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Home My WebLink About194-0561a. 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): GL: N/A 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- 4 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 25.050 102' (ft MSL) 22.Logs Obtained: N/A 23. BOTTOM 32"82 18-5/8" X-57 1,133 13-3/8" K-55 3,547 9-5/8" L-80 9,201 7" P-110 10,102 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 If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): 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, TUBING RECORD 11,472 9,046 9,038 9,029 3-1/2" LS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 6/21/2023 194-056 / 322-609 50-733-20458-00-00 S MGS Unit 17 ADL0018746 686' FSL, 1873' FWL, Sec 35, T8N, R13W, SM, AK N/A 4/15/1994 11,484 / 10,106 Surface 127' 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 229319.2614 2463858.3784 N/A 1115' FNL, 616' FEL, Sec 3, T7N, R13W, SM, AK CASING WT. PER FT.GRADE 5/30/1994 CEMENTING RECORD N/A N/A SETTING DEPTH TVD 2462114.8589 TOP HOLE SIZE AMOUNT PULLED N/A 226791.2030 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. N/A BOTTOM SIZE DEPTH SET (MD) 9,177 / 8,922 PACKER SET (MD/TVD) 3-1/2" SS 9,31432 Surf 47 Surf Surf 1,133Surf Surf 68 9,484 Surf Surf 97.7 82 Surf 3,548 N/A N/A Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information Sr Res EngSr Pet GeoSr Pet Eng Middle Ground Shoal / MGS Oil & SMGS Undefined WDSP N/A Oil-Bbl: Water-Bbl: Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By Grace Christianson at 11:02 am, Jun 30, 2023 Abandoned 6/21/2023 JSB RBDMS JSB 071223 xGDSR-7/19/23 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A N/A N/A Top of Productive Interval N/A N/A N/A N/A 31. List of Attachments: Wellbore schematic, Well operations summary 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Aras Worthington Digital Signature with Date:Contact Email:Aras.Worthington@hilcorp.com Contact Phone: 907 564-4763 Operations Manager 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: 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 INSTRUCTIONS Formation Name at TD: 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. Authorized Title: 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. Authorized Name and 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. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. 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. 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). Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2023.06.30 08:39:11 - 08'00' Dan Marlowe (1267) Dillon Platform Di-17 Dillon Platform Well Di-17 Last Completed 6/15/94 Tubing 3 ½” Production 9.2#, L-80 Surface 9,038’ SBTC / 2.992” Long String/ Internally coated tubing 3 ½” Production 9.2#, L-80 Surface 9,029’ SBTC/ 2.992” Short String Casing and Tubing Detail Size Type Wt / Grade Top Btm CONN / ID Cement / TOC 32” Structural Surface 83’ 18-5/8” Surface 97.7# / X-57 Surface 1,133’ QTE60 / 17.653” 294 lead & 129bbls tail w/additives, good cement returns at surface 13 3/8” Intermediate 68#, K-55, BTC Surface 3,548’ K-55/12.415 360bbls Lead @12.9ppg & 74bbls Tail @15.8ppg w/additives, Calculated TOC=2016’ MD,(Incl. 1°) 9-5/8” Production 47# / L-80 Surface 9484’ Butt / 8.68” 230bbls @15.8ppg w/ additives, CBL TOC @ 6,800’ 7” Liner 32#/P-110 9,314’ 11,472’ TKC-BTC / 6.094” 50bbls Lead @11ppg & 124bbls Tail @15.8ppg w/ additives, CBL TOC @ 10,270’ Dual String Jewelry Detail L O N G S T R I N G Depth (RKB) Length ID OD Item 55.42’ 2.99 Cooper Dual Hanger 1 9038’ 26.30’ 2.687” Trico Kobe Pump Cavity 2 9,081’ 3.54 2.56” S.Sleeve, HES RA SSD # 121RA25623 3 9,116’ 3.54’ 2.56” S.Sleeve, HES RA SSD # 121RA25623 4 9,136’ 8.75’ 2.56” Baker FV6E TRSV 5 9,177’ 11.47’ 2.99” Locator Seal ASSY w/10.45’ of seals 6 9,177’ 6.79’ 5.00” HES VST Retrievable Pkr. Sr# 12VST96350-2 7 9,184’ 7.40’ 5.00” Seal Bore extension 8 9,191 .68’ 2.99” XO 9 9,208’ 1.44’ 2.56” Model “R” Profile Nipple 10 9,215’ .45’ 3.45” WLEG S H O R T S T R I NG 55.42’ 2.99” Cooper Dual Hanger A 9,029’ 1.08’ 1.995” XO, 3 ½” x 2 3/8” B 9,030’ 10.05’ 1.995’ Tbg Pup jt C 9,040’ 26.30’ Trico Kobe Pump Cavity TD = 11,484’ TVD = 10,105’ PBTD = 11,419’ MAX HOLE ANGLE = 83.09O @ 11,260’ MD 13-3/8” @ 3,548’ Top Perf 9876’ RKB-TH: 54.12’ KB 7” @ 11,472’ 7” TOL 9,314’ 1 18 5/8” @ 1133’ 7” CBL TOC @ 10,270’ 9-5/8” @ 9484’ – 24 deg 2 3 4 6 5 7 8 9 10 C B Btm Perf 11400’ Top Perf 9344’ Btm Perf 9460’ A 13 3/8” Cement @ surface 9 5/8” CBL TOC= 6800’ 10 1 B AA Cement Plug #1: 7” Liner: 11,413’ MD (Est’d) to TOL @ 9314’ MD (Est’d) 9-5/8” Casing: 9,314’ MD (Est’d) to 9,215’ MD (Est’d) IA: 9,000’ MD to 5,000’ (Est’d) LS: 9,000’ MD to 4,881’ MD (Tagged 6/16/23) SS: 9,000’ MD to 5,476’ MD (Tagged 6/16/23) Cement Plug #2: OA: 700’ MD to surface IA: 700’ MD to surface LS: 700’ MD to ~600’ MD Cement Plug #3: OOA: 400’ MD to surface LS: 400’ MD to 15’ MD (Tagged 6/22/23) SS: 400’MD to surface Rig Start Date End Date SL / Cmt Pump 6/12/23 6/22/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 17 50-733-20458-00-00 194-056 06/13/2023 - Tuesday Held PJSM, discussed daily ops. R/u EL on SS, M/u CCL, Wt. Bar and 1-9/16" tbg puncher (CCL 4' from top shot) Stab lubricator on well, PT 2500psi-good test. RIH and punched tbg @ 9000'-03'MD. POOH L/d toolstring confirmed gun fired. R/d EL. R/u circ eq. Well pressures LS/SS/IA=400/450/390. Opened IA to gas buster tank and bled to 0psi. LS and SS bled off with IA. Lined up to pump down LS returns up IA. Pumped 29bbls to catch returns, continued circulating 3bpm/150psi, after pumping 80bbls shut down pump. Lined up to pump down LS and returns up SS. Pumped 4bbls to catch returns, continue circ 3bpm/550psi, pumped a total of 40bbls and shut down pump. Secured well and Blow lines dry. SDFN 06/12/2023 - Monday Held PJSM and discussed daily ops. Recorded SI well pressures: LS/SS/IA=400/3200/2650. Hooked up bled hose to return tank. Installed plate covers on top of diffuser tank to bled gas. Bled off SS and IA to 400psi. Final pressures LS/SS/IA =400/400/400. Spotted and R/u EL. M/u CCL wt bars and 2" tbg punch. While stabbing on lubricator the wire was pulled out of the head. L/d lubricator. Re-head W/L;M/u CCL wt bars and 2" x 3' tbg punch (18shots) Top shot to CCL 6.5'. Stabbed on lubricator to the LS. PT t/2500psi good test. Bled off to 400psi. Opened well and RIH, punched holes in LS @9000'-03'. POOH confirmed tbg punch fired. L/d same. M/u CCL wt bars and 2" x 3' tbg punch (18shots) Top shot to CCL 6.5'. Stabbed lubricator on SS. PT t/2500psi. RIH tagged @ 2313' and wire jumped sheave due to torque in the wire. Worked line back on sheave. POOH at 2283' began POOH heavy. Possibly torque wraps or knots in wire underneath grease head. PJSM, Closed WL valve and bled off lubricator. Un stab lubricator above WL Valve and p/u 15' and did not see any knots or twist in wire. Stab back on lubricator. Opened WL valve. Began POOH slowly with f/2283' with drag then wt fell to neutral. POOH. SI well and L/d toolstring. Old records show restriction @ 2300' that was gauged @ 1.75". Plan to run 1-9/16" tbg punch in the AM. Rig Start Date End Date SL / Cmt Pump 6/12/23 6/22/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 17 50-733-20458-00-00 194-056 06/14/2023 - Wednesday Held PJSM, discussed daily ops. R/u cement eq. and choke manifold. Prep to pump lower cement job. Assist crane working boat and arranged deck. PT lines to 3000psi. Lined up down LS returns up IA. Pumped 20bbls of surfactant wash followed with 247bbl of 9.8 brine. Shit-in IA and opened SS pumped 53bbls of 9.8 Brine. Lined up down LS returns up IA, Pumped 25bbls of returned fluid form well closed IA and opened SS, pumped 44bbls of returned fluid from well and spotted at tbg punch @ 9,000'md. Shut-in SS. Performed Injectivity test, Bullhead 115bbls of returned fluid form well down LS @ .8bpm/2500psi. Displaced injection fluid with 44bbls of 9.8 brine and 34bbls of 9.8ppg wt spacer at 1.5bpm/2500psi. placing 9.8 brine in tbg @ 9000'md. SD pump. Lined up down LS returns up SS thru choke, mixed and pumped 58bbls of 14ppg cement slurry @ 4bpm/600psi. Close SS, opened IA. Mix and pumped 20bbls of 14ppg cement slurry @ 4bpm/150psi placing cement in LS at 9,000'. Shut-in IA. Bullhead 102bbls of 14ppg cement slurry into formation, catch pressure at 20bbls away, pumped remaining 82bbls @ 4bpm/1200psi. Sd pump. Opened IA returns thru choke, mix and pumped 189bbls of 14ppg cement slurry @ 4bpm/250psi. Shut in IA at choke. drop wiper ball at cement unit. Open IA and pumped 9bbls of 9.8ppg brine @ 4bpm. SI IA, opened SS and pumped 35bbls of 9.8 brine @ 4bpm placing TOC in LS,SS and IA @ ~5000'. Cement in place @ 19:38hrs. Performed sheen test-no sheen washed up cement overboard. Plan cement job 353bbls Actual cement job=369bbls Injected cement into 7" liner=102bbls Tank straps returned volume from cement job=284bbls. 06/15/2023 - Thursday Held PJSM, discussed daily ops. Crew performed housekeeping and assist crew arranging deck. Continue working in well bay room #1 and #2 prep to pull trees and removing casing valves to verify TOC. Cleaned and inventory parts and tools. R/u Testing eq. to LSxSSxIA. Opened up well LS and SS static IA on vac. pressured up several times on LS,SS,IA working air out. Pre CMIT LSXSSXIA. Initial=2730psi, 15mins=2632psi, 30mins=2583psi Rig Start Date End Date SL / Cmt Pump 6/12/23 6/22/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 17 50-733-20458-00-00 194-056 Held PJSM, discussed daily activities. Housekeeping, standby for WL crew and state inspector to arrive. R/u testing eq. CMIT LSxSSxIA. Pumped 2.6bbls to pressure up. Initial=2759psi,15mins=2644psi, 30mins=2604psi. Good test. Bled off 2.5bbls. Test was witnessed by AOGCC Inspector Sean Sullivan. R/d testing eq. R/u Ak eline on LS. M/u CCL, wt bar, spang jar and 1.75" bailer, RIH tagged TOC 4,881'md, W/t POOH. Recovered sample of wet cement. R/u on SS, RIH with same tools and tagged @ 5476'md. POOH recovered wet cement. M/u 2" x 3' perf gun, 2.8' offset CCL to Top Shot, RIH parked CCL @ 697.2'. Fired gun and shot perf holes 700-03'md. POOH L/d tools confirmed all shots fired. R/u circ eq. Lined to pump down LS, returns up SS. Began pumping 1bpm, pumped 4bbls away and observed fluid coming out of the starting head conductor x annulus. SD pump. Called OE to discuss plan forward. R/d AK E-line and sent crew to beach. Off load cement pods and ISO from Boat. 06/17/2023 - Saturday Held PJSM, and discussed daily activities. Prep wellhead to weld plates to seal leak. Transferred fluid from the return tank to ISO, back load 3 ISO's and misc eq. Held PJSM and obtained permit, welded on plates to cover 8 holes on the conductor starting head. Continued transferring fluid from return tanks to ISO's. R/u circulating eq. Lined up down LS, up SS. Pumped 3bbls away and found leaks coming around the plates starting head. Prep wellhead, welder made several passes around plates to reinforce welds. Will test welds in the AM. 06/18/2023 - Sunday Held PJSM, discussed daily activities. R/u circulating eq. lines down LS, up SS. Pumped .8bbls and conductor leaked again around welded plates. Obtained permit, welder worked on adding caps around areas that were leaking on wellhead. R/u circulating eq. pumped .5 bbls with 3 leaks identified on wellhead. Welder continued welding on areas to seal leak. Work boat arrived, back load ISO's and misc. eq. R/u cement and washup iron to wellhead. Verified conductor x annulus head was not leaking. Lined up to pump down OA returns up OOA, Pumped 1.1 bbls of FIW and caught full returns. Mixing and pumped 1bbl pink dye pill and seen pill return at surface in 4bbls. OA and OOA leak ~15 below the wellhead. 06/16/2023- Friday Rig Start Date End Date SL / Cmt Pump 6/12/23 6/22/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 17 50-733-20458-00-00 194-056 06/19/2023 - Monday Held PJSM and discussed plan forward. Warmed up eq. Lined up pump down LS, spotted 10nbbls of surfactant wash in IA and OA. Circulated 70bbls (2xBU) up IA swapped returns to OA and circulated 84bbls (2xBU). Swapped to OOA, after 3bbls returns clean similar to the OA. Standby. WL working on Di-04ss. R/u AK E-line on SS, M/u CCL, Wt bar and 1-9/16" x 3' tbg puncher, 2.8' offset from top shot, RIH and punched hole @ 700'-03'. POOH L/d tools confirmed puncher fired. R/d Ak E-line. Lined up pump down LS up SS, circulated 6bbls @ 2bpm/100psi and verify holes. Ran borescope thru the OOA outlet down to ~120' with no evidence of cement. Finalized cement job. Held PJSM, mixed and pumped 56bbl 14ppg cement slurry down LS returns up OA. 56bbls away got cement returns at surface, swapped returns to cuttings box and pumped 2bbls with good cement weight. S/d pump. Lined up to pump down OOA returns up OA to clean above leak in the csg. Pumped 6.5bbls of FIW, with returns clean after 5bbls away. Lined up to pump down LS returns up IA, mixed and pumped 36bbls 14ppg cement slurry @ 3bpm/300psi with good cement returns at surface. Dropped wiper ball and pumped 5.5bbl of 9.8brine leaving TOC in LS @ ~600'. SD pump and secured well. Performed sheen test-all good. Washed up cementing eq overboard. 06/20/2023 - Tuesday Held PJSM, discussed daily activities. Crew worked in well bay #2 removing wellhead valves to verify TOC. Worked boat, offloaded and fill two ISO's with brine from return tanks, back load ISO on boat to send to Ken G&I. Mobe Ak-Eline crew to platform by boat. R/u EL on LS, M/u wt bar, CCL (2.8' offset to top shot) and 3' x 2" gun 6spf 23 gram charges, Stab on well. Swab valve would not fully open, opened bonnet and cleanout cement on top of the gate. M/u bonnet and opened valve, RIH parked CCL @ 397.2'. fired gun and perf LSxSSxOOA @ 400-03'md. POOH L/d tools and confirmed all shots fired. R/u circ eq to LS, SS and OOA. Lined up down LS, returns up SS. Rolled pump over and swab valve bonnet leaking. Blew lines dry and replaced gasket on bonnet, Lined back up to pump down LS. returns up SS, pumped .5 bbls and pressured up to 600psi, made several attempts to break circulation with no luck. Lined to take returns up OOA. pumped .8bbls and pressured up to 500psi. Several attempts and could not break circulation. R/u EL on SS, M/u wt bar, CCL (2.8' offset to top shot) and 2' x 2" gun 6spf 23 gram charges, Stab on well. RIH RIH parked CCL @ 397.2'. fired gun and perf SSxLSxOOA @ 400-03'md. POOH L/d tools and confirmed all shots fired. SDFN, will try to break circulation in the AM. R/u circ eq. Circ 2xBU down LS up SS @ 3bpm/300psi, circ 2xBU down LS up OOA @ 1.5bpm/500psi. Rig Start Date End Date SL / Cmt Pump 6/12/23 6/22/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 17 50-733-20458-00-00 194-056 Held PJSM, discussed daily activities. R/u cement eq. Prep to pump 2nd stage surface cement job. Held JSA, circulate and across washup lines and PT 1500psi. Lined up down LS, returns up OOA, pumped 20bbls of surfactant wash, mixed and pumped 14ppg cement slurry @ 1.5bpm/450psi, cement returns early at 36bbl away w/t 11ppg, continued pumping monitoring return weight. 52bbls away returns 13.8ppg, swapped to OA, clean fluid returns then 4bbls away yielding 13.9ppg. Swapped to SS, pumped 4bbls returns 13.9ppg cement. SD/pump. Performed sheen test-no sheen. Washed up equipment overboard. R/u circulating eq. off wellhead. Crew performed housekeeping and removing wellhead valves in Well Bay #4. 06/22/23 - Thursday Held PJSM, discussed daily activities. Removed tree and wellhead valves, verified TOC; OOA-visual cement at surface, OA- visual cement at surface, IA-visual cement at surface, SS-visual cement at surface, LS-tag TOC 15' down. 06/21/23 - Wednesday MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:35 Township:8N Range:13W Meridian:Seward Drilling Rig:N/A Rig Elevation:N/A Total Depth:10508 ft MD Lease No.:ADL 0018746 Operator Rep:Suspend:P&A:X Conductor O.D. Shoe@ Feet Csg Cut@ Feet Surface:18 5/8"O.D. Shoe@ 1133 Feet Csg Cut@ Feet Intermediate:13 5/8"O.D. Shoe@ 3548 Feet Csg Cut@ Feet Production:9 5/8"O.D. Shoe@ 9484 Feet Csg Cut@ Feet Liner:7"O.D. Shoe@ 11472 Feet Csg Cut@ Feet SS Tubing:3 1/2"O.D. Tail@ 9040 Feet Tbg Cut@ Feet LS Tubing:3 1/2"O.D. Tail@ 9215 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified LS Tubing Fullbore Bottom 11848 ft 4881 ft Wireline tag SS Tubing Fullbore Bottom 11848 ft 5476 ft Wireline tag Initial 15 min 30 min 45 min Result Tubing 2759 2644 2640 IA 2759 2644 2640 OA 5 5 5 Remarks: Attachments: Cement sample looked good from tag. Combo MIT 2 tubing strings and IA; 2.6 bbl in, 2.5 bbl out. June 16, 2023 Sully Sullivan Well Bore Plug & Abandonment S MSG Unit Dillon 17 Hilcorp Alaska LLC PTD 1940560; Sundry 322-609 none Test Data: P Casing Removal: Wade Hudgens Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 11-28-18 2023-0616_Plug_Verification_SMSG_Di-17_ss                 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a 1$ SVL 0' SVL SVL 3HUIRUDWLRQ'HSWK0'IW /6DQG66 )RUP5HYLVHG$SSURYHGDSSOLFDWLRQYDOLGIRUPRQWKVIURPGDWHRIDSSURYDO6XEPLW3')WRDRJFFSHUPLWWLQJ#DODVNDJRY By Anne Prysunka at 4:02 pm, Oct 19, 2022 'LJLWDOO\VLJQHGE\'DQ0DUORZH '1FQ 'DQ0DUORZH RX 8VHUV 'DWH 'DQ0DUORZH DSR-10/19/22 X DLB 10/20/2022 Provide 10 days notice for opportunity for AOGCC Wellsite inspection after this sundried work is complete, before September 30th, 2023. 10-407 Monitor and report fluid losses that occur while placing the deep cement plug. BJM 6/7/23 Provide 48 hrs notice for AOGCC opportunity to witness tag of cement plug in the long string and short string and PT of LS after pumping first cement plug. GCW 06/08/2023 JLC 6/8/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.06.08 13:54:36 -08'00' RBDMS JSB 060823 P&A Sundry Well: Di-17 PTD #194-056 Well Name: S MGS UNIT (Dillon) 17 API Number: 50-733-20458-00-00 Current Status: Shut-In Injector Rig: SL, EL, FB Estimated Start Date: October 2022 Estimated Duration: 1 week Regulatory Contact: Juanita Lovett 777-8332 Reg.Approval Req’d? Yes - 403 First Call Engineer: Aras Worthington 907-564-4763 (O) Second Call Engineer: Ryan Rupert 907-777-8503 (O) Current Bottom Hole Pressure (est): 3934 psi @ 9368’ TVD (est.) Maximum Expected BHP: 3934 psi Maximum Potential Surface Pressure: ~2997 psi Gas Column Gradient (0.1 psi/ft) Current Pressures LS/SS/IA/OA/OOA): 260/890/725/0/20 History Di-17 was drilled in 1994 and completed as a Hemlock producer. The well was Shut-In in 2002. In 2011 the well was converted to a disposal well. 18-5/8” casing cemented with 294 bbls lead and 129 bbls tail. 20 bbls of clean cement circulated to surface. 13-3/8” casing cemented with 360 bbls lead and 74 bbls tail. Did not note cement returns to surface. 9-5/8” CBL shows TOC @ 6800’ MD. 7” CBL shows TOC @ 10,270’ MD. Pre-P&A diagnostics completed x Bled OA from 25 psi to 0 psi. OA and OOA tracked. x Bled IA from 700 psi to 0 psi (all gas). x D&T LS: 2.8” & 2.7” GR both tagged @ ~2500’ SLM. 2.25” bailer tagged isolation sleeve in Kobe cavity @ 9018’ SLM. x D&T SS: 2.8” GR tagged @ 30’ SLM. 2.25” bailer tagged @ 2309’ SLM. 1.75” GR tagged @ 9012’ SLM. x Verified LS & SS do not circulate: Isolation sleeve prevents LS and SS from comunicating. x MITIA passed to 2500 psi. SS tracked IA. x Fluid packed OA w/ 8 bbls FIW. PT up to 475 psi, OOA pressure tracked. Held for 5 min w/ 5 psi pressure loss. Bled pressures to 0 psi. Circulation rate from OA to OOA 2 bpm @ ~50 psi. Circulation rate from OOA to OA same. x Pressure up IA to 2250 psi. Injectivity test with RIW 1.5 bpm, FCP 2680 psi. IAP 2200- 2250 psi. x Circulate down SS @ 0.75 bpm/1500 psi. x AOGCC witnessed MITIA to 2330 psi – pass. Witnessed by Matt Herrera. x Attempt to establish circulation down SS and out IA. PT SS to 2500 psi for 5 mins – lost 10 psi - Pass. x D&T SS w/ 1.75” GR to 9016’ SLM. P&A Sundry Well: Di-17 PTD #194-056 x Circulate down OA w/ returns from OOA. Get diesel then RIW back immediately. Repeat process several times to verify. Leak in 13-3/8” casing is very shallow. No need to log w/ EL. x TOC in OOA observed at the OOA outlet. Current Status Shut-in. The OA and OOA have no injectivity and are in communication at surface. The IA pressure-tests to 2250 psi with no communication to the LS but pressure communication to the SS. The SS passed a pressure test to 2500 psi and has integrity down to the Kobe cavity. The LS has injectivity into the perfs (1.5 bpm @ 2680 psi) with no pressure-communication with the IA. This well is a good candidate for fullbore P&A methods. Objective Plug and Abandon the well to surface. Hilcorp requests a variance to 20 AAC 25.112 (d) (1). Hilcorp requests that the surface cement plugs extend up to the wellhead and tree valves. This is to ensure the well is properly cemented and to avoid any uncertainty as to the cement top. The platform legs and wells will need to be severed completely at or near the seafloor to remove the legs eventually, and the extra cement in the casings should not impede this operation significantly. Eline 1. Perforate the LS @ ~9000’ MD. 2. Punch SS @ ~ 9000’ MD (if circulation from LS to SS is not established with perforations). Fullbore 3. Circulate the LS, SS, and IA to FIW. 4. Verify circulation down the LS, out the IA and SS. 5. Pump LS x SS x IA x Reservoir cement plug as follows: ¾ 20 bbls FIW (Filtered-Inlet-Water) w/ Surfactant Wash (down LS and out IA) ¾ 371 bbls 9.8 ppg brine (down LS and out IA) i. At 327 bbls away swap to taking returns from the SS ¾ 20 bbls of weighted mud push ¾ 349 bbls 12 - 15.8 ppg Class G cement (down LS with returns from the SS). i. When 58 bbls of cement are away swap to taking returns from the IA to get mud push circulated up the IA ii. When 78 bbls of cement are away (LS is full of cement) SI returns and bullhead cement into formation until 160 bbls of cement are away at maximum IAP of 2500 psi iii. When 160 bbls of cement are away swap to taking returns from the IA. iv. Launch Foam Wiper Ball behind tail of cement ¾ 44 bbls of 9.8 ppg brine displacement (puts TOC in LS @ ~5000’, equivalent with IA and SS) i. When 9 bbls of brine are away swap to taking returns from the SS. Do not perforate through 9-5/8" casing because it will leave liner cement job in question. Use a tubing punch to punch the LS and another tubing punch for the SS. -bjm bullhead at high rate to ensure efficient displacement of 7" liner. -bjm Variance granted. -bjm P&A Sundry Well: Di-17 PTD #194-056 Volumes ¾ 7” Liner volume from 11,413’ MD to tubing tail: 0.036 bpf * (11,413’ – 9215’ ) = 79 bbls ¾ LS volume from tubing tail to 5000’ MD: 0.0087 bpf * (9215’-5000’) = 37 bbls ¾ IA volume from tubing punch to 5000’ MD: 0.0494 bpf *(9000’ – 5000’) = 198 bbls ¾ SS volume from tubing punch to 5000’ MD: 0.0087 bpf * (9000’-5000’) = 35 bbls Total Cement Volume: 349 bbls ¾ LS volume from tubing tail to surface: 0.0087 bpf * 9215’ = 80 bbls ¾ IA volume from 5000’ MD to surface: 0.0494 bpf * 5000’ = 247 bbls ¾ LS volume from 5000’ to surface: 0.0087 bpf * 5000’ = 44 bbls ¾ SS volume from 5000’ MD to surface: 0.0087 * 5000’ = 44 bbls Fullbore/Slickline/Eline 6. CMIT LSxSSxIA to 2500 psi (AOGCC Witnessed). 