1994 X:317,605Y:2,434,000Lat:60°39' 30.34" N Long:151°01' 04.48" W Conductor 13-3/8" K-55 61 ppf Top Bottom MD 0' 116' TVD 0' 116' Surface Casing 9-5/8" N-80 47 ppf BTC Top Bottom MD 0' 1,853' TVD 0' 1,790' 12-1/4" hole Cmt w/ 700 sks Intermediate Casing 7" N-80 29 ppf BTC Top Bottom MD 0' 5,950' TVD 0' 5,569' 8-1/2" hole Cmt w/ 565 sks, in two stages w/ DV tool @ 4,487' MD Liner 3-1/2" N-80 9.2 ppf AB-Mod IBT Top Bottom MD 5,814' 8,881' TVD 5,433' 8,496' 6" hole Cmt w/ 500 sks, 150 sks to surface TD 8,881' MD 8,496' TVD PBTD 5,513' MD 5,132' TVD Tubing 3-1/2" L-80 9.2 ppf IBT AB-Mod Top Bottom MD 0' 5,430' TVD 0' 5,049' Model H liner hanger packer @ 5,828' MD B3B B3B B3L B4 B4 B16 B17 B18 B19 B20 B21 B23 B24 B25 B27 Date 8/15/19 8/12/19 3/05/14 (6/?/98) Date (1/12/04) (7/28/07) (10/2/96) (9/30/96) (9/28/96) (9/26/96) (9/25/96) (8/13/96) (8/9/96) (8/7/96) (8/5/96) (9/25/94) (9/24/94) (9/24/94) (9/18/94) (9/16/94) (9/16/94) (9/16/94) (9/15/94) (9/15/94) Gun Type 2-3/8" HC, 6 SPF 2-3/8" HC, 6 SPF 2-1/2" HC, 12 SPF2" Scallop, 6 SPF Gun Type 2-3/8", 60º, 4 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF 2-1/2", 60º, 6 SPF2-1/2", 60º, 6 SPF TVD 5,087' - 5,117' 5,102' - 5,105' 5,152' - 5,172' 5,248' -5,256’ TVD 6,048'-6,078' (Cement squeezed) 7,039'-7,079' 7,153'-7,193' 7,259'-7,279' 7,324'-7,344' 7,344'-7,374' 7,381'-7,431' 7,431'-7,461' 7,471'-7,501' 7,512'-7,552' 7,599'-7,649' (Fracture Treated) 7,655'-7,673' (Fracture Treated) 7,691'-7,717' 7,786'-7,806' 7,860'-7,865' 7,873'-7,880' 7,895'-7,911' 8,018'-8,028' 8,051'-8,071' ft 30' 3' 20' 12' ft 30' 40' 40' 20' 20' 30' 50' 30' 30' 40' 50' 18' 26' 20' 5' 7' 16' 10' 20' MD 5,468' - 5,498' 5,483 -5,486' 5,533'-5,553' 5,629'-5,637’ MD 6,429'-6,459' 7,420'-7,460' 7,534'-7,574' 7,640'-7,660' 7,705'-7,725' 7,725'-7,755' 7,762'-7,812' 7,812'-7,842' 7,852'-7,882' 7,893'-7,933' 7,980'-8,030' 8,036'-8,054' 8,072'-8,098' 8,167' -8,187' 8,241'- 8,446' 8,254'-8,261' 8,276'-8,292' 8,399'-8,409' 8,432'-8,452' Sterling Perforations: Beluga Perforations: Tree cxn: 6-1/2" Otis PROPOSED SCHEMATIC PX Plug @ 5,739' MD Tag Fill @ 5,703' MD on 2/18/14Cut Tubing @ 5,620' MD Completion Assembly Includes: 1 - Gaslift Mandrel, ±988' MD (Dummy set 3/1/14) 2 - Chemical Injection Mandrel, ±1,453' MD (Valve 3/1/14) 3 - DLH Hydraulic Packer ±3,200' MD 4- DLH Hydraulic Packer ±5,330' MD 5 - X Landing Nipple ±5,356' MD 6 - GP Screens, ±5,450' MD 7 - GP Bull Plugs, ±5,512' MD 8 - Bridge Plug, 5,549' MD 7/23/19 w/ 36' of cement (TOC 5,513') 8/12/19 9 - Bridge Plug, 5,615' MD B4 B3L 2 1 4 5 6 9 Last Tag: @ 5,552' RKB on 04/10/15 w/ a 2" Bailer B3B 8 7 Top of Gravel @ ±5,440' MD 3 ϳͲϭͬϭϲΗϱD,zZ/>'<EEh>Z ϯϮΗd>>͕&>E' dK&>E' ϳͲϭͬϭϲΗϱD>t^>'d KW Z ^^ tͬsZ/> ZD^/EdKW Z ^^ tͬ>/EZD^/EKddKD ϮϲͲϯͬϰΗd>>͕&>E' dK&>E' ϳͲϭͬϭϲΗϱDZ/>>/E'^WKK> tͬϮͲϭͬϭϲΗϱDKhd> d^ ϭϴΗd>>͕&>E' dK&>E' ΕϳϳΗdKd>^d<, /',d EEh>Z^dz> KW^W ^͗ Ͳϯ͘ϯϬŐĂůůŽŶŽƉĞŶĐŚĂŵďĞƌǀŽůƵŵĞ Ͳϯ͘ϴϲŐĂůůŽŶĐůŽƐĞĐŚĂŵďĞƌǀŽůƵŵĞ 'd ^dz> KW^W ^͗ Ͳϭ͘ϰϱŐĂůůŽŶƐƚŽĐůŽƐĞƉĞƌŐĂƚĞ Ͳϭ͘ϭϴŐĂůůŽŶƐƚŽŽƉĞŶƉĞƌŐĂƚĞ Ͳϱ͘ϰϱ͗ϭĐůŽƐŝŶŐƌĂƚŝŽ Ͳϭ͘ϵϯ͗ϭŽƉĞŶŝŶŐƌĂƚŝŽ ϳͲϭͬϭϲΗϱDKW ,/>KZW>^< Beaver Creek Field BC #9 05/14/2020 Tubing head, CIW-N, 11 5M X 7 1/16 5M, w/ 2- 2 1/16 5M SSO, X-bottom prep w/ 1 ½ VR profile Valve, CIW-F, 2 1/16 5M FE, HWO, AA Qty 4 Beaver Creek BCU #9 13 3/8 X 9 5/8 X 7 X 3 1/2 Casing head, CIW-WF, 13 5/8 3M X 13 3/8'’ csg thrd bottom, w/ 2- 2 1/16 5M EFO Casing spool, CIW-WF, 13 5/8 3M X 11 5M, w/ 2- 2 1/16 5M SSO Valve, swab, OCT-20, 3 1/8 5M FE, HWO Valve, master, CIW-FC, 3 1/8 5M FE, HWO Adapter, CIW-FBB, 7 1/16 5M FE X 3 1/8 5M, prepped for 6 1/4'’ extended neck, 1/2npt control line port Valve, CIW-F, 2 1/16 5M FE, HWO, AA Tubing hanger, CIW-N- FBB, 7 X 3 ½ EUE 8rd lift and 3 ½ IBT susp, w/ 3'’ type H BPV profile, 6 1/4'’ EN, ¼ CL, 410SS material Valve, CIW-F, 2 1/16 5M FE, HWO, AA Valve, upper master, OCT-20, 3 1/8 5M FE, HWO BHTA, Otis, 3 1/8 5M X 6.5'’ Otis quick union Valve, wing, OCT-20, 3 1/8 5M FE, HWO Valve, wing, SSV, Axelson, 3 1/8 5M FE 1 Carlisle, Samantha J (CED) From:Ted Kramer <tkramer@hilcorp.com> Sent:Wednesday, May 27, 2020 8:57 AM To:Schwartz, Guy L (CED) Subject:RE: [EXTERNAL] BCU -09 Gravel pack sundry (PTD 192-122) Guy, Thereasonforthetwopackersisthatthereisasmallzonethatwewanttoshootlaterbetweenthosetwopackers.This willallowustosetapluginthelower[packer(later)andthenshootthisupperzonethroughtubingwithouthavingto putarigonthewell.ItisnotabigzonebutiswhatisproducinginBCU7A. ThewelliscoolenoughandshallowenoughthatIamnotparticularlyconcernedwithanytrappedpressure. TedKramer Sr.OperationsEngineer HilcorpͲAlaskaLLC Office–907Ͳ777Ͳ8420 Cell–985Ͳ867Ͳ0665 From:Schwartz,GuyL(CED)[mailto:guy.schwartz@alaska.gov] Sent:Wednesday,May27,20208:44AM To:TedKramer<tkramer@hilcorp.com> Subject:[EXTERNAL]BCUͲ09Gravelpacksundry(PTD192Ͳ122) Ted, Lookingatthissundry.Whatisreasonfortwopackers(DHL)andareyouworriedabouttrappedpressurebetween themandpossiblycollapsingtubing? 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). STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 0 LL, REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon LJ Plug Perforations ✓j Fracture Stimulate LJ Pull Tubing L1 Operations shutdown Li Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casin g ❑ Change Approved Program ❑ Plug for Redrill 1:1erforate New Pool ❑ Repair Well El Re-enterSusp Well ❑ Other: El2. Operator Hilcorp Alaska, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑✓ Stratigraphic❑ Exploratory ❑ Service ❑ 192-122 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-133-20445-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: FEDA028083 Beaver Creek Unit (BCU) 09 9. Logs (List lags and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Beaver Creek / Beluga - Sterling Gas 11. Present Well Condition Summary: Total Depth measured 8,881 feet Plugs measured 5513 & 5615 feet true vertical 8,500 feet Junk measured N/A feet Effective Depth measured 5,513 feet Packer measured 5,410 feet true vertical 5,132 feet true vertical 5,029 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 116' 13-3/8" 116' 116' Surface 1,853' 9-5/8" 1,853' 1,790' 4,750 psi 6,870 psi Intermediate 5,950' 7" 5,950' 5,569' 7,020 psi 8,160 psi Production Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.2# / L-80 5,430' MD 5,049' TVD Packers and SSSV (type, measured and true vertical depth) DLH Hydraulic Pkr NIA; N/A 5,410' MD 5,029' TVD 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 1630 1680 Subsequent to operation: 0 412 261 785 1 176 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 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 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: 319-306 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilcom com Authorized Signature: * .�— Date: -AN 5 Contact Phone: 777-8420 Form 10-404 Revised 412017 ./ f///� �- i0 Y • RBDMS± OCT 912019 Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig AN Number Well Permit Number Start Date End Date BCU -09 50-133-20445-00-00 192-122 L 7/22/19 1 9/17/19 Daily Operations. 07/22/2019 - Monday Sign in. Mobe to location. PTW, JSA and go over N2 JSA. Spot and rig up lubricator. MU basket plug. PT to 250 psi low and 3,000 psi high. Rig up N2 bottles to lubricator. Start pressuring up lubricator 1,700 psi with N2. Regulator went out so replaced it. Pressure lubricator up to 1,700 psi (Well pressure so when we open swab we won't lose well pressure and bring in water). RIH w/Neo basket plug and tie into OHL. Run correlation log and send to town. Told to shift log down 1'. Shifted log and spotted plug at 5,530'. Fired plug. Showed on amp gauge that it tripped the deployment head. Pulled out of hole and plug had not deployed. Checked deployment head and it was gassed up. broke part of it apart and decided it needed to be taken back to shop and worked over. Plan is to be back in the morning at 7 am. Rigged down lubricator and secured well. 07/23/2019 -Tuesday Sign in. Mobe to location. PTW and JSA. Rig up lubricator. PT to 250 psi low and 3,000 psi high. TP - 1,700 psi. Tested plug deployment head. Ok. Pressured up lubricator with N2 to 1,700 psi. RIH with Neo basket (umbrella) plug and tied into RST log. Run correlation log and send to town. Got ok to set plug at 5,530'. Spotted and set deployment head off with voltage and amp. Both look good. POOH and plug had not deployed. Found that safety pin that was put in to test the plug on surface had not been removed. Removed pin and prep deployment head and plug again. Went. back in well and spotted plug at 5,530' after correlated and voltage and amp look good. Got out of well and plug still hadn't deployed. Called Neo products engineer to get some advice. In the mean time decision was made to just go ahead and dump bail 35' of cement from 5,549' (Tagged fill at) to 5,514'. That would give us 19' above existing perfs and a differential of 5,073 psi. It will take approx. 8 runs with 2-1/2" x40' bailer to get the 35'. The plan is to make 3 runs today and come back around 9 am tomorrow, check and see if perfs took any cement (approx. 15' of cement) and dump bail the rest of cement if everything checks out ok as far as depth. MU 40' of 2-1/2" bailer and fill with cement (approx. 8.14 gals of 17 ppg cement per run). Make 3 runs of 2.5" x40' dump bailer filled with cement and dump on top of fill at 5,549'. TOC should be around 5,534'. Cement in place 1915 hrs. Will be back at 9 am in the morning. All bailers dumped. TP - 1,700 psi. Rig down lubricator and secure the well. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date BCU -09 50-133-20445-00-00 1 192-122 7/22/19 9/17/19 Daily Operations: 07/24/2019- Wednesday Sign in. Mobe to location. PTW and JSA. Rig up lubricator. PT to 250 psi low and 3,500 psi high. TP - 1,700 psi. The 3 cement bottles of cement are still pretty soft but they were left in the truck where the temp was 49 to 55 deg. It had been 13 hours since last dump. It is approx 100 deg where cement was dump. Put bailer together and mixed cement. RIH w/ 2.5" x 40' bailer filled with 17 ppg Neo cement, correlated to plug log and tagged at 5,537' (est TOC 5,534' from yesterday). We are thinking perfs drank 3' of cement. Pulled bailer bottom up 6' from TOC and dumped cement. POOH. Good dump. We also pressured lubricator up to 1,700 psi with N2 before we opened up to well. Added 5' to the bailer and pressured lubricator up to 1,700 psi with N2. RIH w/ 2.5'x 45'dump bailer filled with 17 ppg Neo cement and correlated to Plug log. Dump cement and POOH. Good dump. We added the 5' of bailer to compensate the perfs drinking any cement. Pressured lubricator up to 1,700 psi with N2. RIH w/ 2.5'x 45' dump bailer filled with 17 ppg Neo cement and correlated to Plug log. Dump cement and POOH. Good dump. Pressured lubricator up to 1700 psi with N2. RIH w/ 2.5'x 45' dump bailer filled with 17 ppg Neo cement and correlated to Plug log. Dump cement and POOH. Good dump. Est TOC 5,514' and cement in place at. Rig down lubricator and secure the well. Rigged down rest of equipment. TP - 1,700 psi WOC and compressor work than we will perforate. 08/12/2019 - Monday Sign in. Mobe to location. Spot and rig up AKE-Line equipment. Attempt PT but had o- ring leak. Replaced and PT to 250 psi low and 3000 psi high. TP - 1679, RIH w/2 -3/8"x3' HC, 6 spf, 60 deg phase and tie into plug correlation log. Tag TOC at 5513'. Run correlation log and send to town. Get ok to perf from 5483�'to 5486'. Spotted and fired gun with 1683 psi tubing pressure. After 5 min - 1725 psi, 10 min - 1731.8 psi and 15 min 1737.2 psi. POOH. All shots fired and gun was dry. Had a little bit of sand in the gun and bull plug. Not much though. Rig down lubricator and turn well over to field. 08/15/2019 - Thursday Sign in. Mobe to location. PTW and JSA. SIMOPS with Pollard Slickline. Spot and rig up AKE-Line equipment. PT lubricator to 250 psi low and 3,000 psi high. TP - 620 psi. RIH w/GPT tool, tie into Perf log dated 8-12-19 and tag TOC at 5,513'. Found fluid level at 5,360' with 616 psi on tubing. POOH. Send log to town. GPT log was off 2'. Called town and discussed log and tubing pressure. RIH w/ 2-3/8" x,30' Razor HC, 6 spf, 60 deg phase and tie into revised GPT log. Run correlation log and send to town. Get ok to pert from 5,468' to 5,498' with 612.8 psi. Spot and fired gun. Pressure started bc711ding right away, after 5 min it was 1447 psi, 10 min - 1,458 psi and 15 min -1,455, Tools got blown up hole. Line tension was 1,100 Ib when gun was fired. Lost 600 Ib of line tension right after gun fired. Picked tools up. 80' before we got the 1,100 Ib back. Called town and discussed. Pull up to 3,500 Ib on line 6 or 7 times and it came loose but looked like the tools weren't on it. Also flowed well to try and get some pressure off but hung around 1,570 psi at 600K rate. Pull line up to 754' and worked thru that spot to 410'. Pulled up to 2,200 Ib but wouldn't come thru flow tubes. Stripped and cut approx 410' out of hole at 40' each strip. and cut. Looks like we left 50' or less of wire and the a -line tools in well. Slickline will be out in the morning at 7 am. Ed with AKE-Line will send them the drawing of tools and wire. E -Line will be at KGF to perf KU 24-05B in the morning at 10 am. Rig down off well and turn well over to field. 09/27/2019 -Thursday Met with Reservoir Engineer and jointly decided to call off Soaping operation to try to bring on well. R llilcen, Alask,.. LIA mitL 192-122 9P. 50.133.20445-00-00 party Des: FEDA-028083 ElIvation,n: 183' (23' AGL) Id Date: 7/26/1994 Reached: 8126/1994 Released: 9/5/1994 60" 39' 30.34" N 151° 01'04.48" W I Tree can: 6-1/2" Otis I Completion Assembly Includes: 1 - Gaslift Mandrel, 992' MD (Dummy set 3/1114) 2 - Chemical Injection Mandrel, 1,469' MD (Valve 311114) 3 - Gaslift Mandrel, 5,366' MD (Orifice set 11117114) 4 - DLH Hydraulic Packer, 5,410' MD (40K Shear) 5 -X-Profile, 5,427' MD 6 - WLEG, 5,440' MD 7 - Bridge Plug, 5,549' MD 7/23119 w/ 36' of cement (TOC 5,513') 8/12119 8 - Bridge Plug, 5,615' MD BC -9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M. st Tao: 8 5,552'RKB _Cut Tubing 04/10/15 @ 5,620' MD a 2" Bailer PX Plug @ 5,739' MD CMU Sliding Sleeve @5,823'MID 2.813" ID Production Seal Unit - Model H liner hanger packer @ 5,828' MD Beluga 6,429'.6,459' MD (30') 1/13/2004 Cmt Squeezed Wet Upper Beluga with 10 bbl, 15.8 ppg, 68 sks, of Class G 2,500 psig squeeze 7/28/2007 Model N Bridge Plug @ 8,808' MD G C 838 Be SCHEMATIC Conductor 133/8" K-55 61 ppf Top Bottom MD T 116' 7VD 0' 116' Surface Casino 9518" N,80 47 ppf BTC Top Bottom MD 0' 1,853' TVD 0' 1,790' 12-114" hole Cant .1700 sks Intermediate Casino T' N-80 29 plat BTC Top Bottom MD 0' 5,950' TVD 0' 5,569- 8-1/2" hole Cmt w/ 565 sks, in We stages w/ DV tool @ 4,487' MD Tubing 3.1/2" L-80 9.2 ppf IBTAB-Motl Top Bottom MD 0' 5,430' ND 0' 5,049' Sterling P.r orafons- Liner MD 3.1/2" N40 9.2 ppf AB -Mod IBT W. Top Bottom MD 5,014' 8,881' Tag FIII TvD 5,433' 8,496' @ 5,703' MD 6" hole Cmt w/ 500 sks, 150 sks to surface on 2/18/14 5,533'5,553' Sterling P.r orafons- BID MD Lt W. 5,466'-5,498' 30' B3B 5,483-5,486' 3' B3L 5,533'5,553' 20' B4 Date 12' Beluga Perforations. 8 MD R 114 G.429! 5V 38 816 7,420'-7,460' 40' 817 7,4M534'-7,574' 40' B18 7,6-7,660' 20' B19 7.706-7,725' 20' 7.344'-7.374' 7,725'-7,755' 30' (9/251%) 7,762'-7,817 50' B20 7,812'-7,847 30' 2-0/T, 60°, 6 SPF 7,852'-7,887 30' 821 7,893'-7,933' 40' B23 7,980'.8,030' S0' (915194 8,036'4,054' 18' 8,072'41,098' 26' B24 8,167- 4,187 20' B25 8,241'-8,446' S' (9/21194) 8.254'-8,261' 7' 8,276'.8,297 16 B27 8,399'4.409' 10' (91i8/94) 8437.81457 20' TO BID 8,881' MD 5,513' MO 8,496' ND 5,132' ND ND Gun�T t Date 5,087- .5,'HT 5,107-5,105' 24/8" HC, 6 SPF &15119 8/12/18 5,152'-5,172' 2-3/8' HC, 6 SPF 3/05114 5,256' 2-112- He, 12 SPF 2" Scallop, 6 SPF (&7198) TVDGun 6;048.4,078 T� ^�_A 4 SP. Date (Cement aqua d) Donna Ambruz Downhole Revision Date: 8 p/p j 7,039'-7,079' / (10/2196) 7.153'-7,193' �}90�Ire� 7.259'-7,2'79' - 10{ (91P8/%) 7,324'-7,344' ..: 0 PbFk (9/26196) 7.344'-7.374' p- 2-�/,:&, SPF (9/251%) 7,381'-7,431' (&13196) 7,431'4,461' 2-0/T, 60°, 6 SPF (819/96) 7,471'.7,501' 7,512'4.657 ({; (915194 7cture (g/25/gq) (Frecture Treated) Treat ikgl° I 7,655'-7.673' - (9/21194) (Fracture Treated) 7,691'-7,717- (9124/94) 7,786'-7,806' (91i8/94) 7,860'4,865' (9116/94) 7,873'4,880' (9/16/94) 7,895'-7,911' (9116/94) 8,018'4,1128' (9115/94) 8,051'4,071' (9/15/94) Well Name& Number: Beaver Creek Unit #9 Lease: A-028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska I Countryl USA Angle @KOP and Depth: 8.0° 1,000' Angle/Perfs: 0° Maximum Deviali n: 3L@ 2,500' Date Completed: 02/28/14 Ground Level (above MSL): 760' RKB (above GL): 23' Revised By: Donna Ambruz Downhole Revision Date: 8/15/2019 Schematic Revision Date: 1 9/19/2019 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Beaver Creek Field, Beluga Gas — Sterling Gas Pool, BCU 09 Permit to Drill Number: 192-122 Sundry Number: 319-306 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 W W W.aogcc.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, 40 Daniel T eamount, Jr. Commissioner DATED thisday of June, 2019. RBDMS14,'JUN 2 6 2019 RECEIVED STATE OF ALASKA 1UN 2 ALASKA OIL AND GAS CONSERVATION COMMISSION 2��� APPLICATION F R SUNDRY APPROVALS /420 0 AAC 25 280 - 1. Type of Request: Abandon ❑ Plug Perforations Fracture Stimulate ❑ Repair Well ❑ Operations shutdown El Suspend ❑ Perforate ❑✓ • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑✓ Stratigraphic ❑ Service ❑ 192-122 ' 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20445-00-00• 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 2378 Will planned perforations require a spacing exception? Yes ❑ No ❑✓ Beaver Creek Unit (BCU) 09 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028083 Beaver Creek / Beluga Gas - Sterling Gas it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8,881' 8,500' 5,615' 5,234'-1,574psi 5,615' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 116' 13-3/8" 116' 116' Surface 1,853' 9-5/8" 1,853' 1,790' 4,750 psi 6,870 psi Intermediate 5,950' 7" 5,950' 5,569' 7,020 psi 8,160 psi Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3-1/2" 9.2# / L-80 5,430' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): DLH Hydraulic Pkr 5,410' MD / 5,029' TVD 12. Attachments: Proposal Summary El Wellbore schematic ✓ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Strati ra hic g p ❑ Development ❑✓ Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: July 7, 2019 OIL ❑ WINJ ❑ 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: Ted Kramer Authorized Title: Operations Manager Contact Email: lkramerCdhilcorD.com Contact Phone: 777-8420 `^'^-i Z Authorized Signature: Date: U(� 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: 1BDMS-��UN 2 6 2019 Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes El No Subsequent Form Required: / 0 .- / OL1./ APPROVED BY Approved by' COMMISSIONER THE COMMISSION Date: G P4 Submit Form and orm c-403 evised 4217 Approved applicatiorQv li t�r�drr�Okh{ frlAm�he date of approval. ��/� I u I I\Y'N L /r/f��'� Attachments in Duplicate'/ 4 •27-� /% R Hi1wrD Masi., M Well Prognosis Well: BCU -09 Date: 6/20/2019 Well Name: BCU -09 API Number: 50-133-20445-00 Current Status: Shut In Gas Well Leg: N/A Estimated Start Date: July 7th, 2019 Rig: E -line Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 192-122 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Bo York (907) 777-8345 (0) (907) 727-9247 (M) AFE Number: Current Bottom Hole Pressure: Maximum Expected BHP Max. Allowable Surface Pressure: Brief Well Summary — 2,100 psi @ 5,262' TVD (Flowing survey August 2013 base perf 5,643' MD) ^- 2,100 psi @ 5,262' TVD (Flowing survey August 2013 base pert 5,643' MD) 1,574 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft)) Beaver Creek #9 was drilled as a grassroots gas well in 1994 to target the lower Beluga gas sands. This well was worked over in 1998 to include the Sterling B-4 zone and flow this zone up the annulus. Additional perforations were added in the Upper Beluga in 2003. This zone watered out shortly after coming online and was cement squeezed in 2007. The Beluga was isolated with a PX plug in March 2013. The Sterling B-4 zone flowed gas and water (up to 1,000 bwpd) until going offline in the summer of 2013 when it loaded up with fill. A rig workover in 2014 isolated the B4 and added the B3. The B3 initial production was 10 MMcfd but declined rapidly until it watered out in June 2015 after recovering almost 3 BCF of gas. �C The purpose of this work/sundry is to isolate the B3 and add two sets of perforations in the 13313 Sand. Note: Nitrogen may be required to push away water prior to setting a CIBP. Notes Regarding Condition Condition • Last tag at 5,552' RKB on 4/10/15 w/ a 2.0" Bailer. E -line Procedure: 1. MIRU E -line, PT lubricator to 3,000 psi Hi 250 Low. a. Tree connection is 6.5" OTIS. 2. PU RIH W/ GPT tool and locate fluid level and tag for fill. a. If fluid level is over the desired perfs, pressure up with Nitrogen And push fluid away. POOH. 3. PU RIH W/ through tubing CIBP to 5,530' and set same. Place 10' of Cement on top of plug. POOH. .n Hila,m Alaska, LL, 4. PU RIH W pert guns perforate the following intervals : Well Prognosis Well: BCU -09 Date: 6/20/2019 Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) ft B3B ±5,468' ±5,471' ±5,087' ±5,090' 3' B3B ±5,483' ±5,515' ±5,102' ±5,134' 32' a. Perfs maybe shot one ata time and shot up to 12 JSPF (6 JSPF X 2). b. Proposed perfs 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. Use Gamma/CCL/ to correlate. e. Record tubing pressures before and after each perforating run. f. Spacing allowance is based on CO 2378, no restrictions in Sterling Gas Pool. 5. RD E -line. 6. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Standard Nitrogen Procedure R ilih-,. Al -Le. 1.1.1: k_ 192-122 50-133-20445-00-00 /Des: FEDA - 028083 ation: 183' (23' AGL) AW7/26/1994 :hed: 8/26/1994 ase7: 9/5/1994 317,605 2,434,000 60' 39'30.34" N 151' 01'04.48" W Tree cxn: 64W 0019 Completion Assembly Includes: 1 - Gaslik Mandrel, 992' MD (Dummy set 3/1/14) 2 - Chemical Injection Mandrel, 1,469' MD (Valve 3/1/14) 3 - Gaslift Mandrel, 5,366' MD (Orifice set 11/17/14) 4 - DLH Hydraulic Packer, 5,410' MD (40K Shear) 5 - X -Profile, 5,427' MD 6 - WLEG, 5,440' MD 7 - Bridge Plug, 5,615' MD on 04/10/15 w/ a 2" Bailer PX Plug @ 5,739' MD CMU Sliding Sleeve @ 5,823' MD 2.813" ID BC -9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M. Cut Tubing @ 5,620' MO Production Seal Unit - Model H liner hanger packer @ 5,828' MD Beluga 6,429'3,459' MD (30') 1/13/2004 Cmt Squeezed Wet Upper Beluga with 10 bbl, 15.8 ppg, 68 sks, of Class G 2,500 psig squeeze 7/28/2007 Model N Bridge Plug @ 8,808' MD C SCHEMATIC Conductor 13-3M" K55 61 ppf 33-1/2" N80 9.2 ppf AB -Mod IBT Top Bottom MD 0' 116' WD 0' 116' Surface Casino 95/8" N-80 47 ppf BTC Top Bottom MD 0' 1,853' TVD0' 1,790' 12414" hole Cmt w/ 700 sks 2:�j 2-, 60,' 65PF Intennedlate Casino 7,420'-7,460' T' W80 29 ppf BTC 7,534'4,574' Top Bottom 7,640'-7,660' MD 0' 5,950' 7,T05'-7,725' ND 0' 5,569' 7,725'-7,755' 8-1/2" hole Cont .1565 sks, in two 7,762'-7,812' stages w/ DV tool @ 4,487' MD B20 7,8124,842' 30' Tubing 7,857-7,882 30' 3-1/2" L-80 9.2 ppf HIT AB -Mod 40' Top Bottom so MD 0' 5,430' 18' We 0' 5,049' 64 Liner 8,881' MD 33-1/2" N80 9.2 ppf AB -Mod IBT it Top Bottom MD 5,814' 8,881' Tag Fill @5,703' MD TVD 5,433' 8,496- 6" hole Cmt wl 500 sks, 160 sks to surface on 2118/14 5,629'5,637' sterling Perforations: PBTD 8,881' MD MD it 1331- 5,533'5,553' 20' B4 5,629'5,637' 12 Bewaa Perforations: 2-3%... An., 4SF (]/28107) MD B (10/2196) ],153'-],193' 2:�j 2-, 60,' 65PF B16 7,420'-7,460' 40' B17 7,534'4,574' 40' B18 7,640'-7,660' 20' B19 7,T05'-7,725' 20' (8/9196) 7,725'-7,755' 30' (817/96) 7,762'-7,812' S0' B20 7,8124,842' 30' (9125194) 7,857-7,882 30' B21 7,893'-7,933' 40' B23 7,980'-8,030' so 8,036'-8,0.54' 18' (9/21/94) 8,072'8,098' 2w B24 8,16T -8,1§T 20' B26 8,211'-8,886' V (9/16194) 8,254'-8,''21861' T (9116/94) 8,276.5,292 IV B27 8,399'-8409' 10' (9/15m) 8,4378,457 20' TD PBTD 8,881' MD 8,808' MD 8,496' ND 8,426' ND TVD Gu.o Date 5,152'-5,172' 2-1/2' HC, 12 SPF 3/05114 5,218' - 6,256' 2" Scallo,, 6 SPF (617/98) ND n:°. a °.w Gun Date (1I12I04) (Cement squeezed)6 2-3%... An., 4SF (]/28107) 7,039'-],079' 6og. 6 &� (10/2196) ],153'-],193' 2:�j 2-, 60,' 65PF (91301%) 7,259'-7,279' 7.324'-7,344' z1�� 660 5553VFF 2:1Y2".6�.65PF 11117/20141 7,3"-7,374' 2-112", 60°1 6 SPF 2-112", 60°, 6 SPF (9196) 9125196 ( ) 7,381'-7,431' 2-171", 60°, 6 SPF (8113/96) 7,431'-7,461' 2412-,W',6 SPF (8/9196) 7,471'-7,501' 2-112", 60°, 6 SPF (817/96) 7,517-7,557 (815196) 7,599'-7,649' 2-117', 60°, 6 SPF (9125194) (Fracture Trebled) 2-112", 60°, 6 SPF 7,655'-7,0173' 211r, 60°, 6 SPP (9124194) (Fracture Treated) 2-1/r, 60',6 SPF 7,691'4,717 2-112", 60°, 6 SPF (9/21/94) 7,786'-7,806' 2-112', W. 6 SPF (9/18194) 7,860'-7,865' (9116194) 7,873'4,880' (9/16194) 7,695'4,911' (9116/94) 8,018'-8,028' (9115/99) 8,051'8,071' (9/15m) Well Name & Number. Beaver Creek Unit #9 Lease: A - 028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA Angle @KOP and Depth: 8.0° 1,000' 'J 0. 0° Maximum Deviation: 32° 2,500' Date Completed: 02/28/14 Ground Level (above MSL): 160' 1 RKB (above GL): 23' Revised By: Donna Ambruz Downhole Revision Date: 11117/20141 Schematic Revision Date: 6/21/2019 N Ilil...... .4t -k.. LI.0 192-122 50-133-20445-00-00 Des: FEDA-028083 KW 183' (23' AGL) e: 7/26/1994 ied: 8/26/1994 sed: 9/5/1994 60° 39' 30.34" N 151° 01'04.48" W Tree can: 6-1/2" Obs Completion Assembly Includes: 1 - Gaslift Mandrel, 992' MD (Dummy set 311114) 2 - Chemical Injection Mandrel,1,469' MD (Valve 31VI41 3 - Gaslift Mandrel, 5,366' MD (Orifice set 11117114) 4 - DLH Hydraulic Packer, 5,410' MD (40K Shear) 5 - X -Profile, 5,427' MD 6 - WLEG, 5,440' MD 7 - Bridge Plug, 5,530' MD w/ 10' of cement (5,520') 8 - Bridge Plug, 5,615' MD 04110/15 a 2" Bailer PX Plug @ 5,739' MD CMU Sliding Sleeve Qp 5,823' MD 2.813" ID BC -9 Pad 3 1,188' FNL & 1,568' FWL Sec. 34, T7N, R10W, S.M. Cut Tubing @ 5,620' MD Production Seal Unit Model H liner hanger packer @ 5,828' MD Beluga 6,429'.6,459'MD (30') 1/13/2004 Cmt Squeezed Wet Upper Beluga with 10 bbd, 15.8 ppg, 68 sks, of Class G 2,500 psig squeeze 7/28/2007 Model N Bridge Plug @ 8,808' MD C _> 383L PROPOSED SCHEMATIC 64 Conductor Date 13318" K-65 61 ppf Top Bottom Top Bottom 1,853' MD 0' 116' (W7M) TVD V 116' 64 Surface Casino Date 9518" N40 47 ppf BTC Top Bottom MD 5,814' 8,881- ,881' Top Bottom Proposed MD 0' 1,853' W05114 TVD 0' 1,790- (W7M) 12-1/4" hole Cori .1700 sks 17ons: Intermediate Casino 7" N40 29 ppf BTC Top Bottom MD 0' 5,950' TVD V 5,569- 8-1/2" hote Cent w/ 565 sks, In two stages w/ DV tool @ 4,487' MD 7,534•-7,574' 40' 818 TubinO 27 B19 3-1/2" L40 9.2 pid IBT AS -Mod Top Bottom MD V 6,430' B20 TVD 0' 6,049' 64 Liner Date 3.1/2" N40 9.2 pin AB -Mod WT B71' Top Bottom MD 5,814' 8,881- ,881' T Tag FIII 't @ 5,703' MD on 2/18/14 ,496' TVD 5,433' 8,496- 6" hole Cmt w/ 500 sks, 150 sks to surface S[edina Pedoratlons' Date i5,NT35,050' B71' Proposed 35,102'35,134' 3'5' Proposed W5,53TZ,553' 373' W05114 5,248' - 5,266' 20' (W7M) 02/28/14 Ground Level (above MSL): 17ons: 1 RKB (above GL): 23' 2' Scallop, 6 SPF MD ft B4 6,4274,468= 30' B16 7 4p•-7460' 47 B17 7,534•-7,574' 40' 818 7,640'-7.660' 27 B19 7,705'-7,725' 20' 7,725'-7,755' 30' 7,762'4,817 57 B20 7,81r-7,842' 37 pp:�I�2,",� 5p^°.5 gpF 7,852-7,667 37 B21 ],893'-7,933' 47 B23 7,980'4,030' 57 2-117', 60°, 6 SPF 8.036'4,054' 18' 2 -IM' 60° 6 SPF 8,072'4,098' W B24 8,16T 4,187- 27 B25 8,241'-8,446' S' 2-1/r, 60°, 6 SPF 2-1/r, 60°, 6 SPF 8,254'4,261' T 2-1/Y', 60', 6SPF 8,276'4,297 16' B27 8,399'4,409' 17 8.432'4.452 27 TO PBTD 8,881' MD 8,808' MD 8,496' TVD 8,426' TVD TVD Gun Tye Date i5,NT35,050' TBD Proposed 35,102'35,134' State/Prov: Proposed 5,157-5,177 TBD W05114 5,248' - 5,266' 2,600' (W7M) 02/28/14 Ground Level (above MSL): 2-1/2' HC, 12 SPF 1 RKB (above GL): 23' 2' Scallop, 6 SPF Donna Ambruz Downhole Revision Date: WD Schematic Revision Date: Date 6,-048'4,0]8' (Cement squeezed) Gun TlftZa Wi2/04) (7/28107) 7,039'.7,079'23/8°,°^",�r48Pr (10/2/96) 7,153'-7,193' / •, (930/96) 7,259'4,279' = f (9/28/96) 7,324'-7,344' (926/96) 7,344'-7,374' 7,381'4,431' (Wi996) pp:�I�2,",� 5p^°.5 gpF (8/9/96) 7,41:7,501' Z-1%2".60°.65PF 817/96) 7,517-7,557 2-1/2, 60°, 6 SPF (95/96) 7,599'-7,"7- 2-117', 60°, 6 SPF (925194) (Fracture Treated) 2 -IM' 60° 6 SPF 7,655'.7,673' 2-1/2", 60°,, 6 SPF (924/94) (Fracture Treated) 24/2, 60°, 6 SPF 7,691'.7,71T 2-1/r, 60°, 6 SPF 2-1/r, 60°, 6 SPF (Wz&") 7,786'-7,806' 2-1/Y', 60', 6SPF (W1W94) 7,860'-7,865' (W76194) 7,873'-7,880' (W1a/9.1) 7,895'-7,911' (9116194) 8,018'4,028' (stism) 8,051'4,071' (W16/94) Well Name 8 Number: Beaver Creek Unit #9 Lease: A • 028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA Angle @KOP and Depth: 8.0" 1,000' Angle/Perfs: 0" Maximum Deviadon: 32" 2,600' Date Completed: 02/28/14 Ground Level (above MSL): 160' 1 RKB (above GL): 23' Revised By: Donna Ambruz Downhole Revision Date: 11/17120141 Schematic Revision Date: 6/21/2019 STANDARD WELL PROCEDURE Iileorp Alaska, LLC 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 vl Page 1 of 1 10,000,000 1,000,000 L Y 0 c� C V CL 100,000 LL cV C 0 Y 10,000 m _ � O 0 o Y v (0 u 0 1,000 _V 3 V C m 100 0 0 L 10 1 Jan -1998 HILCORP ALASKA LLC, BEAVER CK UNIT 09 (192-122) BEAVER CREEK, BELUGA GAS Monthly Production Rates 10,000,000 M 1,000,000 0 M 1 100,000 0m 1 0 3 10,000 s 0 w l 1,000 0 -h d .t ro 100 n m 1 0 7 10 T 1 Jan -1995 Jan -2000 Jan -2005 Jan -2010 Jan -2015 Jan -2020 — Produced Gas (MCFM) a GOR � Produced Water (SOPM) - Produced Oil (BOPM) SPREADSH EET_1921220_BCU-9_Prod_Cu"es_W a II_Oi I_V120_20190624.xlsx 6/24/2019 STATE OF ALASKA RECEIVED ALA, t OIL AND GAS CONSERVATION COMMI, iN REPORT OF SUNDRY WELL OPERATIONS App 0 44 Z014 1.Operations Abandon U Repair Well H Plug Perforations U Perforate U Other L .cGCC Performed: Alter Casing ❑ Pull Tubing 0 Stimulate-Frac El Waiver ❑ Time Extension El Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory ❑ • 192-122 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 . 50-133-20445-00 7.Property Designation(Lease Number): 8.Well Name and Number: e FEDA028083 ' Beaver Creek Unit(BCU)09 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): • N/A Beaver Creek/Beluga Gas-Sterling Gas 11.Present Well Condition Summary: Total Depth measured • 8,881 feet Plugs measured 5,615 feet true vertical 8,500 feet Junk measured N/A feet Effective Depth measured - 5,615 feet Packer measured 5,410 feet true vertical 5,234 feet true vertical 5,029 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 116' 13-3/8" 116' 116' Surface 1,853' 9-5/8" 1,853' 1,790' 4,750 psi 6,870 psi Intermediate 5,950' 7" 5,950' 5,569' 7,020 psi 8,160 psi Production Liner SCANNED MAY 2 7 2014 Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.2#/L-80 5,430'MD 5,049'ND • Packers and SSSV(type,measured and true vertical depth) DLH Hydraulic Pkr N/A;N/A 5,410'MD 5,029'ND 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A RBDM MAY 14 2014 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 257 400 40 205 Subsequent to operation: 0 10,846 0 105 1,608 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development 0 • Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil ❑ . Gas 0 WDSPL❑ 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: 314-091 Contact Stan Porhola Email sporholatG7.hiIcorp.com Printed Name Stan Porhola Title Operations Engineer Signature ,,,i/2-7-/nOlk Phone 907-777-8405 Date p(-Vi7 Form 10-404 Revised 10/2012 0 f74. 4 Submit Original Only II Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date BCU-09 50-133-20445-00 192-122 2/26/14 3/5/14 Daily Operations: 02/26/2014-Wednesday MIRU WOR and equipment. Installed Winterization. Bled tbg and csg down to rig tank, Pumped 40 bbls of FSW down tbg, Set BPV, ND PT, NU 7" BOP Stack and connected lines. MU 3-1/2" test joint and floor valves. Tested Valves 250-3000psi, Rams 250-3,000psi and_Annular 250-3,000psL,Charted each test for 10 mins. No failures recorded. 02/27/2014-Thursday Tested the BOPE (Witness waived by Jim Regg, AOGCC), 250 psi low-3000 high psi. MIRU EL, MU tool string with tbg punch 6 shots total. MU Landing jt. TIH and tag at 5,644'ELM. Logged up with CCL to 5,300'. Sent Log to town to for correlation. With tbg punch on depth, punched holes at 5,625'-5,631'. POOH. Well static. TIH with jet cutter to 5,620'. Backed out lockdown pins and PU 10k over string weight. Cut tbg 5,620'. Landed hgr and POOH. RDMO EL. PU tbg hanger and LD. TOOH w/ pup jts, 80 stand and 1 cut jt. PU BP and setting tool and TOOH. Tagged cut jt and PU 5'. Set the top of the BP 5' above the cut jt at 5,615'. RU filter unit and and circulated 220 bbls of 6% KCL. Tested BP to 1,500psi for 30 mins-Test Ok. SOOH and LD setting tool. 02/28/2014- Friday TIH w/3-1/2" completion/jewlery and_25" control line. WLRG, DLH Hydraulic Packer, 2 GLM and Chemical injection mandrel. Landed hanger and secured lock down pins. Dropped the bar and set the packer @ 5,409'. Tested to 3,500psi for 30mins and charted -test ok. Pumped down the cgs and circulation thru GLM. Picked up on tbg to confirm pkr set- pkr is set. Set BPV, ND BOP/NU PT. Pulled BPV. RDMO WOR and equipment. 03/01/2014-Saturday RU Pollard Slickline. PT Lubricator to 250/3,500 psi -test OK. RIH w/2.0"JDC and latch RHBC prong at 5,406'. RIH w/3-1/2" KOT to 5,384', pull dummy valve. RIH w/3-1/2" KOT to 1,474', pull dummy valve. RIH w/3-1/2" KOT to 1,052', pull dummy valve. RIH w/3-1/2" KOT to 1,052', set new dummy valve. RIH w/3-1/2" KOT to 1,474', set chemical injection valve (1,500 psi spring pressure). RIH w/3-1/2" KOT to 5,384', set pocket protector. RIH w/3-1/2" GS to 5,424', pull RHBC plug body. RIH w/ 2.5"x20' dummy gun to 5,624'. Tag bridge plug. POOH. Rig down slickline. 03/04/2014-Tuesday Rig up Baker Nitrogen Pumping Unit. Pressure test lines to 2,000 psi -test OK. Pump 126,000 scf and displaced 175 bbl of 6% KCI. Pump a total of 180,848 scf to bring tubing/casing to 2,000 psi. Secure well. Rig down Nitrogen Unit. 03/05/2014-Wednesday Rig up Schlumberger. RIH w/ PNL/GR/CCL. RIH and log from 5,236'-5,612'. POOH. RIH w/ Perf Gun #1. RIH and correlate guns on depth (2.5" Power Jet Omega)at 5,533'-5,553' to perforate the Sterling B-3. Fire guns. Tubing pressure increased from 1,520 to 1,580 psi. Built to 1,640#in 10 minutes. RIH w/ Perf Gun#2. RIH and correlate guns on depth (2.5" Power Jet) at 5,633'-5,553'to perforate the Sterling B-3 (to get 12 spf). No change in tubing pressure after shot, howerver, it continues Ito climb. Rig down SLB. Ir- •iii• BC_9 ACTUAL Ilikrnrp Alaska•I,ff Pad 3 SCHEMATIC 1,188'FNL&1,568' FWL Sec. 34,T7N,R10W,S.M. i 50-133-20445-00-00 ••e Des: FEDA-028083 levation: 183' (23'AGL) - - Conductor d Date: 7/26/1994 133/8" K-55 61 ppf - TD Reached: 8/26/1994 Top Bottom Riq Released: 9/5/1994 Mo o' 116' X: 317,605 TVD 0' 116' Y: 2,434,000 1 60°39'30.34"N 151°01'04.48"W Surface Casing 2 9-5/8" N-80 47 ppf BTC Top Bottom MD 0' 1,853' TVD 0' 1,790' Tree cxn:6-1/2"Otis 12-1/4"hole Cmt w/700 sks 3 Completion Assembly A Includes: _ Intermediate Casing 1-Gaslift Mandrel,992'MD 4 7" N-80 29 ppf BTC 2-Chemical Injection Mandrel,1,469'MD Top Bottom 3-Gaslift Mandrel,5,366'MD MD 0' 5,950' 5 TVD 0' 5,569' 4-DLH Hydraulic Packer,5,410'MD(40K Shear) 8-1/2"hole Cmt w/565 sks,in two 5-X-Profile,5,427'MD 6 stages w/DV tool @ 4,487'MD 6-WLEG,5,440'MD 7-Bridge Plug,5,615'MD TubinO Last Tao: B3 3-1/2" L-80 9.2 ppf IBTAB-Mod Top Bottom 5,624'SLM I MD 0' 5,430' 2.5"Dummy Gun 7 -; 1111 TVD 0' 5,049' 3/01/14 r:. Cut Tubing �' ti. @ 5,620'MD %. ...... B4 al :a°- Liner h, { 3-1/2" N-80 9.2 ppf AB-Mod IBT y .s r• Top Bottom ?' l: :Y 11 r MD 5,814' 8,881' } f}1 Tag Fill TVD 5,433' 8,496' r ?• r: @ 5,703'MD 6"hole Cmt w1500 sks, 150 sks to surface ti,„ , .,, 4::• r..•,. on 2/18/14 PX Plug :t f.•' @ 5,739'MD 1 r Sterling Perforations: CMU Sliding Sleeve { MD ft �(Q Gun Type Date r ?' '; 83 5,533'-5,554' 5,152'-5,173' 2-112"HC,6 SPF Proposed @ 5,823'MD a} 2.813"ID 11. ti'* B4 5,629'-5,637' 12' 5,246'-5,256' 2"Scallop,6 SPF (6/7/98) ''• •°,,..7: Beluga Perforations: ti l•, �}P '� MD ft rvD Gun Type Date Production Seal Unit I �• g4 gy29'6,469' 30 6.048-6,07& 2 3/r,-60,,4SRF (1/12104) f/[ (Cement squeezed) / „ (7/28/07) Model H liner hanger packer -F . B16 7,420'-7,460' 40' 7,039'-7,079' ii--1//: :1/3••,28:'8 R�� (10/2/96) @ 5,828'MD B17 7,534'-7,574' 40' 7,153'-7,193' 2-1/ ,,,Sg°,6 R�� (9/30/96) B18 7,640'-7,660' 20' 7,259'-7,279' yy /pp••'gg 6 (9/28/96) 819 7,705'-7,725' 20' 7,324'-7,344' 2.112 ,68°;6 SPF (9/26/96) t. 7,725'-7,755' 30' 7,344'-7,374' 2-1/2",60°,6 SPF 9/25/96 2-1/2",60°,6 SPF (9/25/96) � '_• 7,76T-7,812' 50' 7,381'-7,431' 2-1/r,60°,6 SPF (8/13/96) Beluga 6,429'-6,459'MD (30') 1/13/2004 620 7,812'-7,842' 30' 7,431'-7,461' 2-1/2",60°,6 SPF (8/9/96) Cmt Squeezed Wet Upper Beluga with 7,852'-7,882' 30' 7,471'-7,501' 2-1/2",60°,6 SPF (8/7/86) q pP 9 B21 7,89X-7,933• 40' 7,51T-7,552' (8/5/96) 10 bbl,15.8 ppg,68 sks,of Class G -- B23 7,980'-8,030' 50' 7,599'-7,649' 2-1/2",60°,6 SPF (9/25/94) 2,500 psig squeeze 7/28/2007 " (Fracture Treated) 2-1/2",60°,6 SPF IL= 8,036'-8,054' 18' 7,655'-7,673' 2-1/2",60°,6 SPF 2-112",60°,6 SPF (9/24/94) (Fracture Treated) 2-1/2",60°,6 SPF l 8,072'-8,098' 26' 7,691'-7,717' 2-1/2",60°,6 SPF (9/24/94) 824 8,167'-8,187' 20' 7,786'-7,806' 2-1/2",60°,6 SPF (9/18/94) 625 8,241'-8,446' 5' 7,860'-7,865' (9/16/94) -- 8,254'-8,261 7' 7,873'-7,880' (9/16/94) 'I Model N Bridge Plug 8,276'-8,292' 16' 7,895'-7,911' (9/16/94) @ 8,808' a 827 8,399'-8,409' 10' 8,018'-8,028' (9/15/94) 8,432'-8,452' 20' 8,051-8,071' (9/15/94) TD PBTD 8,881'MD 8,808'MD 8,496'TVD 8,426'TVD Well Name&Number: Beaver Creek Unit#9 Lease: A-028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA Angle @KOP and Depth: 8.0°@ 1,000' Angle/Perfs: I 0° Maximum Deviation: 32°@ 2,500' I Date Completed: 02/28/14 Ground Level(above MSL): 160' RKB(above GL): 23' Revised By: Stan Porhola Downhole Revision Date: 3/1/2014 Schematic Revision Date: 3/25/2014 f ,&;,---,,,4, THE S TAT L`a,c!f_ C Lia n' �,i 4 '�- 4� ° � O P �� , ` 1'7 t _ = 333 Wes $even.th Avenue kV GOV1',IZ\C)K SEAN 1�ARNLL1 Anchorage, Alaska 99501 3572 .A Main. 907.279. 433 ' '--,-.AL,Aj-> ^��� Fc�v: ;0 .% G 752 $0144° 9 1 Stan Porhola Operations Engineer Hilcorp Alaska, LLC --f 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Beaver Creek Field, Beluga& Sterling Gas Pools, BCU 09 Sundry Number: 314-091 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, f_29.,,,,4________ Cathy P. oerster Chair — DATED this Z day of February, 2014. Encl. RECEIVED • STATE OF ALASKA - FEB 1 q 2014 • ALASKA OIL AND GAS CONSERVATION COMMISSION arS 2l25� APPLICATION FOR SUNDRY APPROVALS AGC 20 MC 25.280 1.Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations Q• Perforate Q . Pub Tubing Q • Time Extension ❑ Operations Shutdown E Re-enter Susp.Well ❑ Stimulate ❑ Alter Casing ❑ Other. ❑ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number. Exploratory ❑ Development Q • 192-122 ' 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20445-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 237 Beaver Geek Unit(BCU)09 • Will planned perforations require a spacing exception? Yes ❑ No Q 9.Property Designation(Lease Number): 10.Field/Pool(s): FEDA028083 Beaver Creek/Beluga Gas-Sterling Gas , 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): 8,881 ' 8,500 ' 8,808 8,427 5,739' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 116' 13-3/8" 116' 116' Surface 1,853' 9-5/8" 1,853' 1,790' 4,750 psi 6,870 psi Intermediate Production 5,950' 7" 5,950' 5,569' 7,020 psi 8,160 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" 9.2#,L-80 5,824 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): Baker Model H Liner Hanger Pkr;N/A 5,828'MD/5,447'ND 12.Attachments: Description Summary of Proposal Q '13.Well Class after proposed work: Detailed Operations Program U BOP Sketch U Exploratory LI Stratigraphic U Development U t Service U 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 02/24/14 Oil ❑ Gas 2 - WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Phone: 907-777-8412 Email sDorholat hilcorD.com Printed Name /��JSttaa_n Porrrhhhola _ Title Operations Engineer Signature ,•/' " ' L.„L Phone 907-777-8412 Date Z q// '-f- COMMISSION COMMISSION USE ONLY 111 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: q Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: K 3OD& /05 /SOP Te-75. /-- RBDMktIMAY 0 9 2014 Spacing Exception Required? Yes ❑ NoE( Subsequent Form Required: /O—yo y G APPROVED BY Approved by: COMMISSIONER .,/THECOMMISSION Date: Z-ZS-/ I n n /'�Form 10-403(Revised 10/2012) Approve( pRell fafro1 Emths t�Om the date Of aproval. Attachments in Duplicate' ` rel/ • Well Prognosis Well: BCU-09 Hilcorp Alaska,LI) Date:2/19/2014 Well Name: BCU-09 API Number: 50-133-20445-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: February 24th,2014 Rig: Moncla 405 ✓ Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 192-122 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: 1420538 Current Bottom Hole Pressure: —2,100 psi @ 5,262'TVD (Flowing survey August 2013 base pert 5,643' MD) Maximum Expected BHP: —2,100 psi @ 5,262'ND (Flowing survey August 2013 base pert 5,643' MD) Max. Allowable Surface Pressure: — 1,574 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft)) Brief Well Summary Beaver Creek#9 was drilled as a grassroots gas well in 1994 to target the lower Beluga gas sands. This well was worked over in 1998 to include the Sterling B-4 zone and flow this zone up the annulus.Additional perforations were added in the Upper Beluga in 2003.This zone watered out shortly after coming online and was cement squeezed in 2007.The Beluga was isolated with a PX plug in March 2013.The Sterling B-4 zone flowed gas and water(up to 1,000 bwpd) until going offline in the summer of 2013 when it loaded up with fill. The purpose of this work/sundry is to isolate the current perforated interval in the Sterling B-4 sand and complete the well in the Sterling B-3 sand. . Notes Regarding Wellbore Condition • Last tag at 5,703' RKB on 2/18/14 w/a 2.50" Pump Bailer. E-line Procedure: 1. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. a. Tree connection is 6.5"OTIS. 2. Pressure up tubing to 1,500 psi or at least 200 psi above casing pressure. 3. RU 3.5"Tubing Jet Cutter. 4. RIH and jet cut tubing at+/-5,700' MD. a. Have backup cutters on location if tubing does not part. 5. RD Eline. WO Rig Procedure: 6. MIRU Moncla#405 WO Rig. 7. RU Pump. 8. Circulate out gas in well with Produced Lease Water(8.5 ppg). 9. Set BPV. ND Tree. 10. NU BOPE.Test to 250 psi Low/3,000 psi High, annular to 250 psi Low/1,500 psi High(hold each valve and test for 10-min). Record accumulator pre-charge pressures and chart tests. Well Prognosis Well: BCU-09 Hilcory Alaska,LL Date:2/19/2014 a. Notify AOGCC 24 hrs in advance to witness. b. Notify BLM 48 hrs in advance of BOP test. c. BPV in hanger profile. 11. Bleed any pressure off tubing. Pull BPV. 12. MU landing joint and pull tension over string weight on tubing hanger to confirm tubing is cut. 13. SOOH and rack back 3-1/2" IBT-Mod tubing. 14. MU 7" CIBP. RIH on 3-1/2"tubing out of derrick. 15. Set CIBP at+/-5,620' MD. 16. Circulate well clean w/filtered 6%KCI(8.6 ppg). 17. Test casing to 1,500 psi for 30 min and chart. 18. SOOH and rack back 3-1/2"tubing. 19. PU completion w/WLEG,X-Profile, Hydraulic Packer,and Chemical Injection Mandrel. 20. RIH w/3-1 2"tubingand setpacker at+ -5 400'.Test casing/packer to 1,500 psi for 30 min. / / g/p 21. Set BPV. ND BOPE. NU tree. Pull BPV. 22. RD Moncla#405 WO Rig. 23. Turn well over to production. 24. Replace IA x OA pressure gauge if removed (7"x 9-5/8"). E-line Procedure: 25. MIRU Slickline, PT lubricator to 3,000 psi Hi 250 Low. a. Tree connection is 6.5"OTIS. / 26. RIH w/3.5"swab cups and swab fluid down to 2,500' MD.✓ 27. RD Slickline. E-line Procedure: 28. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. b. Tree connection is 6.5" OTIS. 29. RU 2.5"6 spf HC wireline guns(will use 2 each 21'guns). 30. RIH and perforate Sterling B-3 interval from 5,533'-5,554' (2 runs,total of 12 spf). a. Proposed perfs shown on the propose s"d E erratic in red font. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Correlate using SLB Cement Bond Log dated 8/30/94(Tie-in log depth is 5,533'-5,554'). d. Record tubing pressures before and after each perforating run. 31. RD E-line. 32. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. BOPE Schematic I• BC-9 ACTUAL Ililcoraska. Pad 3 SCHEMATIC H E M AT I C .............k.. 1,188' FNL&1,568' FWL 50-133-20445-00-00 Sec. 34,T7N,R10W,S.M. Des: FEDA-028083 •vati.n: 183' (23'AGL) - - - - Conductor Date: 7/26/1994 13-3i8" K-55 61 ppf -.shed: 8/26/1994 Top Bottom 1 eleased: 9/5/1994 MD o' tts' TVD 0' 116' J 1 . 317,605 2,434,000 60°39'30.34"N 151°01'04.48"W Surface Casing 9-5/8" N-80 47 ppf BTC Top Bottom MD 0' 1,853' TVD 0' 1,790' Tree cxn:6-1/2"Otis 12-1/4"hole Cmt w/700 sks fil 1/4".049 wall Chemical injection line Intermediate Casing open to annulus @ 1,012'MD 7" N-80 29 ppf BTC ' Top Bottom MD 0' 5,950' �' ND 0' 5,569' Tubing Conveyed Perforating Assembly8-1/2"hole Cmt w1565 sks,in two @ 5,638'MD stages wl DV tool @ 4,487'MD Includes: *Two AB-Mod Buttress by ST-L crossovers *Y-block Tie-Back Tubing 3-1/2" 0 9.2 ppf AB-Mod *8'of 2"scallop guns TopBottom w/Max OD=5.887" �� MD 0' 5,814' C 6 ND 0' 5,433' Camco KBMM side pocket r. Liner mandrel w/1"Dummy valve V 3-112" N-80 9.2 ppf AB-Mod Butt @ 5,698'MD p Tag Fill Top Bottom 3'; @ 5,6703 MD MD 5,814' 8,881' h f on 2/18/14 ND 5,433' 8,496' 6"hole Cmt WI 500 sks, 150 sks to surface PX Plug nA)i t �',le @ 5,739'MD l I-- 1 r ' Sterling Perforations: Gun Type CMU Sliding Sleeve .' MD ft ND 2"Scallop,6 SPF Date @ 5,823'MD17 B4 5,629'-5,637' 12' 5,248'-5,256' (6/7/98) 2.813"ID �I Y Gu2318 60°4SPF Yi1ti: _-/i ( Beluga Perforations: if __ } (/�' MD ft ND 2-1/2",60°,6 SPF Date Production Seal Unit 're. 84 6,429'-6,469' 30' 6,049'-6,078' 2-1/2",60°,6 SPF (1/12104) (Cement squeezed) 2.112",60°,6 SPF (7/28/07) B16 7,420'-7,460' 40' 7,039'-7,079' 2-1/2",600,6 SPF (10/2/96) Model H liner hanger packer - B17 7,534'-7,574' 40' 7,153'-7,193' 2-1/2",60°,6 SPF (9/30/961 @5,828'MD I 818 7,640'-7,660' 20' 7,259'-7,279' 2-112",60°,6 SPF (9128196)9/26/96 I B19 7,705'-7,725' 20' 7,324'7 344' 2-1/2",60°,6 SPF ( 2-112",60°,6 SPF ) 7,725%7,755' 30' 7,344%7,374' 2-112",60°,6 SPF (9/25196) ' 7,762'-7,812' 50' 7,381'-7,431' (8/13/96) B20 7,812'-7,842' 30' 7,431'-7,461' 2-1/2",60°,6 SPF (8/9/96) Beluga 6,429'-6,459'MD (30') 1/13/2004 _ • - 7,852'-7,882' 30' 7,471'-7,801' 2-1/2",60°,6 SPF (8/7/96) Cmt Squeezed Wet Upper Beluga with B21 7,893'-7,933' 40' 7,512'-7,552' 2-1/2",60°,6 SPF (8/5/96) B23 7,98T-8,030' 50' 7,599'-7,649' 2-1/2",60°,6 SPF (9/25/94) 10 bbl,15.8 ppg,68 sks,of Class G (Fracture Treated) 2-1/2",60°,6 SPF 2,500 psig squeeze 7/28/2007 8,036'-8,054' 18' 7,655'-7,673' 2-1/2",60°,6 SPF (9/24194) • limili---:: (Fracture Treated) 2-1/2",60°,6 SPF 8,072'-8,098' 26' 7,691'-7,717' 2-1/2",60°,6 SPF (9/24/94) 824 8,167'-8,187' 20' 7,786'-7,806' (9118/94) B25 8,241'-8,446' 5' 7,860'-7,865' (9/16/94) 8,254'-8,261' 7' 7,873'-7,880' (9/16/94) 8,276'-8,292' 16' 7,895'-7,911' (9/16194) N Plug 827 8,399'-8,409' 10' 8,018'-8,028' (9115/94) Model @ N Bridge 8,432'-8,452' 20' 8,051'-8,071' (9115/94) l TD PBTD 8,881'MD 8,808'MD 8,496'TVD 8,426'TVD _ Well Name&Number: Beaver Creek Unit#9 Lease: A-028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA Angle @KOP and Depth: 8.0°@ 1,000' Angle/Perfs: 1 0° Maximum Deviation: 32°@ 2,500' Date Completed: 09/15/94 Ground Level(above MSL): 160' RKB(above GL):_ 23' Revised By: Stan Porhola Downhole Revision Date: 2/18/2014 Schematic Revision Date: 2/19/2014 I BC-9 PROPOSED • 3 Ililworp.41a421.,LLt: Pad 3 SCHEMATIC 1,188' FNL&1,568' FWL 19-2-122 Sec.34,T7N,R10W,S.M. 50-133-20445-00-00 iii perty Des: FEDA-028083 KB Elevation: 183' (23'AGL) - - Conductor Spud Date: 7/26/1994 13-318" K-55 61 ppf TD Reached: 8/26/1994 Top Bottom Rig Released: 9/5/1994 ::830 o' 11 s' i D 0' 116' X: 317,605 Y: 2,434,000 Lat: 60°39'30.34"N Long: 151°01'04.48"W Surface Casi 9-518" 47 ppf BTC Top Bottom MD 0' 1,853' TVD 0' 1,790' Tree cxn:6-1/2"Otis 12-1/4"hole Cmt w/700 sks Completion Assembly A ' r Includes: Intermediate Casing Chemical Injection Mandrel,1500'MD JE 7 TopN-8o Bo29ttom f BTC Hydraulic Packer,5,400'MD I I MD IT 5,950' •*X.-Profile,5,415'MD TVD o' 5,569' "`WLEG,5,430'MD ( � 8-1/2"hole Cmt w1565 sks,in two � � stages w/DV tool @ 4,487'MD 9-;3 Tubing 3-1/2" L-80 9.2 ppf IBTAB-Mod Top Bottom B3 MD 0' 5,430' Bridge Plug TVD 0' 5,049' @ 5,620'MD B4 Liner 3-1/2" N-80 9.2 ppf AB-Mod Butt Top Bottom -,- MD 5,814' 8,881' Cut Tubing Tag Fill ND 5,433' 8,496' _ @ 5,700'MCA - @ 5,703'MD 6"hole Cmt WI 500 sks, 150 sks to surface on 2/18/14 PX Plug @ 5,739'MD ' • i Sterling Perforations: CMU Sliding Sleeve r,f MQ ft MI Gun Tyne 8314 5,823'MD ti:'}ti' B3 5,533'-5,554' 5,152'-5,175 2-1/2"HC,6 SPF Proposed @ ♦••}: B4 5,629'-6,637' 12' 5,248'-5,256' 2"Scallop,6 SPF (6/7/98) 2.813"I D '4.1.P.,.` Beluga Perforations: Production Seal Unit "r( ,,i MD ft ND Gun Tvpe Date 64 6;42&'-6468' 30 6,048'-6,078' g ,60°,4SPF (-1132104) (Cement squeezed) g (7/28/07) Model H liner hanger packer B16 7,420'-7,460' 40' 7,039'-7,079' i_1/ip"'6S";8 Rp�p f�f (10/2/96) @ 5,828'MD B17 7,534'-7,574' 40' 7,153•-7,193' 2-11/2 88°'8 pp (9/28/96)(9/30/96) Ir B18 7,640'-7,660' 20' 7,259'-7,279' p pp g SPF B19 7,705'-7,725' 20' 7,324'-7,344' 2-1/2";68°;6 SPF (9/26/96) 7,725'-7,755' 30' 7,344'-7,374' 2-1/2",60°,6 SPF (9/25/96) 2 1/2",60°,6 SPF 7,762'-7,812' 50' 7,381'-7,431' 2-1/2",60°,6 SPF (8/13/96) Beluga 6,429'-6,459'MD (30') 1/13/2004 ~a • B20 7,812'-7,842' 30' 7,431'-7,461' 2-112",60°,6 SPF (8/9/96) Cmt Squeezed Wet Upper Beluga with 7,852'-7,882' 30' 7,471'-7,501' 2-1/2",60°,6 SPF (8/7/96) q PP 9 B21 7,893'-7,933' 40' 7,512'-7,552' (8/5/96) 10 bbl,15.8 ppg,68 sks,of Class G B23 7,980'-8,030' 50' 7,599•-7,649' 2-1/2",60°,6 SPF (9/25/94) 2,500 psig squeeze 7/28/2007 C (Fracture Treated) 2-112'•,60°,6 SPF 8,036'-8,054' 18' 7,655'-7,673'III= 2-1/2",60°,6 SPF 2-112",60°,6 SPF (9/24/94) (Fracture Treated) 2-1/2",60°,6 SPF • 8,072'-8,098' 26' 7,691'-7,717' 2-1/2",60°,6 SPF (9/24/94) B24 8,167'-8,187' 20' 7,786'-7,806' 2-1/2",60°,6 SPF (9/18/94) B25 8,241'-8,446' 5' 7,860'-7,865' (9/16194) 8,254'-8,261' 7' 7,873'-7,880' (9/16/94) Model N Bridge Plug 8,276'-8,292' 16' 7,895'-7,911' (9/16/94) 8,808'MD • B27 8,399'-8,409' 10' 8,018'-8,028' (9/15/94) @ 8,432'-8,452' 20' 8,051'-8,071' (9/15/94) 4 TD PBTD 8,881'MD 8,808'MD 8,496'TVD 8,426'TVD Well Name&Number: Beaver Creek Unit#9 Lease: A-028083 County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country:) USA Angle @KOP and Depth: 8.0°i 1,000' Angle/Perfs: I 0° Maximum Deviation: 32°@ 2,500' Date Completed: 09/15/94 Ground Level(above MSL): 160' RKB(above GL): 23' Revised By: Stan Porhola Downhole Revision Date: Proposed Schematic Revision Date: 2/19/2014 Beaver Creek 2014 Moncla Rig 405 Knight Oil Tools BOP Hilrurp Maxim.l,l.( ini n at mit 2.57' / Shaffer 71/16 5000 • III iii III iii Ill Ill III lil III 2 3/8-3 1/2 variable i`_, w. _ CAMERON Si! 3.68' _� 1111 ) mil: f _ — = Blind mom. iir71/16 5000 =ter 1 � l 7t I11 111'°alill iii 2 1/16 10M Kill Valves 2 1/16 10M Choke Valves Manual and HCR Manual and HCR 1,1.1/1•111 III III • ! ',1. rt"1 ,.,1.56' [ ' If"?,,p, !,iiii . 