7. Tag TOC in LS & SS (AOGCC Witnessed). 8. Perforate the LS, SS, 9-5/8”, and 13-3/8” casing @ ~700’ MD. 9. Punch the SS @ ~700’ MD (if perforations did not establish communication to the SS). Fullbore 10. Verify circulation down the LS, out the IA, OA, and SS. 11. Ensure the OOA is fluid packed to surface. 12. Pump LSxIAxOA cement plug ¾ 20 bbls FIW w/ Surfactant Wash (displace 10 bbls ea. into OA and IA). ¾ Circulate 2x bottoms up from OA and IA (84 and 70 bbls respectively). ¾ 90 bbls 12 - 15.8 ppg Class G cement. i. Circulate out the OA until good cement returns are observed at surface then swap to taking returns from the IA ii. Circulate out the IA until good cement returns are observed at surface iii. Launch foam wiper ball iv. Displace cement down LS w/ 5 bbls 9.8 ppg brine (TOC in LS should be @ ~600’ MD). Volumes: ¾ OA from 700’ to surface: 700’ x 0.06 bpf = 42 bbls ¾ IA from 700’ MD to surface: 700’ x 0.0494 bpf = 35 bbls ¾ SS from 700’ MD to surface: 700’ x 0.0087 bpf = 6 bbls ¾ LS from 700’ to surface: 700’ x 0.0087 bpf = 6 bbls ¾ Total Cement Volume: 89 bbls Eline 1. Perforate the LS, SS, 9-5/8”, and 13-3/8” casing @ ~400’ MD. 2. Perforate the SS @ ~400’ MD (if perforations did not establish communication to the SS). 9-5/8" liner volume from 7" liner top to tbg tail: 0.0732 bpf*(9314-9215) = 7.2 bbls -bjm Total volume without cement in SS and only 100' in LS is 78 bbls. -bjm Cement won't be pumped into SS here. -bjm Pumping down LS. -bjm Diagram misrepresents location of tubing tail relative to 7" liner top. There is 99' of 9-5/8" casing exposed between tubing tail and liner top, which changes cement calc. 353 bbls. -bjm Only 100' of cement will be left in LS. -bjm 0.036 bpf * (11418'-9314') = 75 bbls P&A Sundry Well: Di-17 PTD #194-056 Fullbore 13. Verify circulation down the LS and out the OOA and SS. 14. Pump LSxSSxOOA cement plug ¾ 20 bbls FIW w/ Surfactant Wash displace into OOA (if circulation is established). ¾ Circulate 2x bottoms up from OOA (104 bbls). ¾ 59 bbls 12 - 15.8 ppg Class G cement. i. Circulate out the OOA until good cement returns are observed at surface then swap to taking returns from the SS ii. Circulate out the SS until good cement returns are observed at surface Volumes: ¾ OOA from 400’ to surface: 400’ x 0.129 bpf = 52 bbls ¾ SS from 400’ MD to surface: 400’ x 0.0087 bpf = 3.5 bbls ¾ LS from 400’ to surface: 400’ x 0.0087 bpf = 3.5 bbls ¾ Total Cement Volume: 59 bbls Attachments: Current Schematic Proposed Schematic Confining Zone Log If circulation out OOA is not established, discuss plan forward with AOGCC and obtain approval for new cement plan -bjm Verified cement volumes. -bjm P&A Sundry Well: Di-17 PTD #194-056 Current Schematic Tubing tail is 99' above liner top - bjm P&A Sundry Well: Di-17 PTD #194-056 Proposed Schematic Tubing tail is 99' above liner top, so cement will be placed in 9-5/8" casing between TOL and TT. -bjm 3 $6XQGU\ :HOO'L 37' tĞůůEĂŵĞ͗^D'^hE/d;ŝůůŽŶͿϭϳ W/EƵŵďĞƌ͗ϱϬͲϳϯϯͲϮϬϰϱϴͲϬϬͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗^ŚƵƚͲ/Ŷ/ŶũĞĐƚŽƌ ZŝŐ͗^>͕>͕& ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗KĐƚŽďĞƌϮϬϮϮ ƐƚŝŵĂƚĞĚƵƌĂƚŝŽŶ͗ϭǁĞĞŬ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗:ƵĂŶŝƚĂ>ŽǀĞƚƚϳϳϳͲϴϯϯϮ ZĞŐ͘ƉƉƌŽǀĂůZĞƋ͛Ě͍zĞƐͲϰϬϯ 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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. From:McLellan, Bryan J (OGC) To:Aras Worthington Subject:RE: [EXTERNAL] SMGS 17 (PTD 194-056) Sundry questions Date:Wednesday, June 7, 2023 2:33:00 PM Attachments:image002.png Thanks for clarifying all the diagnostics. Everything is clear to me now. Can you drift through the KOBE pump to TD? As for question #8 below, I don’t want to put holes in the 9-5/8” casing at 9000’ because you are counting on the cement going into the 7” liner and perfs when you bullhead. If you shoot the 9-5/8” casing, some unknown volume of cement will exit the through those holes at 9000’, leaving your liner cement plug in question. I’ll change that from perf to tubing punch in the sundry. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Aras Worthington <Aras.Worthington@hilcorp.com> Sent: Wednesday, June 7, 2023 2:04 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] SMGS 17 (PTD 194-056) Sundry questions Bryan, There is some room for improvement on the clarity of the pre P&A diagnostics. Answers below: From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, June 7, 2023 11:37 AM To: Aras Worthington <Aras.Worthington@hilcorp.com> Subject: [EXTERNAL] SMGS 17 (PTD 194-056) Sundry questions Aras, 1. The pre-P&A diagnostic results are not entirely clear to me. The 8th bullet says there was an IA injectivity test to 1.5 bpm, but then bullet 10 says it passed an MITIA. Where was the fluid going during the injectivity test? The injectivity test was down the LS. We put 2000 psi on the IA during the injectivity test because historically this was always done on this well, allegedly due to tubing movement concerns (pulling the seals out of the packer from tubing pressure). We still do that every time we inject into the well, which is frequently. 2. If it passed an MITIA, where was the 700 psi IA gas pressure coming from? We don’t know, but the well did sit idle for over a dozen years. We assume there was some slow leak from the tubing or packer to the IA which built up a gas-head in the IA. 3. The 9th bullet says “Circulate down SS @ 0.75 bpm.” Where were returns coming from? Bullet 5 says you could not circulate LS x SS. When this was performed the WSS thought he was circulating down the SS and taking returns from the IA, but in retrospect, with the later work it appears this could not have been the case. I probably should have taken that entry out, but it was thought this was the case. 4. The 12th bullet says there was an MIT-T on the SS. Was this a combo MIT of some sort, since you were able to circulate somewhere in bullet 9? No this was a PT of the SS only. 5. Where are the perfs in this well and which perfs are open/squeezed? Per the 404s filed w/AOGCC, below screenshot shows the perforation depths. I can find no record of any perforations having been squeezed, nor any record of any rig workover activity so believe all of the below perforations are open. 6. Are you able to gain access to the perfs below the KOBE pump? Do you mean with pumping? Yes we pump into the perfs for disposal. 7. I believe the diagram misrepresents the location of the tubing tail relative to the 7” liner top and perfs. From the depths listed on the diagram, you should end up with almost 100’ of cement between TOL and tubing tail, which is a good thing. Agreed, the schematic appears to show the TTail below the TOL, which is not correct. 8. In step 1, why are you perforating the long string instead of tubing punch? Don’t want to risk perforating the 9-5/8” casing. The idea is to only have to shoot once by perforating and hit the SS as well. But yes we will definitely put holes in the casing there as well. However, we have cement outside the casing per the CBL, and with the cement plug we are pumping going over these perforations it should not complicate or compromise the cement job. But if the perforations don’t establish circulation to the SS, we’ll probably just go ahead and punch the SS per the contingent step in the Sundry. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. 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By Anne Prysunka at 4:09 pm, Aug 10, 2022 By Anne Prysunka at 10:12 am, Jul 26, 2022 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, July 20, 2022 SUBJECT:Mechanical Integrity Tests TO: FROM:Matt Herrera P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC 17 S MGS UNIT 17 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/20/2022 17 50-733-20458-00-00 194-056-0 N SPT 8922 1940560 2230 320 255 235 220 0 100 100 100 OTHER P Matt Herrera 6/17/2022 MIT-IA performed for injectivity operations for Platform P&A Prep per Sundry 322-257. Tubing pressures in column are for Long String. 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From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: AIO 8.005 - Disposal Operations on the Dillon Platform S MGS Unit Dillon 17 (PTD 1940560) Date:Thursday, March 31, 2022 9:53:47 AM From: Wallace, Chris D (OGC) Sent: Thursday, March 31, 2022 9:53 AM To: Josh Allely - (C) <Josh.Allely@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: AIO 8.005 - Disposal Operations on the Dillon Platform S MGS Unit Dillon 17 (PTD 1940560) Josh, We have reviewed your request and your assumptions below seem correct. Our database shows S MGS Unit 17 (PTD 1940560) (Dillon 17) as a 1WINJ (water injector) and so it is probably appropriate to use a Sundry 10-403 to request this well be converted to a WDSP2 (Class II waste disposal). That Sundry can re-iterate/detail the requirements of AIO 8 and specifically AIO 8.005 for the witnessed MITIA prior to disposal operations commencing. To me it looks like AIO 8.005 identified the Dillon 16 and Dillon 17 approved disposal zone - which I believe correspond with existing perforations. If additional perforations are planned these would need to be approved by Sundry and conform to the identified zones in AIO 8 and more specifically AIO 8.005. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Josh Allely - (C) <Josh.Allely@hilcorp.com> Sent: Friday, March 25, 2022 9:58 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: AIO 8.005 - Disposal Operations on the Dillon Platform Hello Chris Hilcorp is planning to begin abandoning the wells on the Dillon platform this spring. The last time there was a wellwork campaign on Dillon, Unocal received permission to dispose of Class II fluids into Dillon 16 (SMGS UNIT 16) and Dillon 17 (SMGS UNIT 16) through AIO 8.005. We would like to utilize Dillon 17 as described in AIO 8.005 to dispose of any Class II waste generated during the abandonment campaign. In the approval, dated April 12th 2011, condition 6 indicated the remaining authorized disposal volume is 42,000 bbls. According to available data, Unocal injected 255 bbls leaving 41,745 bbls of allowed disposal remaining, per the AIO. My assumptions are as follows: AIO 8.005 is still active. Dillon 16 and 17 are still available for disposal operations for purposes of platform abandonment activities This availability is contingent on complying with the conditions in the order, specifically that we will need to get a state witnessed MIT-IA prior to placing the well into service. We have 41,745 bbls of available disposal. Does that sound correct to you? A few additional pieces of info: We only intend to use Dillon 17, as Dillon 16 did not pass an MIT-IA back in 2011. Only if we have issues with Dillon 17 will we pursue an alternate well. We are planning on mid May to begin this work, and our first order of business will be to get Dillon 17 ready for injection. The total estimated disposal volume is 20,000 bbls. Thanks and let me know if I left any important details out of this analysis. Josh Allely Well Integrity Engineer Kenai – Hilcorp Alaska 907-777-8505 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/L 6A STATE OF ALASKA 7/2412-°" ALASKA SAND GAS CONSERVATION COMMISSION(' REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Lf Repair Well 11 Plug Perforations U Stimulate 11 Other U Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate El / Re -enter Suspended Well ❑ 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑ Exploratory ❑ 194 -056 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic ❑ Service Ei 6. API Number: 50- 733 - 20458 -00. -- () el 7. Property Designation (Lease Number): 8. Well N ame and Number: ADL0018746 (Dillon Platform) S MGS UNIT 17 (Di -17) 9. Field /Pool(s): r , Middle Ground Shoal Field/ E, F and G Oil Pool 10. Present Well Condition Summary: Total Depth measured 11,484 feet Plugs measured N/A feet true vertical 10,105 feet Junk measured N/A feet Effective Depth measured 11,419 feet Packer measured 9,177 feet true vertical 10,094 feet true vertical 8,922 feet Casing Length Size MD TVD Burst Collapse Structural 83' 32" 83' 82' Conductor Surface 1,133' 18 -5/8 1,133' 1,132' Intermediate 3,548' 13 -3/8" 3,548' 3,547' 3,450psi 1,950psi Production 9,484' 9 -5/8" 9,484' 9,201' 6,870psi 4,750psi Liner 2,158' 7" 11,472' 10,103' 12,460psi 10,780psi 9,344'- 9,384', 9,397' - 9,417', 9440' - 9,460', 9,876' -9, 900',9,918'- 9.946'.9,956'- 10,045', 10,054 - 11,018', 11,132'- 11,231', 11,260' - Perforation depth Measured depth 11,297', 11,376'- 11,400' Feet 9,072' - 9.109', 9,121'- 9,139', 9,160'- 9,179', 9,545'- 9,564', 9,579'- 9.600', 9'607'- 9,671', 9,677'- 10,036', 10.055- 10,067', True Vertical depth 10,071- 10,076', 10,087' - 10,091' Feet 9,038' MD 8,796' TVD Tubing (size, grade, measured and true vertical depth) 3- 1 /2 "(LS & SS) / 9.2 # /L -80 (LS & SS) 9,029' MD 8,788' TVD HES VST Retrievable 9,177' MD Packer N/A N/A Packers and SSSV (type, measured and true vertical depth) 8,922' TVD w y 11. Stimulation or cement squeeze summary: 4i • r " t t 0 ! r . . ti .t •• 4 4, , q Intervals treated (measured): N/A 2 Li E , g Treatment descriptions including volumes used and final pressure: N/A 12. Representative Daily Average or Injectio ata srifission Oil -Bbl Gas -Mcf Water -Bbl 'dlisiniPttd9isure Tubing Pressure Prior to well operation: N/A N/A N/A psi 1,100psi SS /1,040PSI LS Subsequent to operation: N/A N/A N/A 800 'i 800psi SS /500psi LS 13. Attachments: 14. Well Class after work: //' p � Copies of Logs and Surveys Run N/A Exploratory ❑ Development ❑ Service le -- Stratigraphic ❑ Daily Report of Well Operations X 15. Well Status after work: Oil ❑ Gas ❑ WDSPL ❑ GSTOR ❑ WINJ El • WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 16. 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: 311 -190 Contact Mike Quick Phone: 263 -7900 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature c --- ` Phone 276 -7600 Date 7/18/2011 RBDMS JUL 2 0 201 Form 10 -404 Revised 10/2010 Submit Original Only hevro Dillon Platform Dillon Platform • Well Di -17 ''............-' Di-17 Actual Last Completed 6/15/94 Casing and Tubing Detail RKB -TH: 54.12' KB Size Type Wt / Grade Top Btm CONN / ID Cement / TOC ,41 ,___, b 32" Structural Surface 83' OTE60 . / 294 lead & 129bbIs tail 18 5/8 @ 18 -5/8" Surface 97.7 # /X -57 Surface 1,133' 17653" w /additives, good cement 1133' returns at surface 133/8" 360bbls Lead @12.9ppg & Calculated 68 #, K -55, 74bbls Tail @15.8ppg A TOC =2016' 133/8" Intermediate BTC Surface 3,548' K- 55/12.415 w /additives, Calculated 13 -3/8" TOC =2016' MD, (Incl. 1 °) @3s4a' 230bbIs @15.8ppg w/ 9 -5/8" Production 47# / L -80 Surface 9484' Butt / 8.68" additives, CBL TOC @ 6,800' 50bbls Lead @11ppg & 95/8" CBL TKC -BTC / 124bbIs Tail @15.8ppg w/ Toc= ,i 7" Liner 32 #/P -110 9,314' 11,472' 6.094" additives, CBL TOC @ 6800' A 10,270' 1 1 B _ Tubing - . c ,.. Long String/ 2 - 3' /z" Production 9.2 #, L -80 Surface 9,038' SBTC / 2.992" Internally coated 3 = i 4 tubing 6 3' /2' Production 9.2 #, L -80 Surface 9,029' SBTC/ 2.992" Short String - 7 . TOL " — 9 =' ' ' Dual String Jewel 9,314' Top Pert 9344' g ry 9518" 10 : L :tm Perf 9460' Detail 9484' -24 deg L 0 N G S T R I N G Depth (RKB) Length ID OD Item = Top Perf 9876' - 55.42' 2.99 Cooper Dual Hanger = 1 9038' 26.30' 2.687" Trico Kobe Pump Cavity 2 9,081' 3.54 2.56" S.Sleeve, HES RA SSD # 7" CBL — 121RA25623 TOC @ = S.Sleeve, HES RA SSD # 10,270 = 3 9,116' 3.54' 2.56" _ 121RA25623 — 4 9,136' 8.75' 2.56" Baker FV6E TRSV 5 9,177' 11.47' 2.99" Locator Seal ASSY w/10.45' of =_- seals 6 9,177' 6.79' 5.00" HES VST Retrievable Pkr. Sr# 12VST96350 -2 7 9,184' 7.40' 5.00" Seal Bore extension — 8 9,191 .68' 2.99" XO 9 9,208' 1.44' 2.56" Model "R" Profile Nipple 10 9,215' .45' 3.45" WLEG = Btm Perf 11400' SHORTSTRING r' 72 55.42' 2.99" Cooper Dual Hanger 11,4' A 9,029' 1.08' 1.995" X0, 3' /z" x 2 3/8" TO = 11,484' TVD = 10,105' — PBTD = 11,419' — B 9,030' 10.05' 1.995' Tbg Pup jt MAX HOLE ANGLE = 83.09 @ 11,260' MO C 9,040' 26.30' Trico Kobe Pump Cavity - Chevron • • Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) DI -17 S MGS UNIT 17 ADL0018746 5073320458 QU1535 127.00 Jobs Primary Job Type Job Category Objective Actual Start Date Actual End Date Perforation - Post Production Well 6/14/2011 Services Primary Wellbore Affected Wellbore UWI Well Permit Number 01-17 507332045800 1940560 Daily Operations 6/14/2011 00:00 - 6/15/2011 00:00 Operations Summary Mob to Platform, Rig Up. Perform baseline injection test - pumped 25 bbls FIW at 0.2 to 0.5 bpm at +/- 1960 psi. Rig up and test E -line lubricator to 250 psi low / 3000 psi high. RIH with 2.30" Gauge Ring and Gamma Ray tool to 9675', POOH. 6/16/2011 00:00 - 6/16/2011 00:00 Operations Summary RIH w/ 23' of 2 -1/8" Perforation guns to 9,148', tie in. RIH to get on depth, gun stuck at 9,063'. Work tool string with no movement. Inject 23.1 bbls FIW at 1,900 psi, work tool string with no change. Pull out of weak point (TOF @ 9,073'), POOH, R/D E -line. R/U Slickline. 6/16/2011 00:00 - 6/17/2011 00:00 Operations Summary R/U Slickline, Pressure test lubricator to 250 psi low /3000 psi high. RIH with fishing tool string to 9,041' and engage fish, moved fish up 10', pulled off. POOH. RIH w/ 1.91" grapple, engage fish at 9030', work fish free and POOH. Recovery of fish, left 17 shots from bottom of gun. RIH w/ 2.50" GR to 9071', POOH. RIH w/ 2.33" GR to 9071', POOH w/ 1 shot. RIH w/ 2.30" GR to 9071', POOH w/ 1 shot. 6/17/2011 00:00 - 6/18/2011 00:00 Operations Summary R/U Slickline, Pressure test lubricator to 250 psi low /3000 psi high. RIH w/2.30" GR to 9073', no recovery. RIH w/2.50" three prong wire grab to 9082', no recovery. RIH w/2.50" super magnet to 9102', POOH w/ 1 -1/4 shots. RIH w /same to 9102', POOH w/1 -1/4 shots. RIH w /same to 9058', POOH w/1 -1/4 shots. RIH w/2.50" three prong wire grab to 9105', no recovery. R/D Slickline. 