1 ji,/i1s;i ,-� III — Davies, Stephen F (DOA) From: Stan Porhola [sporhola@hilcorp.com] Sent: Thursday, February 20, 2014 11:36 AM To: Davies, Stephen F (DOA) Subject: RE: BCU 09 and BCU 14 A Perforations Steve, Currently BCU-09 is on/off production in the Sterling Gas Pool: Other wells not on production but open to the Sterling Gas Pool: BCU-07 BCU-09=> BCU-07 is 5,250' ************************************************************************************ • Currently BCU-14A is not on production (following sidetrack) but planned for producing in the Beluga Gas Pool: BCU-14A=> BCU-19 is 1,500' (closest well open to Beluga not producing but open in Beluga) BCU-14A=> BCU-12 is 1,900' BCU-14A=> BCU-13 is 2,650' BCU-14A=> BCU-16RD is 2,600' BCU-14A=> BCU-18 is 5,000' Stan Porhola l Operations Engineer North Kenai Asset Team Hilcorp Alaska, LLC sporhola@hilcorp.com Office: (907) 777-8412 Mobile: (907) 331-8228 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Thursday, February 20, 2014 11:04 AM To: Stan Porhola Subject: BCU 09 and BCU 14 A Perforations Stan, Two more wells for you: What is the distance from the planned perforation intervals in the BCU 09 and BCU 14A wells and perforations that are, or will be, open to the same gas pool in the closest wells? Thanks, Steve Davies AOGCC 907-793-1224 1 /Maratho~~~f~ MARATHON ' VI~ COmpan~r' June 26, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Marathon fit Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 IUN ~~ "l 20(ld ..., . ~•,. . , ,. c9;:~iz~ ~6 ~c :.+uL ,.:ti~i;,. A..;~Il?ffi!'.:~~~'IrJl~l j Reference: 10-407 Well Completion Report Field: Beaver Creek Field ..~ ~ ~ ~`' Well: Beaver Creek #9 Dear Mr. Maunder: ~ a,~~--. Z00~~ Enclosed for your records is the 10-407 Well Completion Report covering the work performed on BC-9 well under Sundry #303-310. This sundry documents the additional perforations added to the Beluga formation in January of 2004. This sundry submittal is part of our effort to close out the documentation on old work activities. Please contact me at (907) 283-1371 if you have any questions or require additional information. Sincerely, ~Q%~ s ~~w~t~C ~1r~esc ~`'S'~S s~oJ cJ 0.~~~.1.'~eCn LJCtT(~'\ ~u Kevin J. Skiba Engineering Technician t~v (/l~;~~~~ ~~ ~, ~~~u~s a~s ~~~ Enclosures: 10-407 Well Completion Chet>:~;-t r ~ 2:~~}u;ton Well File Operations Summary t°tia~,~:~i Well File ~ Marathon MARATHON Oil Company May 15, 2008 ~ ~~ ±~`~'~ ~ {~~~ ~ ~~ ,~~ y ~~a ~ _~~ ~ =~t ~ ,4~ ~ - t~AY ~ ~0 2008 ~arathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-9371 Fax 907/283-1350 Cov~~ri~~~~~ ~ ~,`Y ~;lask~ Oil ~ ~~ Cong. ~~1 ~ ~chor~9~ ~ d~ Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7'h Ave Anchorage, Alaska 99501 Reference: 10-404 Sundry Submittal List ~~~SE~~ ~.~~~~~ S~v~ ' ~~ ~~ `~, e~L~ ? ~-- ~ ~ ~ ~ ~ ~ ~r ~ _~ ~~c ~.~~ j~-eos~ ~~ ~E ~o ~~ ~~s~~~ ~.«.o~.~.~~e Dear Mr. Maunder: ~~~~~~~~~~~(~~~~ c~ ~~~ Marathon and the AOGCC have had discussions on the follow-up reporting needed to close out 10-403 Sundry approved well work activities. Work has been ongoing to `~ ~yn~~ identify the suspect well activities and complete the appropriate reporting. Submitted for your records is a list of the completed reports aiong with the indicated 10-404 Sundries. I am continuing to work on the remaining sundry reports and plan to submit them upon their completion. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, F} ~ r~;~~~'~~t,.rr '~,~4:, , _ („~tt,~ , ~..~ '~~ ~e11Z/~t-~ Kevin J. Skiba Engineering Technician Enclosures: 10-404 Sundry Submittal List cc: Houston Well File Accompanying 10-404 Sundries Kenai Well File KJS • M Marathon MARATHON Oil Company •Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ~C~~f~~~ January 23, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 MA~Y ~ 6 2008 Alaska Oii & Gas Cons. Cammission Anchorage Reference: 10-404 Sundry Report Field: Beaver Creek Well: BC - 9 Dear Mr. Maunder: Attached for your records is the 10-404 sundry report for well BC - 9. This sundry covers the PLT and temperature log which was covered under sundry #304-262. The results from the log indicated most of the flow contribution from the 6429' - 6440' interval. Please contact us at (907) 283 -1371 if you have any questions or need additional information. Sincerely, l.. Wayne E. Cissell Well Work Over Supervisor Enclosures: 10-404 Sundry Report cc: Houston Well File Operation Summary Kenai Well File KJS KDW ~ ~ ~ '>`< ~ ~ ~; ~~ ~° ~°°~ ,s'~~~ STATE OF ALASKA ~ ALAS~IL AND GAS CONSERVATION COMMI~N , REPORT OF SUNDRY WELL OPERA~`~NS`~ ~"~'` `' n ~,.,.i,., ~;~ 12 (;~c (`nn~ i ;~i1Pt(T1iSSV011 1. Operations Abandon Repair Well Plug Perforations imulate h Other ~ Ran PLT ~ C r PerFormed: Alter Casing ~ Puil Tubing ~ Perforate New Pool ~ Waiver~ 7~ e~x tension ~ 8~ Temp log Change Approved Program ~ Operat. Shutdown ~ Perforate ^ Re-enter Suspended Well ~ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Marathon Oil Company Development ~ ^ E lorato ~ ry ^ 192-122 ' 3. Address: Stratigraphic ~ Service ^ 6. API Number: PO Box 1949, Kenai Alaska, 99611-1949 50-133-20445-00 7. KB Elevation (ft): 9. Well Name and Number: 183' - BC - 9 ~ 8. Property Designation: 10. FieldlPool(s): _ FED A028083~ Beaver Creekl Beluga 11. Present Well Condition Summary: Ran PLT 8~ Temperature log Total Depth measured g,gg~ ~ feet Plugs (measured) Model N BP @ 8808' true vertical 8,500 ~ feet Junk (measured) N/A Effective Depth measured g~gpg feet true vertical g,q27 feet Casing Length Size MD TVD Burst Collapse Structural 116' 13-3/8" 116' 116' N/A N/A Conductor Surface 1853' 9-5/8" 1853' 1725' 4750 psi 6870 psi Intermediate Production 5950' 7" 5950' S555' 7020 psi 8160 psi Liner 3067' 3-1/2" 8881' 8500' 10530 psi 70760 psi Perforation depth: Measured depth: 6429' - 8452' Gross True Vertical depth: 6058' - 8071' Gross Tubing: (size, grade, and measured depth) 3-1/2" L- 80 5814' Packers and SSSV (type and measured depth) Baker Liner Hanaer w/ Seal Bore Extension 5814' 12. Stimulation or cement squeeze summary: Intervals treated (measured): 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 weil operation: 0 5,000 55 750 N/A Subsequent to operation: 0 5,000 55 780 N/A 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Expioratory ^ Development Q 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: 304-262 ~ Contact Kevin Skiba (907) 283-1371 Printed Name ne E. Cissell Titie Well Work Over Supervisor Signature Phone (907) 283-1308 Date 01/23/2008 ~ ~ ~F~: ~U~ 2 ~ 200~ Form 10-404 Revised 04/2006 Submit Original Only ~ ~ 08:30 - 09:00 0.50 RURD SLIK CMPFLW RU to wellhead mwith slickline unit. MU tools sstring with 2.75 gauge ring. 09:00 - 09:15 0.25 TEST BOPE CMPFLW Test lubricator and BOPE. OK 09:15 - 10:15 1.00 RUNPU SLIK CMPFLW RIH with 2.75 gauge ring to 8226 RKB with slickline, POOH. 10:15 - 14:30 4.25 RUNPU SLIK CMPFLW Turn gauges on and RIH at 100 fpm and 30 fpm across perf intervals to 8170' RKB. POOH with gauges. 14:30 - 16:00 1.50 RURD SLIK CMPFLW Check data for quality, OK. RD slickline unit and leave location. 7/9/2004 08:00 - 09:30 1.50 RURD ELEC PR1 EVL Arrive, obtain permit, rig up equipment 09:30 - 10:15 0.75 SAFETY MTG PR1 EVL Hold safety meeting 10:15 - 10:30 0.25 TEST BOPE PR1 EVL PU lubricator and pressure test w/ WHP. 10:30 - 11:45 1.25 TAG BOTM PR1EVL RIH and tag bottom at 8250' w/ 2.75" GR. 11:45 - 12;30 0.75 RUNPU ELEC PR1 EVL POOH w/ gauge ring 12:30 - 13:10 0.67 PULD LOG PR1EVL At surFace. Break out GR and PU MPLT tools. RIH at 160'/min. 13:10 - 19:30 6.33 LOG CSG_ PR1 EVL Stop for 10 min bench at 6300'. Log down and up at 30'/min. Stop at 6300'. Log down to 8170' and back up at 60'/min. Stop at 6300'. Log down to 8170' and up at 90'/min. Stop at 6300' for 5 min. RIH at 180'/min. Make 5 minute benches at 7300', 7200', 6740', 6640', 6540', 6410', 6210'. POOH. 19:30 - 21:00 1.50 RURD_ ELEC PR1 EVL RDMO Expro Event Name: MAINTENANCE/REPAIR Start: 6/30/2004 End: 6/30/2004 Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date From ~ To Hours Code Code Phase Description af t~pers#~flns 6/30/2004 08:00 - 08:30 0.50 SAFETY MTG CMPFLW PJSM discuss job procedure and safety aspects of work. Marathon 0il Company Page ~ of ~ Operations Summary Report Legal Well Name: BEAVER CREEK 9 Common Well Name: BEAVER CREEK 9 Spud Date: 7/28/1994 Printed: 1/24/2008 4:42:44 PM « , • M Marathon MARATHON Oil Company ~~,~~'~~ ~ MA`( ~ 6 l~~'~ • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Alaska OiV & Ga~ Co~s. ~~~~~;~~:o~ Anchorage January 23, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Reference: 10-404 Sundry Report Field: Beaver Creek Well: BC - 9 Dear Mr. Maunder: ~,~;~~y~:'~~~~: AUG ~` _~ i'OQ~ Attached for your records is the 10-404 sundry report for well BC - 9. This sundry covers the lower Beluga perforating work that Marathon covered under sundry #396-154. All of the planned perForations were perforated except for the last interval @ 7384' - 7404' Please contact us at (907) 283 -1371 if you have any questions or need additional information. Sincerely, ~ Wayne E. Cissell Well Work Over Supervisor Enclosures: 10-404 Sundry Report cc: Houston Well File Operation Summary Kenai Well File KJS KDW .~ ~~~E~~'~~ ~ STATE OF ALASKA S~o~o~ ALAS OIL AND GAS CONSERVATION COMM ON ~~A~' 1 6 LO1~ REPORT OF SUNDRY WELL OPERATIONS .~~~~~ ~~~ ~~as Cons. Comm;s~iu,; 1. Operations Abandon Repair Well Plug Perforations Stimulate Other B Performed: Alter Casing ~ Pull Tubing ~ Perforate New Pool ~ Waiver~ Time Extension [] Change Approved Program ~ Operat. Shutdown ~ Perforate Q~ Re-enter Suspended Weli ~ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Marathon Oil Company Development ~^ > Exploratory^ 192-122 - 3. Address: Stratigraphic ^ Service ~ 6. API Number: PO Box 1949, Kenai Alaska, 99611-1949 50-133-20445-00 7. KB Elevation (ft): 9. Well Name and Number. 183'- BC-9 - 8. Property Designation: 10. Field/Pool(s): FED A028083 - Beaver Creek/ Beluga 11. Present Well Condition Summary: Add perforations Total Depth measured $,$$~ - feet Plugs (measured) Model N BP @ 8808' true vertical 8,500 - feet Junk (measured) N/A Effective Depth measured $,$Q$ - feet true vertical g,42~ feet Casing Length Size MD TVD Burst Collapse Structural 116' 13-3/8" 716' 116' Conductor SurFace 7853' 9-5/8" 1853' 1725' 4750 psi 6870 psi intermediate Production 5950' 7" 5950' 5555' 7020 psi 8160 psi Liner 3067' 3-1/2" 8881' 8500' 10530 psi 10160 psi Perforation depth: Measured depth: 7420' - 8452' Gross True Vertical depth: 7039' - 8071' Gross Tubing: (size, grade, and measured depth) 3-1/2" L- 80 5814' Packers and SSSV (type and measured depth) Baker Liner Hanqer w/ Seal Bore Extension 5814' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-6bl Casing Pressure Tubing Pressure Prior to well operation: 0 4,000 5 750 2050 Subsequent to operation: 0 11,424 4 780 1850 14. Attachments: 15. Well Class afterwork: Copies of Logs and Surveys Run Exploratory ~ Development Q Service ~ Daily Report of Well Operations X 16. Well Status after work: Oil ^ Gas Q 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: 396 - 154 Contact Kevin Skiba (907) 283-1371 Printed Name Wa e E. Cissell -~ Title Well Work Over Supervisor r Signature Phone (907) 283-1308 Date 01I23/2008 r ~! G~"`~ ~~ ~~-~ Form 10-404 Revised 04/2006 ~~~~ ~~?~ .;' ` `,1( ~ ~ 2~~~ Submit Original Only ~ • ~ MARATHON OIL COMPANY DAILY WELL OPERATIONS REPORT PAGE 1 OF 1 DATE: 8/5/96 FIELD: Beaver Creek WELL #: Bc-s FILL DEPTH/DATE: 8004' (8/5/96) TUBING: 3.5" 9.3# L-80 CASING: 3-1/2" 9.2# N-80 DATE LAST WL WORK: 4/3/96 TREE CONDITION: Good WORK DONE: PBU/4 Point BENCHES OPEN: B-21 PRESENT OPERATION: Testing well - perf'd B-21 B-23, B-24, 25, 27L covered PROBLEMS: Tight spots in tubing collars at 6297' and 4128', fill tagged above B-23 perfs SUMMARY OF OPERATIONS 0800 1100 1130 1145 1300 1410 1520 1535 1605 1710 1750 1758 1930 0630 SWS arrived on site, spot equipment and RU Wireline unit. Held safety & environmental meeting and reviewed the procedure with everyone. Establish communication blackout. MU 20' 2-1/2" HC, 6 SPF, 60 degree phasing, 10.5 gm RDX 34j Ultra jet charges. PT lub with W HP=1900 psig. Good test. RIH with well Shut In, correlate CCL to the Dual Burst TDT log, dated 9-14-94. Made 3 tie in passes across the Otis nipple, H-paker, liner hanger. RIH and tagged fill at 8004' ELM, above B-23 sand (last tag indicated that the fill was at 8166' wlm). Correlate/made tie-in pass. On depth, perforate the following interval w/ 850 psi DD (WHP = 2150 psig): Run Interval Footage Comments #1 7913 - 7933' 20' B-21 POOH with gun, flagged the wire at 7700', had problems with gun sticking at 6247' and 4078', drop down hole to 6297' and 4128'. POOH (both tight spots appear to be a collar). Establish communication btackout. Out of hole, all shots fired. Fix small leak in the coupting above the tree XO. MU 20' gun as above. RIH with second 20' gun and perforate the following interval w/ 800 psi DD (WHP = 2200 psig): Run Interval Footage Comments #2 7893 - 7913' 20' B-21 No change in well head pressure after guns fired. POOH with gun. Establish communication blackout. Out of hole with guns. All shots fired. MU the tree cap to hook up the Methanol injection and chart recorder to the tree. SWS Rig aside equipment and take their tree connection to shop for tightening the connection. Brought well on at 4.00 mcfpd rate after adjusting choke. Methanol rate = 50 gpd. Appears to be fairly stable at 1845 hrs. Will have the KGF monitor the well from the gas field. Well flowing at 4.0 mmcfpd rate, no water, with 2000 psi on chart. 8/6/96 2.9 mmscfpd; 1950 psig, 0 bwpd. Plan to open well up to 4.0 mmscfpd and stabilize. WELL TESTS: MMSCFPD BWPD TP CP BEFORE: 4.0 5 1850 750 AFTER: 4.2 9 1850 680 COMMENTS: DATE 8/5/1996 R/7/1996 REPORTED BY: Wayne Cissell ~, : ~ • MARATHON OIL COMPANY DAILY WELL OPERATIONS REPORT PAGE 1 OF 1 DATE: 8/7/96 FIELD: Beaver Creek WELL #: Bc-s FILL DEPTH/DATE: 8079' (8/7/96) TUBING: 3.5" 9.3# L-80 CASING: 3-1/2" 9.2# N-80 DATE LAST WL WORK: 8/5/96 TREE CONDITION: Good WORK DONE: Perf B-21 BENCHES OPEN: B-20L, B-21, B-23 PRESENT OPERATION PROBLEMS: Perf B-20L, flowing well B-24, 25, 27L covered SUMMARY OF OPERATIONS 1645 1735 1820 1855 1920 2000 2008 2015 2100 2125 2130 SWS arrived on site, RU Wireline unit. Held safety & environmental meeting and reviewed the procedure with everyone. Went to communication blackout, MU 30' select fire gun, 2 1/2" HC, 6 SPF, 60 degree phasing, 10.5 gm RDX 34j Ultra Jet charges. S/I well. PT lub with WHP=2150 psig, no leaks . RIH with well Shut In, Methanol at 110 gpd rate going into injection mandrel and 12 gpd rate going into tree. Correlate CCL to the Dual Burst TDT log, dated 9-14-94. Made 3 tie in passes across the Otis nipple, H-packer, liner hanger. Sat down at 6250' kbd, tight spot. Tag fill @ 8079' KB. Last tag indicated that the fill was at 8004' KB . Correlate. Made tie-in passes. On depth, verify shot depth, perforate the following interval: Well had 2150 psi on chart. Perforate with 850 psi DD. Run Interval Footage Comments #1 7872 - 7882' 10' B-20L JHP after perforating = 2175 psi on gauge. Drop back down to 8010', make upward pass to check depth on CCL, drop down to 8010' made log up pass to verify on depth. PUH to perforate the following interval: Run Interval Footage Comments #1 7852 - 7872' 20' B-20L Well had 2175 psi on the chart. Perforate with 825 psi DD. POOH with gun, wire is flagged at 7700', had problems with gun sticking at 6247' , drop down hole to 6297' PUH was able to clear the tight spot. IEstablish communication blackout. Out of hole with guns. All shots fired. ~SWS Rig aside equipment and put night cap on BOP. Hooked up the chart recorder and the methanol injection line to tree, rate at 12 gpd rate into flowline, 90 gpd downhole. Opened up well to production, WHP=2200 psi, zeroed the H20 meter. Brought well on at 4.60 mmcfpd rate after adjusting choke to try and bring the WHP to 1850 psi. Will monitor the well. WELL TESTS: mmcfpd BWPD TP CP BEFORE: 4.2 9 1850 680 AFTER: 4.2 9 1850 760 COMMENTS: DATE 8/7/1996 R/A/1 AAF REPORTED BY: Wayne Cissell • MARATHON OIL COMPANY DATE: 8/9/96 FILL DEPTH/DATE: 8070' ('8/9/96) DATE LAST WL WORK: 8/7/96 i DAILY WELL OPERATIONS REPORT FIELD: Beaver Creek PAGE 1 OF 1 W ELL #: Bc-s TUBING: 3.5" 9.3# L-80 CASING: ,3-1/2" 9.2# N-80 TREE CONDITION: WORK DONE: perforated the B-20 lower BENCHES OPEN: B-20U/L, 6-21, B-23 PRESENT OPERATION: perforate B-20 upper B-24, 25, 27L covered PROBLEMS: Tight spots in tubing at 6247' SUMMARY OF OPERATIONS 5 0920 1000 1100 1145 1240 1325 SWS arrived on site, RU Wireline unit. Held safety & environmental meeting and reviewed the procedure with everyone. Went to communication blackout. MU 30' select fire gun, 2 1/2" HC, 6 SPF, 60 degree phasing, 10.5 gm RDX 34j Ultra Jet charges. S/I well. PT lub with WHP=2100 psig, no leaks . RIH with well Shut In, Methanol at 90 gpd rate going into injection mandrel and 12 gpd rate going into tree. Correlate CCL to the Dual Burst TDT log, dated 9-14-94. Made tie in passes across the Otis nipple, H-packer, liner hanger. RIH, Tag fill @ 8070' KB. Correlate/Made tie-in passes. On depth, verify shot depth, perforate the following interval: WHP=2160 psi on chart. Perforate with 840 psi DD. Run #1 #1 Interval Footage Comments 7832 - 7842' 10' B-20U, all shots fired, WHP after perforating = 2175 psi on gauge. 7812 - 7832' 20' B-20U, W HP=2175 psi on the chart. Perforate with 825 psi DD. POOH with gun, gun sticking at 6247'. Establish communication blackout. Out of hole with guns. All shots fired. SWS Rig aside equipment and put night cap on BOP. Hooked up the chart recorder and the methanol injection line to tree, rate at 12 gpd rate into flowline, 90 gpd downhole. Opened up well to production, WHP=2200 psi, zeroed the H20 meter. Gauged the tank. Brought well on at 4.960 mmcfpd rate, choke at same spot prior to perforating. Will bring the WHP to 1850 psi. Monitor the well to stabilize the rate. WELL TESTS: mmcfpd BWPD TP BEFORE: 4.2 9 1850 AFTER: 5.24 7 1850 COMMENTS: CP DATE 650 8/9/1996 835 ~# REPORTED BY: Wayne Cissell • ~ MARATHON OIL COMPANY DAILY WELL OPERATIONS REPORT PAGE 1 OF 1 DATE: 8/13/96 FIELD: Beaver Creek WELL #: Bc-s FILL DEPTH/DATE: 8066.5' (8/13/96) TUBING: 3.5" 9.3# L-80 CASING: 3-1/2" 9.2# N-80 DATE LAST WL WORK: 8/9/96 TREE CONDITION: Good WORK DONE: Perforate B-20U BENCHES OPEN: B-19, 20U/L, B-21, B-2: PRESENT OPERATION: Perf'd B-19L, flowing well B-24, 25, 27L covered PROBLEMS: Tight spots at 6247' and 4070' SUMMARY OF OPERATIONS 1100 1130 1240 1410 1420 1500 ~~ 1640 I 1725 1945 SWS on location. Discussed safety, environment. Reviewed procedure. SI well. Establish communication blackout. MU 30' select fire 2-1/2" Hollow Carrier, 6 SPF, 60 degree ,phasing, 10.5 gram RDX 34J Ultrajet charges. Open swab valve and RIH. Correlate to TDT log dated 9/14/94 (add 1' to collars to be on depth w/ open hole log). Tied into tubing tail. On depth. Tag ~II at 8064' (covering lower part of B-23). WHP = 2175' psig. Perforate w/ 825 psig DD: Run Interval #1 7802 - 7812' Footage 10' Comments B-19L Log collars up. RIH. Perforate w/ 825 psig DD: #1 7782 - 7802' 20' B-19L Log collars up. Flag line at 7600'. POOH. Slow speed to 3000'/hr through tight spots at 6247' and 4070'. Pulled an additional 140# through tight spots. Establish communication blackout. OOH. WHP = 2250 psig. All shot fired. Fine grained sand w/ a small amount of frac sand in gun connections. MU 20' guns as above. RIH. Tie into flag and correlate to TDT +1'. On depth. Tag fill at 8066.5'. WHP = 2300 psig. Perforate w/ 700 psig DD: #2 7762 - 7782' 20' B-19L Log collars up. POOH. Slow going through tight spots at 6247' and 4070'. Establish communication blackout. OOH. All shots fired. WHP = 2345 psig. RD SWS. Bring well on line at 6.0 mmscfpd. Rate = 6.0 mmscfpd at 2160 psig, 0 water. Well still stabilizing. Reduce methanol rate to 50 gpd downhole, and 12 gpd in flowline. update report later w/ stable rates. I8/15/96 0700 rate stable at 6.1 mmscfdp, 2100 psig WHP, 5 bwpd. Plan to increase rate to 7.0 mmscpfd and monitor WHP. Will not drop WHP below 1850 psig. WELL TESTS: MMSCFPD BWPD BEFORE: 5.24 7 AFTER: 6.1 5 COMMENTS: TP CP DATE 1850 670 8/13/1996 2100 8/15/1996 REPORTED BY: Mike Olson ~ • MARATHON OIL COMPANY DAILY WELL OPERATIONS REPORT PAGE 1 OF 1 DATE: 9/26/96 FIELD: Beaver Creek WELL #: Bc-s FILL DEPTH/DATE: 8051' (9/26/96) TUBING: 3.5" 9.3# L-80 CASING: 3-1/2" 9.2# N-80 DATE LAST WL WORK: 9/25/96 TREE CONDITION: Good WORK DONE: PerForate B-19U (1 of 2 runs) BENCHES OPEN: s-~su~~, 2ou/~, e-2~, 8-23 PRESENT OPERATION: Perf'd remaining B-19U - flowing well B-24, 25, 27L covered PROBLEMS: Tight spots at 6247' and 4070' SUMMARY OF OPERATIONS 1200 1320 1330 1400 1510 1515 1600 1800 0600 SWS on location. Prepare to RU. Well flowing 7114 mscfpd at 2165 psig. Establish communication blackout. SI well. MU 20' 2-1/2" Hollow Carrier, 6 SPF, 60 degree phasing, 10.5 gram RDX 34J Ultrajet charges. Open swab valve and RIH. Correlate to TDT log dated 9/14/94 (add 1' to collars to be on depth w/ open hole log). Tied into tubing tail. Tag fill at 8051'. Flow well at 3900 mscfpd to create underbalance. WHP = 2300 psig. Perforate w/ 500 psig DD: Run Interval Footage Comments #1 7705-7725' 20' B-19U Log collars up. POOH. No change in WHP or rate. SI well. POOH. Slow speed through tight spots at 6247' and 4070'. Pulled an additional 200# through tight spots. Establish communication blackout. OOH. All shot fired. WHP = 2420 psig. Bring well on line. Q= 9469 mscfpd at 2025 psig (not stable). 9/27/96 Q= 9154 mscfpd at 1980 psig. Plan to continue opening choke to bring WHP down to 1850 psig. 9/28/96 Q= 10179 mscfpd at 1860 psig. Increase of 1250 mscfpd from B-19U. Plan to perf B-18 on Saturday. WELL TESTS: MSCFPD BWPD TP CP BEFORE: 8925 7 1850 960 AFTER: 10179 3 1860 980 COMMENTS: DATE Q/7d/1 QAR Q/7R/'I QQF'i - REPORTED BY: Mike Olson . ~ • MARATHON OIL COMPANY DAILY WELL OPERATIONS REPORT PAGE 1 OF 1 DATE: 9/25/96 FIELD: Beaver Creek WELL #: ac-s FILL DEPTH/DATE: 8045' (9/25/96) TUBING: 3.5" 9.3# L-80 CASING: 3-1/2" 9.2# N-80 DATE LAST WL WORK: 8/13/96 TREE CONDITION: Good WORK DONE: Perforate B-19L BENCHES OPEN: B-tsu~~, 2ou~~, B-2~, B-2s PRESENT OPERATION: Perf'd B-19L (1 of 2 runs) - flowing well B-24, 25, 27L covered PROBLEMS: Shut down due to high winds. Tight spots at 6247' and 4070'. SUMMARY OF OPERATIONS 1127 1136 1141 1325 1440 1600 SWS on location. Discussed safety, environment. Reviewed proced~re. Well flowing 8878 mscfpd at 1940 psig. Winds gusting up to 35 mph but gradually decreaseing. SI well. Establish communication blackout. MU 30' select ~re 2-1/2" Hollow Carrier, 6 SPF, 60 degree phasing, 10.5 gram RDX 34J Ultrajet charges. Open swab valve and RIH. Correlate to TDT log dated 9/14/94 (add 1' to collars to be on depth w/ open hole log). Tied into tubing tail. Tag fill at 8045' (covering lower part of B-23). WHP = 2320 psig. Perforate w/ 680 psig DD: Run Interval Footage Comments #1 7745-7755' 10' B-19U log collars up. RIH. Perforate w/ 825 psig DD: #1 7725 - 7745' 20' B-19U Log collars up. Flag line at 7600'. SI well. No change in WHP, rate increased -150 mscfpd. POOH. Slow speed through tight spots at 6247' and 4070'. Pulled an additional 150# through tight spots. Establish communication blackout. OOH. All shot fired. MU 20' guns as above. W inds gusting up to 45 mph. Decide to shutdown job until tomorrow and finish perforating B-19U. WHP = 2400 psig. Bring well on line. Q=7661 mscfpd at 2160 psig WHP. Open choke. Well not stable due to debris in choke. Plan to let well clean up and continue perforating B-19U tomorrow afternoon if wind dies down. W ELL TESTS BEFORE: AFTER: COMMENTS: MMSCFPD BWPD TP CP DATE REPORTED BY: Mike Olson ~ ~ MARATHON OIL COMPANY DAILY WELL OPERATIONS REPORT PAGE 1 OF 1 DATE: 9/28/96 FIELD: Beaver Creek WELL #: Bc-s FILL DEPTH/DATE: 8032' (9/28/96) TUBING: 3.5" 9.3# L-80 CASING: 3-1/2" 9.2# N-80 DATE LAST WL WORK: 9/26/96 TREE CONDITION: Good WORK DONE: Perforate B-19U BENCHES OPEN: B-18, 19U/L, PRESENT OPERATION: Perf'd B-18 - flow testing well B-20U/L, 21, 23 PROBLEMS: T~ht spots at 6247' and 4070' Covered: 6-24, 25, 27L SUMMARY OF OPERATIONS 10945 I 1020 11125 11132 1200 1220 SWS on location. Prepare to RU. Well flowing 10,179 mscfpd at 1860 psig. Establish communication blackout. SI well. Closed choke on lineheater - choke holds tight (no flow cutting). MU 20' 2-1/2" Hollow Carrier, 6 SPF, 60 degree phasing, 10.5 gram RDX 34J Ultrajet charges. Open swab valve and RIH. Correlate to TDT log dated 9/14/94 (add 1' to collars to be on depth w/ open hole log). Tied into tubing tail. Tag fill at 8032'. Flow well at 3270 mscfpd to create underbalance. WHP = 2200 psig. Perforate w/ 600 psig DD: Run Interval #1 7640-7660' Footage 20' Comments B-18 Log collars up. POOH. No change in WHP or rate. SI well. POOH. Slow speed through tight spots at 6247' and 4070'. Pulled an additional 200# through tight spots. Establish communication blackout. ' OOH. All shot fired. Secure well w/ night cap. WHP = 2300 psig. Bring well on line. Q= 10,479 mscfpd at 1850 psig. Increase of 300 mscfpd from B-18. Plan to perf B-17 on Monday (9/30/96). WELL TESTS: MSCFPD BWPD TP CP DATE BEFORE: 10179 3 1860 980 9/28/1996 AFTER: 10479 3 1850 975 9/29/1996 COMMENTS: REPORTED BY: Mike Olson ~ ~ MARATHON OIL COMPANY DATE: 9/30/96 DAILY WELL OPERATIONS REPORT FIELD: Beaver Creek PAGE 1 OF 1 WELL #: BC-9 FILL DEPTH/DATE: 8034' (9/30/96) TUBING: 3.5" 8.3# L-80 GASING: 3-1/2" 9.2# N-80 DATE LAST WL WORK: 9/28/96 TREE CONDITION: Good WORK DONE: Perforate B-18 BENCHES OPEN: 8-17, 18, 19U/L, 20U/L, PRESENT OPERATION: Perf'd B-17, flow testing well B 21, B-23 PROBLEMS: Tight spots at 6247' and 4070' Covered: B-24, 25, 27l SUMMARY OF OPERATIONS 0600 0900 0945 1015 1100 1135 1140 1255 1335 1410 1410 1415 1500 1520 0600 1500 Well flowing 8418 mscfpd at 2000 psig. Adjust choke to remove debris from choke (feels like hydrates in choke - not sand). SWS on location. RU on well. Establish communication blackout. Well flowing 10,460 mscfpd at 1920 psig. SI well. MU 20' 2-1/2" Hollow Carrier, 6 SPF, 60 degree phasing, 10.5 gram RDX 34J Ultrajet charges. Open swab valve and RIH. Correlate to TDT log dated 9/14/94 (add 1' to collars to be on depth w/ open ho-e log). Tied into tubing tail. Tag fill at 8029'. WHP = 2300 psig. Flow well at 3800 mscfpd to create underbalance. WHP = 2200 psig. Perforate w/ 550 psig DD: Run Interval Footage Comments #1 7554-7574' 20' B-17 Log collars up. POOH. No change in WHP or rate. SI well. POOH. Slow speed through tight spots at 6247' and 4070'. Pulled an additional 600# through tight spots. Establish communication blackout. OOH. All shot fired. MU 20' 2-1/2" Hollow Carrier, 6 SPF, 60 degree phasing, 10.5 gram RDX 34J Ultrajet charges. Open swab valve and RIH. WHP = 2350 psig. Flow well at 3800 mscfpd to create underbalance. Tied into flag at 7430'. Correlate to TDT log dated 9/14/94 (add 1' to collars to be on depth w/ open hole log). Sat down at 7720'. PU to 7700'. Attempt to RIH. Could not move down. Reduce rate from 3800 to 3000 mscfpd. RIH. OK. Tag fill at 8034'. Make tie-in pass. WHP = 2300 psig. Perforate w/ 450 psig DD: Run Interval Footage Comments #2 7534-7554' 20' B-17 Log collars up. No change in WHP or rate. SI well. POOH. Slow speed through tight spots at 6247' and 4070'. Pulled an additional 600# through tight spots. Establish communication blackout. OOH. All shot fired. Secure well w/ night cap. WHP = 2350 psig. Bring well on line. 10/1/96 Q= 8473 mscfpd at 2000 psig. Open choke to drop WHP to 1850 psig. 10/1/96 Q= 11425 mscfpd at 1850 psig. WELL TESTS: MSCFPD BWPD TP CP DATE BEFORE: 10479 3 1850 9/29/1996 AFTER: 11425 4 1850 780 10/1 /1996 COMMENTS: REPORTED BY: Mike Olson ~ ~ MARATHON OIL COMPANY DATE: 10/2/96 FILL DEPTH/DATE: 8028' (10/2/96) DATE LAST WL WORK: 9/30/96 DAILY WELL OPERATIONS REPORT FIELD: Beaver Creek TUBING: 3.5" 9.3# L-80 PAGE 1 OF 1 W ELL #: ac-s CASING: 3-1/2" 9.2# N-80 TREE CONDITION: Good WORK DONE: Perfd B-17 BENCHES OPEN: 8-16, 17, 18, 19U/L, 20U/I PRESENT OPERATION: Perf'd B-16 - flow testing well B-20U/L, 21, 23 PROBLEMS: Tight spots at 6247' and 4070', 2 miss-runs Covered: B-24, 25, 27L SUMMARY OF OPERATIONS 0630 0725 0740 0825 0900 0935 1035 1050 1055 1125 1150 1330 1405 1420 1425 1445 1510 0700 Well flowing 11.824 mscfpd at 1820 psig. SWS on location. RU on well. SI well and establish communication blackout. MU 20' 2-1/2" Hollow Carrier, 6 SPF, 60 degree phasing, 10.5 gram RDX 34J Ultrajet charges. ' Open swab valve and RIH. Correlate to TDT log dated 9/14/94 (add 1' to collars to be on depth w/ open hole log). Tied into tubing tail. Tag fill at 8028'. Note: checked choke: slight flow w/ choke 100% closed. WHP = 2300 psig. Flow well at 3240 mscfpd to create underbalance. WHP = 2225 psig. Perforate w/ 525 psig DD: Run Interval Footage Comments #1 7440-7460' 20' B-16 - Gun did not fire Log collars up. POOH. Flag line at 7300'. No change in WHP or rate. SI well. POOH. Slow speed through tight spots at 6247' and 4070'. Pulled an additional 100# through tight spots. Establish communication blackout. OOH. Gun did not fire. Blasting cap went off but appears cap pulled out of primer cord when arming guns. MU 20' 2-1/2" Hollow Carrier, 6 SPF, 60 degree phasing, 10.5 gram RDX 34J Ultrajet charges. Open swab valve and RIH. WHP = 2350 psig. Flow well at 3240 mscfpd to create underbalance. Tied into flag at 7300'. Correlate to TDT log dated 9/14/94 (add 1' to collars to be on depth w/ open hole log). WHP = 2275 psig. Perforate w/ 475 psig DD: Run Interval Footage Comments #2 7440-7460' 20' B-16 Log collars up. No cha~ge in WHP or rate. SI well. POOH. Slow speed through tight spots at 6247' and 4070'. Pulled an additional 500# through tight spots. Establish communication blackout. OOH. All shot fired. MU 20' 2-1/2" Hollow Carrier, 6 SPF, 60 degree phasing, 10.5 gram RDX 34J Ultrajet charges. Open swab valve and RIH. Stop at 2000'. CCL not working. POOH. OOH. Rehead CCL. RIH. CCL working OK. WHP = 2375 psig. Flow well at 3240 mscfpd to create underbalance. Tied into flag at 7300'. Correlate to TDT log dated 9/14/94 (add 1' to collars to be on depth w/ open hole log). WHP = 2300 psig. Perforate w/ 450 psig DD: Run Interval Footage Comments #3 7420-7440' 20' B-16 Log collars up. No change in WHP or rate. SI well. POOH. Slow speed through tight spots at 6247' and 4070'. Pulled an additional 500# through tight spots. Establish communication blackout. OOH. All shotfired. RD SWS. WHP = 2390 psig. Bring well on line. 10/3/96 Q= 9353 mscfpd at 2050 psig. Open choke to reduce WHP to 1850 psig. Will update report as well stabilizes. W ELL TESTS: BEFORE: AFTER: COMMENTS: MSCFPD BWPD TP CP DATE 11424 4 1850 780 10/1 /1996 REPORTED BY: Mike Olson ~AARe~T~i®N Alaska Asset Team United States Production Operations a December 4, 2007 P.O. Box 3128 Houston, TX 77253 Telephone 713-296-2384 Fax 713-499-8504 FedEx Alaska Oil & Gas Conservation Commission Attn: Howard Okland 333 W. 7~' Avenue, Suite 100 ~~ ~~~, ~~~ Anchorage, AK 99501 RE: Marathon KDU #5 -API 50-133-20319-00 Marathon KBU #41-7 -API 50-133-20327-00 Marathon KBU #31-7RD -API 50-133-20347-01 ~ / ~ ~ ~ ~ Marathon BC #9 -API 50-133-20445-00 ~' t CONFIDENTIAL Dear Mr. Okland: Enclosed is one CD containing confidential core data for the above referenced wells. The Summary of Core Analyses Results document included all the wells in one document. I've included the original document, and have also saved each well out to a separate document for your files. Summary of Core Analyses Results: KDUS KBU41-7 KBU31-7RD_BC9_Summary_of Core Analsyis.pdf Separate Documents for each Well of Summary of Core Analyses Results: KDUS_50133203190000_Core_Analsyis_Summ.pdf KBU41-7_50133203270000_Core_Analsyis_Summ.pdf KBU31-7RD 501332034701.00_Core Analsyis_Summ.pdf BC9_50133204450000 Core Analsyis_Summ.pdf Please indicate your receipt of this data by signing below and returning one copy to my attention at the letterhead address or fax to 713-499-8504. Thank you, Kaynell Zeman Engineering Tech enclosure Receiv ed by Date: ~ I~ ~c. aW. ~i cY- t a~t> t17 • ~ Marathon A. MARATHON VII C®111p-an~{ November 27, 2007 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Reference: 10-404 Report of Sundry Well Operations -Cement Squeeze -Sundry #307-197 Field: Beaver Creek Field Weli: Beaver Creek #9L (PTD-192-122~rc~,~~, ~~ ~~~ ~ ~ 2{17 Dear Mr. Maunder: Enclosed is the 10-404 sundry 307-197. This sundry reports the cement squeeze operations to isolate perforations 6429'-6459' (30'). We had cement squeezed thts wet-- upper beluga zone with 10bb1 of 15.8ppg, 68sks of Class G Cement. This zone was pressure tested to 2500psig for 45min. Attached with the 10-404 is the detailed operations summary report and current wellbore diagram. Please send any sundries or pertinent documentation to Kevin Skiba at the above address listed. If you have any questions or need further information please call me at (907) 398-1362. Sincerely, Dennis Donovan Production Engineer Enclosures: 10-404 Sundry of Well Ops 307-197 cc: Detailed Operations Summary Report Current We11 Schematic Nt~v ~0~7 p~~~k~ I"~iil ~ u~ t~3~~. ~it~t~trte~sion A~tsh~r`~g AOGCC Houston Well File Kenai Well File DMD KJS ~ ~~ STATE OFaLASKA • N(~V ~ 207 ALASKA O!L AND GAS CONSERVATION COMMISSION ~~~ ~~1 ~ ~~~ ~~fli. ~gmftl~IRSiafi REPC)RT QF SUNDRY WELL t1PERATi01~ An~htiri~~~ 1.Operations Abandon ^ Repair Well Plug Perforations ~ Stimulate Other Performed: Alfer Casing ^ Pufl Tubing ^ Perforate New Pool ^ Waiver^ Time Extension ^ Cement Squeeze Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Weil ^ Perforations 2.Operator Marathon Oil Company N 4. Weli Class Before Work: 5. Permit to Drill Number. ame: Development ~ Exploratory^ 192-122 3. Address: Stratigraphic^ Service^ 6. API Number: PO Box 1949, Kenai Alaska, 99611-1949 50-133-20445-00-00 7. KB Etevation (ff): 9. Weil Name and Number. 183' ~ Beaver Creek 9L 8. Property Designation: 10. Field/Pool(s}: FED A028083 - Beaver Creek Field / Belu a Pool 11. Present Well Condition Summary: Total Depth measured 8,881'' feet Plugs (measured) 8,808' true verticaE 8,500' ~ feet Junk (measured} N/A Effective Depth measured 8,226' (Fill) feet true vertical 7,845' feet Casing Length Size MD TVD Burst Collapse Structural 116' 13-3/8" 116' 116' N/A N!A Conductor Surface 1,853' 9-5/8" 1,853' 1,725' 4,750' 6,870' Intermediate Production 5,950' 7" 5,950' 5,555' 7,020' 8,160' Liner 3,067' 3-1/2" 8,881' 8,500' 10,530' 10,160' Pertoration depth: Measured depth: 7,420' - 8,452' ' True Vertical depth: 7,039' - 8,071' Tubing: (size, grade, and measured depth) 3-1/2" AB Mod Buttress L-80 9.2 ppf 5,814' Packers and SSSV (type and measured depth) Baker Model H packer 5,814' 12, Stimulation or cement squeeze summary: Intervals treated (measured): Cemented 6429'-6459' MD (30') Wet Upper Beluga with (2 squeezes) - 5bbl - 15.8ppg - 34 sks of Class G). Treatment descriptions including volumes used and final pressure: Total of 10 bbl -15.8ppg - 68 sks of Class G, Stepped up to 2500 psig Squeeze Pressure on both treatments and held for 45min with minimal bleed off 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbt Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 29 Subsequent to operation: 0 0 0 0 355 94. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory^ Development ^~ Service ^ Daily Report of Well Operations 6-23-07 to 10-22-07 16. Well Status after work: Oil ^ Gas Q WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or NIA if G.O. Exempt: 307-197 Contact Kevin Skiba (907) 283-1371 Printed Name Dennis M. Signature ~ Jr Tide Production Engineer Form 10-404 Revised 0,' _ .. ~ j.~~-, ~i ~(~Q.( Phone (907) 283-1333 ~-~~3oR~~~~v~ L Date 27-Nov-07 Submit Original Only • Annular Wellbore` ~r~uu-rno?n I ~ I~ F 1164' FNL ~ 1547' FWL API # 50-133-20445 1/4" .049 wall Chemical injection line open to annulus at 1000' -~ s • 13 3/8" K-55 0 61 ppf nla 116 9 5/8" L-80 47 ppf BTC Cemented with 700 sacks 0 1653 MD 3.5" Buttress AB Mod Tubing TCP Assebly @ 5636' Includes two AB- Mod Buttress by ST-L crossovers, Y- block and 8' of 2" scallop guns Max OD = -' 5.887" TVD) Chemical Infection Mandrel ~ Production Seal Unit Model H liner hanger packer 7534'-74', 7640'-60', 7705'-55', 7762'-7842', ~ 7893'-7933', 7980'-8030', 8036'-54', 8072'-98', 8241'-46', 8254'-61', 8276'-92', 8399'-$409', MD I', 7153'-93', 7259'-79', 7324'-74', 7381'-7461', ]1', 7512'-52', 7599'-7649',7655'-73', 7691'-7717', ]6', 7860'-65', 7873'-80', 7895'-7911', 8018'-28', TVD) Model N BP at 8608' MD 2.813 CMU Sliding Sleeve 7" N-80 0 29 ppf BTC 5950 MD Cmt with 565 sks In 2 stages, DV at 4487 MD Cmt Squeezed Wet Upper Beluga with 10bb1 15.8ppg 68sks of Class G 2500 psig squeeze 712812007 Liner Assembly 3.5" L-80 5814 MD 9.2 ppf Butt 8881 MD Cemented with 500 sacks Well Name ~ Number. Beaver Creek 9 Lease Beaver Creek County or Parish: KPB State/Prov. AK Count USA Angle/Perfs Angle KOP and Depth 0 KOP TVD 0 Date Completed: RKB: Prepared By: 0 Last Revision Date: 11/27107 DMD Marathon ail Company Page 1 of 12 apes#ons Surnrnary Report.. Legal Well Name: BEAVER CREEK 9 Common Well Name: BEAVER CREEK 9 Spud Date: 7/28/1994 Event Name: MAINTENANCEIREPAIR Start: 6/23/2007 End; Contractor Name:: Rig Release: Group: Rig Name: Rig Number: Date From - To Hours -Code ..Code Phase Description of Operations 6!23!2007 .08:00 - 11:00 3.00 SAFETY MTG_ PRIEVL Arrive on location, sign fn. Walton Crane arrivat. Obtain work permit and hold pre-job safety meeting. 11:00 -13:00 2,00 SAFETY MTG_ PRIEVL MIRU Crane. Pickup Welt Tree Cover. Move. WsU Tree Cover to side of location out of the way. 13:00 - 13::30 0.50 SAFETY MTG PR1 EVL Hold safety meeting. MIRU E-line Equipment. 13:30 - 13:45 0.25 TEST_ BODE PR1 EVL PU lubricator and pressure test to 2500 psi. Held Pressure. 13:45- 15:15 1.50 RUNPU ELEC PR1 EVL RIH w/ 2.80" Gau a Rin on E-line. Get on Depth @ 5812' on Model H Liner hanger packer. Continue in Hole with Gauge Ringto 685p'. POOH 15:15 -16:00 0.75 TEST^ BOPS PR1 EVL 16:00 - 17:15 1.25` RUNPU ELEC PRIEVL 17:15 - 1:8:45 1.50 RUNPU ELEC PRIEVL 18:45- 19:00 0.25 SECUR WELL PRIEVL 19:00- 19:15 0.25 SECUR ELEC PRIEVL 19:15 -1930 0.25 SECUR ELEC PRIEVL fr124/2007 08:00 - 08:30:. 0.50 SAFETY MTG_ PRIEVL 08;30 - 09:30 1.00 SAFETY MTG_ PR1 EVL 09:31)- 70:00 0.50 TEST_ ROPE PRIEVL 10:00-11':00 1.00 RUNPU :ELEC: PR1EVl 11:00 -11:15 0.25 TEST ROPE PRIEVL 11:15-12:15 1.00 RUNPU. ELEC PRIEVL w/gauge ring. Shutin Well. Remove Lubricator. Remove Gaugge Ring. Install Setting Tool and RBP on Wireline. PU lubricator and pressure test w/WHP. Start RIH w/RBP. RBP stopped @ 100' from surface because of Ice sheen on walls. of 3-112" tubing because of pressure testing lubricator with water. Worked RBP to 140' f! surface. POOH w/ RBP. Poured Methenol in Lubricator. RU Lubricator and Pressure lest w/ Wellhead Pressure. RINw/ RBP. RBPstopped @ 140' from surface. Worked RBP. POOH w/ RBP. Poured Methenol in Lubricator. RU Lubricator and. Pressure test w/ Wellhead Pressure. RIH w/RBP Stopped @ 140' from Surface.. Worked RBP to 200' and RBP started falling freely. Continue. to RIH w/RBP on Wireline. Get on Depth @ 5812' on Model H Liner hanger packer. Continue to RIH w/RBP. Run Collar Strip to For depth check. Set RBP @ 6590' @ 18:15 Hrs.. POOH vol Wireline and Setting Tool Shutin Wetl. Rig Down Lubricator: Secure Well. Rig backwireline equipment. Sign out, tom in paperwork and leave location. Arrive on location, sign in. Obtain work permit and hold pre-job safety meeting. Hold safety meeting about Rigging up antl Testing Lubricator, Arming Cap to break glass on bottom of Bailer to Dump Sand out of Sand Dump. .Bailer. Make sure aN 5catia and cell phones are turned off on Well Pad. Check Tubing Pressure. Tubing Pressure = 7:280 psi. PU lubricator. Pick up Bailer. Arm Bailer with cap. Load 2" OD x 30' tong Dump Bailer with 4.11 gallons of 20/40 Mesh Sand (The 4.11 gallons of Sand in Dump Bailer shoo-d fill 3-1/2" 9.3# Tubing 1.1.25'). Install:Lubricator. Open Well Head°Tree Valves to Pressure test to Well Head Pressure. Held Pressure. Open all Well Head Tree Valves Fully.. RIH w/ 2" OD x 30' Long Dump Bailer with 4.11 gallons of 20/40 Mesh .Sand on E-line.. Get on Depth @ 5812' on Model H Liner hanger packer. Continue In Hole with Dump. Bailer with 4.11. gallons of 20!40 Mesh Sand to 6580' Bottom of Bailer. Fire Cap to Break glass. Dump Sande. out of Dump Bailer. POOH w/ Dump Bailer.. Shutin Well. Retnove Lubricator. Arm Bailer with cap. Load 2" OD x 30' Long Dump Bailer with 4.11 gallons of 20/40 Mesh Sand (The 4.11 gallons of Sand in dump Baiter shautd fail 3-172" 9.3# Tubing 11.25').. Install lubricator and pressure test w/WHP. RIH w/2" OD x 30' Long Qump Bailerwth 4,11 gallonsof 20/40 Mesh Sand on E-line: Get on Depth @ 5812' on Model H Liner hanger packer. Continue in Hole with Dump Bailee with 4.11 gallons of 30!40 Mesh Sand to 6580' Bottom o1 Bailer. Fire Gap to Break glass. Dump Sar1d out of Dump Baiter. Tag Top of Sand Fill @ 6575' (15' Sand fill on top of ,RBP top @ 6590' while sand is still settline from just dumping 2nd Dump bailer load ofsand). POOH w/ Dump :Bailer.. Printed: 11/27/2007 9:52:01 AM • • Marathon Oil Company Operations Summary Report:.. Legal Well Name:. BEAVER CREEK 9 Common Well Name: BEAVER CREEK 9 Event Name: MAINTENANCEIREF'AiR Start: 6/23/2007 :Contractor Name: Rig Release; !Rig Name: Rig Number: Date I From - To I Hours `:Code I Code ~ Phase 24!2007 12:15 - 12:45 0':50 TEST . BOPS PRIEVL 12:45 - 13:45 1.00.. RUNPU ELEC PRIEVL 13.95 - 14:30 i 0.75 ~ TEST_ ~ BOPE ~ PR1 EVL - 15:30 I 1.00{ RUNPtJuELEC iPR1EVL 15:30 -16:1..5 ~ 0.75 ~ TEST_, ~ BOPE ~ PR1 EVL 16;15- 17:30. ~ 1.251 RUNPUuELEC ~PR1EVL 17:30-18:00 0.50. SECUR WELL PRIEVL 18;OD- 18:15 0.25 RURD_ ELEC PRIEVL 18'.15 - 18:30 0.25 KURD. ELEC PR1 EVL 6/25/2007 08:15- 08:45 0:50 SAFETY MTG PRIEVL 08:45 - 09:00 ~ 0.25 ~ SAFETY 1 MTG_ ~ PR 1 EVL 09:00 -.:09:30 i 0.50 TEST_ ~ BOPE ~ PR1 EVL Page 2 of ~ 2 Spud Date: 7/28/1994 End.: Groap: Description of Operations Shutin Well. Remove Lubricator. Arm i3ailer with cap. Load 2" OD x 30' Long Dump Bailer with 4.11 gallons of 20140 Mesh Sand (The 4,1:1 gallons of Sand in Dump Bailer should. fill 3-112" 9.3# Tubing 11.25'). Install lubricator and pressure test w/WHP. RIH w/ 2" OD x 30' Long Dump BaileFwith 4.11 gallons of 20/40 Mesh. Sand on E-line. Get on Depth @ 5812' on Model H Liner hanger packer. Continue in Hole with Dump Bailerwith 4.11 gallons of 20/40 Mesl1 Sand to 8550' Bottom of Baiter. Fire Cap to Break glass.:Dump Sand out of Dump Bailer on 3rd sand dump bailer run. Tag Top of Sand Fili 6571' (19' Sand fill on top of RBP top @ 6590' white sand is still. settling from just dumping 3rd Dump baiter toad of sand). POOH w! Dump Bailer. Shutin Well. Remove Lubricator. Arm Bailerwith cap: Load 2" OD x:30' Long Dump Baiter with 4.91 gallons of 20/40 Mesh Sand (The 4.11 gallons of Sand in Dump Bailer should fill 3-112" 9.3# Tubing 11.;25'), Install lubricator and pressure test wi WWP. RIH w/ 2" OD x 30' Long Dump Sailer with 4.1 ~ gaflorts of 20/40 Mesh Sand on E-line. Get on Depth @ 5812' on Model H Liner hanger packer.. Gontinue in Hole with Dump Bailer with 4.t1 gallons of 20/40 Mesh Sand to B560' Bottom of Bailer. Before dumping Bailer on 4th Bailing Run. Tag Top of Sand Fill Ca"t 6565' (25' Sand fill on too of RBP too 6590'). Fire Cap to Break glass. Dump Sand out of Dump Balser. Dump Sand out of Dump Bailer on 4th sand dump bailer run. POOW w/ Dump Bailer. Shutin Well. Remove Lubricator. Found Wire broken from CGL to bottom of Baiter thatfires cap to break glass bottom to bailer to dump sand.. Laydown Lubricator and Dump Bailer on Ground:. Repair Broken wire. Pick up Lubricator and dump bailer. Arm Bailer with cap. Load 2" OD x 30' Long Dump Bailer with A.11 gallons of 20/40 Mesh Sand (The. 4.11 gallons of Sartd in Dump Bailer should fill 3-1/2" 9.3# Tubing 11.25'). Install lubricator and pressure test w/ WHP. RIH w! 2" OD x 30' Long Dump Bailer with 4.:11 gallons of 20140 Mesh Sand on E-line. Get on Depth @ 5812' on Model H Liner hanger packer. Continue in Hole with Dump Bailer with 4.11 gallons of 20/40 Mesh Sand to 6550` Bottom of Bailer. Before dumping Bailer on 5th Bailing Run. Tag Top of Sand Fill. Q 6555' (35' Sand fill on top_ of RBP top @ 6590,)~t a ap to Break glass. ump Sand out of Dump Bailer on 5th wand dump baiferrun. POOH w/ Dump Bailer, Bailer did not dump°sand bridged off in Bailer. Last Tag with 4 bailers of sand dumped and settle had 35' sand fill on top of RBP. Will return tomorrow to tag sand fill and (dump bail remaining sand on RBP. Shutin Well. Remove and Rig down Dump Bailer.. Rig Down Lubricator: Secure Well. Rigged back wireline equipment. ..Sign. out, turn in, paperwork and leave location:. Arrive on location, sign in. Obtain work permit and hold pre job safety meeting. Hold safety meeting about Rigging up and Testing Lubricator, Arming Cap to break glass on bottom of Bailer to Dump Sand out of Sand Dump Bailer. Make sure all Scada and cell phones are turned off on Weil Pad.. Cheek Tubing Pressure. Tubing Pressure = 1220 psf. PU lubricator. Pick. up Bailer. Arm Baiter with cap. Load 2" OD x 36' long Dump Bafler with. 4.11 gallons of 20140 Mesh Sand (The 4;11 gallons of Sand in, 11127(2!)07 9:52tU1 AM. • • Marathon Oil Company Page 3 of 12 Operatians Summary Report .Legal Well Name: BEAVER CREEK 9 Common Well Name: BEAVER CREEK 9 Spud Date: 7/28/1994 Event Name.: MAINTENANCE/REPAIR Start: 6/23/2007 End: Contractor Name: Rig Release: Group: Rig. Name: Rig Number: Date From - To Mours Code. 1 Code Phase 6/25/2007 09:00 - 09130 0.50 TEST ROPE PR1EVL 09'30- 12:00 2.50 RUNPU ELEC PR1EVL 12:00 - 12:15 0.25 RURD ELEC PR1 EVL 12:15 - 12:30 0.25 RURD_ ELEC PR1 EVL '12:30 - 12:45 0.25 F2URD_; ELEC PR1 EVL 12:45 - 13:00 0.25 RURD ... ELEC PRIEVL 7/26/2067 07;30 - 08:30 1.00 SAFETY MTG CTBG 08:30 - 12:00 3.50 KURD COIL CTBG 1:2:00 -13:30 1.50 RURD COIL CTBG 13:30 -15:00 1:50 RURD_ COIL CTBG 15:00 - 16;30 1.50 WAITON EQIP CTBG - 1$:00 ~ 1 18:00 - 1:8:30 ~ 0.50 ~ RURD_ COtL 7f2712007 108:00 -12:00 4.001 PUMP_~ WTR_ CTBG 12:00 - 13:34 ~ 1.50 ~ PUMP_~ WTR_ 13:30 - 15:00 ~ 1.501 PUMP_i CMT_ 15:00.- 16:45 ~ 1.751 SQUEZE~CMT_ Description of Operations Dump Bailer should fill 3-1{2" 9.3# Tubing 11.25'). }nsia}I Lubricator. Open Well Head Tree Valves to Pressure. test to Well Head Pressure, Held Pressure.. Open all Well Head Tree Valves fully. RIH w/ 2" OD x. 30' Long Dump Baiterwith 4.11 gallons of 20/40 Mesh Sand on E-line. Get on Depth @ 5812' on Model H finer hanger packer. Continue in Hole with Dump Bailer with 4.11 .gallons of 20140 Mesh Sand to 6550' Bottom of Bailer. Before dumping Bailer on 6th Baiting Run. Tag Top of Sand Fill @ 6551' (39' Sand fill en to~of RBP top @ 6590'). Fire Cap to Break glass. Worked hailer for 1-1/2 hrs working to Dump Sand out of Dump Bailer because sand was damp, bailer diameter is small and sand mesh is small (20/40 mesh. sand). Dump Sand out of Dump Bailer ort' 6th sand dump bailer run. Tag Top of Sand Fill @ 6551' (48` Sand fill on top of RBP top @.6590') after dumping sand out of ba}loran 6th'bailer run. POOH w/ Dump Bailer. Should be between 48' and 50' Sand on Top of RBP. RBP Setting depth @ 6530': lop of Sand Fill should be @:6542' to 6540' from surFace: Shutin Well. Remove Lubricator. Laydown Lubricator and DumpBaiier on Ground. Secure Well. Rig down Dnmp Bailer: Rig Down Lubricator. Leave Well Shutin to fet remaining sand fall. RDMO wireline equipment: Sign out,tum in paperwork and leave location. Arrive on location. Qbtain Work permit. Finish RU crane. RU 2" hard lines to coil unit, high pressure pump, N2 pump, and choke manifold' and gas buster: trtstali coil connector. Pull test to 5K. Test good jest BOP's. 350 psi low/3500 psi high. Test fait. Waited°for Vetco Gray to perform maintenance on swab valve and mastervalves. Test BQP's. 350 psi Iow135Q0 psi high. Swab did not hold after maintenance was performed. Shut master and wing valve on tree o successfully test. BOPS. lnstali night capon. tree. Secure kcaton for the night. Sign out and leave location. Arrive on location. Obtairr Work permit Hold tailgate safety meeiing. RU injector on weAhead. Sart in hole wlih cement head. Pumping 18PM to fill hole. Continue to tag sand @ 6545' coil depth. BHA @ 6500'. Start injection test as foilows:.3 BPM @.avg WH psig 172 5 BPM @avg WH psig = 190 .75 BPM @ WH psig = 250 1.0 8PM avg WH psig = 568 1.25 BPM @ WH ps}g = 718 1.5 BPM @avg WH psig = 880 psig 1.756PM @avg WH psig =1035. Used total of 51.2 bbls far test, B}ed off psi. Mix 5 bbis of cement tip 15:8 Ib/gal (94 sks of Glass G cement} pump down coil while TIH to 8525'. Opened return line to establish Ito 1 displacement to track cement in coil. Pumped 1.5 bbis out of the nozzle and begin moving up hole with nozzle. Stop @ 6179` pumped full cement load. Slopped @ 27.5 bbis of displacement @ 1.5 BPM. Bucket tested to confirm returns:. Reciprocated coil from 6100' to 6150' three times to ensure coil is clear of cement. PUN to 5665' and apply psig. Communicaiionsfiailure between pump opr and coil opr. Started sqz @ 900 psig. Left 900 psig far 25 minutgs_ PnhtCtl: 1187/2007 9:52:01 AM • Marathon Oil Company Page 4 of 12 Opera#ions Summary Report .Legal Wep Name: BEAVER CREEK 9 Common Well Name: BEAVER CREEK 9 Spud Date: 7/28/1994 Event Name: MAINTENANCE/REPAIR Start: 6/23t2Q07 End: Contractor Name: Rig Release: Group: :Rig. Name:. Rig Number: Date From -To Hours Code Cede Phase l Description of Operations 7!27/2007 15:00 - 16:45. 1.75 SQUEZE CMT CTBG 16:45 - 18:45 2.00 PUMP_ WTR~ CTBG 18:45 - 20:30 7/29/2007 08:00-09:1b 09:15 - 11130 1.75 RURD_, COIL CTBG 1.25 SAFETY MTG_ CTBG 225 TEST... CMT CTBG 11:30 - 13:50 2.33 PUMP_ WTR_ CTBG 13:50 -15130 1.67 PUMP WTR_ CTBG 15:30 -17:40 1.50 PUMP GMT_ CTBG 17:00 -18:45 1.75 SQUEZ CMT_ CTBG 18>45 - 21:25 2.67 PUMP^ 21:25 - 22:00 0.58 RURD_ 7/31/2007 08A0 -09:15 1.25 SAFETY 09:15 - 11:30 2,25 TEST CTBG CTBG _ CTBG _ CTBG 2500 psig held for 45 minutes with minimal bleed off; Bled off psi slowly to flowback tank. Ail pressures recorded are wellhead pressures. RIH to 5900' start pumping f310ZAN. RIH to:6546' TAG. TOH pumping to jet nozzle stopped @ 5000'. Reversed fluid circula€ioo increase pump [0 1 BPM T1H to tag 6546' @.110 FPM. Strong gray retums: PUH to 6530', Circulated with 1 to 1 volumes. Circulated clears w/ total of 100 bbis. TOH pumping 5 BPM. Rig back coil injector. Install night capon tree:: Secure location for the night. Sign out and leave location:.. Arrive on location.. Obtain Work permit Hold tailgate safety meeting. Bled wellhead to ensure no air an well. Loaded with .25 bbl of fresh RU injector on wellhead. Start in ole with cement head. TIH to fag sand @ 6545' coil depth. Pressure test coil to 3500 psig. PUH w/BHA to 6500'. No injection rate could be established. Prep to pump cement squeeze. Mix 5 bbls of cement @ 15.B Ib/gal (34 sks of Class-G cement) pump down coil while TIH to 6525', Opened return line to establish Ito 1 displacement to track cement in coif. Pumped '1.5 bbis out of the nozzle and begin moving up hole with nozzle. Stop @ 6179' pumped full cement load. Stopped @ 27:5 bbis of displacement @ 1.S BPM. Bucket tested to confirm returns. Reciprocated coil from 6100' to 6150' three Canes to ensure coil is clear of cement. PUH io 5665' and apply squeeze psig. Pump up to 500 psig for 45, minutes, 2040 psig for 5 minutes and 2500 psig held for 45 minutes with minimal bleed off.. Bled off psi slow y to ow ac tan .All pressures recorded are wellhead pressures. Good squeeze pressure. RIH to 5900' startpumping,10 bbis BIOZAN, RIH to 6546' TAG. TOH pumping to jet nozzle stopped @ 5000'. Reversed fluid circulation increase pump to t BPM TIH to tag 6546' @ 110 FPM. Strong gray returns, PUH to 6530'.. Circulated with 1 to 1 volumes. Circulated clean w/ total of 90 bbis, TOH pumping min rate. Stop pump at surface. Rig back coil injector. lnstalf night capon tree. Secure ocatian for the night. Sign out and leave location. Arrive on IocaCron. Obtain Work permit Hold tailgate safety meeting. Prime and prep pumps. Bled wellhead to ensure no air on well. Loaded with .2 bbl of fresh water and pressured to 535 psig. Held pressure for 30 minutes -bled down to 516 psig. Good test.. Was notified from the 11:30 - 12:30 ~ 1.00 RURD_~ COIL ~ GTBG 8/2!2007 ~ 09:30 -14:27 ~ 4.95 ~ ET ETY I WTR_ I CTBG Shut down operations pending stand down meeting. Set up furthecwork far Thursday morning. Secure location for the night. Sign out and leave IocaCwn. Arrive ontocation. Obtain Work permit. Hold tailgate safety meeting. Prime and prep. pumps. RU coil injector on wellhead. Shell test to 1000 psig. OK TIH w/ jet nozzle to 3000' and pull tested cdil. OK. Contnue in hole tq light tag @ 6838 estimated top of sand'. Start jetting @ 1BPM to 6589'. Getting full returns with some gray colored sand material. Worked up 10 6500' with full returns @ 1.5BPM. Gircuiated until fluid came back Printed 11727I20D7 9:52:D1 AM • COIL ~ CTBG Marathon Oil Company Page 5 of 1z Operations Summery Report. Legal Well: Name; BEAVER CREEK 9 Common Wefl Name: BEAVER GREEK'S Spud Date: 7/28/1994 Event Name: MAINTENANCE/REPAIR: Start: 6!23/2007 End: Contractor Name: Rig Release: Grotap: Rig Name:. Rig Number: .Date I From - To Hours Code , ode Phase ` Description of Operations )9:30- 10.:27 4.95 JET ~WTR_ CTBG 14:27 -17::15 2.80 JET, N2_ CTBG 17:15 - 1:8:50 1.58 RURD_ COIL CTBG 8:50 - 19:30 ~ 0.67 ~ ~ ~ CTBG - 09:00 I 0 501 KURD YI SL K- I WRL 09:00 - 16;00 ~ 7:00 16:D0 -16:30 0.50 RURD_ 8F5/20t)7 08:00 - 08:30 0.50 SAFETY 08:30 - 09;D0 0.50 RURD_ D8:30 - 09:30 1.00 RUNPUL 09:3D - 11:00 I 1.501 RUNPUL 11:00 -1:3:30 13'30 -14:00 14:00 -16:30 16;30 - 19.30 f 3.04 19:30 - 20:00 ~ 0.50 consistently clean @ 44 bbls of fresh water. Avg pump psi = 3300 and WH psi = 48. Started coot down on N2 pump. Switched over to Nitrogen. Injecting ai an average of 750 SCFM. Move up hole until water returns stopped. Continued pumping N2 to 800 FFS. Shut off N2 and continue outnf hole with coil. Returned a total of22 bbis of water to return tank. Coil to surface. RB injector head and installed well cap, Left equipment in place for tomorrow. inspected & repaired weight'ndicator pads. Turned paperwork in and signed out. Arrive on location: Obtain'Work permit. Hold tailgate safety meeting: After discussing what toot is in the well, PWL did not have the proper tool to retrieve the Weatherford RBP. Ordered tool to be delivered tonight. Will RU & retrieve RBP on Sunday and move Coil out today. Nipple down BOPS, Began rigging down coif unit to prep to move to Sterling Unit 43-9X. BJ mechanic is working on power-pak. Loading and moving equipmentout. CTBG. I Turned paperwork in and signed out.: WRLN Signed in @ BC control room. Held JSA and obtained a safe work SLIK WRLN SLIK WRLN EQIP SLIK PLUG WELL, ~ WRLN 8/7/2007 + 08100 - 08:30 ~ 0:50 ~ SAFETY ~ MT`G_ ~ WRLN 08:30 - 09:00 ` 0.50 09:00 - 10:D0 I 1.00 10:00 - 10:30 ~ 0.50 10:30 = 11:00 0.50 1:1.:00 - 12'AO SIIK (WRLN SLIK WRLN Rig up slick line. Test lubricator to 25Q0 psig. OK Run: in hole with 2.75" gauge ring. Slight tag @ .Worked down through fag and worked this area forseverat minutes unfit drag diminished. RIH w! LIB to tag @ 6591' KB depth. TON and. read L1B. Tagging °soft material (sand) PU pump baler- RIH and worked bailer from 8500' down. to 6591'. TOH - LD bailer. Racked offwith sand. Pump. rod stuck. Ordered replacement pump from shop. RIH w/drill down bailer to hard tag @ 6591' KB dept!}. Worked bailer and TOH. Bailer had some. sand ... not a significant amout. Walton' pump bailer. Wait on replacement pump hater to arrive from PWL shop. RU 2.25" pump bailer. Made three' erns to same depth. Recovered app 1 quart of sand on the firstrun and very slight amount on second run. No fill recovered on last run. PU Weatherford fishing sleeve mated to GU -RIH to 6593' made several attempts to latch on to RBP and equalize. TOH - inspect tool Did notrecover retieval tool. Made several attempts to PU tool. Galled Fred Pollard, decided to SDFN. Secured equipment and well. Signed out. W)Il wait ortfurther insUuctions in the morning. Signed in @ BC control room. Held JSA and obtained a-safe work permit. Rig up slick line. Test lubricator to 2500 psig. OK RIH.. wt LIB to tag @ 6591' KB depth. TOH and read t,i6. Tagging SLIK WRLN Rig up slick line. Test lubricator to 2500 psig. OK SLIK WRLN R1H w13" GS to hard tag @ 6591' KB depth. Worked overshot and tndicated tool came free. No pressure @ surface. TOH did not recover overshot. SLIK WRLN RIH w!3" Bulldog. spear to hard tag @ 6591' KB depth. Worked overshot :and indicated toot came free. PU 150# over and releasetl.No pressure @ surface. TOH did not recover overshot. • LJ Marathon Oil Company Page s of 12 Operafions Summary Report Legal Well Name:: BEAVER CREEK 9 Common Well Name: BEAVER CREEK 9 Event Name: MAINTENANCE/REPAIR Contractor Name: Rig Name: Date From - T© Hours Code I Coda.. Phase 81712007 12:00-13:20 1.33. RUNPU SLIK WRLN 13:20 -15:30 ~ 2.17 ~ SETREL ~ PLUG 15;30 -16:00 0.50 .SECUR WELL WRLN 08:30--09:00 0.50 SAFETY MTG_ WRLN 09:00 -.09545 0.75 RURD;._ SL[K WRLN 09:45 - 12x30 2.75 RUNPU SLtK WRLN 12:30 - 13:30 I 1.001 RUNPULISLIK (WRLN 13:30 - 14;30 I 1.00 14:30 - 15:80 RUNPU SLIK WRLN RUNPU SLIK WRLN 15:00 - 17:00 ~ 2.00 17:00 - 17:30 0:50 8/9/2007 08:00 - 08:30 0.50 08:30 - 09:00 0.50 09:00 - 12:00 3.00 12:00 = 13:30 ~ 1.50 13;30 - 16:00 16'00,- 17:DO I 1.00 17:00 - 17:30 8/1012007 08:00 - 08:15 RUNPl1 SLIK WRLN SECUR "WELL WRLN SAFETY MTG_ WRLN RURD SLIK WRLN RUNPU SLIK WRLN RUNPU SLIK WRLN RUNPU SLIK WRLN RUNPU SLIK WRLN SECUR WELL WRLN SAFETY MTG_ WRLN Spud Date: 7/28/1994 Start: 6/23!2007 End: Rig Release: Group: Rig Number: - Description of ~peratans RiH w13" Bulidog spear wl ears spread to 2:.56" to hard tag @ 6591' KB depth_ Worked overshot and indicated-tool came free. PU 150# over and released.No pressure @ surfFace. TOH had Weatherford overshot: Overshot in very bad condition. Weatherford Toot operator arrived on oration and inspected overshot. Decision was made to install replacement fishing neck-which will be flown in from the slope. Will have PWL build bailer dip tube to fit into overshot fish neck. Secured equipment and well.: Signed out. WilEwait an further instructions in the morning. Signed in @ BC control loom. Held JSA and obtained a safe work permit. :Rig up slick. line.: Test lubricator to 250o pstg. OK RU 2.25" pump bailer. Made three runs to same depth. Recovered app 3 quart. of sand on the first run and very slight amount on second. run. No fill recovered on last run.. Laydown Pump Bailer. Test lubricator to 2500 psig. OK. RIH w/3" GU to hard tag @ 6591' KB depth. Worked overshot and indicated tool came free. No pressure surface. POOH w1 GU and w/o WRP Pulling tool overshot. GU Pulling tool unlatched from WRP Pulling Tool. Test lubricator to 2500 psig. OK. RIH w! 3" Bulldog spear to hard'tag 6591 ° KB depth. Worked overshot and PU 3 times 1500# over and released on 3rd Try. No pressure ,@ surface. TOH did not recover ~ overshot. Spear pulled out of GU tool. (Test lubricator to 2500 pstg. OK. RIH w/3" Bulidog spearw/ears spread to 2.56"'to hard tag @ 6591' KB depth. Worked overshot and indicated tool came free. PU 1500# over and released:: No pressure @ surface. Test lubricator to 2500 psig. OK. RU 2.70" pump bailer. Made two runs to same depth.. Recovered. app 1 quart of sand on each run: RD Bafler. RD Lubricator. C1ase all Valves on Well Head:. Install Night Capon Well, Secured equipment and well. Signed out. SDFN. Signed in @ BC control .room. Held JSA and obtained a safe work permit. Rig up slick line. Cut Off 5tic~c Line arsd Rehead. Pick up and Install Lubricator and BalecTest lubricatorto 2500 psig, OK RIH w12',70" pump baiter. Made 3 Bailer runs to 6591' KB depth:: Recovered app 112 gallon of sand on each of First 2 Bailer runs.,No Sand. in Bailer on 3rd Bailer Run. RD pump Baiter. RU Lead Impression Block. Test lubricator to 2500 psig. OK. RIH w/LIB to tag @ 8591' KB depth. TOH and read LIB Tagging soft material (sand). RD LIB, RU Bailer. Test lubricator to 2500 ps'sg. OK.'RIH w/ 2.70" pump bailer. Made 3 Bailer runs to 6591' KB depth. Recovered app 1/2 gallon of sand on each ofFirst 2 Bailer runs. No Sand fn Bailer on 3rci Bailer Run. RD pump Hailer. RU Hydrostatic Baiter Test lubricator to 2500 psig. OK. RIH w/ 2.70" Hydrostatic bailer. Made 1 Hydrostatic Bailer run to 6591' KB depth. Recovered app 1 quart of sand, RD Hydrostatic Bailer. RD Lubricator. Close ail Valves on Weil Nead. Install Night Cap on Well. Secured equipment and well. Signed out.: SDFN. Signed in @ BC control room. Held JSA and obtained a safe work rftnleu:. { iic ri<vue. n.... ,... • Marathon Oil Company Page 7 of 12 Operations Summary Report Legal Well Name: BEAVER CREEK 9 Common Well Name: BEAVER CREEK 9 Spud Date: 7/28/1994 Event Name: MAINfiENANCElREPAIR Start: 6123I20D7 End: Contractor Name: Rig Release: Group: Rig .Name: Rig Number: I Date- From - Ta Hours Code Code: Phase Description of Qperations 8110{2007 08:00 - 08:15 0.25 SAFETY MTG_ WRLN permit, 08:15 - 09:00 0.75 RURD_ SUK WRLN Rig up slick line. Cut Off Stick Line and Rehead. Picfc up and Install Lubricator and Bailee.Test iubricator'to 2500 prig. OK 09:00 - 09:45 0.75 RUNPU SLIK WRLN RU Hydrostatic Bailer. Testlubricatoi• to 2500 psig. OK. RIH w/ 2.50'! Hydrostatic bailee Made 1 Hydrostatic Bailer run to 6591' KB depth. Recovered No sand,. Bailee Standing. Valve Bail Sheared pin that holds it in plaoe causing holes to be exposed that could have allowed sand to escape out of bailer. Pin shearing could have been caused by tagging the WRP Retreavable bridge Plug Fishing Neck. RD Hydrostatic Bailer. 09:45 - 10:45 1.00 RUNPU SLIK WRLN RIH w/ 2,25" pump bailer. Made 1 Bailer run to 6591' KB depth.. Recovered app lquart tyf sand on Bailer Run. RD pump Bailer. 10:45 -11:45 1.00 RUNPU. SLIK WRLN RU Hydrostatic Bailer. Test lubricator to 2500 psig. OK. RIH wl 2.50" Hydrostatic bailer_ Made 1 Hydrostatic Bailer run to 6591' KB depth.: Recovered No sand. Sailer Standing Valve BaiLSheared-pin that holds;tt in place. causing holes to be exposed that could have allowed sand to escape out of bailer. Pin shearing could have been caused by tagging the WRP Retreavable brldgePlug Fishing Neck. RD Hydrostatic Bailer. 11:45 - 12:45 1:00 RUNPU. SLIK WRLN RU Lead Impression Block. Test lubricator to 2500 psig. oK. RIH w/LIB to tag @ 6591` KB depth. TOH and read LIB. Tagging Hard and got impression of top of WRP Retreavable Bridge Plug Fishing Neck. RD L1B. 12:45 - 13;1.5 0.50 RUNPU SLIK WRLN RU Hydrostatic Bailer with. different BHA#o prevent Fishing Neck from. hitting Bailer sealing ball. Test lubricator to 2500 psig. QK. RIH w{ 2.50" Hydrostatic bailer. Made 1 Hydrostatic Bailerrun to 6591' KB.depth: Recovered app 1 quart of sand. RD Hydrostatic:Bailer. 13:15 - 14:00 0.75 RUNPU SLIK WRLN Test lubricator to 2500 psig. OK. RIH w{3" GU Coupled on to WRP Pulling Tooi tag @ 8591' KB depth. Worked. overshot to Slide Equalizing Sleave and Latched on to WRP Retrievable Bridge Plug. Tried to Release RBP. POOH w/ GlJ', WRP Pulling tool overshot... Did Not Equil'¢e, Unset or Retrieve.. WRP Retrievable Bridge Plug. Sand around Fishing Neck of WRP Retrieveable Bride Piug. 14:00 - 16:00 2.00 RUNPU. SLIK WRLN RU Hydrostatic Bailer with Extension on Bottom of Bailer to allow Bailer to Swallow Fishing Neck to get all sand from above sliding sleave and not allow check valve assembly to be held open by fishing neck oh WRR Retrievable Bridge Plug. Wait on Delivery of parts for Bailer BHA.Tast lubricator to 2500 psig. OK, RIH w/ 2:50" Hydrostatic bailer, Made 1 Hydrostatic Bailer run to 6591' KB depth. Recovered app 1 quart of sand. RD Hydrostatic Bailer.. Bailing Extension 51id Equilizing Sieave on WRP Retrievable Bridge Plug. Fluid level was @ 4000' from surface. Pulling out of hole found fluid level @ 350D' from surface. 16:00- 18:30 2.50 RUNPU SLIK WRLN RU WRP RBP pulling assembly. Test lubricator to 2500 psig. OK: R1H w/3" GU Coupled on to WRP Pulling Toot tag @ 6591' KS depth.. Found Fluid Level 1500' Higher Fluid Level now @ 2500' from Surface. Pressure Rose from 30 psi to 480 psi. Worked overshot,. Finish Sliding Equalizing Sieave and latched on to WRP Retrievable Bridge Plug:. Wait on Pressure to equilize, Jar upon WRP RBP to Release RSP. GU .Released when started to Jar down on RBP because fluid entry-from below RBP caused releasing motion to tool. POOH w/ GU Pulling tool. Left WRP Pulling, tool overshot Latched on to WRP Retrievable Bridge Plug. Could not Puil WRP RBP because Rubber on WRP RBP needs to relax overnight. Well Needs to finish equilizing and Need to beef up BHA with 2-tl8" Stem weight bars and excellerator, RD Hydrostatic Bailer. RD Lubricator. Close all Valves on Well Head. Install Night Cap P~intetit. 11F27l2~g7 Marathon Oil Company Page 8 of 1z Operations Summary Report Legal Well .Name.: BEAVER CREEK 9 Gomman Wel! Name: BEAVER CREEK 9 Spud Date: 7{28/1994 Event Name: MAINTENANCE/REPAIR Start: 6/23/2007 End: Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date From: - 7o Hours Code ~ de Phase Description of Operations 8/10/2007 16`.00 - 18.30 2.50 RUNPU SL1K WRLN on Weli, 18{30 - 19:00 0.50 SECUR WELL WRLN Secured equipment and well. Signed out. SDFN. 8/19/2007 08:00 - 08:15 0:25 SAFETY MTG_ WRLN Signed in @BC control room. Held JSA and obtained a safe work permit: 08:15 - 09:15 1.00 RURD_ SLIK WRLN Rig up slick line. Gut Off Slick L1ne and Rehead. Pick up and Install Lubricator and Bailer.Test lubricator to 2500 psig. OK 09:15 - 09:45 0.50 RUNPU SLIK WRLN RIH w! 3" G5 Pulling tool with 2-1/8" Stem, Jars & sissor jars and tag @ 6591' KB depth. Jarred down on GS to Latch into WRP Retrievable Bridge Piug Pulling tool. Pulled up 1600# to Release RBP. Startto POOH w/ GU, WRP Pulling tool overshot and WRP Retreveable Bridge Plug. GS Tool came uNatched while pulling out of hole. Lost WRP Pulling tool and WRP RBP while pulling out. 09:45 - 10:30 0.75 RUNPU SLIK WRLN Changed GS Pulling tool to GU Pulling tool. Test lubricator to 2540 psig. OK. RIH w/3" GU Pulling tool on Sticklne tag @ 7680' KB depth. Latched an to WRP Pulling tool and WRP Retrievable Bridge Plug. WRP Retrievable Bridge Plur~. RU LubnCator: close alp varves on vveFi Head. Install Night Cap on Well. 10:30 - 1.2:00 1.50 RURD! SLIK WRLN RDMO Pollard Slickiine Unit, Crane and Equipment. Clean and Inspect: Location. Tum well back to production operations. Sign out at BC Office and turn in paper work and close permit. 9/6/2007 09:00 - 10:00 1.00 SAFETY MTG_ CMPFLW Signed in @ BC control room. Held JSA and obtained a safe work permit. 10:00 - 1:2x}0 2.00 RURD_ COIL CMPFLW Lay-out spin liners: Spot coil tubing unit and N2 pumper fo we[I head. Lay 1-1/2" hard line from N2 unit to tubing reel manifold. Lay 2" hard lines from reef man'rfold to well head. 12:00 - 13:30 1.50 RURD_ COIL CMPFLW RU flow cross to welt head.. Tie in 2" hard lines from flow crass to choke manifold... Hookup vac truck to pump unit. 13:30 - 14:30 1.00 KURD . COIL CMPFLW PU BOP's. Install on well head.: 14:30 - 15:30 1.00 TEST_ BOPE CMPFLW Fun lion testa ' . Blindlshears and Pipe rams/slips function tested OK. Tested accumulator: Pressure test BQP blind/shear rams 250 psi/4500 psi. Pressure test pipelslps rams250 psV 4500 psi.Tesi choke and kit/ fines to 4500 psi. Test held pressure. Jim Regg with AOGCC waived inspector for thfs test. 15;30 - 17:30 2,00 SECUR WELL CMPFLW Install nightcap. Close swab and master valves(15 turns). Secure. wet/ for the night Tum In permit and sign out at office. 9/7/2007 08:00 - 09:00 1.00 SAFETY MTG_ CMPFLW Signed in @ BC control room. Held JSA artd obtained a hot work permit. Discuss job scope. 09:00 - 09:30 0.50 RURD_ COIL CMPFLW PU injector. Install on WH. Establish circulation across flow cross. Test Bowes to 1000 psi: Test good, Hold pressure and open WH. 1682 psi on Wti. 73 bbls KCL to supply tank: 3" in returns tank (17 bbls) 5.7885 bbisrrtch 09:30- 10:20 0.83 RURD_ COIL CMPFLW Blow down WH to gas buster. Start RiH. 10:20 - 10:52 0,53 RUNPU COIL CMPFLW RIH. Bring on N2 @ 150 scf/mm. 1.0:52 -10:58 0.10 RUNPU COiL CMPFLW RIH @ 80 fpm, 2600',. WHP 26 psi., 88 psi Pump P, 150 scf/min N2 10:58.- 11:20 0.37 RUNPU COIL CMPFLW :3000' Puli test 8K, 11:20:• 11:40 0:33 RUNPU.. COIL CMPFLW RIH to 4500`. Increase N2 rate to 500 seflmin. 11:40 - 11:44 0.07 RUNPU COIL CMPFLW 4900', WHP 114 psi, 430 psi Pump pressure 11:44 -12;25 0,68 RUNPUL COIL CMPFLW Hold. @ 5000' for returns to surface, 125 psi WHP, 444 psi Pump pressure 12:25 - 12:45 0.33 RUNPUL COIL CMPFLW No returns to surface--RIH.: Open choke up 66 psi WHP, 495 psi pump P. 12:45.- 13:25 0.67 RUNPU COIL CMPFLW 5600', RIH 40 fpm WHP 37 psi, 484 psi Pump P rnrneaa ~ utnwvr a.ar:v+ nm. • • Marathon Oil Company page ~ of 12 Operations Summary Report Legal Welt Name: BEAVER CREEK 9 .Common WeflName: BEAVER GREEK 9 Spud Qate: 7/28!1994 !.Event Name: MAWTENANCE/REPAIR Start: 6f23/2007 End: Contractor Name; Rig Release: Group: !;Rig Name: Rig Number: Date From:...- To Hours Code Cie Phase Description of Qperatians , 9/7/2007 13:25 - 13:35 O.i7 RUNPU ' COIL. CMPFLW 7000', RIH 4D fpm, 7 psi 1NHP, 726 psi Pump P 13:35 - 13:42 0.12 RUNPU COIL CMPFLW 7400', 26 psi WHP, 810 psi Pump P, Returns to surface: gray to black and dirty. 13:42- 1.3:49 0.12. RUNPUL COIL .CMPFLW 7600' Pull. test 20.gK, 13:43.- 14:00 0.18 RUNPUL COIL .CMPFLW 7700' Setting weight down,. acts like sand. Sticky. gal/min returns. 81 psi WHP, 890 psi pump P 14:00- 14;02 0.03 RUNPU COIL CMPFLW 7900', 88 psi WHP, 909 psi Pump P. 14:02 = 14:15. 0.22 RUNPU COIL CMPFLW $000' 84 psi WHP, 928 psi Pump. P 14:15 - 14:50. 0.58 RUNPU COIL CMPFLW Hard tag @ 8108'. Cann't make hole. Call Ken discuss plan forward. Plan to jet. w/ kcl fluid ,FRW-14 friction. reducer, and Tomado Jet nozzle. Wash down to 8500'.: Circulate out w/fluid. Drop ball to open f/4" ports. Switch to N2 and jet dry.) 14:50- 15113 0.38 RUNPU COfL CMPFLW POOH. 15:13 - 16:05 0.87 RUNPU COIL CMPFLW 5200' Shut down N2. 16:05 -16':08 0.05 RURD_ COIL CMPFLW OOH. Close swab and mastervalves. Recover 11 bbls total fluid. 111:08 - 16:30 0.37 RURD_ WELL CMPFLW RD injector. Move injector to craddle. Install. nightcap. 1ti30 - 17:00 0.50 SECUR WELI. CMPFLW Secure well for the night. Turn in permit. Sign out. Leave loc. 918/2007 07:30 - 08:30 1..00. SAFETY MTG_ CMPFLW Signed in @ BC control room. Held JSA and obtained a hot work permit.: Discuss job. scope. 08;30 - 09:00 0.50 RURD_ COIL CMPFLW Intali Tomado Jetting nozzle on coil. Add FRW-14 to vac ruck of water to mix. Load into Rain for Rent tank. 243 bbis. 6% KCL water, Returns tank-5" 111 bbis) 5.7885 bbls/inch: :09:00 - 10:30 1.50 RURD COIL CMPFLW PU injector. Install on WH. Load Bail- circulating across flow cross to gas buster. 23.7 bbis. 10:30 - 11.:27 095 RURD COIL CMPFLW Pack leaking on fluid pump truck. Shut down. job to find replacement unit: Send three members of crew to KGF to retrieve pump truck. 11:21- 11:30 0,05 RURD COIL CMPFLW The decision was made to cancel this job inorder to prepare coil unit and pumper for Sterling frac job and clear the pad to prepare it for the rig. Recall pump crew. Cancel fight,tower from United Rental. 11:30 - 13:00 1.50 .RURD COIL CMPFLW Begin rig down. 13:00 -13:30 0.50 RURD COIL CMPFLW Cool down N2. Blow down coil wt N2. 13:30 - 14;45 1.25 RURD_ COIL CMPFLW Finish blowing down the coil. RD injecioc Lay down BOP's. RD 2" hard lines. 14:45 - 15:30. 0.75 RURD COIL CMPFLW RD flow cross.. Install tree cap. Secure well. 15:30 -17:30 2.00 RURD COIL CMPFLW Vac out hoses and filter unit. Clean and roll up equipment liners, MOe out equipment Turn in permit and sign out: Start haulung returns fluid to KGF. Haul KCL back o storage tank @KGF 34-31 pad(Rain for rent 10/17/2007` ~ 07:30 - 08:30 ~ 1.00 (SAFETY ~ MTG_ ~ CMPFLW ~ Signed im@ BC control room. Held JSA and obtained a hot work permit Discuss job scope. 08:30 - 10;30 2.00 RURD_ COIL CMPFLW Lay pit liner undertanks. ;Pat Grantcalled Mr. Jim Regg w/ AOGGG to give 24 hour notice of intent to test BOP's-10/1:8/2007 Mr. Regg. stated that "if we were not contacted, consider witness to test waived". 10:30 - 11:30 1.00 RURD„ COtt CMPFLW Spot tankage. install gas buster. lay out liner for BJ Cot equipment. 11:30 - 12:30 1.00 RURD_ COIL .CMPFLW Spot coil equipment. 12:30 - 17;30 5.00 RURD_ COIL CMPFLW RU coil spread, Haul 6% KCL water. Pat Grant tailed Mr. Jim Regg w1 AOGCC to give 24 hour notice of intent to test BOP's-10/18/2007(13:0.0). Mr. Regg stated that "if we were not contacted, consider witness to test waived". 17:30 - 18:00 0.50 RURD COIL CMPFLW :Secure. location for the night: 1011.812007 07:30 - 08:30 1.00 SAFETY MTG_ CMPFLW Signed in @ BC control room. Held JSA and obtained a hot work.. permit. Discuss job scope:. 08:30 - 10:30 2.00 >RURO, COIL CMPFLW .Complete rigging up coil spread. rnnteu: ur~rraur ~:ot.:u ~. r.m • Marathon Oil Company Page ~o of ~2 Operations Summary Report Legal Well Name: BEAVER CREEK 9 Common Well Name: BEAVER CREEK 9 Spud Date: 7128!1994 Event Name: MAIN7ENANCElREPAIR Start: 6l23l20Q7 End::. Contractor Name: Rig Release:.. Group::: Rig Name: Rig Number: • Date' From - To Hours Code Code Phase Description of Operations ' 10/18!2007 10:30 - 11:30 1.00. RURD_ COIL GMPFLW Install inline filter on coil. Test surface lines to 5000 psi. 11:30 -12:30. 1.00 TEST BOPS GMPFLW Test Blind/shearrams-25p psi low/4500 psi high. Test Pipe rams/slips-250 psi Iow14500 psi high: Test accumulator, All. 12:30 - 13:30 13:30 -14:00 14:00 - 14:45 14:45 - 15:15 15:15 - 15:30 15:30 - 15;40 15:40 - 16:30 16:30 - 17:00 10/19/2007 07:30 - 08:30 - 09;00 - 09:45 1.00 I RURD_I COIL 0.50 RURDV COIL 0.75 RURD COIL 0.50 RURD_ COIL 0.25 TEST` EQIP 0,17 TEST EQIP 0.83. RURD_ COIL 0.50 1.00 SAFETY MTG_ 0.50 RURD.. COIL 0.75 TEST .EQIP GMPFLW PU injector assembly; Install grapple, Pull test grapple to 20K. GMPFLW Load coil w/ methanol water- 27,5 bbls. PTest coil to 4000 psi. GMPFLW PU lubricator and tool string-2.25" OD grapple, 2-118" Duaf flapper check valve, 2-1/8" Hydraulic disconnect, 2-118" Dual crc sub:, 2-1/8" motor, 2-3l4" 4•bladed milt: GMPFLW Take injectorto WH. Line up valves to circulate fhru motor. GMPFLW Test sheN to 1000 psi, Test. good. GMPFLW Function test motor assembly. Establish .5 bpm thru motor. Barely hear motor noise:. Increase rate to 1 bpm-verydefinite buu of motor. Motor funcflonng. Shut down circulation. GMPFLW Lay down tool string. Lay down lubricator. Secure well for the night. GMPFLW Tum in Permit. Sign out and leave location. CTBG Signed in @ BC control roam. Held JSA and obtained a hotwork permit. Discuss job scope. CTBG Warm up equipment, prepare to p!u injector. CTBG Pickup injector, go to well:. PT lubricator and displace methanol from coil. CTBG MN 2:125" milling BHA with 2.75"4 blade junk mill (tool diagram in well folder). CTBG Go to well with injector, PT lubricator to 3500p5i. CTBG Open well, 81eed whp to return tank whp=1,450ps !RIH CTBG Wt. check @ 3,900'=10,000#. WHP=714psi, start pumping @ .3 bpm CTBG Wt. check @ 8,000'=20,000#, RIW=10,000#' CTBG RIH for tag, .3 bpm /tag at 8,115'. PUH to 8,090', increase rate to 1 bpm 218psj on tAil, CTBG Start mining @ 8,121' @ 1.25 bpm @ 1,100ps'.on coil.. Experience 2 stalls,.. get a pattern going and proceed milling @ 5 fpm ROP - 10:15 { 0.50 { PULD_ {BHA 10:15 - 1`!);30 10:30- 1.1:50 11:50 -11:55 11:55 - 12:40 12:40 - 12:49 0.25 TEST_ EQIP 1.33 RUNPU COIL 0,08 RUNPU Ct31L 0.75 RUNPU COIL 0.15 RUNPU COIL 12;49 - 1.4:14 14:14- 14:45 1.42;{ MILL^ ~ JUNK MILL_ JUNK I CTBG: PUH to 8,100' @ 30 fpm @ !bpm @ 1,000psi back reaimming. RBIH @ same to 8,400'.. 14:45 - 15:40 0.92 MILL JUNK CTBG. Continue milling @ 5 fpm @.1.2 bpm (x31100 Rsi to 8,795'... 15:40 - 1:6:30 0.83 CIRC_ CFLD CTBG Position coil reef and drop .5" ball Circulate 27 bbls. 16:30- 18:20 1.83 PUMP_ N2_ CTBG Ciro. sub opened, online with N2 @ 750 scfm. 18:20 -19:40 t.33 RUNPU COI! .CTBG 50 obis. returned., N2 @ surface, POOH 19:40 - 20:00 0.33 RURD_ COIL CTBG At surface, close swab, set down injector. 20:00.20:30 0.50 SECUR WELL CTBG Secure Weil and location fornight_ 10!20/2007 07:30 - 08:00 0.50 SAFETY MTG_ CTBG Signed in @ BC control room. Held JSA and obtained a hot work permit. Discuss jab scope, 08:00 - 10:30 2.50 RURD . COIL CTBG Start RD on BC-9 10:30. - 1.3:00 2.50 RURD_ COIL CTBG Change of plans, decision: made to het in BC-9 again, Rig backup. 1.3:00- 13:40 0.67 CIRC_ CFLD CTBG Displace methanol from coil with kcl water. 13:40 - 13:50 0.17 TEST, EQIP CTBG PT stack to 1500 psi 13:50 - 14:50 1.00. RUNPU COIL CTBG Open well, R1H. whp=350 psi 14:50 - 15:00 0.17 JET_ N2_ CTBG At 3,900' starting to get fluid returns4o surface;. Start jetting N2 500scfm, whp::=7 psi. RIH. to 5,000'.. 15:00 --15:50 0.83: JET_ N2, CTBG Park coil at 5,000', wait for N2 at surface. 15:50 - 16:00 0.1 T JET_ N2_ CTBG PUH to 4,000' jetting @ 1.,000 scfm. 16:00 -16:10 0.17 JET N2_ CTBG WHP= 90 psi, starting to get returns to surface. 16:10 -19:30 3.33 JET_ N2` CTBG Start grabbing 5011' bites until N2 back at surface at each stage ertl reaching 8,500'. Printed: • • Marathon Oil Company Page 11 of 12 Operations Summary Report ,,Legal Well Name: BEAVER CREEK 9 iCommon Well. Name: BEAVER CREEK 9 Spud bate:: 7/28/1994 Event Name: MAINTENANCEIREPAIR Start: 6/23/2007 End: Contractor Name: Rig Releaser Group: Rig Name: Rig Number: Date From - Tp Mourn Code Code Phase Qesctptlon of Operations 10120!2007 19:30 - 20:20 0.83 RUNPU COIL CTBG N2 at surface from. 8,50D'. 83 bbls: +/- of water back ai surface. POOH. 20:20 - 20:45 0.42 RURD_ COIL CTBG At surtace, stand back injector. 20:45 - 21::00 0.25 SECUR' WELL CTBG Secure well and location for night. Turn in permit.: 10/22/2007 07:00 -.08:30 1.50 SAFETY MTG CMPFLW Held PJSA and obtained work permit. Discuss job scope. 08:30 - 10:30 2.00 RURD_ COIL CMPFLW PU injector, BHA consist of BOT 2 18" MHA, 2 918"nozzle. Go to well head and PT shell to 1500 psig. Good test. Open weU, WHP= 360. psig.. RIH with coif. 10:30.-.10:50 D.33 WORK COIL CMPFLW Coil at 4160' CTM, Started N2 at 500 SCFM, N2 pump problem, trouble wKh N2 temperature. 10:50 - 12:30 1,67 WORK COtL CMPFLW Found joy coupling parted, N2 cooled down the hydraulic fluid. Fixed pump coupling wait on pumping unit to heat back up. 12:30 -12:45. 0.25 RURD_ COIL CMPFLW Start pumping N2, RIH with coil pumping at 550 SCFM. Coil at 5200', PU coil till retums to flow back tank. WHP up to 160 psig, good 12:45 -13:00 0.25. PUMP N2_ CMPFLW RIH with coil, coil at 5420' CTM, N2 rate at 75D SCFM., PIP= 1055 psig, WHP=O psig, 13:00 - 13:20 0.33 PUMP_ N2_ CMPFLW Good returns to flow back tank; WHP=200 psig. PIP=1154 psig. Vac truck pulled load of water, QO BBLS}. Total water from well today 75 BBLS, 13:20 - 14:50 1..50 PUMP_ N2~ CMPFLW Coil below perforations Q 8500' CTM, WHP= 150 psig: PIP = 1425 psig. 750 SCFM N2. 14:50 - 15:40 083 PUMP_ N2_ CMPFLW PU coil to 8300' C7M, PIP= 1250 psig,WHP= 29D psig. 182, 000 SCF' total N2 pumped. 15:40 - 16:00. 0.33 PUMP_ N2_ CMPFLW RIH with coil pumping N2 accross perfortions„lost N2 pump coupling. SD pumping N2 to fix. Back on line with N2. WHP= 77 psig. PUH with coil to 7+100' CTM. PIP= 660 psig 16:00 - 18:15 0.25 PUMP_ N2_ CMPFLW N2 pump coupling faced again, No retums to flow back tank. Start N2 500 SCFM. 16:15°- 17::00 0.75 PUMP ^ N2_ CMPFLW N2 pump coupling broke. No way to pump N2. No returns to flow back tank. WHP= 0 psig. POOH with coil. Total fluid recovered from well is 145 BBLS today, flow rate above 500 BPD rate on fluid with no response from well. 17:00 -18:00 1:00 RURD_ COIL CMPFLW OOH with coil, closed swab valve. Blew down lines. Break Bowen connection take injector to ground. 18:00- 18:30 0.50 RURD_ COIL CMPFLW RD coil unit,. move to BC 11. 18:30 -19:00 0.50 RURD_ COIL CMPFLW Turn. in Permit. Sign oat and leave,location: · . ~V1ÆVŒ (ID~ 1Æ~1Æ£)~i% / .u.ø.SIiA. OIL AND GAS / CONSERVATION COMMISSION / SARAH PALIN, GOVERNOR 333 W. 7th AVENUE. SUITE 100 ANCHORAGE. ALASKA 99501·3539 PHONE (907) 279-1433 FAX (907) 276-7542 Dennis Donovan Production Engineer Marathon Oil Company PO Box 1949 Kenai, AK 99611-1949 Re: Beaver Creek Field, Beluga Gas Pool, Beaver Creek 9L Sundry Number: 307-197 sGANNE.D JUN 2 0 2007 Dear Mr. Donovan: 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, DATED this J!/day of June, 2007 Encl. ,q~ - l~~ ¡¡ I.." "" n - - 1. Type of Request: Abandon 0 Suspend 0 Operational shutdown 0 Perforate 0 ..w....wai~~~ '.... uu"... r Uther U Alter casing 0 Repair well 0 Plug Perforations [;] Stimulate 0 Time Extension nchorage Change approved program 0 Pull Tubing 0 Perforate New Pool 0 Re-enter Suspended Well 0 2. Operator Name: Marathon Oil Company 4. Current Well Class: 5. Permit to Drill Number: Development [2] Exploratory 0 192-122 , 3. Address: Stratigraphic 0 Service 0 6. API Number: PO Box 1949, Kenai Alaska, 99611-1949 50-133-20445-00-00 ~ 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: Spacing Exception Required? Yes 0 No [;] Beaver Creek 9L / 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): FED A028083 183' I Beaver Creek Field / Beluga Pool - 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 8,881' . 8,500' , 8,226' (FiJI) 7,845' 8,808' N/A Casing Length Size MD TVD Burst Collapse Structural 116' 13-3/8 " 116' 116' N/A N/A Conductor Surface 1,853' 9-5/8" 1,853' 1,725' 4,750' 6,870' Intermediate Production 5,950' 7" 5,950' 5,555' 7,020' 8,160' Liner 3,067' 3-1/2" 8,881' 8,500' 10,530' 10,160' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6,429' - 8,452' 6,058' - 8,071' 3-1/2" AB Mod Buttress L-80 9.2 ppf 5,814' Packers and SSSV Type: Packers and SSSV MD (ft): 5,814' Baker H packer 13. Attachments: Description Summary of Proposal 0 14. Well Class after proposed work: Detailed Operations Program [;] BOP Sketch 0 Exploratory 0 Development [;] Service 0 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: 6/13/2007 Oil 0 Gas [;] Plugged 0 Abandoned 0 17. Verbal Approval: Date: WAG 0 GINJ 0 WINJ 0 WDSPL 0 Commission Representative: 18. I horeby "''',;' 'he '''ego'og ;, IT"e aod "'"00' '0 the b,," o¡ my ,,,wi edge. C",tact Kevin Skiba (907) 283-1371 Printed Name Dennis Donolan Title Production Engineer Signature J >/"I/}/ ¡j \ -77/ Phone (907) 283-1333 Date 6/11/2007 d'" V jI' ¥ ~\. ~, COMMISSION USE ONLY ~ :?O'l*' 101 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity 0 BOP Test ~ Mechanical Integrity Test 0 Location Clearance 0 Other: 45 ()O Ç" -:.', \SO ~~ <:. \- ~~ \> \~~~~ . ~SSIONER R8DMS 8FL JUN 2 0 2DD7 / Subsequent Form Required: 4C) W ~ APPROVED BY 6-/?,f) -:f Approved by: -/1 THE COMMISSION Date: ~ ~~ Form 10-403 Revised 06/2006 (ì "" J , Submit in Duplicate Æ" C IÒ1 I ~~ .. E ~ STATE OF ALASKÄ f' ¿-/< RECEIV '^ A& OIL AND GAS CONSERVATION COM SSION Ý ~ APPLICATION FOR SUNDRY APPROVALSJhh\ JUN 132007 ......~ ~~~~ ~ NAL . (. M" ') Marathon MARATHON Oil Company . Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1326 Fax 907/283-1350 June 11, 2007 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W ¡th Ave Anchorage, Alaska 99501 RECE n LJ 1:: {j JUN L ;) .~¡aska Oil & Gas Gúns. Anchorage Reference: Sundry Notice Field: Beaver Creek Field Well: BC-9L Dear Mr. Maunder: We plan to cement the Upper Beluga interval that was approved previously for a patch. We were not able to nitrogen lift the well through the temporary patch and were unable to get down with a permanent patch so cement is necessary so we can restore production from the Lower Beluga. I am including a proposed wellbore diagram and a procedure for your files. If you require further information, I can be reached at (907) 283-1333 or bye-mail at ddonovan@marathonoil.com. Dennis Donovan Production Engineer Enclosures: 10-403 Sundry Notice Operations Procedure Current Wellbore Diagram Proposed Wellbore Diagram cc: AOGCC Houston Well File Kenai Well File DMD KJS . . Tuesday May 29, 2007 Marathon Oil Corporation Alaska Region Beaver Creek #9L Objective: Coil tubing squeeze upper most Beluga perforations at 6429' -6459' to shut off water production and return well to production. Procedure: 1. MIRV Liner, a Rain-for-Rent tank with fresh water, and flow-back choke/tank skid, and man-lift. 2. MIRV Expro. Hold PJSM and review conditions of Safe Work Permit. Install crossover connection from Expro BOP to 4-3/4" Otis standard tree cap connection. Install lubricator and pressure test with water to 25Opsi/2500 psi. MV Weatherford WRP Bridge plug. RIH and set plug @ 6600' with E-Hne.. 3. MIRV BJ CoilTech and 40T crane. Hold PJSM and review conditions of Safe Work Permit. Install crossover connection from BJ BOP's to 4-3/4" Otis standard tree cap connection. PTest BOP's 250 psi/4500 psi. Install lubricator and PTest with KCL water to 3500 psi. Install dimple-on connection and pull test to 20 - 25K. Install cementing nozzle. 4. RIH and set nozzle @ 6590' Spot 60' sand plug on top of bridge plug ( 3- 100 lb. sacks). POOH. Shut well in for the night to allow sand to fall. . . 5. MIRV BJ cement van. Prepare to squeeze perforations at 6429'-6459'. PTest flow·back iron to 250 psi/3500 psi. 6. RIH with cementing nozzle on coB tubing. Load hole with fresh water. Tag sand plug @ 6540', PU CT nozzle to 6400'. Establish circulation to surface. Perfonn injection tests recording pump rates, pump pressures, and wellhead pressures at 1,4, lh, %, 1, 1-1/4, 1·1/2, and 1-3/4 bpm. 7. Establish injection rate into perforations using the same rates, and pressure as in step 6. Do not exceed 2500 psi surface prf),ßsure. RIH to 6525'. 8. Batch mix xxx sacks (7 bbls) of cement as listed below. Perfonn BJ standard QAJQC tests, Tentative cement blend is detailed below. Note slight changes in additive concentrations may result due to lab tests. BHST: 123 F @6600' BHCT: ????F Class G cement with the following additives, 0.7% FL-63 0.3% CD-32 0.5% R-3 0.3% EC-l 0.1% ASA 301 2 g/hs Fp·6L Slurry weight: Slurry yield: Water requirement: 15.8 ppg 1.158 cu. fUsk. 5.0 gals/sk Pump Time Fluid loss Free water 7:37 Hrs:min. 40 -50cc/30 min. o 9. Pump 5 bbls of 15.8 ppg cement slurry into the coil tubing. Displace cement to the CT nozzle with xx bbls fresh water. (Pig CT if necessary in order to more accurately detennine the CT volume.) Concurrent with cement at the nozzle of the coil, begin measuring well returns to the 50 bbl returns tank in order to more closely know the position of the cement slurry in the wellbore. ,~:. 10. Position CT nozzle at 6525'. Pump 2 bbl out the nozzle, begin PUH at 57 fþm while continuing to displace cement out nozzle at Y2 bpm. Laying in a 575' cement plug. Hold at 6180' until all cement has exited the nozzle. . . 11. Pull up hole to 5665'. Close back side and apply squeeze pressure. Step pressure according to squeeze schedule below until 2500 psi. is obtained: 500 psi hold 15 min. 1000 psi hold 10 min. 1500 psi. hold 5 min. 2000 psi. hold 5 min, 2500 psi. hold 40 min. 19. Once squeeze pressure is reached, hold for 40 min. 20. After 40 min., release surface pressure and circulate 6 bbls. of Biozan to nozzle. Jet Biozan 1 to 1 from 5965' to 6540'. (1 bpm. and 115 [pm.). 21. POOH to 5000'. 22. RIH at 30 fpm reversing out a 1 bpm. Maximum pressure 2200 psi. Continue reversing to 6520'. ( 20' into sand plug) 23. POH. WOC 24 hrs. 24. Ptest to 1000 psi. 25. Jet down and pull IBP. Or re-squeeze as necessary. 1164' FNL & 1547' FWL API # 50-133-20445 1/4" .049 wall Chemical injection line open to annulus at 1000' 3.5" Buttress AB Mod Tubing TCP Assebly @ 5638' Includes two AB- Mod Buttress by ST-L crossovers, Y_ block and 8' of 2" scallop guns Max OD = 5.887" 133/8" 61 ppf K-55 n/a o 116 g 5/8" L-80 47 ppf BTC Cemented with 700 sacks o 1853 MD Sterling B-4 Perforations 5629-5637 MD -- (5248-5256 TVD) ¡Chemical Injection Mandrel Production Seal Unit Model H liner hanger packer Beluga 7420'-60',7534'-74',7640'-60',7705'-55',7762'_7842', 7852'-82', 7893'-7933', 7980'-8030', 8036'-54', 8072'-98', 8167'-87'.8241'-46',8254'-61',8276'-92',8399'_8409', 8432'-52' MD (7039'-79',7153'-93',7259'-79',7324'-74',7381'_7461', 7471'-7501', 7512'-52', 7599'-7649',7655'-73', 7691'-7717', 7786'-7806',7860'-65',7873'-80',7895'-7911',8018'_28', 8051'-71' TVD) Model N BP at 8808' MD 2.813 CMU Sliding Sleeve 7" N-80 0 29 ppf BTC 5950 MD Cmt with 565 sks in 2 stages, DV at 4487 MD Beluga 6429-6459 MD (30') 1/13/2004 Wet Upper Beluga Liner Assembly 3.5" L-80 9.2 ppf Butt Cemented with 500 sacks 5814 MD 8881 MD Well Name & Number: Beaver Creek 9 T Lease T Beaver Creek County or Parish: KPB I State/Prov. I AK Country: I USA Angle/Perfs 1 Angle @KOP and Depth I 0 KOP TVD I 0 Date Completed: I RKB: I Prepared By: 0 I Last Revision Date: 06/04/061 MAM 1164' FNL & 1547' FWL API # 50-133-20445 1/4" .049 wall Chemical injection iine open to annulus at 1000' 3.5" Buttress AB Mod Tubing TCP Assebly @ 5638' Includes two AB- Mod Buttress by ST-L crossovers, Y_ block and 8' of 2" scallop guns Max OD " 5.887" 133/8" 61 ppf K-55 n/a o 116 9 5/8" L-80 47 ppf BTC Cemented with 700 sacks o 1853 MD Sterling B-4 Perforations 5629-5637 MD - (5248-5256 TVD) Chemicallnjection Mandrel Production Seal Unit Model H liner hanger packer Beluga 7420'-60',7534'-74',7640'-60',7705'_55',7762'_7842', 7852'-82', 7893'-7933', 7980'-8030', 8036'-54', 8072'-98', 8167'-87',8241'-46',8254'-61',8276'_92',8399'_8409', 8432'-52' MD (7039'-79',7153'-93',7259'-79',7324'-74',7381'_7461', 7471'-7501',7512'-52',7599'-7649',7655'_73',7691'_7717', 7786'-7806', 7860'-65', 7873'-80', 7895'-7911', 8018'-28', 8051'-71' TVD) Model N BP at 8808' MD 2.813 CMU Sliding Sieeve 7" N-80 0 29 ppf BTC 5950 MD Cmt with 565 sks in 2 stages, DV at 4487 MD Beluga 6429-6459 MD (30') 1/13/2004 Proposed Squeezed Wet Upper Beluga Liner Assembly 3.5" L-80 9.2 ppf Butt Cemented with 500 sacks 5814 MD 8881 MD Well Name & Number: Beaver Creek 9 I Lease I Beaver Creek County or Parish: KPB I State/Prov. I AK Country: I USA Angle/Perfs I Angle @KOP and Depth I 0 KOP TVD I 0 Date Completed: I RK8: / Prepared By: 0 I Last Revision Date: 06/04/06/ MAM . (. M,. ') Marathon MARATHON Oil Company . Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1326 Fax 907/283-1350 June 8, 2007 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W yth Ave Anchorage, Alaska 99501 RECEI\/ED Reference: 10-404 Sundry Report Field: Beaver Creek Field Well: BC-9L JUN .1 1 2007 Alaska Ojl & Gas r .. '. ""ems, CDmmisslOn Anchorage SCANNED JUN 142007 Dear Mr. Maunder: f ~:¡.,- \:}.'r Attached is the 10-404 Sundry Report, Operations Summary, and wel.lbore diagram for ..,,- BC-9L. We were unable to flow the well with the restricted 10 temporary patch and unable to reach setting depth with the larger 10 permanent patch. We are submitting a new 10-403 sundry to cement squeeze the wet upper beluga zone to allow us to N2 lift the well from bottom to reestablish production from the lower beluga. If you have any questions or need further information please call me at (907) 398-9954. Sincerely, ~~0 Senior Production Engineer Enclosures: 10-404 Sundry Report Well Schematic Operations Summary cc: Houston Well File Kenai Well File MAM KJS · STATE OF ALASKA _ ALA" OIL AND GAS CONSERVATION COM~ION REPORT OF SUNDRY WELL OPERATIONS ~ ~ -/..:?--ð~ 1 . Operations Abandon Performed: Alter Casing 0 Change Approved Program 0 2. Operator Name: Repair Well Pull Tubing 0 Operat. Shutdown 0 Plug Perforations Perforate New Pool 0 Perforate 0 4. Current Well Class: Development 0, Stratigraphic 0 Stimulate Other.¡ None Waiver 0 Time Extension 0 Re-enter Suspended Well 0 5. Permit to Drill Number: /92-1220 6 ../,;¡,'/ Marathon Oil Company Exploratory 0 ServiceO 6. API Number: 50-133-20445 QPOO' 3. Address: P. O. Box 196168, Anchorage, AI< 99519· 6168 7. KB Elevation (ft): 183' KB from MSL / 9. Well Name and Number: Beaver Creek 9L 8. Property Designation: 10. Field/Pool(s): fV' V> Beaver Creek Field, Beluga Poo~t - FED A028083 11. Present Well Condition Summary: 8808 N/A ¿ Total Depth measured 8881 / feet true vertical 8500 / feet Effective Depth measured 8226 (Fill) feet true vertical 7845 feet Casing Length Size MD Structural 116 13 3/8" 116 Conductor Surface 1,853 95/8" 1853 Intermediate Production 5,950 7" 5950 Liner 3,067 3 1/2" 8881 Perforation depth: Measured depth: 6429-8452 Plugs (measured) Junk (measured) ::Þ ::3 C") ::r o C"') ;; g ~ ~ ...... I') = = --...J ...... .....) ~ m <: m a TVD Burst 116 N/A 1725 4750 5555 7020 8500 10530 C"') <::) :3 3 r:;;- åÐllapse :::I N/A 6870 8160 10160 True Vertical depth: 6058-8071 Tubing: (size, grade, and measured depth) 3 1/2", AB Mod. Butt L-80, 9.2 ppf 5814' Packers and SSSV (type and measured depth) Baker H packer 5814' 12. Stimulation or cement squeeze summary: Intervals treated (measured): RBDMS 8Ft JUN ] 3 2007 Treatment descriptions including volumes used and final pressure: Oil-Bbl Representative Daily Average Production or Injection Data Gas-Met Water-Bbl Casing Pressure o o Tubing Pressure 1000 1000 13. Prior to well operation: 0 Subsequent to operation: 0 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations o 0 o 0 15. Well Class after proposed work: Exploratory 0 Development 0 16. Well Status after proposed work: Oil 0 Gas 0 WAG 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. NA X Service 0 GINJ 0 WINJ 0 WDSPL 0 Sundry Number or N/A if C.O. Exempt: 305-378 Contact Michael A. Mullin Signatu Title Senior Production Engineer Printed Name Michael A. Mullin Phone (907) 398-9954 Date 6/8/2007 Form 10-404 Revised 04/2f) R \ G \ N A L k~ I ~ì- Submit Original Only I Annular Well bore Diagram 1164' FNl & 1547' FWl API # 50-133-20445 1/4" .049 wall Chemical injection line open to annulus at 1000' 3.5" Buttress AB Mod Tubing TCP Assebly @ 5638' Includes two AB- Mod Buttress by ST -l crossovers, Y- block and 8' of 2" scallop guns Max OD = 5.887" 133/8" 61 ppf K-55 n/a o 116 9 5/8" l-80 47 ppf BTC Cemented with 700 sacks o 1853 MD Sterling B-4 Perforations 5629-5637 MD - (5248-5256 TVD) IChemicallnjection Mandrel Production Seal Unit Model H liner hanger packer Beluga 7420'-60',7534'-74',7640'-60',7705'-55',7762'-7842', 7852'-82', 7893'-7933', 7980'-8030', 8036'-54', 8072'-98', 8167'-87',8241 '-46',8254'-61',8276'-92',8399'-8409', 8432'-52' MD (7039'-79',7153'-93',7259'-79',7324'-74',7381'.7461', 7471'-7501',7512'-52', 7599'-7649',7655'-73', 7691'-7717', 7786'-7806',7860'-65',7873'-80', 7895'-7911', 8018'-28', 8051'-71' TVD) Model N BP at 8808' MD 2.813 CMU Sliding Sleeve 7" N-80 0 29 ppf BTC 5950 MD Cmt with 565 sks in 2 stages, DV at 4487 MD Beluga 6429-6459 MD (30') 1/13/2004 Wet Upper Beluga liner Assembly 3.5" L-80 9.2 ppf Butt Cemented with 500 sacks 5814 MD 8881 MD Well Name & Number: Beaver Creek 9 I lease I Beaver Creek County or Parish: KPB I State/Provo I AK Country: I USA Angle/Perfs I Angle @KOP and Depth I 0 KOP TVD I 0 Date Completed: I RKB: I Prepared By: 0 I Last Revision Date: 06/04/061 MAM Legal Well Name: Common Well Name: Event Name: DATE 12/14/2005 12/24/2005 . . Page 1 of 1 BEAVER CREEK 9 BEAVER CREEK 9 MAINTENANCE/REPAIR Start Date: 12/13/2005 End Date: TMD 24 HOUR SUMMARY (ft) Drifted to 2.75" for Slickline patch and correlated TD tag at 8221'. (ft) Marathon Oil Company Final Well I Event Sum.mary Set patch from 6422' - 6466', patching off perfs from 6429' - 6459'. Printed: 6/8/2007 8:50:04 AM . . . , Marathon Oil Company Final Weill Event Summary Page 1 of 1 Legal Well Name: BEAVER CREEK 9 Common Well Name: BEAVER CREEK 9 Event Name: MAINTENANCE/REPAIR DATE TMD 8/8/2006 (ft) 8/9/2006 (ft) 8/10/2006 (ft) 8/11/2006 (ft) 8/12/2006 (ft) 8/15/2006 (ft) 8/16/2006 (ft) Start Date: 8/8/2006 24 HOUR SUMMARY End Date: 8/9/2006 MIRU SJ coiltec on well and spot equipment to N2 lift well. Continue wirh jetting operation down to top of liner at 6429' Continue N2 unloading or RD Bj coil. Continue wirh jetting operation down to top of liner at 6429' Pulled slickline retrievable patch from upper Beluga. Unable to get past SS with 2.80" OD X 42' patch. Unable to pass 6250' with 2.70" X 42' patch. RIH 2.74" GC. Tag TD at 8210'. RIH 2.79" GC. Stop at 6500' and POH. RIH 35' , 2.70" specail clearance patch. Unable to pass 6260' (same as friday. Run 2.70" X 10' patch as dummy run. Unable to pass 6263'. POH RD Expro. RDCT Printed: 6/8/2007 8:50:07 AM ~lT~lTŒ e (ffiu rÞu· .¡lE\ n fA\ till ,¡ uJ Lb/JlJ e In~7/r¡\ . ( : if" " U. ¡ U \1..rl~ FRANK H. MURKOWSKI, GOVERNOR AI¡A.SIiA OIL AND GAS CONSERVATION COMMISSION Michael Mullin Production Engineer Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 333 W. ]T" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 \~J: ly1/ Re: Beaver Creek 9 Sundry Number: 305-378 ~CA.N~~IE[: f < e¡, t,' t· Dear Mr. Mullin: 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. Please provide at least twenty-four (24) hours 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 this13 day of December, 2005 Enc!. e 'M ~ Marathon MARATHON Oil Company e Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 7/1/2004 RECEIVED DEC 1 2 Z005 Ataska Oil & Gas Cons. CommissiQn Anchorage Winton Aubert State of Alaska Alaska Oil & Gas Conservation Commission 333 West yth Ave, Suite 100 Anchorage, AK 99501 Reference: Sundry Notice Field: Beaver Creek Unit Well: Beaver Creek 9L Dear Mr. Aubert, Enclosed please find the Application for Sundry Approvals along with an operations program and a wellbore diagram. The Sundry Application is for isolating the Upper Beluga sand with a casing patch. We are running a removable patch but the intention of the job is to abandon the Upper Beluga perfs so I feel a Sundry is appropriate. In the case that the patch does not eliminate the water we have the ability to remove it. If you require further information, I can be reached at 907-283-1337 or bye-mail at MMullin@MarathonOil.com. Sincerely, C;?#~~ Michael Mullin Production Engineer Enclosures: Sundry Notice Operations Plan Wellbore Diagram ./ tttr 1.1..t1~ STATE OF ALASKA ALAe. OIL AND GAS CONSERVATION COM SION APPLICATION FOR SUNDRY AfPROVAL ~6Â:-E CI Z- 1 t..l2.Dd?" LJI: 1 2 2005 Alaska Oil & Gas Cons. Commission ~nchorage 20 MC 25.280 1)\ ~ 1<J/Jf.5' 1. Type of Request: Abandon U Suspend U Operational shutdown U Perforate U Waiver U Annular Dispos. U Alter casing 0 Repair well 0 Plug Perforations 0 Stimulate 0 Time Extension 0 Other 0 Change approved program 0 Pull Tubing 0 Perforate New Pool 0 Re-enter Suspended Well 0 2. Operator Name: 4. Current Well Class: / 5. Permit to Drill Number: MARATHON OIL COMPANY Development 0 Exploratory 0 92-122 r- 3. Address: Stratigraphic 0 Service 0 6. API Number: P. O. Box 196168, Anchorage, AK 99519-6168 50-133-20445 /' 7. KB Elevation (ft): 9. Well Name and Number: 183' KB from MSL Beaver Creek.9\: , \J.¥:I1r 8. Property Designation: 10. Field/Pools(s): FED A028083 Beaver Creek Field, Beluga 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): 8881 8500 8226 (Fill) 7845 8,808 N/A Casing Length Size MD TVD Burst Collapse Structural 116 13 3/8" 116 116 N/A N/A Conductor Surface 1853 95/8" 1853 / 1725 4750 6870 Intermediate Production 5950 7" 5950 ( 5555 7020 8160 Liner 3067 3 1/2" 8881 ".- 8500 10530 10160 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6429-8452 /~ 6058-8071 3 1/2", AB Mod. Butt L-80, 9.2 ppf 5814' Packers and SSSV Type: Packers and SSSV MD (ft): Baker H packer 5814' 12. Attachments: Description Summary of Proposal U 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Development 0 /S . 0 ervlce 14. Estimated Date for Dec~¡' 2005 15. Well Status after proposed wo~ Commencing Operations: Oil 0 Gas 0 Plugged 0 Abandoned 0 16. Verbal Approval: (/ Date: WAG 0 GINJ 0 WINJ 0 WDSPL 0 Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Michael Mullin "'/ Title Production Engineer , Signature ~¿"/'.,// Þ'r¿. 7L~ ¿./l...e.hone 907-283-1337 Date 12/9/2005 f / / COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~.- ("2:.,7 ~ Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: RBDMs 8FL DEC J 4 2DD5 Subsequent Form Required: 0 404-, m l¿., BY ORDER OF /",,/3 .,.()~ Appm.,d by [7 11~W COMMISSIONER THE COMMISSION Date: Form 1 0-403 R~12/2003 INSTRUCTIONS ON REVERSE Submit in Duplicate --""1-1 \I. . J e e 12/08/2005 Marathon Oil Company Alaska Region ABU BC 9L Beaver Creek Unit, Pad 3 API # 50-133-20485 History: Beaver Creek 9L was perforated in the Upper Beluga on January 13,2003 with an initial rate of 17 mmscfpd which depleted rapidly and appears to have watered out. It is thought the Lower Beluga sands are still gas bearing and the water is coming from the Upper Beluga. .---' Objective: Set a removable patch over Upper beluga perfs from 6429' - 6459' MD and flow /' test well. Procedure: 1. Move in E-line Company. a. Hold pre-job safety and operations meeting. RU E-line unit. b. MU tool string with 2.75" gauge ring and CCL to ensure 2.71" OD casing patch can pass through tubulars. c. MU lubricator and BOPE and pump in sub to tree. Test lubricator and BOPE to wellhead psi. d. RIH and tag PBTD, correlate to CBL, and POOH. Report e-line depth ofTD. .,/ 2. Move in Slickline Company. a. Hold pre-job safety and operations meeting. RU E-line unit. b. Perform wire twist test. MU dummy tool string with 2.75" gauge ring and anti- blowup tool with spangs, oil jars and stem to simulate 2.71" OD casing patch. c. MU lubricator and BOPE with pump in sub to tree. Test lubricator and BOPE against swab valve to wellhead psi. d. RIH and tag PBTD, adjust depth to E-line run, and POOH. e. MU first section of patch. RIH and tag TD. Adjust depth to E-line depth. f. POH to Patch depth. Position bottom of patch at 6464' and set bottom section of patch. MAM 12/0812005 e e 12/08/2005 g. Continue runs, stacking patch until top seal can be set at 6424' . h. RDMO slickline unit. 1. Attempt to unload well to tank. If well flows, turn to system. If well is unable to flow, continue with step 3. 3. MI CT Unit. a. RU gas buster on existing tank and rerig line from diffuser to gas buster. b. Hold pre-job safety and environmental awareness meeting. RU CT unit with Jetting nozzle and DFCV. MU lubricator to tree cap and pressure test to 200/ 4,500 psi against swab valve. c. RIH to 1000' and start N2 at minimum rate. Continue RIH at 60' Imino d. Stop CT at 5000' and unload water to tank through gas buster. e. Unload water until well starts to produce. SD N2. f. POH CT and observe well. g. RDMO CT unit. / Contacts: Production Eng Reservoir Eng Geologist Mickey Mullin John Ozcan Scott Szawalski Work Phone 283-1337 713-296-2388 713-296-3390 Cel 398-9954 MAM 12/08/2005 1164' FNL & 1547' FWL API # 50-133-20445 1/4" .049 wall Chemical Injection line open to annulus at 1000' 3.5" Buttress AB Mod Tubing TCP Assebly @ 5638' Includes two AB- Mod Buttress by ST-L crossovers, Y- block and 8' of 2" scallop guns Max 00 = 5.887" Production Seal Unit Model H liner hanger packer 13318" 61 ppf K-55 nla 9518" L-80 47 ppf BTC Cemented with 700 sacks o 1853 MO Sterling B-4Perforations 5629-5637 MO --,(5248-5256 TVD) Beluga 7420'-60',7534'-74',7640'-60',7705'·55'.7762'-7842', 7852'-82', 7893'-7933', 7980'-8030', 8036'-54', 8072'-98', 8167'-87', 8241 '-46', 8254'.61', 8276'-92', 8399'·8409', 8432'-52' M 0 (7039'-79',7153'-93',7259'-79',7324'-74',7381'-7461', 7471'-7501',7512'-52',7599'-7649',7655'-73',7691'-7717', 7786'-7806',7860'-65',7873'-80',7895'-7911',8018'-28', 8051'-71' TVD) Model N BP at 8808' MO 2.813 CMU Slidlnq Sleeve 7" N-80 0 29 ppf BTC 5950 MO Cmt with 565 sks in 2 stages, DV at 4487 MD Beluga 642g·645gMP (30') 1/13/2004 4Q' Casing Patch (6424-6464 MO) Liner Assembly 3.5" L·80 9.2 ppf Butt Cemented with 500 sacks 5814 MO 8881 MO o Last Revision Date: o 116 USA o ( / M Marathon \:ARATHON. Oil Company ( Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 7/1/2004 q d- - / d--- '7-- :.r"" k"'1. Winton Aubert State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Ave, Suite 1 00 Anchorage, AK 99501 I'l"~ ,.' \.'