6/18/2011 00:00 - 6/19/2011 00:00 Operations Summary R/U Slickline, Pressure test lubricator to 250 psi low /3000 psi high . RIH w/ 2.50" super magnet to 9105', POOH w/3 shots. RIH w /same to 9103', POOH w/1 -3/4 shots. RIH w /same to 9105', POOH w /small piece of shot. RIH w/2.25" wire grab to 9105', work tool and broke through debris. RIH to 9415' - confirm tubing clear, POOH. R/D Slickline. Rig up and test E -line lubricator to 250 psi low /3000 psi high. RIH w/ 20' of 2" Powerjet Omega guns, 6 spf, 60 deg phase, to 9360', pull up to 8950' and tie in. RIH to 9380', pull up to 9340.7'. Perf interval 9344' - 9364'. Perform injection test - pumped 11 filtered Inlet water (FIW) at 0.25 bpm at +/- 1475 psi. RIH w/ 20' of 2" PowerjetOmega guns, 6 spf, 60 deg phase, tie in and perf interval 9364' - 9384'. Perform injection test - pumped FIW at 0.25 to 0.5 bpm at +/- 1880 psi. 6/19/2011 00:00 - 6/20/2011 00:00 Operations Summary Rig up and test E -line lubricator to 250 psi low /3000 psi high. RIH w /20' of 2" Perforation guns, 6 spf, 60 deg phase, and tie in log, and perf interval 9,397' - 9,417'. Perform injection test - pump FIW at 0.2 to 0.5 bpm at +/- 1940 psi. RIH w /20' of 2" Powerjet Omega guns, 6 spf, 60 deg phase, and tie in and perf interval 9440' - 9460'. R/D E -line. Perform injection test - pump FIW at 0.2 to 0.5 bpm at +/- 1880 psi. Rig up and test E -line lubricator to 250 psi low /3000 psi high. RIH w /Isolation sleeve w /open bottom to 9038'. Set sleeve across Kobe cavity. R/D E -line. R/U test pump, pressure annulus to 2000 psi - holding. Perform injection test - pumped FIW, 0.5 bpm © 1884 psi, 1.0 bpm @ 2555 psi, 1.5 bpm @ 2900 psi, 2.0 bpm @ 3180 psi, 2.5 bpm @ 3350 psi, 3.0 bpm @ 3600 psi, 3.5 bpm @ 3950 psi. Bleed pressure off annulus, secure well. 6/20/2011 00:00 - 6/21/2011 00:00 Operations Summary Bring 9 -5/8" pressure to 2000 psi. Pump 26.5 bbls, pressure reached 3600 psi, and started taking fluid. Continued to pump 43 bbls (70 bbls total over 30 minutes) at 3600 psi or less. 9 -5/8" pressure dropped to 1800 psi during pumping, increased back to 2000 psi after pumps shut down. Pressure on LS dropped to 500 psi after 60 minutes. R/D, Bleed off annulus, secure well. • • sun g if tatzmKn SEAN PARNELL, GOVERNOR �1 ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Timothy C. Brandenburg Drilling Manager Union Oil Company of California I G _ C)‘'.5-74 P.O. Box 196247 Anchorage, AK 99519 Re: Middle Ground Shoal Field, E, F, and G Pool, S MGS Unit 17 (Di -17) Sundry Number: 311 -190 Dear Mr. Brandenburg: ANN JUN 9 6 2011 Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, II Daniel T. Seamount, Jr. I � Chair DATED this ,b day of June, 2011. Encl. • I . b' � a,s...0 E D STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ' ' r 1 20i APPLICATION FOR SUNDRY APPROVALS (+ 20 AAC 25.280 Ai'' ,h ; � t Sa ts1;flissiOn 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change A ❑ Suspend ❑ Plug Perforations ❑ Perforate 0 Pull Tubing p Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: Union Oil Company of California 4. Current Well Class: 5. Permit to Drill Number: Development ❑ Exploratory ❑ 194 - 056 -"' 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic ❑ Service 6. API Number: 50- 733 - 20458 -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: S MGS Unit 17 (Di -17) - Spacing Exception Required? Yes ❑ No 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL0018746 (Dillon Platform) Middle Ground Shoal Field / E F and G Oil 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): 11,484' 1 10,105' / 11,419' 10,094' N/A N/A Casing Length Size MD 7 TVD Burst Collapse Structural 83' 32" 83' 82' Conductor Surface 1,133' 18 -5/8" 1,133' 1,132' 2,740psi 880psi Intermediate 3,548' 13 -3/8" 3,548' 3,547' 3,450psi 1,950psi Production 9,484' 9 -5/8" 9,484' 9,201' 6,870psi 4,760psi Liner 2,158' 7 11,472' 10,103' 12,460psi 10,780psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 9,876-9,900', 9,918' - 9,946', 9,545'- 9,564', 9,579' - 9,600', 3 - 1/2" (LS and SS) , 9.2# L - (LS and SS) 9,038' LS 9,956'- 10,045', 10,054'- 11,018', 9,607'- 9,671', 9,67710,036', / 9,029' SS 11,132'- 11,231', 11,260'- 11,297', 10,055'- 10,067', 10,071'- 10,076', 11,376- 11,400' 10,087'- 10,091' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): HES VST Retrievable Packer / N/A 9,177' MD ( 8,922' TVD) / N/A l 12. Attachments: Description Summary of Proposal El 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sket ❑ Exploratory ❑ Development ❑ Service E 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 5-J 11 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ 0 / GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mike Quick 263 -7900 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature iC. one 276 -7600 Date 5/31/2011 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31k-19, O Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: IC - t.{ 0 it r APPROVED BY Approved by: , , COMMISSIONER THE COMMISSION Date: ( 1 1 J UN a 6 201 - 10 -403 Revised 1/2010 R 1 1 A BDMS Submit in Duplicate Chevron • South eldle Ground Shoals Dillon Platform Well # Di -17 5/31/11 OBJECTIVES: • Perforate Tyonek F zone for fluid injection. Current BHP: 4297 s @ 9,545' TVD (Based on pressure survey ran 10 -3 -2008) VICIA MASP: i psi (Based on current stabilized shut in tubing pressure - well has been shut in since 2002) PROCEDURE SUMMARY: 1. Rig up E -line. Pressure test lubricator 250psi Io 000psi high. 2. Perforate the Tyonek F sand from 9,334' to 9,390' ( + / -). �` cc � �f u .. 3. Rig down E -line. ` 4. Perform injectivity test. it ,^ NV C) �`�` G * l�, Contingency #1 — Add additional Tyonek F sand perforations pending results of injectivity testing. 1. Rig up E -line. Pressure test lubricator 250psi low /3000psi high. 2. Perforate Tyonek F sand from 9,397' to 9,417' ( + / -). 3. Rig down E -line. 4. Perform injectivity test. Contingency #2 — Add additional Tyonek F sand perforations pending results of injectivity testing. 1. Rig up E -line. Pressure test lubricator 250psi low /3000psi high. 2. Perforate Tyonek F sand from 9,440' to 9,465' ( + / -). 3. Rig down E -line. 4. Perform injectivity test. hevro • Dillon Platform &lion Platform • Well Di -17 ii.........../ Di-17 Last Completed 6/15/94 RKB-71-1, 54.12' KB Casing and Tubing Detail Size Type Wt / Grade Top Btm CONN / ID Cement / TOC 32" Structural Surface 83' `' QTE60 / 294 lead & 129bbls tail 185 " 18 -5/8" Surface 97.7 # /X -57 Surface 1,133' w /additives, good cement 1133' 17.653" returns at surface J 13 3/8" 360bbIs Lead @12.9ppg & TOC =2016' 68 #, K -55, 74bbls Tail @15.8ppg 13 3/8" Intermediate BTC Surface 3,548' K- 55/12.415 w /additives, Calculated 13-3/8" §3,548' TOC =2016' MD, (Incl. 1 °) 230bbls @15.8ppg w/ 9 -5/8" Production 47# / L -80 Surface 9484' Butt / 8.68" additives, CBL TOC @ 6,800' 9 5/8" CBL 50bbls Lead @1 1 ppg & roc= TKC -BTC / 124bbIs Tail @15.8ppg w/ 6800' a 7 Liner 32 #/P -110 9,314 11,472' 6.094" additives, CBL TOC @ A 10,270' 1t fT i B � Tubing 2 !_� Long String/ 3 = 4 3'%" Production 9.2 #, L -80 Surface 9,038' SBTC / 2.992" Internally coated _� tubing i- 7 b 3' /2" Production 9.2 #, L -80 Surface 9,029' SBTC/ 2.992" Short String L g 9 :1 79:3T11- O a 10 4 Dual String Jewelry 9-5/8 "@ '2.. Detail 9484' - 24 deg Top Pert 9676' L 0 N G S T R I N G Depth (RKB) Length ID OD Item 55.42' 2.99 Cooper Dual Hanger 1 9038' 26.30' 2.687" Trico Kobe Pump Cavity 7° CBL — 2 9,081' 3.54 2.56" S.Sleeve, HES RA SSD # TOC @ . — 121RA25623 10,270' 3 9,116' 3.54' 2.56" S.Sleeve, HES RA SSD # = 121RA25623 4 9,136' 8.75' 2.56" Baker FV6E TRSV 5 9,177' 11.47' 2.99" Locator Seal ASSY w/10.45' of — seals 6 9,177' 6.79' 5.00" HES VST Retrievable Pkr. Sr# 12VST96350 -2 — 7 9,184' 7.40' 5.00" Seal Bore extension 8 9,191 .68' 2.99" XO 9 9,208' 1.44' 2.56" Model "R" Profile Nipple 10 9,215' .45' 3.45" WLEG - Btm Pert 11400' 7 ., @ SHORTSTRING 11,472' TD = 11,484' TVD = 10,105' 55.42' 2.99" Cooper Dual Hanger PBTD = 11,419' A 9,029' 1.08' 1.995" XO, 3'/2' x 2 3/8" MAX HOLE ANGLE = 83.09 @ 11,260' MD B 9,030' 10.05' 1.995' Tbg Pup jt C 9,040' 26.30' Trico Kobe Pump Cavity hevro Dillon Platform Dillon Platform NW Well Di -17 PROPOSED Di-17 Last Completed 6/15/94 RKB- TH:54.12' KB Casing and Tubing Detail r_______________, Size Type Wt /Grade Top Btm CONN / ID OTE60 / Cement / TOC 32" Structural Surface 83' 294 lead & 129bbIs tail 18 5/8" @ 18 -5/8" Surface 97.7# / X -57 Surface 1,133' 17.653" w /additives, good cement 1133' returns at surface Calcul ated 360bbIs Lead @12.9ppg & Calculated A TOC =2016' 13 3/8" Intermediate 68 #, K -55, Surface 3,548' K- 55/12.415 74bbls Tail @15.8ppg BTC w /additives, Calculated 13 -3/8" TOC =2016' MD, (Incl. 1 °) @ 3,548' 230bbIs @15.8ppg w/ 9 -5/8" Production 47# / L -80 Surface 9484' Butt / 8.68" additives, CBL TOC @ 6,800' 50bbls Lead @11ppg & 95/8" CBL TKC -BTC / 124bbIs Tail 15.8 w/ roc= 7" Liner 32 #/P -110 9,314' 11,472' ppg 6800' 6.094" additives, CBL TOC @ A 10,270' 1 rT Tubing C Long String/ 2 3' /2" Production 9.2 #, L -80 Surface 9,038' SBTC / 2.992" Internally coated a = 4 tubing — –=-`� s 3 Production 9.2 #, L -80 Surface 9,029' SBTC/ 2.992" Short String 7" TOL _ 9,314' ''' la 9 , Top Pelf 9334' Dual String Jewelry 9-5/8" L ta" @ 10 > h.. Detail 9484' - 24 deg Top Pert 9876' L 0 N G S T R I N G Depth (RKB) Length ID OD Item = 55.42' 2.99 Cooper Dual Hanger 1 9038' 26.30' 2.687" Trico Kobe Pump Cavity 2 9,081' 3.54 2.56" S.Sleeve, HES RA SSD # = 7° CBL 121RA25623 TOC @ 10,270' =.7. 3 9,116' 3.54' 2.56" S.Sleeve, HES RA SSD # 121RA25623 = 4 9,136' 8.75' 2.56" Baker FV6E TRSV 5 9,177' 11.47' 2.99" Locator Seal ASSY w/10.45' of — seals 6 9,177' 6.79' 5.00" HES VST Retrievable Pkr. Sr# 12VST96350 -2 7 9,184' 7.40' 5.00" Seal Bore extension 8 9,191 .68' 2.99" XO 9 9,208' 1.44' 2.56" Model "R" Profile Nipple = 10 9,215' .45' 3.45" WLEG Btm Pert 11400' SHORTSTRING 7" @ 55.42' 2.99" Cooper Dual Hanger 11,472 A 9,029' 1.08' 1.995" X0, 3'/z' x 2 3/8" TD = 11,484' TVD = 10,105' PBTD = 11,419' B 9,030' 10.05' 1.995' Tbg Pup jt MAX HOLE ANGLE = 83.09° f 11,260' MD C 9,040' 26.30' Trico Kobe Pump Cavity lGA STATE OF ALASKA v5 1 ALASKA. AND GAS CONSERVATION COMMISSIW REPORT OF SUNDRY WELL OPERATIONS 1. Abandon U Repair Well Lf Plug Perforations LJ Stimulate U Other U Well Status Change Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator Union Oil Company of Califomia 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 Exploratory ❑ 194 -056 -° 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic ❑ Service ❑ 6. API Number: 50- 733 - 20458 -00 " 0 0 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018746 (Dillon Platform) . S MGS Unit 17 (Di -17) ` 9. Field /Pool(s): _ Middle Ground Shoal Field / E F and G Oil Pool 10. Present Well Condition Summary: / Total Depth measured 11,484 feet Plugs measured N/A feet true vertical 10,105 feet Junk measured N/A feet Effective Depth measured 11,419 feet Packer measured 9,177 feet true vertical 10,094 feet ry � t � rue vertical 8,922 feet Casing Length Size M Y 1 i Burst Collapse Structural 83' 32" 83' / 82' Conductor Surface 1,133' 18 -5/8" 1,133' 1,132' 2,740psi 880psi Intermediate 3,548' 13 -3/8" 3,548' 3,547' 3,450psi 1,950psi Production 9,484' 9 -5/8" 9,484' 9,201' 6,870psi 4,760psi Liner 2,158' 7" 11,472' 10,103' 12,460psi 10,780psi / Perforation depth Measured depth 9,876- 9,900', 9,916- 9,946', 9,956- 10,045', 10,054'- 11,018', 11,132'- 11,231', 11,260'- 11,297', 11,376- 11,400' / True Vertical depth 9,545' - 9,564', 9,579'- 9,600', 9,607- 9,671', 9,67710,036', 10,056- 10,067', 10,071'- 10,076', 10,087'- 10,091' Tubing (size, grade, measured and true vertical depth) l 9,038' LS 8,796' LS 3 -1/2" 9.2# L -80 9,029' SS 8,788' SS Packers and SSSV (type, measured and true vertical depth) HES VTL Retrievable Packer /NA 9,177' MD (8,922' TVD) / N/A 11. Stimulation or cement squeeze summary: RECEIVED Intervals treated (measured): y t N/A Treatment descriptions including volumes used and final pressure: N/A Alsika Oil & t.e Coo. Gorni ssion 12. Representative Daily Average Production or Injection Data 1 :N1 -'fl('C Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: - - - - - Subsequent to operation: - - - - - 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory El Development ❑ Service El Stratigraphic ❑ Daily Report of Well Operations Y 15. Well Status after work: Oil ❑ Gas ❑ WDSPL ❑ GSTOR ❑ NI N.. 151 WAG ❑ GINJ ❑ SUSP❑ SPLUG ❑ 16. 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: 311 -062 Contact Mike Quick 263 -7900 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature Phone 276 -7600 Date 5/19/2011 Form 10-404 Revised 10/2010 Submit Original Only Chevron • • 11 10 Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) DI -17 S MGS UNIT 17 ADL0018746 5073320458 QU1535 127.00 Jobs Primary Job Type Job Category Objective Actual Start Date Actual End Date Plug - Permanent Abandon 4/20/2011 4/24/2011 Primary Wellbore Affected Wellbore UWI Well Permit Number 01-17 507332045800 1940560 Daily Operations • 4/20/2011 00:00 - 4/21 /2011 00:00 Operations Summary Email to Jim Regg, AOGCC, 4/20 advising of upcoming MIT for Di -17. Mobilize to Dillon Platform. RU on Di -17, pressure test lubricator to 250 psi low, 3000 psi high. Assemble test pump plumbing. Shut down for night. 4/21/2011 00:00 - 4/22/2011 00:00 Operations Summary Phone call to Jim Regg, AOGCC, 4/21 (out of office). Called AOGCC North Slope pager and left message of upcoming MIT's, email sent to AOGCC inspectors. Di -17: Re -test lubricator to 250 psi low, 3000 psi high. RIH w/ 2.83" OD gauge ring to 9050', POOH. RIH w/ 2.5" GS w/ 2.84" OD isolation sleeve with solid bottom and set in Kobe cavity at 9029.5', POOH. RD. Bleed gas cap on Di -17. RU on Di -17 and Pump FIW down 9 -5/8" casing x tubing annulus, pressure up to 2300 psi. Shut down for night. 4/22/2011 00:00 - 4/23/2011 00:00 Operations Summary / Jeff Jones with AOGCC waived witness of MIT at 0850 4/22, per Jim Regg. Cont. to bleed gas cap from Di -17. RU on Di -17 and Pump FIW down 9 -5/8" casing x tubing annulus, pressure up to 2345 psi, chart test for 40 minutes, no pressure drop. RU on Di -17, bleed 9 -5/8" pressure to 1550 psi, pressure 3 -1/2" Long String tubing to 2600 psi, chart test for 45 minutes, pressure at 2530 psi in 30 minutes. RU on Di -17, Pressure test lubricator to 250 psi low, 3 psi high, RIH w/ 1" OD prong to 9074', work tools to knock out plugs, pressure dropped from 2500 psi to 1500 psi, POOH. Shut down for night. 4/23/2011 00:00 - 4/24/2011 00:00 Operations Summary RU on Di -17 and pump FIW for 120 minutes at 3 gpm and 1450 psi to establish stabilized injection, pumped a total of +/- 8.5 bbls. RU on Di -17, Pressure test lubricator to 250 psi low, 3000 psi high, RIH w/ 2.5" GS to 9052', latch isolation sleeve, POOH. Secure well and depart platform. . hevro Dillon Platform *Mon Platform • Well Di -17 "..........--/ Di -17 Last Completed 6/15/94 aK6TH:54.12'KB Casing and Tubing Detail j 1 Size Type Wt /Grade Top Btm CONN / ID QTE60 / Cement / TOC 32" Structural Surface 83' 294 lead & 129bbls tail 18518"@ 18 -5/8" Surface 97 # /X -57 Surface 1,133' w /additives, good cement " returns at surface 13 3/8" Calculated 360bbls Lead @12.9ppg & TOC =2016' 68 #, K -55, 74bbls Tail @15.8ppg 13 3/8" Intermediate BTC Surface 3,548' K- 55/12.415 w /additives, Calculated 13 -3/8" @3548' TOC =2016' MD, (Incl. 1 °) 230bbls @15.8ppg w/ 9 -5/8" Production 47# / L -80 Surface 9484' Butt / 8.68" additives, CBL TOC @ 6,800' 9 5/8" CBL 50bbls Lead @11 ppg & ToC= TKC -BTC / 124bbls Tail @15.8ppg w/ 6800' 7" Liner 32 #/P -110 9,314' 11,472' 6.094" additives, CBL TOC @ A 1 TT B 10,270' — Tubing 2 -- - Long String/ s -i a 3 Production 9.2 #, L -80 Surface 9,038' SBTC / 2.992" Internally coated . _� . 6 tubing _ 7 3' 'A" Production 9.2 #, L -80 Surface 9,029' SBTC/ 2.992" Short String —a' 9 :4;. 9,314'1- ' MI ": Dual String Jewelry 9-5/8" @ L 10 9484' - 24 deg Detail Top PeA9816' L 0 N G S T R I N G Depth (RKB) Length ID OD Item 55.42' 2.99 Cooper Dual Hanger 1 9038' 26.30' 2.687" Trico Kobe Pump Cavity 7 "CBL 2 9,081 3.54 2.56 S.Sleeve, HES RA SSD # TOC -- 121 RA25623 10,270' t — 3 9,116 3.54' 2.56" S.Sleeve, HES RA SSD # — 121 RA25623 = 4 9,136' 8.75' 2.56" Baker FV6E TRSV 5 9,177' 11.47' 2.99" Locator Seal ASSY w/10.45' of — seals 6 9,177' 6.79' 5.00" HES VST Retrievable Pkr. Sr# 1 12VST96350 -2 — 7 9,184' 7.40' 5.00" Seal Bore extension = 8 9,191 .68' 2.99" X0 = 9 9,208' 1.44' 2.56" Model "R" Profile Nipple 10 9,215' .45' 3.45" WLEG - Btm Pert 11400' 7„@ SHORTSTRING 11,472' ,(,,, TO = 11,484' TVD = 10,105' 55.42' 2.99" Cooper Dual Hanger PBTD = 11,419' A 9,029' 1.08' 1.995" X0, 3 1 /2' x 2 3/8" MAX HOLE ANGLE = 83.09 @ 11,260' MD B 9,030' 10.05' 1.995' Tbg Pup jt C 9,040' 26.30' Trico Kobe Pump Cavity • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.reao alaska.gov; doa .aoocc.crudhoe.bay(8alaska.gov: phoebe.brooksl8alaska.aov: tom.maunder(@alaska.gov OPERATOR: Union Oil Company of California FIELD / UNIT / PAD: Middle Ground Shoal Field / E F and G oil pool DATE: 04/22/11 OPERATOR REP: Shane R Hauck AOGCC REP: Packer Depth Pretest Initial _ 15 Min. 30 Min. 45 Min. 60 Min. Well Di -17 Type Inj. I TVD 8,922' Tubing 1,090 1,008 1,008 1,008 Interval 0 P.T.D. 1940560 Type test P Test psi 2230.5 Casing 780 2,345 2,345 2,345 P/F P Notes: AIO 8.005 authorizes injection; MITIA OA 38 55 55 55 Prepare Di -17 well for disposal of fluids from decommissioning operations on platform; longstring tubing Well Di -16 Type Inj. I TVD 9,292' Tubing 1,240 Interval P.T.D. 1940570 Type test P Test psi 2323 Casing 525 P/F F Notes: AIO 8.005 authorizes injection OA 10 ,,=---- Unable to get Pre- test on 9 -5/8" X tbg (did not attempt MIT test); longstring tubing Well Di -17 Type Inj. I TVD 8,922' Tubing 990 2,600 2,550 2,530 Interval O P.T.D. 1940560 Type test P Test psi 2230.5 Casing 1,550 1,550 1,550 1,550 P /F_ P Notes: AIO 8.005 authorizes injection; MITT OA 38 38 38 38 _ longstring tubing Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. _ Type test Test psi_ Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey T = Test during Workover W = Water D = Differential Temperature Test 0 = Other (describe in notes) I Form 10 -426 (Revised 06/2010) MIT MGS 1617 04 22 11.xis • • Page 1 of 3 Regg, James B (DOA) From: Brooks, Phoebe L (DOA) AkZ(III 05 Sent: Tuesday, April 26, 2011 2:07 PM To: Quick, Mike [ASRC] 1 t 1 40 57 0 Cc: Regg, James B (DOA); Maunder, Thomas E (DOA) ° . Subject: RE: Dillon platform MIT of Di -16 & di -17 Attachments: MIT MGS 16,17 04- 22- 11.xls Mike, Attached is a revised MIT report for MGS 16,17 04- 22 -11. The AOGCC Rep field is now blank (an inspector's name is entered only when witnessed); LS was removed from the Pretest tubing data as these fields are numeric (long string was added to the notes); "0" was entered in the interval field for 16; the A10 # was included in each note field. Please let me know if you have any questions or disagree. Thank you, Phoebe Phoebe Brooks Statistical Technician 11 Alaska Oil and Gas Conservation Commission A R Ct'h Phone: 907- 793 -1242 Fax: 907- 276 -7542 From: Quick, Mike [ASRC] [mailto:MQuick @chevron.com] Sent: Tuesday, April 26, 2011 11:07 AM To: Quick, Mike [ASRC]; Regg, James B (DOA); Maunder, Thomas E (DOA); Hauck, Shane R; DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Hammons Jr, Darrell James; Neighbors, Joel [Swift Technical Services]; Kanyer, Christopher V; Bonnett, Nigel ( Nigel.Bonnett) Subject: RE: Dillon platform MIT of Di -16 & di -17 Correction: The chart we used was a 24 hour chart (1 day), not a 7 day chart as stated below. We could not locate any 3 hour charts for our recorder in time for this pressure test. Apologies for the typo. Mike From: Quick, Mike [ASRC] Sent: Tuesday, April 26, 2011 10 :49 AM To: 'Regg, James B (DOA)'; Maunder, Thomas E (DOA); Hauck, Shane R; DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Hammons Jr, Darrell James; Neighbors, Joel [Swift Technical Services]; Kanyer, Christopher V; Bonnett, Nigel (Nigel.Bonnett) Subject: RE: Dillon platform MIT of Di -16 & di -17 Please find the attached updated MIT Report form including the test data from the long string on Di -17 (PTD 194 -056). This test was recorded on a 7 day chart for +1-45 minutes of chart time, causing the line to appear to have not stabilized, but according to Mr. Hauck, 70 psi total was lost in 30 minutes, and the pressure had stabilized at the end of the test. Note additionally that the tubing pressure was constant throughout the 9- 4/26/2011 • Page 2 of 3 5/8" casing /packer test at 1,008 psi for 30 minutes. Also, the tubing still contains compressible reservoir fluids, as we are not equipped to circulate the well to water at this time. Please let me know if we can provide any additional information. Regards, Mike Mike Quick Project Manager / Drilling Engineer MidContinent /Alaska SBU Chevron North America Exploration and Production 3800 Centerpoint Drive, Suite 100 Anchorage, Alaska 99503 Direct 907 - 263 -7900 Fax 1- 866 - 480 -5398 mquick a,chevron.com From: Regg, James B (DOA) [mailto:jim.regg @alaska.gov] Sent: Monday, April 25, 2011 4:39 PM To: Quick, Mike [ASRC]; Maunder, Thomas E (DOA); Hauck, Shane R; DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Hammons Jr, Darrell James; Neighbors, Joel [Swift Technical Services]; Kanyer, Christopher V; Bonnett, Nigel (Nigel.Bonnett) Subject: RE: Dillon platform MIT of Di -16 & di -17 Di -17 (PTD 1940560) original message includes test charts of MITs on 9 -5/8 by tubing (MITIA) and on Tubing longstring (MITT) MITIA test clearly is a pass but MITT is questionable - do not see from chart recording where pressure drop stabilized Also, both tests need to be reported on the MIT Report Form Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907 - 793 -1236 From: Quick, Mike [ASRC] [mailto:MQuick @chevron.com] Sent: Monday, April 25, 2011 12:46 PM To: Maunder, Thomas E (DOA); Hauck, Shane R; Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Hammons Jr, Darrell James; Neighbors, Joel [Swift Technical Services]; Kanyer, Christopher V; Bonnett, Nigel (Nigel.Bonnett) Subject: RE: Dillon platform MIT of Di -16 & di -17 Mr. Maunder — Both wells had a small gas cap on them, so Shane bled gas on each well. We pumped filtered inlet water for the pressure tests. On Di -16, after running an isolation sleeve in the Kobe cavity with a solid bottom, and bleeding the 9 -5/8" casing pressure 4/26/2011 • Page 3 of 3 down to zero, we pumped approximately 5 bbls of FIW in 54 minutes, pressuring the 9- 5 casing by tubing annulus to 2300 psi. The pressure bled off 125 psi in 7 minutes. A second pressure test was attempted 1.5 hours later, pumping an additional +/- 5 bbls of FIW and pressuring the 9 -5/8" casing by tubing annulus to 2300 psi. The pressure bled off 150 psi in 10 minutes. A third pressure test was attempted 1.25 hours later, pumping an additional +/- 5 bbls of FIW and pressuring the 9 -5/8" casing by tubing annulus to 2300 psi. The pressure bled off 150 psi in 10 minutes. Shut down for night. A fourth pressure test was attempted the next day, pumping an additional +/- 4 bbls of FIW and pressuring the 9 -5/8" casing by tubing annulus to 2400 psi. The pressure bled off 150 psi in 10 minutes to 2250. Both the sliding sleeves on Di -16 had been open for some length of time prior to being closed this week, and it is possible that they are leaking, as they are located below the Kobe cavity and above the 9 -5/8" packer. In all tests, the tubing pressures increased slightly due to compression (LS +/- 900 to 1000 psi, SS +1- 350 to 400 psi), but are not in communication with the annulus above the Kobe cavity isolation sleeve. Please let me know if you have any further questions. Regards, Mike From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Monday, April 25, 2011 7:09 AM To: Hauck, Shane R; Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Quick, Mike [ASRC]; Hammons Jr, Darrell James; Neighbors, Joel [Swift Technical Services] Subject: RE: Dillon platform MIT of Di -16 & di -17 Hi Shane, On Di -16, how would you describe the pumping operation you attempted? How much and what did you pump and was there any pressure response on the well? Thanks in advance, Tom Maunder, PE AOGCC From: Hauck, Shane R [mailto:haucks @chevron.com] Sent: Sunday, April 24, 2011 9:39 PM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA); Maunder, Thomas E (DOA) Cc: Quick, Mike [ASRC]; Hammons Jr, Darrell James; Neighbors, Joel [Swift Technical Services] Subject: Dillon platform MIT of Di -16 & di -17 Jim Here is our M.I.T paper work Di -17 was good But Di -16 failed Thanks Shane R Hauck Drill Site Manager MidcontinentlAlaska SBU Chevron North America Exploration and Production Office 907 - 263 -7613 Fax 1- 866 - 914 -1485 Cell 907- 250 -2713 Rig 907 - 776 -6639 haucks @chevron.com 4/26/2011 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.reacaalaska.gov; doa .aogcc.prudhoe.bavaalaska.aov; phoebe.brooks(cDalaska.aov; tom.maunder(aalaska.aov OPERATOR: Union Oil Company of California FIELD / UNIT / PAD: Middle Ground Shoal Field / E F and G oil pool DATE: 04/22/11 OPERATOR REP: Shane R Hauck AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well Di -17 ' Type Inj. 1 TVD 8,922' Tubing 1,090 1,008 1,008 1,008 Interval 0 P.T.D. 1940560 Type test P Test psi 2230.5 Casing 780 2,345 2,345 2,345 ' P/F P Notes: AIO 8.005 authorizes injection; MITIA OA 38 55 55 55 Prepare Di -17 well for disposal of fluids from decommissioning operations on platform; longstring tubing Well Di -16 , Type Inj. I TVD - 9,292' Tubing 1,240 Interval 0 P.T.D. 1940570 Type test P Test psi ' 2323 Casing 525 P/F F Notes: AIO 8.005 authorizes injection OA 10 Unable to get Pre- test on 9 -5/8" X tbg (did not attempt MIT test); longstring tubing Well Di -17 - Type lnj. I TVD 8,922' Tubing 990 2,600 2,550 2,530 Interval 0 P.T.D. 1940560 Type test P Test psi 2230.5 Casing 1,550 1,550 1,550 1,550 P/F P ' Notes: AIO 8.005 authorizes injection; MITT 0A_38 38 38 38 longstring tubing Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type lnj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey T = Test during Workover W = Water D = Differential Temperature Test 0 = Other (describe in notes) Form 10-426 (Revised 06/2010) MIT MGS 1617 04 22 11.xis • • MIT — S. Middle Ground Shoal Unit 17 Dillon Platform PTD 1940560 4/22/2011 rIPP ' ' ' ' MITIA DI - .1'1 rirr itcir. r st/se. 1, p et- <:- $+4,r 34) 0 ,1A) c -... 1 E..' 4,, r $: ,‘,.. r 1 111 " W ' '11111,11W,- i5. , 1.:110•+ 7); -,7 * fr T MITT N-c 141.- r , 5 i r ' .' , PC - - -------'--,-, ,sZ) ...1 4 „ Ps' 0 k a 4.” ---, --, , ...,_ _ ..... Y • • I SMITE OF AELASEA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Timothy C. Brandenburg � Drilling Manager \ ",..,,______________L\, (� Union Oil Company of California P.O. Box 196247 Anchorage, AK 99519 Re: Middle Ground Shoal Field, E, F and G Oil Pool, S MGS Unit 17 (Di -17) Sundry Number: 311 -062 Dear Mr. Brandenburg: w mi s iED APR 1 4 21111 Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. ely I A • .n o mi : oner DATED this 1.3 day of April 2011. Encl. • • Chevron Timothy C Brandenburg Union Oil Company of California Drilling Manager P.O. Box 196427 Anchorage, , AK AK 99519 -6247 Tel 907 263 7657 Fax 907 263 7884 Email brandenburgt @chevron.com March 1, 2011 Commissioner RECEIVEL .` Alaska Oil & Gas Conservation Commission 333 W. 7 Avenue SAAR ) '� a � I Anchorage, Alaska 99501 Alaska Oil & Gag C.o Commi 4ion Re: Well Status Change Request PTD 194- 056 4 ; f, Q , Dear Commissioner, Union Oil Company of California would like to request a change of status for a well on the Dillon Platform, S MGS Unit 17 (Di -17) PTD 194 -056 from '1 -OIL' to 'WINJ'. Please see the attached 10 -403 Application for Sundry Approvals, and the attachments containing information per 20 AAC 25.402. Please let us know if we can provide any further information by contacting myself at 263 -7657 or Mike Quick at 263 -7900. Sincerely, i■" . /•► AM Timothy C. Brandenburg , Drilling Manager Attachments: Form 10 -403 in duplicate, Dillon Injection Well Status and Plan Forward, Dillon Spider Plot, and Well Schematic. Union Oil Company of California / A Chevron Company V-I • . Ak, 04/131wtt STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS k3 he 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Well Status Change El . 2. Operator Name: Union Oil Company of California 4. Current Well Class: 5. Permit to Drill Number: Development Ell Exploratory ❑ 194 -056 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic ❑ Service ❑ 6. API Number: 50 -733- 20458 -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: S MGS Unit 17 (Di -17) Spacing Exception Required? Yes ❑ No Q 9. Property Designation (Lease Number): 10. Field /Pool(s): ADL0018746 (Dillon Platform) Middle Ground Shoal Field / E F and G Oil 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): 11,484' , 10,105' • 11,419' 10,094' N/A N/A Casing Length Size MD / TVD Burst Collapse Structural 83' 32" 83' 82' Conductor Surface 1,133' 18 -5/8" 1,133' 1,132' 2,740psi 880psi Intermediate 3,548' 13 -3/8" 3,548' 3,547' 3,450psi 1,950psi Production 9,484' 9 -5/8" 9,484' 9,201' 6,870psi 4,760psi Liner 2,158' 7 11,472' 10,103' 12,460psi 10,780psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 9 ,876'- 9,900', 9,915- 9,946', 9,545- 9,564', 9,579' - 9,600', 3 - 1/2" (LS and SS) 9.2# L - (LS and SS) 9,038' LS 9,955- 10,045', 10,054'- 11,018', 9,607' - 9,671', 9,677'10,036', 9,030' SS 11,132'- 11,231', 11,260'- 11,297', 10,055- 10,067', 10,071'- 10,076', 1 11,376 10,08T-10,091' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): HES VST Retrievable Packer / N/A 9,177' MD ( 8,922' TVD) / N/A 12. Attachments: Description Summary of Proposal III 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ❑ Service 0 14. Estimated Date for 15. Well Status after proposed work: 21- Mar -11 Commencing Operations: Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ 0 , GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mike Quick 263 -7900 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature C. Phone 276-7600 Date 3/1/2011 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 ( 1.-0(0 a Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test S Location Clearance ❑ RECEIVE,L Other: vercstkkvz,r..c.7 `tc...clCLC.0 v3.._.c(:),©S 1.--- el 40.3 A !' ?:j? Subsequent Form Required: i, 0 i iy s ka Oil � Has Con& Conunissi APPROVED BY i r Approved by: ,JOMMISSIONER THE COMMISSION Date: 4-13-(f ! MS APR 4 , Form 10 -403 Revised 1/2010 ,,, '3- '3'. it 1 i V • 1�b Submit in Duplicate . hevro Dillon Platform glillon Platform Well Di -17 �.....-0" Di-17 Last Completed 6/15/94 Casing and Tubing Detail RKB -TH: 54.12' KB - t Size Type Wt /Grade Top Btm CONN / ID OTE60 / Cement / TOC 32" Structural Surface 83' 294 lead & 129bbis tail 185/8 "@ 18-5/8" Surface 97 # /X -57 Surface 1 w /additives, good cement Ale j 1133' 17.653" returns at surface 13 3/8" Calculated 360bbls Lead @12.9ppg & TOC =2016' 68 #, K -55, 74bbls Tail @15.8ppg 13 3/8" Intermediate BTC Surface 3,548' K- 55/12.415 w /additives, Calculated 13-3/8" @3,548' TOC =2016' MD, (Incl. 1 °) 230bb1s @15.8ppg w/ 9 -5/8" Production 47# / L -80 Surface 9484' Butt / 8.68" additives, CBL TOC @ 6,800' 95/8 "CBL 50bbls Lead @11ppg & roc= TKC -BTC / 124bbls Tail @15.8ppg w/ 6800' 7" Liner 32 #/P -110 9,314' 11,472' 6.094" additives, CBL TOC @ A Fr B - 10,270' 1. __: c Tubing 2 - =_ Long String/ 3 = 4 3' /2" Production 9.2 #, L -80 Surface 9,038' SBTC / 2.992" Internally coated — tubing 7 a 3' /2' Production _ 9.2 #, L -80 Surface 9,029' SBTC/ 2.992" Short String g w. 9 • •• . 'i 7" TOL 10 9' 314' Dual String Jewelry ■ 9-5/8" @ L ` Detail 9484' - 24 deg Top Perf 9876' L 0 N G S T R I N G Depth (RKB) Length ID OD Item 55.42' 2.99 Cooper Dual Hanger 1 9038' 26.30' 2.687" Trico Kobe Pump Cavity 7" CBL = 2 9,081' 3.54 2.56" S.Sleeve, HES RA SSD # TOC @ = 121RA25623 10,270' — 3 9,116' 3.54' 2.56" S.Sleeve, HES RA SSD # — 121RA25623 = 4 9,136' 8.75' 2.56" Baker FV6E TRSV 5 9,177' 11.47' 2.99" Locator Seal ASSY w/10.45' of — seals 6 9,177' 6.79' 5.00" HES VST Retrievable Pkr. Sr# 12VST96350 -2 = 7 9,184' 7.40' 5.00" Seal Bore extension 8 9,191 .68' 2.99" X0 = 9 9,208' 1.44' 2.56" Model "R" Profile Nipple — 10 9,215' .45' 3.45" WLEG Btm Perf 11400' 7 "@ SHORTSTRING 11,472' t, ' , TD = 11,aaa' TVD = 1o,1os' 55.42' 2.99" Cooper Dual Hanger PBTD = 11,419' A 9,029' 1.08' 1.995" X0, 3' /2' x 2 3/8" MAX HOLE ANGLE = 83.09 / 11,260' MD B 9,030' 10.05' 1.995' Tbg Pup jt C 9,040' 26.30' Trico Kobe Pump Cavity • February 28, 2011 Union Oil Company of California South Middle Ground Shoal - Dillon Platform, Cook Inlet, Alaska Dillon Injection Well Status and Plan Forward Current Status The currently approved EOR (enhanced recovery) wells, Di -12 (PTD 168 -056) and Di -14 (PTD 175 -066), authorized for waste injection on the Dillon Platform are in questionable service state per the October 2009 work on the platform. Mechanical Integrity Tests (MIT) and injectivity tests were conducted on these wells in 2009 with mixed results. Di -12 would not take injection of any fluids. Di -14 did not pass a standard pressure Mechanical Integrity Test (MIT); however, a temperature survey provided data / showing that the disposal fluid was confined to authorized zones. Di -14 was utilized to inject 1613 bbls at injection rates between 0.5 and 0.7 bpm, but was pressure limited to 2000 psi of 9 -5/8" casing pressure due to the connectivity of the tubing and casing. These two wells, Di -12 and Di -14, are EOR (enhanced recovery) wells that are authorized under AIO 8.0 and Administrative Approval AIO 8.2, issued January 29, 2003, to dispose of up to 50,000 barrels of non- hazardous Class II liquid wastes. By UOCC records, a total of 6,347 barrels of waste liquid have been injected into Di -12, and a total of 1,613 barrels of waste liquid have been injected into Di -14, for a total of 7,960 barrels out of the authorized 50,000 barrels, leaving 42,040 barrels of authorized disposal volume remaining per AIO 8.2. Plan Forward In preparation for well abandonment activities on the Dillon Platform, the 15 wells (there are 17 wells on the Dillon, less the two injection wells) will need to be circulated with kill weight fluid. With no active pipelines from the platform, all waste fluids associated with the well circulation (and ultimately the well abandonment activities) will need to be disposed of in authorized wells. Due to the lack of operational production facilities, temporary well flowback /separation equipment is required to safely circulate these wells with kill weight fluid. The well circulation activities are scheduled for June of 2011, in advance of planned abandonment activities, which will also utilize the injection wells. After review of well files and other data, two injection well candidates were selected: Di -17 (PTD 194- 056) and Di -16 (PTD 194 -057). Both wells are oil producers that were shut -in December 2002 when the platform production was halted. These two wells will need to be converted to water injector EOR well classifications per 20 AAC 25.402, and either pass a MIT pressure test per AOGCC regulations, or if the pressure test does not pass, prove injection is confined to authorized zones with temperature survey data both per 20 AAC 25.412. Both wells were being produced in 2002 by pumping power fluid down the long string at a surface pressure of 2700 psi, and due to high KOBE pump efficiencies, the wells were known to be mechanically sound at that time. Additionally, upon receipt of approved 10 -403 for the status change to EOR well, and upon a successful MIT, a separate 10 -403 may be submitted requesting to perforate approximately 136 feet of F zone in Di -17 below the tubing tail, which has the potential to greatly improve injection capability over the traditional G zone injection rates of 0.5 to 1.0 bpm. The F • • sand has porosity between 22% and 24% with permeability greater than 1000 md, where the G zone typically has porosity less than 15% and permeability less than 50 md. In Accordance with 20 AAC 25.402 Per 20 AAC 25.402 (c), the following is included in this submittal: 1. A spider plat showing the wells on the Dillon Platform is attached. 2. Union Oil Company of California is the only operator within 'A mile of the proposed injection wells. There are no surface owners. 3. Not applicable. 4. Upon receipt of approved status changing to water injector (EOR) well status with an approved 10 -403 form, and after receipt an approved request for administrative approval (the administrative approval will be submitted under separate cover) for authorization to dispose of non - hazardous Class 11 fluids into these two wells (Di -17 and Di -16) under AIO 8.0, 8.2, and 8.3, the wells would be tested for mechanical integrity per 20 AAC 25.412. Upon successful MIT results, the wells would be used for disposal of liquid wastes associated with the well circulation and abandonment activities. Per AIO 8.0, 8.2 and 8.3, this liquid will primarily consist of filtered and unfiltered inlet water, kill weight brine or mud, produced water, produced oil, cementing waste fluids (cement pushes, surfactants, rinsate), water with some detergents used to clean equipment, and deck drainage due to rainfall on the platform. UOCC will not dispose of solids (no grind and inject operation) or domestic sanitary waste into these wells. 5. Currently the perforated zones are limited to the "G" unit of the Hemlock formation from 9876' MD to 11400' MD in Di -17, and 10,150' MD to 10,718' MD in Di -16. 6. Di -17: G1, G2, and G3 zones in the Hemlock formation are perforated from 9876' MD to 11400' MD. The vertical net perforated interval is 484' thick, as the wellbore is at high angle across the zones (37 degrees building to 80 degrees). Porosity ranges from 16 to 20 %, permeability ranges from 20 and to 56 md. Di -16: G1, G2, and G3 zones in the Hemlock formation are perforated from 10,150' MD to 10,718' MD. The vertical net perforated interval is 318' thick, as the wellbore is at high angle across the zones (44 degrees building to 81 degrees). Porosity ranges from 15 to 22 %, permeability ranges from 12 and to 58 md. The zones in the Tyonek intervals above the Hemlock, commonly notated as the Tyonek A through F zones, have proven to be confining zones from hydrocarbon mobility; they will also confine the injection fluids to the Hemlock. 7. All logs previously on file with the AOGCC. 8. Mechanical integrity of each well will be demonstrated with a pressure test under 20 AAC 25.412. Di -17: Install standing valve in long string tubing and perform bundle test to 2231 psi (packer depth of 9177' MD / 8922' TVD) to verify integrity of packer and 9 -5/8" casing. Install dummy pump in Kobe cavity and perform a Standard MIT on the tubing long string to 2231 psi to verify integrity of tubing long string (pressure will be kept on 9 -5/8" casing and • will be monitored during test, tubing short string will be isolated with the dummy pump and will be monitored during test). Di -16: Install standing valve in long string tubing and perform bundle test to 2323 psi (packer depth of 9925' MD / 9292' ND) to verify integrity of packer and 9 -5/8" casing. Install dummy pump in Kobe cavity and perform a Standard MIT on the tubing long string to 2323 psi to verify integrity of tubing long string (pressure will be kept on 9 -5/8" casing and will be monitored during test, tubing short string will be isolated with the dummy pump and will be monitored during test). 8. (A) MGS ST 1874617 — (Di -17) PTD # 194 -056 Di -17 was drilled and completed with a dual 3 -1/2" string KOBE cavity pump, with a 9- 5/8" production packer set at 9177' MD / 8921' ND in 1994, and passed a MIT test to 2650 psi in December 2002, after a dummy pump isolated the short string which has a known tubing leak. The 18 -5/8" 98 # /ft, X -57 surface casing was cemented at 1133' with 305 bbls of 13.0 ppg lead class G cement and 129 bbls of 15.8 ppg tail class G cement. Had cement to surface, with 20 bbls of good cement returns. Casing was pressure tested to 2000 psi. 18 -5/8" shoe was tested with a leak off test to a 16.5 ppg EMW. The 13 -3/8" 68 # /ft, K -55 intermediate casing was cemented at 3548' with 360 bbls of 12.9 ppg lead class G cement and 74 bbls of 15.8 ppg Class G tail cement. No CBL was ran, and calculated top of cement is 2016' (with a 10% washout factor and assuming the 200 bbls of mud lost during the cement job were cement losses). Casing was pressure tested to 2800 psi. 13 -3/8" shoe was tested with a leak off test to a 14.0 ppg EMW. The 9 5/8" 47 # /ft, L -80 production casing was cemented at 9484' with 230 bbls of 15.8 ppg Class G cement. Good circulation was observed throughout the job. Casing was pressure tested to 5000 psi. The 9 5/8" shoe was FIT tested to a 16.5 ppg EMW with no leak -off. The CBL ran on 6/5/94 indicated the top of cement at approximately 6800', with good cement below that depth. The 7" 32 # /ft, P -110 liner was cemented at 11,472' (top at 9314') with 50 bbls of 11 ppg lead class G cement and 124 bbls of 15.5 ppg Class G tail cement. Full returns were observed throughout the job. Liner was pressure tested to 3500 psi. The CBL ran on 6/5/94 indicated the top of cement at approximately 10,270', with good cement below that depth. The 3 -1/2" 9.2 # /ft, L -80 dual tubing string completion in the well was run on 6/14/94. The well was producing in 2002 with a KOBE pump, and the power fluid was pumped down the long string with a surface pressure of 2700 psi. Due to the high pump efficiency, the long string was known to be mechanically sound when shut -in December 2002 (as long as the annulus was full to compensate for the leak on the short string side). This will also be confirmed with the proposed MIT test. • • MGS ST 1874616 — (Di -16) PTD # 194 -057 Di -16 was drilled and completed with a dual 3 -1/2" string KOBE cavity pump, with a 9- 5/8" production packer set at 9925' MD / 9292' TVD in 1994. This well would be the "back up" well to Di -17. A back up well is deemed necessary to support operations on the platform. The 18 -5/8" 98 # /ft, X -57 surface casing was cemented at 1132' with 40 bbls of 10.5 ppg pre -flush cement, followed by 294 bbls of 13.2 ppg lead class G cement and 129 bbls of 15.8 ppg tail class G cement. Had 13.0 ppg cement returns to surface. Casing was pressure tested to 2000 psi. 18 -5/8" shoe was tested with a leak off test to an 18.1 ppg EMW. The 13 -3/8" 68 # /ft, K -55 intermediate casing was cemented at 3640' with 373 bbls of 12.9 ppg lead class G cement and 74 bbls of 15.9 ppg Class G tail cement. No CBL was ran, and calculated top of cement is 762' (with a 10 %o washout factor). Casing was pressure tested to 2700 psi. 13 -3/8" shoe was tested with a leak off test to a 15.0 ppg EMW. The 9 5/8" 47 # /ft, L -80 production casing was cemented at 10,155' with 163 bbls of 15.8 ppg Class G cement. Good circulation was observed throughout the job. Casing was pressure tested to 4800 psi. The 9 5/8" shoe was FIT tested to a 14.2 ppg EMW with no leak -off. The CBL ran on 7/17/94 indicated the top of cement at approximately 8300', with good cement below that depth. The 7" 32 # /ft, L -80 liner was cemented at 11,703' (top at 9987') with 140 bbls of 15.8 ppg Class G cement. Full returns were observed throughout the job. Liner was pressure tested to 3300 psi. The CBL ran on 7/17/94 indicated the top of cement at approximately 10,150', with good cement below that depth. The 3 -1/2" 9.2 # /ft, L -80 dual tubing string completion currently in the well was run on 7/20/94. The well was producing in 2002 with a KOBE pump, and the power fluid was pumped down the long string with a surface pressure of 2700 psi. Due to the high pump efficiency, the long string was known to be mechanically sound when shut -in December 2002. This will also be confirmed with the proposed MIT test. 9. Per AIO 8.0, 8.2 and 8.3, this liquid will primarily consist of filtered and unfiltered inlet water, kill weight brine or mud, produced water, produced oil, cementing waste fluids (cement pushes, surfactants, rinsate), water with some detergents used to clean equipment, and deck drainage due to rainfall on the platform. UOCC will not dispose of solids (no grind and inject operation) or domestic sanitary waste into these wells. The source of these fluids will be from circulating out the 15 wells on the Dillon platform, and surface operations associated with the operation of circulating the wells. The estimated daily maximum injection amount is 800 bbls per day. The injected fluid is primarily water or oil, both of • • • which are compatible with the injection zones, which produced oil with a higher than 90% water cut prior to being shut -in. 10. The estimated average injection pressure is 2500 psi, and the estimated maximum injection pressure is 3500 psi. Tube movement calculations have been performed for each well, and during injection operations pressure will be applied to the 9 -5/8" casing to ensure the tubing does not move the seals out of the packer. 