.. 04 J Jl. i:!~ 'Zo . Reference: Sundry Notice Field: Beaver Creek Unit Well: Beaver Creek 9L Dear Mr. Aubert, Enclosed please find the Application for Sundry Approvals along with an operations program and a well bore diagram. The Sundry Application is for running a PL T/Temp log to identify and isolate the Beluga sand with a casing patch. If you require further information, I can be reached at 907-283-1337 or bye-mail at DE Eynon@MarathonOil.com. Sincerely, ~~ Donald Eynon Operations Engineer Enclosures: Sundry Notice Operations Plan Well bore Diagram ORIGINAL 1. Type of Request: (" STATE OF ALASKA ( ALAv...Ä OIL AND GAS CONSERVATION COMrvll.,jSION APPLICATION FOR SUNDRY APPROVAL 'I' , 20 MC 25.280 ' : Operational shutdown U Perforate U WaiverU Annular Dispos. U Plug Perforations 0 Stimulate 0 Time Extension 0 Other 0 Perforate New Pool 0 Re-enter Suspended Well 0 4. Current Well Class: 5. Permit to Drill Number: ',r,""'- ,.,w'f;JI\- 7/1212.004- ìX'~I"J¡,1'! <I' '~~. ~:'~:J' ;:~ \~'¡ ijr :~..., ::.~.., ,~.~. ~\.'l7J¡~L' c,,'~ ~ 7004 Y 1 ~ Abandon U Alter casing 0 Change approved program 0 2. Operator Name: MARATHON OIL COMPANY Suspend U Repair well 0 Pull Tubing 0 3. Address: P. O. Box 196168, Anchorage, AK 99519-6168 7. KB Elevation (ft): 183' KB from MSL Development Stratigraphic 0 0 Service Exploratory 0 92-122 /' 0 6. API Number: 50-133-20445 ./ 8. Property Designation: FED A028083 11. Total Depth MD (ft): 8881 9. Well Name and Number: (' Beaver Creek~ -=, w6~ 10. Field/Pools(s): Beaver Creek Field, Beluga Pool Total Depth TVD (ft): 8500 PRESENT WELL CONDITION SUMMARY Effective Depth MD (ft): Effective Depth TVD (ft): 8226 (Fill) 7845 Plugs (measured): 8,808 Junk (measured): N/A Casing Length Size Structural 116 13 3/8" Conductor Surface 1853 95/8" Intermediate Production 5950 7" Liner 3067 3 1/2" Perforation Depth MD (ft); Perforation Depth TVD (ft): 6429-8452 6058-8071 Packers and SSSV Type: MD 116 TVD 116 Burst NIA Collapse NIA 1853 1725 4750 6870 5950 8881 5555 8500 Tubing Grade: 7020 8160 10530 10160 Tubing MD (ft): 5814' Tubing Size: Baker H packer 31/2", AB Mod. Butt L-80, 9.2 ppf Packers and SSSV MD (ft): 5814' / 12. Attachments: Description Summary of Proposal U Detailed Operations Program 0 BOP Sketch 0 14. Estimated Date for Date: 13. Well Class after proposed work: Exploratory 0 Development 15. Well Status after proposed work: Oil 0 Gas 0 Plugged WAG 0 GINJ 0 WINJ 0 Service 0 Commencing Operations: 16. Verbal Approval: Commission Representative: July 7th 2004 0 0 Abandoned WDSPL 0 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Donald Eynon Title Production Engineer Signature ~~ ~ Phone 907-283-1337 Date / COMMISSION USE ONLY 6/30/2004 Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3o.¿/:.. ;;2 t,;r- Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: Bf~ !\ll 4: 1~~~ " OR\G\NAL COMMISSIONER BY ORDER OF THE COMMISSION Date: s!i:~f/ Form 1 0-40~ 12/2003 "-- INSTRUCTIONS ON REVERSE (' 1M \ :ARATHON, 6/29/2004 Marathon Oil Company Alaska Region &k ABU BC 9~ \tl Beaver Creek Unit, Pad 3 API # 50-133-20485 History: Beaver Creek 9L was perforated in the Upper Beluga on January 13,2003 with an initial rate of 17 mmscfpd which depleted rapidly and is currently making approximately 5 ./ MMSCFPD with 55 bwpd. It is thought the majority of the ga0ioming from the Lower Beluga sands and the water is coming from the Upper Beluga. The BC 6s offset in the Upper Beluga has watered out and is currently making 140 MCFPD with 100 bwpd over the last month. ,,/ Objective: Run Quick temp to identify gas and water production and also confirm patch can pass through tubulars. DO NOT shut in well at any time during procedure, while running gauge ring or pressure survey. Ensure SSV well controls do not shut in well while connecting to tree cap. ,// Procedure: 1. Move in Slickline Company. a. Hold pre-job safety and environmental awareness meeting. RU E-line unit. b. Perform wire twist test. MU tool string with 2.75" gauge ring and anti-blowup tool with spangs, oil jars and stem to ensure 2.71" OD casing patch can pass through tubulars. c. MU lubricator and BOPE and pump in sub to tree. Test lubricator and BOPE to /~ wellhead psi. RIH and tag PBTD, POOH. d. MU tool string with pressure bomb and quick temp tool, Rill at 100 fpm to perfs and then slow to 30 fpm 100' above, through and 100' below perforated intervals. / POOH. RDMO slickline unit. IF PL T is required move to step 2 if not move to step 3. 2. Move in Slickline Company. a. Hold pre-job safety and environmental awareness meeting. RU E-line unit. b. Perform wire twist test. MU tool string with 2.75" gauge ring and anti-blowup tool with spangs, oil jars and stem to ensure 2.71" OD casing patch can pass through tubulars. . c. MU lubricator and BOPE with pump in sub to tree. Test lubricator and BOPE /' against swab vale to 2,500 psi. RIH and tag PBTD, POOH. DEEYNON 6/29/2004 1( ( 6/29/2004 d. MU tool string to mirror PLT string, RIH at 120 [pm to perfs and then slow to 30( [pm 100' above, through and 100' below perforated intervals. POOH. e. MU PL T string and RIH making required passes and benches per Expro PL T recommendation (To be Determined). POOH £ RDMO slickline unit. 3. MI E-line company. a. Hold pre-job safety and environmental awareness meeting. RU E-line unit with sufficient lubricator to contain 52.4' of setting tool and patch. MU lubricator to ~/ tree cap and pressure test to 2,500 psi against swab valve. Well will be shut in just prior to Rill with patch. b. Run 2.75" gauge ring on junk basket ifmultiple days have passed since running gauge ring on slickline. c. MU 2.71" OD Owen Oil Tools patch with 40' of blank in assembly (42.4" from / top patch to bottom). Patch length to be determined by length of zone producing water. d. RIH and correlate with CCL to Schlumberger TDT log dated Aprill 0, 1998. If /' uppermost Beluga interval is producing water set patch to isolate 6,429' to 6,459' with top swage at 6,422' MD. If a different interval is the water source; center require patch length over Beluga interval to be isolated. Set patch, wait five minutes, PUR 10' set back down to confirm set and POOH. " e. RDMO E-line unit. Contacts: Completion Reservoir Eng Geologist Don Eynon Tara West Bob Lanz Work Phone 283-1337 713-296-3383 713-296-3388 Pager 877-950-7558 DEEYNON 6/29/2004 ~, (H!') ¡Current Annular Wellbore 1164' FNL & 1547' FWL API # 50-133-20445 ~ 1 ,,¡ ," 11/411 .049 wall Chemical injection 1- ~ line open to annulus at 1000'; ~: 3.5" Buttress AB Mod Tubing TCP Assebly @ 5638' Includes two AB- Mod Buttress by ST-L crossovers, Y- block and 8' of 2" scallop guns Max OD = 5,887" Chemlcallnjection Mandrel Production Seal Unit Model H liner hanger packer Beluga 7420'-60',7534'-74',7640'-60',7705'-55',7762'-7842', 7852'-82',7893'-7933',7980'-8030', 8036'-54', 8072'-98', 8167'-87',8241'-46',8254'-61',8276'-92',8399'-8409', 8432'-52' MD (7039'-79',7153'-93',7259'-79',7324'-74',7381'-7461', 7471'-7501',7512'-52', 7599'-7649'.7655'-73'. 7691'-7717', 7786'-7806',7860'-65',7873'-80',7895'-7911',8018'-28', 8051'-71' TVD) Model N BP at 8808' MD ~ ~ ",' .~ : " .: ~, .~ I '...~ ~ ~. Q'~ ~~. ~ :~ l: :j ,; l' 133/8" 61 ppf K-55 n/a 95/8" L-80 47 ppf BTC Cemented with 700 sacks 0 1853 MD , W '" ¡ j f J,~ i ~ Ie ~i 1,1 \ ,: ;, II ¡ 'I J 'I' ¡~:. :.'.:.1.1..; ¡Sterling B-4 Perforations 5629-5637 MD Nt ~ - (5248-5256 TVD) 1 ; ),\ ~ - ~ I' íl " ~ 1- ~ 2,813 CMU Slidin¡:¡ Sleeve 7" N-80 0 29 ppf BTC 5950 MD Cmt with 565 sks in 2 stages, DV at 4487 MD ¡t1 I ~ :) ~ , ~:04 ~ IBelUga 6429-6459 MD (30') 111312004 (6048-6078 TVD) ~ \..~ ~ /' I t ~! Liner Assemblv 3,5" L-80 9.2 ppf Butt Cemented with 500 sacks 5814 MD 8881 MD -~ H Well Name & Number: County or Parish: Perforations: (MD) AnglelPerfs I BHP: FWHP: Date Completed: Prepared By: Beaver Creek 9 I Lease I KPB I StatelProv, AK (TVD) I 0 Completion Fluid: FWHT: I I Last Revision Date: Beaver Creek I Cou ntry: I I KOP TVD I I Other: RKB: 01/00100 I Angle @KOP and Depth I 0 BHT: I 0 FBHP: FBHT: ( 0 116 / USA .. ... r-' ,~ ~MAMR"'JHO'N' . Marathon M . Oil Company Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 April 28, 2004 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 Reference: Completion Report (10-407) Field: Beaver Creek Field Well: Beaver Creek Unit BC-9 Dear Mr. Aubert Enclosed please find the Well Completion Report, form 10-407 and the associated attach ments. Enclosed please find the Sundry Notice that notified your office of a potential work over scheduled for BC 9. We have elected to cancel the Sundry and would like to follow the cancellation with this Sundry notification. If you require further information, I can be reached at 907-283-1308 or bye-mail at wecissell@marathonoil.com. to- Wayne Cissell Engineering Technician RECEIVED MAY 062004 Alaska Oil & Gas Cons. Commission Anchorage Enclosures: Wellbore schematic Sundry By Certified Mail OR\GINAL " ~ /"'., STATE OF ALASKA ALASKA Oil AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 Status of Well OILD GASC!] 2, Name of Operator MARATHON OIL COMPANY 3 Address P. O. Box 196168, Anchorage, AK 99519-6168 4 Location of Well at Surface 1188' FNL, 1568' FWL, Sec. 34, T7N, R10W, S.M. At top of Producing Interval 2811' FSL, 1277' FWL, Sec. 27, T7N, R10W, S.M. @7039' TVD At Total Depth 2792' FSL, 1259' FWL, Sec. 27, T7N, R10W, S.M. @ 8500' TVD 5. Elevation in feet (indicate KB, DF, etc.) [6. Lease Designation and Serial No. A-028083 Classification of Service Well SUSPENDEDD ABANDONEDD SERVICED 7. Permit Number 92- 122 8. API Number 50-133-20445 9. Unit or Lease Name Beaver Creek Unit 10. Well Number BC-09 11. Field and Pool Beaver Creek, Beluga 12. Date Spudded 13-0ct-O3 17 Total Depth (MD+TVD) 8028' MD, 7647' TVD 14 Date Comp.. Susp. or Aband. 115, Water Depth, if offshore 116. No, of Completions 15-Nov-O3 N/A feet MSL 1 18, Plug Back Depth (MD+ TVD) 19. Directional Survey 120, Depth where SSSV set 121. Thickness of Permafrost 8881' MD, 8500 TVD YeSDNo D N/A feet MD N/A 13. Date T.D Reached 13-0ct-03 22, Type Electric or Other Logs Run NIA 23 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED CASING SIZE WT. PER FT. GRADE 20" 13-3/8" 61 116' 95/8" 47# 1853' 7" 29# 5950' 32" 9.2# 8881' 124 Perforations open to Production (MD+TVD ofTop and Bottom and interval, size and number) 7420' - 50', 7534' - 74', 7640' - 50', 7705' - 55', 7762' - 7842', 7652' - 62', 7693' - 7933', 7980' - 8030', 8036'-54',8072' - 98', 8167'- 87', 8241' -46', 8254'- 61', 8276' - 92', 8399' - 8409', 8432' - 52' 25, SIZE 31/2" TUBING RECORD DEPTH SET (MD) PACKER SET (MD) 5814' 5814' 7039' - 79', 7153' - 93', 7259' - 79', 7324' - 74',7381' - 7461', 7471' - 7501', 7512' - 52', 7599' - 7649', 7655'- 73', 7691'- 7717', 7786' - 7806', 7860' - 65', 7873'- 50', 7895' - 7911', 8018' - 28', 8051'. 71' Sterling 8-4: 5629' - 5637' MD, 4 spf, 2" scallop guns Added Derforations: 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) IAM OUNT & KIND OF MATERIAL USED 27. Date First Production 20-Nov-03 Date of Test Hours Tested Flow Tubing Pres. Casing Pressure PRODUCTION TEST IMethod of Operation (Flowing, gas lift, etc.) Flowing PRODUCTION FOR OIL-BBL GAS-MCF TEST PERIOD -+ 0 2,500 CALCULATED OIL-BBL GAS-MCF 24-HOUR RATE-+ 0 0 WATER-BBL CHOKE SIZE IGAS-OIL RATIO 50 NIA NIA WATER-BBL OIL GRAVITY-API (corr) 50 NIA 28. Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit CORËsC E IVE 0 no cores taken MAY 0 6 2004 Alaska Oil & Gas Cons. Gumrr,¡SSiQll Anchorage Form 10-407 Rev. 7-1-80 Submit in Triplicate CONTINUED ON REVERSE SIDE AOGCC BC-09 Completion 10-407- 043004.xls RBDMS Sf L MAY ,1 '7 ZOO~' .. ~ /"'., 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME MEAS.DEPTH TRUE VERT. DEPTH Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase. Upper Beluga 7420' MD 8452' MD 5629' MD 5637' MD 7039' TVD 8071' TVD 5248' TVD 5256' TVD NIA Sterling NIA 31. LIST OF ATTACHMENTS wellbore schematic 32. I hereby certify that the foregoing is true and correct to the best of my knowledge Sig",' (}.. ~ ~aYUe a.sell Title E""io,,"og Teelmidao INSTRUCTIONS Date 28-Apr-04 General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.) Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 AOGCC BC-09 Completion 10-407 _043004.xls r-- ~ ¡Current Annular Wellbore -- ,-- , ~ ~. 1164' FNL & 1547' FWL API # 50-133-20445 " ¡ . " ~ 1 .~ ; 1 : .~ , :1 .; ~ l' ... . 11/4" 049 wall Chemical Injection I-; line open to annulus at 1000' ~ " , , , , , ! ¡ ¡ ¡ '1 ! ~ :~ ~ ,- 133/8" 61 ppf K-55 nla 0 116 ,,' , i.. 9 518' L.80 47 ppf 6TC Cemented with 700 sacks 0 1853 MD .; , ~ " ", ¡ , ! ' , ¡ .~ ,¡ tn, : ,¡ J ~ i; ; ¡ r ~ ¡ ~~:. ..'li ¡Sterlln9 6-4 Perforations 5629-5637 MD - ~ ~¡, "7- (5248-5256TVD) " ',- ¡, i ~ ,j . , ! 3 5" Buttress AB Mod Tubing TCP Assebly @ 6638' Includes two AB- Mod Buttress by ST-L crossovers, Y- block and 8' of 2" scallop guns Max OD = 5887" ¡ChemlCallnJeCIiOn Mandrel " .; 1-1' ~! . " Production Seal Unit " " > , ' , )' ~ Model H liner hanger packer Beluga 7420'-60',7534'-74',7640'-60',7705'-55',7762'-7642', 7852'-82',7893'-7933',7980'-8030',8036'-54',8072'-98', 8167'-87',8241'-46',8254'-61',8276'-92',8399'-8409', 8432'-52' MD (7039'-79',7153'-93',7259'-79',7324'-74',7381'-7461', 7471'-7501',7512'-52', 7599'-7649',7655'-73', 7691'-7717', " 7786'-7806',7860'-65',7873'-80',7895'-7911', 8018'-28', -Þ-} 8051'-71' TVD) (, ~': Model N BP at 8808' MD \¡a ~. ;. -¡. - 2813 CMU ShdlnQ Sleeve 7" N-80 0 29 ppf BTC 5950 MD Cmt with 565 sks In 2 stages, DV at 4487 MD Liner Assemblv 35" L-80 5814 MD 92 ppf Butt 8881 MD Cemented with 500 sacks Well Name & Number County or Pansh Perforations' (MD) !>ngle/Perfs , BHP' FWHP Date Colnpleted Prepared By Lease I AK (TVD) I 0 Completion Fluid FWHT 1 FBHT I Last RevIsion Date, Beaver Creek I Country. 1 I KOPTVD I I Other RKB 01/00/001 Beaver Creek 9 KPB I StateiProv Angle @KOP and Depth I 0 BHT I 0 FBHP /"'., USA 0 Marathon MARATHON Oil Company` June 26, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 • Marathon ®iE Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 -~ ..-ulv ~ 7 zQO~ Alss~a Coil ~~~ ~~ :. ~;w>~r ai~~icn a~. s.: N Reference: 10-407 Well Completion Report Field: Beaver Creek Fiel Well: Beaver Creek #9 Dear Mr. Maunder: d ~ ~ _ I a'~ 1 ~, ~-- ~~~N~~ JUL ~ 8 2008 Enclosed for your records is the 10-407 Well Completion Report covering the work performed on BC-9 well under Sundry #303-310. This sundry documents the additional perforations added to the Beluga formation in January of 2004. This sundry submittal is part of our effort to close out the documentation on old work activities. Please contact me at (907) 283-1371 if you have any questions or require additional inf~rmatinn_ Sincerely, ~ ~ ~. C~Ci~% ~ " Kevin J. Skiba Engineering Technician Enclosures: 10-407 Well Completion Rep: Operations Summary ~~ ..... ~'~.esc ~c~ s~o~ ~~ p5~tn~.)\~~> ~a=ton Well File ,e~i Well File STATE OF ALA ~~ AL~ OIL AND GAS CONSERVATI C ON WELL COMPLETION OR RECOMPLL ~ORT 6 a~•o~ AND LOG Oil^ GasQ .Plugged ^ Abandoned ^ Su ,~ .,_ _ ;, '~~"1~!~~`~~: 20AAC25.105 2onnczs.~~o ,:; ~0' Develo ment ~ Ex lorato P ^ ~ P rY ^ GINJ^ WINJ ^ WDSPL^ WAG ^ Other^ No. of Completions: 2 Service ^ Stratigraphic Test ^ 2. Operator Name: 5. Date Comp., Susp., or 12. Permit to Drill #: 192-122' Marathon Oil Company Aband.: 9/2/1994 Sundry #: 303-310 3. Address: 6. Date Spudded: 13. API Number: p0 Box 1949, Kenai Alaska, 99611-1949 7/28/1994 50-133-20445-00-00 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 1,188' FNL, 1,568' FWL, Sec. 34, T7N, R10W, S.M. 8/27/1994 Beaver Creek Unit #9 Top of Productive Horizon: 8. KB (ft above MSL): 183'. 15. Field/Pool(s): 2,830' FNL, 1,287' FWL, Sec. 34, T7N, R10W, S.M. Ground (ft MSL): 160' ~ k Fi ld /St li & B B C l D er ng eaver ree e e uga Total Depth: +TVD): 9. Plug Back Depth(M Formations 2,792' FNL, 1,259' FV11L, Sec. 34, T7N, R10W, S.M. 8,808' MD 8,426' TVD 4b. Location of Well (State Bas e PIa3~~ ~`dinates, N~ 7);., ~~ 0 10. Total Depth (MD + TVD): 16. Property Designation: ~ ~ ~ Surface: x- 1 ~ Zone- 4 8 881' MD - 8,496' TVD , {f.~ A-028083 TPI: x- ,~,1~-+ ~ y_ _~3g2- Zone- 4 • 11. SSSV Depth (MD + TVD): 17. Land Use Permit: l Total Depth: x- 3.1~69~ y- $;431,462 Zone- 4 NA 18. Directional Survey: Yes No ~ ~ p. 19. Water Depth, if Offshore: 20. Thickness of Permafrost (TVD): (Submit electronic and printed information per 20 AAC 25.050) ~• NA (ft MSL) NA 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): 22. CASING, L INER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT TOP BOTTOM TOP BOTTOM PULLED 13-3/8" 61# K-55 0' 116' 0' 116' Driven NA N/A 9-5/8" 47# N-80 0' 1,858' 0' 1,794' 12-1/4" 700 sks N/A 7" 29# N-80 0' 5,950' 0' 5,569' 8-1/2" 565 sks N/A 3-1/2" 9.2# N-80 5,814' 8,881' 5,433' 8,500' 6" 500 sks 150 sks 23. Open to production or injection? Yes 0 No ~ If Yes, list each 24. TUBING RECORD interval open (MD+TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD) Sterlin B4: 5629-5637' MD Beluga: 6429-6459', 7420-60, 7534-74, 7640- 3-1/2" 5,824' 5,814' 60, 7705-55, 7762-842, 7852-82, 7893-933, 7980-8030, 8036-54, 8072-96, 8167-87, 8241-46, 8254-61, 8276-92, 8399-8409, 8432-52' MD Sterling 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 5248-5256' TVD Beluga: 6048-6078,.7039-79, 7153-93, 7259-79, 7324 DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 74, 7381-461, 7471-501, 7512-52, 7599-649, 7655-73, 7691-717, 7786-806, 7860-65, 7873-80, 7895-911, 8018-28, 8051-71' ND 26. PRODUCTION TEST Date First Production: 9/18/1994 Method of Operation (Flowing, gas lift, etc.): Flowing Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: Test Period 0 100% Gas Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity- API (corr): Press. 24-Hour Rate --~ 0 NA 27. CORE DATA Conventional Core(s) Acquired? Yes ^ No Q Sidewall Cores Acquired? Yes ^ No Q If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. 1IJ'~ f.. ; ~ , ~~(~ ~ ZQ~~ Form 10-407 Revised 2/2007 j'"'1 (~ ~ ~ ~ (~ ~ ~C~ONTINUED ON REVERSE ,~- l',~- 28. GEOLOGIC MARKERS (List all formations and m encountered): 29. FORMATION TESTS NAME M TVD Well tested? Yes ~ If yes, list intervals and formations tested, briefly summarizing test results. Attac separate sheets to this form, if needed, and submit Permafrost -Top detailed test information per 20 AAC 25.071. Permafrost -Base Sterling 64 5,248' 5,629' Beluga 5,884' 6,264' Formation at total depth: 30. List of Attachments: O erations Summa 31. 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: Engineering Technician ~ Signature: • ~ Phone: (907) 283-1377 Date: June 26, 2008 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. ttem 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: ff this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 2/2007 ~ ~'~~3~~ MARATHON OlL COMPANY Page 1 of 4 Daily Workover Report Increase Production WELL NAME BEAVER CREEK 09 K8 ,GL 24 HRPROD!TMD ~ __~ _ ~ _ __,~ ~__~.-_ ~ ND `OFS 'DOL ~RPTN 'DATE _ _~_ 0 _~___~___1__~ 13-Jan-2004 SUPERVISOR Don_E non ,_._ FlELD NAME BEAVER CREEK ~`~ I RNs NAME & NO. AUTH MD _ __ _ -I{-~ ,____ PHONE w ~ MOC W1 ; _ I _ i_ _~_~_I - J WBS `SAPANBS COST ~__ W00409967EXP NRI DAILY WfLL~COST~CUM wELL COST 8,000.00_ I _ 8,0_00.00 ____. .._-.~ _ STATT/PROV ALASKA _ - _ _ t `LAST CASINO ~ NEXT CASING LEAKOFF COUNTYIOTHER V _ --- I _ KENAI _._~-__~ 0 ~__-. ~in~01ft) ~ ~ CURRENT STATUS / MTS Producing -~ 24 HR FORECAST "_~ ~ _ ,_-__._.-..~.. OPERATION COMMENTS Perforate Upper Betuga from 6,429' to 6,459'. -••-~ ~Q ~ ~~~y MANHRS WORKED f ACCIDENT TYPE LAST SAFETY MTG .'BOP PS~1'~ESTS LAST STOP CARD AUDR ~ ~R~EGULATORY INSP7 LAST RIG INSPECTION 27.00 _ ~~ ~. _~~~ ~~ ~ ACCIDENT DESCRIPTION: ~~ SAFETY MTG TOPICS: WOrI(In With IIVe Well. ~ _. _ ~ OPERATtON 3 SUM MARY FROM Tfl HRS FROM . TO »16 PHASE OP TRBt. QE8CRN~710N- 09:00 10:00 13:00 13:30 10:00 1 13:00 13:30 18:00 1.00 3.00 0.50 4.50 __ _ - AF AF AF ~AF~ CMPPR CMPPRF CMPPR CMPP SAFETY RURD TEST_ PERF_ I I ~ _ I PJSM, talk about perforating system and no need for radio silence. RU to wellhead, -20 degree weather hampers progress Pressure test lubricator to 3000 psi. Well at 4.8 mmscfpd and 840 psi, Cut rate on well to increase WHP wiht little sucess . Shut in well to increase WHP to 1250 psi. _ RI~H with 30' 2.375 perforating gun, ksaded 4 spf with 60 degree hasing, Correlate to GR CCL on TDT log dated April 1998. p Perforate 6429.6459 overall interval with 1250 si on sin t { ~ ~ I . j y ___J __ surtace with gas gradient to perforations. Positive indication of firing on Tine, lost 5001bs of line weight, POOH pulled 2000 feet before regaining ail weight Surface pressure built from 1250 to 1850 in 1 minute, 1940 in 2 minutes, 1975 in 5 minutes. POOH aq shots fired. Top 15 feet shot, then a 1.5 foot blank the 13.5 feet shot 213.5 feet of net interval. RDMO E-Gne. Flow we11 to sales__ _ PERSONNSt_ DATA POB ~ Os:tia:. CfltAPANY SEttViCE NO. HOURS COMPANY ~ ~ SERWfCE - NO. HOURS Expro Perforate _ 3 27.00 .~ CA51NG SUMMARY' _ LAST BOP TEST: LAST CASING TEST: NEXT BOP TEST: SIZE it? _ MD 11/D WT GRADE B RST SHOE TEST ,MAX SiCP ~! _ _ Printed: 2/13/2008 3:08:16 PM Marathon OilCompany Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 9071561-5311 Fax 907~564-6489 October 12, 2003 Sarah Palin Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Reference: Sundry Notice Field: Beaver Creek Unit Well' Beaver Creek 9 Annular Dear Ms. Palin Enclosed please find the Application for Sundry Approvals along with an operations program, BOPE sketch and a wellbore diagram. The Sundry/Application is for recompletion of the well as an annular producer in the Sterling B-3a sand. The well is currently configured with the Sterling B-4 interval as an annular producer and the Beluga completion produces up the tubing string. Currently the Sterling B-4 is watered out due to coning. I have also included a discussion of the reserves associated with this project and addressed potential problems with the annular completion. If you require further information, I can be reached at 907-564-6318 or by e-mail at DEEynon@ MarathonOil.com. · ~ ~) Sincerely, Donald Eynon Operations Engineer Enclosures: Sundry Notice Detailed Operations Program Wellbore Diagram (2) ..... ?'- ........... B'O'PE Sketch Reserves - Annular Flow Discussion F ECEIVED OCT ! 4 0'03' Alaska 0il & Gas Cons. Commission Anchorage ORIGINAL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Suspend Operation Shutdown Alter Casing Repair Well Plugging Change Approved Program Pull Tubing X Variance Re-enter Suspended Well Time Extension Stimulate PeRorate X Other 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 1188' FNL, 1568' FWL, Sec. 34, T7N, R10W, S.M. At top of Productive Interval 2811' FNL, 1277' FWL, Sec. 34, T7N, R10W, S.M. @ 7039' TVD At Effective Depth 2800' FNL, 1270' FWL, Sec. 34, T7N, R10W, S.M. @ 7647' TVD At Total Depth 2792' FNL, 1259' FWL, Sec. 34, T7N, R10W, S.M. @ 8500' TVD 5. Type of Well: Development X Exploratory Stratigraphic Service 6. Datum Elevation (DF or KB) 183° KB feet 7. Unit or Property Name Beaver Creek Unit $. Well Number BC-9 9. Permit Number 92-122 ~'" 10. APl Number 50-133-20445 j 11. Field/Pool Beaver Creek Field, Sterling and Beluga 12. Present Well Condition Summary Total Depth: measured true vertical 8881 feet Plugs (measured) 8500 feet Baker "N" bridge plug @ 8808' MD Effective Depth: measured true vertical 8028 feet Junk (measured) 7647 feet Casing Structural Conductor Surface Intermediate Production Liner PeRoration Depth: Beluga Length Size Cemented Measured Depth True Vertical Depth 116 13 3/8% 61# Driven 116 116 1853 9 5/8", 47# 700 sks 1853 1725 measured true vertical 5950 7", 29# 565 sks 5950 5555 3067 32", 9.2# 500 sks 8881 8500 742~~-6~'~7534~-74~~764~'-6~'~77~5'-55'~7762~-7842~~7852'~82'~7893'-7933'~798~~-8~3~'~ 8036'-54',8072'-98',8167'-87',8241'-46',8254'-61',8276'-92',8399'-8409',8432'-52' 7~39'-79~~7153'~93'~7259~-79'~7324'-74'~7381'-7461'~7471'-75~1'~7512'-52~~7599~-7649'~ 7655'-73~~7691'-7717'~7786'-78~6'~786~'-65'~7873'-8~'~7895~-7911~~8~18'-28'~8~51'~71' Tubing (size, grade, and measured depth) Sterling B-4: 5629' - 5637' MD, 4 spf, 2" scallop guns 32", 9.2#, L-80, AB Mod. Butt to 5814' Packers and SSSV (type and measured depth) Baker model H packer @ 5814' with Hyflo-II liner hanger and sealbore extension 13. Attachments Description Summary of Proposal Detailed Operations Program X ~ ~_,,(~'"~tIIV'-~ D 14. Estimated Date for Cj;)mmencing Operation 17-Nov-03 16. If Proposal was Verbally Approved Name of Approver Date Approved 15. Status of Well Classification as: Oil __ Gas _~X Service OCT '14 2_00:3 Ss d Alaska ~d~~-0ns. Commission Anchorage 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Title Production Engineer FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so representative may witness Plug Integrity BOP Test Location Clearance Mechanical Integrity Test Subsequent Form Required 10- Approved by Order of the Commission Form 10-403 Rev. 06/15/88 Date 10/12/2003 TApproval No. Commissioner Date Submit irf'~iplica/t~ Marathon Oil Company Beaver Creek Field Well BC-9 WBS# RW.03.09432.CAP.CMP.01 Recompletion Procedure History: BC-9 was re-completed as an annular producer from the Sterling B-4 interval in ~ June of 1998. The well has recently produced at a high water-gas ratio and was shut in. Purpose: Recomplete well BC-9 to produce the Sterling B-3A Sand up the tubing/casing annulus. Procedure: 1. Call out ABB Vetco wellhead hand to test void on wellhead. Perform UTT inspection for erosion prior to workover. 2. MIRU slickline. a) Pressure test lubricator and BOPE to 3000 pSi:, b) RIH with 2.8" OD gauge ring to :PBTD, POOH. c) ~MO slickline unit. : 3. :MIRU:e-line. :: a)::Shut in well BC,9L.i:RU to Otis tree cap with BOPE and lubricator and :: test to 2500 psi with methanol trailer. b) RU GR CCL tool and 1.69" OD inflatable packer with reservoir tool. :: MU tool string and RIH to 5,854,,.(40' below the liner top) and set inflatable bridge plug in middle of tubing joint. POOH. (Note: Inflatable :: BP has differential pressure rating of:4550 psi.) Make note of RA tag in :: long string for current placement of TCP gun. :4. Mix 500 bbl of 6% KC1. Bleed off all pressure from long string to production system. Fill' tubing with 6% KC1 from vacuum truck. 5. MIRU slickline unit. : :: a) pressure test lubricator and BOPE to 3000 psi. ' b) KIH with dump bailer and dump 10' of sand on inflatable BP. :c) Rm with PX plug and set in nipple at 5,765'. POOH, RU PX prong and :' : RIH, set in PX plug at 5765'. POOH. d) MU kick over tool (OK-6) for 3.5' KBMM gas lift mandrel with pulling tool for dummy valve. e) RIH to gas lift mandrel at 5698', pull dummy valve, watch for vacuum on tubing. POOH with valve. RIH with circulating valve, insert in GLM at 5698', POOH. RDMO. . RU BJ services pump truck on tubing. Test lines to 4000 psig. Circulate 6% KC1 until well is dead, if necessary pump Flo-vis pill to mitigate losses to Sterling formation. RDMO pump truck. . MIRU Glacier Drilling Rig #1. Bleed down and disconnect control line. Set BPV in tree. ND tree, NU 13 5/8", 5M BOPs fitted with 2.875-5.5" variable pipe rams. Send tree to ABB Vetco for inspection and repair..Verify well is dead, pull BPV, and install 2-way check. Test BOPs to 3000 psig.'"Pull 2-way check. ge . RU landing joint, back out lock down screws and pull on mandrel hanger. Tubing string should weight 53,500 lbs dry and 49,500 lbs buoyed by 6% KC1. If tubing does not pull free, RU APRS and run free point survey. Contact Anchorage office with free point information, additional cuts below gas lift mandrel and y-block assembly may be made to mitigate need to wash over gas lift mandrel and y-block if decision is made to pursue workover. TOH with 3 ~2" tubing laying down while checking periodically for NORM. Send packer seals to shop for redress. RIH with 6" bit and 7" casing scraper for 7" 29 ppf casing on 4" drill pipe. POOH. a) PU 7" 29 ppfRBP on 4" DP. b) TIH to 5500' and set, pressure test casing to 2500 psi. Release RBP and RIH to 5750' and set. POOH 100,:. Spot 3 sks (approx. 14') Sand and ::::: alloW:to settle on top ofRBP. RIH and tag sand: :POOH to 5650', shut BOP and establish injection rate at a maximum pressure of 2,000 psi into Sterling B4 perforations. : 10:RUBJ cementers,. a) Mix and spot.75 skSo£Class G Cement as per BJ's recommendation. b) POOH to 200 abov cement top. c) Perform hesitation squeeze by apPlying pressure to casing. d) Rever:se circUlate:drill pipe, POOH, Lay down retrieving head. WOC : :I1. RIH with "" ~:'t o m and collars and tag cement top. Pressure test casing to 2500 psi. : :: Drill oUt:cement, RIHiand tag sand, POOH 50' and test to 1500 psi. POOH, RIH . bit and scraper on drillpipe to RBP, POOH. 12. RIH with retrieving head for RBP, circulate sand with viscous pill. Latch RBP and POOH. liner wash out assembly with 2 3/8" tubing, RIH and wash out to inflatable RBP. 14. TIH with liner tie back seal assembly for 4" seal bore and space out with approximately 6 joints of 3.5" EUE 8 rd L-80 tubing to place top of packer at a depth of 5600'. (It is 214' from liner top to 5600', this would correspond to the distance from bottom of locator to top of Model F packer. This will isolate Sterling B-4 squeeze perfs at 5,629'-5,637') MU 7" 29 ppfmodel F packer with 4" ID seal bore extension on Model B setting tool. RIH to liner top, establish PU and SO weights, start circulation at minimum pump rate for indication of insertion into polished bore. Mark pipe, shut off pump and bleed off pressure. Measure distance traveled to fully insert seals into polished bore, PU 2' and mark pipe. Drop ball for setting tool, wait for ball to drop, pressure up drill pipe in increments to set packer. PU on drill pipe to verify set, rotate free from packer, TOOH. 15. TIH with seal assembly, pup joint, 2.813 x-nipple, 3.5" tubing, y-block, 3.5" tubing, sliding Sleeve and 3.5" tubing to surface. Install chemical injection mandrel at 1500' from surface with ¼" .049 stainless steel line to surface, The space out from the TCP guns to the locator sub on the seal bore is critical. Include radioactive (RA) tag in collar above TCP assembly. Record distance from RA tag to top perf. Perfs will be from 5536' to 5556' TDT (4/10/98, 5,155- 5175 TVD). Perforations can be between 5532' to 5556, MD. 16. Sting seals into model F packer at 5600'. Slack off tubing until loCator sub contacts top of packer. PU 1' and mark pipe. 17. MIRU electric line. RIH with GR/CCL. Have RST (TDT) tool available if needed:Use gamma ray log t© tie RAtag to TDT logOf 4/10/98:1 POOH, RDMO electriC line.: i 18: Pull seals out:Of seal bore, space out with pup joints and tubing hanger. Install : : tubing mandrel hanger with control line prPp. Land tubing hanger, test annulus to : 2000 psi and test hanger seals to 4000 PSig, 19. Set BPV in tubing hanger. ND BOPs, NU and test 3-1/16", 5M tree. RDMO :i Glacier Rigl, 20. Hook up fl°~v lines from BC-9a to production facilities. : 21:i Pull BPV fr°~ tree. MIRU flow back tank, chicksan and choke skid, pressure test :to 3000 psi. : 22. iMIRu sliCkline. · ~5 Pressure test lubricator to 3000 psi. : b) RIH with lead impression block and tag top of RBP to check for fill. POOH. If no fill is encountered, RBP will be pulled with slickline in step 2{5. c) RIH with 2.813 PX plug to nipple at 5595'. POOH, RIH with prong to same. POOH. d) RIH with shifting tool and open sliding sleeve above y-block. POOH. 23. RU nitrogen pump on annulus. Pump nitrogen down annulus taking returns on tubing. Continue until annular volume is displaced. a) RIH with shifting tool and close sliding sleeve. 24. Pressure up tubing to 1000 psi and monitor for 15 minutes to confirm sleeve is closed. Continue to pressure up to approximately 2000 psig using 6% KC1 to shear firing head. Monitor tubing and casing for signs of 2", 4 spf, 0© phase scallop guns firing. Guns are designed to fire when tubing pressure reaches 1800 psig with 6% KC1 in the tubing. a) RII-I with slickline and pull PX plug at 5,595' 25. Line up BC-9s to flow back tank. Attempt to unload well as per instructions of Production Engineer. a) If well will not unload by itself, RU slickline to open sliding sleeve above y-block. Pump nitrogen down tubing taking returns up casing to unload well. RDMO nitrogen when annulus is flowing. 26. Produce and test as per Production Foreman,: Move flow back rig uPfrom annulUs: to tree. 27. MIRU BJ coiled tubing. e) over pipe. Test all coiled tubing and BOPE equipment to 150/3000 psi. RIH With wash over pipe circulating 6% KCL to RBP at 5854'. Circulate bOttoms up 2 times. POOH. MU retrieving tool to CT connector, double flappers, CT disconnect, RIH, stOp I00' away from RBP and jet hole dry with nitrogen, hold approximately 1500 psi at surface, latch RBP, equalize, release and POOH. 28. Line up BC-9L to floW back tank. Attempt to unload well as per instructions of ProduCtion :Engineer. ::: Marathon Oil Well BC-9 BOP Stack I FIow Nipple 13 5/8" 5M Annular Preventer Flow Line 13 5/8" 5M Double z" Ram Preventer I. ~--'----' IPipe Ram I -----I 12 1/16" 5M I I----- IBlind Ram I '-----I Check Valve 12 1/16" 5M Manually / .... / 3.. 1/8" ,5M, .H.y,draulically I ~ I ~ ~ <~ upera[ea valve 3 1/8" 5M Manually ~ I Pipe Ram I -'-----I Operated Valve 13 5/8" 5M Single Ram Preventer 13 5/8 5M Flange UP by 7 1/16" 5M Studs Down Bottom of Single gate must be I24-45" from ground level for Glacier 1 rig placement. 7 1/16" 5M Tubing Head Flange Beaver Creek Field, Well BC-9 Reserves - Annular Production Discussion History: Beaver Creek 9 was initially complete.,d as a 3.5" Beluga monobore in 1994. The well was then recompleted as an annular producer'up the 3.5" by 7" annulus during a workover in 1998 to add the Sterling B4 sand as shown in the attached well bore diagram. The Sterling B4 sand was produced intermittently as a swing producer during times of high demand for gas. In January of 2003 the well started producing at a high water-gas ratio and was shut in. We left the well shut in 200+ days and then started producing at a Iow rate to see if we could produce below critical coning rate. The well quickly lost well head pressure in 2-3 days, started producing water, and was shut in. Reserves We have up-hole potential in the Sterling B-3a interval in this wellbore ~ we believe to be dry gas. Recoverable reserves attributed to this zone are approximately,,5"BC~ut are uneconomic to drill another well for. The last reservoir pressure data point obtai~n the Sterling B-3 and B- 3a was a BHP of 1,160 psi which, with a methane gradient to surface, would create a well head pressure of 1,030 psi. Individual well P/Z plots for Sterling B-3 and B-3a intervals have indicated a volumetric reservoir, however, some recharge in reservoir pressure may have occurred. Well Design With regard to wellbore integrity, the 7" production casing is 29 ppf N-80 with a burst pressure rating of 8,160 psi. The production casing was cemented in two stages, with 215 sks in the first stage and a 7" DV tool at 4,487' was used with 350 sks in the second stage. Full returns were /-' indicated through out the job with the cement top calculated to be within 976' (25 bbls) from surface based on returns of mud flush. Current plans for the workover are to cement squeeze the current interval and pressure test the casing. The well is currently set up to produce out both sides of the tubing head spool from the tubing casing annulus. A surface safety valve is installed in the flowline. We have and will continue to produce the new annular completion at rates limited by erosional velocity and not reservoir / completion capacity. UTT analysis indicated no erosion of the wellhead or flow lines the last time it was inspected. Corrosion Gas produced from the Sterling intervals is over 99% methane. Carbon dioxide content of Sterling gas is approximately .25 mole percent, which produces a partial pressure of 6 psi at initial reservoir pressure. Gas mixtures with less than 7 p~si partial pressure are generally considered non-corrosive. No hydrogen sulfide is present. / Erosion The most likely place for erosion to occur is at the dual tubing head outlets where the valve removal thread internal diameter is 1.469". The sand free production chart is shown below for producing the well below erosive rates. Production rates to unload the well and keep the flow stream free of water are below the erosive rate for flow out of one outlet. We have and will continue to produce the well out of both tubing head spool outlets simultaneously to reduce the likely hood 'of erosion. Production Allowable to Prevent Erosion 1600 1800 2000 2200 Marathon OilCompany October 8, 2003 Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907~564-6489 Sarah Palin Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Reference: Sundry Notice Field: Beaver Creek Unit Well: Beaver Creek 9 Dear Ms. Palin Enclosed please find the Application for Sundry Approvals along with an operations program and a wellbore diagram. The Sundry Application is for perforating an additional Beluga sand. If you require further information, I can be reached at 907-564-6318 or by e-mail at DEEynon@MarathonOil.com. Sincerely, Donald Eynon Operations Engineer Enclosures: Sundry Notice Operations Plan Wellbore Diagram RECEIVED Alaska Oil & Gas Cons. Commissio~'t Anchorage STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Alter Casing Change Approved Program Suspend__ Operation Shutdown Repair Well Plugging Pull Tubing Variance Re-enter Suspended Well ., Time Extension Stimulate Perforate X Other Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 1188' FNL, 1568' FWL, Sec. 34, T7N, R10W, S.M. At top of Productive Interval 2811' FNL, 1277' FWL, Sec. 34, T7N, R10W, S.M. @ 7039' TVD At Effective Depth 2800' FNL, 1270' FWL, Sec. 34, T7N, R10W, S.M. @ 7647' TVD At Total Depth 2792' FNL, 1259' FWL, Sec. 34, T7N, R10W, S.M. @ 8500' TVD 5. Type of Well: Development X Exploratory Stratigraphic __ Service 6. Datum Elevation (DF or KB) 183' KB feet 7. Unit or Property Name Beaver Creek Unit 8. Well Number BC-9 9. Permit Number 92-122 10. APl Number 50-133-20445 11. Field/Pool Beaver Creek Field, Sterling and Beluga 12. Present Well Condition Summary Total Depth: measured true vertical 8881 feet Plugs (measured) 8500 feet Baker "N" bridge plug @ 8808' MD Effective Depth: measured true vertical 8028 feet Junk (measured) 7647 feet Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: Beluga Length Size Cemented Measured Depth True Vertical Depth 116 13 3/8", 61# Driven 116 116 1853 9 5/8", 47# 700 sks 1853 1725 measured true vertical 5950 7",29# 565 sks 5950 5555 3067 32", 9.2# 500 sks 8881 8500 742~~-6~'~7534'-74'~764~'-6~'~77~5'~55''7762~-7842'~7852'-82~~7893'-7933'~798~~-8~3~'~ 8036'-54',8072'-98',8167'-87',8241'-46',8254'-61',8276'-92',8399'-8409',8432'-52' 7~39'-79'~7153'-93'~7259~-79~~7324~-74'~7381~-7461'~7471'-75~1~~7512'-52'~7599~-7649'~ 7655'-73',7691'-7717',7786'-7806',7860'-65',7873'-80',7895'-7911',8018'-28',8051'-71' Tubing (size, grade, and measured depth) Sterling B-4.: 5629' - 5637' MD, 4 spf, 2" scallop guns 32", 9.2#, L-80, AB Mod. Butt to 5814' Packers and SSSV (type and measured depth) Baker model H packer @ 5814' with Hyflo-II liner hanger and sealbore extension 13. Attachments Description Summary of Proposal__ 14. Estimated Date for Commencing Operation 13-Oct-03 15. 16. If Proposal was Verbally Approved Name of Approver Date Approved Detailed Operations Program X Status of Well Classification as: Oil Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Gas X FOR COMMISSION USE ONLY Signed '~r'~. ~ ~ Title Production Engineer BOP Sketch ~'.:~a'~, I~'~P~'~ ~ ~un ,,-~ ,,., U IVb, D r_,,** r'... Commission Anchorage Commissioner Date Subr~it in ~'ripl[cate OR GINAi., Conditions of Approval: Notify Commission so representative may witness Plug Integrity__ BOP Test Location Clearance Mechanical Integrity Test S"--ubsequent Form Required 10--- ~ 12 ~ Approved by Order of the Commission ~ '~ Form 10-403 Rev. 06/15/88 IApproval No. ,,~,¢,.~ -~,~/g2 Date 10/9/2003 10/08/2003 Marathon Oil Company Alaska Region ABU BC 9L Beaver Creek Unit, Pad 3 API# 50-133-20485 History: Beaver Creek 9 was drilled as a crestal producer in the Beluga interval. A recompletion added the Sterling as an annular producer in 1998. The Beluga is currently producing out of the long string at 5 MMSCFPD and the Sterling annular producer quickly coned in water last week after being shut in 200+ days. Objective: Perforate additional Beluga interval at a depth of 6,429' to 6,459'. Procedure: 1. MIRU chicksan, choke skid and flow back tank, test to 3000 psi with methanol test skid. 2. Move in e-line company. a. Hold pre-job safety and environmental awareness meeting. RU E-line unit. b. MU lubricator and BOPE and pump in sub to tree. Test lubricator and BOPE to 3000 psi. Monitor wellhead pressures for build while perforating. c. MU 20' 2." HSD power jet 2006 HMX perforating gun with CCL and weight bar. RIH and correlate to Schlumberger TDT log dated April 10, 1998. d. Perforate Beluga interval from 6,439' to 6,459' (6058' to 6078' TVD). POOH. e. MU 10' 2." HSD power jet 2006 HMX perforating gun with CCL and weight bar. RIH and correlate to Schlumberger TDT log dated April 10, 1998. f. Perforate Beluga interval from 6,429' to 6,439'. (6058' to 6078' TVD). POOH. g. RDMO Schlumberger. o Flow well to tank to clean up. a. Flow well to tank at a FTP of 1,500 psi if at unload rate, lower draw down if necessary to reach unload rate. b. Observe a minimum flowing tubing pressure of 1300 psi which equates to a 1500 psi BHP (40% drawn down) with a low rate, methane gradient and minimal water production. c. Turn well to production as soon as well cleans up. 10/08/2003 Contacts: Work Phone Pager Completion Don Eynon 564-6318 268-6953 Reservoir Eng Ralph Affinito 564-6303 231-3775 Geologist Bob Lanz 564-6427 1164' FNL & 1547' FWL APl # 50-133-20445 1/4" .049 wall Chemical injection line open to annulus at 1000' 13 3/8" K-55 0 61 ppf n/a 116 9 5/8" L-80 0 47 ppf BTC 1853 MD Cemented with 700 sacks 3.5" Buttress AB Mod Tubing TCP Assebly @ 5638' Includes two AB- Mod Buttress by ST-L crossovers, Y- Iblock and 8' of 2" scallop guns Max OD = 5.887" Sterling B-4 Perforations 5629-5637 MD (5248-5266 'IA/D) Production Seal Unit Model H liner hanger packer Beluga 7420'-60',7534'-74',7640'-60',7705'-55',7762'-7842', 7852'-82',7893'-7933',7980'-8030',8036'-54',8072'-98', 8167'-87',8241'-46',8254'-61',8276'-92',8399'-8409', 8432'-52'MD 17039'-79',7153'.93',7259'-79',7324'-74',7381'-7461', 17471'-7501',7512'-52',7599'-7649',7655'-73',7691'-7717', 17786'-7806',7860'-65',7873'-80',7895'-7911',8018'-28', 8051'-71'TVD Model N BP at 8808' MD 7" N~80 0 29 ppf BTC 5950 MD Cmt with 565 sks in 2 stages, DV at 4487 MD -- [Proposed Beluga perfs 6429,.6459' MD (6048-6078 TVD) I Liner Assembly 3.5" L-80 5814 MD 9.2 ppf Butt 8881 MD Cemented with 500 sacks '" Weli 'Name & Number: Beaver Creek 9 I Lease I Beaver Creek Countyor Parish: KPB I State/Prov.I AK I Country: I USA Perforations: (MD) ('P/D) I BHP: 0 BHT: 0[ Completion Fluid: FWHP: FBHP: IFWHT: I FBHT:IOther: Date Completed: RKB: Prepared By: 0 I Last Revision Date: 01/00/001 .... Alaska R~ n Domestic 15roduction Marathon Oil Company September 2, 1998 P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Mr. Blair Wondzell Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99513-7599 Reference: Gas Well Open Flow Potential Test Report for Marathon Oil Company Well Beaver Creek 9s Dear Mr. Wondzell: Please find enclosed the Gas Well Open Flow Potential Test Report for the Beaver Creek Well No. 9s. If you have any questions, please call me at 564-6315. Sincerely, gineer /nr~ H:\WF~OPNS98~JGE92 Enclosure RF CE VED r.[ i998 Alaska 0ii & Gas Cons. C0mrniss~L,: Anchorage A subsidiary of USX Corporation Environmentally aware for the long run. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT la. TEST: INITIAL X lb. TYPE TEST STABLILIZED I I NON STABILIZED X ANNUAL MULTIPOINT CONSTANT TIME SPECIAL OTHER ISOCHRONAL 2. Name of Operator 7. Permit No. Marathon Oil Company 92-122 3. Address 8. APl Number 3201 C Street, Ste. 800, Anchorage, Alaska 99503-3934 50- 133-20445 4. Location of Well 9. Unit or Lease Name At surface Beaver Creek Unit 1188' FNL, 1568' FWL 10. Well Number Section 34, T7N, R10W, S.M. BC-9s ~11. Field and Pool Beaver Creek Field, Sterling Pool 5. Elevation in feet (KB, DF etc.) 16. Lease Designation and Serial No. 183' KBI A-028083 7~98 8881' 8808' Annular completion, cased hole 16. Csg. Size Weight per foot, lb. I.D. in inches Set at ft. :Perforations: From To 7" 29~ 6.184" 5950' 5629' - 5637' TDT 17. Tbg. Size Weight per foot, lb. I.D. in inches Set at ft. 3~" 9.2# 2.992 5814' 18. Packer set at ft. 119. GOR cf/bbl. 120. APl Liquid Hydrocarbons 21. Specific Gravity Flowing fluid (G) 22. Producing thru: Reservoir Temp. °F. Mean Annual Temp. °F. Barometric Pressure (Pa), psia Tbg.r'~ csg.r~ 103 45 14.65 24. Flow Data Tubing Data Casing Data Choke Prover Orifice Line Size X Size Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. (in.) (in.) psig hw °F. psig °F. psig °F. Hr. I 3 X 2.25 811.2 4.0 60 1820.9 60 2.000 2. 3 X 2.25 842.7 16.8 60 1809.7 61 2.000 3.13 X 2.25 858.7 36.0 60 1782.8 63 2.000 5' X Basic Coefficient ~ (24-Hour) hwPm Pressure Flow Temp. Factor Gravity Factor Super Comp. Factor Rate of Flow No. Fb or Fp Pm Ft Fg Fpv Q, Mcfd 1. 33.2 57.0 825.9 1.0000 1.329 #DIV/0! 1,889 2. 26.1 119.0 857.4 1.0000 1.329 #DIV/0! 3,110 3. 34.0 175.8 873.3 1.0000 1.329 #DIV/0! 5,975 4. 42.3 204.9 889.5 1.0000 1.329 #DIV/0! 8,664 5. Pg. 125 GPSA Temperature for Separator Gas for Flowing Fluid No. Pr T Tr Z Gg G 1. 520 0.566 2. 520 3. 520 Critical Pressure ~ ~'F i ~t,~ ~ i-') 4. 520 Critical Temperature ] ~' ~ ~""" ~''' ' " ~" ""~ 5. ~-ormu-421 ~"~1~i"3 ir-. ~, ~[,.~{,~ Rev. 7-~-S0 SEI kz~AOGCCGAS.XLS CONTINUED ON REVERSE SIDE Submit in duplicate Alaska 0il & Gas O(,~,.~ ~.;0mrnissior' Anchorage Pc 1,848 P~ 3,413,995 Pf PF 0 No. Pt Pt2 Pc~ - PF Pw Pw~ Pc~ - Pw~ Ps Ps~ PF - Ps~ 1. 0 0 3,413,995 - - - 2. 0 0 3,413,995 .... 3. 0 0 3,413,995 - - - 4. 0 0 3,413,995 ..... 5. 0 0 25. AOF (Mcfd) 96,289 n 1.000 Remarks: Data performed with surface pressure gauges. Test data is hampered by apparent water entry into the wellbore during the flow test. Assumed a maximum "n" value of 1.0, from which the AOF is calculated. I hereby.certify that the foregoing is tr~[e and correct to the best of my knowledge. x, DEFINITIONS OF SYMBOLS AOF Fb Fp Fg Fpv Ft G Gg GOR hw H L n Pa Pc Pf Pm Pr Ps Pt Pw Q Tr T Z Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia. Basic orifice factor Mcfd/ ~ hw/Pm Basic critical flow prover or positive choke factor Mcfd/psia Specific gravity factor, dimensionless Super compressibility factor = -~ 1/Z dimensionless Flowing temperature factor, dimensionless Specific gravity of flowing fluid (air = 1.00), dimensionless Specific Gravity of separator gas (air=1.00), dimensionless Gas-oil ratio, cu. ft. of gas (14.65 psia and 60° F.) per barrel oil (60° F) Meter differential pressure, inches of water Vertical depth corresponding to L, feet (TVD) Length of flow channel, feet (MD) Exponent (slope) of back-pressure equiation, dimensionless Field barometric pressure, psia Shut-in wellhead pressure, psia Shut-in pressure at vertical depth H, psia Static presssure at point of gas measurement, psia Reduced pressure, dimensionless Flowing pressure at vertical depth H, psia Flowing wellhead pressure, psia Static column wellhead pressure corresponding to Pt, psia Rate of flow, Mcfd (14.65 psia and 60°F.) Reduced temperature, dimensionless Absolute temperature, degrees Rankin Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the MANUAL OF BACK-PRESSURE TESTING OF GAS WELLS, Interstate Oil Compact Commission, Oklahoma City, Oklahoma Form 10-421 Rev. 7-1-80 kzV~,OGCCGAS.XLS CONTINUED ON REVERSE SIDE Submit in duplicate Well BC-9s, Beaver Creek Field Sterling B4 Deliverability, 8/5/98 1,000,000 100,000 10,000 1,000 / AOF = 96,289 MCFD n = 1.0 (assumed) 10,000 100,000 Q (MCFD) n:\drlg\bc\wells~bcg~aogcc02.xls ~ .... STATE OF ALASKA ALAS OIL AND GAS CONSERVATION COMM ION WELL COMPLETION OR RECOMPLETION REPORT AND LO 1. Status of Well Classification of Service We!!:; !_ 2 0 ~9(~ OILF'1 GASE~ SUSPENDEDF1 ABANDONEDr~ SERVICEr'--'] 2. Name of Operator 7. Permit NumberAli:t~Jt~ ~,),; ~ d ~.:, ',~,,- _. MARATHON OIL COMPANY 92-122 Ancr~0rage 3. Address 8. APl Number P. O. Box 196168, Anchorage. AK 99519-6168 50-133-20~5 4. Location of Well at Su¢ace ,~*~ 9. Unit or Lease Name 1188' FNL, 1568' FWL, Sec. 34, ~N, R10W, S.M. ~~:' J~:' ~ Beaver Creek Unit At top of Pr~ucing Inte~al , ~ j 10. Well Number 2829' FNL, 1286' FWL, Sec. 34, T7N, R10W, S.M. ~ 5629' MD~ BC-9s At Total Depth 11. Field and Pool . 2792' FNL, 1259' FWL, Sec. 34, T7N, R10W, S.M. ~ 8500' TVD Beaver Creek Field, Sterling 5; Elevation in f~t (indicate KB, DF, etc.) 16. Lease Designation and Serial No. 183' KBI A-028083 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or Aband. 115. Water Depth, if offshore ~16. No. of Completions 7/28/94 8/27/94 7/2/98~ N/A feet MSLJ ~o Directional Su~ey 12o. Depth where SSSV set J21. Thickness of Permafrost 17. Tolal Depth ~D) 18. Plug Back Depth ~D+~D) 19. Yes~No~ ~ 8881' MD, ~08' MD, I I N/A feet MD N/A 22. Type Electric or ~her Logs Run DIL, AlT, NGS, DSI, FMS, ~N, CET, TDT 23 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 13-3/8" 61 K-55 0 116' Driven N/A N/A 9-5/8" 47 N-80 0 1853' t 2-1/4" 700 sks N/A 7' 29 N-80 0 5950' 8-1/2" 565 sks N/A , 3-1/2" 9.2 L-80 5814 8881' 6" 500 sks N/A 24. Perorations open to Pr~uction (MD+TVD of Top and BoSom and 25. TUBING RECORD intewal, size and numar) SIZE DEPTH SET (MD) PACKER SET (MD) 3-1/2" 5825' 5825' Sterling B4: 5629' - 5~7' MD, 52~' - 5256' TVD, 4 spf ~6. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED N/A N/A 27. PRODUCTION TEST (3 U I f21~i ~ate First Production ~Method of Operation (Flowing, gas li~, etc.) , ~ ~ ~ ! ~ ~ I ~ 6/13/98 ~ Flowing Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE JGAS-OIL RATIO 6/13/98 2 TEST PERIOD ~ 0 ~1 0 14/64~ N/A FIowTubing Casing Pressure CALCU~TED OIL-BBL GAS-MCF WATER-BBL OIL GRAVIS-APl (corr) Press. 1800 psig N/A 2~HOUR RATE ~ 0 ~07 0 N/A 28. CORE DATA ~Hef description of lithology, porosi~, fractures, apparent dips and presence of oil, gas or water. Submit core chips. N/A Form 10-407 Submit in Triplicate Rev. 7-1-80 CONTINUED ON REVERSE SIDE n:\d rlg\bc\wells\bc9~aogcc02.xls 29. 30. GEOLOGIC MARKERS FORMATION TESTS Include interval tested, pressure data, all fluids recovered NAME MEAS. DEPTH TRUE VERT. DEPTH and gravity, GOR, and time of each phase. Sterling B-3 5467' 5086' Beluga 6264' 5884' Sterling B-4 5629' 5248' Tested interval from 5629' - 5637' MD for a total of 4 hours. Final tested rate for 2.5 hours was 4807 MCFD, 0 BWPD, 0 BCPD at 1800 psig FTP on a 14/64" choke. Completion is produced via the annulus of the 7" casing and 3-1/2" tubing. REC[IV[ JUL 2O 199[ 31. LIST OF ATTACHMENTS ~t~aska 0il ~ ~as Cons. Wellbore Diagram, Daily Operations Summary Anchorage 32. I hereby ce '~at the foregoing iNrue and correct to the best of my knowledge D nissJon INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1' Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pedinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.) Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other- explain. Item 28: If no cores taken, indicate "none". Form 10-407 Well BC-9, Beaver Creek Field Daily Operations Summary April 10 to July 2, 1998 Well BC-9 was recompleted from a single producer to a dual producer. The original BC-9 completion is now renamed well BC-91. The new completion, BC-9s, is produced via the annulus of the 7" casing and 3-1/2" tubing. Approval for this work was given via sundry approval #398-098. Below is a brief summary of the work performed. - Ran TDT and production logs in well BC-9. - Punched holes in tubing to allow circulation. - Move in workover rig. Killed well with 3% KCI. - N/U and tested BOPs. - Pull 3-1/2" tubing. - Make slickline gauge run to top of packer. TIH with tubing and tubing-conveyed guns. - Sting into packer. Set plug in tubing. - N/D BOPE. N/U and test tree. - Circulate completion fluid out of hole using nitrogen. - Apply tubing pressure to fire TCP guns. Move out workover rig. - Flow test well BC-9s up the 7" casing. - Attempt to unload well BC-91 (the original 3-1/2" tubing completion.) The well sanded up during flowback. - Move in coil tubing. Wash out sand and fill to PBTD. - Unload well BC-91 and flow test. Beaver Creek Field Well BC-9, Pad #3 Marathon Oil Co., Alaska Region KB-GL: 22.7' 1164' FNL & 1547' FWL Sec. 34, T7N, R10W API: 50-133-20445 1/4" Chemical injection line open to annulus at 1000' ~d · 13-3/8", 61#, K-55 Drive pipe @ 116' 9-5/8", 47#, L-80, BTC Casing @ 1853' Cmt w/700 sks Tubing: 3-1/2", 9.2#, L-80, AB-Mod. Butt Annular Completion Sterling B-4 5629' - 37' TDT (2" scallop, 4 spf, TCP) TCP Assembly @ 5638' Includes two AB-Mod. butt. by ST-L crossovers, Y-block, and 8' of 2" scallop guns Max. OD = 5.887" B-16 B-17 B-18 B-19 B-20 B-21 B-23 B-24 B-25 B-27 Camco KBMM side pocket mandrel @ 5698' 1" dummy valve installed Otix "X" Nipple @ 5765' 11)=2.813" Tubing Locator Sub @ 5826' 7420' - 7460' 7534'- 7574' 7640' - 7660' 7705' - 7755' 7762' - 7842' 7852'- 7882' 7893'- 7933' 7980'- 8030' 8036'- 8054' 8072' - 8098' 8167'- 8187' 8241' - 8246' 8254'- 8261' 8276' - 8292' 8399'- 8409' 8432'- 8452' (2-1/2" HC, 6 spf, 60°, 10.5 gm, 10/2/96) (2-1/2" HC, 6 spf, 60°, 10.5 gm, 9/30/96) (2-1/2" HC, 6 spf, 60°, 10.5 gm, 9/28/96) (2-1/2" HC, 6 spf, 60°, 10.5 gm, 9/26/96) (2-1/2" HC, 6 spf, 60°, 10.5 gm, 8/13/96) (2-1/2" HC, 6 spf, 60°, 10.5 gm, 8/5/96) (2-1/2" HC, 6 spf, 60°, 10.5 gm, 8/5/96) (2-1/2" HC, 6 spf, 10.5 gm, 9/24/94) (2-1/2" HC, 6 spf, 10.5 gm, 9/24/94) (2-1/2" HC, 6 spf, 10.5 gm, 9/24/94) (2-1/2" HC, 6 spf, 10.5 gm, 9/18/94) (2-1/2" HC, 6 spf, 10.5 gm, 9/16/94) (2-1/2" HC, 6 spf, 10.5 gm, 9/16/94) (2-1/2" HC, 6 spf, 10.5 gm, 9/16/94) (2-1/2" HC, 6 spf, 10.5 gm, 9/15/94) (2-1/2" HC, 6 spf, 10.5 gm, 9/15/94) Note: Whole core taken 6376' - 6454' MD & 7989' - 8109' MD. 8881' Baker model H packer @ 5814' TDT Baker Hyflo-lI liner hm~ger w/10' sealbore extension @ 5819' 7", 29#, N-80, BTC Casing @ 5950' Cmt w/565 sks in two stages Note: Beluga B-23 sand (7980' - 8098') frac stimulated with 92,000 lbs of 20/40 Carbolite pumped at 2 to 8 ppg on 11/5/94. Washed fill to 8450' CTM (7/2/98) Baker model "N" bridge plug @ 8808' 3-1/2", 9.2#, L-80, Butt. & AB-Mod Butt Liner 5814'- 8881' Cmt w/500 sks Last Rev: JGE, 7/10/98 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: David Jo h ns.b;x~;:::> DATE: Chairman THRU: FILE NO: Blair Wondzell, ~ P. I. Supervisor~67¢~ FROM' Lou Grimaldi, ~¢-'~ SUBJECT: Petroleum Ins~Sector June 7, A99JFGFE.DOC BOPE Test CC-1 Marathon BC-9 Beaver Creek PTD #92-O 122 Sunday, June 7, 1998: I witnessed the initial BOPE test on CC-1 which was preparing to work over Marathon well #BC-9 in the Beaver Creek unit. The rig was ready to test when I arrived and we began immediately. All BOPE equipment was tested with numerous flange leaks observed. The test spanned a time frame of 20 hours with actual test time of 13 hours. A seven hour down time was due to the mud pump engine failing to run and a Dowell unit was brought in to kill the well prior to changing the back pressure valve to a two way check in order to test the blind rams. The bottom pipe rams could not be tested due to the close proximity of the ram blocks to the neck on the tubing hanger and a upset 8 round connection. I allowed for the rig to test these after the hanger was pulled and a regular test plug run in its place. I found a spot in the choke line where a piece of four-inch pipe had been welded into a flange on a 20-degree angle (approx.) to clear the trip tank. I advised George Brewster that a targeted tee would be needed and the welder began work on straightening this line. Failures included the isolation valve on the choke manifold gas buster isolation valve, which ended up having to be replaced. The inside manual choke valve had a persistent small leak, which cleared up after greasing and cycling the valve two times. Flange leaks on the stack, choke and kill lines and choke manifold slowed the test considerably. The problem with the mud pump engine seemed to be probably a contaminated fuel problem but had not been fixed before I left. The Dowell unit was still on location and I requested before it was released a performance test on the rigs pumping capability be performed to insure the pumps would be ready if needed. A99JFGFE.DOC page I of 2 A99JFGFE.DOC page 2 of 2 The location was half covered with water due to all the rains we have been experiencing lately. The layout of equipment was good and a production test unit was being rigged up in order to clean this well up after the workover is finished. This rig is one of the older jackknife types and is in poor condition due to neglect over the years. George Brewster.(Inlet Drilling Toolpusher) worked very hard to keep the test moving along. This rig is leased to Inlet Drilling and Jerome Dodge (Owner) was on location and brought many replacement parts while I was there. There are plans to work this rig regularly this summer and it bears watching closely. ..~.- ~,.~ SUMMARY: I witnessed the initial test of the BOPE on CC-1 working over Marathon well # BC-9 in the Beaver Creek Field. There were Three major failures observed. Test time 13 hours. Attachments: A99JFGFE.XLS 06: Bill Barron (Marathon drilling supervisor) NON-CONFIDENTIAL STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: Drlg Contractor: Operator: Well Name: Casing Size: 7" Test: Initia Workover: X Inlet Drilling Rig No. CC-1 PTD # Marathon Oil Co. Rep.' BC-9 Rig Rep.' Set @ 5,950 Location: Sec.__ X Weekly Other DATE' 6/7/98 92-0122 Rig Ph.# 227-0421 Pete Berga George Brewster 34 T. 7N R. lOW Meridian Seward TEST DATA MISC. INSPECTIONS: Location Gen.: P Housekeeping: P (Gen) PTD On Location P Standing Order Posted NO Well Sign P Drl. Rig Poor Hazard Sec. N/A BOP STACK: Annular Preventer Pipe Rams Lower Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve Quan. Test Press. P/F 1 250/3,000 P 1 250/3,5OO P 1 250/3,500 P* f 250/3,500 P f 250/3,500 F f 250/3,500 P 2 250/3,500 P N/A 250/3,500 N/A MUD SYSTEM: Visual Alarm Trip Tank P P Pit Level Indicators P P Flow Indicator P P Meth Gas Detector P P H2S Gas Detector P P FLOOR SAFETY VALVES: Upper Kelly /IBOP Lower Kelly / IBOP Ball Type Inside BOP Test Quan. Pressure P/F 25O/3, 5OO 250/3,500 2 250/3,500 P 2 250/3,500 P CHOKE MANIFOLD: No. Valves No. Flanges Manual Chokes Hydraulic Chokes Test Pressure P/F 250/3, 500 F 30 250/3,500 F 1 P Functioned Functioned ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure 0 System Pressure Attained Blind Switch Covers: Master: Nitgn. Btl's: 2,950 P 2,500 P minutes 39 sec. minutes 13 sec. P Remote: P Four BoNes 2350 Average Psig. TEST RESULTS Number of Failures: 3 ,Test Time: 13.0 Hours. Number of valves tested 18 Repair or Replacement of Failed Equipment will be made within N/A days. otify the Inspector and follow with Written or Faxed verification to the A©GCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-3607 or 3687 If your call is not returned by the inspector within 12 hours please contact the P. I. Supervisor at 279-1433 REMARKS' Gas Buster isolation valve failed, replace and retest "OK". Flange leaks on stack and choke manifold all tightened and retested "OK". Need a check valve to isolate N2 backup from accumulator hydraufics, install by next test Distribution: orig-Well File c - Oper./Rig c- Database c- Trip Rpt File c - Inspector STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Witnessed By' Louis R. Grimaldi FI-021L (Rev. 12/94) A99jfgfe.xls g: ~cm n ~d rig ~bc~wells~bcg~,ogcc01 .)ds STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon Suspend__ Operation Shutdown Alter Casing Repair Well Plugging Change Approved Program Pull Tubing ~X Variance Re-enter Suspended Well Time Extension Stimulate Perforate X Other 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 1188' FNL, 1568' FWL, Sec. 34, TTN, R10W, S.M. At top of Productive Interval 2811' FNL, 1277' FWL, Sec. 34, 'i-/N, R10W, S.M. {~ 7039' TVD At Effective Depth 2800' FNL, 1270' FWL, Sec. 34, 'YTN, R10W, S.M. @ 7647' TVD At Total Depth 2792, FNL, 1259' FWL, Sec. 34, 'rTN, R10W, S.M @ 8500' TVD 5. Type of Well: Development X Exploratory Stratigraphic Service 6. Datum Elevation (DF or KB) 183' KB feet 7. Unit or Property Name Beaver Creek Unit · 8. Well Number BC-9 9. Permit Number 92-122 10. APl Number 50-133-20445 11. Field/Pool Beaver Creek Field, Steding & Beluga 12. Present Well Condition Summary Total Depth: measured true vertical Effective Depth: measured true vertical 8881 feet Plugs (measured) 8500 feet 8028 feet Junk (measured) 7647 feet Baker "N" bridge plug @ 8808' MD DUPLICATE Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: Length Size Cemented Measured Depth True Vedical Depth 116 13%", 61# Ddven 116 116 1853 9%", 47# 700 sks 1853 1725 measured true vertical Tubing (size, grade, and measured depth) 32,', 9.2#, L-80, AB Mod. Butt to 5814' Packers and SSSV (type and measured depth) Baker model H packer ~ 5814' with Hyflo-II liner hanger and sealbore extension 5950 7", 29~ 565 sks 5950 5555 3067 3'.~", 9.2~ 500 sks 8881 8500 7420' o 60', 7534' - 74', 7640' - 60', 7705' - 55', 7762, - 7842,, 7852' - 82', 7893' - 7933', 7980' - 8030', 8036' - 54', 8072' - 98', 8167' - 87', 8241' - 46', 8254' - 61', 8276' - 9Z, 8399' - 8409', 8432' - 52' 7039' - 79', 7153' - 93', 7259' - 79', 7324' - 74', 7381' - 7461 ', 7471' - 7501 ', 7512' - 52', 7599' - 7649', 7655' - 73', 7691' - 7717, 7786' - 7806', 7860' - 65', 7873' - 80', 7895' - 7911', 8018' - 28', 8051' - 71' 13. Attachments Description Summary of Proposal ~ Detailed Operations Program ~ BOP Sketch X , , 14. Estimated Date for Commencing Operation 15. Status of Well Classification as: 15-Ma~/-98 16. if Proposal was Verbally Approved Oil Gas X Name of Approver . Date Approved Service 7. I he at oregoing is true ah~ correct to the best of my knowledge. Sig ned '~/'~' k'~, ,r%~,-%"-~"~ (~,~. \ '~._~.~, Title Production Engineer FOR COMMISSION USE ONLY Conditions of Al~proval: % Notify Commission'So representative may witness ~Plug Integrity ~ Test V/ Location Clearance ~1 Integrity Test '~Subsequent Form Required 10- ¢~? ? Approved by Order of the Commission dnginal Signed By 0avid W. johnston Form 10-403 Rev. 0~/15/88 Date 4/6/98 Commissioner Submit in Triplicate Beaver Creek Field Well BC-9, AFE 8102298 Proposed Recompletion Procedure Purpose: Recomplete well BC-9 to produce the Sterling B-4 Sand up the tubing/casing annulus. The procedure also includes steps for detecting and isolating water production from the existing Beluga completion. Procedure: 1. Call out Cameron wellhead hand to test void on wellhead. Casing pressure should be bled to zero before testing void. 2. Using jumper hose from tubing, pressure test casing to SITP (between 2500 and 3000 psig). Record casing test on a chart recorder. Maintain pressure on casing. MIRU crew to shoot fluid level on casing annulus. Verify that annulus is full of liquid before arrival of logging unit. 3. MIRU slickline. Shut in well BC-9. Test BOPE and lubricator to SITP. RIH with 2'/2" impression block. Tag fill, POOH. RIH with 20' of dummy tools to TD. POOH, RDMO slickline. 4. MIRU electric line. Leave well BC-9 shut in. Test BOPE and lubricator to SITP using methanol. RIH with production logging suite (to be determined) with well shut in. Tag fill, and log up to 5500' DIL. When static logging is complete, open up well to production (at a rate to be determined). Make another logging pass up to 5700' with the well flowing. Make additional flowing logging passes as needed. POOH. RDMO electric line. 5. Confirm all pressure is bled from casing. Have pump truck rigged up on tubing on standby to kill well if needed. Use roustabouts to install 2", 5M gate valves on both sides of the tubing head (outlets to 7" casing). When complete, each side will have two gate valves on the casing from which flowlines will be run. 6. SI well BC-9 and allow tubing pressure to build overnight. Verify that casing pressure is zero. Test BOPE and lubricator to 4000 psig. RIH with electric line tubing punch to 5800'. Shoot holes in tubing at 5800' to equalize with casing. POOH, RDMO electric line. 7. Mix 500 bbl of 3% Kcl. RU pump truck on tubing. Test lines to 5000 psig. Circulate 3% Kcl fluid down casing and up tubing until well is dead. Do not exceed 2500 psig pump pressure. RDMO pump truck. 8. MIRU workover rig. Bleed down and disconnect control line. Set BPV in tree. ND tree, NU 7-1/16" 5M BOPs fitted with 3~A'' pipe rams. Send tree to Cameron for inspection and repair. Test BOPs to 5000 psig. Pull BPV. Beaver Creek #9 AFE 8102298 - Annular B-4 Recompletion April 8, 1998 Page 2 9. TOH with 3 ~5" tubing, strapping pipe while standing back in derrick. LD SCSSV, perforated joint and any other damaged joints of tubing. Redress packer seals and inspect X-nipple. 10. MIRU slickline. RIH with 6.000" gauge ring to packer at 5814' MD. POOH, RDMO slickline. a) If gauge ring does not pass, pick up 6" mill and 4~A'' motor and make scrapper trip to top of packer. 11. TII-I with tubing and accessories spaced out approximately as follows. The space out from the guns to the sealbore is critical. Include radioactive (RA) tag in collar one joint above TCP assembly. Record distance from RA tag to top perf. Perfs will be from 5636' to 5646' DIL. Include 1000' of chemical injection line (for annular methanol injection). Number of Length Depth Top Depth Bottom Joints tubing hanger 1.03 0.00 1.03 3 ½" tubing 181 5,625.00 1.03 5,626.03 TCP gun system 30.00 5,626.03 5,656.03 3½" tubing 2 52.00 5,656.03 5,708.03 sidepocket GLM (with ' 10.00 5,708.03 5,718.03 pressure valve installed) 3 ½" tubing 3 91.00 5,718.03 5,809.03 X-nipple 1.43 5,809.03 5,810.46 tubing Iocator sub 0.66 5,810.46 5,811.12 packer seals 17.35 5,811.12 5,828.47 12. Sting seals into model H packer at 5814'. Pressure test annulus to 500 psig to confirm seals are holding. Slack offtubing until locator sub contacts top of packer. Mark pipe. Beaver Creek #9 AFE 8102298 - Annular B-4 Recompletion April 8, 1998 Page 3 13. MIRU electric line. RIH with GR/CCL. Use gamma ray log to tie RA tag to open hole measurements. Space out tubing as necessary. Tubing will move upwards an estimated' 30" during gun firing procedure; ensure spacing provides for adequate seal engagement. POOH, RDMO electric line. 14. Pull seals out of sealbore, and install pup joints and tubing hanger. Attach chemical injection line to hanger. Land tubing hanger and test hanger seals to 4000 psig. 15. MIRU slickline. Set PX plug in X-nipple at 5809' MD. POOH, RDMO slickline. 16. MIRU nitrogen unit. Pressure up annulus to 2200 psig while taking returns up tubing through orifice valve at ±5708'. Once displaced, bleed casing pressure to 700 psig to achieve desired underbalance (approximately 1500 psi). RD nitrogen unit. Standby nitrogen unit until guns are confirmed to have fired. 17. Pressure up tubing to 2500 psig using 3% Kcl to shear firing head. Hold pressure for 30 seconds, then bleed tubing to zero. Monitor tubing and casing for signs of 2", 4 spf, 0° phase scallop guns firing. Guns are designed to fire in 6 to 7 minutes. 18. If positive indications of guns having fired, set BPV in tree. ND BOPs, NU and test 3-1/16", 5M tree. RDMO workover rig. Pull BPV from tree. a) If no indication of guns firing after 30 minutes, pump 3% Kcl down annulus. Do not exceed 2500 psig pump pressure on annulus. If there is still no indication of open perfs, pull PX plug, then pull tubing and TCP guns. Replace faulty components as necessary and rerun guns. 19. Line up BC-9 annulus (completion name BC-9a) to catch tanks. Attempt to unload well as per instructions of Production Engineer. a) If well ~vill not unload by itself, RU slickline to pull pressure valve at +5708'. Install circulating valve in mandrel, RDMO slickline. RU nitrogen, and pump nitrogen down the tubing and up the casing to unload annulus. RDMO nitrogen when annulus is flowing. 20. Hook up flowlines from BC-9a to production facilities. Produce and test as per Production .Foreman. 21. Shut in BC-9 annulus. MIRU 13¼" coil tubing and nitrogen unit. Test BOPE, lines, and valves to 4000 psig. RIH with coil tubing. Wash sand from 8000' to PBTD at 8808' Beaver Creek #9 AFE 8102298 - Annular B-4 Recompletion April 8, 1998 Page 4 taking returns to open-top catch tank. Use nitrogen and foam as needed. Note: Possibly want HIP-tripper and sand chisel. If necessary, at~er washing to PBTD use nitrogen to jet well in. POOH, RDMO coil tubing. 22. Open well BC-9 to production. Produce as per instructions of Production Foreman. 23. (Optional) RU electric line on tubing of BC-9. Test BOPE and lubricator to 3000 psig. MU tubing patch for 3 ~/-'' z2 , 9.2# tubing. RIH with patch. Set patch across interval previously defined as being water productive. POOH. RDMO electric line. G:\C~RLGX.BC\WELLSXBC9\TCP. W P D JGE - April 8, 1998 Beaver Creek Field Well BC-9, Pad #3 Marathon Oil Co., Alaska Region B-16 B-17 B-18 B-19 B-20 B-21 B-23 B -24 B-25 B-27 KB-GL: 27.7' 1164' FNL & 1547 F'~% Sec. 34, TTN, R 1 OW API: 50-133-20445 Otis XXO SCSSV with "X" Nipple profile (ID = 2.813") C~ 1012' Tubing: 3-1/2", 9.2#, L-80, AB-Mod Butt Otix "X" Nipple (¢ 5811' ID = 2.813" Tubing Locator Sub with 17' Seal Assembly ~ 5813' 60°, 10.5 gm, 10/2/96) 60°, 10.5 gm, 9/30/96) 60°, 10.5 gm, 9/28/96) 60°, 10.5 gm, 9/26/96) 60°, 10.5 gm, 8/13/96) 60°, 10.5 gm, 8/5/96) 60°, 10.5 gm, 8/5/96) 10.5 gm, 9/24/94) 10.5 gm, 9/24/94) 10.5 gm, 9/24/94) 10.5 gm, 9/18/94) 10.5 gm, 9/16/94) 10.5 gm, 9/16/94) 7420'- 7460' (2-1/2" HC, 6 spf, 7534'- 7574' (2-1/2" HC, 6 spt', 7640'- 7660' (2-1/2" HC, 6 spf, 7705'- 7755' (2-1/2" HC, 6 spf, 7762'- 7842' (2-1/2" HC, 6 spfi 7852'- 7882' (2-1/2" HC, 6 spfi 7893'- 7933' (2-I/2" HC, 6 spt', 7980'- 8030' (2-I/2" HC, 6 spf, 8036'- 8054' (2-1/2" HC, 6 spf, 8072'- 8098' (2-1/2" HC, 6 spf, 8167' - 8187' (2-1/2" HC, 6 spf, 8241'- 8246' (2-1/2" HC, 6 spf, 8254'- 8261' (2-1/2" HC, 6 spf, 8276'- 8292' (2-1/2" HC, 6 spt", 10.5 gm, 9/16/94) 8399'- 8409' (2-1/2" HC, 6 spf, 10.5 gm, 9/15/94) 8432'- 8452' (2-1/2" HC, 6 spf, 10.5 gm, 9/15/94) Note: Whole core taken 6376' - 6454' MD & 7989' - 8109' MD. X TD= 8881' ~, 13-3/8", 61#, K-55 Drive pipe @ 116' · 9-5/8", 47#, L-80, BTC Casing (~ 1853' Cmt w/700 sks Baker model H packer ~ 5814' Baker Hyflo-ll liner hanger w/10' sealbore extension @ 5819' 7", 29#, N-80, BTC Casing ~ 5950' Cmt w/565 s'ks in two stages Note: Beluga B-23 sand (7980' - 8098') frae stimulated with 92,000 lbs of 20/40 Carbolite pumped at 2 to 8 ppg on 11/5/94. Tagged fill ~ 8028' ELM (10/2/96) Baker model "N" bridge plug (¢ 8808' DIL 3-1/2", 9.2#, L-80, Butt. & AB-Mod Butt Liner 5814'- 8881' Cmt w/500 sks Last Rev: JGE,3/2/98 ---PROPOSED--- Beaver Creek Field Well BC-9, Pad #3 Marathon Oil Co., Alaska Region KB-GL: 27.7' 1164' FNL & 154T FWL Sec. 34, T7N, R10W API: 50-133-20445 Annular chemical injection line to +1000' Tubing: 3-1/2', 9.2//, L-80, AB-Mod. Butt Annular Completion Sterling B-4 5636' - 46' DIL (2" scallop. 4 spf. Otix "X" Nipple 6~. 5811' ID = 2.813" Tubing Locator Sub with 17' Seal Assembly @ 581Y B-16 B-17 B-18 B-19 B-20 B-21 B-23 B-24 B-25 B-27 7420'- 7460' (2-1/2' HC, 6 spf, 60°, 10.5 ~mn, 10/2/96) 7534'- 7574' (2-1/2" HC, 6 spf, 60°, 10.5 gm, 9/30/96~ 7640'- 7660' (2-1/2" HC, 6 spt; 60°, 10.5 gm, 9/28/96) 7705'- 7755' (2-I/2" ItC, 6 spf, 60°, 10.5 gm, 9/26/96) 7762'- 7842' (2-1/2" HC, 6 spf, 60°, 10.5 gm, 8/13/96) 7852'- 7882' (2-1/2' HC, 6 spf, 60°, 10.5 gm, 8/5/96) 7893'- 7933' (2-1/2" HC, 6 spt; 60°, 10.5 gm, 8/5/96) 7980'- 8030' (2-1/2' HC, 6 spf, 10.5 gut, 9/24/94) 8036'- 8054' (2-1/2' HC, 6 spf, 10.5 gm, 9/24/94) 8072'- 8098' (2-I/2" HC, 6 spf, 10.5 gm, 9/24/94) 8167'- 8187' (2-1/2' HC, 6 spt', 10.5 gm, 9/18/94) 8241'- 8246' (2-1/2" HC, 6 spf, 10.5 gm, 9/16/94) 8254'- 8261' (2-I/2" HC, 6 spf, 10.5 gm, 9/16/94) 8276'- 8292' (2-I/2" HC, 6 spfi 10.5 gm, 9/16/94) 8399'- 8409' (2-I/2" HC, 6 spf, I0.5 gm, 9/15/94) 8432'- 8452' (2-1/2" HC, 6 spf, 10.5 gm, 9/15/94) Note: Whole core taken 6376'- 6454' MD & 7989' - 8109' MD. TD= 8881' 13-3/8", 61//, K-55 Drive pipe @ 116' · 9-5/8", 47//, L-80, BTC Casing ~ 1853' Cmt w/700 sks TCP Assembly (~ 5626' Includes two AB-Mod. butt. by ST-L crossovers, Y-block, and 10' ofT' scallop gtuts Max. OD = 6.00" Camco side pocket GLM ~ 5708' Orifice valve installed Baker model H packer ~ 5814' Baker Hyflo-ll liner hanger w/10' sealbore extension (~ 5819' 7", 29//, N-80, BTC Casing @ 5950' Cmt w/565 sks in two stages Note: Beluga B-23 sand (7980' - 8098') frae stimulated with 92,000 lbs of 20/40 Carbolite pumped at 2 to 8 ppg on 11/5/94. Tagged fill @ 8028' ELM (10/2/96) Baker model "N" bridge plug @ 8808' DII. 3-I/2", 9.2//, L-80, Butt. & AB-Mod Butt Liner 5814'- 8881' Cmt w/500 sks Last Rev: JGE,3/2/98 WELL BC-9, BEAVER CREEK FIELD ANNULAR RECOMPLETION POTENTIAL PROBLEMS ADDRESSED Potential Problem Solution Erosional Velocity Corrosion Surface Safety Controls Burst/Collapse of Casing The highest potential for erosive flow exists at the 2-1/16", 5M flanged outlets of the tubing head. At initial flowing tubing pressure (i.e. 1900 psig) erosion can be expected to occur if sand- free flowrates exceed 24 MMCFD. This is a higher than the anticipated maximum initial flowrate of 15 MMCFD. Because the erosive threshold will change over the life of the completion, Marathon plans to conduct periodic UTT inspection of the wellhead and flowlines for signs of unusual wear. The CO2 content of the Sterling B-4 gas at Beaver Creek Field is approximately 0.25 mole-percent. Partial-pressure of CO2 at initial reservoir pressure is approximately 6 psi. If the partial pressures of CO2 is less than 7 psi the gas is generally considered noncorrosive. Furthermore, there is no H2S produced in the Beaver Creek Field. Corrosion of the casing is unlikely. The annular Sterling completion will be produced via a separate flowline from the existing Beluga completion. Surface safety controls will be similar to that of other Beaver Creek completions. Pressures imposed on the 7" casing during this procedure will not compromise the integrity of the casing. Worst-case forces will not exceed 64% of the rated casing burst or collapse. ~/98 ~0~ 12'54 F.~% 9075225558 DS~ FAX Date 4~6-98 I Number of ~age,~ i. noluding_ cover ~heet TO: Gary Eller Marathon Oil Co. Anchoraeg, Alaska Phone Fax Phone REF: 7" BOP ~ack FROM: Bruce Sprttler Swaco / DSR 721 West 1st A venue Anchorage, Ak. 99501 Phone 907-522-3234 Fax Phone 907-522-8568 ...... IREMARKS: Ga~, ~ Urgent For your review J--] Rel~fy ASAP [~ Please Comment Per your request please find the attached BOP stack schematic we discussed earlier. (1) (1) Shaffer 7 1/16-5M spherical (annuJar) BOP (1) Shaffer 7 1116-5M 'Chasavoy' double gate preventer, stud x stud, manual lock cylinders, 3 ~" rams top, blind rams bottom 7 1/16-5M drilJJng spool with (2) 3 118-5M flanged outlets (1) Shaffer 7 1116-5M 'Chasavey' single gate preventer7 stud x stud, manual tock cylinders, 3 %" rams Regards, Bruce Spittier ~, · i' ,' i I CViO K._~ ~iLN! POLl' H: tqqq ._ ,,_ ¢ '~ ¢)-I ' Alask' gion Dome. Production Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 February 5, 1997 Mr. Jack Hartz Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 RE: Multipoint Gas Well Tests Beaver Creek Unit Wells BCU-la ~d BCU-9 ¢.. Dear Jack: Attached in duplicate are copies of AOGCC Form 10-421 with results of multipoint tests for the above referenced gas wells. These multipoint tests are the first to be conducted following the recent completion of permitted activities for these wells. (Sundry completion notices for these activities were previously submitted.) If you have any questions or require additional information, feel free to contact me at 564-6327 Reservoir Engineer Alaska nil & :?,,as C.3ns. Cori;l-nissiorl Anchora~js LCI~' 'kz:H:'.WP" ENG, B CU4PT.WPD Attachments A subsidiary of USX Corporation Environmentally aware for the long run. -_ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT la. TEST: INITIAL ' X lb. TYPE TEST STABLILIZED ~ NON STABILIZED ANNUAL MULTIPOINT ~ CONSTANT TIME SPECIAL ISOCHRONAL 2. Name of Operator 7. Permit No. Marathon Oil Company 92-122 3. Address 8. APl Number 3201 C Street, Ste. 800, Anchorage, Alaska 99503-3934 50- 133-20445 4. Location of Well 9. Unit or Lease Name At surface Beaver Creek Unit 1188' FNL, 1568' FWL 10. Well Number Section 34, TTN, R10W, S.M. BCU-9 I11, Field and Pool Beaver Creek Field, Beluga 5. Elevation in feet 16. Lease Designation and Sedal No. 183' KBI A-.028083 12. Completion Date 113. Total Depth 114. Plugback T.D. 115. Type Completion (Describe) 9/18/94 8881 8808 (junk) Single tbg. stdngJcased holeJmonobore 16. Csg. Size Weight per foot, lb. I.D. in inches Set at ft. Perforations: From To 3.5" 9.2 2.992 8881 7420-7460 7762-7842 8038-8054 8254-8261 17. Tbg. Size Weight per foot. lb. I.D. in inches Set at ft. 7534-7574 7852-7882 8072-8098 8276-8292 7640-7660 7893-7933 8167-8187 8399-8409 3.5" 9.2 2.992 5~22 7705-7755 7980-8030 8241-8246 8432-8452 18. Packer set at ft. 119. GOR cf/bbl. 120' APl Liquid Hydrocarbons 21. Specific Gravity Flowing fluid (G) 5822I -I - 0.56 22. Producing thru: Reservoir Temp. °F. Mean Annual Temp. °F. Barometric Pressure (Pa), psia Tbg{-~ Csg.~-~ 121 33 14.73 24. Flow Data Tubing Data Casing Data Choke Prover Odfice Line Size X Size Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No.i (in.) (in.) psig hw °F. psig °F. psig °F. Hr. 1. 3.826 X n/a 676 2.5 70 2343 53 - - 0.750 2. 3.826 X nJa 729 4.55 69 2262 53 - - 0.800 3.1 3.826 X tva 784 6.5 69 2048 53 - - 0.800 4.! 3.826 X n/a 827 8.65 68 1742 53 - - 0.800 5.I × Basic Coefficient (24-Hour) hwPm Pressure Flow Temp. Factor Gravity Factor Super Comp. Factor Rate of Flow No. Fb or Fp Pm Ft Fg Fpv Q, Mcfd 1. 75.9 41.1 690.7 0.9905 1.336 1.1463 3,120 2. 102.4 57.6 743.7 0.9868 1.336 1.1463 5,897 3. 1 22.4 71.4 798.7 0.9840 1.336 1.1 438 8,736 4. 141.1 84.6 841.7 0.9786 1.336 1.1337 11,937 5. Pg. 125 GPSA Temperature for Separator Gas for Flowing Fluid No. Pr T Tr Z G~ G 1. 0.9912 530 1.545 0.761 0.56 2. 1.0689 529 1.542 0.7610 3. 1.1496 529 1.542 0.7644 Critical Pressure 682 4. 1.2126 528 1.539 0.7781 Critical Temperature 343 5. Form 10421 Rev. 7-1-80 kz~.~C, GAS.xls Page 1 Submit in duplicate Pc 2,711 Pc~ 7,349,521 Pf n/a PF 0 No. Pt Pt2 Pc~ - PF Pw Pw~ Pc~ - Pw~ Ps Ps~ PF - Ps~ 1. 2,343 5,489,649 1,859,872 - - - 0 0 2. 2,262 5,116,644 2,232,877 - - - 0 0 3. 2,048 4,194,304 3,155,217 - - - 0 0 4. 1,742 3,034,564 4,314,957 - - - 0 0 5. 0 0 25. AOF (Mcfd) 20,211 n 1.0000 Remarks: Temperatures under Flowing Data and Tubing Data are estimates; actual values ,,,,~re not recorded. 4--point test conducted on 12/21/96, using surface recorders only. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed /~-~)~ Title Reservoir Engineer Date 2/5/97 k. ,v... DEFINITIONS OF SYMBOLS AOF Fb Fp Fg Fpv Ft G Gg GOR hw H L n Pa Pc Pf Pm Pr Ps Q Tr t Z Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia. Basic odf'm..,e factor Mcfd/ hw/Pm Basic critical flow prover or positive choke factor Mcfd/psia Specific gravity factor, dimensionless Super compressibility factor = 1/Z dimensionless Flowing temperature factor, dimensionless Specif',:: gravity of flowing fluid (air = 1.00), dimensionless Specific Gravity of separator gas (air=1.00), dimensionless Gas-oil ratio, cu. ft. of gas (14.65 psia and 60° F.) per barrel oil (60° F) Meter differential pressure, inches of water Vertical depth corresponding to L, feet (TVD) Length of flow channel, feet (MD) Exponent (slope) of back-pressure equiation, dimensionless Field barernetdc pressure, psia Shut-in wellhead pressure, psia Shut-in pressure at vertical depth H, psia Static presssure at point of gas measurement, psia Reduced pressure, dimensionless Flowing pressure at vertical depth H, psia Flowing wellhead pressure, psia Static column wellhead pressure corresponding to Pt, psia Rate of flow, Mcfd (14.65 psia an,~ 60°F.) Reduced temperature, dimensionless Absolute temperature, degrees Rankln Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the MANUAL OF BACK-PRESSURE TESTING OF GAS WELLS, Interstate Oil Compact Commission, Oklahoma City, Oklahoma Form 10-421 Re¥. 7-1-80 kz~,OGCCGAS.xls Page 2 Submit in duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend__ Operation Shutdown Alter Casing Repair Well__ Plugging . Change Approved Program Pull Tubing Variance Re-enter Suspended Well Time Extension Stimulate X Perforate X Other 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 1188' FNL, 1568' FWL, Sec. 34, T7N, R10W, SM At top of Productive Interval 2830' FNL, 1287' FWL, Sec. 34, T/N, R10W, SM @ 7591' TVD At Effective Depth 2792' FNL, 1259' FWL, Sec 34, TTN, R10W, SM @ 8427' TVD At Total Depth 2792' FNL, 1259' FWL, Sec. 34, T7N, R10W, SM @ 8500' TVD 5. Type of Well: Development Exploratory Stratigraphic Service 6. Datum Elevation (DF or KB) 183' KB feet 7. Unit or Property Name Beaver Creek Unit $. Well Number BC-9 lO. APl Number 50- 133-20445 11. Field/Pool Beaver Creek Field, Sterling & Beluga 12. Present Well Condition Summary Total Depth: measured true vertical 8881 feet 8500 feet Plugs (measured) Effective Depth: measured true vertical 8808 feet 8427 feet Junk (measured) Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: measured true vertical Length 13-3/8" 9-5/8" 7~, 3-1/Z' Size 61# Cemented Driven 47# 575 SX 29~ 9.2/¢ 44O SX 500 SX See Attached Perforation Summary Measured Depth 116' 1853' 5950' 8881' True Vertical Depth 116' 1725' 5555' 8500' Tubing (size, grade, and measured depth) 3-1/2", L-80, 9.2~, 5824' Packers and SSSV (type and measured depth) Baker Liner Hanger w/Seal Bore Extension - 5814', SSSV - N/A 13. Attachments Description Summary of Proposal ~ Detailed Operations Program BOP Sketch 15. Status of Well Classification as: 14. Estimated Date for Commencing Operation 8/2/96 16. If Proposal was Verbally Approved Name of Approver Date Approved Oil Gas X Suspended Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~~;1 /~ Title Production Engineer FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so representative may witness Plug Integrity~ BOP Test ~ Location Clearance Mechanical Integrity Test Approved by Order of the Commission Form 10-403 Rev. 06/15/88 Approval No. Subsequent Form Required 10- /¢'o ~ Original Signed By David W. Johnston Anr~roved (]~1~/nissi°ner Returned 9 3/-- Submit in Triplicate Marathon Oil Company Wireline Work Request Well BC-9 Field/Platform: Beaver Creek Packer: Lease: A-028083 Site: Pad 3 Tbg: 5814' Baker liner hanger 3-1/2" L-80 9.2// Sand: B-23, 24, 25, 27L EOT: 5824' KB: 22.7' Min ID: 2.813" (1012', 5823') Est Start Date: 8/2/96 Est Comp Date: 9/2/96 Status: 4.0 mmscpfd, 5 bwpd, 2050 psig Fill depth: 8166' (4/3/96) Tree Connection: 3~1/2" 8rd OBJECTIVE: Perforate the Lower Beluga sands B15-21. Perform PBU analysis as necessary to determine fracture potential. Fracture stimulate zones as necessary. POTENTIAL PROBLEMS: IHyrdates, high pressure gas. Note: when returning BC-gto production, this well should be brought on line quickly to avoid hydrate formation in the tubing. LAST WELL WORK: 4/3/96 - PBU and 4 point. PROCEDURE: 1. Conduct safety and environmental meeting. Discuss procedure. 2. RU SWS. 3. Establish communication blackout. 4. MU 2-1/2" Hollow carrier guns, 6 spf, 60 phasing and perforate the following interval w/500-800 psig underbalance Interval Footage Comments 1 7893-7933' 40' B-21 2 7852-7882' 30' B-20 (Lower) 3 7812-7842' 30' B-20 4 7762~7812' 50' B-19 5 7705-7755' 50' B-19 6 7640-7660' 20' B-18 7 7534-7574' 40' B-17 8 7420-7460' 40' B-16 9 7384-7404 20' B-15 - may not be perf'd Note: each interval should be flow tested prior to perforating next interval. The above intervals may need to be frac'd based on flow test data. 5. RD SWS and clean up location. 6. Perform PBU and 4 point after well has stabilized. QUESTIONS/COMMENTS? Mike Olson, ext. 564-6315 APPROVALS: (Terry J. Kovacevich) Fax to KGF Foreman H :excel\wellwork\bc\bc-9\003 .xls .,','IARATH.'DN i-].T.L.~ ~HPANY BEAVER CF-t..:-E~< 7TEL'.b' WELL _9C-9 COMPLETED g/!~,/9~- &ti measuremenzs are RKB ~o Too o£ equipment (RKB= 82.68'). Comot¢~ion S±r;ng' Honge¢' 3-:/8 CIW 5S3, 8RD CUE top X AB Hod Butt bum Tubing: 5-!,/2". L-80. 9.2#, BTC Tbg w/AB-Mod Cplgs Casing Deta;~ 116' 13-3/85 K-55, 61~, (Driven) 1,853' 9-5/8% N-80, 47i4, BTC 5,950' 7', N-80, 29~, BTC 5.814'-8.881' 5-1/2". N-80, 9.2#. AB MO0-BTC 1,012' 2.815" 5,825' 2.815" 5,824' 2.992' 5.814' 2.992" OESCRIPTION OTIS XXO $CSSV Landing Nipple w,tn 2.81,5' X-profile. Otis "X" Nipple BoRer Locotor and 10' Seal Assembly (Iocotor 1' above SBE) Baker Liner Hanger (7" by 5") with Seal Bore Extension Below and Liner ToD Packer on Top. Packer Not Positively Set. Liner LoP Teste0 to ,5,000 psi With 8.4 ppg on 8/,51/94 Zone B-25 OERFORATIDNS [ntemvat 8.036'- 8.054' 8,072'- 8.098' 7,980'- 8.0~0' F_2t 18' 26' 50' B-24. B-25 B-27L ~.167' - 8,187' 8,241' - 8,246' 8,254' - 8.261' 8,276' - 8.292' 8,399'- 8,409' ~,452'- 8.452' 23' 7' 16' 10' 20' 8166' Fill tagged 4/3/96 ~,808' Baker "N" Bridge ..:lug set 9/14/94 PBTD 8,808' TD 8,851' A~oot,,, Oi! ~: f'::,:; C,::,I~;, C.': :ifi-;ts[;i0n ,Revision Dote: 9,/26/9~ Pevised By: ~R/evo Reason= Perforate PCevious Revision; 9/22/94 PERk~IT ---~ &OGCC Ind'¥ v'¥dua'i We i i Ge .2g'ic,-z..'i ~ater~a'is Ii]ver'Fh~Ol"y DATA T .E..,ATA_F'L L! S 92'"'i 22 ~267 T 8868-~5822 92---i22 ,,,~268 T 8868-'-'-85a. 7 92 ..... ~.,~.oo ~6269 1" 8875-~5878 92'-'-'i22 70 T 8880""8L~8~ 92~-'i22 ~1 T 8865-5882 92-'-- 122 ~T/SP L 5944--~8828 92--- I22 ~/VDL L. 2800--5770 92-~ 122 ~E'I~ L 2800-5770 92--'-- 122 ~L/SFL L 185a-~5967 F M S/A I T kl A I N LOG F I !.. E FMS/.&I'F REF'EAT FILE D S I biA I N LOG F ]i L E DSI REPEAT FILE LDS/APS/HNGS 92-.-'~ 22 ~,,,~rSI L. 594a.-~883a. 92.----- 122 ~.,,,~,sI L. 1854-5922 92-.-1"~2~. ~.~S L 5944-.-8860 92-...-122 ~ L 5944-~8881 92 "" 1 ~ ~ ~F ~ ~ /ARR/EPI/NE~T L 5944--8852 92---'I22 ~DT/CNL L 1854-5968 92 .... 122 ~T L 1854--~59~a. / 92.--'122 ~RF L 7900~-8264 92 ..... 122 ..,,~. E RF L 8050--8S00 ~.q2--. 129:_ o.,o.... 122 92 .... 122 v,,~'ERF L 8150~'8770 ~,--'LUG SETTING L 8650-~8808 ~DT---P L 5000-*8803 P E Rh'lI T DATA T DATA~.~,P L LIS Date' 06/C,i:}/Sit:, R Ul'.i DATrJ:..~.R i!(C VD Ar'e we'l 'l tests r'eqLl') Vle i i -i' s 'i' n comp 'i 'i' ar',ce I n -¥ t 'f a "i TRANSMITTAL AND ACKNOWLEDGEMENT OF RECEIPT TO: AOGC ANCHORAGE, AK MA TERIALS RECEIVED VIA: CORE LAB PERSONNEL ITEMS RECEIVED: CHIP SAMPLES FOR THE STATE FROM BEAVER CREEK #9 BOX 1 BOX2 BOX 3 6376-6404 FT 6405-6428 FT 6429-6455 FT Shipped by: PER~R~BRO,WN,.,/,/ for CORE LAB Date: 17-May-95 by: /~~~ ~ for~ /~~ Date: r~ r" Received /, ..... RE~.Ei ¥ Please note that the items listed above are inventoried, shipped and received in good faith, but due to errors, are subject to minor adjustments. In such case both shipper and receiver agree to make a timely and bona fide effort to correct any observed discrepancies.MA Y CORE LABORATORES 8005 SCHOON ST., ANCHORAGE, ALASKA 99518 (907) 3497&~¢~¢~~ Mil & 6as STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RE;COMPLIETION REPORT AND LOG 1. Status of Well Classification of Service Welt OIL ~ GAS..~ SUSPENDED ~ ABANDONED 2. Name of Operator Marathon Oil Company 3. Address P. O. Box 196168, Anchoraqe, Al< 99519-6168 4. Location of well at surface 1188' FNL, 1568' FWL, Sec. 34, T7N, RiOW, SM'. At Top Producing Interval 4~2830' FNL, 1287' FWL, Sec. 34, T7N, RIOW, SM At Total Depth 2792' FNL, 1259' FWL Sec 34 T7N RIOW SM SERVICE 7. Permit Number 92-122 8. APl Number so- 133-20445 9. Unit or Lease Name Beaver Creek Unit 10. Well Number DC-9 1 1. Field andPool Beaver Creek Field 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. Sterl lng & Del uga Gas Pool . 183.0 KB (MSL) I A-028083 12. Date Spudded 113. Date T.D. Reached I 14. Date Comp., Susp. or Aband. I 15. Water Depth, if offshore 16. No. of Completions 7 7-28-94 + I 8-27-94 ! 9-2-94 I N/A feetMSL ! 1 Depth 1. Total Depth (MD TVD)118. Plug Back Depth (MD+TVD)l 19. Directional Survey ] 20. whereSSSV set 21. Thickness of Permafrost 8881 & 8500 I 8808' & 8427 ,IYES [~ NO[] I N/Afeet MD I N/A 22. Type Electric or Other Logs Run DIL, AIT, NGS, DSI~ FMS, LAN, CET 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 116 Driven 13-3/8 g-5/a 61 47 K-55 N-80 ITOP 0 J 0 1853 7 29 N-80 0 5950 3-1/2 9.2 . N-80 5814 8881 24. Perforations open to Production (MD+TVD of Top and Bottom and interval, size and number) 12-1/4 N/A 575 SX Cement N/A N/A See Attached RE,,¢EiVED JAN 2 4 8-1/2 6 440 SX Cement 500 SX Cement N/A N/A 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD) 3-1/2 5824 5814 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT& KIND OF MATERIAL USED 27. Date First Production PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.) Flowina Date of TeBs~-1~-94 ~ Hours Tested 12/1/94I 24 Flow Tubing Casing Pressure Press. 2150 0 28. PRODUCTION FOR IOTL-BBL GAS-MCF TEST PERIOD II~IO 3740 CALCULATED I OIL~BBL GAS-MCF 24-HOUR RATE ~ 3740 coRE DATA WATER-BBL 34 WATER-BBL 34 ICHOKE SIZE GAS-OIL RATIO iN/A N/A OIL GRAVITY-APl (corr) Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. Beluga B2' SS; lt-dkgy, vfn-mgr, sa, m-w srtd, lithic, wkly consolidated, good porosit~v, alternating with carbonaceous mudstone Beluga B23' SS; m-dkgy, vfn-vcrs, sa, poor-msrtd, carbonaceous in part, wkly consolidated, poor-fair porosity, alternating with mudstone & silt; complete( gas zone. Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate 29. 30. NAME Sterling B3 Beluga GEQLQG C MARKLRS T! MEAS DEPTH ii TRUE VERT. DEPTH 5467' 5086' 6264' i! 5884' FORMATION TESTS Inclmde interval tested, pressure data, all fluids recovered and gravity, GOR, and time. of each phase. 31. LIST OF ATTACHMENTS Wellbore Diagram, Perfora_tion Summary, Operations ReEort Summary 32. I hereby certify that the foregoing is true and correct to the best of my knowledge , Directional Survey____ INSTRUCTIONS General' This form is designed for submitting a complete and correct well completion report and tog on all types of lands and leases in Alaska. Item 1' Classification of Service Wells' Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23' Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27' Method of Operation' Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28' If no cores taken, indicate "none". Form 10-407 v~.RATHON RTL COMPANY ~FAV~- r,': CREr._K ~,,/EL L .~C-9 COMPLETED 9/i$/94 measurements are RKO ~o top o? equipment (RKO= Comp~etlon String: Hanger: 3-1/P CIW DCB, 8RD EUE "cop X AB Mod Butt lot;m. Tubing: 3-1/2", L-80, 9.25. OTC Tbg w/AB-Mod Cplgs Casing Detail 1!6' 13-3/8', K-55, 61~ (Omiven) 1,853' 9-5/8', N-80, 47~, OTC 5,950' 7', N-80, ~9~, BTC 5,814'-8,881' 3-1/2", N-80, 9.2#, AB MOD-OTC DEPTH [.D_._~. 1,012' 2.813" 5,823' 2.813" 5,824' 2.992" 5,814' 2.992" DESCRIPTION OTIS XXO SCSSV Landing Nipple with 2.813" X-profile. Otis 'X" Nipple Baker Locator and 10' Seal Assembly (Iocator 1' above 5BE) Baker Liner Hanger (7" by 5") with Seal Bore Extension Below and Liner Top Packer on Top. Packer Not Positively Set. Liner Lap Tested to ,3,000 psi With 8.4- ppg on 8/31/94 Zone B-23 PERFORATIONS 7,980'- 8,030' 50' 8,036'- 8,054' 18' 8,072'- 8,098' 26' 9-24 8-25 B-27L 8,808' Baker "N" Bridge Plug set 9/14/94 PBTg 8,808' TD 8,881' 8.167'- 8,187' 20' 8,241'- 8,246' 5' 8,254'- 8,261' 7' 8,276'- 8,292' 16' 8,399'- 8,409' 10' 8,432'- 8,452' 20' RECEIVED JAN 2 4 1995 Alaska Oil & Gas Cons. Commission Anchor~ ? Revision :Date: 9/26/94 Revised By: VHR/evo Reasom Perforate Previous Revision, 9/22/94 BC-9 PERFORATION SUMMARY BELUGA ZONE ZONE I MD I ~D GUNSIZE I SPF B-23 7980-8030 7591-7649 2-1/2" 6 8036-8054 7655-7673 2-1/2" 6 8072-8098 7691-7717 2-1/2" 6 B-24 8167-8187 7786-7806 2-1/2" 6 B-25 8241-8246 7860-7865 2-1/2" 6 8276-8292 7895-7911 2-1/2" 6 B-27L 8399-8409 8018-8028 2-1/2" 6 8432-8452 8051-8071 2-1/2" 6 /nfs H:\WP\DRILL95\BC9123 Marathon Oil Company FINAL ENGINEERING REPORT BEAVER CREEK 9 BCBC-9 SECTION TWO DAILY OPERATIONS OPERATION SUMMARY REPORT WELL: BEAVER CREEK 9 BC DATE:: iii RPTi: DEPTH MUD ~T.~ ]DAILY opERATIONS SUMMARY 07/27/94 1 116 6.650 ACCEPTED RIG AT 0600 HRS 7/26/94. FILLED RIG WATER TANK AND PITS AND MIXED SPUD MUD. SPUDDED WELL AT 1500 MRS 7/26/94. CLEANED OUT DRIVE PIPE FROM 35' TO SHOE AT 85'. DRILLED 12.25" HOLE FROM 85' TO 105'. POOH. DROVE PIPE FROM 85' TO 116'(90' OF PENETRATION). CUT OFF DRIVEPIPE AND WELDED ON STARTING HEAD. STARTED N/U DIVERTER. 07/28/94 2 175 8.700 N/U DIVERTER AND DIVERTER SYSTEM AND FUNTION TESTED SAME. P/U BNA. DRILLED FROM 105' TO 175'. 07/29/94 3 624 9.150 DRILLED FROM 175' TO 559'. INJECTION WELL DC-3 PRESSURED UP. ATTEMPT TO INJECT WITH RIG PUMPS W/O SUCCESS. POOH. MADE BAILER RUNS ON DC-3 WITH SLICK LINE, RIGGED UP TO CATCH CUTTINGS. P/U DIRECTIONAL BHA AND RIH. DRILLED FROM 559' TO 624'. 07/30/94 4 1866 9,500 DRILLED AND SURVEYED FROM 624' TO 1710'. LOST RIG POWER, RESTORED SAME, CBU. DRILLED FROM 1710' TO 1886', CBU. SHORT TRIPPED TO 150' CIRCULATE AND CONDITION MUD TO RUN CASING. 07/31/94 5 1866 9.500 POOH, L/D BHA. R/U AND RUN 9 5/8" CASING TO 1858', CIRCULATED AND CONDITIONED MUD. CEMENT CASING WITH 700 SX CEMENT. WOC. R/U AND RUN TEMPERATURE LOG. 08/01/94 6 1866 9.500 FINISHED RUNNING TEMPERATURE SURVEY. N/D DIVERTER. CUT CASING AND N/U AND TESTED CASING SPOOL. N/U BOP'S. 08/02/94 7 1866 9.500 NIPPLE UP AND TEST BOP'S. 08/03/94 8 2635 9.550 FINISHED TESTING BOPS. P/U BHA AND RIH. TESTED CASING. DRILLED FLOAT EQUIPMENT AND FORMATION TO 1876'. CBU. TESTED SHOE TO 12.0PPG. DRILLED AND SURVEY FROM 1876' TO 2635'. 08/04/94 9 3180 9.750 DRILLED FROM 2635' TO 3158'. CBU. POOH FOR BHA. REPLACED CLUTCH ON #1 MOTOR. RIH. DRILLED FROM 5158' TO 3180', 08/05/94 10 4361 9.400 REPAIRED MUD LINE. DRILLED FROM 3180' TO 4243'. MADE WIPER TRIP. DRILLED FROM 4243' TO 4361' 08/06/94 11 5331 9.450 DRILLED FROM 4361' TO 4669', CBU. POOH, P/U MOTOR AND NE!W BIT. RIH, DRILLED FROM 4669' TO 5331' 08/07/94 12 5965 9.400 DRILLED FROM 5331' TO 5965'. CBU. POOH, HOLE TIGHT. PUMPED OUT OF HOLE FROM 5407' TO 4551'. CBU. POOH. BHA. M/U REAMING ASSEMBLY, RIH TO 4418'. STARTED WASHING AND REAMING, 08/08/94 i3 5965 9.450 WASHED AND REAMED FROM 4480' TO 5965'. CBU. MADE 15 STAND WIPER TRIP. CBU. POOH TO LOG. 08/09/94 14 5965 9.500 POOH. R/U E LINE. LOG RUN #1. DIT E/DSI/GR FROM 5965'-1858'. RUN #2. FDC/CNL/NGT FROM 5965'-1858'. R/O. RIH TO 5965', CIRCULATED AND CONDITIONED MUD. POOH TO RUN CASING. RECEIVED JAN 2 4 1995 A!a~ka Oil & Gas Cons. Commission /~nnhnr~ .. OPERATION SUMMARY REPORT WELL: BEAVER CREEK 9 BC DATE:: ~: ]RPT' DEPTH MUD WT. DAILY OPERATIONS SUMMARY 08/10/94 15 5965 9.500 FINISHED POOH BREAKING CONNECTIONS. L/D BHA. PULLED WEAR BUSHING. INSTALLED 7" CASING RAMS AND TESTED TO 2000 PSI. RAN 139 JTS OF T" CASING WITH SHOE AT 5950'. CIRCULATED AND CONDITIONED MUD. CEMENTED FIRST STAGE WITH 90 SACKS OF LEAD AND 125 SACKS OF TAIL. CIP AT 0415 HRS. CIRCULATED AND WOC. 08/11/94 16 5965 9.500 CIRCULATED AND WOC. CEMENTED SECOND STAGE WITH 350 SACKS. CIP AT 11:14 HRS. L/D DRILL PIPE. CUT CASING. STARTED INSTALLING TUBING SPOOL. 08/12/94 17 5965 9.400 INSTALLED TUBING SPOOL. TESTED PACKOFF. N/U AND TESTED mOP'S. CLEANED PITS. M/U BHA AND STARTED RIH PICKING UP 3-1/2" DRILL PIPE. 08/13/94 18 5986 9.450 RIH. TAGGED STAGE COLLAR AT 4489'. TESTED CASING TO 3000 PSI. DRILLED STAGE COLLAR. RIH TO FLOAT COLLAR AT 5862. TESTED CASING TO 3000 PSI. DRILLED FLOAT EQUIPMENT, CEMENT AND 9' NEW FORMATION TO 5986'. TESTED SHOE TO 14 PPG EMW. STARTED CLEANING PITS AND MIXING PHPA MUD FOR DISPLACEMENT. 08/14/94 19 6376 9.600 CLEANED PITS AND MIXED PHPA MUD SYSTEM. DISPLACED HOLE WITH PHPA MUD SYSTEM. DRILLED FROM 5986' - 6376'. SHORT TRIPPED BEFORE CORING. 08/15/94 20 6395 9.650 SHORT TRIPPED TO SHOE. POOH. P/U 60 FT CORING ASSEMBLY. RIH. CORED 6376' - 6395'. CORE JAMMED. POOH. L/D CORE. PREPARE TO RIH WITH CORING ASSEMBLY. 08/16/94 21 6454 9.700 L/D 19' CORE (FULL RECOVERY). RIH WITH 60' CORE BARREL. CORED 6395' - 6454'. CBU. 08/17/94 22 6769 9.950 POOH. L/D CORE (FULL RECOVERY). RIH. HIT TIGHT SPOT AT 6279'. P/U KELLY. HAD 3000 UNITS GAS WHILE CIRCULATING. S/I WELL WITH ZERO PRESSURE. CIRCULATED OUT GAS AND WEIGHTED UP TO 9.9 PPG. WASHED AND REAMED FROM 6279' - 6454'. DRILLED FROM 6454' - 6769'. 08/18/94 23 7205 9.950 DRILLED FROM 6769' TO 6898'. CBU. MADE WIPER TRIP TO SHOE. REAMED TIGHT HOLE. DRILLED FROM 6898' TO 7205' 08/19/94 24 7284 9.950 DRILLED FROM 7205' TO 7248'. CBU. POOH TO SHOE. HOLE TIGHT. PUMPED SLUG AND POOH. BHA. TESTED BOPS. BHA. RIH TO SHOE. RIH REAMING TIGHT SPOTS. DRILLED FROM 7248' TO 7284'. 08/20/94 25 7765 9.850 DRILLED FROM 7284' TO 7462'. CBU. DROPPED SURVEY. POOH TO SHOE. RETRIEVED SURVEY. 1 DEGREE. RIH. DRILLED FROM 7462' TO 7765' 08/21/94 26 7989 9.950 DRILLED FROM 7765' TO 7819'. CBU. WIPER TRIP TO SHOE. DRILLED TO 7986'. CBU FOR SAMPLES. DRILLED TO 7989'. CBU. WIPER TRIP TO SHOE. CIRCULATED HOLE CLEAN. DROPPED SURVEY. POOH. M/U CORING ASSEMBLY. RECEIVED JAN 2 4 1995 A!ask~ 0il & Gas Cons. Commission OPERATION SUM1WARY REPORT WELL: BEAVER CREEK 9 BC DATE:il RPT DEPTH ]MuD WT. DAILY OPERATIONS'SUMMARY 08/22/94 27 8049 9.950 RIH. DROPPED BALL AND SPACED OUT. CORED FROM 7989' TO 8049'. CBU. POOH. L/D CORE BARRELS. 08/23/94 28 8101 10.000 L/O CORE BBLS AND RECOVERED CORE. 100% RECOVERY. DRESSED AND M/U CORE BBLS. RIH WITH CORING ASSEMBLY. CBU. CORED FROM 8049' TO 8101' 08/24/94 29 8288 10.000 CORED FROM 8101' TO 8109'. CBU. POOH. L/D CORE BBLS. FULL RECOVERY. M/U DRILLING BHA. RIH. REAMED FROM 7989' TO 8109'. DRILLED FROM 8109' TO 8288'. 08/25/94 30 8608 10.000 DRILLED FROM 8288' TO 8297'. MADE 10 STAND WIPER TRIP. DRILLED FROM 82971 TO 8486'. MADE 10 STAND WIPER TRIP. DRILLED FROM 8486' TO 8608' 08/26/94 31 8683 10.000 DRILLED FROM 8608' TO 8613'. ROTARY TABLE LOCKED UP. CBU. POOH. TESTED BOP'S. CHANGED OUT ROTARY TABLE. M/U BIT #10 AND RIH. DRILLED FROM 8613' TO 8683'. 08/27/94 32 88~1 9.900 DRILLED FROM 8683' TO 8773'. CBU. MADE 10 STD SHORT TRIP. DRILLED FROM 8773' TO 8881'. CBU. SHORT TRIPPED TO SHOE. CBU. STARTED POOH TO LOG. 08/28/94 33 8~1 9.900 FINISHED POOH. R/U E LINE AND RAN AIT FMS GR SP FROM 8868' TO 5944'. RAN IPLT FROM 8868' TO 5944'. R/D E LINE. RIH, HAD 15' OF FILL. WASHED FILL AND CIRCULATED. STARTED POOH. 08/29/94 34 8881 9.900 FINISHED POOH. R/U E LINE AND RAN DIPOLE SONIC IMAGER FROM 8868' TO TO 5944'. RIH AND SHOT 39 SWC'S, FULL RECOVERY. RIH, HAD 12' OF FILL CBU. STARTED POOH. 08/30/94 35 8881 10.000 FINISHED POOH. R/U AND RUN 3 1/2" LINER TO 8881'. CIRCULATED AND CONDITIONED MUD. CEMENTED WITH 500 SX. RELEASED FROM HANGER AND CIRCULATED OUT 150 SX CEMENT. POOH. RIH WITH CEMENT BOND LOG TOOLS. 08/31/94 36 8881 8.400 FINISHED RUNNING CEMENT BOND LOG. RIH WITH SEALS, STUNG INTO PACKER AND TESTED SEALS. DISPLACED MUD WITH FRESH WATER. POOH, LAYING DOWN DRILL PIPE. 09/01/94 37 8881 0.000 L/D BHA. RAN 187 JOINTS OF 3.5" TUBING EXTERNALLY TESTING TO 5000 PSI. STUNG IN AND TESTED SEALS TO 500 PSI. CIRCULATED AND INHIBITED FLUID. SPACED OUT AND M/U TUBING HANGER. LANDED HANGER AND TESTED BACKSIDE TO 2000 PSI. SET BACK PRESSURE VALVE. N/O BOPS. 09/02/94 38 0 0.000 FINISHED N/D BOPS. N/U AND TESTED TREE TO 5000 PSI. CLEANED MUD PITS. MOVED CATWALK, L/D V DOOR RAMP AND REMOVED WINOWALL FOR COIL TUBING WORK. RIG OFF HIRED AND ON LUMP SUM DEMOB AT 2400 HRS. 9/1/94 OPERATION SUMMARY REPORT WELL: BEAVER CREEK 9 BC DATE: :: RPT: DEPTH MUDiWT: DAILY OPERATIONS] SUMMARY . 09/05/94 59 0 0.000 DUMPED AND CLEANED CUTTINGS CONTAINERS. R/U COIL TUBING. TESTED COIL AND BOPS TO 4000 PSI. RIH. TAGGED UP AT 883T'. CIRCULATED LINER AND TUBING CLEAN. TESTED LINER TO 3000 PSI. BLED TO 2700 PSI ILN 5 MINUTES. DISPLACED WITH 6% KCL. POOH WITH COIL TUBING TO 4500'. BLE¥/ TUBING DRY WITH NITROGEN. POOH. R/D. CLEANED AUXILLARY TANK. 09/04/94 40 0 0.000 SHOVELED OUT CELLAR. LOADED OUT MISCELLANEOUS EQUIPMENT. PUMPED STANDING WATER OFF OF LOCATION LINER INTO INJECTION TANK. 09/05/94 41 0 0.000 CLEANED TANKS FOR DEMOB. 09/06/94 42 0 FINAL REPORT. DEMOB RIG. BC-9 POST-RIG OPERATIONS SUMMARY 12/6/94 , Perforated and tested Beluga intervals as follows. Ail perforating guns 2.5", 6 SPF, 60 degree phased. DATE ZONE INTERVAL COMMENTS 9/15/94 B-27L 8432-8452 8399-8409 BLED TBG TO ZERO, NO INFLOW. FL=4300 FT. 9/16/94 B-25 8276-8292 8241-8246 8254-8261 BLED TO ZERO WITH SLIGHT BLOW. BUILDS 100 PSI/HR. 9/18/94 B-24 8167-8187 BUILT 200 PSI/HR IMMEDIATELY AFTER PERF. ROCKED WELL & RECOVERED 28 BBLS WATER. WELL BUILDS 375 PSI/HR NOW. FLOWING TO SYSTEM 9/20/94 AT 150 MCFD & INCREASING, TP=600 PSI. RAN SURFACE PBU 9/23.DATA LOOKED GOOD, KH=2.23 MD- FT, S=-0.40. 9/24/94 9/25/94 B-23 8072-8098 8036-8054 B-23 7980-8030 RECEIVED .Oil.& Gas Cons. Commissior~ Anchor - BRIEF ATTEMPT MADE TO FLOW. BLED TUBING PRESS FROM 2400 TO 1600, DROPPED RAPIDLY & S/I FOR NEXT PERF RUN. BLED TP AT 300 MCFD RATE. TP DROPPED TO 1290 & STARTED CLIMBING. 9/28/94 WAS +-350 MCFD W/1600 PSI. RAN DOWNHOLE PBU 9/30/94. POOR DATA, CHU GUESSES NO SKIN. DROPPED FTP & RECOVERED MORE WATER. RATE 800 MCFD WITH 1650 PSI FTP. SANDED BACK TO BASE OF B-23 FOR FRACTURE TREATMENT. 2. 9/30/94 - 10/4/94 Run pressure build-up survey on slickline. o o . . o 10/20/94 - 10/26/94 R/U CTU and plug back perforations with sand from PBTD to 8,801' 10/31/94 - 11/9/94 Fracture stimulated the B-23 Sand with 97,000 lbs 20-40 carbolite. Cleaned out sand with coiled tubing to 8,800'. Unloaded well with nitrogen. 11/9/94 - 11/12/94 Flowed well at varing rates from 1 - 3 MMCFD. Hydrates plugged tubing string and well S/I. 11/15/94 - 11/20/94 Attempted to clear hydrate plug using wireline without success. 11/23/94 - 11/25/94 Cleared Hydrate Plug using coiled tubing. RECEIVED d/-",[,! 