11. The following table summarizes the results of the FIT /LOT tests from the wells UOCC drilled on the Dillon Platform in 1994. This data shows the maximum pressure the well was subjected to without fracturing. All injection will take place below 9450' TVD depth, and all values reported on the table near this depth are FIT values, indicating that the formation strength was not exceeded with these formation tests. The proposed injection wells should not initiate nor propagate fractures at the estimated injection pressures. Well Casing Equivalent Pressure Equivalent Depth Mud Weight Gradient Pressure (TVD) (# /Gal) (PSI /Ft) (PSI) Di-16 1133 18.1 0.941 1066 3640 15 0.780 2839 9470 14.2 0.738 6992 Di-17 1133 16.5 0.858 972 3548 14 0.728 2583 9200 16.5 0.858 7894 Di -18 1133 15.9 0.827 937 3988 14.6 0.759 3028 9450 15.3 0.796 7518 12. Not applicable. 13. The Dillon platform (Middle Ground Shoal field) is operated under the fresh water exemption for Class II injection activities by 40 CFR 147.102(b)(2)(B) and 20 AAC 25.440(c). 14. Not applicable. 15. All wells on the Dillon Platform are shut -in and are monitored for pressure changes on a monthly basis. During the proposed injection, all wells will be monitored daily. UOCC does • not know of any mechanical deficiencies at this time on the Dillon Platform, all well pressures are currently stabile. Dillon Platform Spider Map ' 22408 226008 228000 238888 232888 2468857 I I 2468657 r __ I 2488080- + + 1 + + DI + 2488000 0I -16 DI -8 1 DI-8" ) DI -9RD 1 1 I '41-4 • 1 1 I 2466880- + + I + I - - i 01 -41 + 2466880 r I r 1 DI -2 . 1 r DI t .� Q I II I_ 1 2454000- + + O S9- t4 ., , + + 2464000 I Iii-12 , 4, i , i • DI -1 _ i DI -17'' 1 / I 2462000- + + G I + / + + 2462000 1 DI / ; I 1 1 . 1 1 DI -5 _ 1 2488088- + + 1 + + + 2468080 I 1 . DI 1 1 2 I 2458000-1- +. _ __ _ _ _4 + + + 2458000 DI— = G f I • DI — 1 1 r I 2456888- + + 1 + + + 2456080 I I 1 1 1 DI— - 11D I 1 1 2454051 I I I I I 2454051 224880 226888 228080 238888 232808 scale IP ......... Dillon Platform 0 1000 2000 3000 4000 Peet O :\NAU\MCBU\Alaska\Depts\Drilling \Users \TylerS\2009 Projects\ z_ 2009_ Platform _Pressure_Mitigation\Platform & Well Data\Dillon Platform \! Dillon Platform Docs\DillonPlatformSpiderMap .new.docx dolanjj Page 1 3/2/2011 • • MF.CBARICAL INTEGRITY REPORT S PUD DAzz: ttit5 — SA opER tali) \ RIG RELEAS:: WELL NUMBER L L DATA ').1)1 ‘voN-Wx V3NUATVD; ti Casing: cA9cc Shoe: St TM DV: JVD 1 Shoe: 1111 TVD; TOY: HD :1".TD ubing: - S t b„ .. Patkor C il *). 11 4 1) TVID St. at - - Hole S;fa,e, \VILk an6 6() Perfs _a\j to t140 C■kt,C.s.A. =WICAUsd INTEGRZTY - PART fl Annu 1 nv Prcss es t : 15 xj ; 3 0 mill • Comments: 4- a- e-ae■ Mi.^=s V •ON..., • f, .f • KE:CRANICAL INTEGRITY - PART e2 C ement V oltmiss Ame . Liner CI\*\,s Cs D'ai‘I• D\ Cmt vol to cover perf:s Theoreticz.1 TOC Cement Bond. Log (TEs or ; In AOGCC F5.le CL Evaluation, zone above perfs x. Cr-6\Z S 4.1••••■ Pe. Producxion Log: Type Evaluation ()11- S•vr:230 • CONCLUSIONS: Part 2 • #3/V 31((,c VN®CALf) Dill latform • \ elWDi -17 API# 50- 733 - 20458 -00 I('1. RRENT (()\1PLETIONI Completed 6 /15/95 RKB to Tbg Hngr = 54.12' C a s i n g & T u b i n g 1 Size Wt Grade Thread ID Top Btm 32" Surface 83' 18 -5/8" 97.7# X - QTE60 17.653 Surface 1133' 13 -3/8" 68# K -55 BTC 12.415 Surface 3548' 9 -5/8" 47# L -80 BTC 8.681 Surface 9484' Liner 7" 1 32# � P -110 1 TKC -BTC 1 6.094 9314' 11472 Tubing 3 -1/2" 9.2# L -80 SCBTC 2.992 Surf 9038 3-1/2" 9.2# L -80 SCBTC 2.992 Surf 9038 Jewelry Item 1 Depth 1 Length I ID 1 Description LONG STRING 55.42' 2.99 Cooper Dual Hanger 1. 9038' 26.30' 2.687 Trico Kobe Pump Cavity 2. 9081' 3.54' 2.56 Sliding Sleeve, HES RA SSD # 121RA25623 A 3. 9116' 3.54' 2.56 Sliding Sleeve, HES RA SSD # 121RA25623 II B 4. 9136' 8.75' 2.56 Baker FV6E TRSV 1 5. 9177' 11.47' 2.99 Locator Seal Assy w/ 10.45' of seals. C 6. 9177' 6.79' 5.00 HES VST Retrievable Pkr. Serial # 12VST96350 -2 7. 9184' 7.40' 5.00 Seal Bore Extension 8. 9191' .68' 2.99 Crossover 2 77,7- 9. 9208' 1.44' 2.56 Model "R" Profile Nipple 3 10. 9215' .45' 3.45 WLEG 5 .• 4 SHORT STRING I- , .; 55.42' 2.99 Cooper Dual Hanger = 17 A. 9029' 1.08' 1.995 Crossover, 3 -1/2" x 2 -3/8" 8 B. 2930' 10.05' 1.995 Tbg Pup Jt. _ ., 9 C. 9040' 26.30' Trico Kobe Pump Cavity 10 I 'G -3 Perforations Zone Top Btm Ft SPF Date Comments FOC fig; G 03 9,876' 9,900' 24' 10,270' — G-03 9,918' 9,946' 28' I G -03 9,956' 10,045' 89' G -03 10,054' 10,232' 178' ' G -03 10,432' 10,889' 457' 1 G -03 10,897' 11,018' 121' G -02 11,132' 11,231' 99' G -2 G -02 11 ,260' 11,279' 19' G -01 11,376' 11,400' 24' ow G -1 - TD = 11,472' PBTD = 11,419' Vlax Deviation = 83.09° @ 11,260' • • Plot Pressure & Rate vs Time - Well Di -17 1200 1000 800 l '".j\ 9 5/8" E 13 3/8" 3 20" rn' 600 T — Tubing a — Tubing2 400 200 - ......."""""""° -° co co co co co rn rn rn rn rn rn 0 rn rn CD rn rn 0 0 0 0 O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O O cn N N I� co co r r c0 to R V C) co N M N N O m m O r O M N N N N N N N N N N N N N N N N N N N N N N N N c0 O) O N N CO O LO O r O O O N N M V ID O IZ W O) O N (-- - V - O O O O O O O O O O O ,-- .- .- O O O O O O O O O ,- O O Date 54. 13 3/8" 20" Tubing la TIO Report 02/15/11 0 20 1100 01/05/11 870 0 20 1090 10901 Data Sheet 12/14/10 770 0 10 1090 1080 11/17/10 770 0 20 1090 10/29/10 60- 0 20 1080 Di -17 10/09/10 0 20 08/11/10 750 0 20 1080 1080 07/14/10 750 0 20 1080 1075 BOT HOLE HYD PUMP 06/16/10 740 0 20 1070 1070 05/19/10 730 0 20 1070 1060 04/21/10 730 0 20 1070 1060 Permit # 1940560 03/24/10 730 0 20 1070 1060 02/17/10 720 0 20 1060 1060 01/20/10 710 0 20 1060 1050 API # 50- 733 - 20458 -00 12/20/09 700 0 20 1050 1050 11/25/09 700 0 20 1060 1050 10/31/09 700 0 20 1050 1050 08/30/2008 to 03/01/2011 10/30/09 700 0 20 1050 1060 10/29/09 700 0 20 1050 1060 10/28/09 700 0 20 1050 1060 10/27/09 700 0 20 1050 1060 10/26/09 700 0 20 1050 1060 10/25/09 700 0 20 1060 1050 10/24/09 710 0 20 1050 1050 10/23/09 660 0 20 1000 1000 10/16/09 900 30 20 1050 1050 10/10/09 900 20 20 1050 1050 10/02/09 890 20 20 1050 1050 09/25/09 880 20 20 1050 1050 09/12/09 890 20 20 1050 1050 09/10/09 880 20 20 1050 1040 09/09/09 880 20 20 1050 1040 09/08/09 880 20 20 1050 1050 08/29/09 880 20 0 1050 1050 08/28/09 880 20 0 1050 1050 08/27/09 880 20 20 1050 1040 3/10/2011 8:44 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2011 03 01 (6).xls Di -17 • • Plot Pressure & Rate vs Time - Well Di -17 1200 a _ n.._ ,. , 1000 I 800 ....._..__ — - � 9 5/8" �_ 13 3/8" 3 N 600 , 20" i Tubing a — Tubing2 400 r 200 t 0 O o O i O O O O O o o O o O o O o O o 0 11! O 6 111 N N N N N N N N N O N N N N N N V N in" N N N O , - i N N N N N N N N N N N N N <D I� W O O N N 8 2 N N I� W 1 1 O O O O O � � � O O O O O O O O � O Date 133/8" 20" Tubing 1 11,1 TIO Report 07/14/10 0 20 1080 06/16/10 0 20 1070 1070 Data Sheet 05/19/10 0 20 1070 1060 04/21/10 0 20 1070 1060 03/24/10 0 20 17Q,. , ,,,..,10 0 Di -17 02/17/10 0 20 01/20/10 710 0 20 1060 1050 12/20/09 700 0 20 1050 1050 BOT HOLE HYD PUMP 11/25/09 700 0 20 1060 1050 10/31/09 700 0 20 1050 1050 10/30/09 700 0 20 1050 1060 Permit # 1940560 10/29/09 700 0 20 1050 1060 10/28/09 700 0 20 1050 1060 10/27/09 700 0 20 1050 1060 API # 50- 733 - 20458 -00 10/26/09 700 0 20 1050 1060 10/25/09 700 0 20 1060 1050 10/24/09 710 0 20 1050 1050 01/30/2008 to 07/31/2010 10/23/09 660 0 20 1000 1000 10/16/09 900 30 20 1050 1050 10/10/09 900 20 20 1050 1050 10/02/09 890 20 20 1050 1050 09/25/09 880 20 20 1050 1050 09/12/09 890 20 20 1050 1050 09/10/09 880 20 20 1050 1040 09/09/09 880 20 20 1050 1040 09/08/09 880 20 20 1050 1050 08/29/09 880 20 0 1050 1050 08/28/09 880 20 0 1050 1050 08/27/09 880 20 20 1050 1040 08/26/09 880 20 20 1040 1040 08/25/09 880 20 20 1040 1040 08/24/09 880 20 20 1050 1050 08/23/09 880 20 20 1040 1040 08/22/09 880 20 0 1040 1040 08/20/09 880 20 20 1040 1050 08/17/09 880 20 20 1040 1040 3/10/2011 9:32 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2010 07 31 (5).xls Di -17 0 • Plot Pressure & Rate vs Time - Well Di -17 1200 - - 9 5/8" 13 3/8" ® 20" — Tubing 1000 — Tubing 21 800 A, - .w a) 3 N 600 w a` 400 200 0 0 0 0 0 N. N. N. 0 0 0 0 0 0 0 O 0 0 N 41 N N N O O O •- O O O Date 13 3/8" TIO Report 01/23/08 0 12/19/07 0 Data Sheet 11/21/07 0 10/17/07 800 0 20 910 940 09/12/07 770 0 20 900 920 Di -17 08/12/07 760 50 40 900 980 07/18/07 760 50 20 890 970 06/13/07 750 50 20 880 960 BOT HOLE HYD PUMP 05/16/07 740 50 20 870 960 04/18/07 730 50 40 860 950 03/22/07 730 50 20 860 940 Permit # 1940560 02/21/07 720 50 20 870 920 01/18/07 720 50 20 840 910 12/15/06 710 60 40 830 900 API # 50- 733 - 20458 -00 10/20/06 700 60 30 810 880 09/29/06 690 60 30 800 880 09/04/06 670 70 50 800 870 11/01/2005 to 01/31/2008 07/20/06 680 70 30 780 860 06/25/06 660 60 40 750 800 05/24/06 660 70 0 950 850 04/21/06 650 80 30 760 750 03/17/06 640 90 30 740 730 02/26/06 640 80 0 740 720 01/19/06 630 110 60 720 720 12/08/05 660 400 50 800 700 11/18/05 600 380 60 125 710 11/01/05 3/10/2011 9:28 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2008 01 31.xis Di -17 • • Plot Pressure & Rate vs Time - Well Di -17 1200 1000 - 800 — Tubing — 9ubing 2 bib' -� ^ 9 5/8" 13 3/8" E 20 _ A Ada m 600 Arai' a` 1400 .' I'M li a____ 200 0 0 0 ° 0 0 0 0 0 0 _ . r r u N N N u b Ti me " . m DATE HRS ON Tubing Tubin• 2 9 5/8" 13 3/8" 20" 01/19/06 0 Ir 720 ( 630 110 60 Wavered Well 12/08/05 0 800 704 660 400 50 11/18/05 0 125 710 600 380 60 Data Sheet 10/24/05 0 740 680 610 390 70 10/18/05 0 125 710 600 380 60 09/20/05 0 710 660 560 0 0 Di -17 08/20/05 0 640 640 580 40 40 07/21/05 0 400 0 520 0 10 07/02/05 0 700 440 600 110 25 Permit # 1940560 05/21/05 0 375 400 590 0 20 04/16/05 0 250 350 560 5 25 02/24/05 0 500 320 10 21.5 30 API # 50- 733 - 20458 -00 01/29/05 0 625 340 550 38 36 12/28/04 0 600 360 540 38 38 11/13/04 0 600 450 490 38 38 02/01/2004 to 01/31/2006 10/31/04 0 600 450 490 38 38 10/06/04 0 09/30/04 0 580 420 510 40 40 08/20/04 0 525 450 490 40 40 07/07/04 0 490 460 480 38 40 06/23/04 0 500 180 470 38 40 04/30/04 0 450 280 440 35 38 03/24/04 0 400 150 410 34 38 01/27/04 0 250 130 400 38 0 12/26/03 0 250 110 350 35 40 12/15/03 0 k 250 110 350 35 40 11/04/03 0 I 0 320 32 38 3/10/2011 9:24 AM - Wavered Wells Reports v7b.xls J J Dolan Wavered Well Report Jan 2006.xls Di -17 • Chevron Timothy C Brandenburg Union Oil Company of California Drilling Manager P.O. Box 196427 Anchorage, AK AK 99519 -6247 Tel 907 263 7657 Fax 907 263 78888 4 Email brandenburgt @chevron.com • March 8, 2011 RECEIVED Commissioner MAR 0 8 20 i I Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue ' ` & au COM Conanission Anchorage, Alaska 99501 Anchorage Re: Dillon Platform: Area Injection Order Administrative Approval 8.2 and 8.3 Dear Commissioner, Union Oil Company of California (UOCC) respectfully requests that Area Injection Order 8.2 (AIO 8.2) dated January 29, 2003, and AIO 8.3 dated March 4, 2003, be amended to include two wells on the Dillon Platform, S MGS Unit 17 (Di -17) PTD 194 -056 and S MGS Unit 16 (Di- 16) PTD 194 -057. These two wells, Di -17 and Di -16, were oil producers when the platform halted production in 2003, and under separate cover 10 -403 forms have been submitted to change their status to EOR (enhanced recovery) water injector. The currently approved EOR wells, Di -12 (PTD 168 -056) and Di -14 (PTD 175 -066), authorized for waste injection per AIO 8.2 and 8.3 on the Dillon Platform, are in questionable service state per the October 2009 work on the platform. UOCC plans to circulate out 15 wells on the Dillon Platform commencing in June 2011, in advance of planned well abandonment activity. By UOCC records, a total of 6,347 barrels of Class II waste liquid have been injected into Di -12, and a total of 1,613 barrels of Class II waste liquid have been injected into Di -14, for a total of 7,960 barrels out of the authorized 50,000 barrels, leaving 42,040 barrels of authorized disposal volume remaining per AIO 8.2. At this time, UOCC estimates that the injection requirements for circulation and abandonment Class II fluid disposal will be under the remaining limit of 42,040 barrels. Per AIO 8.0, 8.2 and 8.3, this Class II injection liquid will primarily consist of filtered and unfiltered inlet water, kill weight brine or mud, produced water, produced oil, cementing waste fluids (cement pushes, surfactants, rinsate), water with some detergents used to clean equipment, and deck drainage due to rainfall on the platform. UOCC will not dispose of solids (no grind and inject operation) or domestic sanitary waste into these wells. Please let us know if we can provide any further information by contacting myself at 263 -7657 or Mike Quick at 263 -7900. Sincerely, Timo C. Brandenbur Drilling Manager Union Oil Company of California / A Chevron Company • • Page 1 of 2 Maunder, Thomas E (DOA) From: Quick, Mike [ASRC] [MQuick @chevron.com] Sent: Thursday, March 10, 2011 2:57 PM To: Maunder, Thomas E (DOA) Cc: Greenstein, Larry P; Kanyer, Christopher V Subject: RE: Request on Dillon Wells Tom — I am having a copy of each log made for your files, and should have them to you by the middle of next week. Thanks, Mike From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Thursday, March 10, 2011 2:12 PM To: Quick, Mike [ASRC] Cc: Greenstein, Larry P; Kanyer, Christopher V Subject: RE: Request on Dillon Wells Thanks Mike. As I am reviewing the files, I find that cement evaluation logs were run in both wells however I have not been able to locate any copies over here. Does Unocal /Chevron have copies of the cement logs available? Tom From: Quick, Mike [ASRC] [mailto:MQuick @chevron.com] Sent: Thursday, March 10, 2011 11:34 AM To: Maunder, Thomas E (DOA) Cc: Greenstein, Larry P; Kanyer, Christopher V Subject: RE: Request on Dillon Wells Mr. Maunder — Thank you for the follow up questions on our request for Administrative Approval for Dillon wells 16 and 17. We have submitted 10 -403 forms for each well to change their status, and have outlined how we plan to perform an MIT within that request. Here is what we submitted along with the 403's in regard to your question: Mechanical integrity of each well will be demonstrated with a pressure test under 20 AAC 25.412. Di -17: Install standing valve in long string tubing and perform bundle test to 2231 psi (packer depth of 9177' MD / 8922' TVD) to verify integrity of packer and 9 -5/8" casing. Install dummy pump in Kobe cavity and perform a Standard MIT on the tubing long string to 2231 psi to verify integrity of tubing long string (pressure will be kept on 9 -5/8" casing and will be monitored during test, tubing short string will be isolated with the dummy pump and will be monitored during test). Di -16: Install standing valve in long string tubing and perform bundle test to 2323 psi (packer depth of 9925' MD / 9292' TVD) to verify integrity of packer and 9 -5/8" casing. Install dummy pump in Kobe cavity and perform a Standard MIT on the tubing long string to 2323 psi to verify integrity of tubing long string (pressure will be kept on 9 -5/8" casing and will be monitored during test, tubing short string will be isolated with the dummy pump and will be monitored during test). 3/15/2011 • Page 2 of 2 In regards to your question on information regarding MIT and pump in, a MIT test was successfully performed on Di -17 in December 2002 (the short string was isolated for the test, as it has communication with the 9 -5/8" annulus). Neither well has any pump in history. Please let me know if I can provide any further details or information. Best Regards, Mike Mike Quick Project Manager / Drilling Engineer MidContinent /Alaska SBU Chevron North America Exploration and Production 3800 Centerpoint Drive, Suite 100 Anchorage, Alaska 99503 Direct 907 - 263 -7900 Fax 1- 866- 480 -5398 mquick @chevron.com From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Thursday, March 10, 2011 10:53 AM To: Quick, Mike [ASRC] Cc: Greenstein, Larry P Subject: Request on Dillon Wells Mike and Larry, I am looking at the request regarding waste injection into SMGS 16 and 17. I have looked at the files as well as the LTSI information that Larry sends monthly. From examination of the LTSI plots, it appears that 16 has "better" isolation than 17. At least the casing pressures appear to be more stable on 16 than 17. What plans might you have for performing an MIT or a pump in on the wells? Do you already have any information regarding MIT and pump in? Thanks in advance for your reply. Tom Maunder, PE AOGCC 3/15/2011 • • r E [t Z n SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 8.005 Mr. Tim Brandenburg Drilling Manager Union Oil Company of California (UNOCAL) AP 3. 2 201 ! P.O. Box 196247 Anchorage, Ak 99501 Re: South Middle Ground Shoal Unit 16 (194 -057) (South Middle Ground Shoal Unit 17 (19- 5-6j) Request to Inject Approved Wastes into the Stratigraphic Interval Authorized for Enhanced Recovery by Area Injection Order No. 8 Mr. Brandenburg: In correspondence dated March 8, 2011 UNOCAL requested authorization to use South Middle Ground Shoal Unit (SMGS) wells 16 and 17 for purposes of disposal of liquid wastes generated through well circulation and abandonment. Both wells are on the Dillon Platform. The Commission GRANTS UNOCAL's request. Production operations on Dillon Platform were halted December 8, 2002 when UNOCAL determined that such operations were not economically viable. Area Injection Order (AIO) No. 8 authorized injection of non - hazardous oil field fluids for the purpose of fluid disposal into strata that correlate with those found from 2620' to 3090' measured depth (MD) and from 4330' to 4955' MD in Pan American Petroleum Corporation State 17595 well No. 4. Based in part upon a Commission finding that disposal operations would not cause waste due to the limited volume of disposed fluids and the swept or depleted condition of the authorized reservoir intervals, on January 29, 2003 AIO 8.002 authorized disposal of 50,000 barrels of non- hazardous, Class II fluids generated by cleaning operations on Dillon Platform into the MGS A, B, C, D, E, F, and G Oil Pools, within wells SMGS 12 and SMGS 14. Authorized fluids are unfiltered inlet water, produced water, produced oil, sludge, triethyleneglycol, paraffin and asphaltenes. On March 4, 2003 AIO 8.003 authorized injection of storm water. UNOCAL injected 6,347 and 1,613 barrels of waste fluids into wells SMGS 12 and SMGS 14, respectively, while cleaning surface equipment and performing well work. Deteriorating well performance during the most recent work accomplished in October, 2009 prompts this request for additional Administrative Approval. Wells SMGS 16 and 17 are two of the Dillon Platform's most recently drilled wells, and are open in the Middle Ground Shoal E, F, and G Oil Pools, as are wells SMGS 12 and 14. SMGS 16 and 17 were completed in 1994, and are equipped with tubing and packers. Well operations • • AIO 8.005 April 12, 2011 Page 2 of 3 reports and bond logs have been examined, and both wells are satisfactorily constructed and exhibit mechanical integrity. UNOCAL proposes to perform standard mechanical integrity tests as required by regulation prior to placing the wells in operation. UNOCAL is not requesting an increase in the authorized injected fluid volume. Rule 9 of Area Injection Order No. 8 allows the Commission to administratively amend any rule in the order as long as the operator demonstrates to the Commission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into an underground source of drinking water. The portion of aquifers beneath Cook Inlet described by a 1 /4 -mile area beyond and lying directly below the Middle Ground Shoal Field are exempted for Class II injection activities by 40 CFR 147.102(b)(2)(B) and 20 AAC 25.440(C). Commission administrative approval to inject the above - specified non - hazardous, Class II oil field fluids into Dillon Platform wells SMGS 16 and 17 within the MGS A, B, C, D, E, F, and G Oil Pools is conditioned on the following: 1. Prior to placing each well into service as a disposal well, UNOCAL shall perform mechanical integrity tests which comport with the requirements of 20 AAC 25.412. The tests should be witnessed by a Commission Inspector; 2. UNOCAL shall monitor wellhead pressures and injection rate continuously during injection; 3. UNOCAL shall submit to the Commission a post- injection report of injected fluid source, type, and volume by well; 4. UNOCAL shall immediately shut in the well and notify the Commission if there is any change in the well's mechanical condition; 5. After well shut -in due to a change in the well's mechanical condition, the Commission's prior approval shall be required to restart injection; and 6. The total remaining authorized disposal volume is 42,000 barrels. DONE at i chor . ' e, Alas a and dated April 12, 2011. jai / 7 t ! orman Cathy P. Foerster 0 issis - -r Commissioner p1L AAr,, t n ,` 63 y s•1 � AIO 8.005 • • April 12, 2011 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[tlhe questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Re: Baker and Dillon Sundries ) ) Subject: Re: Baker and Dillon Sundries From: Thomas Maunder <tom_maunder@admin.state.ak.us> Date: Mon, 08 Nov 2004 13: 11 :52 -0900 To: "Cole, David A" <dcole@unoca1.com> \ \/oé).p \C\~ Thanks Dave. I figured you were likely out. Tom Cole, David A wrote: Tom, I have been on vacation for the past 2 weeks. Regarding this issue, I will try to give you a call this afternoon, after 3 pm as I am in meetings until then. David A. Cole Unocal Alaska Anchorage, Alaska Phone No. 907-263-7805 E-Mail: dcole@unocal.com -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Monday, November 08, 2004 11:0""1 AM To: Dave Cole Subject: Re: Baker and Dillon Sundries Dave, Below is the text of the note I sent you a few weeks ago regarding the multitude of sundries you have submitted regarding Dillon and Baker. I have not received any return message from you. I would appreciate your response to the questions I posed in my original message. Thanks in advance, Tom Maunder, PE AOGCC On October 25, 2004 at 4:01 PM, Thomas Maunder wrote: Dave, Earlier in the month a series of 403s regarding changing the monitoring frequency on the Baker and Dillon wells was sent to the Commission. I have been looking at our regulations and I don't find where daily monitoring is required. I know that is "the industry standard" but I can't tie that to a specific regulation. What is your reference?? I am also not sure that so many individual sundries is the correct process to address this matter. I am inclined to believe that some sort of conservation order is needed. This may tie into the letter that Bob Shipley just sent to the Commission with regard to the phased SCANNECì NOV 2 4 2004 10f2 11/15/20042:53 PM Re: Baker and Dillon Sundries ') ) plugging of the wells. Let me know your thoughts on this. Give a call or message back. Tom Maunder, PE AOGCC 20f2 11115/20042:53 PM ') . ~~fÆ~E :} !