2 4 1995 ~..b.s~"a Oil & Gas Cor~s. Cormnissiort Anchon RECEIVED DEC 2 8 1994 ALASKA REGION DRILLING DEPARTMEN'i' NARATHON OiL Company Pad #3 BC-9 slot ~/9 Beaver Creek Unit Kenai, Alaska SURVEY LISTING by Baker Hughes INTEQ Your ref : Schlumberger <5943-8858'> Our ref : svy4531 License : Date printed : 14-Dec-94 Date created : 14-Dec-94 Last revised : 14-Dec-94 Field is centred on n60 38 50.050,w150 59 49.92 Structure is centred on n60 38 50.050,w150 59 49.92 Slot location is n60 39 30.340,w151 1 4.480 Slot Grid coordinates are N 2434003.281, E 317381.884 Slot local coordinates are 4091.92 N 3716.14 W Reference North is True North MIC OFIL 4ED ORIGINAL MARATHON Oil Company SURVEY LISTING Page 1 Pad #3,BC-9 Your ref : Schlumberger <5943-8858'> Beaver Creek Unit,Kenai, Alaska Last revised : 14-Dec-94 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D ! N A T E S Deg/lOOFt Sect 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 452.00 0.20 136.10 452.00 0,57 S 0.55 E 0.04 0.43 604.00 0.20 142.40 604.00 0,97 S 0.89 E 0.01 0.74 693.00 0.40 186.70 693.00 1.40 S 0.95 E 0.33 1.14 782.00 1.30 170.90 781.99 2.71 S 1.07 E 1.04 2.39 871.00 3.40 183.60 870.91 6.34 S 1.07 E 2.42 5.92 963.00 6.70 196.90 962.54 14.20 $ 0.66 W 3.78 13.97 1055.00 9.90 193.40 1053.56 27.03 S 4.06 W 3.52 27.24 1147.00 13.90 191.30 1143.57 45.57 S 8.06 W 4.37 46.20 1239.00 16.20 190.20 1232.41 69.04 S 12.50 W 2.52 70.06 1332.00 19.30 188.10 1320.97 97.03 S 16.96 ~ 3.40 98.32 1424.00 21.40 187.40 1407.22 128.73 S 21.26 ~ 2.30 130.16 1516.00 24.00 187.40 1492.09 163.93 S 25.84 ~ 2.83 165.47 1609.00 26.70 188.10 1576.13 203.38 S 31.22 ~ 2.92 205.10 1702.00 29.80 187.40 1658.04 246.99 S 37.14 ~ 3.35 248.90 1816.00 29.10 187.80 1757.31 302.55 S 44.55 ~ 0.64 304.67 1913.00 29.40 188.10 1841.94 349.49 S 51.10 g 0.34 351.86 2022.00 30.00 187.10 1936.62 403.02 S 58.24 W 0.71 405.59 2113.00 30.60 186.40 2015.19 448.61 S 63.64 ~ 0.76 451.20 2206.00 31.00 186.40 2095.08 495.94 S 68.94 ~ 0.43 498.48 2300.00 31.00 187.10 2175.65 544.01 S 74.64 ~ 0.38 546.57 2390.00 31.60 186.40 2252.55 590.44 S 80.13 ~ 0.78 593.02 2482.00 32.00 186.40 2330.74 638.62 S 85.53 ~ 0.43 641.14 2573.00 31.90 187.10 2407.96 686.44 S 91.19 W 0.42 688.98 2665.00 32.00 187.40 2486.02 734.74 S 97.34 ~ 0.20 737.39 2757.00 31.30 187.40 2564.33 782.61 S 103.55 g 0.76 785.41 2852.00 31.50 187.40 2645.42 831.70 S 109.93 ~ 0.21 834.64 2942.00 31.70 188.50 2722.08 878.40 S 116.45 ~ 0.68 881.59 3033.00 31.60 188.10 2799.54 925.65 S 123.34 W 0.26 929.16 3126.00 31.80 188.10 2878.67 974.03 S 130.23 W 0.22 977.82 3219.00 31.20 188.10 2957.96 1022.14 S 137.08 W 0.64 1026.21 3311.00 29.40 188.80 3037.39 1068.05 S 143.89 ~ 1.99 1072.46 3404.00 27.70 188.80 3119.08 1111.97 S 150.69 W 1.83 1116.77 3497.00 26.40 188.80 3201.91 1153.77 S 157.16 ~ 1.40 1158.93 3588.00 24.70 191.30 3284.01 1192.41 S 163.98 ~ 2.21 1198.10 3680.00 24.30 192.00 3367.72 1229.77 S 171.68 ~ 0.54 1236.23 3772.00 23.50 192.70 3451.83 1266.18 $ 179.65 ~ 0.92 1273.50 3861.00 22.70 193.80 3533.70 1300.17 S 187.65 ~ 1.02 1308.42 3954.00 21.30 193.40 3619.92 1334.03 S 195.84 W 1.51 1343.25 4045.00 20.60 193.40 3704.91 1365.68 S 203.38 g 0.77 1375.79 4136.00 19.50 193.40 3790.39 1396.03 S 210.62 g 1.21 1406.99 4228.00 19.50 194.80 3877.12 1425.81 S 218.10 g 0.51 1437.70 4318.00 18.80 195.20 3962.13 1454.33 S 225.74 ~ 0.79 1467.20 4410.00 18.40 195.90 4049.33 1482.60 S 233.60 g 0.50 1496.53 4502.00 17.90 194.80 4136.75 1510.24 S 241.19 g 0.66 1525.17 4593,00 17.50 194,50 4223.44 1537.00 S 248.19 W 0.45 1552.83 4703.00 15.60 195.50 4328.88 1567.27 S 256.28 ~ 1.75 1584.14 4794.00 12.40 198,00 4417.17 1588.36 S 262.57 g 3.58 1606.12 4887.00 10.20 197,30 4508.36 1605.72 S 268.11 W 2.37 1624.28 4980.00 8.20 197.60 4600.16 1619.90 S 272.56 ~ 2.15 1639.11 RECEIVED d' 2 4- 19 Alaska Oil & 6as Cons. Commission Anchorc All data is in feet unless otherwise stated Coordinates from slot ~ and TVD from RKB (185.10 Ft above mean sea level). Vertical section is from wellhead on azimuth 193.32 degrees. Declination is 0.00 degrees~ Convergence is -0.87 degrees, Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ MARATHON Oil Company Pad #3,BC-9 Beaver Creek Unit,Kenai, Alaska SURVEY LISTING Page 2 Your ref : Schlumberger <5943-8858'> Last revised : 14oDec-94 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D ! N A T E S Deg/lOOFt Sect 5072.00 5.80 198.00 4691.47 1630.58 S 275.98 W 2.61 1650.29 5165.00 3.70 197.60 4784.14 1637.91 S 278.34 W 2.26 1657.97 5259.00 1.60 202.50 4878.04 1642.02 S 279.76 ~ 2.24 1662.29 5352.00 0.50 322.80 4971.02 1642.89 S 280.50 ~ 2.04 1663.31 5446.00 0.50 336.80 5065.02 1642.19 S 280.91 ~ 0.13 1662.72 5540.00 0.40 319.60 5159.02 1641.56 S 281.29 ~ 0.18 1662.20 5634.00 0.50 311.90 5253.02 1641.04 $ 281.81 W 0.12 1661.81 5728.00 0.50 314.30 5347.01 1640.48 $ 282.40 ~ 0.02 1661.40 5823.00 0.50 299.20 5442.01 1639.98 S 283.06 ~ 0.14 1661.07 5923.00 0.60 298.20 5542.00 1639.52 S 283.91 ~ 0.10 1660.82 5943.00 0.40 207.99 5562.00 1639.54 $ 284.03 ~ 3.62 1660.86 6000.00 0.50 325.71 5619.00 1639.51 S 284.26 W 1.36 1660.89 6100.00 0.78 283.22 5719.00 1638.99 $ 285.18 ~ 0.54 1660.59 6200.00 0.62 320.06 5818.99 1638.42 $ 286.19 g 0.47 1660.27 6300.00 0.61 320.11 5918.98 1637.60 S 286.88 ~ 0.02 1659.63 6400.00 0.87 35.11 6018.98 1636.57 S 286.78 ~ 0.92 1658.61 6500.00 0.59 341.54 6118.97 1635.46 S 286.51 W 0.70 1657.47 6600.00 0.66 317.85 6218.96 1634.55 S 287.06 W 0.26 1656.70 6700.00 0.82 336.70 6318.96 1633.46 S 287.73 ~ 0.29 1655.80 6800.00 0.73 10.67 6418.95 1632.18 S 287.89 ~ 0.46 1654.59 6900.00 1.00 318.33 6518.94 1630.90 S 288.35 ~ 0.80 1653.45 7000.00 0.93 339.15 6618.92 1629.48 S 289.22 W 0.36 1652.27 7100.00 0.83 333.28 6718.91 1628.08 S 289.84 ~ 0.14 1651.05 7200.00 1.06 21.38 6818.90 1626.56 S 289.83 ~ 0.80 1649.57 7300.00 1.06 332.20 6918.88 1624.88 S 289.92 W 0.88 1647.96 7400.00 0.84 319.89 7018.87 1623.50 S 290.82 ~ 0.29 1646.82 7500,00 1.22 307.78 7118.85 1622.29 S 292.14 ~ 0.44 1645.94 7600.00 1.41 340.55 7218.83 1620.47 S 293.39 ~ 0.76 1644.47 7700.00 1.46 319.57 7318.80 1618.35 S 294.63 ~ 0.52 1642.68 7800.00 1.37 311.44 7418.77 1616.59 S 296.35 ~ 0.22 1641.37 7900.00 1.49 18.03 7518.74 1614.56 S 296.84 ~ 1.57 1639.51 8000.00 1.79 311.56 7618.71 1612.28 S 297.61 W 1.82 1637.47 8100.00 1.35 291.91 7718.67 1610.81 S 299.88 ~ 0.69 1636.56 8200.00 1.30 283.58 7818.64 1610.10 $ 302.07 W 0.20 1636.37 8300.00 1.31 314.73 7918.62 1609.03 S 303.99 ~ 0.70 1635.77 8400.00 1.26 280.05 8018.60 1608.03 S 305.89 ~ 0.77 1635.24 8500.00 1,18 307.87 8118.58 1607.20 S 307.79 W 0.59 1634.87 8600.00 1.03 333.04 8218.56 1605.77 S 309.01 ~ 0.50 1633.76 8700.00 0.38 340.84 8318.55 1604.65 S 309.53 W 0,66 1632.79 8800.00 0.51 31.36 8418.55 1603.95 S 309.40 ~ 0.40 1632.08 8858.00 0.01 133.08 8476.54 1603.73 S 309.26 ~ 0.89 1631.84 RECEIVED jA['I 2 4 1995 Ai~ska Oil & Gas Cons, Commission Anchorz - All data is in feet unless otherwise stated Coordinates from slot #9 and TVD from RKB (185.10 Ft above mean sea level). Vertical section is from wellhead on azimuth 193.32 degrees. Declination is 0.00 degrees, Convergence is -0.87 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes !NTEQ MARATHON Oil Company Pad #3,BC-9 Beaver Creek Unit,Kena~, Alaska SURVEY LISTING Page 3 Your ref : Schlumberger <5943-8858'> Last revised : 14-Dec-94 Targets associated with this wellpath Target name Position T.V.D. Local rectangular coords. Date revised BC9 Target #1 Revise not specified 5107.10 1520,00S 360.00W 25-Aug-92 All data is in feet unless otherwise stated Coordinates from slot ~9 and TVD from RKB (185.10 Ft above mean sea level). Bottom hole distance is 1633.28 on azimuth 190.91 degrees from wellhead. Vertical section is from wellhead on azimuth 193.32 degrees. Declination is 0.00 degrees~ Convergence is -0.87 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ PERMIT DATA AOGCC Individual Well , Ge~iogical Mater±als Inventory T DATA_PLUS Page' 1 Date' 01/19/95 RUN DATE_RECVD 92-122 6267 92-i22 6268 92-122 6269 92-122 6270 92-122 6271 92-122 AiT/SP 92~-!22 CBL/VDL 92-122 CET 92-122 DiL/SFL 92-122 DSI 92-122 DSI 92-122 92-122 92-122 92-122 NGT 92-122 ~NGT 92-122 PERF T 8868-5822 FMS/AIT MAiNLOG FILE 2 T 8868-8547 FMS/AIT REPEAT FILE 2 T 8875-5878 DSi MAINLOG FILE 2 T 8880-8583 DSI REPEAT FILE T 8865-5882 LDS/APS/HNGS L 5944-8828 L 2800-5770 L 2800-5770 L 1854-5967 L 5944-8834 2 2 2 1 1 1 2 1 2 2 1 1 1 1 1 1 1 1 L 1854-5922 FMS L 5944-8860 LDT/ARR/EPI/NEUT L 5944-8852 LDT/CNL L 1854-5968 L 1854-5944 L 1854-5944 L 7900-8264 92-122 PERF L 8050-8300 92-122 PERF L 8150-8770 92-122 PLUG SETTING L 8650-8808 92-122 TDT-P L 5000-8803 10/05/1994 10/05/1994 10/05/1994 10/05/1994 10/05/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 12/22/1994 Are dry ditch samples required? yes no And received? yes no Was the well cored? yes no Analysis & description received? yes no Are well tests required? yes no Received? yes no Well is in compliance Initial ALAS~ OIL AND GAS CONSERVATION COMMISSION TONY KNOWLE$, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 January 12, 1995 Mark Sinclair Marathon Oil Company P O Box 190168 Anchorage, AK 99519 Re: 92-0122 Beaver Creek Unit No. 9 - Noncompliance Dear Mr. Sinclair: The Commission has not yet received the Well Completion Report (Form 10-407), daily well operations and directional survey for Beaver Creek Unit No. 9. Steve McMains spoke with Ed Oberts on October 26, 1994 and sent a letter to Guy Whitlock on November 29, 1994 concerning these materials which are required under 20 AAC 25.070(2). Our regulations require that the operator provide these items within thirty (30) days after the well is completed. The Commission requests action on this matter within 10 working days. Chairman ~ Marathon Oil Company P.O. Box 1961 68 Anchorage, AK 99519-61 68 Telephone (907) 561-5311 TRANSMITTAL December 22, 1994 Mr. Howard Okland Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 Enclosed are well logs and mylars for Beaver Creek No. 9. Marathon requests that all information concerning the subject well be kept confidential in accordance with the Commission. If you have any questions or require additional information, please contact Mark Sinclair at 564-6450. Sincerely, C.A. Underwood Exploration Aide RECEIVED ON THE ~./~AY OF DECEMBER, 1994. ALAS .~L AND GAS CONSERVATION COMMISSION BY: RECEIVED DEC 2'~ 1994 Alaska 0il & Gas O0~s. 60mmissi0rl Anchorage No. 8961 COMPANY LOCATION : ATTENTION : WELL NAME SERVICES NO. OF BOXES: SCHLUMBERGER GEOQUEST INTERPRETATION AND COMPUTING SERVICES i ,..,'~/ q/.~/- 500 W. INTERNATIONAL AIRPORT ROAD ZL & 6AS . - -94 3001 PORCUPINE DRIVE ~_ 0F T"E F"S,AZT,DSZ,LBT,APS, ANB % HNGS MAIN & REPEAT FILES ONE NO. OF BOXES: JOB NO. : 94294 JOB NO. : ADD'L TAPES : WELL NAME : SERVICES : NO. OF BOXES: JOB NO. ADD'L TAPES WELL NAME : · MARATHON & BLM ..~ A~).~ TAPES · //¢¢ ¢ NO. OF BOXES: JOB NO. : ADD'L TAPES : WELL NAME : SERVICES : SERVICES : NO. OF BOXES: JOB NO. : ADD'L TAPES : NO. OF BOXES: JOB NO. : ADD'L TAPES : SCHLUMBERGER COURIER: DATE DELIVERED: RECEIVED BY: MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: David John.~__,t~ DATE' Chairman.---'"-' August 11, 1994 THRU: FILE NO: Blair Wondzell, .~.~.~J-- P. I. Supervisor e/tsl,~,~ FROM: Lou Grimaldi,. ~ SUBJECT: Petroleum Inspector A9SJHKBD.DOC BOP test Nabors rig #154 Marathon well #BC'9 Beaver Creek Field PTD # g2-122 ...ThursdaY,, August 11,1994: I travelled to Marathons Beaver Creek Facility to witness the weekly BOP test on Nabors dg # 154. The rig was not quite ready to test when I arrived. I made a tour of the~and found that a Choke bypass line had not been installed, I discussed this with Vick Rudolph (Marathon Company rep.) and Paul Smith (Nabors Toolpusher) and a Blooey line will be installed before they drill out of the 7" shoe. The test was done in stages as the equipment was rigged up. The choke manifold tested well although some of the valves tended to be difficult to swing with pressure on them. I suggested that a thorough internal cleaning and inspection of the choke manifold at the next rig move to Paul Smith. The rest opf the BOP equipment tested out "OK". SUMMARY: I witnessed the weekly BOP test on Nabors rig # 154. Test time five hours, 24 valves, no failures. Attachments: AgSJHKBD.XLS cc: Mark Sinclair (Marathon Drilling/Production supt.) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: X Workover: Drlg Contractor: Nabors Rig No. 154 PTD # Operator: Marathon Rep.: Well Name: BC #9 Rig Rep.: Casing Size: 7" Set @ 5965' Location: Sec. Test: Initial Weekly X Other DATE: 8/11/94 92-122 Rig Ph.# 252-1802 Vick Rudolph Paul Smith 34 T. 7N R. 10W Meridian Umiat MISC. INSPECTIONS: Location Gen;: OK Housekeeping: OK (Gen) Reserve Pit N/A Well Sign OK Drl. Rig OK BOP STACK: Annular Preventer Upper Pipe Rams Lower Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve Test Quan. Pressure P/F 1 250/3500 P 1 250/5000 P 1 250/5000 P 1 250/5000 P 1 250/5000 P 1 250/5000 P 2 250/5000 P N/A N/A N/A MUD SYSTEM: Visual Alarm Trip Tank P n/a Pit Level Indicators P P Flow Indicator P P Methane Gas Det. P P H2S Detectors n/a n/a FLOOR SAFETY VALVES: Upper Kelly / IBOP Lower Kelly / IBOP Ball Type Inside BOP Test Quan. Pressure P/F 1 250 / 5000 P 1 250/5000 P 1 25O/5OOO P 1 250/5000 P CHOKE MANIFOLD: No. Valves No. Flanges Manual Chokes Hydraulic Chokes 16 Test Pressure P/F 250 / 5000 P 38 250/5000 P 1 P Functioned Functioned ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure System Pressure Attained Blind Switch Covers: Master: Nitgn. Btl's: Four Bottles 3050 I P 1550 P X minutes 25 sec. minutes 26 sec. Remote: X 2150 Psig. Number of Failures 0 Test Time 5 Hours Number of valves tested 24 Repair or Replacement of Failed Equipment will be made within N/A days. Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-3607 or 3687 If your call is not returned by the inspector within 12 hours please contact the P. I. Supervisor at 279-t433 REMARKS: Good Test, Install Blooey line. Note in IADC when driller functions Rams. Distribution: odg-Well File c - Oper./Rig c - Database c - Trip Rpt File c -Inspector F1-021L (Rev. 2/93) STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Witnessed By: IHKBD.XLS Louis R Grimaldi Alaska ~. _~ion Domestic Production Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 July 18, 1994 Mr. Blair Wondzell Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99507 RE: Beaver Creek Well #9 Dear Blair: Please find attached a change of plans sundry for Beaver Creek Well #9. Our original well plan contemplated using a 21 1/4" diverter with two 10" outlets while drilling our surface hole. The Nabors drilling rig that we selected to use on this well has a 21 1/4" diverter with one 10" outlet as shown on the attached schematic. We request that you approve this change of plans. Please contact me at 564-6450 if you have any questions. Sincerely, M. F. Sinclair Drilling Superintendent MFS/cah Enclosures R E C E IV E D JUL '1 8 1994 Alaska Oil & Gas Cons. Commission Anchorage h:\wp\Sund~\BC-9 A subsidiary of USX Corporation Environmentally aware for the long run. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend __ Alter casing __ Repair.well __ Change approved program _.~ 2. Name of Operator Marathon Oil Company/ 3. Address P.O. BOX 196168, Anchorage, AK 4. Location of well at surface 1164' FNL, 1547' FWL, At top of productive interval Pull tubing m Variance __ I 5. Type of Well: Development Exploratory Stratigraphic 99519-6 68 Service Operation shutdown i Re-enter suspended well __ Plugging ~ Time extens,on m Stimulate ~ Pedorate m Other __ Sec 34, T7N, RIOW, S.M. 2684' FNL, 1187' FWL, Sec 34, T7N, RIOW, S.M. @ 5100' TVD At effective depth At total depth 2684' FNL, 1187' FWL, Sec 34, T7N, RIOW, S.M. @ 8500' TVD 6. Datum elevation (DF or KB) ]78' KB feet 7. Unit or Property name Beaver Creek Unit 8. Well number Beaver Creek Well #9 9. Permit number 92-122 10. APl number 5o-133-20445 11. Field/Pool Beaver Creek Fiel Sterlin§ & Belu,qa Gas Poo 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Casing Length Structural Conductor Surface Intermediate Production Liner Perforation depth: measured true vertical Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) feet Plugs (measured) feet feet Junk (measured) feet Size Cemented Measured depth True vertical depth RECEIVED JUL. 1 8 ]994 Alaska UII & Gas Cons. Commission Anchorage 13. Attachments Description summary of proposal __ Detailed operations program __ BOP sketch X 14. Estimated date for commencing operation July 25, 1995 16. If proposal was verbally approved Name of approver Date approved 15. Status of well classification as: Oil __ Gas __ Suspended __ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~ ,~. ~ Title Dri l lin~ Superintendent FOR COMMISSION USE ONLY Date 7/18/9 4 Conditions of approval: Notify Commission so representative may witness Plug integrity __ BOP Test i Location clearance __ Mechanical Integrity Test __ Subsequent form required 10- Approved Copy Returned Original Signed By -- Approved by order ofthe Commission qavid W. Johnston Commissioner IApproval No. ~, r¢ ~ / ¢ / Date Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE .,9) UNI~D STATES (Other instructions re- DEPARTMEN 3F THE INTERIOR ,e,se-'de) BUREAU OF LAND MANAGEMENT SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen or plug back to a different reservoir. Use "APPLICATION FOR PERMIT--" for such proposals.) rUKM APt'ROVED OMB NO. 1004-0135 Expires: Sepiember30. 1990 ,~. LEABE DESIGNATION AND I~B~,IAL NO. A-028083 A84 6. IF INDIAN, ALLOTTEE OR TIIBE NAME l. 7. UNIT AGREEMENT NAME O,LWE,.L [--1 GAS WELL F~ oT~ Beaver Creek Unit 8. FARM OR LEASE NAME Beaver Creek Well 2. NAME OF OPERATOR Marathon 0il Company 3. ADDRESS OF OPERATOR P.O. Box 196168, Anchorage, AK 99519-6168 LOCATION OF WELL {Report location clearly and in accordance with any State requirements.' See also space 17 below.) At surface 1164' FNL, 1547' FWL, Sec 34, T7N, R1OW, S.M. j 1 5. ELEVATIONS (Show whether DF, IT, GR, 178' 'KB 14. PERMIT NO. F¥94-00] 9. WaLL 1~0. --lO. FigLD AND POOL., OR WILDCAT Beaver Creek Fi eld 11. sic., T., R., M., gl BLK. ~ #9 Sec 34, T7N~ R10W~ S.M. 12. C~:)gNT¥ OR P~ISI~J ~8. ITATE ~enai Peninsul~ Alaska 16. Ch~ck Appropr, ate Box To Indicme Nature of Notice, Report, or Other Data NOTICE OF INTENTION TO' FRACTURE TREAT ?,II I.?IPI.E COMPI.ETE SHOOT OR ACIDIZE ABANDON* REPAIR WELL CHANGE PLAN? (Other) SUBSEQUENT RIPOIT OF FRACTCRE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* IOther) I NOTE: Report result~ of multiple completion on Well ('ompletlon or Recotapletlon Report and Log form.) l?. I)ES('RIBE I'ROI't).'-;EI) OR ('OMPI.ETE:) OI'ERATIO\F {Clo:ll'ly slat. all l)orltllellt details, and give pertinent dates, including estimated date of Btartlng any proposed work. If well is direetionally drilled. Rive subsurface locations and measured and true vertleni depths for all markers and sones perti- nent to this work.) ' The original well plan contemplated using a 21 1/4" diverter with two 10" outlets to drill the surface hole. The Nabors rig to be utilized for this project has a 21 1/4" diverter with one 10" outlet as shown on the attached schematic. RECEIVED JUL 1 8 1994 A. iask~ Uil & G~s Cons. Commission Anchorage 18. I hereby certify that the foregoing is trae and correct S,~.~mD ~~--~-. ~_'~ ~,TL~ Drilling Superintendent 7/12/94 (This space for Federal or State off, ce use) APPROVED BY CONDITIONS OF APPROVAL, IF AN'X: TITLE DATE *See Instructions on Reverse Side TT Tit'.e IS ~;.S.C. Sect:on '-':]]' , makes :t a ,:r:::-.e fo:- an',' person kno'.;'_'n~i.v and willfui,'.v to maN,? :' an'.' d~Dartment c.: a~.enc_', o:' the Un,.tee. States ~nv fa:se, filC~.ItlOLIS C'r :raudulcr.: statements or reoresentatlons as to ar,': .'}:att,:' v :,.h:n :ts EXHIBIT A SECTION I PROPOSED BOP STOCK CONFIGURATION ,2,,1 - 1/4-" I~IVERTER STACK TO TANK ,V^C*UATORS / - 5 TO TANK .-~--- ~---. //-MECHANICAL INTERCONNECT 10" 150# HCR KNIFE GATE VALVE (AUTOI,(ATIC,.ALLY OPENS VCHEN DiV~RTER CLOSES) 21 ~,'4" 2000# HYDR!L MSP ANNULAR BOP/DIVERTER 2'~ 21 1/4' 2000~ FLANGE 2' O' SURFACE DIVERTER ELEVATION RECEIVED JUL 3 8 1994 Alaska 0il & Gas Cons. Commission Anchora,.je Marathon Oil Company 4-3 Alaska =lion Domestic Production Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 July 8, 1994 Mr. Blair Wondzell Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99507 RE: Beaver Creek Well #9 Dear Blair: Enclosed is a "Application for Sundry Approvals," reflecting some changes in our plans for Beaver Creek Well #9. The surface location for the well has been moved from 1200' FNL, 1460' FWL, Sec 34, T7N, R10W, S.M. to 1164' FNL, 1547' FWL, Sec 34, T7N, R10W, S.M. The proposed BHL has been moved from 2725' FNL, 1650' FWL, Sec 34, T7N, R10W, S.M. to 2684' FNL, 1187' FWL, Sec 34, T7N, R10W, S.M. Additionally, the casing program has been revised from 30", 20", 13 3/8", and 9 5/8" to 13 3/8", 9 5/8", 7", and 3 1/2". Our current plans are to spud this well on July 18, 1994. I have included a copy of the revised well plan for your information. If you have any questions, please call. Sincerely, M. F. Sinclair Drilling Superintendent MFS/cah Enclosures H:\WP\SUNDRY\BC-9 A subsidiary of USX Corporation Environmentally aware for the long run. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend __ Alter casing __ Repair well Change approved program ~ 2. Name of Operator Marathon Oil Companiy 3. Address PO Box 196168, Anchorage, AK Operation shutdown ~ Re-enter suspended well ~ Plugging __ Time extension ~ Stimulate __ Pull tubing __ Variance __ Perforate ~ Other 5. Type of Well: Development Exploratory Stratigraphic 9951'9-616 Service RIOW, S.M. RIOW, S.M. @ 5100' TVD Location of well at surface 1164' FNL, 1547' FWL, Sec 34, T7N, At top of productive interval 2684' FNL, 1187' FWL, Sec 34, T7N, At effective depth At total depth 2684' FNL, 1187' FWL, Sec 34, T7N, R10W, S.M. @ 8500' TVD 6. Datum elevation (DF or KB) 178' KB 7. Unit or Property name Beaver Creek Unit feet 8. Well number Beaver Creek Well #9 9. Permit number 92-122 10. APl number 50-133-20445 11. Field/Pool Beaver Creek Fiel Sterling and Beluqa Gas Po 12. Present well condition summary Total depth' measured true vertical Effective depth: measured true vertical Casing Length Structural 100 ' Conductor Surface 1 853' Intermediate 591 7' Production Liner 3134' Perforation depth: measured true vertical Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) feet Plugs (measured) feet feet Junk (measured) feet Size 13 3/8" 9 5/8" 7" 3 1/2" Cemented Measured depth True vertical depth Driven 100' 100' 725 SX 1853' 1803' 550 SX 5917' 5583' 525 SX 8834' 8500' :"' F-* VFD 13. Attachments Description summary of proposal __ Detailed operations program __ BOP sketch __ 14. Estimated date for commencing operation July 18~ 1994 16. If proposal was verbally approved Name of approver Date approved 15. Status of well classification as: Oil__ Gas ~ Suspended __ Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed ~~.'.~. ~' Title Drill lng Supe.r.!ntendent FOR COMMISSIO~ USE ONLY Conditions of approval: Notify Commission so representative may witness Plug integrity __ BOP Test ~ Location clearance __ Date 7/8/94 Mechanical Integrity Test __ Subsequent form required 10- /-f' d~ 7 Approved by order of the Commission Form 10-403 Rev 06/15/88 lApprOval N°C)/./..--/~ / ' Approved Copy Returned Commissioner Date ~ - / I - ~ y SUBMIT IN TRIPLICATE ls Form 3 f60-5 (May 1989) U NIT-~O STATES P-UBMIT (Other instructions re- DEPARTMEN .)F THE INTERIOR verse ~lde) BUREAU OF LAND/vlANAGEMENT SUNDRY NOTICES AND REPORTS ON WELLS (Do not Ltse this form for proposals to drill or to deepen or plug back to a different reservoir. Use "APPLICATION FOR PERMIT--" for such propo~is.) I-ORM APPROVED OMB NO. 1004-0135 Expires: September 30, 1990 LEASE DESlONATION AND mRRIAL NO. A-028083 A84 6. IF INDIAN, ALLOTTSE OR TRIBE NAME 1. 7. UNIT AGREgMSNT NAME OIL E~ GAS [] OTHER W,LL W,LL Beaver Creek Unit 2. NAME OP OPgRATOR Marathon Oil Company 3, ADD'gaB OF OP.~RA'I"OR P.O. Box 196168, Anchoraqe, AK 99519-6168 LOCATION OF WELL (Report location clearly and in accordance with any State requirements.* See also space 17 below.) At surface 1164' FNL, 1547' FWL, Sec 34, T7N, R10W, S.M. At proposed production zone 2684' FNL, 1187' FWL, Sec. 34, T7N, RIOW @ 5100' TVD and 5978' TVD. 14. PERMIT NO, 16. 15. ELEVATIONS (Show whether DI 178' KB (est) 8. FiRM OR LEASE NAMR Beaver Creek Well #9 WILL NO. '--10. rIRLD AND POOL~ OR WILDCAT Beaver Creek Fi eld 11. 8IC., T., a., a., OI BLK. AND BURY1! OR A~BA ___Sec 34, T7N, R1OW, S.M. 12. COUNTY OR P~iaH/13. ITATg [ Kenai Peninsul~ Alaska Check Appropriate Box To Indicaie Nature of Notice, Re~rt, or Other Data NOTICE OF INTENTION TO : FRACTURE TREAT M U LTIPLECO M PI.ETE SHOOT OR ACIDIZE ABANDONs REPAIR WELL C.ANGE PLANS (Other) SUBSEQUENT RBPOUT Or : WATER SHUT-OFF ~ REPAIRING WELL FRACTURE TREATMENT ALTERING CARING SHOOTING OR ACIDIZlNG ABAN~NMgNT* ~Other) (NOTE: Report results of multiple completion on Well Completion or Reco~pletion Report and Log form.) 17. DESCRIBE PROPOSED OR COMPI.ETED OPERATIONS (Clearly state all pertlnen details, and give pertinent dates, including estimated date of starting any proposed work. If well is directionaJly drilled, give subsurface Iocatiuns and measured and true vertical depths for all markers and zones perti- nen~ to this work.) * The proposed surface and bottom hole locations have been moved to those noted above. The proposed casing and cementing program has been modified as follows' Size of hole Size of Casing Weight per foot Setting Depth Quantity of cement Driven 13 3/8" 61 100' MD 12 1/4" 9 5/8" 47. 1803' TVD/1853' MD 725 SX 8 1/2" 7" 29 5583' TVD/5917' MD 550 SX 6" 3 1/2" 9.2 8500' TVD/8834' MD 525 SX 18. I hereby certify that the foregoing is true and correct SIGHED ~ ~'<~' ~/~,,__.' TITLE Drilling Superintendent DSa~ 7/R/94 (This spac~ for Federal or State office use) APPROVED BY CONDITIONS OF APPROVAL, IF AHY: TITLE DA'CE *See Instructions on Reverse Side Title 18 U.S.C. Sec:ion !001, makes it a cri~ne for an.,,, person knowingly and willfully to make to any. department or agency of the United States any fa,se, £ict:t~ous or fraudulent statements or representations as to any matter w~th:n its jurisdiction. ILLING AND COMPLETION PROGRAM MARATHON OIL COMPANY ALASKA REGION WELL: BC #9 FIELD: Beaver Creek Field LEG: NA AFE No.: 8100893 SLOT: NA TYPE: Sterling/Beluga Producer REVISION NO.: 5 DATE: 7/6/94 SURFACE LOCATION: 1164'FNL, 1547'FWL,Sec.34,T7N,R10W, S.M. TARGETS: Sterling: Beluga: 2684'FNL, 1187' FWL, Sec 34, T7N, R10W @ 5100' TVD 2684'FNL, 1187' FWL, Sec 34, T7N, R10W @ 5978' TVD BOTTOMHOLE LOCATION: 2684'FNL, 1187' FWL, Sec 34, T7N, R10W @ 8500' TVD KB ELEVATION: 178 ft. mean S.L. (est.) GL ELEVATION: 158 ft. mean S.L. (est.) I. IMPORTANT GEOLOGIC HORIZONS: FORMATION DEPTH (MD) DEPTH (TVD) Alluvium Surface Surface Potable water is generally encountered between surface and 150 ft. Sterling (Top B-2) 5392 5058 Beluga 6312 5978 ESTIMATED FORMATION TOPS AND CONTENT: FORMATION DEPTH (MD) DEPTH(TVD) Sterling B-2 5392 5058 B-3 5427 5093 B-3a 5497 5163 B-4 5587 5253 Beluga B-2 6312 5978 B-4 6419 6085 B-15 7354 7020 B-18 7614 7280 B-19 7684 7350 B-23 7954 7620 B-24 8119 7785 B-26 8309 7975 B-28 8459 8125 B-30 8594 8260 Total Depth 8834 8500 POTENTIAL CONTENT gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water ~.._., ,, ~ ~1 ~! page 1 III. WELL CONTROL EQUIPMENT DIVERTER SYSTEMS The diverter system on the 13-3/8" conductor will consist of a 21-1/4" x 2000 psi annular preventer and two 10" diverter lines each ecluipped with a 10" hydraulically actuated full-opening ball valve. A preselected diverter valve will open automatically and simultaneously when the annular is closed. 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 outfitted with blind rams in the bottom and pipe rams in the top, a 13-5/8" 5000 psi drilling spool {mud cross) equipped with 3-1/16" x 5000 psi outlets, and a 13-5/8" x 5000 psi single gate ram type preventer outfitted with pipe rams. 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 a vacuum-type degasser. A flow sensor will be installed in the flowline and the mudpits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. WELLHEAD SYSTEM S'~ARTING FLANGE: 20" Bradenhead STARTING HEAD: 11" - 3000 psi x 11" SOW with two 2-1/16" - 2000 psi studded outlets, one blind flange and one 2-1/1 6" - 5000 psi flanged gatevaive. TUBING HEAD: 11" - 3000 psi bottom x 7-1/16"-5000 psi top tubinghead with two 2-1/16" - 5000 psi studded outlets, one blind flange and one 2-1/6" - 5000 psi flanged gatevalve. CHRISTMAS TREE: 3-1/8" - 5000 psi christmas tree including two master valves, one flow tee, one manually adjustable choke, and one swab valve. page 2 IV. CASING PROGRAM: TYPE CONDUCTOR: SURFACE: SIZE 13-3/8" 9-5/8" CASING DESCRIPTION WT. GRADE THREAD 61 47.0 INTERMEDIATE 7" 29 LINER K-55 N-80 N-80 N-80 3 1/2" 12.95 BTC BTC BTC BTC SET SET HOLE FROM TO SIZE Surf 100' MD DRIVEN 1 00' TVD Surf 1853' MD 12-1/4" 1803' TVD Surf 5917' MD 8-1/2" 5583' TVD 5700' 8834' MD 5383' 8500' TVD CASING DESIGN SIZE 13-3/8" 9-5/8" 1, 3 1/2" WEIGHT 61 .OCt 47.0Ct 29.0# 9.2# GRADE K-55 N-80 N-80 N-80 SETTING DEPTH,TVD 100' 1803' 5583' 8500' FRAC GRD @ SHOE N/A 14.0 17.0 17.0 FORM PRSS @ SHOE 950 2200 382O MASP DESIGN FACTORS TENS COLL BURST 1642 13.54 5.56 6.03 2851 5.03 5.77 1.90 2842 9.39 17.27 4.01 page 3 V. CEMENTING PROGRAM SURFACE: 9-5/8" @ 1853' MD LEAD SLURRY' Halliburton Premium w/ 2% calcium chloride, 4% gel, .1% CFR-3, .25 lb/sk cellophane flakes TOP OF CEMENT: SURFACE WEIGHT: 14.2 ppg. YIELD: : 1.54 cu. ft./sk WATER REQ.: 7.58 gal/sk PUMPING TIME: 5:2.7 hrs:min EXCESS (%): 50 % ESTIMATED VOLUME 550 sx TAIL SLURRY ' Halliburton Premium w/ 1% calcium chloride, . 1% CFR-3, .25 Ib/sk cellophane flakes TOP OF CEMENT: 1873 ft. WEIGHT: 15.8 ppg. YIELD: 1.16 cu. ft./sk WATER REQ.: 5.0 gal/sk PUMPING TIME: 4:36 hrs:min EXCESS (%): 50 % ESTIMATED VOLUME 175 sx RUNNING AND CEMENTING DETAILS: ENSURE WEAR BUSHING IS REMOVED ! 1. Remove thread protectors and visually inspect connections. 2. Pickup shoe joint. Baker-iok float shoe. Check float. Fill pipe until circulating. 3. M/U float coilar.(Baker-lok top and bottom of float collar) 4. Fill pipe until circulating. 5. Run remaining casing. M/U cementing head, install bottom plug and test all lines. 6. Circulate and reciprocate until no gain in circulating efficiency is made. 7. With as little shut down as possible, drop bottom plug and begin pumping spacer. Pump spacer as follows: 40 bbls 18% NaCi 20 bbls drill water 20 bbls Super Flush (increase if losing circulation) 20 bbls drill water 40 bbls 18% NaCI Pump 5 bbls drill water. Mix and pump 150 bbis lead slurry (550 sx). 1 Mix and pump 36 bbis of tail slurry (175 sx). 1 Displace cement. Reciprocate as long as possible. 1 Bump plug w/500-1000 psi over final circulating pressure. Check floats. 1 WOC 12 hours holding pressure on annulus. 1 1 . 9. 0. 1. 2. 3. 4. N/D diverter. Set slips. N/U casing head and blowout preventers. 5. Test BOPE. Run wear bushing. page 4 V. CEMENTING PROGRAM (conti~ I iINTERMEDIATE LEAD SLURRY' 7" @ 5917' MD Halliburton Light Premium w/ .2% CFR-3, .25% HALAD-344, .3% HR-7 TOP OF CEMENT: WEIGHT: YIELD: WATER REQ..' PUMPING TIME: EXCESS (%): ESTIMATED VOLUME 1800 ft. 13.6 ppg. 1.53 cu. ft./sk 7.59 gai/sk 5:04 hrs:min 35 % 350 sx TAIL SLURRY ' Halliburton Premium w/.2% CFR-3, .3% HALAD-344, .1% HR-7 TOP OF CEMENT: 5200 ft. WEIGHT: 15.8 ppg. YIELD: 1.15 cu. ft./sk WATER REQ.: 5.0 gal/sk PUMPING TIME: 5:01 hrs:min EXCESS (%): 35 % ESTIMATED VOLUME 200 sx RUNNING AND CEMENTING DETAILS: ENSURE WEAR BUSHING IS REMOVED! 1. Remove thread protectors and visually inspect connections. 2. Make up float shoe and 2 shoe joints. Check float. Fill pipe until circulating. 3. M/U float collar. (Baker-lok ali connections to top of float collar) 4. Fill pipe until circulating. 5. Run remaining casing. M/U cementing head, install bottom plug and test all lines. 6. Circulate and reciprocate until no gains in circulating efficiency is made. 7. With as little shut down as possible, drop bottom plug and begin pumping spacer. Pump spacer as follows: 40 bbls 1 8% NaCI 20 bbls drill water 20 bbls Super Flush 20 bbls drill water 40 bbls 18% NaCi 8. Pump 5 bbls drill water. 9. Mix and pump 96 bbls. lead slurry(350 sx). 10. Mix and pump 41 bbls. of tail slurry(200 sx). Drop top plug. 11. Displace cement. Reciprocate as long as possible. 12. Bump plug w/500-1000 psi over final circulating pressure. Check floats. 13. WOC 12 hours. 14. P/U BOP stack. Set slips. N/U tubing spool. N/U BOP stack. 15. Test BOPE. page 5 V. CEMENTING PROGRAM (continued) r I LINER LEAD SLURRY ' 3 1/2" 8834'-5700' MD TOP OF CEMENT: ft. WEIGHT: ppg. YIELD: cu. ft./sk WATER REQ.: : gal/sk PUMPING TIME: hrs:min EXCESS (%): % ESTIMATED VOLUME SX TAIL SLURRY ' Halliburton Premium w/ .2% CFR-3, .3% HALAD-344, .1% HR-7 TOP OF CEMENT: 5700 ft. WEIGHT: 15.8 ppg. YIELD: 1.15 cu. ft./sk WATER REQ.: 5.0 gal/sk PUMPING TIME: 5:01 hrs:min EXCESS (%): 50 % ESTIMATED VOLUME 525 sx RUNNING AND CEMENTING DETAILS: · 2. 3. 4. 5. 6. 7. o 9. 10. 11. 12. Set packer and reverse out two drillpipe volumes. POOH. 14. Test BOP'S. Remove thread protectors and visually inspect connections. Make up float shoe and 2 shoe joints. Check float. Fill pipe until circulating. M/U float collar. (Baker-lok ali connections to top of float collar) Fill pipe until circulating. Run remaining casing. M/U hanger, circulate liner capacity. RIH w/ DP. Circulate and reciprocate until no gains in circulating efficiency is made. With as little shut down as possible, drop dart and begin pumping spacer. Pump spacer as follows: 40 bbls 18% NaCI 20 bbls drill water 20 bbis Super Flush 20 bbls drill water 40 bbls 18% NaCI Pump 5 bbls drill water. Mix and pump 117 bbls. of taiislurry(525 sx). Drop top plug. Displace cement. Reciprocate as long as possible· Bump plug w/ 500-1000 psi over final circulating pressure. Check floats. page 6 MUD PROPERTIES DEPTH DEPTH WEIGHT VISCOSITY WATER MUD FROM TO TVD ppg seciqt LOSS TYPE 100' 500' 8.6-10 80-250 1 5-30 Freshwater spud 500' 1800' 9.6-10 42-80 < 12 Non-dispersed 1 800' 8500' 9.6-11.5 42-80 <8 PHPA Mud solids and cuttings will be ground and slurrified for injection into Beaver Creek //3. MUD EQUIPMENT The solids control equipment will consist of a shale shaker, a 2-cone desander, a mudcleaner, and a centrifuge. Included will be equipment to dewater the underflow from the mud processing equipment to allow disposal of the cuttings and solids by slurrification and injection into Beaver Creek//3. VII. LOGGING, TESTING, AND CORING PROGRAMS LOGGING PROGRAM CONDUCTOR: No logging is planned for this interval. SURFACE: No logging is planned for this interval. INTERMEDIATE: LINER: AMT/SP/GR/DIL/LDT/CNL-CAL from TD' to 1800'. Borehole image tool from 5900' to 5000'. NGS/SP/AIT/LDT/CNL-CAL from TD to 5900 ' Borehole image tool from TD to 5900' GR/SONIC/DSi from TDto5900'. COMPLETION: A Cement Bond Log (CET/GR) and a directional gyro- survey will be run prior to perforating. A pulsed nuetron log will also be run from TD to 5000' prior to perforating. CORING PROGRAM Two 60 ft. cores are planned in benches B-2 and B-23 of the Beluga Sand utilizing conventional coring techniques. Corepoint: Beluga B-2 5978' +- Beluga B-23 7620' +- TESTING PROGRAM No open hole tests are planned for this well. A mud logger will be utilized from the surface casing shoe at 1853' to total depth. page 7 VIII. BOTTOMHOLE PRESSURES AN~3 POTENTIAL HAZARDS Anticil~atea bottomnole pressures in the Sterling and Beluga sanas are 2200 psi and 3820 psi respectively. ~.ost returns are possible in the depleted Sterling interval. Overpressued gas sands may be encounterea Jetween 4000 aha 5000 ft. reauiring mud weights up to 11.5 ppg. Hydrogen sulfide gas has not been encountered in any well in the Beaver Creek field. IX. OTHER INFORMATION DIRECTIONAL PLAN DESC SOUTH EAST MD TVD INCL AZIM COORD COORD F~KB KICKOFF HOLD DROP HOLD Total Depth 0 0 0 S0E 0 0 650 650 0 S0E 0 0 build @ 2.5 deg/100ft 1853 1803 28.7 S14.95E 292 -32 tangent section of 27.4 deg 3519 3264 28.7 S14.95E 1066 -239 drop @ 1.5 deg/100ft. 5434 5100 0 S0E 1520 -360 POTENTIAL INTERFERENCE: 8834 8500 0 S0E 1520 -360 WELL DISTANCE (ft.) DEPTH (MD) Beaver Creek #3 24 1000 VERT SECTION 0 0 257 1106 1534 1534 page 8 DRILLING PROGRAM CONDUCTOR: Move in and rig up rotary drilling r~g. Drive 13 3/8" conductor to +-100 ft. RKB. Drive 13-3/8" rathole. Weld 20" starting flange to drive pipe. Nipple up 20" diver~er, diver~er valves, and 2-10" diverter lines. Function test diverter and diverter valves. SURFACE: Drill a 12-1/4" hole to 1 853' per the directional plan. Run and cement 9-5/8" casing. WOC. Cutoff 13-3/8" and 9 5/8"..-Weld on 11" SOW by 11" 3M wellhead. N/U 13 5/8" 5M BOP'S. Test BOP'S and choke manifold to 250/3000 psi. Set Wear bushing. Test surface casing to 2000 psi. INTERMEDIATE Drill float equipment and 10' of new formation w/8 1/2" bit. Run leak off test. Do not exceed 12.0 ppg equivalent mud weight. Drill a 8 1/2" hole from 1853' to 5917' per the directional program. Log. Pull wear bushing. Run and cement 7" casing. P/U diverter. Set slips, N/D diverter, install casing head and test to 1000 psi. N/U 13-5/8 x 5M BOPE. Test BOPE and choke manifold to 250 psi/3000 psi. Set wear bushing. Test Intermediate casing to 3000 psi. LINER Drill float equipment and 10' of new formation. Run leak off test. Do not exceed 14.0 ppg. equivalent test pressure. Drill a 6" hole from 5917' to 8834' per the directional program. Log. Pull wear bushing. Run and cement 3 1/2" Liner. Test BOP'S and choke manifold. Set wear bushing. Clean out to liner top and test intermediate casing, liner lap and liner to 3000 psi. COMPLETION: Run gyro and CBL. Completion procedure to follow. page 9 ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279;1433 TELECOPY: (907) 276-7542 November 29,1994 G. R. Whitlock Marathon Oil Company P O Box 190168 Anchorage, Alaska 99519 RE: 92-0122~ Beaver Creek Unit # 9 Dear Mr. Whitlock, A review of our well files after September reported oil production indicates the reference well completion report (10-407), daily well operations and survey has not been received by the commission to date. I called Mr. Ed Oberts on October 26, 1994 concerning this report. This report is required under 20 AAC ' 25.070(2). I hope this situation can be corrected quickly to update our well files. Sincerely, Steve McMains Statistical Technician WALTER J. HICKEL, GOVERNOR ALASKA OIL AND GAS CONSERVATION COMMISSION December 31, 1992 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 G. R. Whitlock Drilling Superintendent Marathon Oil Company P O Box 190168 Anchorage, AK 99519 Re: Beaver Creek Unit BC#9 Marathon Oil Company Permit No: 92-122 Sur. Loc. 1200'FNL, 1460'FWL, Sec. 34, T7N, R10W, SM Btmhole Loc. 2725'FNL, 1650'FWL, Sec. 34, T7N, R10W, SM Dear Mr. Whitlock: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below the surface casing shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission at 279-1433. -- Chairman BY ORDER OF THE COMMISSION dlf/Enclosures Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA ALASKA ,-.,- AND GAS CONSERVATION CC MISSION PERMIT TO DRILL 20 AAC 25.OO5 ¢'1a._ Type of work Drill ~% Redrill El lb. Type of well. Exploratory :- Stratigraphic Test ~ Development Oil Re-Entry ~ Deepen:-I Service - Developement Gas %_ Single Zone '- Multiple Zone 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool MA_RATHON OIL COMPANY 178' KB feet BEAVER CREEK FIELD 3. Address 6. Property Designation ,.q¢~-r-/,'.~,- / P. O. BOX 190168 ANCHORAGE, AK 9~519, A-028083 ~-/~ ~ ~/ 4. Location of well at surface /,,j 7. Unit or property Name 11. Type Bond(see 20AAC25.0251 1200'FNL, 1460'FWL, SEC34,T7~, Rt0~, S.M. BEAVER CREEK UNIT --At top of productive interval 8. Well nu,mber Number 5194234 2725' FNL, 1650'FWL, SEC34, T7N, R10W, S.M. BC#9 At total depth 9. Approximate spud date Amount $200,000 2725'FNL, 1650'FWL, SEC34, T7N, R10W, S.M. 6-1-93 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth fMD and TVD) property line 4750 feet 1750 feet 2560 8435 'TVI)/8730 'MD feet 16. To be completed for deviated wells 17. Anticipated pressure ~see 2o AAC 25.035 lei(2)) Kickoff depth 650 feet Maximum hole angle 26 o Maximum surface 2851 psig At total depth (TVD) 3820 ps,g 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) Driven 30 309.72 B Welded 100 SUR]~ACE 100 100 26 20 133 X-56 RL4S 500 SUR]~ACE 500 500 1170 SX 17~ 13 3/~ 61 K-55 BTC 2073 SUR]~ACE 2073 2000 1480 SX ±2~ 9 5/8 47/53.J N-80 BTC 8730 SUR]~ACE 8730 8428 2080 SX - 19. To be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Total depth: measured feet Plugs (measured) true vertical feet Effective depth: measured feet Junk (measured) true vertical feet Casing Length Size Cemented Measured depth True Vertical depth Structural Conductor Surface Intermediate Liner . -. Perforation depth: measured Alaska 0il & Gas Cons. Comfmss~o~ true vertical Anchorage 20. Attachments Filing fee '~ Property plat ~_ BOP Sketch ~ DiverterSketch ~_ Drilling program % Drilling fluid program ~ Timevs depth plot ~ Refraction analysis -- Seabed report ~ 20AAC25.050 requirements 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed .A,~, /¢,..) ~"~ o<_/- Title..~',..,[[~.....~,~.~,~ Dateil · Commission Use Only~ I r~,~date 'See c°ver letter Permit Number APl number App ¢~.-/..;2 .~- 50--//O.~._F- .~. O ~ zZz ,,~ -'-~/-~~for other requirements Conditions of approval Samples req_uired ~ Yes ~ No Mud log required -- Yes /~No Hydrogen sulfide measures '~ Yes ~'No Directional survey required ,'~ Yes - No Required working pressure for BOPE %2M; ~- 3M; ~ 5M; -'-' 10M; - 15M Other: Original Signed By by order of Approved by David W. Johnston Commissioner the commission Date/c,~ ~..~c;~L. Form 10-401 Rev. 12-1-85 Submit in triplicate Alaska ' ~n Domest,. loduction Marathon Oil Company RO. Box 190168 Anchorage, AK 99519-0168 Telephone 907/561-5311 Mr. Dave Johnston Alaska Oil and Gas Conservation Commision 3001 Porcupine Drive Anchorage, Alaska 99501 October 29, 1992 BEAVER CREEK WELL No. 9 Enclosed is our Application for Permit to Drill for the subject well. A rig has not been selected yet, and once the rig has been selected, we will notify you and send you the schematics and details of the rig equipment. We are electing to submit in this manner to expedite the permit. G. R. Whitlock Drilling Superintendent GRW:Ihl Enclosures A subsidiary of USX Corporation RECEIVED N 0V - 4 199'Z Alaska 0il & Gas Cons. 'Anchorage Surface Use Plan for Beaver Creek #9 Surface location: Anticipated at 1200' FNL, 1460' FWL, Sec. 34, T7N, RIOW, S.M. 1) Existing Roads Existing roads which will be used for access to Beaver Creek #9 are shown on Fig. 2. 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 Beaver Creek #9. 3) Location of existing wells The location of all existing wells in the Beaver Creek Field is shown on Fig. 2. 4) Location of existing and/or proposed facilities The locations of existing production facilities in the Beaver Creek Field are shown on Fig. 2. The only new facilities required for Beaver Creek # 9 is the possible addition of a new flowline from the wellhead to the Dehydration Facility located on Pad lA. If a new flowline is required, it will be routed to stay clear of the archeological site KEN-041 (figure 4). 5) Location of Water Supply A water supply well exists on the pad that will be used to drill Beaver Creek #9. This is shown on Fig. 3. 6) Construction Materials Sand and gravel necessary to enlarge the pad, if required, will be obtained from the approved gravel pit in the SW/4, NE/4, Sec. 5 T6N, RIOW, S.M. Other materials will be obtained from various vendors and suppliers in Alaska. 7) Methods of handling waste disposal; a) Mud and Cuttings Muds and cuttings will be dewatered on location. All liquids will be hauled to the water disposal facilities on Pad lA for injection into Beaver Creek #2 an approved disposal well (Alaska Oil and Gas Conservation Commission Disposal Injection Order No. 4). Cuttings and solids will be stabilized and placed in the Beaver Creek Waste Site, an approved disposal site for exempt waste (Alaska Department of Environmental Control Permit # 9023-BA001). An alternative method of handling the mud and cuttings is also under consideration. The cuttings would be ground and slurrified for injection into Beaver Creek #2 or KGF #14-4 in the Kenai Gas Field, or injected in BC-3 which is on the same pad as BC-9 (pad 3). The rig contractor will be required to provide an additional 1500 to 2000 barrels of reserve capacity pits, while the rig is in operation, i~_ i'~ '~' E I V ~ D · '. :,-~ ar~ka Oii& Ga.~ Cons. C,o[nrniSsioln Anchorage r. b) Garbage All household and approved industrial garbage will be hauled to the Kenai Peninsula Borough Soldotna Landfill. c) Completion Fluids Salts and brines used during the completion of Beaver Creek #9 will be hauled to the water disposal facilities on Pad la for injection into Beaver Creek #2 an approved disposal well (Alaska Oil and Gas Conservation Commission Disposal Injection Order No. 4). Produced water obtained from testing Beaver Creek # 9 will be disposed of in the same manner. d) Chemicals Unused chemicals will be returned to the vendor which 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. No airstrip or additional structures will be necessary. 9) Wellsite Layout An anticipated layout of the wellsite is shown on Fig 3. 10) Plans for reclamation of the surface Beaver Creek #9 will be drilled from an existing pad. Reclamation of the pad will occur after the abandonment of Beaver Creek #9 and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from the U.S. Fish and Wildlife Service prior to any reclamation work beginning. 11) Surface ownership The surface owner of the land in the Beaver Creek Unit is the U.S. Fish and Wildlife Service. The minerals are under the jurisdiction of the U.S. Bureau of Land Management. ~,~,o,.,a~" Oil (:..," Gas Co,Is. i.\nchora~.js 12) Other Vehicle parking areas, as well as other areas on the pad where equipment will be setup and operating will be lined with an impervious liner to prevent spills. While drilling BC-9, all work will be performed in accordance with the Oil Spill Contingency Plan, Environmental Guidelines, Emergency Action Plan, and Safety Policies and Procedures, as set forth by Marathon for all operations in the Beaver Creek Field. 32 O~ 3 5"0.0 Kenai . :.. Airport ' EE D E YA"i'L' '' I i MARATHON OIL COMPANY BEAVER CREEK AREA Figure I VICINITY MAP SEC 34 T7N RIOW' SM Drill$1te · 0 8000 I SCALE IN FEET N . /~~~~ BCU 6 ..O~UCT~O..,~ // v / ecu 4, o I / ~ ~ PAD3~ SEC. 33 // SEC. 34 AVER LAKE , // ~ ..... Io i acu 7 .... ~s,:.~o~ ' Aiaska O~l ~ Ga~ PAD 7 PURPOSE: DRILL & COMPLETE PLAN VIEW PROPOSED LOCATION FOR BCU 9 BCU 9 ON: PAD 3 ADJACENT PROPERTY 0 1'000 2000 AT: BEAVER CREEK PRODUCTION I . ~ FACILITY OWNERS SCALE IN FEET IN: PAD 3 KENAI PENINSULA KENAI NATIONAL WILDLIFE REFUGE MARATHON OIL COMPANY' BOUROUGH, AK. P.O. BOX 190168 APPLICATION BY: ANCHORAGE, AK. 99519 MARATHON OIL COMPANY DATE 10-8-92 FIGURE 2 · 2' DRISCO Water Well ~ potable water line ~,/ / / crude oil pipeline ~D/. ~' -- ~- / ~).cu ~ / z p~ta~}e ~- /- ' 6' oil pipeline ~ water line / BCU 3 4' DRISCO line / > ~ ~ ~ / ['~'~/ ~ A ~9 PURPOSE: DRILL & COMPLETE BCU 8 ADJACENT PROPERTY OWNERS KENAI NATIONAL WILDLIFE REFUGE PLAN VIEW 0 150 SCALE IN FEET MARATHON OIL COMPANY P.O. BOX 180168 ANCHORAGE, AK. 99519 PROPOSED LOCATION FOR BCU 9 ON: PAD 3 IN: BEAVER CREEK PRODUCTION FACILITY KENAI PENINSULA BOUROUGHo AK. APPLICATION BY: MARATHON OIL COMPANY DATE 10-8-92 Figure 3 FIGURE 3 , · · ~ , ° _-.%~, -.. - -~ ....; .. ~.~.... ~'..'.. ~ T?N .~ ,~ ~ ~,~"~,D. ~ TSN b L",'.~: ']""'~":~'¢;]~ .~7~ WALL THICKNESSS -~ ...... o .:.. .... . .... ......., :~ -,~ AVE ' ' ''~ }'j"' ''~2 . ' , ' . '}cig ~ .[..'. ,' '. ~" ',"' ~ '. '"2:~..'".':' '.-';'~ ' O3 . ., ~ . ..[...~... ". ~; ~ , ~; . . . ] : ;~:~. ~. /'..-- .-'t.,..~,~~.'? : .... , ._... .,., . ,: : ; .' '. , . '.t~.' " " ; ~ ' ' '...,... - ~ . . ~,,. .'"" · , ..., :,-~ .. ~.~,..~, , ' ".. :*. ~ " " .'. ' ., ~ /.' -?0~':'~:' . ~"':' ".' ' ' · ~ . . [i~: . -."t ' ' · · · . ' ~.,.'. · ; .. .,'~. , ...~., ~,~.....,.~ ..,.,~.'....'..' ".' '.....~ '~';~,;:,':"..'~':( . WETL~S . :u,,'". 3 k'~, ' ' .;" ) .~;"~?'27,.',:; ~j · ' AREA · .;.~,..,..,b.~ . . ..~ ~.~,~...:,. ..... . .... ., ' I '-'~ "~"-":~ . . ., .. ~., ; '.;. ~ ' ~ ~. ..',~ . .'' ~ , .. ~ .... . "" . : . · . - .:~;~.{...;'.'. . .," . .. .:j, :-.. ~..~.~ ~ , .. ~. · . PROOUCTION · '. ~.:'i?i'~_...;~ ... ;; ,-: ,? 8.6 2 5"O.D .322 WALL THICKNESS GRADE X-42 O1 .' ~ ,t,''~' ,e 8,625"O. .322" WALL THICKNE5~ GRADE X-42 6.625"O.D. 4 .250" WALL THICKNESS GRADE X-4 MARATHON OIL COMPANY ANCHORAGE DIVISION Date :~2._ BEAVER CREEK UNIT GAS GATHERING SYSTEM &TRUNK LINE 1 I I HILE Author File no. 3RILUNG AND COMPLETION PROGR/~' MARATHON OIL COMPANY ALASKA REGION WELL: BC #9 FIELD: LEG: NA AFE No.: SLOT: NA TYPE: Beaver Creek Field 8162-2 (Sterling)/8164-2 (Beluga) Sterling/Beluga Producer REVISION NO.: 2 DATE: 11/1/92 SURFACE LOCATION: 1200'FNL, 1460'FWL, Sec.34,T7N,R 10W, S.M. TARGETS: Stealing: Beluga: 2725'FNL, 1650' FWL, Sec 34, T7N, R10W @ 5253' TVD 2725'FNL, 1650' FWL, Sec 34, T7N, R10W @ 5978' TVD BO'I-rOMHOLE LOCATION: 2725'FNL, 1650' FWL, Sec 34, T7N, R10W @ 8428' 'I'VD KB ELEVATION: 178 ft. mean S.L. (est.) GL ELEVATION: 158 ft. mean S.L (est.) i. IMPORTANT GEOLOGIC HORIZONS: FORMATION DEPTH(MD) DEPTH(TVD) Alluvium Surface Surface Potable water is generally encountered between surface and 150 ft. Steding 5360 5058 Beluga 6280 5978 II. ESTIMATED FORMATION TOPS AND CONTENT: FORMATION DEPTH(MD) DEPTHCI'VD) Stealing B-2 5360 5058 B-3 5395 5093 B-3a 5465 5163 B-4 5555 5253 Beluga B-2 6280 5978 B-4 6420 6118 B-15 7270 6968 B-18 7595 7293 B-19 768O 7378 B-23 7750 7448 B-24 7930 7628 B-26 8030 7728 B-28 8260 7958 B-30 8420 8118 Total Depth 8730 8428 page 1 POTENTIAL CONTENT gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water .R C E IV E b Oil a Ga:; Cop, s. Oon'imi,~sion ~nchora~ III. WELL CONTROL EQI.;~--~IENT DIVERTER SYSTEMS The diverter system on the 30" drive pipe will consist of a 29-1/2" x 500 psi annular preventer and two 10" diverter lines each equipped with a 10" hydraulically actuated full-opening ball valve. A preselected diverter valve will open automatically and simultaneously when the annular is closed. The diverter system on the 20" conductor will consist of a 21-1/4" x 2000 psi annular preventer and two 10" diverter lines each equipped with a 10" hydraulically actuated full-opening ball valve. A preselected diverter valve will open automatically and simultaneously when the annular is closed. 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 outfitted with blind rams in the bottom and pipe rams in the top, a 13-5/8" x 5000 psi drilling spool (mud cross) equipped with 3-1/16" x 5000 psi outlets, and a 13-5/8'° x 5000 psi single gate ram type preventer outfitted with pipe rams. The choke manifold will be rated 3-1/16" 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 a vacuum-type degasser. A flow sensor will be installed in the flowline and the mudpits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. WELLHEAD SYSTEM STARTING FLANGE: 30" series 300 MSS x 30" butt weld STARTING HEAD: 21-1/4" - 2000 psi x 20" SOW bradenhead with two 2-1/16" - 2000 psi studded outlets, one blind flange and one 2-1/6" - 2000 psi flanged gatevalve. CASING HEAD: 21-1/4"- 2000 psi bottom x 13-5/8"-5000 psi top casinghead with two 2-1/16" - 5000 psi studded outlets, o blind flange and one 2-1/6" - 5000 psi flanged gatevalve. TUBING HEAD: 13-5/8" - 5000 psi bottom x 11"-5000 psi top tubinghead with two 2-1/16" - 5000 psi studded outlets, one blind flange and one 2-1/6" - 5000 psi flanged gatevalve. CHRISTMAS TREE: 3-1/16" - 5000 psi dual christmas tree including two master valves, one flow tee, choke, and one swab valve per tubing string. page 2 Gas Cons. Cornmissior~ Anchorage IV. CASING PROGRAM: TYPE SIZE WT, DRIVE PIPE: 30 309 CONDUCTOR: 20 SURFACE: 13.375 CASING DESCRIPTION 133 SET SET HOLE GRADE THREAD FROM TO SIZE B BEV Surf 100' Driven 100'TVD X-56 RL4-S Surf 500' 26" 500'TVD K-55 BTC Surf 2073' 17-1/2" 2000' TVD N-80 BTC Surf 7523' 12-1/4" 7221 "r'VD N-80 BTC 7523' 8428' 12-1/4" 8730'TVD 61 PRODUCTION: 9.625 47.0 53.5 SIZE WEIGHT GRADE 30" 309 B 20" 133 X-56 13-3/8" 61.0# K-55 9-5/8" 47.0# N-80 53.5# N-80 CASING DESIGN SE'i-i'ING FRAC GRD FORM PRSS DESIGN FACTORS DEPTH,TVD @ SHOE @SHOE MASP TENS COLL BURST 100' N/A 500' 14.0 679 1324 31.92 3.65 9.19 2000' 17.0 2672 10.28 1.56 1.88 7221' 2851 2.60 1.10 2.41 8428' 17.0 3820 19.26 1.31 2.78 page 3 Anchora,,"..la MAXIMUM ANTICIPATED SURFACE PRESSURE (MASP) MASP =(FRAC GRAD+SAFETY FACTOR) *. 052*TVD - (GAS GRAD. * TVD) 20" CONDUCTOR MASP = (14.0ppg + 1.0ppg)*.052*500 - (.115'500) = 390psi - 57psi = 333psi 13 3/8" SURFACE MASP = (17.0ppg +l.0ppg)*.052*2000 -(.115'2000) = 1872psi-230psi = 1642psi 9 5/8" PRODUCTION MASP = FORMATION PRESS. - (GAS GRAD * TVD) = 3820psi - (.115'8428) = 3820psi - 969psi = 2851psi P,.iaska 0il & Ga:~ Cons. ~ornrp. issio~'~ Anchoraga V. CEMENTING PROGRAI~, CONDUCTOR: LEAD SLURRY' 2O" @ 5OO' MD Halliburton Premium w/2% calcium chloride, 4% gel,. 1% CFR-3, .25 Ib/sk cellophane flakes TOP OF CEMENT: SURFACE WEIGHT: 14.2 ppg. YIELD: 1.54 cu. ft./sk WATER REQ.: 7.60 gal/sk PUMPING TIME: 4:46 hrs:min EXCESS (%): 100 % ESTIMATED VOLUME 590 sx TAIL SLURRY: TOP OF CEMENT: 300 ft. WEIGHT: 15.8 ppg. YIELD: 1.17 cu. ft./sk WATER REQ.: 5 gal/sk PUMPING TIME: 4:13 hrs:min EXCESS (%): 100 % ESTIMATED VOLUME 580 sx RUNNING 1. 2. 3. 4. 5. , 7. 8. 9. 10. 12, 13. 14. 15. 16, 17. 18. 19. 20. AND CEMENTING DETAILS: Remove thread protectors and visually inspect connections. Pickup shoe joint. Baker-lok float shoe. Fill pipe until circulating. Check float. M/U stab-in float collar.(Baker-lok top and bottom of float collar) Fill pipe until circulating. Run remaining casing (filling every joint) and land in the 30" MSS flange (install centralizers on jts. 1,2,4,6,8,10,12,) Rig up false rotary and run and space out stab-in cementing string. Secure drill pipe and circulate while reciprocating casing. Continue circulating until no gain in circulating efficiency is made. With as little shut down as possible, begin pumping spacer. Pump spacer as follows: 40 bbls 18% NaCl 20 bbls drill water 20 bbls Super Flush (increase if losing circulation) 20 bbls drill water 40 bbls 18% NaCl Mix and pump 162 bbls of lead slurry (590 sx). Mix and pump 119 bbls of tail slurry (580 sx). Reciprocate casing as long as possible. Displace ddllpipe. Check float. Pull seals out of float shoe. Pull out of hole w/d.p. WOC 12 hours holding 75 psi on annulus. N/D 30" diverter. Cut off 30" and 20" casing. Weld on stadng head. N/U 20" diverter. page 4 V. CEMENTING PROGRAM (continued) SURFACE: 13-3/8" @ 2073' MD LEAD SLURRY' Halliburton Premium w/2% calcium chloride, 4% gel, .1% CFR-3, .25 Ib/sk cellophane flakes TOP OF CEMENT: SURFACE WEIGHT: 14.2 ppg. YIELD: 1.54 cu. ft./sk WATER REQ.: 7.58 gal/sk PUMPING TIME: 5:27 hrs:min EXCESS (%): 50 % ESTIMATED VOLUME 1240 sx TAIL SLURRY: TOP OF CEMENT: WEIGHT: YIELD: WATER REQ.: PUMPING TIME: EXCESS (%): ESTIMATED VOLUME Halliburton Premium w/1% calcium chloride, .1% CFR-3, .25 Ib/sk cellophane flakes 1873 ft. 15.8 ppg. 1.16 cu. ft./sk 5.0 gal/sk 4:36 hrs:min 50 % 240 sx RUNNING , 2. 3. 4. 5. 6. 7. . 9. 10. 11. 12. 13. 14. WOC 12 hours holding pressure on annulus. 15. Test BOPE. Run intermediate wear bushing. AND CEMENTING DETAILS: ENSURE WEAR BUSHING IS REMOVED ! Remove thread protectors and visually inspect connections. Pickup shoe joint. Baker-lok float shoe. Check float. Fill pipe until circulating. M/U float coilar.(Baker-lok top and bottom of float collar) Fill pipe until circulating. Run remaining casing. M/U cementing head, install bottom plug and test all lines. Circulate and reciprocate until no gain in circulating efficiency is made. With as little shut down as possible, drop bottom plug and begin pumping spacer. Pump spacer as follows: 40 bbls 18% NaCI 20 bbls drill water 20 bbls Super Flush (increase if losing circulation) 20 bbls drill water 40 bbls 18% NaCI Pump 5 bbls drill water. Mix and pump 338 bbls lead slurry (1240 sx). Mix and pump 49 bbls of tail slurry (240 sx). Displace cement. Reciprocate as long as possible. Bump plug w/500-1000 psi over final circulating pressure. Check floats. N/D diverter. Set slips. N/U casing head and blowout preventers. page 5 V. CEMENTING PROG~(,continued) PRODUCTION: 9-5/8" @ 8730' MD LEAD SLURRY' Halliburton Light Premium w/.2% CFR-3, .25% HALAD-344, .3% HR-7 TOP OF CEMENT: 1870 ft. WEIGHT: 13.6 ppg. YIELD: 1.53 cu. ft./sk WATER REQ.: 7.59 gal/sk PUMPING TIME: 5:04 hrs:min EXCESS (%): 35 % ESTIMATED VOLUME 880 sx TAIL SLURRY: Halliburton Premium w/.2% CFR-3, .3% HALAD-344,. 1% HR-7 TOP OF CEMENT: 5300 ft. WEIGHT: 15.8 ppg. YIELD: 1.15 cu. ft./sk WATER REQ.: 5.0 gal/sk PUMPING TIME: 5:01 hrs:min EXCESS (%): 35 % ESTIMATED VOLUME 1200 sx RUNNING AND CEMENTING DETAILS: ENSURE WEAR BUSHING IS REMOVED! 1. Remove thread protectors and visually inspect connections. 2.Make up float shoe and 2 shoe joints. Check float. Fill pipe until circulating. 3.M/U float collar. (Baker-lok all connections to top of float collar) 4.Fill pipe until circulating. 5.Run remaining casing. M/U cementing head, install bottom plug and test all lines. 6.Circulate and reciprocate until no gains in circulating efficiency is made. 7.With as little shut down as possible, drop bottom plug and begin pumping spacer. Pump spacer as follows: 40 bbls 18% NaCI 20 bbls drill water 20 bbls Super Flush 20 bbls drill water 40 bbls 18% NaCI 8. Pump 5 bbls drill water. 9. Mix and pump 238 bbls. lead slurry(880 sx). 10. Mix and pump 245 bbls. of tail slurry(1200 sx). Drop top plug. 11. Displace cement. Reciprocate as long as possible. 12. Bump plug w/500-1000 psi over final circulating pressure. Check floats. 13. P/U BOP stack. Set slips. N/U tubing spool. N/U BOP stack. 14. WOC 12 hours. 15. Test BOPE. page 6 VI. MUD PROGRAM MUD PROPERTIES DEPTH DEPTH WEIGHT VISCOSITY WATER MUD FROM TO ppg sec/cF LOSS TYPE 100' 500' 8.6-10 80-250 15-30 Freshwater spud 500' 2000' 9.6-10 42-80 < 12 Non-dispersed 2000' 8428' 9.6-11.5 42-80 <8 PHPA Mud solids and cuttings will be seperated from the mud and disposed of in the Beaver Creek Waste Site, or they will be ground and slurrified for injection into Beaver Creek #2 or KGF #14-4 in the Kenai Gas Field, .~-_~._.__~_-~.~ ...... -~. Uquids from the mud will be hauled to the water disposal facilities on the Beaver Creek Pad lA for injection into Beaver Creek #2, MUD EQUIPMENT The solids control equipment will consist of a shale shaker, a 2-cone desander, a mudcleaner, and a centrifuge. Included will be equipment to dewater the underflow from the mud processing equipment to allow disposal of the cuttings and solids into the Beaver Creek waste cell,or they will be ground and slurrified for injection into Beaver Creek #2, KGF #14-4 in the Kenai Gas Field, or Beaver Creek #3. VII. LOGGING, TESTING, AND CORING PROGRAMS DRIVE PIPE: LOGGING PROGRAM No logging is planned for this interval. CONDUCTOR: No logging is planned for this interval. SURFACE: No logging is planned for this interval. PRODUCTION: NGS/SP/Cal/DIL/BHC from 8,730'-2073 '. FDC/CNL/Cal/GR from 8,730'-2,073'. COMPLETION: A Cement Bond Log (CET/GR) and a directional gyro- survey will be run prior to perforating. CORING PROGRAM Two 60 ft. cores are planned in benches B-23 and B-24 of the Beluga Sand utilizing conventional coring techniques. TESTING PROGRAM No open hole tests are planned for this well. A mud logger will be utilized from the surface casing shoe at 2073' to total depth. page 7 A~'~chorag3 VIII. BO'I'rOMHOLE PRE~--"IRES AND POTENTIAL HAZARDS Anticipated bottomhole pressures in the Steding and Beluga sands are 2200 psi and 3820 psi respectively. Lost returns are possible in the depleted Steding interval. Overpressued gas sands may be encountered between 4000 and 5000 ft. requiring mud weights up to 11.5 ppg. Hydrogen sulfide gas has not been encountered in any well in the Beaver Creek field. IX. OTHER INFORMATION DIRECTIONAL PLAN SOUTH EAST VERT DESC MD 'I'VD INCL AZIM COORD COORD SECTION RKB 0 0 0 S0E 0 0 0 KICKOFF 650 650 0 S0E 0 0 0 build @ 2.5 deg/100ft HOLD 1671 1637 26 S7.1E 222 28 224 tangent section of 25.5 deg DROP 3854 3607 25.5 S7.1 E 1155 144 1164 drop @ .75 deg/100ft. HOLD 5555 5253 0 S0E 1525 190 1537 Total Depth 8730 8428 0 S0E 1525 190 1537 POTENTIAL INTERFERENCE: WELL Beaver Creek #3 Beaver Creek #5 Beaver Creek #6 DISTANCE (ft.) DEPTH (MD) 77 917 52 1050 32 817 page 8 DRILLING PROGRAM DRIVE PIPE: Move in and rig up rotary drilling rig. Drive 30" drivepipe to +-100 ft. RKB. Drive 13-3/8" rathole. Weld 30" MSS flange to drive pipe. Nipple up 29-1/2" -500 psi diverter, diverter valves, and 2-10" diverter lines. Function test diverter and diverter valves. CONDUCTOR: Drill a 17-1/2" hole to 500' per the directional plan. Open the hole to 26". Run and cement 20" casing. WOC. Cutoff 30" and 20". Weld on 20" SOW bradenhead. N/U 20" diverter, diverter valves and 10°' diverter lines. Test diverter and 20" casing to 500 psi. SURFACE: Drill float equipment and 10' of new formation w/17-1/2" bit. Run leak off test. Do not exceed 12.0 ppg equivalent mud weight. Drill a 17-1/2" hole from 500' to 2073' per the directional program. Pull wear bushing. Run and cement 13-3/8" casing. P/U diverter. Set slips, N/D diverter, install casing head and test to 1000 psi. N/U 13-5/8 x 5M BOPE. Test BOPE and choke manifold to 250 psi/3000 psi. Set wear bushing. Test 13-3/8" surface casing to 2000 psi. PRODUCTION: Drill float equipment and 10' of new formation. Run leak off test. Do not exceed 14.0 ppg. equivalent test pressure. Drill a 12-1/4" hole from 2073' to 8730' per the directional program. Log. Pull wear bushing. Run and cement 9-5/8" casing. Pick up stack and set slips. Cutoff 9-5/8" casing and N/U tubing spool. Test tubing spool, BOPE and choke manifold to 250 psi/3000 psi. Test production casing to 3000 psi. Set wear bushing. COMPLETION: Cleanout casing to PBTD. Run gyro and CBL A dual completion of the Steding and Beluga sands is planned. Oil & Gas Cons. Coramissio~'~ page 9 DIVERTER SCHEMATIC BEAVER CREEK ~9 MARATHON OIL COMPANY 10' Remote Operated Valve 29 1/2° x 500~' MSP Annular Diverter Spool I ! ~ Flowline 10' Remote Operated Valve 30' MSS Flange 30' Drive Pipe DIVERTER SCHEMATIC BEAVER CREEK ~9 MARATHON OIL COMPANY lO' Remote Operated Valve L 21-1/4' x 2m Annular -. [ I Diverter Spool I I I (~ Flowllne 10' Remote Operated Valve 20' SOW x 21-1/4' 2m 30' Drive Pipe BOP SCHEMATIC BEAVER CREEK **9 MARATHON OIL COMPANY Rig Floor Annular I I 13-5/8' x 5m Annular Kill Line Pipe Rams Blind Rams I ! II !] Pipe Rams I I HCR 13-5/8' x 5m Double Gate Drilling Spool Choke Line 13-5/8' x 5m Single Gate 21-1/4' x 2m x 13-5/8' x 5m' Casing Spool 21-1/4' x 2m SOW -10o L TYPE LOG BC-1 SP RES 0 1 J L__ '-B_:iA MAPPED . v/ ~ GAS/~-A4TER '-~ -5200 100 29 i 32 · I · I · I i I i BC-7 mill ., RIOW 8C-8 X 27 -6127 B(. / // BC_90 34 BC-tA i UNIT BOUNDARY 'i 8/92 MARATHON OIL COMPANY ALASKA REGION BEAVER CREEK FIELD BEAVER CREEK UNIT KENAI, ALASKA BEAVER CREEK DEVELOPMENT PROJECT STERLING FM. B-4 SAND X C.I.: 50' 0 1/2 1 MILE PENETRATION ABANDONED WELL GAS WELL WATER DISPOS~L~W~E LL -175 TYPE LOG BC-1A SP -10 I RES 100 J I I 8-18 ~ -7200 ~ B-23 ~ HORIZON T ~C-? RIOW BC-: ,*2 i ,11 lllll Ii 10~ UNIT BOUNDARY / 26 8/92 MARATHON OIL COMPANY ALASKA REGION BEAVER CREEK FIELD BEAVER CREEK UNIT KENAI, ALASKA BEAVER CREEK DEVELOPMENT PROJECT TOP OF B-23 SAND L 0 WER BELUGA FM. C.I.: 50' 0 1/2 1 MILE x PENETRATION GAS WELL NET W.I. - 50% ALASKA :CREATED BY : JONES For: L LAMON~ DATE PLOTTED : 28--0CT--92 PLOT REFERENCE IS BC #9, VERSION #3. : COORDINATES ARE IN FEET REFERENCE SLOT #g. TRUE VERTICAL DEPTHS ARE REFERENCE WELLHEAD.i EASTN/IAN MARATHON 0IL Company Sfrucfuro : Pod #3 Woll : B~-~ Hold : Boovor (;reek UnH Locofion : Konoi, ~losko I i .... WELL PROFILE DATA .... i j---- POINT .... MO lNG DIR ~v~) NORTH EASTI i 0J ITIE ON 0 o,oo 205.00 o o -15 j END OF HOLD 650 O.00 205.00 650 0 0 !KOP 10.50 IO.00 205*.00 1044~ -32 j END OF BUILD 1854- 27.57 171.02 1~08 -282 -15 {TARGET 5586 0.00 O.OO 5253 - I 579 j~ND OF HO~) 1~761 O.OQ Q,0Q ~4.:~1~ -I,579 19oj ...... East --> 30" CONDUCTOR cq · . 20 CSG PT ~]]i KOP 2.50 ~ 7.50 L)~ BEGIN TURN TO TARGET (/3i 14-.09 \ 2.5 DEG /I00'DOGLEG 18.49 --,~ ~.o., -~23.14 EOB ~,13 3/8' CSG PT EL ~ MAXIMUM ANGLE (D ~ 27.67 DEG 1 9.50 1 6.50 ~ DROP 1.5 DEG / 100' 13.50 1 O50 (D 7.50 4.50 :~ 8-~,.5o L ' ----,L-- STERLING B-4 / 5600_~ I ~oO~ 8-2 8-4. V 64O11. 5800.. B-15 - 7200_ B- 1 8 _ B-19 8-23 76oo_ B - 2~- B-26 soo( 8-28 8-30 LTD - 9 5/8" CSG PT 840 8800 i i i i i i 12100 I I i o 400 800 1600 SCALEI: 200.00 Vertical Section on 175.14 azimuth with reference 0.00 N, 0.00 E from slot lOO o IOO 200 300 ~oo I I I I I I I I I I I I ~> I-- rq too .. 200 ~ - b 3oo 0 _ 700 -- ---I-- _800 -- _ 900 J - I _1ooo _ _1 $ O0 -- _1200 S 6.86 DEG E 1590' (T0 TARGET) · ..~ o, ,,o~o,,~... MARATHON OIL Company Pad #3 BC-9 slot #9 Beaver Creek Unit Kenai, Alaska PROPOSAL LISTING Your ref : BC #9, Version #3 Our ref : prop605 Other ref : Date printed : 28-0ct-92 Date created : 25-Aug-92 Last revised : 28-0ct-92 Field is centred on 315831.400,2435215.800,999.00000,N Structure is centred on 315831.400,2435215.800,999.00000,N MARATHON OIL Company Pad #3,BC-9 Beaver Creek Unit,Kenai, Alaska Measured Inclin. Azimuth True Vert. R E C Depth Degrees Degrees Depth C O O PROPOSAL LISTING Page 1 Your ref : BC #9, Version Last revised : 28-Oct-92 #3 TANGULAR RDINATES Dogleg Vert Deg/100Ft Sect 0.00 0.00 205.00 0.00 0.00 N 0.00 E 0.00 0.00 100.00 0.00 205.00 100.00 0.00 N 0.00 E 0.00 0.00 30" 500.00 0.00 205.00 500.00 0.00 N 0.00 E 0.00 0.00 20" 650.00 0.00 205.00 650.00 0.00 N 0.00 E 0.00 0.00 KOP 750.00 2.50 205.00 749.97 1.98 S 0.92 W 2.50 1.85 850.00 5.00 205.00 849.75 7.90 S 3.68 W 2.50 7.41 950.00 7.50 205.00 949.14 17.77 S 8.29 W 2.50 16.65 1050.00 10.00 205.00 1047.97 31.56 S 14.71 W 2.50 29.57 1100.00 10.86 199.98 1097.15 39.92 S 18.16 W 2.50 37.46 1200.00 12.77 192.09 1195.03 59.58 S 23.70 W 2.50 56.32 Conductor Csg Pt Begin Turn To Target 1300.00 14.86 186.31 1292.14 83.14 S 27.42 W 2.50 79.27 1400.00 17.05 181.94 1388.28 110.55 S 29.33 W 2.50 106.25 1500.00 19.32 178.57 1483.28 141.75 S 29.41 W 2.50 137.22 1600.00 21.64 175.88 1576.95 176.68 S 27.67 W 2.50 172.11 1700.00 23.99 173.70 1669.12 215.29 S 24.12 W 2.50 210.86 1800.00 26.37 171.88 1759.62 257.49 S 18.75 W 2.50 253.40 1854.42 27.67 171.02 1808.10 281.94 S 15.06 W 2.50 278.12 EOB 2000.00 27.67 171.02 1937.02 348.72 S 4.51 W 0.00 345.68 2071.11 27.67 171.02 2000.00 381.34 S 0.65 E 0.00 378.68 13 2500.00 27.67 171.02 2379.83 578.08 S 31.75 E 0.00 577.73 3000.00 27.67 171.02 2822.64 807.44 S 68.02 E 0.00 3500.00 27.67 171.02 3265.44 1036.80 S 104.28 E 0.00 3741.18 27.67 171.02 3479.04 1147.44 S 121.77 E 0.00 3800.00 26.79 171.02 3531.34 1174.02 S 125.97 E 1.50 3900.00 25.29 171.02 3621.18 1217.38 S 132.83 E 1.50 3/8" Csg Pt 809.78 1041.83 1153.77 Begin Angle Drop 1180.66 1224.53 Ail data is in feet unless otherwise stated Coordinates are from slot #9 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 173.14 degrees. Calculation uses the minimum curvature method. MARATHON OIL Company Pad #3,BC-9 Beaver Creek Unit,Kenai, Alaska Measured Inclin. Azimuth True Vert. Depth Degrees Degrees Depth PROPOSAL LISTING Page 2 Your ref : BC #9, Version #3 Last revised : 28-Oct-92 R E C T A N G U L A R Dogleg Vert C O O R D I N A T E S Deg/100Ft Sect 4000.00 23.79 171.02 3712.14 1258.40 S 139.31 E 1.50 1266.04 4100.00 22.29 171.02 3804.17 1297.06 S 145.42 E 1.50 1305.15 4200.00 20.79 171.02 3897.18 1333.33 S 151.16 E 1.50 1341.84 4300.00 19.29 171.02 3991.12 1367.17 S 156.51 E 1.50 1376.08 4400.00 17.79 171.02 4085.93 1398.58 S 161.48 E 1.50 1407.86 4500.00 16.29 171.02 4181.54 1427.52 S 166.05 E 1.50 1437.14 4600.00 14.79 171.02 4277.88 1453.99 S 170.24 E 1.50 1463.91 4700.00 13.29 171.02 4374.89 1477.95 S 174.02 E 1.50 1488.16 4800.00 11.79 171.02 4472.50 1499.40 S 177.41 E 1.50 1509.85 4900.00 10.29 171.02 4570.64 1518.31 S 180.40 E 1.50 1528.99 5000.00 8.79 171.02 4669.26 1534.68 S 182.99 E 1.50 1545.55 5100.00 7.29 171.02 4768.27 1548.50 S 185.18 E 1.50 1559.53 5200.00 5.79 171.02 4867.62 1559.75 S 186.96 E 1.50 1570.91 5300.00 4.29 171.02 4967.23 1568.43 S 188.33 E 1.50 1579.69 5390.95 2.93 171.02 5058.00 1574.08 S 189.22 E 1.50 1585.41 B-2 5400.00 2.79 171.02 5067.04 1574.53 S 189.29 E 1.50 1585.86 5425.99 2.40 171.02 5093.00 1575.69 S 189.48 E 1.50 1587.04 5496.03 1.35 171.02 5163.00 1577.95 S 189.83 E 1.50 1589.33 5500.00 1.29 171.02 5166.97 1578.04 S 189.85 E 1.50 1589.42 5586.04 0.00 0.00 5253.00 1579.00 S 190.00 E 1.50 1590.39 6000.00 0.00 0.00 5666.96 1579.00 S 190.00 E 0.00 1590.39 6311.04 0.00 0.00 5978.00 1579.00 S 190.00 E 0.00 1590.39 6451.04 0.00 0.00 6118.00 1579.00 S 190.00 E 0.00 1590.39 6500.00 0.00 0.00 6166.96 1579.00 S 190.00 E 0.00 1590.39 7000.00 0.00 0.00 6666.96 1579.00 S 190.00 E 0.00 1590.39 B-3 B-3a Sterling B-4 B-2 B-4 Ail data is in feet unless otherwise stated Coordinates are from slot #9 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 173.14 degrees. Calculation uses the minimum curvature method. MARATHON OIL Company PROPOSAL LISTING Page 3 Pad #3,BC-9 Your ref : BC #9, Version #3 Beaver Creek Unit,Kenai, Alaska Last revised : 28-Oct-92 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C O O R D I N A T E S Deg/100Ft Sect 7301.04 0.00 0.00 6968.00 1579.00 S 190.00 E 0.00 1590.39 B-15 7500.00 0.00 0.00 7166.96 1579.00 S 190.00 E 0.00 1590.39 7626.04 0.00 0.00 7293.00 1579.00 S 190.00 E 0.00 1590.39 B-18 7711.04 0.00 0.00 7378.00 1579.00 S 190.00 E 0.00 1590.39 B-19 7781.04 0.00 0.00 7448.00 1579.00 S 190.00 E 0.00 1590.39 B-23 7961.04 0.00 0.00 7628.00 1579.00 S 190.00 E 0.00 1590.39 B-24 8000.00 0.00 0.00 7666.96 1579.00 S 190.00 E 0.00 1590.39 8061.04 0.00 0.00 7728.00 1579.00 S 190.00 E 0.00 1590.39 B-26 8291.04 0.00 0.00 7958.00 1579.00 S 190.00 E 0.00 1590.39 B-28 8451.04 0.00 0.00 8118.00 1579.00 S 190.00 E 0.00 1590.39 B-30 8500.00 0.00 0.00 8166.96 1579.00 S 190.00 E 0.00 1590.39 8761.04 0.00 0.00 .8428.00 1579.00 S 190.00 E 0.00 1590.39 TD - 9 5/8" Csg Pt Ail data is in feet unless otherwise stated Coordinates are from slot #9 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 173.14 degrees. Calculation uses the minimum curvature method. MARATHON OIL Company Pad # 3 BC-9 slot #9 Beaver Creek Unit Kenai, Alaska CLEARANCE REPORT Your ref : BC #9, Version #3 Our ref : prop605 Other ref : Date printed : 28-Oct-92 Date created : 25-Aug-92 Last revised : 28-Oct-92 Field is centred on 315831.400,2435215.800,999.00000,N Structure is centred on 315831.400,2435215.800,999.00000,N Main calculation performed with 3-D minimum distance method Object wellpath GMS <8000-16247'>,,BC-5,Pad #3 GMS <0-15844'>,,BC-6,Pad #3 MSS <0-6395'>,,BC-3,Pad #3 Closest approach with 3-D minimum distance method Last revised Distance M.D. Diverging from 5-Sep-92 52.4 1050.0 1050.0 5-Sep-92 31.6 816.7 816.7 5-Sep-92 76.9 916.7 916.7 M.D. 0.0 100.0 200.0 300.0 400.0 500.0 600.0 650.0 700.0 750.O 800.1 850.0 900.5 950.0 1001.4 1050.0 1100.0 1102.9 1200.0 1205.1 1300.0 1308.1 1400.0 1412.3 1500.0 MARATHON OIL Company Pad #3,BC-9 Beaver Creek Unit,Kenai, Alaska Reference wellpath CLEARANCE LISTING Page 1 Your ref : BC #9, Version #3 Last revised : 28-Oct-92 Object wellpath T.V.D. Rect Coordinates M.D. T.V.D. 0.0 0.0N 0.0E 0.0 0.0 100.0 0.0N 0.0E 100.0 100.0 200.0 0.0N 0.0E 199.9 199.9 300.0 0.0N 0.0E 299.9 299.9 400.0 0.0N 0.0E 399.9 399.9 500.0 0.0N 0.0E 500.0 500.0 600.0 0.0N 0.0E 600.1 600.1 650.0 0.0N 0.0E 650.0 650.0 700.0 0.5S 0.2W 699.9 699.9 750.0 2.0S 0.9W 749.6 749.6 800.0 4.4S 2.1W 799.7 799.7 849.7 7.9S 3.7W 849.7 849.7 900.0 12.4S 5.8W 900.1 900.1 949.1 17.8S 8.3W 949.3 949.3 1000.0 24.4S ll.4W 1000.2 1000.1 1048.0 31.6S 14.7W 1048.1 1048.1 1097.1 39.9S 18.2W 1097.3 1097.2 1100.0 40.4S 18.3W 1100.1 1100.1 1195.0 59.6S 23.7W 1195.5 1195.4 1200.0 60.7S 23.9W 1200.4 1200.4 1292.1 83.1S 27.4W 1292.1 1292.0 1300.0 85.2S 27.6W 1299.9 1299.9 1388.3 110.5S 29.3W 1388.1 1388.0 1400.0 114.2S 29.4W 1399.8 1399.8 1483.3 141.7S 29.4W 1483.2 1483.2 : GMS <8000-16247'>,,BC-5,Pad #3 Angle fm Rect Coordinates HighSide 49.2S 35.1E -60.5 49.2S 35.2E -60.6 49.2S 35.3E -60.7 49.3S 35.6E -60.8 49.3S 35.8E -61.0 49.2S 35.8E -61.0 49.2S 35.5E -60.8 49.2S 35.3E -60.6 49.4S 35.2E -60.9 49.7S 35.1E -62.1 50.1S 35.2E -64.2 50.3S 35.0E -67.5 50.4S 34.8E -72.0 50.4S 34.6E -77.9 50.5S 34.4E -85.3 50.7S 34.1E -93.5 51.1S 33.8E -97.8 51.1S 33.8E -98.0 51.7S 33.4E -109.5 51.7S 33.4E -110.2 51.8S 32.9E -122.5 51.8S 32.9E -123.5 51.6S 33.1E -132.7 51.6S 33.1E -133.8 51.3S 33.1E -139.7 Min'm Dist 60.4 60.5 60.6 60.8 60.9 60.9 60.7 60.6 60.4 59.8 58.9 57.4 55.6 53.9 52.7 52.4 53.2 53.2 57.6 58.0 68.0 69.2 85.8 88.5 109.9 TCyl Dist 60.4 60.5 60.6 60.8 60.9 60.9 60.7 60.6 60.4 59.8 58.9 57.4 55.6 53.9 52.7 52.4 53.2 53.2 57.8 58.2 68.7 70.0 87.9 90.8 114.2 All data is in feet unless otherwise stated Coordinates are from slot #9 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 173.14 degrees. Calculation uses the minimum curvature method. Alas!<a Oil & ~as Coi~s. ~on}mj~sJon M.D. MARATHON OIL Company Pad #3,BC-9 Beaver Creek Unit,Kenai, Alaska Reference wellpath T.V.D. Rect Coordinates 1517.7 1500.0 147.7S 29.2W 1600.0 1577.0 176.7S 27.7W 1624.8 1600.0 185.9S 27.0W 1700.0 1669.1 215.3S 24.1W CLEARANCE LISTING Page 2 Your ref : BC #9, Version #3 Last revised : 28-Oct-92 Object wellpath : GMS <8000-16247'>,,BC-5,Pad #3 Angle fm Min'm M.D. T.V.D. Rect Coordinates' HighSide Dist 1499.9 1499.9 51.3S 33.1E -140.6 114.7 1577.3 1577.3 51.4S 33.1E -143.7 139.2 1600.4 1600.4 51.5S 33.1E -144.3 147.3 1669.8 1669.8 51.8S 33.2E -145.6 173.2 TCyl Dist 119.6 147.1 156.2 186.4 Ail data is in feet unless otherwise stated Coordinates are from slot #9 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 173.14 degrees. Calculation uses the minimum curvature method. M.D. 0.0 100.0 200.0 300.0 400.0 500.0 600.0 650.0 700.0 750.0 800.1 850.0 900.5 950.0 1001.4 MARATHON OIL Company Pad #3,BC-9 Beaver Creek Unit,Kenai, Alaska Reference wellpath T.V.D. Rect Coordinates CLEARANCE LISTING Page 3 Your ref : BC #9, Version #3 Last revised : 28-Oct-92 Object wellpath : GMS <0-15844'>,,BC-6,Pad #3 Angle Rect Coordinates HighS M.D. T.V.D. 0.0 0.0N 0.0E 0.0 0.0 100.0 0.ON 0.0E 100.0 100.0 200.0 0.0N 0.0E 200.0 200.0 300.0 0.0N 0.0E 300.0 300.0 400.0 0.ON 0.0E 400.0 400.0 500.0 0.0N 0.0E 500.0 500.0 600.0 0.0N 0.0E 600.0 600.0 650.0 0.ON 0.0E 650.0 650.0 700.0 0.5S 0.2W 700.0 700.0 750.0 2.0S 0.9W 750.0 750.0 18.0S 26.6E -81 18.0S 26.6E -81 18.0S 26.6E -81 18.0S 26.6E -81 18. OS 26.6E -81 fm Min'm TCyl ide Dist Dist .0 32.1 32.1 .0 32.1 32.1 .0 32.1 32.1 .0 32.1 32.1 .0 32.1 32.1 18.0S 26.6E -81.0 18.0S 26.6E -80.9 18.0S 26.6E -80.8 18.1S 26.5E -81.6 18.2S 26.4E -84.4 26.4E -89.1 26.3E -95.7 26.2E -104.1 26.1E -113.3 26.0E -123.0 25.8E -131.4 25.7E -134.3 25.7E -134.4 25.6E -139.5 25.5E -139.8 800.0 4.4S 2.1W 800.0 800.0 18.3S 849.7 7.9S 3.7W 849.8 849.8 18.4S 900.0 12.4S 5.8W 900.0 900.0 18.5S 949.1 17.8S 8.3W 949.2 949.2 18.7S 1000.0 24.4S ll.4W 1000.1 1000.1 18.8S 1050.0 1048.0 31.6S 14.7W 1048.1 1048.1 19.0S 1100.0 1097.1 39.9S 18.2W 1097.3 1097.3 19.2S 1102.9 1100.0 40.4S 18.3W 1100.2 1100.2 19.2S 1200.0 1195.0 59.6S 23.7W 1195.3 1195.3 19.6S 1205.1 1200.0 60.7S 23.9W 1200.2 1200.2 19.6S 1300.0 1292.1 83.1S 27.4W 1292.4 1292.4 20.0S 25.4E 1308.1 1300.0 85.2S 27.6W 1300.3 1300.3 20.0S 25.4E 1400.0 1388.3 l10.5S 29.3W 1388.7 1388.7 20.3S 25.3E 1412.3 1400.0 114.2S 29.4W 1400.4 1400.4 20.4S 25.3E 1500.0 1483.3 141.7S 29.4W 1483.8 1483.8 20.7S 25.2E All data is in feet unless otherwise stated Coordinates are from slot #9 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 173.14 degrees. Calculation uses the minimum curvature method. 32.1 32.1 32.1 32.1 32.1 32.1 32.0 32.0 31.8 31.8 31.6 31.6 31.8 31.8 32.6 32.6 34.4 34.4 37.7 37.9 42.5 42.7 48.5 49.0 48.9 49.4 63.4 64.4 64.3 65.3 -143.7 82.4 84.3 -144.0 84.1 86.1 -146.6 105.4 109.0 -146.9 108.6 112.4 -148.4 132.8 139.0 R CE{VED · .~Jaska Oij & Gas Cons, Con]mission Anchorage M.D. MARATHON OIL Company Pad #3,BC-9 Beaver Creek Unit,Kenai, Alaska Reference wellpath CLEARANCE LISTING Page 4 Your ref : BC #9, Version #3 Last revised : 28-Oct-92 Object wellpath : GMS <0-15844'>,,BC-6,Pad #3 T.V.D. Rect Coordinates M.D. T.V.D. Angle fm Min'm Rect Coordinates HighSide Dist 1517.7 1500.0 147.7S 29.2W 1500.6 1500.6 20.8S 1600.0 1577.0 176.7S 27.7W 1577.5 1577.5 21.1S 1624.8 1600.0 185.9S 27.0W 1600.6 1600.6 21.2S 25.2E -148.6 25.2E -149.0 25.2E -149.1 138.0 164.3 172.8 TCyl Dist 145.0 174.7 184.5 Ail data is in feet unless otherwise stated Coordinates are from slot #9 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 173.14 degrees. Calculation uses the minimum curvature method. M.D. 0.0 100.0 200.0 300.0 400.0 500.0 600.0 650.0 700.0 750.0 800.1 850.0 900.5 950.0 1001.4 1050.0 1100.0 1102.9 1200.0 1205.1 1300.0 1308.1 MARATHON OIL Company Pad #3,BC-9 Beaver Creek Unit,Kenai, Alaska Reference wellpath CLEARANCE LISTING Page 5 Your ref : BC #9, Version #3 Last revised : 28-Oct-92 Object wellpath T.V.D. Rect Coordinates M.D. T.V.D. 0.0 0.0N 0.0E 0.0 0.0 100.0 0.0N 0.0E 99.9 99.9 200.0 0.0N 0.0E 199.7 199.7 300.0 0.0N 0.0E 299.7 299.6 400.0 0.0N 0.0E 399.7 399.6 500.0 0.0N 0.0E 499.6 499.6 600.0 0.0N 0.0E 600.4 600.4 650.0 0.0N 0.0E 652.5 652.4 700.0 0.5S 0.2W 703.2 703.1 750.0 2.0S 0.9W 754.2 753.8 800.0 4.4S 2.1W 804.2 803.5 849.7 7.9S 3.7W 853.1 851.9 900.0 12.4S 5.8W 901.9 900.0 949.1 17.8S 8.3W 949.1 946.5 1000.0 24.4S ll.4W 997.3 993.9 1048.0 31.6S 14.7W 1042.7 1038.5 1097.1 39.9S 18.2W 1089.0 1083.8 1100.0 40.4S 18.3W 1091.1 1085.9 1195.0 59.6S 23.7W 1178.0 1170.6 1200.0 60.7S 23.9W 1182.6 1175.1 1292.1 83.1S 27.4W 1262.3 1252.1 1300.0 85.2S 27.6W 1269.4 1259.0 : MSS <0-6395'>,,BC-3,Pad #3 Angle fm Rect Coordinates HighSide Min'm Dist 81.3S 40.6E -51.6 90.9 81.6S 40.2E -51.2 91.0 82.4S 38.9E -50.3 91.2 83.4S 37.7E -49.3 91.5 84.2S 36.7E -48.6 91.9 85.0S 3610E -48.0 92.3 85.6S 35.4E -47.5 92.6 84.6S 35.8E -48.0 91.9 82.1S 37.5E -49.9 90.0 78.6S 40.1E -53.4 87.0 74.0S 43.6E -58.6 83.3 68.6S 47.9E -65.6 79.7 62.4S 53.1E -74.7 77.2 56.1S 58.5E -84.9 77.0 49.4S 64.3E -95.9 80.0 43.0S 70.1E -105.8 86.1 35.9S 76.2E -110.1 95.3 35.6S 76.4E -110.2 96.0 20.8S 88.8E -116.7 121.5 20.0S 89.6E -117.0 123.1 4.4S 102.4E -120.3 157.0 2.9S 103.6E -120.6 160.3 TCyl Dist 90.9 91.0 91.2 91.5 91.9 92.3 92.6 91.9 90.1 87.2 83.5 79.9 77.3 77.1 80.3 87.3 97.8 98.5 128.9 130.8 174.0 178.4 All data is in feet unless otherwise stated Coordinates are from slot #9 and TVDs are from wellhead. Vertical section is from wellhead on azimuth 173.14 degrees. Calculation uses the minimum curvature method. N OV - 4 Alaska_ Oil & Gas Cons. 6ommissiO" ~nchorage Coastal Project Questionnaire and Certification Statement Please answer all questions. To avoid a delay in processing, please call the department if you answer "yes" to any of the questions related to that department. Maps and plan drawings must be included with your packet. An incomplete packet will be returned. · APPLICANT IN'FORMATION l. MARATHON OIL COMPANY Name of AppLicant P.O. BOX 190168 Address ANCHORAGE: ALASKA City Sram (9O7) 561-5311 - Daytime Phone 2. GUY WHITLOCK Contact Pcmon P.O. BOX 190168 Address 99519 ANCHORAGE, ALASKA 99519 Zip Code City Statc Zip Codc (907) 56/4-6326 Daytime Phone (907) 564-6489 Telecopy Number · PROJECT INFORMATION Provide a brief description of your entire project and ALL associated facilities (access roads, caretaker facilities, waste disposal sites, etc.). Please use an extra sheet of paper if necessary. To drill and complete Well BC-9 as a gas well in Beaver Creek Field on Pad 3. please see Surface Use Plan. Proposed starting date for project: 06-01-93 Proposed ending date for project: 08-01-93 Attach a detailed description of the project and all associated facilities. Include a project timeline for completion of all major activities in the proposal, a site plan depicting all proposed actions, and any other supporting documentation that would facilitate review of the project. · PROJECT LOCATION Location of project (include nearest community or name of the land feature or body of water. Identify-...; _ ,' :_ :' , township, range and section): Marathon's Beaver Creek Production Facilities, Pad#3, 1200'FNL, Township 7N Range 10W Section 34 Meridian Seward USGS Map /1460'FWL. Revised 6/99_ Page I , The project is on: i"-I State Land* ~ Federal Land [~l Private Land [] Municipal Land *State land can be uplands, tidelands, or sub, merged lands to 3 miles offshore. See Question #I in DNR section. The project is located in which region (see attached map)' I-'] Northern [] Southcentral [] Southeast Attach a copy of the topographical map with the project location marked on it. CURRENT APPROVALS Yes No Do you currently have any State or federal approvals for this project? ............. [] Note: Approval means permit or any other form of authorizcaion. If "yes," please list below: Stat~ Review ID# (pr~vio~ly AppmvaJ Type Approval # Expiration Date aasigne..d by DC_.K2) [] FEDERAL APPROVALS Is the proposed project on U.S. Forest Service (USFS) land or will you need to cross Yes No USFS lands for access? .......................................... [--] IX't If yes, have you applied for or do you intend to apply for a USFS permit or approval? Date of submittal' Does the cost of the project exceed S250.0007 ............................ 12~1 1--] Will you be constructing, a bridge over tidal (ocean) waters, or navigable rivers, streams or lakes? .............................................. If yes, have you applied for or do you intend to apply for a U.S. Coast Guard permit for the bridges? ................. [-I . . I-3 Date of submittal: Will you be placing structures or fills in any of the following: tidal (ocean) waters? streams? lakes? wetlands*? ........................... [--I *If you are not certain whether your proposed project is in a wetlands, contact the fl.& Corps of Engi- neers, Regulator~,~ Branch at (907) 753-2720 for a wetlands deter~rdnation (outside the Anchorage area ca~l toll free 1-800-478-271Z) If yes, have you applied for or do you intend to apply for a U.S. Army Corps of Engineers (COE) permit? ..................................... Date of submittal: Revised 6/c~_ Page 2 . o Have you applied for, or do you intend to apply for a U.S. Environmental Protection Agency National Pollution Discharge Elimination System permit? (Note: i:or in./'om,,uio,, Yes regarding the need for an NPDES permit, coraact EPA at (907) 271-50830 ................... ['~ Date of submittal: Have you applied for or do you intend to apply for permits from any other federal agency? .................................................... AGENCY APPROVAL TYPE DATE SUBMITTED Bureau of Land Management Permit to Drill No [] DEPARTMENT OF NATURAL RESOURCES ~NR) APPROVALS Note: In n~_ition to State-owned uplands, tt~ State owns almost a21 land below the ordinary high water line of navigable streams, rivers and lakes, and the mean high tide line seaward for three miles. Is the proposed project on State-owned land or will you need to cross State-owned land Yes for access? .................................................. I--] o Is any portion of your project to be placed on State-owned land below the ordinary high water line of a stream, river, or lake, or the mean high water line of a salt- water body? ................................................. I--I 3. Do you plan to construct an aquatic farm on State-owned land? .................. [-] Do you plan to dredge or otherwise excavate/remove materials on State-owned land? .... l--'] Location of dredging site if other than the project site. (describe J: Township Range Section Meridian . Do you plan to place fill or dredged material on State-owned land? ............... I-] Location of fill disposal site if other than the project site. (describe): Township Range Section Meridian Source is on: [--] State Land ~ Federal Land [--] Private Land [~ Municipal Land o Do you plan to use any of the following State-owned resources: ................. [-] [-~ Timber:. Will you be harvesting timber? Amount: [-] Materials such as rock, sand or gravel, peat, soil, overburden, etc.: Which material? Amount: No Rcvis-~l 6/92 Page 3 . . o I0. 12. 13. 14. 15. Location of source if other than the project site: (describe): Township Rmage Section Meridian Are you planning to use any fresh water? Amount (gallons per day): dtt6 Source: (::~t37~d6~ 6d~r~ No Will you be building or altering a dam? ................................ Do you plan to drill a geothermal well? ................................ [~ At any one site (regardless of land ownership, do you plan to do any of the following7 . .. Mine five or more acres over a year's time? Mine 50,000 cubic yards or more of materials (rock, sand or gravel, soil, peat, overburden, etc.) over a year's time? [] Have a cumulative unrectaimed mined area of five or more acres? If you plan to mine less than the acreage/amount stated above and have a cumulative unreclaimed mined area of less than five acres, do you intend to file a voluntary recla- mation plan for approval? ......................................... [--] Will you be exploring for or extracting coal? ............................ 7-] [] Will you be drilling for oil/gas? ..................................... [X'-I [] Will you be investigating or removing historical or archaeological resources on State- owned land? ................................................. [~] Is the proposed project located in a unit of the Alaska State Park System? ........... [-] [] If you answered "No" to ALL questions in this section, you do not need an approval from DNR. Continue to next section. If you answered "Yes" to ANY questions in this section, contact DNR to identify and obtain necessary application forms. Based on your discussion with DNR, please complete the following: Approval Type Date Submitted Temporary Water Use Permit //- 2-qz. Permit to Drill Have you paid the filing fees required for the DNR permits? ................... ~ [~ Revised 6/99_ Page 4 16. If you answered yes to any questions and are not applying for DNR permits, indicate reason below: (DNR contact) told me on approvals or permits were required on this project. Reason given by DNR: that no DNR tv} b. Other: · DEPARTMENT OF FISH & GAME (DFG) APPROVALS Will you be working in, or placing anything in, a stream, river or lake? CI'his includes work in running water or on ice, within the active flood plain, on islands, the face of Yes the bank~ or the tidelands down to mean low tide.) ......................... [-l Will you do any of the following? .................................... [-"I Please indicate below: Build a dam, river training structure or instream impoundment? Use the water? Pump water out of the stream or lake? Divert or alter the natural stream channel? Block or dam the stream (temporarily or permanently)? Change the water flow or the water channel? Introduce silt, gravel, rock, petroleum products, debris, chemicals, or other organic/inorganic waste of any type into the water? Use the stream as a road (even when frozen), or crossing the stream with tracked or wheeled vehicles, log-dragging or excavation equipment (back- hoes, bulldozers, etc.)? Alter or stabilize the banks? Mine or dig in the beds or banks? Use explosives? Build a bridge (including an ice bridge)? Install a culvert or other drainage structure? Construct a weir? Use an in-stream structure not mentioned here? If yes, describe: No o . . Revised 6/92 Is your project located in a designated State Game Refuge, Critical Habitat Area or State Sanctuary? ............................................... l--] Does your project include the construction/operation of a salmon hatchery? .......... [--I Does your project affect, or is it related to, a previously permitted salmon hatchery? .... [--'] Pag~ 5 Yes No Does your project include the construction of an aquatic farm? ................... If you answered "No" to ALL questions in this section, you do not need approval from DFG. Continue to next section. If you answered "Yes" to ANY questions under 1-3, contact the Regional DFG Habitat Division Office for information and application forms. If you answered ~Yes" to questions 4--6, contact the DFG at the FRED division headquarters for information and application forms. Based on your' discussion with DFG, please complete the following: Approval Type Date Submitted If you answered yes to any questions and are not applying for DFG permits, indicate reason below: [--] a. (DFG contact) told me on that no DFG approvals or permits were required on this project. Reason given by DFG: ~ b. Other: · DEPARTMENT OF ENVIRONMENTAL CONSERVATION (DEC) APPROVALS Will a discharge of wastewater from industrial or commercial operations occur including Yes No storm water drainage? ........................................... [--] [] If so, will you be connecting to an already approved sewer system? ............... [-=I ~ . Do you intend to construct, install or modify any part of a wastewater (sewage or greywater) disposal system? ....................................... so, will the discharge be 500 gpd or greater? ........................... ['-] Do you expect to request a mixing zone for your proposed project? (Tfyour wastewater discharge will exceed Alaska water quali~ standards, you may apply for a mixing zone. If so, please contact DEC to discuss inforvnation required under 18 AAC 70.032.) Revised 6/92_ Page 6 . . o Will the project result in either of the following: ........................... [] Dredging in a wetland or other water body? ['-I Placement of fill materials or a structure in a wetland or other waterbody? (Note: Your application for this activity to the Corps of Engineers also serves as your application to DEC.) Will your project produce any domestic or industrial solid waste that, because of logis- tics or the nature of the material, cannot be disposed of in a presently permitted land- fill? ....................................................... Will your project require the application of oil or pesticides to the surface of the land? . . . [-] bo Co do eo Will you have a facility that will generate air emissions from processing greater than five tons per hour of material? ......................... [--I Will you have one or more units of fuel burning equipment with a heat input rating of 50 million Btu per hour or more? ......................... I) Will you have a facility containing incinerators with a total charging capacity of 1,009 pounds per hour or more? ................... ['-] 2) Do you incinerate sludge? ............................... [--I Will you have any of the following processes: ....................... [-] ~ Asphalt plant Petroleum refinery Coal preparation facility Portland cement plant Will your facility use the following equipment? ....................... [] ~ diesel internal combustion engines? (Tom capacity greater than 1.750 ta'lowatt) or total rated brake specific horsepower greater than i300 bhp) l--I gas fired boilers (Tot~ heat input rating of JO0 million Btu per hour) [] oil fired boilers (Total heat input rating of 65 million Btu per hour) ['-I combustion turbines (total rated power output of 8.000 Hp) Will your facility burn more than the following per year in stationary equip- ment? ................................................ I--I I--I 1,000,000 gallons of fuel oil [-I 900 million cubic feet of natural gas [--I 35,000 tons of coal If you have answered 'yes" to any of the above questions (7 a-f), have you in- stalled, replaced or modified any fuel burning or processing equipment since 19777 ................................................ [-'4 No Revised 6/92 Page , . Will you be altering a public water system? Yes ad bo Will your project involve the operation of waterborne tank vessels or oil barges that carry crude or non-crude oil as bulk cargo, or the transfer of oil or other petroleum products to or fi.om such a vessel or a pipeline system? ........... Will your project require or include onshore or offshore oil facilities with an effective aggregate storage capacity of greater than 5,000 barrels of crude oil or greater than 10,000 barrels of non<rude oil? ...................... I-'] No 10. Co Will you be operating facilities on the land or water for the exploration or pro- duction of hydrocarbons? .................................... t'~ Will you be subdividing lands into two or more lots (parcels)? If you answered NO to ALL questions in this section, you do not need a permit or approval from DEC. Please continue to certification statement. If you answered YES to ANY of these questions (see #4 note), contact the DEC Regional office for information and application forms. Based on your discussion with DEC, please complete the following: Approval Type Date Submitted If you answered yes to any questions and are not applying for DEC permits, indicate reason below: ~ a. (DEC contact) told me on that no DEC approvals or permits were required on this project. Reason given by DEC: [~ b. Other: Revised 6/92 Page 8 Certification Statement The information contained herein is tree and complete to the best of my knowledge. I certify that the proposed activity complies with, and will be conducted in a manner consistent with, the Alaska Coastal Management Program. Signature of Applicant or Agent Note: Federal agencies conducting an activity that will affect the coastal zone are required to submit a federal consistency determination, per 15 CFR 930, Subpart C, rather than this certification statement. To complete your packet, please attach your State permit applications and copies of your federal permit applications to this questionnaire. Revised 6/92 Page 9 Slate: Alaska Borough: V/ell: BC#9 Field: Beaver Creek '.-31. Perm # 92-122 BC~IS'CSG.XLS Date 12111192 Engr: M. Minder Casing Interval Interval Size Bottom Des~iption Description Description Tension Top Ler, gth lA 20 5OO 0 50O 2.A 13.375 2000 0 ~2000~"~ 3A 9.625 7221 0 4A 9.625 8428 '7221 1207 5A 0 0 0 0 6A 0 0 0 0 7A 0 0 0 0 8A 0 0 0 0 9A 0 0 0 0 10A 0 0 0 0 Lbs Grade Thread Lbs 193 X-56 RL4S 0 61 K-55 BTC 0 4'7 N-80 BTC 0 59.5 N-80 BTC 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Mud Hydraulic Wieght Gradient ppg psi/ft lB 10.0 0.520 2B 10.0 0.520 3B 11.5 0.598 4B 11.5 0.598 5B 0.0 0.000 6B 0.0 0.000 7B 0.0 0.000 8B 0.0 0.000 9B 0.0 0.000 1 OB 0.0 0.000 Maximum Minimum Pressure Yield psi psi BDF 500 3150 6.3 2000 3090 1.5 9257 6870 2~1 3257 7930 2.4 0 0 #OlV/O! 0 0 #DiVl0) 0 0 #DlVf0! 0 0 #DIV~'0! 0 0 #DIM/0! 0 0 #DIM/O! Tension Strength K/Lbs K/Lbs 1C 66.5 2130 2C 122 962 $C 353.581 1086 4C 64.5745 5C 0 6C 0 ?C 0 8C-' 0 9C 0 10C 0 TDF 32.03 7.89 3.07 1244 19.26 0 #DIVi0! 0 #DlVi0! 0 #DiVIO! 0 #DIVlO! 0 #glVlO! 0 #DlVl0! Collapse Collapse Pr-Bot-Psi Resist. 6DF 260 1450 5.577 1040 ~ 1.481 4318 47.50 1.100 5040 ~2r~ 1.314 0 0 #DIV/O! 0 0 #DiviO.i 0 0 #DIM/0! 0 0 #DIVED! 0 0 0 0 #DIVlO! BcIIgCMT.×LS State: Well: Field: State Permit 122 Engineer. 'w'ork Sheet: Date: Cer~en! Vo&rr~ C~tc~lion,~ 12..'71/92 C~ng T~pe Casing Size Casing Length Hole Diamete[ Cement- Sacks Cement-Yield Cement- Cubic ft Cement- Cubic ft Cement- Sacks Cement- Yield Cement- Cubic ft Cement- Cubic tt Cement-Sacks Cement- Yield -Inches - Feet -Inches 111 111 111 111 112 112 112 112 113 113 Cement- Cubic it 113 Cement-Cubic ft 113 Cement- Cubic tt ! Vol Cement- Fill Factor Casing T.~e Casing Size -inches Casing Deplh- Feet Hole Diameter -Inches Cement- Sacks 111 Cement-Yield111 Cement- Cubic It 111 Cement-Cubic tt 111 Cement-Sacks112 Cement- Yield 112 Cement- Cubic tt 112 Cement- Cubic it II2 Cement-Sacks113 Cement- Yield 113 Cement- Cubic it 113 Cement- Cubic ft 113 Cement- Cubic it ! Vol Cement-InterYal fl. Top of Cement- Feet Conducto~ 20.000 500.000 26.000 590.000 1.540 908.600 908.600 580.000 1.170 678.600 678.600 1..587.200 2.109 Intermediate 111 0.000 0.000 0.000 0.00 0~00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11DIV/O! IIDIV/O! SurFace 13.375 2,073.000 17. 500 1,240.000 1.540 1,909.600 1,909.600 240.000 1.160 278.400 278.400 0.000 0.000 0.000 0.000 2,188.000 1.519 o1~ Intermediate 112 0.000 0.000 0.000 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11DIV/O! I~DIV/O! P6nted 12/11/92 Line[ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 1~DIV/O! Roduction 9.625 8,730.000 12.250 I~0.00 1.53 1,348.40 1,346.40 1,200.00 1.15 1,380.00 1,380.00 0.00 0.00 0.00 0.00 2,726.40 8,705.49 24.5 Ok: Measured Depth (1) ~ee (2) Loc ** CHECK LIST FOR NEW WELL PERMITS ** · PROVE DATE '[ 2--~hru ,, 5. 6. 7. 8. 9. 10. [9 thru 13] [10 & 13] 12. 13. [14 thru 22] 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. Company /~//o~ Is permit fee attached ............................................... Is well to be located in a defined pool .............................. (5) BOPE ~,~,~, [23 thru 28] IS well located proper distance from property line ............. : ..... Lease & Well ~-O2-~O~ YES NO Is well located proper distance from other wells ..................... Is sufficient undedicated acreage available in this pool ............. Is well to be deviated & is wellbore plat included ................... Is operator the only affected party .................................. Can permit be approved before 15-day wait ............................ Does operator have a bond in force ................................... Is a conservation order needed ....................................... Is administrative approval needed .................................... Is lease n~nber appropriate .......................................... Does well have a unique name & n~nber ................................ Is Wi to Is Wi Wi Wi Is Is Is Is Is drilling fluid program schematic & list of equipment adequate ..... Are necessary diagrams & descriptions of diverter & BOPE attached .... Does BOPE have sufficient pressure rating -- test to ,~~ psig ..... Does choke manifold comply w/API RP-53 (May 84) ...................... Is presence of H2S gas probable ...................................... conductor string provided ......................................... ll surface casing protect all zones reasonably expected serve as an underground source of drinking water .................. enough cement used to circulate on conductor & surface ............ ll cement tie in surface & intermediate or production strings ...... ll cement cover all known productive horizons ..................... ll all casing give adequate safety in collapse, tension, and burst. well to be kicked off from an existing wellbore ................... old well bore abandonment procedure included on 10-403 ............. adequate wellbore separation proposed ............................. a diverter system required ........................................ REMARKS (6) Other /~c ~/~/~u31] [ 29 th ,~3 2 ] (8) Addl geo 1 ogy · DWJ~ eng i nee r i n9: MTM~ RAD~ rev 08/18/92 jo/6.011 29. 30. 31. 32. 33. FOR EXPLORATORY & STRATIGRAPHIC WELLS: Are data presented on potential overpressure zones ................... Are seismic analysis data presented on shallow gas zones ............. If offshore loc, are survey results of seabed conditions presented... Name and phone nt~nber of contact to supply weekly progress data ...... Additional requirements ............................................. INITIAL GEOL UNIT ON/OFF POOL CLASS STATUS AREA # SHORE Additional remarks' -r Z Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history, file.. To improve the readability of the Well History file and to simplify finding information, information-of this nature is accumulated at the end of the file under APPENDIX. No special'effort has been made to chronologically organize this category of information. ,Ch lUmp,etcher Page ***************************** * , ***************************** ***************************** LTS/~ Ohv~ir,31 rocor ~P 9~ Sl.~D A2.~94 94]LOG_O28.LIS '~<ell. ~ame BEAVER CRMEK ~9 ~, F J,.e ld ~:~ a~e B~AVER State ALASKA $~rvice ~3rder ?~umber 549~7~ Date 26-SEP-94 ~Un ~4 u?~tbe r TwO MICROFILMED ~)~ r¥ odtput i c ated by T/SO~,!¢.'i&RY I sum~'~ar~es written for Lo,ica! LIS struc%ures: I wlbE (~bhrev: F) LT~ logical ~le ~Dfo ! rAPE (Abbrev: ~) LT6 loqtca! tape in¢o t ~E~L (~bhrev~ ~) [,TS logical reel ~nfO I and for the entire bTS/,& i.put loqlcal unit: ! f,U (Abhrev: L) LTS/~ logical unit ~DfO The field labels appear on so~e or all of these t summaries, as ~[~d~.cated hV the abDrev, on right. I .,t~,uS uL]mver of logical reels ,)n (5 ) I TRPES ~u~ber of lonlcal taDes on ~£r,ES ~!umber o~ looical files on fliRT ) t fiP~ ~,iurnber of ~hVsiCal records (LRTF) I .~,,p Uu~ber o~ lo~ical ~ecor~s (LRTF) I ~DP ~)u~oer o~ data records ( F) 1 ~,E~C ¢0umDer of encrypted records ( F) ! ~[;"~ ~umber of data frames ( F) i ~I_UN[~S ~rlmarv index units mneraonlc ( F) ! ~AXPT ~aximtim primary l.n~ex value ( F) i ~I~P! "inimU~ Dr~mar¥ index value [,T5~.: ~t. St,)~'A?,~q42q41bnq i)p8 bTS~I EFaUL? ader D$ST~ .028 e data recoro($) enco~mtered , !~ .DR ~Fv PI P ',I$ ~AXPI MINPI ---;~ ......... ~;~ .... ~; ...... ; ....... ; ...... .... .......... .... ~8 0 D~ T,1! 1o65660 1029960 DEPT F ~8~0 5 8583 DmPT ,! 2706' ' .7764 2616.0984 26-SEP-~4 Mhd o£ llstlnq 10:05t56 Paqe 3 Chlumherqer Ll$,'i.! r.~hvsic~l, record ~a~ of ~1SD~~4~4~OG_O~I8~I USinq co~,~and L,!ST/~R~EF/OOTPUT=(t, 0G~.LS~,UM~Y Co!'~'~anv ?,;an~ ~R~T~c)~,: OIL CO~'~~. F~,e]d ~,.~a~.~ ~EAvER CREEK State AI.,~%SKA Service 3taler ~.~umber 54997~ L~a te 2 6 Page HICI OFILMED = .... rv nutput created LIST/SD~*~ARY summaries wr~tten for Y,oolcal bls structures: Wll~E (~Obrev: F) o logical file info TA~6~ (St~rev: ~) b!~ logical tapo info ~EEL (.~bbrev~ ~) ~!S log~.cai reel info an~ for e.~e enti~e b'~S/A ing~ut logical unit: I.,U (~:,brev~ [,) I,~S/A logical u~It ~.~fo field !.abels a~oear on some or ali of these Summary Field ~,abels~ ~E~LS ~.~]mhe:r of ]onlca]. reels on ([, ) T~P~,g ~u~Der of ].o~ica] fades on ([,R ) FI?,ES '~umDer of logical flies on (LRT ~'P~ '~umoer of ~nvs~cal records ~ ~],~ber of lo~lcai records (LRTF) ~Qs ~umber of data records .ncrvpte~ record~ ( ~F,~ ~umoer of t~ata frames ( F) ~r~F~arv ,~n~ex channel name ( F) oi_U~i~S ~:~rl~ary index units mner~onlc { F) AXPI' ~.~ax~mum nfl. mary ~ndex value { F~ ~Ir,~PT.. ~.ir~imum ~r.t.~,arvm ~ndex value ( F~ Tape ?APE ~eel tr REEL ChlumberqQr bTST $1.$DlA2:rg42o4~LOG.01.3,bl$~ eel Deader DEFAIILT Tape header wile header .EST .013 Fra~ne data record~s) encountered File trailer ~IM~T .013 FILE ~P~ '"'"'"'"'"'~ ~ ...... ~, '"'"'"'~;~.~] ..... ~p~"'"','"'"",,,'"'""'"'""~.. ~, ~o ~o~o DEPT 886B. 8547. DMPT g ~ ~702.9664 2605.1~56 trailer ~ ....... ~ ............. a~ler SUmmARY FILES T~PES ~LR ~P~ 1 1 670 1.975 FIb,S T~P~$ R~E~,S #LR ~P~ 1 I I 670 !975 26-S~P-g4 0g:30~4~ Pa~e 3 ~nd of lis'ting chlumberqer Page ***************************** LTSY~! physical, record map o~ $15DIA2:[94294]bOG_O~9.bI$~! Using command bTST/BRIEF/OUTPtIT:(LOG_O29'LST]/SUMMARY JnS ~umber 94326 Commanv Na~ne MARATHON OIL COMPANY ~ell Name BEAVE~ CREEK #9 Field Name BEAVER CREEK County KENAI State AbASKA $~rvice Order ~umber 54927~ Date 26-SEP-94 Run ~umber TWO MICROFILMED ChlUmberger Page 2 rv out u is created by LIST/SU~ RY su~arJ, es written for Logical LIS structures: ~ILE (Rbbrev~ ~) LiS lo~cal ~le info TAPE (~bhrev: T) bls logical ~ape info ~EEL {Abhr~v: ~) Ll$ logical reel info and for t, he entire h!S/a input logical unit: [~if (~Dbrev: L) LI$/~ logical unit info T~le field labels appear on some or all of t~ese ~ummar~es, as indicated by the abDrev, on right. su~marF Field babels: ~E~LS Number of loaical reels on (L TAPES ~3umber of looical tapes on (LR FII, ES ~umber of lo61cal fi].es on CLRT #P~ ~umber of pb.