Æ~!Æ~~«!Æ AI,A~KA. ORAND GAS CONSERVATION COMMISSION Mr. Dave Cole Oil Team Manager UNOCAL P.O. Box 196247 Anchorage,AK 99516-6247 Re: Middle Ground Shoal Unit Platforms Dillon and Baker Dear Mr. Cole: ) FRANK H. MURKOWSK/, GOVERNOR 333 W. 7fH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 This letter confirms your conversation with Commission EngLlleer Tom Maunder last week regarding the multiple Applications for Sundry Approval (Form 403) you submitted in mid October regarding changing the monitoring frequency on the 16 wells on Dillon Platform and 23 wells on Baker Platform. Production and injection operations were halted on these platforms in 4th Q 2002 and 2nd Q 2003 respectively. Attached, please fmd the Sundry Applications, which are being returned without approval~ because the relief you request needs to be sought through a different procedure. The intent of submitting sundry notices for each well was to establish a monthly pressure and general monitoring frequency for all wells on Dillon and Baker. There is a requirement in place for some of the water injection wells that pressures and rates are to be monitored daily and reported monthly. Since the platforms are unmanned and not operating, it is not possible to obtain daily information. When operations were curtailed, a monthly monitoring frequency was established in the Plans of Development (POD) annually filed with the Division of Oil and Gas and Unocal desires to assure that this monitoring scheme is accepted by the Commission. As noted in the conversation, changing the monitoring frequency where presently in place and establishing a monthly monitoring frequency in general is not an action that is best accomplished with multiple sundry notices. A letter application requesting the desired monitoring schedule should be made under the applicable Area Injection Orders (AlO 7 for Baker and AIO 8 for Dillon) and Conservation Orders (CO 44 and CO 54) for the platforms/unit. The Commission looks forward to receiving your letter applications. If prior monthly monitoring information has not been submitted to the Commission, that infonnation should be llbmitted forthwith. ~ . No an Daniel T. Seamount, Jr. Ch . Commissioner BY ORDER OF THE COMMISSION DATED this _day of November, 2004 Ene!. ) -, UNOCAL8 David A. Cole Oil Team Supervisor Dir Tel 907.263.7805 Dir Fax 907.263.7847 e-mail dcole@unocal.com October 8, 2004 Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 W ih Avenue, Suite 100 Anchorage, Alaska 99501-3539 RECEIVED OCT 1 2 2004 Alaska Oil & Gas Cons. Commission Anchorage MIDDLE GROUND SHOAL BAKER PLATFORM Dear Mr. Maunder: Please find enclosed completed 10-403 reports requesting a change in pressure monitoring frequency from daily to monthly for the 23 Middle Ground Shoal Baker Platform wells and the 16 Middle Ground Shoal Dillon Platform wells. This will align our operational procedures on each platform as stated in the Plan of Development submitted to and approved by the Department of Natural Resources. If you have any questions regarding this, please contact me at 263-7805. Very truly yours, £L/Jót!L David A. Cole DAC:dma Enclosures ORIGINAL Unocal Alaska 909 West 91h Avenue, Anchorage, Alaska 99501 www.unocal.com ) STATE OF ALASKA ') ALAShr\ OIL AND GAS CONSERVATION COMMlb~'~ECE'VED APPLICATION FOR SUNDRY APPROVAL 1 0 2004 20 AAC 25.280 OCT Iii Operational shutdown U Perforate U. as.we,Ò'W:~ ~mÍ!mg~~-DiSPOS. U Plug Perforations 0 Stimullt\a~ 0\\ A ~xtension D Other 0 Perforate New Pool 0 Re-enter susp~g~~œ~~b Monitor Frequency 4. Current Well Class: 5. Permit to Drill Number: Di-17 10. Field/Pools(s): MGS/E,F&G Pools PRESENT WELL CONDITION SUMMARY / Effective Depth MD (ft): Effective Depth TVD (ft): ~gS (measured): 11,419' 10,094' / MD ~yt> Burst 83' / 83' 1,133' /. 1,132' 3,548'. 3,547' 9,484' 9,201' 11,4 , 10,103' Tubing Size: Tubing Grade: " Abandon U Alter casing 0 Change approved program 0 2. Operator Name: Union Oil of California aka Unocal Suspend U Repair well 0 Pull Tubing 0 1. Type of Request: 3. Address: P. O. Box 196247 Anchorage, Ak. 99519-6247 7. KB Elevation (ft): KB 127' above M5L 8. Property Designation: Dillon Platform 11. Total Depth MD (ft): 11,484' Total Depth TVD (ft): 10,105' Length Size Casing Structural Conductor 83' 1,064' 3,480' 32 18-5/8" 13-3/8" 9-5/8" Surface Intermediate Production Liner 9,416' 2,158' 7" Perforation Depth TVD (ft): 9,607 to 10,091 Perforation Depth MD (ft): 9,956 to 11,400 Packers and SSSV Type: 12. Attachments: Description Summary of Proposal Detailed Operations Program 0 BOP Sketch 14. Estimated Date for Commencing Operations: 16. Verbal Approval: Commission Representative: Date: Development Stratigraphic 0 0 Exploratory 0 94-56 Service 0 6. API Number: 50-733-20458 9. Well Name and Number: Junk (measured): Collapse /2" 55: 3 1/2" Both 9.2# L-80 Packers and SSSV MD (ft): 2,250' 630 psi 3,450 psi 1,950 psi 6,870 psi 4,760 psi 11,640 psi 10,780 psi Tubing MD (ft): L5 : 9,038' 55: 9,038' 9,177' 13. Well Class after proposed work: Exploratory 0 Development 15. Well Status after proposed work: Oil 0 Gas 0 WAG 0 GINJ 0 0 Service 0 0 0 Abandoned 0 0 Plugged WINJ WDSPL Contact 17. I hereby certify that the foregoing is true and rrect to the best of my knowledge. Plug Integrity 0 Phone Printed Namz~) . ",. C.?le Signature M-v!f/'á ~ Title Oil Team Supervisor 907-263-7805 Date COMMISSION USE ONLY 28-Sep-2004 Conditions of approval: Notify Commi sion so that a representative may witness Sundry Number: 3:' '-t -4 \. c-t 0 0 B Mechanical Integrity Test Location Clearance Other: RBDMS BFL NOV 2 2 2004 Subsequent Form Required: Approved by: ""oJ Form 1 O-Aetr'Revised 12/2003 APPLICATION RETURNED 11/17/04 NOT APPROVED BY COMMISSION n Q , G , N A ~y ORDER OF COMMISSIONER THE COMMISSION Date: Submit in Duplicate 1. Operations Abandon Performed: Alter Casing D Change Approved Program D 2. Operator Union Oil of California Name: aka Unocal I<r-, r.,-' ST ATE OF ALASKA ¡~~~ ~:: (~E' I \/:.,~" . ALASKA OIL AND GAS CONSERVATION COMMISSION =-£826 REPORT OF SUNDRY WELL OPERAT1?a~a~);: r;~~~".,2004 Suspend Operation Shutdown Perforate .~~~{: " ',.:Other.J RepairWell D Plug Perforations D StimulateD Time Extension 0 Shut in and secure Pull Tubing D Perforate New Pool D Re-enter Suspended Well D 4. Current Well Class: 5. Permit to Drill Number: Development 0 Exploratory D 94-56 Stratigraphic D Service D 6. API Number: 50-733-20458 9. Well Name and Number: Di-17 10. Field/Pool(s): MGS/E,F&G Pools 3. Address: P. O. Box 196247 Anchorage, Ak. 99519-6247 7. KB Elevation (ft): KB 127' above MSL 8. Property Designation: Dillon Platform 11. Present Well Condition Summary: Total Depth measured 11,472' feet true vertical 10103' feet Effective Depth measured 11,419 feet true vertical 10,094 feet Casing Length Size Structural Conductor 32" Surface 1,064' 18-5/8" Intermediate 3,480' 13-3/8" Production 9,416' 9-5/8" Liner 2,158' 7" Plugs (measured) Junk (measured) MD TVD Burst Collapse 83' 83' 1,133 1,132 3,548 3,547 9,484 9,201 11,472 10,103 Perforation depth: Measured depth: 11,376-11,400 11,260-11,29711,132-11,23110,897;'11,01810,432-10,88910,054-10,2329,956-10,045 9,918-9,946 9,876-9,900 True Vertical depth: 10,087-10,09110,071-10,07610,055-10,067 10,013-10,036 9,887-10,011 9,677-9,7889,607-9,671 9,579-9,600 9,545-9,564 Tubing: (size, grade, and measured depth) LS 3-1/2" 9.2# L-80 SCBTC @ 9038' SS 3-1/2" 9.2# L-80 SCBTC @ 9029' HES VST Retrievable Pkr @ 9,177' Packers and SSSV (type and measured depth) 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 Prior to well operation: 17 6 151 80 Subsequent to operation: This well shut in subsequent to operation 14. Attachments: 15. Well Class after proposed work: Copies of Logs and Surveys Run Exploratory D Development 0 Daily Report of Well Operations 16. Well Status after proposed work: Oil[2],_,.. Gas D WAG D 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Tubing Pressure 90 Service D GINJ D WINJ D WDSPL D Sundry Number or N/A if C.O. Exempt: Contact Printed Name P. M. Ayer Signature Title Petroleum Engineer ; R 1 ~ 2004. Phone 263-7620 Date 18-Feb-2004 Form 10-404 Revised 12/2003 u DCAL API# 50-733-20458-00 RKB to Tbg Hngr = 54.12' I . c 10 TOC@ 10,270' G-3 G-2 G-l ,.,.,.,.,.,.,.,.,.,. """"""'N'N ,.,.,.,.,.,.,.,.,.,. oN'N',",","bN trD =11,472'PBTD =11,419' I lMax Deviation =83.09° @ 11,260' Cas Size Wt Grade Thread 32" 18-5/8" 97.7# X-56 QTE60 13-3/8" 68# K-55 BTC 9-518" 47# L-80 BTC Tubing ID Top Surface Surface Surtàce Surface Btm 83' 1133' 3548' 9484' 17.653 12.415 8.681 Liner 7" I 32# I P-] 10 I TKC-BTC I 6.094 I 93]4' I ]]472 Tubing 3-]/2" 19.2# I L-80 I SCBTC 12.992 I Surf 19038 3-]/2" 9.2# L-80 SCBTC 2.992 Surf 9038 Jeweir Item I Depth I Length I ID I Description LONG STRING 55.42' 2.99 Cooper Dua] Hanger 1. 9038' 26.30' 2.687 Trico Kobe Pump Cavity 2. 9081' 3.54' 2.56 Sliding Sleeve, HES RA SSD # 121RA25623 3. 9116' 3.54' 2.56 Sliding Sleeve, HES RA SSD # 121RA25623 4. 9136' 8.75' 2.56 Baker FV6E TRSV 5. 9177' ] 1.47' 2.99 Locator Seal Assy wi 10.45' of seals. 6. 9177' 6.79' 5.00 HES VST Retrievable Pkr. Serial # 12VST96350-2 7. 9184' 7.40' 5.00 Seal Bore Extension 8. 919]' .68' 2.99 Crossover 9. 9208' 1.44' 2.56 Model "R" Profile Nipple 10. 9215' .45' 3.45 WLEG SHORT STRING 55.42' 2.99 Cooper Dua] Hanger A. 9029' 1.08' 1.995 Crossover, 3-1/2" x 2-3/8" B. 2930' 10.05' 1.995 Tbg Pup Jt. C. 9040' 26.30' TriGO Kobe Pump Cavity Zone G-03 G-03 G-03 G-03 G-03 G-03 G-02 G-02 G-O1 Top 9,876' 9,918' 9,956' 10,054' 10,432' 10,897' 11,132' 11,260' 11,376' Perforations Btm Ft SPF Comments Date 9,900' 9,946' 10,045' 10,232' 10,889' 11,018' 11,231' 11,279' 11 ,400' 24' 28' 89' 178' 457' 121' 99' 19' 24' DATE COMPLETED 1986 5/2 Steelhea LAST WORK: Well DI-17 1996 10/19 1997 1998 1999 1/16 1/22-24 1/25-26 3/3-4 3/7 4/1-4 DillON PLATFORM API # 50-733-20458-00 S. MGS UNIT # 17 WELL HISTORY 7/8/99 EVENT Completed as an Oil Well. WL - ,Pulled standing valve @ 9,020'. Well went on vacuum. RIH W/3" valve to 3000'. Shake off valve. POOH WL - Pull pump & SV . Pulled 3" standing valve & tried to tag fill, but could not get through SSSV sleeve @ 9158' KB. Found scale in cavity and pack-off sub at 9,110'. Reran SV and pump back in well. WL - (Pull standing valve) Made several runs w/ equalizing prong & pulling tool, but could not latch, due to fill on standing valve. Made several runs w/ 1.75" pump bailer, getting scale. Bailed sand & scale from Kobe standing valve @ 9,079' KB, equalized standing valve & left prong inside standing valve. Pulled 3" Kobe standing valve w/ Bull dog spear from 9,079' KB. WL - (Brush Short String) Ran 2.75" wire brush to 344' Kb, stuck in tight spot. Pumped fluid in tubing & got blown down hole to 752' KB, tools stuck again, Continued jarring up. Pulled tools free using hyd pressure. WL - Pulled standing valve, attempted to pull blanking sleeve. Beat up for 20 min @ 1500#, sleeve will move up about 4', but won't move any further, sheared pin, POOH. Broach through nipple (2.50") to 9,145' KB, no apparent scale. WL - Pulled standing valve, broach RA sleeve & tried to pull pack off. RIH wi 2Y2" super GS to 9,137' KB, latched pack off, beat on for 30 min., couldn't pull, POOH. RIH wi standing valve to 2,000' KB, shake off, POOH. TAG - CO - (Pulled standing valve, latch & clean out well). RIH wi 2-%" bull dog spear to 9,142' KB, latched SSSV, hit 15 times, wouldn't come, RIH wi 1.25" DD bailer to 9,142' KB, couldn't pass, POOH. RIH wi 1.50" slick line brush to 10.532' KB. taaaed fill. Swanson 6/11 7n-8 2002 WL - Pulled standing valve from 9,005' KB; didn't rerun one, Production will after well test. SIS - Scale Inhibitor Squeeze using a mutual solvent pre-flush to water-wet the formation. A scale inhibitor pill designed to last for one year follows the pre-flush. The pill is pushed back into the formation using a double displacement over-flush of produced water. Pump Preflush. Pump Scale Inhibitor Pill. Pumping 1st Overflush. Shut-in well for 12 hour soak. Pump 2nd Displacement. Shut-in well for 4 hour soak. 12/09/2002 This well was shut in and isolated at the surface with multiple flanges to isolate the well from surface flow lines. Don Sta LEG ROOM.1 lEG ROOM n LEG ROOM lU 20x 13 518 18 SI8 x 13318 13 318 x . 518 9 5/8 x dU81 3 1/2 9518 x c1ua12 7/8 9 SI8 x 3 1/2 133/rx95/r 01-18 ~ !!:!! !!:!.! DI-8 01-7 ABN-6 !!:! 01-3 ~ ~ ~ ~ 12 bbIs S4A8 3 112 tbg. 38.73 2 7/8 tbg. 20.13 1L21 . 17.13 18.78 0.181. 0.1291 ..0.0871 0-0507 0.0871 0.0828 -. cUll 9518" x 3 1/2" ~ 30 bbIs 0.0087 O..OOS79 300 300 r- -- 858 :: ~ I wel' .2 w8l. M w.n ft Well . 10 Wen #13 Wen .., W8I. .. WeI' #1 t wen .18 wen 17 Well" 18 w.11 n WeI' ß Wen.. 12 Well .14 wen .15 WELL BAY # 1 Pumped down tbg.tbg on vac. bled clown 9 5/8 x Ibg. Pumped 28 bbIs. Gas stiU at mace. Pumped down 2Ox135/8 2bbIs 100 psi. 20 bbIs In 133/8. Try to pun eclipse paker with wire line could not get out. . . WeD had 180 on annulus and 150 on Ibg would not bleed down. TryIed pumping down short side old pump In hole could not pump. Put 30 bbIs of 9.8 In annulur 9 5/8x tbg. Pumped down l.s. tbg. Returned up short side 100 bbIs. Put 15 bbIs In 13 5/8x9 5/8. 4 bbIs In 20" ann. Hook up to 20" took approx 1 bbl with charge press on ann. 13 3.8x 9518 RiønP and bleed 3 I»!' ~ ~. 9 5/8x1bg fluid packed with oil. 14.4 bbIsIn tbg. well 10 Is abondoned FiJI 20" ann 2 bbIs. 1bg on vac 7bb1s In 13318 x 9 5/8 28 bbls 9518 x tbg. 51.s. 5 s.s.bbIs down short side did fbg. And ann same time WELL BAY # 2 20" fluid packed.13 3/8 x 95/82 bbIs and started getting diesel fluid back to SU1face. Pumped 5bbIs In fbg.' 20 bbls In 9 5/8 ann.Annulus and fbg. Have 011 returns 0 press on well. 20" fluid packed.13 3/8 x 9 5/8 2 bbls and started getting diesel fluid back to 1UIface. PU'nped 5bbIs In tbg.' 20 bbls in 9 5/8 ann.Annulus and tbg. Press up to 500 psi. on both tbg. S1rIngs had 011 to top no press on tbg. Pumped and bled 7bbIs In tbg. Annulus. When annulus was fluid packed. 011 at surface.5 bbls In 13 5/8 x 9 5/8 press Dmlt . .5 bbls In 20" Well had SOpII. On 13 3/8x 9518 bleed down to 20psI put bbls of 9.8 fluid. 95/8onn. 20 bbls fluid. tbg.5bbIs each. wells 185/8 has 110 psi. bled off and fluid packed with press Omit of 50 pSi..75 of a bbl. Well had 100ps1. On 13 3/8x 9 5/8 bleed down to 20psI put 1Sbb1s of 9.8 fluid. 95/Sann. 20 bbls fluid. 1bg.5bb1s each, wells 185/8 has 60 psi. bled off and fluid packed ann with .75 bbls. WeB had 15Ops1. On 13 3/ax 9518 bleed down to 20psI put 20bbIs of 9.8 fluid. 95/Sann. 20 bbIs fluid. tbg.5bbIs each, wellS 185/8 has25 psi bled off and fluid packed with 9.8 satt took 1.2 bbls. WELL BAY Ii 4 Rig up pump 4 bbIs I.s. 4 bbI s.s. 9 5/8 x fbg. 25 bbIs. 13318 x 9518 fluid packed wI 12 bbIs. 20" OM. 2 bbIs. Ruid packed Pumped 4 bbls l.s. fbg. 4 bbls's.s.R/u to 9 5/8 x 3 112 OM. Pumped 15 bbIs fluid packed oil to surface. Pumped 4bbIs down tbg Is, 4 bbIs s.s. both went on vac. Pumped 15 bbIs 95/8 x3112. WHh50 psi press Itmlt 0 bbIs In 13 3/8x 95/8 fluid packed 20x 133/82 bbIs, RuId packed 13 3/8x9 5/8 12 bbIs press up to 200 psi and held. Rig up pump 5 bbls l.s. 25 bbI s.s. & 9 5/8 x tbg. 8 bbIs ftufd packed on to surface 13 5/8x9 5/8. RJU to 20" ann fluid pack 5 bbIs. Press Omit 20 psi. Unocal Energy Resources 909 West 9th, P.O. BOX 196_ .I. Anchorage, AK 99519-6247 Telephone (909) 276-7600 Fax (907) 263-7828 UNOCAL ) Debra Childers Clerk DATA TRANSMITTAL 96-8 April 11, 1996 Larry Grant 3001 Porcupine Anchorage, AK 99501 Alaska Oil & Gas From: Debra Childers 909 VV. 9th Avenue Anchorage, AK 99519-6247 Unocal Transmitting the following item. II Middle Ground Shoal Dillon #17 I TAPE Cased Hole CN / GR II p, CF_!VED Alasl(a 0~ & Gas Cons. Please ac knowledge~rec~pt by signing and _r~et~~ copy of this tmnsmi tt. a l or FAX to (907)263-7828. i~'~'" AOGSC Indi'v'iduai Well Geo'iog~'ca/ ~later'~'ais Znventor'y 1:' ,Et g e: 1 Date: 0~/10/@6 PERMIT DATA 94'--056 ~0,7- 94-056 ' ,~/AILY WELL OP 94--056 ~~JRVEY 9,q.--056 O//DPR/GR 94-056 ~/~NL./GR/PC L 94--056 CNL/'GR T DATA_PLUS R COHP DATE:06/15/94 R 04/15/94~-06/15/94 R 0,00-10242 L 9450-11/~50~ ~tD ~ L 9450-11450~ ~4D -~ L 9290--11377 L 0-10457 RUN DATE._R ECVD o?/oe/9~ 07/08/94 07 toe/ 9~ 17 07/25/94 17 07/25/9~ 1 07/25/94 1 07/25/94 Ar'e dr'y ditch Was the we'l I cor'ed? Ar'e we'l '1 We I '1 ~' s COH~ENTS tests r'equi'r'ed? ~/yes i' r~ comp 1 i' ance ........... 1',4 Zn~ ~'a"l r,e c e ~' ved,?~'~-~ samples r'equ~'r'ed9 yes ~ And Analyst's & descr'~'pt~'on~R-Tr~ce~'ved? Rece~'ved? yes no Unocal North Amer!<~:, Oil & Gas Divison Unocal Corporation P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL~) Alaska Region Monday, July 18, 1994 DOCUMENT TRANSMITTAL TO: tarry Grant FROM: Dan Seamount LOCATION: 3OOl ~o~tc~n~ DmV~ ANCHORAGE, AK 99501 ALASKA OIL & GAS CONSERVATION COMM. LOCATIONn,.o.mx 196247 ANCHORAGE AK 99519 TRANSMllTING AS FOI. X~WS 1 blueline and 1 sepia of each of the following MGS DIlJ/)N 16 fBltC Aconstilog/Gamma Ray/Caliper ..-Compensated Densilog/Neutron/Gamma Ray/Caliper .,,"Dual Induction Focused Log/Gamma Ray MGS DIlJI)N 17 ~' Compensated Neutron/Gamma Ray/PCL 7" Casing /Compensated Neutron/Gamma Ray .~ ~,/ Dual Propagation Resistivity/Gamma Ray2~& 5' PLEASE ACKNOWLEDGE RECEIFr BY SIGNING AND RETURNING ONE COPY OF THIS ~oc~~ ~ ~~ ~ ~o ~, c~ ~s. ~,~ ~o ~ DATED: STATE OF ALASKA AI~. , OIL AND GAS CONSERVATION COI~ ~SION WELL COMPLETION OR RECOMPLETION n':PORT AND LOG 1. Status of Well Classification of Service Well 2. Name of Operator ~ ~. 7. Permit Number UNION OIL COMPANY OF CALIFORNIA (UNOCAL)f ~f ~!_;~) ! 94-56 ,C/f,,./,4L ,.,,.,,un.,,,., P.O. BOX 196247 ANCHORAGE, AK 99519 ' -~ ~ .... , 50-733-20458 4. Location of well at surface Dillon Platform, Leg #2, Slot #6 9. Unit or Lease Name 694' FSL & 1870' FWL Section 35, TON, R13W, SM At Top Producing Interval 9876' MD/9547' TVD (;O~'LETt0t~ Ii 1%~3~!D i' 10. Well Number 291' FNL & 592' FWL SECTION 2, T7N, R13W, SM./,., A/~'r~, / ~/'~, ~!~ ! 17 At Total Depth 11484' MD/' 10107' TVD "'~'Z-~-l/-~-~ i 11. Field and Pool · oo,. 5. £1oYation127'KB in fe~t {indicate KB, DF, otc.) 6. I.oa~e DesignationADL 18740 and Serial No. 11484'/10107' N/A~YES [] NO U_J~ 9137 feetMD N/A 22. Type Electric or Other Logs Run DIL/GR/SP/NEU/SBT 23. CASING, LINER AND CEMENTING RECORD t FT.' SETI'ING DEPTH MD CASING SIZE WT. PER GRADE TOP I BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PUl I FD 18- 5/8' 97 X-56 69' 1133' 24' 2376' cu. ft. - - - 13- 3/8" 68 K- 55 68' 3548' 17-1/2" 2431' cu. ft. 9- 5/8" 47 L- 80 68' 9484' 12-1/4' 1302 cu. ft. 7" 32 P 110 9314 11472 8-1/2' 983 cu.ft. 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE I DEPTH SET (MD) I PACKER SET (MD) 3-1/2'. 9.2#, L-80 (~ 9210' PACKER (~ 9172' See Attached 28. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) I AMOUNT & KIND OF MATERIAL USED 9690'-9692' CMT ClRC SQZ WITH 186 cu.ft. 9860'-9862' 27 PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) N/A Date of Test Hours Tested PRODUCTION FOF OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE I GAS-OIL RATIO TEST PERIOD ............... FlowTubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OILGRAVlTY-API (corr) Press. 24-HOUR RATE ...... 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chipe. Form 10-407 Submit in duplicate rev. 7-1-80 CONTINUED ON REVERSE SIDE GEOLOGIC MARK'S FORMATION TESTS NAME Include interval tested, pressure data, all fluicl~ recovered' and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. 31. LIST OF ATI'ACHMENTS 32. I hereby~~ correct to the best of my knowledge ~[~/'7/~Signed G. RUSSELL SCHMIDT T,e DRILLING MANAGER Da. 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 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'. 32' Structural @ 83' BLM 18-5/8" Surface @ 1133' 97#, X-56, QTE60 13-3/8" Intermediate (iD 3548' 68#, K-55, BTC COMPLETION DESCRIPTION 1) Dual 3-1/2", 9,2#, L80, SCBTC 2) Kobe BHA @ 9038' 3) 3-1/2" "RA' sleeve ~ 9081' 4) 3-1/2" "RA' sleeve @ 9116' 5) Baker 3-1/2" FV6E SSSV ~ 9137' 6) Otis "VS'I" Packer @ 9172' 7) 3-1/2" 'R' landing nipple @ 9203' 8) 3-1/2" Re-entry guide @ 9210' 9) 1/4" SS control line RKB -- 127' TOL @ +/-9314' 9-5/8' Production @ 9484' 47#, L-80, BTC Cmt sqz holes; 9690'-92'; 9860'-62' Hemlock Perfs ETD@ 11419' 7" L @ 11472' Pll TKC-BTC 32#, 0, 9876'-9900' 9918'-9946' 9956'-10045' 10054'-10232' 10432'-10889' 10897'-11018' 11132'-11231' 11260'-11279' 11376'-11400' DILLON 17 ACTUAL COMPLETION UNOCAL ENERGY RESOURCES ALASKA ' DRAWN: CLL DATE: 6-17-94 FILE: DIL17.drw UNOCAL DILLON PLATFORM DILLON #17 DAY 1-3 (04/15-17/94) PICK UP CENTER PUNCH ASSEMBLY & HWDP. TIH & SET DOWN @ 139'. CIRC. COND 139' TO 281' (SHOE). DRILL F/281' TO 330', TOH W/CP ASSEMBLY. RUN DIRECTIONAL SURVEY. RIH W/DIRECTIONAL ASSEMBLY & DRILL 17-1/2" HOLE F/330' TO 1148'. TOH. TOTAL DISPLACEMENT OF CONDUCTOR; 8.21'S & 14.66'W. TIH W/24" HOLE OPENING ASSEMBLY. OPEN HOLE F/281' TO 1148'. TOH. RIH W/18-5/8" CSG, LAND SHOE @ 1,133'. DAY 4 (04/18/94) RIH W/5" CEMENTING STRING. ENGAGE WELLHEAD & CMT 18-5/8" CASING, CIRC. CEMENT TO SURFACE. POH W/5" DP, ND 30" RISER. INSTALL BLIND FLANGE ON WELLHEAD. RELEASED RIG @ 1200 HRS APRIL 18, 1994. SKID RIG. DAY 5 (04/26/94) 18-5/8" @ 1148' 9.6 PPG SKID RIG F/DI #16. NU BOP & TEST SAME TO 3M. DAY 6 (04/27/94) 18-5/8" @ 1148' 9.6 PPG TEST BOP'S. CLEAN OUT CEMENT TO 1098 TEST CASING TO 2000 PSI. DRILL 10' OF NEW FORMATION TO 1158' PERFORM L.O.T., 86 PSI/FT FRAC GRADIENT, 1 6.5 PPG EMW. DRILL 17-1/2" HOLE FROM 1158' TO 2122'. DAY 7 (04/28/94) 18-5/8" @ 1148' 9.9 PPG DRILL FROM 2122' TO 2748'. 3190'. CBU. POOH F/BIT CHG. DRILL F/2748'- RECEIVED JUL-8 ~994- ~';;~ & 6~.,s cons, 6o~missioa Anchoraue UNOCAL DILLON PLATFORM DILLON //17 DAY 8-10 (04/29,04/30 & 5/1/94) 13-3/8" @ 3548' 8.7 PPG DRILLED 17-1/2" HOLE F/3190'- 3560' POOH TO 2725', RIH, CCH F/CSG. POOH TO 18-5/8" CSG. AT 1133'. RIH, CCH F/CSG. POOH, CHG RAMS & RU TO RUN CSG. RIH W/13-3/8" 68~ K-55 CSG. TO 3548', CCM. M&P 360 BBLS LEAD CMT AT 12.9 PPG & 74 BBLS TAIL CMT AT 15.8 PPG. CIP AT 1230 HRS, FLOATS OK. PRESS TEST CSG. TO 2800 PSI F/30 MINS, OK. INSTALL CSG. PACKOFF & TEST SAME TO 3000 PSI F/30 MINS, OK. ND 20" BOP. NU "B" SECT OF WH, TEST SEALS TO 3M & 5M, OK. NU 13-5/8" BOP STACK. TEST BOPE. RIH DRILLED CEMENT FROM 3432' TO FLOAT COLLAR AT 3459'. CLEARED OUT FLOAT TRACK AND HOLE TO 3560'. PERFORMED L.O.T. · 728 PSI/FT. DAY 11 (5/2/94) 13-3/8" @ 3548' 8.8 PPG DRILLED 12-1/4" HOLE F/3560'- 4514' DAY 12 (5/3/94) 13-3/8" @ 3548' 8.8 PPG DRILLED 12-1/4" HOLE F/4514'- 4663'. SHORT TRIP TO THE 13-3/8" SHOE AT 3548'. DRILLED F/4663' - 5416'. DAY 13 (5/4/94) 13-3/8" @ 3548' 8.8 PPG DRILLED 12-1/4" HOLE F/5416'- 5502' (KOP). TRIPPED FOR DIRECTIONAL BHA. DRILLED 12-1/4" HOLE F/5502' - 5887'. DAY 14 (5/5/94) 13-3/8" @ 3548' 9.2 PPG jUL-'8 'i994 f:,'i & Gas Cons, C~mmission Anchorage UNOCAL DILLON PLATFORM DILLON #1 7 DAY 15-17 (5/6,7 & 8/94) 13-3/8" @ 3548' 9.2 PPG DRILLED 12-1/4" HOLE F/6422'- 6967'. POOH F/BIT & BHA CHG. DRILLED 12-1/4" HOLE F/6967' - 7606'. POOH, TIGHT AT INTERVALS. TEST BOPE. MU BHA & RIH, SET DN 7440'. REAM F/7440' - 7606'. DRILLED F/7606' - 7700'. DAY 18 (5/09/94) 13-3/8" @ 3548' 9.2 PPG DRILLED 12-1/4" HOLE F/7700'- 8234'. FORMATION RATTY SLOWER ROP, MAKING COURSE CORRECTIONS AS NEEDED. DAY 19 (5/10/94) 13-3/8" @ 3548' 9.3 PPG DRILLED 12-1/4" HOLE F/8280'- 8696'. DAY 20 (5/11/94) 13-3/8" @ 3548' 9.3 PPG DRILLED F/8758'- 8895'. DAY 21 (5/12/94) 13-3/8" @ 3548' 9.3 PPG DRILLED F/8895'- 9327'. POOH F/BIT & BHA CHG. jUL-8 i994., ~"; c~ C:~s Cons, 6~mrnission UNOCAL DILLON PLATFORM DILLON #17 DAY 22-23 (5/22-24/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.2 PPG MU BHA &RIH. DRILLED 12-1/4" HOLE F/9327'-9498'. CCH. POOH. CHG RAMS TO 9-5/8 & TEST SAME. RU & RIH W/9-5/8" 47# L80 CSG TO 9485'. CCM. M&P 230 BBLS OF 15.8 PPG CMT ClP AT 1830 HRS 5-14-94, PLUGS BUMPED & FLOATS HELD. PRESS TEST CSG TO 5000 PSI F/30 MINS, OK. INSTALL WH SEAL ASSY, TEST W/OVERPULL & PRESS, OK. CHG RAMS & TEST BOPE. MU 8-1/2" DRLG BHA & RIH. TAG CMT AT 9385'. CLOUT CMT, FLOAT EQUIP & NEW 8-1/2" HOLE TO 9506'. CCM. PERFORM FITTO 16.5 PPG EMW. DRILLED 8-1/2" HOLE F/9506'-9735'. DAY 24 (5/25/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.2 PPG DRILLED F/9735'-9937'. POOH, CHG BIT & ADD LWD (RES/GR). RIH, REAM F/9900'-9937'. DRILLED TO 9984'. DAY 26 (5/16/94) 13-3/8" @ 3548' 9-5/8" ~ 9484' 9.2 PPG DRILLED F/9984'-10156'. POOH, POSSIBLE BIT OR MOTOR PROBLEM. CHG OUT MOTOR. MU BHA & RIH. DRILLED F/10156'-10190'. DAY 27 (5/18/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.3 PPG DRILLED TO 10225', HI-TORQ & TIGHT HOLE. DRILLED F/10225'-10242', TIGHT HOLE ON PU. STUCK BHA AT 10242'. ATTEMPT TO PULL FREE, NEG. JAR UP/DN ON BHA, NEG. PREP TO FISH BHA. SPOT 36 BBLS OF SOLTEX. RU WL, FREE PT BHA TO MWD. POOH. RIH W/STRING SHOT AND BACK-OFF HWDP @ 10127' DPM. POOH W/WL. POOH W/DRLG BHA. 4 UNOCAL DILLON PLATFORM DILLON #17 DAY 28 (5/19/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.3 PPG RIH W/FISHING BHA #1. SCREW INTO TOF @ 10127' (FISH BHA = 115'). JAR ON FISH Fl7 HOURS W/O SUCCESS. RIH W/STRING SHOT & BACK-OFF AT 10157'. FiSH LEFT IN HOLE; BIT, MOTOR & LWD. POOH. PU 2-7/8" TBG. DAY 29-31 (5/20-22/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.3 PPG RIH W/TBG TO TOF At 10157'. M&P BAL PLUG OF 48 BBLS OF CMT AT 17 PPG F/10157'-9700'. REVERSE OUT 5 BBLS CMT. CIP AT 0730 HRS. WOC POOH W/TBG TAIL. TEST BOPE & REPAIR DRLG NIPPLE. MU BHA & RIH. TAG CMT AT 9601', DRILLED GRN CMT F/9601'-9688'. ORIENT MTR & KICK-OFF CMT PLUG AT 9688'. DRILLED 8-1/2" HOLE F/9688'-9917', POOH, CHG BIT & RIH. DRILLED F/9917'-10270'. DAY 32 (5/23/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.2 PPG DRILLED TO 10279'. POOH DUE TO SLOW ROP. TIGHT SECTION AT 9512'. CHG BHA & BIT. RIH, REAM F/10224'-10279'. DRILLED TO 10343'. DAY 33 (5/24/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.2 PPG DRILLED F/10343'-10369', SLOW ROP DUE TO FORMATION CHG. DRILLED TO 10408'. POOH, TIGHT HOLE AT INTERVALS. BIT FOUND PINCHED & UNDER GAUGE ALONG W/MTR SLV WEAR DAMAGE. MU BHA & RIH. UNOCAL DILLON PLATFORM DILLON #17 DAY 34 (5/25/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.2 PPG REAM F/10320' TO BTM. DRILLED 8-1/2" HOLE F/10408'-10469', IMPROVED ROP & APPARENTLY HAVE RE-ENTERED HEMLOCK G-3 INTERVAL. DRILLED F/10469'-10823'. DAY 35 (5/26/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.2 PPG DRILLED TO 10855'. MWD TOOL FAILED. CBU. POOH, TIGHT HOLE IN COAL SEAM INTERVAL F/10400'-10250'. PERFORM BOP TEST. CHANGE MWD & RIH. REAM F/10270' TO 10445'. PU TO 10355' & SET BACK DOWN @ 10408'. WORKED DOWN TO ~1041____7' & COULD NOT WORK FURTHER. NO TORQUE OR OVERPULL. POOH TO CHECK TOOLS. DAY 36-39 (5/27-30/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.6 PPG POOH TO SHOE, INCR. MW TO 9.5 PPG., CONT POOH. FOUND SHAFT ON MOTOR BROKEN, CHANGE SAME. TIH, WASH & REAM F/10,270' TO 10,855'. DRLD F/10,855' TO 11,315'. ROP FELL OFF & INCREASE IN OFF BOTTOM PUMP PRESS, TOH TO CHK TOOLS. TIGHT HOLE FOR FIRST 150' OFF BOTTOM, REST O.K. CHANGE OUT BIT AND MUD MOTOR. TOOK MWD OUT OF STRING. TIH, WASH & REAM F/10,519' TO 11,186', REAM F/11,186' TO 11,31 5'. DRILL F/11,31 5' TO 11,484'. HAD SOME TROUBLE STICKING AND PACKING OFF @ 11,484'. CIRC & CLEAN UP WELL FOR MWD LOGGING RUN. POOH FOR MWD & LOGGING TOOL. TIH WITH MWD & LOGGING TOOL. HAD 2' OF FILL, DID NOT CLEANOUT. LOGGED FROM 11,482' TO 10,827' AT 2400 HRS. UNOCAL DILLON PLATFORM DILLON #1 7 DAY 40 (5131194) 13-3/8" @ 3548' 9-5~8" @ 9484' 9.6 PPG CMPT LOGGING OPEN HOLE W/LWD F/11450'-9484'. POOH. RU & RIH W/7" 32# P110 TKC-BUTT LINER TO 9-5/8" SHOE. RIH, LINER SET DN AT 10388'. ATTEMPT TO WORK LINER DN HOLE W/ROTATION & REClP, NEG. POOH. DAY 41 (6/1/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 9.6 PPG SECT F/9696' - 10,835'. COAL SECT APPEARS TO BE SLOUGHING IN. REAM F/10,835' - 11,477', LOST JUNK F/LINER SHOE APPEARS TO BE NOW ON BTM. CIRC HI-VISC SWEEP & SPOT SOLTEX PILL IN OPEN HOLE. DAY 42 (6/02/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 7" L F/11472'-9315' 9.6 PPG SHORT TRIP TO CSG SHOE, TIGHT HOLE AT INTERVALS. RIH & C/OUT TO 11,477'. CCM. POOH. MU 7" 32# Pl10 LINER ALONG W/HANGER & RUNNING TOOL. RIH W/LINER, WORK LINER DN HOLE WASHING F/11224'- 11472'. FLOW LINE PLUGGED ONCE ON BTM, CORRECT SAME. CCM. RU CMT LINES & TEST SAME TO 5M. M&P 50 BBLS LEAD CMT AT 11 PPG & 124 BBLS TAIL CMT AT 15.8 PPG. UNOCAL DILLON PLATFORM DILLON #17 DAY 43-45 (6/03-05/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 7" L F/11472'-9314' 9.7 PPG CMT 7" F/9314'-11471'. CIP AT 0030 HRS 6-3-94. REL F/HANGER & CBU, NO CMT. PRESS TEST LINER TO 3500 PSI F/30 MINUTES. POOH, LOST HANGER SETTING TOOL IN HOLE. TEST BOPE. MU FISHING BHA & RIH. SCREW INTO FISH AT 9315', ATTEMPT TO REL FISH, NEG. PRESS UP TO 5500 PS! & JAR FISH FREE. POOH, CMPT RECOVERY. MU 6" BIT & 7" CSG SCRAPER. PU 3-1/2" DP & RIH TO 11421' ETD (LANDING COLLAR) CBU. POOH. RU E-LINE & RIH W/SBT/GR/CN TO 10460'. LOG F/10460' - SURFACE AS REQ'D W/(3) SEPARATE TOOL FAILURES. RU PCL OPS & RIH W/SBT/CN/GR/CCL TO 11382'. LOG INTERVAL F/11382'-9300'. DAY 46 (6/06/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 7" L F/11472'-9314' 9.7 PPG CMPT PCL OPS. POOH W/VVL, DP & LOGGING TOOLS. LAY DN HWDP & PU 3-1/2" TBG. RU WL, RIH & PERF SQZ HOLES @ 9690'-92' AND 9869'-62' AT 4 SPF. RU & RIH W/7" EZSV, SET SAME AT 9845'. PU 2-7/8" TBG TAIL F/CMT SQZ. DAY 47 (6/07/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 7" L F/11472'-9314' 9.7 PPG RIH TO RET AT 9845'. STAB RET, BRK CIRC W/1200 PSI AT 2.75 BPM. Si BACKSIDE & BREAK DN FORMATION W/2000 PSI AT 2 BPM. M&P 25 BBLS OF CMT F/CIRC SQZ. UNSTING FROM RET & REV CIRC. M&P BAL CMT PLUG W/15 BBLS F/9845'. PULL TO 9377' & REV CIRC. SI & SQZ AWAY 8.5 BBLS CIP @ 0900 HRS. POOH. PU 3-1/2" TBG & RIH. POOH, STD BACK SAME. MU 6" BHA & RIH. 8 UNOCAL DILLON PLATFORM DILLON #17 DAY 48 (6/08/94) 13-3/8" @ 3548' 9-5~8" @ 9484' 7" L F/11472'-9314' 8.4 PPG RIH TO TOC AT 9632'. C/OUT CMT TO 9722'. TEST UPPER SQZ HOLES TO 2000 PSI, OK. C/OUT CMT TO RET AT 9845'. DRILL RET AT 9845' & CHASE SAME TO 11419' ETD. TEST SQZ LOWER PERFS TO 2000 PSI, SLIGHT LEAK. DISPLACE DRLG MUD AT 9.7 PPG TO 3% KCL WATER AT 8.4 PPG. SI WELL, SLIGHT FLOW. CIRC WELL THRU CHOKE. DAY 49 (6109194) 13-3/8" @ 3548' 9-5/8" @ 9484' 7" L F/11472'-9314' 8.9 PPG CIRC WELL. CLEAN TANKS WEIGHTED BRINE TO 8.9 PPG W/KCL AND NACL. CIRCULATED AROUND, WELL STABLE. POOH L/D EXCESS PIPE, RIH W/7" & 9-5/8" CASING SCRAPERS. DAY 50-52 (6/10-12/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 7" L F/11472'-9314' 9.3 PPG RIH W/TANDEM 7" & 9-5/8" SCRAPERS TO 11419'. DISPL WELL TO 8.9 PPG KCL/NACL BRINE. CK WELL FOR FLOW, SLIGHT FLOW. INCR BRINE WT TO. 9.2 PPG & CK FOR FLOW, OK. POOH. TEST BOPE. MU TCP PERF GUN ASSY & RIH TO 11416' (BTM). RU WL & CORRELATE GUNS ON DEPTH. DETONATE TCP GUNS AT 0528 HRS 6-12-94, PERF HEMLOCK F/9876'- 11400' AT INTERVALS. ATTEMPT TO FLOW WELL TO SURFACE, NEG. FLUID LEVEL STABLE AT 800' F/SURFACE. REL PKR & REV CIRC, FLUID LOSSES AT 8 BPH. POOH W/TCP GUNS. UNOCAL DILLON PLATFORM DILLON #17 DAY 53 (6/13/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 7" L F/11472'-9314' 9.3 PPG MU OTIS 9-5/8" PKR & TBG TAIL ASSY ON DP, RIH W/SAME. FLUID LOSSES AT 6.5 BPH. SET PKR AT 9172' W/TBG TAIL AT 9210', TEST BACKSIDE TO 2000 PSI, OK. POOH. PU & RIH W/3-1/2" TBG, POOH. CHG RAMS TO DUAL 3-1/2" & TEST SAME, OK. DAY 54 (6114194) 13-3/8" @ 3548' 9-5/8" @ 9484' 7" L F/11472'-9314' 9.3 PPG RU & RIH W/DUAL 3-1/2" KOBE COMPLETION, HYDRO-TEST SAME TO 5000 PSI. TAG PROD PKR AT 9172', ATTEMPT TO BREAK ClRC, NEG. RU SLICKLINE, RIH & RETRIEVE LOCK & STRINGER F/SSSV. BREAK ClRC, OK. DAY 55 (6/15/94) 13-3/8" @ 3548' 9-5/8" @ 9484' 7" L F/11472'-9314' 9.3 PPG FINISHED RUNNING DUAL COMPLETION. LANDED TBG W/20K OVER STRING WEIGHT ON LONG STRING. TESTED TBG/CSG ANNULUS TO 1000 PSI-OK. ND BOP'S. NU TREE. TEST TREE. RIG UP FLOWLINES & PRODUCTION EQUIPMENT. INSTALLED JET PUMP IN TREE. MADE REPAIRS TO RIG FLOWLINE & TOP DRIVE. START SKIDDING RIG TO DILLON #16 @ 1700 HOURS. RELEASED RIG TO DILLON #16 @ 1800 HRS 6-15-94. 10 UNOCAL D[LLON Platform D'17 slot #2'6 Middle Ground Shoals Cook Inlet, Alaska SURVEY LISTING by Baker Hughes ]NTEQ Your ref = GSS <0 - 1100"> : PNSS <1233-10242'> Our ref : svy4369 License = Date printed : 3-Jun-94 Date created : 28-Apr-94 Last revised : 21-May-94 Field is centred on n60 50 4.803,w151 29 11.941 Structure is centred on n60 44 0.8~1,w151 31 22.418 Slot location is n60 44 7.674,w151 30 44.809 Slot Grid coordinates are N 2463855.846, E 229317.013 Slot local coordinates are 694.00 N 1870.00 E Reference North is True North UNOCAL DILLON Platform,D-17 Middle Ground Shoaks,Cook Intel, Alaska SURVEY LISTING Page 1 Your ref : PHSS <1233-10242'> Last revised : 21-Hay-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 I N A T E S Deg/lOOFt Sect 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 100.00 0.25 310.00 100.00 0.14 N 0.17 W 0.25 0.05 200.00 0.25 306.00 200.00 0.41 N 0.51 W 0.02 0.16 300.00 1.00 276.00 299.99 0.63 N 1.56 ~ 0.79 0.87 343.00 1.25 288.00 342.98 0.81 N 2.37 ~ 0.80 1.42 422.00 2.25 253.00 421.95 0.62 N 4.68~ 1.80 3.38 512.00 2.50 250.00 511.87 0.56 S 8.21 N 0.31 6.92 601.00 2.75 235.00 600.78 2.45 S 11.78W 0.82 10.91 691.00 2.50 220.00 690.68 5.19 S 14.81 ~ 0.81 14.98 779.00 1.75 211.00 778.62 7.82 S 16.74 N 0.93 18.09 869.00 0.50 150.00 868.61 9.33 S 17.25 ~ 1.74 19.41 959.00 0.50 109.00 958.60 9.80 S 16.68~ 0.39 19.23 1052.00 0.75 103.00 1051.60 10.07 S 15.71 W 0.28 18.61 1100.00 0.75 98.00 1099.59 10.18 S 15.09 ~ 0.14 18.18 1233.00 0.65 97.90 1232.58 10.41 S 13.48 W 0.08 17.03 1328.00 0.92 83.60 1327.58 10.40 S 12.19 ~ 0.35 15.99 1421.00 1.10 77.50 1420.56 10.12 S 10.58 W 0.22 14.53 1514.00 0.87 82.20 1513.55 9.83 S 9.00 ~ 0.26 13.10 1606.00 0.70 76.10 1605.54 9.60 S 7.77'W 0.20 11.97 1699.00 0.79 56.90 1698.53 9.12 S 6.68 W 0.28 10.80 1794.00 0.90 59.20 1793.52 8.38 S 5.49 N 0.12 9.41 1979.00 0.58 63.20 1978.50 7.21 S 3.40 W 0.18 7.04 2165.00 0.65 62.10 2164.49 6.29 S 1.63 ~ 0.04 5.07 2352.00 0.19 206.20 2351.49 6.07 S 0.83 W 0.43 4.30 2538.00 0.44 171.60 2537.49 7.06 S 0.86W 0.16 4.91 2698.00 0.50 164.00 2697.48 8.34 S 0.58 W 0.05 2987.00 0.90 236.00 2986.46 10.82 S 2.12 ~ 0.30 3488.00 1.00 134.00 3487.42 16.06 S 2.23 ~ 0.29 3604.00 0.74 243.50 3603.42 17.09 S 2.18 W 1.23 3697.00 0.98 241.80 3696.40 17.74 S 3.41 W 0.26 5.45 8.16 Gyro Single Shot 11.39 Gyro Single Shot 11.96 13.34 3790.00 1.10 246.70 3789.39 18.46 S 4.93 W 0.16 15.00 3884.00 1.10 253.40 3883.37 19.08 S 6.63 ~ 0.14 16.72 3976.00 1.30 263.80 3975.35 19.44 S 8.51 W 0.32 18.45 4069.00 1.40 262.20 4068.33 19.71 S 10.68 W 0.11 20.35 4163.00 1.50 267.80 4162.30 19.92 S 13.05 ~ 0.18 22.37 4255.00 1.70 268.30 4254.26 20.00 S 15.62 W 0.22 24.48 4349.00 1.90 277'.60 4348.21 19.84 S 18.56 W 0.38 26.74 4443.00 1.90 272.70 4442.16 19.56 $ 21.66 W 0.17 29.06 4536.00 2.00 278.50 4535.11 19.25 S 24.80 W 0.24 31.39 4628.00 2.30 281.60 4627.04 18.64 S 28.20 W 0.35 33.75 4720.00 2.40 278.70 4718.97 17.98 S 31.91 W 0.17 36.33 4814.00 2.60 281.20 4812.88 17.26 S 35.95 W 0.24 39.14 4909.00 2.70 281.10 4907.78 16.41 S 40.26 W 0.10 42.08 5001.00 2.70 283.50 4999.67 15.49 S 44.49 W 0.12 44.93 5094.00 3.00 281.50 5092.56 14.49 S 49.01 W 0.34 47.95 5188.00 3.00 286.70 5186.43 13.30 S 53.77 ~ 0.29 51.05 5282.00 3.00 285.90 5280.30 11.92 S 58.50 g 0.04 54.01 5376.00 3.20 288.90 5374.16 10.39 S 63.34 ~ 0.27 56.99 5467.00 3.20 290.70 5465.02 8.67 S 68.12 g 0.11 59.79 5526.00 3.10 279.80 5523.93 7.82 S 71.24 W 1.03 61.77 Att data is in feet unless otherwise stated Coordinates from slot #2-6 and TVD from wellhead (127.00 Ft above mean sea level). Vertical section is from wet[head on azimuth 233.28 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL DILLON PLatform,D-17 Middle Ground Shoals,Cook Inlet, Alaska Heasured [nc[in. Azimuth True Vert. Depth Degrees Degrees Depth 5619.00 3.50 279.10 5616.78 5713.00 3.30 262.00 5710.62 5806.00 4.00 247.80 5803.43 5901.00 5.70 235.80 5898.09 5995.00 7.80 232.00 5991.43 6089.00 10.00 235.60 6084.29 6181.00 11.90 235.80 6174.61 6275.00 13.30 233.30 6266.35 6369.00 15.20 229.10 6357.46 6462.00 16.90 228.90 6446.83 6555.00 18.70 228.90 6535.37 6649.00 19.60 227.90 6624.17 6742.00 21.20 228.00 6711.33 6837.00 22.80 224.40 6799.42 6927.00 24.40 226.80 6881.89 7030.00 24.40 227.60 6975.69 7124.00 24.00 228.10 7061.43 7218.00 23.70 228.20 7147.40 7312.00 23.80 227.30 7233.44 7406.00 23.70 226.80 7319.48 7500.00 23.40 227.60 7405.65 7573.00 23.40 227.70 7472.65 7590.00 23.20 226.90 7488.26 7683.00 22.90 232.40 7573.85 7/'/6.00 23.30 231.60 7659.39 7872.00 25.30 232.50 7746.88 7964.00 25.90 232.90 7829.85 8058.00 25.10 235.50 7914.69 8150.00 25.40 234.90 7997.90 8243.00 25.20 232.90 8081.98 8336.00 25.20 233.50 8166.13 8430.00 24.40 230.40 8251.47 8523.00 25.70 229.20 8335.?2 8617.00 26.70 228.80 8420.06 8710.00 27.31 228.18 8502.92 8808.00 25.98 229.90 8590.51 8901.00 26.10 229.90 8674.07 8996.00 26.27 229.01 8759.32 9089.00 26.03 229.65 8842.80 9183.00 25.68 229.47 8927.39 9276.00 25.08 229.23 9011.42 9369.00 24.33 229.18 9095.90 9470.00 23.90 228.91 9188.09 9547.00 24.7"5 231.17 9258.26 9600.00 24.78 232.44 9306.39 9652.00 25.38 232.44 9353.49 9734.00 29.59 230.56 9426.22 9828.00 36.45 232.74 9504.99 9888.00 36.51 233.42 9553.23 9929.00 37.41 234.09 9586.00 SURVEY LISTING Page 2 Your ref : PMSS <1233-10242'> Last revised : 21-May-94 DogLeg Vert Deg/lOOFt Sect 6.94 S 76.52 W 0.43 65.48 6.86 S 82.03 W 1.10 69.86 8.46 S 87.68W 1.22 75.34 12.37 S 94.65 W 2.07 83.26 18.92 S 103.54 ~ 2.28 94.31 27.46 S 115.30 ~ 2.41 108.84 37.30 S 129.74 ~ 2.06 126.30 49.21 S 146.43 W 1.60 146.80 63.74 S 164.41 W 2.30 169.90 80.61 S 183.82 ~ 1.83 195.54 99.30 S 205.24 ~ 1.94 223.88 119.78 S 228.29 N 1.02 254.61 141.49 S 252.36 W 1.72 286.88 166.14 S 278.01 ~ 2.20 322.18 191.32 S 303.76 ~ 2.07 357.88 220.23 S 334.98 W 0.32 400.19 246.09 S 363.55 ~ 0.48 438.55 271.45 S 391.86 W 0.32 476.41 296.91 S 419.88 ~ 0.40 514.09 322.70 S 447.60 g 0.24 551.72 348.22 S 475.15 W 0.47 589.07 367.75 S 496.58 W 0.05 617.92 · 372.31 S 501.52 W 2.20 624.61 395.87 S 529.23 ~ 2.34 660.91 418.33 S 557.98 ~ 0.55 697.38 442.62 S 589.14 W 2.12 736.88 466.70 S 620.76W 0.68 776.63 490.38 S 653.57 W 1.46 817.08 512.78 S 685.79W 0.43 856.30 536.19 S 717.90 ~ 0.94 896.04 559.91 S 749.61 g 0.27 935.64 584.19 S 780.66 W 1.62 975.04 609.62 S 810.73 W 1.50 1014.34 636.84 S 842.04 W 1.08 1055.73 664.83 S 873.66 W 0.72 1097.81 693.65 S 906.84 W 1.57 1141.63 719.95 S 938.07 ~ 0.13 1182.39 747.20 S 969.92 ~ 0.45 1224.21 773.91 S 1001.01 W 0.40 1265.10 800.50 S 1032.21 ~ 0.38 1306.01 826.47 S 1062.45 W 0.65 1345.78 851.86 S 1091.88 g 0.81 1384.55 878.91 S 1123.04 W 0.44 1425.70 899.26 S 1147.35 W 1.62 1457.35 912.98 S 1164.79 g 1.01 1479.53 926.42 S 1182.26 ~ 1.15 1501.57 950.00 S 1211.84 W 5.24 1539.38 981.69 S 1252.04 W 7.40 1590.55 1003.12 S 1280.56 W 0.68 1626.22 1017.69 S 1300.44 W 2.40 1650.87 Att data is in feet unless otherwise stated Coordinates from stol #2-6 and TVO from wellhead (127.00 Ft above mean sea Level). Vertical section is from wellhead on azimuth 233.28 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL DILLON Platform,D-17 Hiddle Ground Shoals,Cook Inlet, Alaska SURVEY LISTING Page 3 Your ref : PHSS <1233-10242'> Last revised : 21-Hay-94 Heasured Inc[in. 