¥$ical records (LRTF) ~LR ~.~umber of lo~lcal records (LRTF] #D~ ~u~ber of data records ( #ENC ~umber o~ encrypted records ( ~F~ ~umber of data frames ( PI ~r~marv index channel name~ si.UNITS Pri{~ar¥ index units mne~)onlc ( ~AYPT ~axlm~ Pri~arY ~ndex value ( ~I~P! ~inimu~ primary lndex value ~rame 6ate recordCs~ File tra~r ~$$mA .029 encouhtered {IR }PP #ENC {DR #F~ PI PI.UNITS ~AXPI {INPI 6 18 180 4 0 5995 5995 D~ lin 65000 7 D~PT F 88?5, 5878 D~PT ~ ~705,1 1791~6144 trailer DEFAnLT TAPE FILE~ #LR #PR ............. I 02o !8 6 eel t~ hFS T~P~S ~I,,~ ~P~ EOD~ FIb,S TAPES REEL6 #LR #P~ 1 1 1 6022 18018 , . End of llstin9 $15DIA2;[O41~94]LOG_O2g'.LI,.,I C~l,~erqer LTS/LI PhySlca! record map of o~oanV'Name NAR~TNON OIL COmPaNY ,~ell, ~)ame BEAVE~ CREE~ ~9 F~eld ~Jame BEAVEP CREE~ Cou~tv ~ENAI State ALASK~ Servlce Order Number 549~7B Date 26-8EP-94 Run ~umber TWO HLI, fED chlu~nheroer Page 2 i LIST Command bls:lng ~EY I bTST SU ,.,~RY ~NMMONICS Su~ rv output is rea:ed by $?/SU~NARY summaries written for Logical LIS structures: ~Ib£ (~bbrev: F) LIS logical file info TAPE {~brev: ?~ LIS lo~cel tape info E,..~L (~br~v: ~ LIS logical reel info an4 for tr~e entire b[S/l input logical unit= UU (~obrev~ b) bI$/l logical unit info ?ne field labels aDpea~ on some or a~l of t~ese summaries, as in~icate~ bV [he abbrev, on right. summary Field Mumber of logical reels on (b ) TAPES ~,~u~ber of logical t~pes on (LR ) ~ILE$ ~,umber of logical files on (LRT) #P~ ~u~ber of pn.yslCal records (bR?F) #L~ ~umber of logical records (LRTF) ~D~ ~um~er of data records C F) ~EMC Wumbe:r of encrypted records ( F) #F~ ~umber of data frames ( ~) PI Primary index channel name PI.UNITS Primary index units mnemonic F) ~AXPI ~axtmum prl~arv index value ~I~PI ginimum primary index value ( chlumheroer .~i~?'$'r $1$DTA.9.: r942~4]bD.~_AP$_HMGS_D{ER.[,IS~. eel header DEFAULT Tape Leader DEFA[]LTi~ ~ile header I~OS .0)8 Frame data record(s) ~i],e tra~ler bD$ .038 encountered FIL£ ' ..... ~ ...... ' .... ~'" ...... '"" ..... ';'"'""""';'~'"' .... #. ~P~ ~C #DR ~F~ I PI_UNITS A PI ''''''~'''''''5~ 6~7 .... ~'' .... 5~''''''~ ~'''''''''''''~'''''pT lIN 63800 .... ''~''''''I00020 ~-~~PT ~ 886 , 85835 OMPT ~ 270 .052 2616:2508 File header LoS .039 Frame data record(s~ encountered ~ile tra~.ler b~$,903 FILE SUi~ARY ..... ;~ .... ;P~ ,FNC ;~ ............. ~F~ PI' ......... P,_UNI~'''''''S ~AXPT .... ''''''~INP, ..... ''' ......... 2138 2''''''''''''''''''''''''''''''''''''''''''''''''''''''''''''''g 0 2). ] ~1~3 DEPT lin 1063800 937080 " DEPT ~ 8865 7809 Wile header Frame data record(s~ mile trailer LDS .040 encountered FILE ~ ' #LR ~PR #~C #DR #F~ PI PI_UNITS AXPI ~INPI -....,~....,,., ..... ,,...........-.--.......-.,,-,,,.,,,..,,.---...-....- ~'~' 4656 OEPT m 7897.5 5~8~.5 .DE~T ~ 2407,.158 179~.986 Tape trailer ~eel t. ra~ler DF~FAULT 26-SEP-94 07:59:~6 pa~e 3 LU SI~A~Y FIL~_S TAPES R~E~: #LR 3 i I 6787693 ~nd of listing $1$DIaT.:[~.4~g4]LDS_APS_HNG$.~ER.SIS;2 26-SEP-g4 07:59:16 Paae 4 ChlUmherQer TS/U physical record map of 815DIA~:[94294]LOG.O~4,LIS;~ ~$in~ co~,~amd BIST/DYNAMIC/OUTPUT=(5OG.O14,LST)/STATIC/SUg~!~Y ~ob Nu~er 94326 Company Na~'~e ~ARAT~ON OIL COmPaNY ,,ell ~a~e BEAVER C~EE~ Field ~ame BEAVER CREEK County State ALASKa Service Order ~'~umber 549~78 Run t~u~er TWO ChlUmberqer Page LIST SU~RY ~NEMONICS sum,narles wrltt n for ~oglcal LiS structures: ~ILE (~Dbrev~ F) LIS lo~%cal f~le ~nfo T~PE (Abbrev: ?) LIS logical tape Info ~E~L (.~bbrev: ~) LIS logical reel ~nfo an~ for the entire LI$/A input logical unit: [~U (~bbrev: b) LI$/A logical unit info T~e field labels appear on some or all of these summaries, as ~ndlcated by the abbrev, on right. Summary Field [,abels: RE[]~S ~umber of loqlcal reels on {5 ) PE .... Number of logical ta $ on (LR ) FILES ~u~Der of lo~lcal.flies on (LBT) ~PR Number of Ph~Sica& records (LRTF) #LR Vumber of logical records (LRTF} ~D~ '~u~ber of data records ~E~C ~umber of encrypted records #F~ ~umber of data frames C F) PI ~rimarv ~ndex c~an~el'na~e ( PI.UNITS ~ri~arv ln~ex units ~ne~onic ( F) ~AXPI Paximum ~rlmary index value C F) ~INPI ~lnimum prlmar¥ lndex value ( F) chlumberQ~r LTST $15DIA~:[942qalbOG_O~4.Ll[S:l 25-SEP-g4 09:33:46 PaGe 3 eel header ** RFEL t~E~DMR ** SERVICE ~4~] : ~4~S$ DaTE : 9at0~/27 0~I g I :'¢ : DLIS REEl, ~'A~.~E : O~F~UT,T CONTI~)U~TIO~ 8:1 P~EVIOUS ~EEL :. ~- Tape heaoer DF~F~OLT ** TaPE SERVICE ~NM : F~EST DaTM : 94/08127 O~ICIM : TAP~ ~AME : DEFAULT CONTI~UaTION #: P~EVimU$ TAPE : CO~UE~T : PROCESSED BY SCHbUM~E~GMR D5I$ TO bis CONVERTER UTILITY Wile t~eader ,' ESI 0~.4 ** FILE HEADEm WILE NAMM ~ NEST ,0~4 SERVICE NAME ~ DEPTH- VERSION # DATE ~AX REC. wI~ TYPF PRFVTOU8 FXLE table type TOOL O~jNAu ST,~T H~IG V~LU WETG PRES TE~P MEST AbbO O. ~.6 46~, O, ~?. A~$ ~'LL'O 8~.0 88 0~2 ~30... S~AA ~bSO 897 8~ 0,~87 50. O. Fnd of set L,?$T $t$OTA2:[g4~q4!L~lt(;.O14,L?S~l 25-SEP-94 0q:33~45 Paqe 4 Ta~]e type C~EA ListJ~o o~ set 4 type OBJ~A~:' CHAN [~!JRA MEAS REFE BTI, PHAS TUNI 2A 3~ r,~ESTICI_PxtC~b ~ ' ' Il ~.959276 8. ,qEST/C2_Z~';/C~LI_~ 11 ~12.50428 ~4 g S T/C 2_ P ~!/C ,~ !'., I_~ 77797~508 BEFD IN 777973404 0£F0 IN 777~73508 BMFO IN llA 4 6. O, 7779736~9 BEFO GPYI-MAGN/[)U~. ONTH/CALI.~ 4 ~57. O. 777973619 I?AGPIT.NAG~/OUM.~Ui~B/Cg. 5I.~f 13A 60 -50000., , "0.,61375 0 MAST ~ IT/~ AS.IN~TMRUCaL~EC~/V.CAL~EA$ 16A 60 -50~00. ~,9914286 0 MAST &IT/~AS.INQADCAb~OOSTRECT/V CALMEAS 7~ 4 1. O. 777973598 BEFO GPIT_ACCE/DOM.MONTM/CALi_M 6A ,E4 ~ 86 ~ O. 777973598 BEFO 67.99997 3~.00001 7779735q8 BEFO DEGF GPTT_ACCE/DU~_TE~P/CaI.,I_~ cblumber~er hiST SlSDIA?:rg42q4]LOG_014.LIS:I 17A 60 50000 6 808571 ~ ~tt :.~ AS.I ~ DADC~LU A~ E~'r/V. C,A L ~ fA S 60 3964 872 3~50. a I T/"AS.SPAPLUS/CA f,~E AS A I T t,,~ AS.SP A Z F~R O/CAL~%F, AS -50. 20A 60 4.500563 4,5 a IT/.~,' A$_TE~PDLUS/C ~ L~E~S 21A 6~ -0.04844565 -0.05 -50000. 3,255 0 AITt~AS_TEt, PPAW/CAL~,~AS 23A 60 50000. AI~/~{AS_TE~'PCA~ICAL~AS 73.39998 0 24A 6n -50000, 2.4 AIT/F~AS.VOLTPL:US/CAL~EA$ 6o -5oo0o. AIT/,~AS.VOLTZERO/C.AL'~'EA$ -0, O5 0 26A 60 -50000. 1. 0 AIT/gAS_VOLTCAL/V.CALNEAS ~ITI~AS_INDT~R{C L~A~NLEV/CA~,~A~ 28A 60 ~50000'. 0 0 A1T/~S.INDADC LBAGAINLEW/CA~EAS · 29A '60 -Snc'O0 0 0 ~[,~v cAf~AS 30~ o -soe:oo~ _ ~ o 3lA 60 -50000. 0 0 AIT/~AS-INDADCt, LUUGAINLEV/C~I'$ 3~A 60 0~4750562 AIT/BEF_INDTHRUCAL~ECT/V.CAL~EAS AlT ' T ';'~' .. /~gF .... aDADCREt.,GR~ .... 34A 60 3 51022 3 5 A'IT/BEF. I{~DADCA~ATTE~RECT/V,~ALAEAS 0 MAST 770~35681 ~AST ~V 770035681 HAST NV 770035681 ~AST V 770035681 MAST V MAST V ~AST DEGF 0 ~AST V ;4AST V ~ AST V ~AST 777987171 BEFO 777987171 BEFO 777987171 BEFO 77'1987171 BEFO 25-SEP-94 09t33~46 Page 5 Chlum~erger 36A 6o 0,04217395 6,80857! 37a 5~ 3966.146 3950, A ITt BEF_$PAPLLIS/CAL~EAS 777987171 777987171 BEFO MY 38A 6D -47,80452 -50, aIT/BEF.$PAZERO/CALMEAS 39A 60 4.496845 4,5 AIT/BEF.TE~PPLU$/C~L 4OA 6~ -0.0470990~ -0,05 AIT/BEW.TE~PZE~O/C~L~E~$ 41A 60 ~.R8~072 3,255 4PA 60 I~O 73. 3999~ AIT/BEF_TE~PC~L~ / _~ALMEAS 4~A 60 2'38~684 2.4 AIT/MEF_VOLTPbU$/CAL~E~$ 44A 60 ~-0~04117977 -0.05 AIT/BEF_VOGTZE~O/C~L~EA$ 45A , ~" 60 16175978 ~IT/ ..... ~F.VOLTCAL/V_CALMEAS 46A ~' 60 0 ~IT/ .... EF-INDTWRU~SLGA~NLEv/cA~MEA$ 777987171 OEFO ~V 77798717i BEFO V 777987171 BEFO V 777987171 BEFO V 777987389 B£FO DEGF 777987171 OEFO V 777987171 BEFO V 777987171 BEFO V 777987389 47A 6t~ 0 . 'V 0 777987389 BEFO A IT/SEF_I~:4DADCa~AGA l NLE 48A 60 0. ' I ~ 0 ' ~'77987~89 BEFO 69 127. ~ i 777987'389 49 A ~ I T/'B E ~. ~ ~ID ADC ~.SU A G'A I N[,EV / 50 O, , 0 777987389 51A 60 -5000~, -0 61~75 0 AFTE AIT/AFT_I~'~ .I~RUCALPECT/%.CALM~AS 59A 60 -50000. 19,5 0 AFT~ .a IT/~FT_I ~D.ADC~.ESGP ~CT/V_CALMEA6 53A 60 -50000, 3 5 0 AFT'E A. IT/~'FT_I NDADCALa TT~8 ECT/V.~ALMEAS 54A 60 -50~00 0 9~1.4286 0 AFTE 25-SEP-94 09:33:46 Paqe 6 L~ST 55A i'.~ .... aL ~,~ bJ a~ E~T / V.CALI~E.~ 57A O~ ~ 1T /a. F,_S P A ZER~/C. AL''~ ~AS .t~ IT/,~F , _TEMPPb~S/CgL~4EAS 50A fo -50000. -0.o5 ~ IT/IFT..TE~,IPZE!~O/C a [ ME~S 60A 60 -50000. 3,255 a I Tt,IF?_TEVp~AW ICAL~,{~ iS 6t ,% 60 -5000o '73. 3999R. AIT/AFT_TEuPCAI,/CALM 6~A 65A 69A 70A 71A 73A AFTE AFTE ~V AFTEv AFTM V AFTE V AFTE DEGF AFTM V AFTE V AFTM V AFTE AFTF~ AFTM BAST MM/M ~AST ~M/M 25'SEP-94 09:33:46 Page 7 75A 6~ -5000~ 0,015 0 ~ I T / ;~ AS. r ~DE L~CC ~ b_b ~ / v_C AL 76A 60 186,~8 0,015 A I T/~%EF_ t ~ DEbECC ~ L/V.C.~ 5~{E AS 77A ~0 -50000, 0,015 0 6~ 0 00~4~477~ 015 7 ~ A~ l T/~.EF_T N D~L~]C~ a. LNO~R~CT/V~ 7gA 60 .-50000, ..... 0 015 0 AIT/AFT.T~DELECCALflO~R~uT/V.~AL~EAS 60 -50000, 0 0 80AAIT/~qAS_TNDR ~WGAI'NORNG/C~LME~$ 81A 6o AiT/BEF_IND AiT/~FT_I~D~ 83A 60 AIT/MAS_TEW 60 ~I.T/~AS.TE~ RA~GAINORNG/CALME~$ -50000, PCAL-GL/CAGME~S -50000. PCAL.HL/CAL~E~$ 777987389 BEFO ~/~ 777987299 BEFO AFTE 777987389 BEFO 0 AFTE 7].39998 0 MAST DEGF 73,39998 0 ~AST DEGF ~SA 60 -$O0~ 73.39998 O BEFO DEGF 86A bO -50000 ~ 73.39998 0 'BEFO DEaF ~IT/BEF_TE~PCAL_NL/C~L EAS 87A 60 -50000. 73.39998 0 AFT~ DEGF AIT/A~FT_TE~PCA[,-LL/CALME~S 88A 60 -5000Q 73.39998 0 AFTE DEGF AIT/.AFT.?EWPCAb.!4L/C~hMEA$ ' 8gA 10 0.000'14496~8 1, 77797~748 MAST V A[T/~AS.INQR~/S.CAL~EAS 9lA 10 0,00014~9638 i, ??797~?~8 BgFO ~IT./BEF.INOR&W/S.C~ 9~,~ I0 0.0~0i449638 1, 777973748 AFTE V alT/~F~.TNORAW/S_CAL~E.~S 25-SEP-g4 09:33:46 Page 8 [iTST 9 4 A 96A 97A A AITtBEF.T AIT/AFT_T AIT/~AS_I 98A ~IT/~E~.I I 61. %~E/E.CAuNE~S ! 61. ~,- ~2685~ 1,1~9643 ~J~THR G/V.C~L~EA$ 60 ~.~0~083 -2,357143 NDTHRUCAL_PHA/V.CA~ME~$ 60 1,~23349 1 129643 NDT~RUCAL.MAG/V_CAb~EAS 99A 60 1 ~6624 2 357143 ~IT/BEF_INDTHRU~AL_PHA/~_CA~M~AS 1~I~9643AS 0 101A 102~ 1031 lo4A 1061IT/AF?.I60 -50000. 25 0 NDADCREbG-~AG/V.CAbfi~AS 10'lA 60 -50000. _ O~ 0 AIW/I~T_INDADC~ELG-~A/V_cA~ EAS IOaA 60 1.010813 1, AIT/~AS_TSC_~A~/V.CALM~AS 109A 60 0 02~52579 0 IIT/~AS_TLC_~HI~¥_CAL~EAS ' Ii. OA.T 60. 19,]41~5 1. AITt~AS-~E~.C~D.Xt"V_CAbMEAS ' 60 -50000, _ -2 357 IT/AFT.INDTHRUCAL.P'HA/V.CALM~AS 143 0 60 25~05714 25. IT/MAS_INDADCRELG.MAG/V.C~L~EI$ 60 0.2330633 O. 1 ~!~ A S_I N DADC~ EtG-PH A IV.CA,~E AS 60 25,05412 25~ IT/BEF_I'N,,ADCREbG_MAG/V.CASME~S , , ~,~. ,..:m..,.. 60 0.~1.41133 , 0 777973684 SAST 777973684 BEFO 777973684 AFTE 770035681 MAST 770035681 MAST DEG 777987197 BEFO 777987197 BEFO DEG AFTE AFTE DEG 770035681 MAST 770035681 ~.AST DEG 777987197 BEFO 777987197 BEFO PEG AFT~ 770035681 MAST 770035681 MAST DEG 770035681 ~AST MM/N 77003568'1 ~AST 25-SEP-94 09:33:46 Paqe 9 ChlUmberqer 1t2~t llq~, liSA 1 t 6~ 1!,7t 11.9~ 1~1 1~3~ 1 ~ 4 A l~6A 1~7~ 6n -5oooo~ IT/TEST.SDAZERfl/CAL/EAS 60 50000, 4 5 iT/TSST_'IE~,PP US/CALMEAS 60 -50()00, IT/TEST.TE~PZERO/CA~ME~S 60 -50000, 60 -5000'0 IT/:TEST_T~WPCAL/C~E~S oooo !T/TES~.VOL.P US/CA 60 IT/TEST.VOLTZERO/CAS~A8 IT/TEST. IT/TEST_ T~ I', /TEST_ fT/TEST_ 6 T IT/~S -I ~Fg42q4] LOG_O 14. bT$ ! 1 0 -50000, -0.61375 0 n -50000 1~.5 0 . - 50 0 (> 0 3,5 0 DADC~LATT~NPECT/V.CAbME~S ~ -500o0~ 0,9214286 0 ~13 ~ OC A ~BCO~ T~ECT/V.CA LME.~ $ 0 -50000. 6,80857~ 0 ~]I) ADC~bUAR~CT/V.CAbMEAM 0 5noOo~ 3950, 0 PAPG~S/C ~ [.,~EAS -50. 0 -O.05 0 3.255 0 73.39998 0 -0,05 0 60 ~ -50000}.M~~- 1,. 0 -soooo._ , o INDTH~UC. ALG~I..bEi ., 60 -50000 0 IUDADCALBnG~IMLMV/~L~EA$ 60 -50000 0 0 I'SID~DCAbBI.~G~INbE'V/C~L~EAS ~o -50000 , I o ~D~OCA[,UAG~I~bEV/C~L~E~S o -500o9 o o ND~DCALU{..!G~INLEV/C~L~E~S 0 V 0 V MV MV DEGF 25-SEP-94 09:33:46 10 ¢t~lumberq~r b~S'r A 1~2.~ A 133~ 6O -5O000. ~0. I"rt T S .... . E~.~ I .i~I>~[~CCALIV.CALI4EAS 0 0 60 -5oo00 0,015 IT/mES I~DELECCAt, N~RECT/V.CIL~EAS 134A ~<, 500 O, ~ , 0 -5000 0 135A AIT/TEST.D 136~ 1 ~IT/TE~T_D nlT/~EST_T 138~ 1 AIT/TEST_C 139.a. AiT/T~$T_T 0 -5000o 0 TAGD~CRE~L~I~E~RR/~AL~EAS 0 i50()00 O, 0 OOLSTATUS/~AI,MFAS n -50000 O. 0 ~DECHOTEL/~ALME~S 0 -50000. O, OOLMODE/CALMEAS 140~ 7 ~50000. I 0 ~IT/TEST.I~D~AW/TV_C~L~EAS ' 14lA 60 -50000. . O. AIT/TEST_INDR.AW/W.CA~M~AS 142,A 10 -50000. 1. AlT/TESt_t, DRAW/~V.CAb~EA$ 0 V 146A 7 50000m -0.61375 0 AIT/TEST.INDTH~OCALR~:CT/TV_CAL~EAS AIT/TEST.IND~[)C~LUARECT/TV.C~L~E~$ 14B~i . bO -50000. I 0 T/TEST-I~tDTH~UCALRECT/VO.C~h~EAS 149A 60 -50000. 1, 0 ~I~/TEST_I.~,~DELECCAL,~..NRECT~5~V.CAL~EA$ 25-SEP-94 09:33:46 Paqe I1 chlumherg~r LIST 150A 15lA 15~a A lS3~ lS4A I~5~ A 158A 16lA 162A I 6 ? IT/TgST.I~t 0 ~¥.CAL~EAS ~v ' o .CAGMEA$ 0 0 o O.CAL~4EAS 0 O_CALMEAS 0 o O.CAbM~AS 60 iT/TEST.I~DELECCA![ ECT5/V. Al:, 6o -500~0 , ~ 0 ~o -sooo~. _ l~' o IT/TEST_I~t)~L~CCAL~OMRECT~/V.CALa~AS 163~ 60 -50000, I 0 AI'T/TEST.INDEbECCALMOMRMCT1/O_CALMEAS 164A 60 - O00O- NDEL~CAL ' 1, 0 ........ NO~'R'ECTO/V.CAbN IT/TE$~.i EAS 165!. 30 33.45576 O, 166A 30 ~50000- O, 0 167A 60 190o89 165° 168~ 60 50000. i65. 0 8GTLIP~_~FT/CA[' ~ ,. 7779737~I BEFO GAPI AFTE GAPI 777973903 BEFO GAPI 25-SEP-94 09:33:46 Paqe 12 hIST $1~DTA?:[94294!~nG.014,b!$;]. 25-SEP-94 09:33:46 Pa~e ~3 169A 45 ~91,3252 u, 777973903 BEFO GAPI SGTL/ZPC_~F/C~I,I_5~EAS i70~a ~5 -50~;00 O. 0 AFTE GAPI SGTb/ZoC. T 17IA 45 -50000. O, 0 BEFO C~API SGTL/~PC.BEF/CA~ii~:~EAS ;% 45 50000 0, 0 AFTE GAPI 172 SGTL,' r,~pC. &rT / C~b X-~.~E ~S -50000 0 0 BEFO GAPI SGTL/PpC.BEF/CaLI.~E~$ ' 174A 4~ -50000. O. SGT!~/PPC.A FT/C A 6.T_~,~EAS 0. AFTE GAPI ~mmmm~#m~-m~m#~--m-~mmmmm-mm~mmmmmmmm~m~m~mm~m-~m~mmmmmmmm~m~m~m~mm~mmm~mmm~m~m~em~mmm~!of s 'raole tvpe DUTP Listlno of set 5 type OBJNA~ TUN! PUNI DESC BS IN IN CS FtWR F/MR CVEL F/~M F/M~ FMO~ OER O~R FTNC DEC D~G OEG DEG DPAZ DE~ DEG OU?P DDA AREA FT2 FT2 AFCD FT~ FT2 FCD IN I'~ I~V F3 ICV w3 STIA ~ F S~IT ~ F 1~ mEG DMG 2~ OEG DEG ADCZ v ACPS v ACN$ V V PCPS V V chlumberq'er hIST PC~S v SDEV OgC bEG 4~ G~DZ V G~ v V G~V V V wV V v ~P ~V ~V SPAR RSP ~V RSP~ ~V ~qV ATRA v A~Rw ASFI RGR GAPI GAPI TIME MS ~Sw2 G~T ~EgF DEGF G~T DEGF DEG~ CTE~ DE~F DEGF RUTF DEGF DEGF A ~'I'E DEaF D~GF ATCA D E~F" DEGF GS~ 25-SEP-94 09:33:46 Pa~e 14 chlumber~er 5~27 ~A15 BA2! Be14 Bet5 BC21 BC2~ BC23 BC24 SC26 MC27 B~2~ BB23 BD28 B~25 ~B26 B~27 BB14 BM16 B~4 BD26 BD27 DB3A DB4A $150IAT:[94204]bOG.V14,LI8;1 25-SED-94 09:33146 Pa~e 15 FrAY rtS2 F/S2 Fr'A? FtS2 C~ ~ I~~' C~ ~ DCHV V V ~xtZ ~XSZ RCi IN Cp F% nE~ ORR ~'Y n~R OER FtS2 F/S2 F/S2 F/S2 ATOS AnDE AIBP PSI PSI 25-$EP-94 09:33:46 Page 16 ChlUmberger AIPO AIFC AISC AQAF ATCO A?C~ ACRS AVPL AVZE AVP~ AVZ~ A?~L A~ZE A~PA ATZA ASZ~ ASPA ASZA ADT~ A~CG ADTD ADT~ A AUA~ AUUG AQUA ADR~ ADA~ ADBO AIAT AIBU AIU~ AIR~ Rnd o v V v v V f set 25-SEP-94 09:33~46 ~a~e ~1? chlum~erq~r Lt$? ~l~DT.~:[942o~t]l.,oG.O1.4.L~S;1 2~-$EP-94 0~.'33:46 Page 18 T~O1 e tVOO lstJn~ of set t'3BO~'Ar~ TYD}~ ~"~AME ORI~ CN~ rr .......... C.~i'~E[, .............. DEVI~ ~ ~ ........ 0 3A CHA~J~EL PlaZ_~EST 20 0 9a C~ANNEL TI~] ~O 7 12A tHAN ~.~gt, TI~C 20 10 1IA C~AN~!EL TI~E 20 mmm mimiI ,MI I mm m mm Il End of s Table type CONS Listing of set 8 type COWS OBJNA~ STAT TUNI PUNI DESC VALU A ~0 F ~ al Dept 8881. ~gDU ~bSO ~aqnetlc ~arK Depth Units LCP ~BLO BOM$ Client Product [)IFF ALSO F F Maximum Permitted Depth TPE~..OO.O.~.LT.,O L, BF LBF Cable Tension Re~erence Difference .%bLO DEG, gEgf Bottom Hole Temperature (used In calculations) 140. JFTA .BBLO ,.)ob Events Auto Save AhLO ~%bbO LB-1 LB-1 Cable Elongation Coefficient GC$~ ~LLO Generalized Caliper Selection ~ock ~atrix Tvoe Geoeral~zed ~ud Resistivity Selection 25-SEP-q4 09:33:46 Paoe BgS AbLO OPeN 8ore Hole Status $!4T ALLO DEGF DEGF Surface Hole Temperature 67,gq997 ~TF~ Generalized Temperature Selection GDEV o, I.~IT 4, STEP 2, ]5, ALLO DEG DEG Average Angular Deviation of Borehole from ~ormal ALLO F F Correlation Interval Correlation Step ~bLO DEG DEG Correlation Search ~nqle DPAD ALLO oisaoled Pad 1/4 SRUT ALLO ~SD8 STD! O, STDA O, DIP soanninq DIP Se% of ~uttons CSB DIP Number of bevels Electrical Radius Side-by-Side Distance Factor ~DLO D~G DEG Structural DIp an~le Structural DIP Azlmuth CD ALLO F F 5964, Casin~ Shoe Depth 19 ALL;] IN ~N Future Casing (Outer) Diameter 3.5 IHVC ~DLO Integrated HOle Volume Control STAR HVCS AUTO integrated qole Volume Caliper Selection 2,5 PTYP ALLO STI StUC~ Threshold Pad TYPe - High Resolutlon or Medium M~tended Coveraoe F SCit~ MEST Looqlng ~ode snF~ aLLO IN I.~ Stand-Ofi XCA! ALLO Gain 3 XOFF ~LI,O Offset 0 RBS abLO AUTO ReSlStivit~ BUtton Selection X~OD ALL(] fmex ~ode ~ANU GPlT LOgglnq ~ode G~IT Telemetry GLM ALLO hIP~ GT~ ~LLO DIP~ AbLO DEGF DEaF Accelerometer Re~erence ?emperature A~T67,99997 R~ ASLO 9EGF DEGF aaQneto Reference Temperature g.i~i~,gpg0 . ACPP ALUO accelerometer PROM Presence gAPP AbLO PRES Maqnetometer PROM Presence ACCN ALL!3 ~76 Accelerometer Serial Number ~AGM ADLO ~57 ~ao~etometer Serial Number 2O Chlumberq~r Acceleror~eter Year of CallDration Time o~ acc calibration ~a~netometer Yesr of Calibration ~ccelerometer Month of Calibration ~a~netometer ~ontb of Calibration ~ C C T A L L 0 3 Accelero~eter TVpe ~GT ALI~3 Maonetometer Type (ganufacturer (~anufacturer MTIM AbLU 'rime of mag Calibration 7779736t9 ACCC -0.000999999g g~gC ALLO -0.00079o9099 ICMO ~LLO aUTO -151.01, LOND ~LLO PEG DE~ ALLO DEG MD5~163.7117 ~FI~ ALLO DER OER 0.3593656 MINC ~LLO D~G -40.]0584 Accelerometer coefficients Accelerometer Ftlterin~ Mode Inclinometry Computation MOde Longitude CE=% W~-'} ~agnetlc Field Declination ~aonetlc Field IntensitV Magnetic ~teld 'Tncllnation ABLM ~LL{3 A. IT Basic Logs Mode 1.TW ~BLV AbLO ATT Basic bogs version Number 630 Code) Code) 25-$EP-04 09:33:46 Pa~e 21 chlumber~'j~r LIST $15DT~%~:[q4204]LnG.o14.PTS:l 25-SEP-94 09:33:46 Pa~e A~T 8hole Correction Mode AnhV ALLO 600 AIT ~hOl. e Correction Version ~umDer Tool CentertnQ Flag (Xn Borehole) ~'0 Enable Bhole Correction (Playback Recompute Only) AiT Enable Basic Logs (PlaybaCK Reeompute Only) AlT Enable Radial Prof~linq (Playback RecomDute 0n1¥) AlT Enable Radial Para[netrizat~on (Playback ReeomPute Only) 61 ATT Naster Cartridge Serial Number AqCT ~LLO DEGF DEGF AIT ~aster Cai Sonde Temperature 32,o0001 AgDT ~L[.O AIT ~aster Date and Time wr! gay ~7 10:48:0~, ~994 AURn ~hl.,O F F 0. AIT ~,.,~d Reslsltivv Cal.~bration Depth AIT ~Wuci Resistivity Factor' A~SE ALLO hl~/~ ~i~/~ AIT Master Sonde Error Correct'on !.6in235 AgTt~{ ALLO 61 AlT Master Transmitter Serial Number A~TL aLLO 0.g94800~ AIT ~aster Test 5oop Ga~.n Correction APFV ,~LLO 610 ATT Radial Profiling Version Number ATT Radial Process~n{~ Mode A~.PV ALLO 6o 0 Radial Parametrizat~on version Uumber ~$CT .~L, LO AIT sonde Characterization Time Tt~e ~4~r 9 16:05:20 1§93 22 Chlumher~mr LTST SlSDTA2:[942941LnG_O14.LIS;! A.qt~O ALLO AIT sonde 5erl, a]. Number 25-SEP-94 09:33:46 Pa~e AATL ALI, O 73169312~ ASPC O. 0.5 ASTC -2.2R992 ATSE aLSO TNTK AWC~ A~T~ ~LLO 6! A?T sonde Characterlzatton Time (as a lonmword) sonde Char Pressure Coefficients Tool Star,doff AlT sonde Char TemPerature Coefficients AIT Temperature Selection(Sonde Error Correction) ATT ~ells~te Cartridge Serial Number AIT ~el!slte TraDsmltter Serial Number FP},tI DPHI Form ~actor Porosity Source Form ~actor Numerator For~ Factor Exponent R~CO - ~t Invasion Correction TSR! ALLO 60 Telemetry Status Report Interval (for IO ~on) Telemetry Er,rot ~sg RePort. Interval (for SCP) ~UTD DTB Telemetry Frame Rate TBR 1.00~ DTB Telemetry Baud Rate TLC Kit 23 LTST SP~V SvD~ O. ~ JAP:[942g41~.G_014, ~bl,O F r ~TEM COmPutation AUT,O !,~V ~%V' SP Next Value RL, LO h,V/F ~V/F SP Drift Interval 25-SEP-q4 09:33146 Paae 24 ~nd of set Taol, e type Listl~o of se mm~m~m~mm~m OBJNA~ mYPE 14A CON~ 1LA CO~S 22A 40A CONS 4~A CO~S 46A CONS 48A CONS 4~A CONS 50A CONS 5~a CO~S 53A CO~*S 54A CON~ 5~A CONS 7~A CONS 74A CONS 75A CONS 76A CONS A 7gA 89A 91A 94A CONS 95A co~s 96A 97A 98A 9gA iO1A CONS I02~ CONS 103~ COMB I04~ CO~S · I~5~ CONS 106A CONS 107A I08A C(3NS 109A CONS t 9 type XNAM NAME ORIG CNI.IM PBVSADP ALTDPCHAN Sm_XR~TE SO_UT SO_PEOU SO.HOSTILE SO_DISCF $O.~2$ SO.DIBC~ SO'CANADI~'N SO.DO SO.TRIP ~ $O~RQTAPE SO, ~ATE $0, NTY SO., CONS SO CONS CONS CONS ,WT 20 0 20 0 2O 0 2O 0 20 0 20 0 20 0 20 0 2O 0 20 0 2O 0 2O o 20 0 20 o 20 0 20 o 20 0 20 0 20 0 2O o 2O 0 ~0 O' SO.SCURRENCY $O.PCURRENCY Sm_ST S~!.'vAPERW S~_FIIJiqR~ SO, SO, SO, SO, SO, SO, SO, SO' IGHT ,UID 20 0 20 o 20 0 20 0 20 0 2o 0 0 0 20 o 2O 0 20 0 ~o 0 2t)~ 0 20 0 2O 0 20 0 ChlUmberq.r llOA CON,5 SO.UDE?~SITY ~0 ~ l12A CONS SD.~D~PTg ~0 O 1~.3~ CO~S F[,S~STR~ 20 0 End of set 25-SEP-94 0g:33:46 pac~e 25 Llstino of set 10 type CONS OBJNA~ STAT TiJNI PLtNI D~SC VALU 14A AL,~,O Use alternate depth channel for plaYbac~ ~0 1SA Al~tO Name of alternate deot~ channel TVDE 22A ALLO Exchange Rate Primary to Secondary 40A ALLO boaging Unit, TvDe MAXI 45A ~L[,,[',~ Pressure Equipment Used NO 46A ADLO M 0 Hostile Conditions 48A abhO DlSCOU~t Format F,U,bh 4gA ~LLO H2S Present NO 50A RbLO Dis'count Allowed YES 5~A ~'LLO Canadian Service order 53A ~L, LO Day lig[~t Operation YES 54 A A L L 0 T r i p 57A ALLO Tapes Requested NO '7~A ALL{] Service Company Addr ZiP 77252-~175 74A .5{.~L["3 Service Company Addr grate TEXAS 75A AbLO HADRI8 77A ;%!,LO P.O. Sf~X 2J75 7~A Service Company Addr County Service Company Addr city Service Company Addr Line 2 aDLO Service Company Addr Line ~ DIVISIO~i OF SCHLtNBERGER TECHNOLOGY CODPOR&TION 79A ~I~LO Service Company Name SCHb~)~'~gERGER WELL SERVICES 89A LAND Operation T~Pe ALI.,O Drilled For OIL EXDL 94A 95A ALLO U S $ ~ 6 A ~ L ~ u 97A ,ALLO NA~ Secondary Currency Primary.Currency Service Type OPeratin~ Group Floppy Received at Well 99A Tape Received at Well IOOA ALLU Film ~eceived at Well 101 .A Tool Protection Requested .2A ALLU Price Zone LAND 25-SgP-g4 09:33:46 Paoe 26 ChlUmberqer LIST gl~DTA2:[942o41bnG. Ol~,DTS;1 1 0~ AbLO LBS Order we~qht UnitS GA L Service Order Flu.~d 1)nits lO5A ~LLO GAL Service Order ~olume Units 25-SEP-g4 00:33:46 Page 27 106~ ~LLO NR Service Order Time Units !O7~ ALLO r~IbE ,Service Order Mileage units PS! Service Order Pressure Units F LB/G service Order benqth Units Service Order l)ensitv Units Service Order Temoerature Units t 1 2 ~ SO Depth Units I ~ 3A MO Flush dept~]-delaYed streams to output at end 115A ai~LO OXO0 Depth bogging Mode A~? DeSir~'d T'O'°I .ode ~nd of set Listlno of set 11 type O~j~A~ L~E TYPK ATTR E~ V~bU 2~ ACCC CoNS vALU 2 ~004 3~ ~CCC C~NS VAbU 3 005 6~ aCrC CONS VALu 6 '? E-05 7. a .~CCC CONS VALU 7 8A aCCC CONS VALU 8 I, M-05 9~ .~CCC CONS VALU g 4,)E-08 cblumberqer bTST $ISL~TA?: [942o4]bnG.Ot4,b!~:l 47A 48A 57A 58A 59A 6OA 62A 6 ~ .~ 66A ~CCC Co!,~S VALU 13 ,~CCC CONS VALU 14 ACCC CONS VALU 15 4CCC CONS VALU ~6 ACCC CONS VALU ~7 ~%CCC CONS VALO X8 ACCC CONS VALU 19 ACCC CONS VALU 20 -0.0006 -6;O0o7 ~.0004 0,0005 -2,0~'06 3.0~06 -7.4E-05 2,0~'05 &CCC CONS VAbU 21 O, ACCC CO*S N~. VALU 23 20E-07 ACCC CONS VALU 24 '4.0E-08 ~CCC CONS VALU 25 -0,00~8 ACCC CONS VAL{J 26 -0,099999E-05 ACCC CO~S VAL~ 27 0.0004 ~CCC CO~'oS VAbU 28 0,001~ ACCC CONS VA[,,[] 29 'C '999999E 7 ~C,C CO~$ VALU 30 ~CCC CONS VAbU 31 .999999E 06 ACCC CO~$ VAt, U ~2 -0,000102 ACCC CONS VALU 33 ACCC CONS VALU 34 -9,999999M-09 ACCC CONS rAGU ~5 ACCC CONS VALU 36 ~G~C CON8 vASU' 1 ~G~C CO~S VAL{~ 2 ~G~C CONS VALU 3 ~G~C CONS VALU 4 ,G~C CONS VAbU 5 uG~C CONS VALU 6 ~ CONS VAbU 7 2.8E 07 -0.0007999999 0.0036 0~0016 0.0012 -o 000104 -7 OE'06 ~G~C CONS VAbU 8 l, 35 M~,~ cON .... ~G~C CONS. VALU 1! 5 B ~G~C CONS VALU .~C CON'S VALU 13 0 999999 ~G~C CONS= VALU 14 -0 ~C co~s VA,bU · ~G~C CONS VALU 16 -0 ~G~C CONS VAb'U ~GuC CONS VALU 18 ~G~C CO~S VA5[I t9 .~$~C CONS VALU 2O ~G~C Cn~S VALt} 2~, 5.8E 07 ~G~C CO~S VASU 23 -6.19999~E-07 ~G~C CONS v,ALU 24 9.999999g-09 ~G~C COSS VALO 25 '0.0~04 ~G~C CO~S VAI.,~]29 4,0F206 ~G~C C~NS VALU 30 2,1E ~5 25-SEP-O4 09:33:46 PaOe 28 }~IG~C CO.~S VALb 31 -1~[ ~r, .,-4E'05. ~G~'~C C..,~LS VAI.,L~ j2 6,~99~qm 05 "G~.~C COi,~$ VAL~ 35 9 ~'~SE CO~$ V~bL; 1 ~SE CONS VA!,U 2 ~SE CO~S VALU 3 ~;~SE CO~S VALU 4 ~MSE CO~$ VALU 5 ~SE Co~S VALU 6 AMSE CO~S VaLU 7 ~SE CO~S V~LU 8 ~SE COi,~S VAL~ 9 a~SE C~NS V~bO 10 ~:~SE CO~S VALU I~ .aasE CONS VALU 13 ~,~SE Co~S vALU 14 AMSE CO~S VALU 15 AMSE CONS VALO 16 AMSE CONS VALU 17 5MSE CONS VAbU 18 ~SE C~NS VALU I~ 11.04073 a~SE CONS Va~,U ~0 -17.357~7 a~Sg CO~$ VALU 2~ 7,~34~45 ' ~ ol 164 A~iSE CO,~$ v~t,U 23 A.~SE CO~$ VALU 24 . 0665 A.MSE CONS VALtl 25 1~I97382 I~SE CONS Va~U 27 565 A~SE CO~4S V.ALU ~8 { 8 763 8~-07 i2~-07 999~99E-00 ,26E 06 I,b10235 4.990398 83513 50.{7267 -3 125487 45 82525 ~8 33144 -5 969384 9 ~98809 . 015 25-SED-g4 09:33:46 PaOe 29 IlIA 1121 1!3~ 1141 116~ 117~ I.!8~ llgA i20A 12I.~ 123~ 4 ,M?L CONS V~I.,U 12 O. ,NTb C0~$ V.~LU ~3 ~i ,72 ~MTL ~ONS VALU 14 !4885~ A~?L O~S VA'LU I~ :l,, 339 A~ITL CONS VALU 2~ ~,0~516~7 A~T~ CONS VALU 23 1,00969~ ~4TL CONS V~LtJ 24 0.1305313 ~,',~iTb COi~S VAI, U 25 1.009732 A~TL CO~S V~h!~{.~ 2~% -0.0933466 ~P~"'L CO~]$ VALU 27 1,0~.2766 A~TL CONS VALU 28 -0.08279419 ASPS CONS VALU I O. ~SPC CO&S VALU 2 O, ASPC CONS VALU 3 O. AS°C CONS VALU 4 O, A$PC CONS VALU 5 O. aSPS CONS VALU 6 O. ~SPC cnNs VALU 7 O. ~SPC CONS VALU 8 O. ASPS CONS VALU 9 O, nSPC CONS VALU ~0 O, aSPC CONS VAL!J 11 O. aSPC CONS VAI,U 1~ O, ~SPC CONS VALU 13 O, RSPC CO~S VA[,U 14 O. A6~C CONS V~LU 15 O. ~$~C CONS VALU I6 O. ASPC CO~S VAbU 17 O. ~SPC CONS VAbU 18 O. aS~C CONS VASU lO O, a$oC CONS V~LU 20 O, ~S~C CONS VAbU 2! O, aSPS CONS VAb~ 22 O, ~SPC CONS VALU 23 O, 5S~C CONS VASU 2~ O, aS~C CONS VAbU 25 O, AS.C, C. NS VAbU 26 , ~SPC CONS VALU 27 O, ~6PC CONS VALU 28 ASPC CO!:~S VALU ~g O, ~S~C co~S 16IA 163A 165A 1661 167~ 168~ 69A i7 ~ t73A t74~ 175A 176~ I77A 178A 179A I~OA aSPS CONS vAhU 34 O, ~$~C cons VALU 3~ O' ~$PC CO~S V.A[,U ~ .ASPS CO~S vALU ]. ASPC CONS VALU 38 O, ASPC CONS VALU 39O, ASPC CONS VALU ~0 ASPS CONS VALU 4~ O, RSPC CONS VALU 4~ O. AS'PC CONS VALU' 43 O. 5SmC CONS VALU 44 O. ~S~C COWS VAbU 45 O, aSPC CONS VALU 46 O, ASPC CONS VAbU 4'7 A$~C CONS VALU 48 O. ~SPC CONS VALU 49 ASPC C~NM VALU 50 ~S~C CONS VAb~.! 51 O. aS~C CONS VAbU 5~ O, 25-SEP-94 09:33:46 Pa~e 30 chlumherqer bTST $1~OIAP:[94294]bOG_O14.LIS~! l~4A I87A l~gh 190~ I~IA 1~2~ l~5A 196A 107A 109A 20OA ~02A 20~A 204A 205~ 206A 207A 208A 209A 2~OA 21 215~ 2t8A 220A 222~ 223 226A 2Pga 230~ 23iA 232a 233a 234~ 235A 236a 237~ ASP'~C CONS VALU 53 O. ~,SPC CCNS VAL9 54 ISPC CO~$ VALU 55 ~C CO?~$ VaLO 56 .~S~C CONS V.ALLi 57 O, !5PC Cn~,~S v~t,U 5~ aSPC COi'~S VAr, ti 59 o. IS~C Cfi~ VALU 60 O. ISPC CO;~$ V~LU 61 O. ASPC CONS VALU 62 O. A$~C C~NS VALU 6~ O, aSPC CONS VALU ~SPC CONS VALU 66 AS~C CONS VALU 67 aSPC CONS VALU 6~ O. ASPC CO~S VALU 69 O. A6PC CONS V~[,U 70 0, ASPC CONS VALU 71 O. 5SPC CONS VAbU 72 O. A, SPC C~N~ VALu 73 ASPC CO~S V~L$ 74 ~SPC CONS VALU 75 O. aSPC CO~S VALU 76 O. ASoC CONS VALU 77 O, ASPC CONS VALU 78 ASPC CGNS VABU 79 ASPC CONS VASU ~0O, AS~C CONS VALU 8 ASPC CONS VALU ASPC CONS VALU ~3 O, p~ ~S.C CGNS VALU ~4 ASPC CONS UALU 8'5 O, A~PC CONS VALU 86 ~SPC CONS VALU 87 A,6 ,.~..~C, CQ~,,~,,, VA~,U, 8,8 AS~C CONS VALU 90 O~ aSPC CONS VALU 9 ASpC :O~,S ~ 93 AS, C 94 , ASPC VALU 95 O, ~PC CO~.S I'~LU 96 O. ~SPC CONS VALU 97 O. ASPC CONS VALU 98 O. ~SPC COMS VALU A$~C Cc~N~ VAbU t02 O, ASPC CONS VALU 103 O, ASPC CONS VADU i04 O, .~SP~ CO~$'~ VALU 105 18u CONS VALU A8PC CONS VALU i0~ O, ASPC CONS VALU 108 O. ASPC CONS VALU 109 25-SEP-04 09:33:46 Paoe 31 ChlUm~,erqer b~ST $i~DIA~: r94204]LnC;.014.L?S;1 238A 239~ 241~ 242A 243A 244A 245~ 247~ 250~ 2~1~ 252A 253A 255~ 256A 258A 259~ 260A 262A 2~3A 264A 266A 267A 269~ 270~ 272A ASPC CONS VAI,iJ 110 O, aSPC C~S VALu ASPC C~.~$ VAt,,U !12 O, ~S°C CO~S VA!,U 1~3 O. ~SPC CCSS YALU 114 0. ASPC CONS VA~.O 1~5 O, ~SPC CONS VALU 196 O. ASPC CONS VALU 117 0. ~SPC CONS VASU 118 0. ASPC CONS VALU 119 0, aSPC CQNS VqLU 120 0. ASPC C0mS VALU 12~ 0, ~SDC COI{$ VALU i~2 0. ASPC CONS VALU ~] 0, ASPC CONS VASU ~4 0. ASPC CO~S VA5[~ 125 0. ~SPC CoNS VALU 126 O, ASPC CONS YALU A$PC CONS VALU 1~8 O, ~SuC CONS VALU 129 O, &SPC CONS VALU 1BO o, ASPC CONS VALU i3! O, ~S~C CONS VA[,U 132 ASPC CONS VALU 33 ~$DC CONS VALU ~SPC CONS VALU ASPC CONS VALU 116 0, ASPC CONS VALU I370, ASDC CONS VALD i38 0, ASDC CONS VALU 119 O, ~Sm, C Cn~S VALU 3 ,~STC CONS VALU 4 274/~ 277A 6 .s~c coN,s ~.s?c cons vA~,U 8 ~s~c cons VA~,,U 9 5 AS~C CON8 VASD ~TC cons ~s~c co~s v Ar~u aSTC CONS ASTC CONS VAbU 22 noTC CO~;S Vab ASTC CO~S VALL{ 24 ~STC CnN:S ViLU 26 '06 ~7 E-CiO 25-OEP-g4 09:33:46 Pa~e 32 chlut'llberc.~er l,T$'r $,[~DIg2: [94~94] ~STC CO~ VA!.,U 27 0.1574934 ~$~"C C0:iqS V.:%LU 28 -_.004740066h IS~C CO:',:$ V~I..,~ 2~ 9'43276RE-05 ASTC C[~'~,~R VaI..d 30 '3,350538E-07 ~.. rS VAT..,U 3X -2,548456 ~STC CO~'~S VAbLi 32 0,101568 ASTC CO~'!$ VALU 33 2.949863E-05 ASTC CDNS VALU 34 ~'6.~04162E 07 ASTC CObS VALU 35 ASTC CO~S VALU 36 AS~C C~r,:~ VALU 37 ISTC CONS VA!.,LI 39 ~8TC CoNS vAI, U 4~. 55TC CO~JS VALU 4~ IS~C CONS VALU 43 ASTC CtINS V~UU 44 ,aSTC CONS V.ALU 45 ISTC CONS VabU 46 ASTC Cr~NS VAY.,,U 47 ISTC Cass vASU 48 ~STC CONS VALU 49 ASTC CONS VALU 50 IGTC CO~S vALU 51 ASTC CONS VALU 52 ,%STC CONS VAbU 53 ~STC CONS v~bu 54 5 .,STC CONS VALU 55 1 348'76E'08 ASTC CO~S VALU 560 586515 . o037 45236 aSTC COr~S VALU 57 ASTC CONS vALU 58 - 0003~2699 ~STC CCNS VALU 59 2' 03007E-06 .aSTC CO~4S VALU 60 -{ 735242~-08 ASTC Cnr~s VALU 61. -1 ~48 331~ ~.C C:O~$ VAD'U 63 E-05 332~ ;~,$TC CONS vA,.,~U 6 07 333t 15 C CONS: V~.~,U 334A AS',~,.C CON8 VALU 66 3~'5A ~STC CONS VALU 67 , ~'73 3361 ASTC C~NS VA!,U 68 09 337A ASTC CONS VA.SU 69 6 5 3381 RSTC CONS VAI.~U 70 - -07 34()A .ASTC CO~JS VALU 72 0 3,4~A ASTC C~NS VALU 73 - ~-05 24,9~6926~'10 . 3451 ASTC CONS VaLU 77 O, 8993~5 3~6A ASTC CO~S VALU 78~6sO0167.2854 3471 ASTC CONS vabu 79 3.249579E'-05 3481 ,SSTC CO~'~,, VALU 80 ~,9~779E'08 349~ ,~5TC CON,: viSb 81 1,055827 3501 ~6TC CONS VALU 8~ 0.0424978~. 351A ASTC Co~S vALU 83 -t.367849D 05 25-SEP-94 09:33:46 PaOe' 33 3521 353~ 354a 3571 358~ 3!9A 360A 36 A 3~I~ 363~ 364R 3671 368A 369a 370~ 3741 375A 376~ 3771 3791 3,0~ 3~1~ 384A 386~ 3 3901 39 3931 396A $98A 399A 40la 405~ 406~ STC c)~tS V.~Lt..,~ 84 I 195398E-07 .~STC Cn~,:S vaLi'] 8~ 1,611277E-10 ~S~C CO~:~$ VAL:., 86 ~ 408863 ~STC CO:~S VaLU 87 ~,0461448 ,STC CONS VAI, U 88 -0 003109~06 ,STC C~S V~LU 8~ ~[*~984E-05 aSTC CO~S V~l.,:j 90 ,066297E-07 A~TC Cf}NS VAL0 91 .989818~ ~o, C S VALU 96 314441 aS~,C CONS VALU 97 ,02671909 ASTC CONS VALU 98 0 001652436 · ~STC CONK VAI.,U 99 ~TC CONS VALU 100 -~ 601808E-08 . o C CONS VAI..,'~ 101 0 5151049 ~BTC CONS vALU 102 305E-10 ~STC co~s vA~,u lo5 4. A~TC CON~ VALU 106'0 4 57443 ASTC CONS wA[W 107 0,6I-'34929 VALU 110 1. ,07 VALU I l l I~TC CONS VALU 112 0,, 126 ~STC CONS v~[,,U li~~ 532E-05 ~STC CONS VALU ~ - -o7 ASTC CO~$ VALU 116 ,09~7046 0 A6TC CONS VALU ~17 -0 002345178 ~8TC CONS VALO ASTC CPNS VALU ~$ C C[~S VAL~ ASTC CONS VALU AKTC CONS VALg I27 ISTC CONS VALU 1.28 ASTC COi~S vAbu l.o,C ¢"ONS VAL!~ 130 lo C C~NS VALU 32 AS...C C ..... ,$ VAL0 I33 ASTC C NS VALU 134 ASTC CONS VALU i35 ASTC CONS VALU 136 -0 ASTC CONS VAL0 137 ,955 ~9 ,E-08 .E'05 :-07 0 747 ASTC CO~q,S VAbU 139 6,.191484E-'06 ~$~C CONS v~%t~ t40 -2,467486E-08 25-8EP-94 09:33~46 Page 34 Chlu~beroer bT$~ $1~O.~:~942~4]LOG_L)l~.LIS;1 25-SEP-9~ 09:3.]:46 Paqe 35 End o~ set Table type Listln~ of set 1~ type CON6 O~dNA~4 ST~T T~IN~ PUli DESC VAbU ~~m~m~m ~m~m~m~ ~mm~m~m~m ~mm~mm~mm~m~ m m ~mmm~m~m~m ~m~m~mmm ~m~~m~~~m~ H~,D ~LLO Header beoal Disclaimer INCL CWEI ~bLO LB/F LB/F Casing weight ~9. CSI~ ~LLO I~! IN Current Caslna Size g.625 STEU 63. 97.4 TW$ 400, RW ALLO ONMM OHMM Res~stlvit¥ of Connate Water 0,09~99999 ~T~ ~LLO DFGF DEGF ~axi~pum Recorded Temoerature ~ ~T ~DLO DMGF DEGF MaXimum Recorde~ ~emOerature 1:1"0. RMFB Ab~O OHM~ OHMM ReSistivity Of MU4 FiltTate - BHT 0 .056369~7 ~B ~LSO OH~ OM~ ~esistlvit¥ O~ ~ud - 0.08844566 MCST ~LLO D~GF DEGF Mud CaKe Sample Temperature RgCS ALLf] OHMS OH~M Resistivity Of ~ud Cake sample 2,3o5 MFS ~bI~O DEGP DE,~ Mod Filtrate Semele Tem~eratur'e 2. AL[,O DEGF DEGF S~rface Temperature a~LO DEC DEG Maximum Hole Deviation ~LLO DEGF DEGF Temperature o~ Connate water Sample AbLO PPM PpM Borenole Sallnitv Chlna, ber<~er L~ST ~I~DI.aP:[94294]bOG.O14,L!$:i R~FS ALLO O~M O~a ~eslstlvity o~ ~u~ Filtrate Sample a.11.2 67. R~6 AbL, O n~t~ nH~ Resistivity of ~ud Sample 0.~4 9,1999 4.8 DFV ~LLO 44° Orll, llng Fluid PM 03 Orllllno Fluid boss DFD Drilling Fluid V{scostty AbtO LB/G I,B/G Orllllng Fluid Density 9.9 ~LLO IN IN Bit Size AL[,,O F/HR W/HR Nominal bogging Speed 1800. FLEV ASI, O F w Fl'uld Level O, BSD · AhLO 5977. Bit SiZe Depth To BSDF ~L, LO F F 1858. CBL? AbLO F ..854' 8it SiZe Depth From Casing 8ottom of 5oooer CBDR AbLO F w 1858. Casino BOttom of nrlller Casing Depth To CDF Abb~ F F O. Casln~ Depth From TLI abLO 1854. TOD Log Interval ALLo F F 5968. Bottom Log Interval TD5 ALLO F F 5971. Total Depth - Logger 25-SEP-94 09:33146 Page 36 5977. Total DePt~ -Or~ller ECL ~[,[~0 ~ w Elevation of Ground bevel 157.4 EKB abLO F F Elevation of Kelly Bushing frei,' ~bLO F F Elevatior, of Derr[c~ Floor J,~4.~ ELZ ~[,L,~ F ~ E)evation of Lo~ Zero ADD ~LLO F F Above Permanent Datum ~7.70001 EPD ~LT.t] F LCC aLtO 44O Elevation of Permanent Datum bogging Company Code Unit Number SECTION 'T'OWNSHTP 8ection/Latftude [,abel Townshis/t, ongt/ude Label RLAB AbLO Ranoe/BlanA ~,abel RANG~ CJT ~LLO PRTA PvE~ 6C0-490 SON 549277 HIDE A~LO ~ea~er LITHODENSITY HTD~ aLT,O Header COMPENSATED ~EUT~ON OSi A~LO Other DSST/DIT~ 0~2 LDT/CNT,/NGT Cement JOb Type P~oqram Version Service Order Number Identifier t~enti,f~er Line .~: Services Line I Other Services L~ne 2 25-SEP=94 09:33:46 Paqe 37 chlu~berqer blS'r Sl$I)I,~?: [942~4]LOG_O!4.bJ8~l RI ~b[,,O ~emar~ Line ~bl:~ Remark Line ~AN wITH SO,SPRiNG R4 ~LL[~ Remark I, lme LDT aND C~t, PA~ mN SANDSTONE MATRIX ~,LLO Remark Line PR~SE~TATION~ AT CLIENT ~EOUEST 25-SEP-94 09:33:46 paoe R6 AL[,Q Remark Line ~ gAIN bOG i~'~;OT gIJ:'{ FNO~ TD (AT CLIENw'S REOUMST) DUE TO CONCERNS WITN R7 ALLU Re~ar~ Line 7 DIFf'ERF~{TI AL STtCK~ R~ ALLO Ren,ar~ Line 8 wltness'$ Name ~¢TTN ALL~'~, C. UNDERWOnD E~IGT ~LLO $~ITM/uCCRO$SAN K E N A I EnQineet's Name bogging Unit Location TLAB ALLO DLAB ALLO OB'AUG'94 TCS0400 H~$ DCS ALLQ MCSS abLO Time boqger At .Bottom Date booger At Bottom Time Circulation Stopped Date Circulation StO~ped CaKe Sample Source ~.id Filtrate Sample Source ~ud Sample Sotlrce Drilling Fluid Type 38 25-SEP-q4 09:33146 paqe 39 RItN ~LLO R~D D~TF ~LLO Date as Nont. h-Dav-Year 98-AUG-g ~ OgF ~LLO Drlllln~ Measured From AuLG boo Measurer] From KELLY BiJ~qH~f NG R~ Nt'; ~,bI, O Ranoe SECT ~LLO Section PDAT ~ L I.,t3 Permanent Datum GROUND bgVKb APlN 5LLO API serial ~umber 50-i3~-20445 !Lt, O Field Location 1164' FNL & 1547' FWL 'T S.AT ALLO state or Province SLAB ALLO state/Province Label STA~ , COUN ~LLO COUntv or R'~g Name CLAB AbLO · n Cou ty/Parlsn bal~el FN Ah~.,O Field Name REAV~R CRE~K , AbLO Well Name BEAVER CREEK ~9 CN ALLO Company Name ~ARATHON OIL COMPANY E~nd of set chlu,~berq,r LTS~ $[~DT.%~:r94294~bOG.Ot4,LIS;I 25-SEP-94 09:33:46 Page [.,ls~ln~ o£ set 13 Cype DBdN~M STAY TI!MI PUNI DESC VALU SPE~ a550 F/HR W/HR S~mulated Logg~n~ Speed .~00 PP AhLO Playbac~ Processin~ NOR~ E~VI AbLO Acquisition Environment VCE~ ALLO F3 ~3 Cumulated Cement Volume 46,~0068 VNO[~ aLLO Fl F3 Cumulated Hole Volume 6~,~469 A&PL ALLO AIT Answer Product bevel(Depth Lo~/V~ew only) ACRL ALLO ATT calibrate Report benqth FULL ASAP abLO AIT Suspend Asswer Product Processino 0.~O ~!G$ ALLO AIT Select AKimm Interpolation Oatln~ OFF ATRL ALLO ATT TeSt Report Length FUbL ATT$ ~LLO AIT Test Phase Tool Strin~ C~RT AwFa aLLO F F AIT Telemetry write Frame Max DeDtt~ 5000~ AWF~ ~L~O AlT Telemetry write Frame Max Number To Process 9999 ADFA AhI.O F F AIT Telemetry Oump Frame ~ax Depth 50000, ADFU ALLO AIT Teleg~etr¥ Dump Fra~,e Update Cycle 24 AETP AL[,O AIT Enable SOnde ~rror Temp&Pres corr ARFA A550 F F AIT Telemetry Rea~ Frame MaX Depth 50000 A~F~ ALLO AiT Te%emetr~ Read Frame ~ax Number T@ Process 99999~ A~ RbbO AlT' Telemetry Monitor_update C¥cl.e 24 AUhv ~LhO AlT User bevel Control NORM O~D~I UNAL FEET End of set Table type FILM ListlnQ bi set 14 type FILM OBJNA~ GCOD GDEC OEST DSC~ ~22 i~2 PF? 8 ~g~ --- PF~ 85 E2~ -22 ~F9 ~ Kn~ o~ set Llstina of set 15 type PRES . OBjNAM OUTP STAT TR~,C CODI DES MOD~ FIhT LEDG REDG cs sPo 0,5 o. o&oo. ooo 4O L, IST ~:116 Hrtl6 HT16 01)16 91126 DU36 DU46 DU56 DI166 DUB6 Pl16 Rgl6 5!16 S116 8~'26 TF. 16 ATI7 AT27 AT37 A~P47 A~57 A'P67 AT17 A.?87 AT97 AmA7 ATB7 ATC7 ATD7 ATi7 CS: 0/%37 QAL? : . n .... LIS; 1 $t,~D!A2 I'94294 ] L.. ~.,-014. ~AZI ~TEN DI~'~ ~ DU~ OU~M SiLO STIT TENS ~T~O AT30 ATOO ATRX ~T~T AT~I ATDI ATDm ATD2 ~IBO AIBD ALbO F12 bbi~ 6 NB 1. ALbO F2 LDAS 6 RB$ 0.5 A!,LP F2 LSPO 6 NB 1. A!,,LO rl LL!~I 6 SNIF 0.5 hbLO Fl2 LDAS 6 NB 1. ALLO F1 MOAS 6 WRAP 0.5 {)ISA F34 LLIN 6 NB 1. D!$~ F34 bLIN 6 NB !. OlSA F34 LLIw 6 NB ~. PISA F34 LLIN 6 NB I. OISA F34 bLIN 6 NB I. PISa w34 LLI~ ~ NB DISa F34 bLI~ 6 NB DISA F34 5LIW 6 NB ALLO F12 LSPO 6 NB 1. ALLO P12 LDAS 6 NB DIS~ ~L) HLIN 6 NB ~. ALbO FD LLIN 6 NB ALLO PD LLIN 6 NB 1. Al, LO F4 LSPO 6 WRAP 0.5 AbLO T2] LLI~ 7 GRAD ALLO T2] LSPO 7 ~R O ALSO T23 5DAS 7 GRAD 1. Al, BO T2,t bGAD 7 GRAD 1 T2~ [.,bin 7 GRAD AbbO DISA ~2~ bbI~ 7 GRAD 1. DISA T2] LLIN 7 G~AD DISA ~HT1 LSPO 7 NB 1 DI~S~ LHTi LSPO 7 NB DISA ~HT1 LDAS 7 NB DIS~ LHT1 bOAS 7 NB DIGA TD bLIN 7 NB At,LO RHT1 5bin 7 NB Al, LO LHT1 LLIN 7 NB 0. 0. 0. 4O 0560. -10. ""20, ..,70 Oo O. 0 1 ~000. 0.2 N,B NB NB I. NB NB NB NB I. SNIF $~IF .5 SHIP ~ NB 0,5 NB 0,5 NB 0'5 S~IP 0.~ 10, 500~ 80, ~0, ~0 - 36 50. 5O 3060. 2000, 2000 2000~ 2000, 2000, 90. 0 O. O. 24. 90. ST2 50 TEl7 3650. C118 Cl ALLO T2 4. ~I~ C2 ALLO 73 14 FC28 PCO ALLO T3 OmI8 CR ALbO T1 ~ 610,. H~I8 MA~I ALLO Ti 360. 000 000 000 0~0 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 il0 303 ).O4 04O 4OO 000 000 000 000 000 000 000 000 O~ 404 404 0 0~ 044 000 000 0,00 000 000 000 4OO 004 000 000 000 O30 02 ! 25-SEP-94 09:33:46 Page 41 HT18 $T18 T~18 AT19 AT2q AT59 AI29 AC19 0S19 CSI~ GRig ~R19 QA39 O~4q ~a59 QA69 ST'iq ST19 S~29 T~ AT2A AT3A AI2A AC2A OAIA ~A3A Q~4A OA5A Q~6A 5PIA SIVA STIA ST2A $1gl)lA?: ~942o41btl)G_O1.~.LT$;1 PlAZ ALLO T1 bSPO 9 TENS ALSO T3 GSPO ~ AT1U ALLO T23 bLIN 9 ~T20 ALLO T23 bSPO ~ AT.]() AI~LO 72~ LDAS 9 AT6U AbLO T~ LGAP 9 AI~D ALLO T1 5SPO 9 ACRS PISA ~! bSPO 9 ACED PISA ~t bSPO g BS DISA T1 LGAD g CS DTSA Ti D~PO 9 HT~N ALLO 73 HDAR q ~RE$ DTS~ ~1 DbIN g OAIT PISA XXXX hbI~ g OAIT OISA XXX ~N g QAIE [)ISA XXX~ ~lN 9 OATE pISA XXXX LLI~ 9 OA~U PISA XXXX bLIM 9 QAIU PISA XXXX LbIN 9 S,P ALLO Ti LGAD 9 STIT PISA TD LLI~ 9 STIA DTSA TO bLlM 9 ~T,O ALLO T23 LLI" A ,,~20 ALbO A:T3o ALLO hDAS A AT60 ALLO T23 A AI~D Al,bO T!. ~I~R PISA T1 AC~$ DI Ti ACMD DI C$ DISA T1 LGAP bSPO A bG,A,P A ~RAP ~ 0.5 NB 1. N~ 1. WRAP 0.5 GRAD 1. GRAD 1. GRAD l. GDAO GRAD . N~ 0.5 NB NB SuIF 0.5 NB 0.5 ~ o GRAD 0 5 NB NB NB NB 1. NB NB . ~RAP ~,5 G'~AD . GRAD i. 10500. -40. O. O. 0 1~§~0o 0-2 0.2 0,2 0o~ 0~o Oo 5oo. o O2 -29. O' 0,2~00' ,,2 500. 000 360. 014 50. 000 50. 000 ° ooo 3 , 000 2000, 110 2000. 303 2000, 002 2000, 400 2000, 104 400 1 203 1~. 430 16 000 so oo, ooo 100 030 000 oo: ooo 49. 404 11] 030 . 044 13. 044 ,, 400 50, 000 00,0 0'0, I10 2000, 303 2000, 002 4OO 14. O, so oo. .100, 900 ~ ~0, 0': 50' O, 50, ~0 0. 25. SA 83000 LLI~ A 000 .... All PISA XXX× LLIN A 404 OATT DIS~ XXXX LLI~ A 404 OAIE PISA XX×X LL~N A 0]0 OA~U PISA XXXX LLI~ a 044 OAIU D~SA ×XX× hblN A 044 SP ALLO TI LGAP A 400 SILO DISA TD HLIN A 000 STIT PISA TO LLIN A 000 STIA DI'S:A TD bi, IN A 000 TE~S ALLO T3 bSPO A 000 ABPR ALLO PHil DL/N B 000 25-SEP-94 09:33:46 Paqe 42 AO1B AgAF ALhO T23 LSPO B GRAD 1. 2. 20000 gO0 AO2B ~AF ALLO T'23 bgAS B GRAD 1. 2. 20000~ 000 A03~ ~OAF ~LL~ T23 DG~P B (;RAg ~. 2. 20000. 000 A04~ A~F AT,LO ~23 LLITM TM G~AD ]. 2. ~0000. 000 AOSB ~A~ ALLO T23 LSP~ B GRAD ~. 2. 20000. 000 AObR A{~F' hLbO ~23 bDAS B G~AD ~. 2. ~0000. 000 AO7B AQAF ALLO T23 [,GAP B GRAD 1. 2. ~0000. I04 CSI~ CS DISA ~1 5SPO B NB 0.5 0 50000. 000 HTI~ NTEN ALLD T3 H~AS B ~RAP 0.5 1~500. 50~ 000 9a1~ OATT DIS~ XXXX LLIN B NB 1. 13. -4-~ 404 ~A3~ OAIE DIS~ XXXX LLI~ R NB ~. ~I -2~. ~A4g OAIE OISA XXXX LLIN B NB 1. ~ 3i OA6~ OA~U DISA XXXX LhI~,~ B NB ~. 4~. X3. 044 $~lg SILO DIS,A TO hLIN g N~ ~. O. 50. 000 STIB STIr DISA TO LLI~ g ~<g I. O. 50. 000 ST2~ ST!A OISA TD b[,I~ B NB l. 0 50 000 "~ . 3560. ooo ], .1R TENS AI,LO T3 LSPn R ~AP 0,5 1~500 25-SEP-94 09:33146 Paoe type AREA [,,istXnQ of set 16 type AREA ORJNA~ STA~ BEG: ~ND PAT? DEST FC:O'~,' BCOL [,AB~ ..... ....... ,.............................................-. A~LO . ST16 O~b 000 444 Cable Drag TOI6 AR2? QA77 TO17 C~,18 TOI8 O~8~ OA99 OAA~ TOl~ CAl,n Q A 7 A oAgA BHiB C~IB ALLC XX~ ST~6 ANHY 6 000 444 Tool/Tot. Drag ~LLO Arc? Z2 COAL 7 000 444 A~T Volume of, Mud Filtrate Area AL[,,O Z2 .ATD7 COAL 7 000 444 AIr Ct]rye out of Order Flag Area ALLO ST27 ST17 OIL 7 000 444 Ca~le Drag ALLO QA17 QA~7 OIL 7 404 444 QAIT.Area aLLO QA6? OA],7 GRO ALLO Z9 ST~7 AN'HY A~50 18 ~C~8 " $T~8 ANHY ST2g ST19 OIL ~X.~LQ OAi9 OA~9 OIL ALLO QA3g OA49 OIL ALLO QA5g 0A69 OIL DI~A OA69 OA~g GRO DiSA Z~ ST~9 ANHY DiSA ST2A STIA OIL AhLO QAtA OA2A OIL ~bLO OA3A OA4A OIL AbhO ~ALA OA6A OIL OISA ~,A6A OAlA DISA Z~ STOA ANHY ALLO 1,38 AB~.B GAS ALT,O 2.25 AB]B COAL ~ISA $T2~ ST~B OIL 444 444 lq 000 444 000 444 000 444 444 444 044 444 44.4 444 lq 000 444 Tool/Tot. Dra~ 000 444 Cable Draq 404 444 ~AIT'~rea -30 444 QAiE.Area ~4 444 O~IU.Area 444 444 lq' 000 444 00~ 444 m O0 444 S8 Corr Cr 000 444 Cable Drag 43 ChlUmherqer LTST ~l ~ 7B .~LLO OAIB OA~80TL ~ 404 444 ~AIT.Area 9~AR ~I~A :,'~6g OA!B GRO R 44~ 444 1~ .... ~213 ANHY B O0~ 444 Tool/Tot, Drag 25-SEP-g4 09:33{46 mmmmmmmmmmmmmmmmm#mmmm~mmmmmmmmmmmmmmmmmmmmmmmmm#mmmmm#mmm#mmmmmmmmm et Taol. e type PIP f, lstln~ of s-t 17 t OBJNA~ TR~C OUTP STAT 1)416 LETD 1~ DISA I~26 I, ETD I~V DISA IC16 ~E~D ICY DISA IC26 WETD ICY DISA IT16 ~E~D ITT DISA IT26 RETD ITT DISA 6T16 LET9 6~I~ DISA I~*17 LETD IWV DISA I~27 LETD I~V DiSh ICI7 ~ETD ICY DiSA IC27 ~E~D ICY DISA ITl7 RETB ITT DISA IT27 ~ETD ITT DISA I~I~ LETD IWV ~LLO I~2~ LETD IHV ALLO IC18 ~ETD ICY &bLO IC28 REmD ICY ASLO IT18 RETD ITT DISA IT2~ RETO I. I DISA I~19 LETD IHV DISA IM29 [,ETD I~V D~MA RETD DI~A 9 A A !C2~ ~ISA A DISA A IH1B bETD DISA B I~!2B LETO PISA 8 ICIB R~TD DISA B ITIB ~ETD [)ISA B IT2B WE~D DI~A B Mhd of set ITT ITT ICY ICV ITT ITT ICY ICV ITT ITT pe PIP D~ST INTE COLO 10. 000 6 100, 000 6 10 000 5 106, 000 6 1, 000 b 10 000 6 60' 10' 444 ~ ooo 10 , 000 v ooo 7 1 , 000 7 ~,., 000 7 i6, ooo 8 I0" 000 8 lo~. ooo ooo 1 , O0 8 1. 000 9 10" 000 I 000 1~ 000 t0 10 1,0 10 i5 ooo 16, 000 lO Ooo io~ ooo 10' 000 lo6. ooo O0 Paoe 44 ChlUmberqer LTSm $15DIA?:[q42o41br~G_Ol,~.b!S~1 25-SEP-94 09:33:46 Paqe 45 TaOle type PCPS PCN$ ~LLC VGAZ ~YIZ ~6bO ~×3Z ~GLO ~4Z ALLO MXSZ ~bLO AhLO PP ALLO CP Bal3 AbLO 8116 8A18 0~2~ B~24 BA25 B BB11 BB13 BBI4 0~15 BB16 BB17 B~2~ BB22 BB23 8B2~, BB25 B~26 BB27 U, 18. O, Oo I8. ©, 18. O. 1~. O. !.8. O, !B. it, O, 18. O, 1 8, 0, 18. O 1.8, 0 1,8, 0 0 !~, O. 0, 1 8 ,. 0 · l, S. 0, I8. O. 18. O. O. V V V V V v V V IN MEST -~EST MEST MEST MEST MEST MEST ~EST MEST MEST MEST MES=T MEST ~EST MES? ~EST MEST ~EST ~ES'T MEST MEST MMST ~EST ~EST ~EST ACPS ACNS gI EV ~SWl ~SW2 PCPS PCNS VGaZ ~XIZ ~X2Z "X3Z ~X4Z ~XSZ RC2 ~p CP I;057901 1,261728 128349 '-2.10919 ~B2fl abt, O 0. 1,8. BCi~ ~LLO o. 18. bCl~ 5bL0 0. 5C14 &LLC 0. I~. BC15 abLG O. 18. BCI6 ALLL) 0. !8. BC17 ILLP O. BCi~ ALLO 0. ~8. 8C23 abLO 0. 18, Be24 ALLO O. 18. BC25 ALL~? 0. BC26 ALLO O. tS. BC27 ahLO 0. 18. BC28 ~LLO O, ~8. BDiI aLE, Q 0 18 BDI2 ~LLO O. BD14 ALI,O ()] SD15 ~hL, U 0. 18. BDi6 abY.,O ~ lB, BD17 ~I.,LO,,: 18. BDl~ abl,O O, 18, BD22 AGLO O. 18. Bm23 ~SLO O. J8. BP24 ~LLO 0. 1.8, BD25 ~LLO 0, ~8~. BO26 ~.DL(3 0,. 18. BD27 Al, LO O, !8. BD28 ALLU O. 18. AX ~LLO O, 0. AY AhbO 0. 0, A ~.I,,O ,O: ,, 0 ALLO O. '0. FY ALLO O, 0. GADZ ADLO o, O. GPV ALtO O, 0, GNV AL[.,O O, 0 GAT ALI..,O O, 0 G~4'T ~LLO O, FT,I~ ALLO O. GSW ALLO 0, ,, .aiDe aLr~O . .~6 .A~D{~ ALL0 o, 126 AIDL ~LI.,O O, 126 AYEC R,L L ED O. 126 AIGL AbLO O, 1,26 AIGO ALY,O O. !26 .ATR~ Ai.~Y~ 0 26 AIBO ALLO 0 126 OER OER ORR OER ¥ V V V V V DEGF DEGF D~:G~ DEGF MEST MEST ~EST MEST MMST s~EST M~$T MMST MEST MEST M~ST MEST MMST REST ~EST ~ FY G M~ T FTIM MEST GSW .25 AIT AIDC ,25 AIT AIDH .25 AI~ AIDL ,25 M~/~ MM/M AT AISC I, .25 AlT ~I'GL I, .2~ A~T aIGO i; ,25 AIT ABAG .25 AIT ABUG .~5 ATT O. O. 0. 0. O. 25-$EP-g4 09:33:46 Pa~e 46 :'h lUmber<~F ATCG ~LLiJ 0 ASCA ALL(3 O, hgPL ~LLt) O. ASRW ~LLO 0, ASZ ~ h hBO O. A~C~ A[,Lt~ O, g~Ph ~LLO O. ATPL ~LLG 0. ATR~ A [,~C 0 ATZA Ab[,,(5 O. ATZ~ ALLC 0. AVCL ALL~ O, AVPA Ai, 5~ t), AVPL AL ,~{~ n, AVRW ALtO t). AVZA ALLO o. AVZ~ ~L,.,,C, O, ABAT ALLC 0. ADBO ~[,[ O O. ABES A~LO 0., ADRG AbLO 0, ABSP ~LbO 0. ADTD &LBO 0. ADT~ ~LLD O. AQTR AbLO 0, ADTS AL[,O O, ADU~ ADLO 0, AOVO ~LLO O. ATOM ~L50 O, 25 ~26.75 126.25 !2~.25 12 .P5 126.25 126 25 126 ~5 126 ~5 126 ~5 ~ 26 25 ~26 ~5 V ~26.¢5 V 126.75 ~ 126 25 V ~ 26~5 V ~26 25 V 126. ~5 V ! 26, 95 V 126 25 ~ 26 ~5 126 ~5 12~ ~5 t~ 25 126 55' 0. 0,, 0~ 0. 0. O, O. O, O. 0 ~5 ~5 25 ~5 .... , GA,PI.GAPI O. 0. AlT ATCG AlT AUAG AlT AU~!G ATT ASCA AlT ASPA AIT ASPL AIT ASRW hit ASZA AIT AIT ATCA ATT ATPA A~T ATPL A~T ~TRA AlT ATZA AIT ATZE AlT AVC5 A~T AVPL AlT AVRW AIT AVZE AIT ADAT AIT ADBO AIT ADDE hiT ADES AlT ADR:G AlT ADSP A%T &D?D AIT ADTE AIT ADTR AlT ADTS AlT ADUA AlT ADVO AlT ATO~ SGTL TCCF HV TCCF TCCB TCC~ T~ CB O. 1. 0. 1, O. 1. 0. I. 0, GAPI GAP1 1.048057 O. V v DEGF TCCB 09:33:46 Page 47 Chlumberqer L~ST 1. Oo 1. O. 25-SEP-94 09:33:46 PaOe 48 mmmmmmmmmmmmmmm~mmmmmmmmmmmmmmmmmmmmmmmmmmmm#mmmmmmmmmmmmm#mmmmmmm#mm ~n~ of set 0ata format specification record l, istino ~f set 1 type 64EB EMT~Y VA[,d~ REPCOD~ SIZ~ 1 0 66 2 0 66 1 3 2294& 7q 2 4 ~ 56 5 1 66 6 o 73 4 7 TN 65 8 60 7] 4 9 iTt~ 65 4 13 1 66 1 14 lIN 65 4 1~ ~3 6~ 1 0 66 0 ~n~ o~ set object 0 bistin~ of set 0 '''' TC,. APl TO ORDER ~ ~OG TYP E. I IN 2 201 0 17 $ ~EST F/HR 6 621 0 17 EL uEST F/MN 63 600 0 17 ~EST LBF 63 521 0 17 I ~ ~EST S 63 6~i 0 17 MAR~ ~EST F 15 001 0 17 I 1 FNO~ ~EST OER 63 101 0 17 :FINC ~EST bEG 63 10~ 0 17 ! ~PCF "L,.~rs' 6i I01 0 17 I DPT~ ~EST D~G 61. t01 0 17 1 DPA~ ~EST D~G 61 101 0 17 I ~UAF ~EST 61 101 0 DDIP ~EST D~G 61 i01 0 i7 I DbA ~EST PEG 61 101 0 ~7 I 1 AREA ~EST FT2 28 004 0 17 AFCD ~EST FT2 28 201 . ~ ~MS' ES~' FT2 28 20! 0 17 FCD ~EST I~] ~8 20~ 68 0000 )0 68 0000 )0 68 00~ 68 00( )0 68 0000000000 68 0000000000 6B 0000000000 68 000§000000 68 000 000000 68 0000000000 68 0000000000 68 0000000000 68 0000000000 0000000000 68 0000000000 68 0000000000 68 0000000000 68 0000000000 25-SEP-g4 09:33:46 IHV ~EST FI 28 2010 17 1 1 4 68 0000000000 ICV vES'l~ F'~ 2~ . z,.,. 10 17 ] 1 ~ 68 0000000000 STI~ "EST F 0 I7 1. ! 4 68 0000000000 STIT ~ ES'!' F 0 17 1 1 4 68 0000000000 D~V! ~'~:s'; aEG 62 oo~ c 17 ~ ~ ~ 6s ooooooooon HAZT r.~,_ DEG 63 001 0 17 ~ 1 4 68 0000000000 P1AZ "EST DKG 63 O010 17 ~ I 4 68 0000000000 RB vEST DEG 6.~ 10i 0 17 I 1 4 68 0000000000 SDEV ~EST D~G 69 001 0 17 ~. I 4 6fl OOOO000000 RT ~EST 0~.~ M 93 501 {) 17 1 i 4 68 0000000000 HV ~'EST V 0 17 ~ 1 4 68 0000000000 HTEN ~EST 5~F o 17 I I 4 68 0000000000 MRES ~EST OT4 ~ ~ 0 17 I 1 4 68 0000000000 S~ ~ ~,',S T ~v 10 010 17 I I 4 &~ 0000000000 SPAR ~ESI ~{v 10 OIO 17 I ~ 4 6~ 0000000000 RSP ~ESI ~V lo 010 17 ~ I 4 68 0000020000 RSPA ~EST ~,v I0 010 17 1 ] 4 68 00000~0000 ASCA ~EST ~,~V 0 17 1, ! 4 68 0000000000 RGR VEST G~,PI 0 17 1 1 4 68 0000000000 TT~ ~EST ~$ 53 6210 17 ] ] 4 68 0000000000 A.O~ ~'EST F/S2 63 lOi 0 17 I 1 4 68 O00OO00OO0 ~I~ ~EST D~GF 0 17 1 1 I 6~ 000~000000 CTE~ VEST D~GF 0 17 1 1 4 68 0000000000 RMTE ~EST DEG' 'F 0 17 1 1 4 68 0000000000 TEM ~EST DEGF 0 17 1 1, 4 68 0000000000 ~TF ~' · .EST DFGF 0 17 ~, J 4 68 0000000000 ATCA ~EST DEGF U 17 ~ 1 ~ 68 0000000000 DTEM ~EST DWHF 0 17 ~ ~ 4 68 0000000000 GR ~ E;'ST GAPI 0 17 , ~ 4 6. 0000000000 7 M 73 ~E,sTE~I ~6I;61 ,,,Q;O000000 . 6060 ,240 240 o~' ((u~O'O00 3 .ESr 61 000 0 17 , 60 240 68 600 9 mEST 6' 000 0 17 I 60 2.40 68 0000000000 3 ~EST 6! 0000 17 ! 60 68 0000000000 ~EST 61 0000 17 1 60 68 00000000:0'0 ~ES'T 61 000 0 17 i 60 240 6~ 0000000000 9 VEST 61 0000 17 ! 60 240 68 0000000000 ~ VEST 61 000 0 f71 60 240 68 0000000000 23 ~"ES.T 61 0000 17 1 rio 240 68 0000000000 B~24 VEST 61 0000 i7 1 60 240 68 0000000000 BC28 ~EST 6! 000 0 i7 I 60 240 6~ 0000000000 B.~.25 ~EST 61 000 0 17 ~ 60 240 68 0000000000 B~26 ~.~EST 61 0000 17 1 60 240 680000000000 B~27 ~EST 61 9000 17 ! 60 240 68 0000000000 BAll ~EST 61 oho 0 17 ! 60 240 68 0000000000 B~l~ ~EST 61 0000 i7 ] 60 240 68 0000000000 ,~gS~ 61 000 0 I7 I 60 240 8 0000000000 6 B~15 ~EST 61 000 0 17 1 60 240 6~ 0000000000 Bl~t6 ~EST 6I 000 0 17 ~, 60 240 6~ 0000000000 BA18 ~ST 6] 0000 I7 I 60 240 680000000000 B~21 ~ES'r 61 0000 17 ~ 60 240 68 0000000000 Page 49 Chlumbe~er ~:[~tJT:~: [94294~]L~C,,.O14.LI$;1 25-SEP-94 09:33:46 Pa.qe 50 BC11 ~£ST bl. OhO 0 17 I 60 240 68 0000000000 BC12 ~ST bl. Ot')O 6 t7 i 60 240 68 0000000000 BCI4 u~$~ 61 OO~ C 17 ~ 60 240 68 0000000000 BCI5 ~'EST 6t OOC 0 17 ~ 60 240 68 OOOO000000 BC16 ~gST 61 000 ~ 17 1 60 240 OB 0000000000 BC18 UEST 6~ ~00 t.) 17 1 60 240 68 0000000000 BC21 vEST b!. ()nO 0 17 t 60 240 68 0000000000 BC22 UEST 61 OoO 0 17 I 60 240 68 0000000000 BC23 uEST 61 000 o 17 ~ 60 240 68 0000000000 BC24 uEST 61 000 0 17 t 60 240 68 0000000000 BC25 UEST 6~ 000 0 ~7 1 60 240 68 0000000000 BC26 uEST bl 000 9 ~7 ~ 60 240 68 0000000000 BC27 ugsr 6~ oho 0 17 1 60 240 68 0000000000 BB22 ~Es~' 61 0000 17 ~ 60 240 68 0000000000 BB2] "EST 6l gO00 17 ~ 60 240 68 0000000000 BB24 UEST 6~ 000 O 1~ 1 60 240 68 0000000000 BD28 ~EST bl. ono 0 ! ! 60 240 68 0000000000 BB2~ u~T 61 0o00 17 ! ~o 240 68 0000000000 BB26 ~EST 61 0000 17 I 60 240 68 0000000000 BB27 ~ESV 61 0000 17 1 60 2.40 68 0000000000 BBIJ. ~EST 61 0000 17 1 60 240 68 0000000000 ~ ~EST 61 0000 17 1 60 240 68 0000000000 ~4 ~EST 610000 17 1. 60 240 680000000000 .~.~. 5 uEST 61 000 0 17 i 60 240 68 0000000000 BB16 ~Sr 61 000 0 17 1 60 240 68 0000000000 BBl, ~EST 6i 00'00 i7 ,. 60 240 68 0000000000 :.~B.21.Dl,. ~EST~EST 6,61 000000 O0 i~ }. 60 60 ~4040 ~ 00000000000000000000 sD ~ ~gs~ si ooo o 17 t 60 ~4o 68 oooooooooo ~O . ~g~u,i 61 oho 0 17 t 60 240 68 0000000000 .~ 5 uEc. 3. 61 0000 17 ! 60 240 68 0000000000 ':','__ 6 ~ST ~I ooo o l? ~ 60 240 ~m oooooooooo ~ ~sw 6~ ooo o ~? ~ 6o ~4o 68 oooooooooo { ~EST 6~ 000 0 17 1 60 240 68 0000000000 ,,ES~' 61 000 0 17 I 60 ooo o oooooooooo o 6! 0:00 0000 )0 8 0 6~ 0000 I? i 60 240 68 0000000000 ,2 ~s~, ~. ~oo § . ~! ~ ~o ~4:o ~e oooooooooo ,~ .~sT ~ oo ~ ~. ~o ~4o ~8 oooooooooo ,~ ~s, ~, ooo o 1 ~o ~4o ~ oooooooooo ~sr ~, ooo o ~.~ ~ 6o ~4o ~, oooooooooo ~ ~'ss~ a{ ooo o ~, ~ 6o ~4o ~ oooooooooo ~,~ ~s~ 6~. ooo o ~v ~ ~o 2.4o 6~ oooooooooo ~ ~s,? 6~ ooo o ~ ~ ~o ~o 6. oooooooooo DB4 ~EST 61 0000 17 60 240 68 0000000000 FCA~ '~EST F/$2 0 I7 60 240 68 0000000000 . ES F/S2 0 ~7 1 60 24068 0000000000 ~EST F/S2 O lU I 60 2,40 6~ · ~' T , ~ 0000000000 ?I~ ~E$ ~$ 0 17 1 60 240 6.. 0000000000 'A ~EST MS 6,3 621 0 17 1, 4 16 6~ 0000000000 11 ~EST IN 2~ 041 0 i7 I 4 16 68 0000000000 I'~ ugS I~ . .Y..T ~ 2~ 0420 ~7 1 4 ~6 68 0000000000 ~E~T F/~ AY ~EST Z UEST F/S~ Z ~'EST O~R 8~ ~EST MS A~BD UE~T PSI AIBD ~EST AIFF ~EST ACES ~ ,ES7 ACED ~FST I~ ACCR ~EST ~/~ ACRF ~EST A.BF~ .EST AT10 AT20 O~ ~EST ~'190 ~EST ,':~0A ~E;ST M~/u ','{ BT ~: EST DEGF A'IFC ~EST WEST EST EST ~gST ~'EST 9,4294] LOG-O.~ 4, LIS ~ 1 2~ 0 0 0 0 6J 6~ 61 0 63 0 0 0 0 25'$EP'94 041. 0 17 1 4 16 68 0000000000 042 0 17 ~ ~ 16 68 0000000000 17 I 4 16 68 0000000000 17 l 4 16 68 0000000000 17 1 4 16 68 O000000000 17 1 4 16 68 0000000000 17 ~ ~ 16 6R 0000000000 502 0 17 ! 4 16 68 O000000000 503 0 17 1 4 16 68 0000000000 501 O 17 1 4 16 68 0000000000 17 1 4 16 68 0000000000 6~I 0 17 1 12 4 8 6~ O0 17 J ~ 8 °° oo oooooooooo 17 5 ~ 40 68 17 I 1 4 68 6 0 )0 End Of set 09:33:46 Page 51 Data record true 0 DEPT 1.064160 ..!IN 8868. FT 2702.9664 ,......-........................-........................,..........,..,................,,.... ,S 6,. Cs 814. 4796 CVl~b -13.5746 TENS 367.0. .TI' 0.. MAR' ~89' FNOR ~,572~793 FINC 78.2.4995 SPCF 1,87905~ 0 . . DPTR 9'99,25 ~FCD 0.06681332 ABS 494 FeD. 3.5 STIT o, DMVI Oi~ ],,'rST $1$PTA2: [.4294]bOG.O14. SP -~0. SPAP -20. 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