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 I N A T E S Deg/lOOFt Sect 10022.00 43.88 235.89 9656.52 1052.38 S 1350.06 W 7.07 1711.38 10101.00 49.45 235.91 9710.72 108~.58 S 1397.62 W 7.05 1768.76 10190.00 53.40 236.00 9766.20 1123.52 S 1455.27 ~ 4.44 1838.25 10242.00 55.71 236.00 9796.36 1147.21S 1490.38 ~ 4.44 1880.56 Projected Data - NO SURVEY All data is in feet unless otherwise stated Coordinates from slot #2-6 ar,~ TVD from wellhead (127.00 Ft above mean sea level). Vertical section is from wellhead on azimuth 233.28 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL DILLON PLatform,D-17 HiddLe Ground Shoals,Cook Inlet, Alaska SURVEY LISTING Page Your ref = PHSS <1233-10242"> Last revised = 21-Hay-94 Co~nents in wel[path MD TVD Rectangular Coords. Con~nt 2987.00 2~86.46 10.82 S 2.12 W Gyro Single Shot 3488.00 3487.42 16.06 S 2.23 W Gyro Single Shot 10242.00 ~7~6.36 1147.21S 1490.38 ~ Projected Data - NO SURVEY Targets associated with this weLLpath Target na~e Position T.V.D. Local rectangular coords. Date revised 17 TARGET #-5 not specified 10077.00 1819.41S 2447.91g 22-Hat-94 17 Hid G-4a Possible not specified WO0.O0 1255.60S 168~.2~ 22-Hat-94 17 G-1 Possible not specified 9350.00 956.65S 1282.51g 22-Nar-94 ALL data is in feet unless otherwise stated Coordinates fro~ slot #2-6 and TVO fro~ wellhead (127.00 Ft above mean sea Level). Botto~ hole distance is 1880.78 on azimuth 23Z.41 degrees from wellhead. Vertical section is fro~ wellhead on azimuth 233.28 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minim[zn curvature method. Presented by Baker Hughes INTEQ UNOCAL DZLLON PLatform O17st1 slot #2-6 Middle Ground Shoals Cook ]nlet, Alaska SURVEY LISTING Baker Hughes I NTEQ Your ref : PNSS <9763-11484'> Our ref : svy4428 License : Date printed : 3-Jun-9A Date created : 21-May-9~ Last revised : 3-Jun-g& Field is centred on n60 50 4.803,u151 29 11.941 Structure is centred on n60 44 0.841,u151 31 22.418 SLot Location is n60 4~ 7.674,u151 30 ~.809 SLot Grid coordinates are N 2463865.846, E 229317.01~ Stol Local coordinates are 694.00 N 1870.00 E Reference North is True North UNOCAL DILLON P[atform,D17st1 Hidd[e Ground Shoals,Cook Inlet, ALaska SURVEY LISTING Page 1 Your ref : PHSS <9763-11484'> Last revised : 3-Jun-94 Measured Inc[in. 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 I N A T E S Deg/lOOFt Sect 9652.00 25.38 232.44 9353.49 926.42 S 1182.26 W 1.15 9763.00 28.68 238.73 9452.37 954.76 S 122~.90 W 3.93 9864.00 36.80 242.20 9537.26 981.49 S 1271.46 W 8.25 9921.00 39.67 242.00 9582.03 998.00 S 1302.64 ~ 5.04 10014.00 44.38 239.73 9651.10 1028.35 S 1356.97 ~ 5.32 1501.57 Tie-in to Original Hole 1551.90 1606.00 1640.86 1702.56 10108.00 49.90 237.20 9715.02 1064.43 S 1415.63 W 6.19 1771.15 10202.00 54.70 235.00 9772.49 1105.93 $ 1477.31 W 5.43 1845.40 10294.00 57.80 236.10 9823.60 1149.19 S 1540.39 ~ 3.51 1921.83 10360.00 61.50 234.80 9856.94 1181.49 S 1587.28 ~ 5.86 1978.7'5 10442.00 67.36 233.68 9892.32 1224.71 S 1647.27 ~ 7.25 2052.66 10548.00 7'5.17 234.58 9928.10 1283.14 S 1728.09 ~ 5.54 2152.37 10642.00 74.10 234.87 9954.58 1335.22 S 1801.72 W 1.03 2242.54 10736.00 76.19 235.41 9978.68 1387.15 S 1876.27 ~ 2.29 2333.34 10828.00 77.53 235.43 9999.59 1438.00 S 1950.03 ~ 1.46 2422.87 10923.00 78.55 236.31 10019.28 1490.14 S 2026.96 ~ 1.40 2515.71 11015.00 79.69 236.30 10036.65 1540.26 S 2102.13 ~ 1.24 2605.93 11141.00 81.52 235.75 10057.21 1609.72 S 2205.21 W 1.51 27~0.09 11235.00 82.93 235.65 10069.93 1662.21 S 2282.15 ~ 1.50 2823.14 11266.00 83.13 236.73 10073.69 1679.33 S 2307.72 ~ 3.52 2853.87 11337.00 81.92 237.07 10082.93 1717.77 S 2366.69~ 1.77 2924.12 11402.00 80.82 237.83 10092.68 1752.35 S 2420.86 ~ 2.05 2988.22 11484.00 79.43 237.83 10106.74 1795.36 S 2489.24 W 1.69 3068.75 Projected Data - NO SURVEY ALl data is in feet unless otherwise stated Coordinates from slot #2-6 and TVD from wellhead (127.00 Ft above mean sea Level). Vertical section is from wellhead on azimuth 233.28 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL SURVEY L]ST]NG Page D]LLON P[atform,D17st1 Your ref : PHSS <9763-11484'> HiddLe Ground Shoals,Cook ]nLet, Alaska Last revised : 3-Jun-94 Comments in wet[path ND TVD Rectangular Coords. Comment 9652.00 9353.49 926.42 S 1182.26 W Tie-in to Original Hote 11484.00 10106.74 1795.36 S 2489.24 W Projected Data - NO SURVEY Targets associated with this wet[path Target name Position T.V.D. Loca[ rectangular coords. Date revised 17 TARGET fi3 not specified 10077.00 1819.41S 2447.91U 2Z-Her-94 17 Hid G-4a Possibte not specified ~00.00 1255.60S 1683.2~ 22-Hat-94 17 G-1 Possible not specified 9350.00 956.65S 1282.51U 22-Hat-94 Ali data is in feet un[ess otherwise stated Coordinates from slot #2-6 and TVD from wet[head (127.00 Ft above mean sea lever). Bottom hole distance is 3069.14 on azimuth 2~4.20 degrees from wet[head. vet[ica[ section is from wetthead on azimuth 233.28 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Catcutation uses the minimumcurvature method. Presented by Baker Hughes [NTEG MEMORANDbM TO: · State ," Alaska David Johann/ Chairma'd,~ THRU: Blair Wondzell, ~ FILE NO: P. I. Supervisor Alaska Oil and Gas ConServation Commission DATE: April 27, 1994 AVDJD1BD.DOC FROM: Lou Grimaldi, SUBJECT: Petroleum Inspector BOP test Pool Rig #428 Unocal well # Dillon 17 Middle Ground Shoal Field PTD # 94-56 , Tuesday, April 26, 1994: I traveled to Unocars Dillon platform to witness the initial BOP test on Pool rig # 428. When I arrived the Rig was skidding back over the hole. We tested the choke manifold this evening with all valves passing. We then stood by until the stack was nippled up. Wednesday, April 27,1994: The stack and floor valves were tested with all equipment functioning properly and holding its pressure tests. The accumulator passed its function test with a 2 minute and 15 second recharge time. Chuck Sheavey (Pool Toolpusher) performed a good BOP test that insured all BOPE recieved a proper function and pressure test. This test is indicitive of the condition of this rig and the personnel who man it, I find that this operation is one of the best running at this time. Summary: I witnessed initial BOP test on Pool rig # 428. Test time 2 hours, No failures. Attachment: AVDJD1BD.XLS OPERATION: Drlng X Drlg Contractor: Operator: Well Name: Casing Size: 18 5/8 Test: Initial X STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Workover: Pool Arctic Rig No. 428 PTD # Unocal Rep.: Dillon #17 Rig Rep.: Set ~ 1,133 Location: Sec. Weekly Other 94-56 DATE: Rig Ph.# Don Byrne ! Shane Houck Chuck Sheavey 35 T. 8N R. 13W Meridian Seward MISC. INSPECTIONS: Location Gen.: OK Housekeeping: OK (Gen) Reserve Pit NV~ TEST DATA , , , , , , ,,, ,, , , ,, , , , , Well Sign OK Drl. Rig OK BOP STACK: Annular Preventer Pipe Rams Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve Test Quan. Pressure I 250\1500 P/F P P 250\3000 250\3000 P 250\3000 P 250\3000 P 250\3000 P 250\3000 P N~A NH MUD SYSTEM: Visual Trip Tank P Pit Level Indicators P Flow Indicator P Gas Detectors P Alarm P P P P FLOOR SAFETY VALVES: Upper Kelly / IBOP Lower Kelly / IBOP Ball Type Inside BOP Test Quan. Pressure P/F 1 25O\3O0O P I 250\3000 P 2 250\3000 P I 250\30o0 P CHOKE MANIFOLD: No. Valves 15 I No. Flanges 318 Manual Chokes Hydraulic Chokes 2. Test Pressure 250\3000 250\3000 P/i= P P P P ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure System Pressure Attained Blind Switch Covers: Master: Nitgn. Btl's: Eleven Bottles 2,950 I P 1,800 P minutes 53 sec. minutes 15 sec. Remote: X 2150 Average Psig. Nu~nber of Failures: TEST RESULTS 0 ,Test Time: 2.5 Hours. Number of valves tested 29 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 279-1433 REMARKS: Good Test, Rig well prepared. Distribution: orig-Well File c - Oper./Rig c - Database c - Trip Rpt File c - Inspector F1-021L (Rev. 7/19) STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO AVl Waived By: W~nessed By: ID1BD.XLS Louis R Grimaldi Memorandum State of Alaska Oil and Gas Conservation Commission To: Commission Fm~ Subj' J. Hart~" Unocal Request for Diverter Waiver and Batch Drilling Middle Ground Shoal Platform Dillon Wells 16 and 17 April 11, 1994 Unocal has requested a waiver of diverter requirements on the subject wells. They propose to drill the conductor hole to 1100' with a flow niipple then drill the surface hole to 3500' with a 20 3/4" 3000 psi. BOPE system. They state in their application letter that the fracture gradient anticipated at the surface and intermediate casing shoes are .80 psi/foot and the rock is competent enough to shut in the well and circulate a kick rather than divert. The fracture gradients are based on recent leak off tests done in the Cook Inlet area tabulated in the permit application. I reviewed 5 wells which offset the subject wells. There were no shallow gas kicks, abnormal pressure or lost circulation noted in the wells reviewed. Platform Dillon is in the southern portion of the field at the structural low point. Unocal states that there is no gas above 1100' in the vicinity of the Dillon platform based on the information available to them. Regulation 20 AAC 25.035 (b) (3) and (c) (2) authorizes the Commission to waive diverter requirements if drilling experience in the near vicinity indicates a diverter system is not necessary. The same approach and arguments were used to waive diverter requirements on Granite Pt. 42 and wells Ba-28, Ba-29 and Ba-30. The proposal to drill the surface hole to 1100' with a drilling nipple means there is no annular preventer to divert the well and returns go straight to the shakers and pits. For the hole sections from 1100-3500', their permit application shows a 20 3/4" BOP system that has a diverter spool and a 2000 psi annular preventer which is shown to be blinded off and not used. Unocal believes the diverter is not appropriate and would rather use positive control measures and shut in on kicks given the formation is competent. Batch drilling entails doing segments of the two wells consecutively. As each section of the hole is completed and cased the well will be secured with a wellhead assembly, flanged such that there is a drill pipe connection and gauge to monitor the shut in well. This drilling procedure is innovative and is similar to an operations shutdown. I would advocate a stipulation in the permit allowing this method and waive application for operations shutdown after each hole segment conditioned on securing the well (which they plan to do anyway). In summary, drilling history indicates no shallow gas has been encountered at the Dillon platform. A review of AOGCC well histories on five wells in the vicinity of the 2 proposed wells indicated Page 2 no shallow gas, kicks or lost circulation zones. Most recent drilling at Dillon occurred in 1976. The section of hole drilled from the structural pipe to the conductor depth of 1100' RKB would be done without any means to divert. Drilling from 1100' RKB to total depth would be accomplished with BOP equipment. Recommendation: Absent shallow gas and other notable drilling problems in the vicinity of the wells to be drilled, I recommend approval of the waiver of diverter requirements. If there are other circumstances which the Commission thinks would cause a need for diverter use, Unocal should be allowed to address those circumstances. The batch drilling procedure should be approved with a stipulation that each casing segment be secured prior to moving the rig to the next well,which they plan to do. I don't recommend requiring a 10-403 (operations shutdown) for each segment in that it requires at least 4 filings and operations will be resumed within 60 days baring unforeseen circumstances. Alaska Unocal Energy Resourc~vision Unocal Corporation 909 West 9th Avenue, RO. box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 April 6, 1994 UNOr L Mr. Bob Crandall Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 SOUTH MIDDLE GROUND SHOAL Dear Bob: After reviewing the shallow hydrocarbon potential of the South Middle Ground Shoal area we have made the fOllowing observations' . . No hydrocarbon production from zones shallower than Hemlock has ever existed at SMGS. Only ten sands shallower than Hemlock have been tested at SMGS. Tests were conducted on seven Tyonek sands from 5702' to 8962' in SMGS #6 when Amoco was looking for a gas supply. No hydrocarbons were recovered. Three sands were tested from 7986' to 9160' in SMGS #2. GTS in 5 1/2 hour was recovered from one of the tests. 3. No tests have been conducted shallower than 5702'. , Some zones deeper than 3000' appear to have hydrocarbon potential based on Icg analyses. -,., The section shallower than 3000' appears to be fairly shaley and generally tight. Unocal possesses no mudlogs from SMGS and is presently searching for them in the State of Alaska files. Any new information or interpretations we mak_eif_we RE¢£i V rr' L)' APR -- B 1994 Alaska Oil & Gas Cons. Commission Anchorage Mr. Bob Crandall April 6, 1994 Page 2 acquire any of the missing mudlogs will be reported to you immediately. We should know if mudlogs are attainable within one week. 7. Unlike the Platform Baker area, eight miles to the north and 2000' updip, which contains rich, stacked hydrocarbon deposits from 1000' to 10,000'+, SMGS probably has very little shallow hydrocarbon potential. Unocal intends to mudlog the first well (SMGS Cf 17) from surface to TD in order to more fully evaluate the shallow hydrocarbon potential &~ SMGS. If you have any questions or comments, give me a call at: 263-7699. Sincerely, Geologic Development Advisor DTS:dma RECEIVED /~PR - 8 1994 Alaska Oil & Gas Cons. Gommisslon Anchorage Unocal Energy Resource~'"~vision Unocal Corporation I ! 909 West 9th Avenue, R O. B,.,,~ 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL Alaska April 6, 1994 Mr. Bob Crandall Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 SOUTH MIDDLE GROUND SHOAL Dear Bob: ............ .................... After reviewing the shallow hydrocarbon potential of the South Middle Ground Shoal area we have made the following observations: . No hydrocarbon production from zones shallower than Hemlock has ever existed at SMGS. . Only ten sands shallower than Hemlock have been tested at SMGS. Tests were conducted on seven Tyonek sands from 5702' to 8962' in SMGS #6 when Amoco was looking for a gas supply. No hydrocarbons were recovered. Three sands were tested from 7986' to. 9160' in SMGS #2. GTS in 5 1/2 hour was recovered from one of the tests. 3. No tests have been conducted shallower than 5702'. . Some zones deeper than 3000' appear to have hydrocarbon potential based on log analyses. 5. The section shallower than 3000' appears to be fairly shaley and generally tight. . Unocal possesses no mudlogs from SMGS and is presently searching for them in the State of Alaska files..Any new information or interpretations we m_a_k.e_if[~we 0ii & Gas Cons, C0mmissl0~ Anchorage Mr. Bob Crandail April 6, 1994 Page 2 acquire any of the missing mudlogs will be reported to you immediately. We should know if mudlogs are attainable within one week. 7, Unlike the Platform Baker area, eight miles to the north and 2000' updip, which contains rich, stacked hydrocarbon deposits from 1000' to 10,000'+, SMGS probably has very little shallow hydrocarbon potential. Unocal intends to mudlog the first well (SMGS Cf17) from surface to TD in order to more fully evaluate the shallow hydrocarbon potential at SMGS. If you have any questions or comments, give me a call at: 263-7699. Danie~ T. S e a~'o"u'n'( Geologic Development Advisor DTS:dma RECEIVED APR -8 1994 Alaska Oil & Gas Cons, Commission Anchorage Unocal North Americax'T~ Oil & Gas Division I ? Unocal Corporation I ' P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL Alaska Region April 6, 1994 Mr. David Johnston Commissioner Alaska Oil & Gas Conservation Commissioner 3001 Porcupine Drive Anchorage, AK. 99501-3192 Dear Mr. Johnston: Please find enclosed applications for a Permit to Drill (Form 10-401) for the Dillon Platform wells #16 & 17, The timing to spud these wells is approximately mid April when the ongoing rig move from the Baker Platform will be completed. As part of this continued development drilling program UNOCAL is requesting that the AOGCC waive the diverter system requirement on both the (30") structural and (18-5/8") surface casing strings for both wells. This waiver request is similar to our August 1993 request for wells #28, 29, & 30 at the Baker Platform which was subsequently approved by the AOGCC. As outlined in each well procedure, UNOCAL is intending to drill out the 30" structural casing to :t:1100' with a flow nipple then install a 20- 3/4" 3M BOPE stack on th6 18-5/8" casing that will be cemented at :!:1100' to surface. The 18-5/8" casing will then be drilled out to a depth of+3500' and 13-3/8" intermediate casing will be cemented from that depth to surface. UNOCAL has selected the casing points for the 18-5/8" at +1100' and the 13-3/8" at :!:3500' to be areas of competent formations. No gas bearing zones are evident above :!:1100', based on offset well data. It is anticipated that the minimum formation fracture gradients at both shoe depths to be 0.80 psi/ft. UNOCAL's recent experience in the Middle Ground Shoals Field at the Baker Platform and elsewhere in the Cook Inlet (see Leak Off Test Data) has demonstrated true fracture gradients ranging from 0.75 - 0.94 psi/ft. In both wells at Dillon the maximum surface pressure (MSP) expected while drilling below the 18- 5/8" surface casing will be far less than the anticipated fracture pressures. Since the casing shoes will not break down in a well kick situation and the setting depths are in competent formations, UNOCAL believes these are prudent casing designs and warranted operations. RECEIVED APR -7 1994 Alaska 0il & Gas Cons. Commission Anchorage Mr. David Johnston April 6, 1994 Page - 2 UNOCAL plans to complete Dillon//16 & 17 with a hydraulic pumping completions; these wells are expected to require artificial lift for production of oil reserves. An outline of how UNOCAL plans to safely and economically produce these wells will be submitted under a separate cover. Additionally, hydrogen sulfide gas is known to be produced in existing wells at Dillon. Drilling operations at Dillon will be conducted in compliance to AOGCC regulation 20 AAC 25.065 and API RP 49 prior to drilling out the 13-3/8" casing string at :k3500'. If you should have any questions regarding these permits please contact C. Lee Lohoefer (Senior Drilling Engineer) assigned to this project. Thank you for your attention to these matters. Sincerely, t3. Russell Schmidt Drilling Manager CLL/cll enclosure: RECEIVED APR -7 1994 Alaska Oil & 13as Cons. Commission Anchorage ALASKA OIL AND GAS CONSERVATION COMMISSION April 7, 1994 ADMINISTRATIVE APPROVAL NO. 44.55 WALTER J. HICKEL, GOVERNOR .. 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99S01-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 Re: The application of Unocal Corporation to drill, complete and produce the Middle Ground Shoal Dillion No. 17 well in the Middle Ground Shoal Field. G. R. Schmidt Drilling Manager North American Oil and Gas Division Unocal Corporation P. O. Box 190247 Anchorage, Alaska 99519-0247 Dear Mr. Schmidt: The referenced application was received on April 7, 1994. The Middle Ground Shoal Dillion No. 17 well is to be drilled to the steeply dipping west flank of the reservoir.- 'Structural complexities in this portion of the field require producers to be drilled at less than 80-acre spacing to insure adequate drainage. The subject well will be the third producer in a governmental quarter section. The Alaska Oil and Gas Conservation Commission has reviewed the evidence available and hereby authorizes .the drilling, completion and production of the referenced well pursuant, to Rule 6 of Conservation Order No. 44. Sincerely, Commissioner BY ORDER OF THE COMMISSION ~.~ 'Pd,,iod on ~'ec. ycled pai,e, b y C D ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOFI 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 278-7542 April 13, 1994 G. Russell Schmidt Alaska Business Unit Drlg Mgr Union Oil Company of California (UNOCAL) P O Box 196247 Anchorage, AK 99519-6247 Re: Chakachatna Dillon No. 17 UNOCAL Permit No: 94-56 Surf Loc: Dillon Pltfm Leg #2, Slot f/6, 694'FSL, 1870'FWL, Sec 35, T8N, R13W, SM Btmhole Loc: 11325'MD/10027'TVD, 1239'FNL, 722'FEL, Sec 3, T7N, R13W, SM Dear Mr. Schmidt: Enclosed is the approved application for permit to drill the above referenced well. The Commission grants your request to waive the diverter requirements on both the 30" structural casing and the 18 5/8 surface casing. It is understood that UNOCAL will install a flow nipple on the structural casing and a 3M BOPE stack on the surface casing in lieu of the diverter. Your proposed packerless completion is approved contingent on the well not being capable of flow to the surface. The permit to ddll does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting ddlling 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 C.' Department of Fish & Game, Habitat Section w/o encl Department of Environmental Conservation w/o encl ~"--,, -S'FATE OF ALASKA ALASKA ~;i~ -AND GAS CONSERVATION COMi~.JSION PERMIT TO DRILL 20 AAC 25.005 la. Type of work Drill [] Redrill ~ 1 lb. Type of well. Exploratory [] Stratigraphic Test r-] Development Oil Re-Entry r--I Deepen r--II Service I-1 Development Gas r-] single Zone r-I Multiple zone 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool Union Oil Comapny of California (UNOCAL) 127' RKB ABOVE MSL feet Middle Ground Shoals 3. Address 6. Property Designation E,F & G Pool P.O. Box 196247, Anchorage, AK 99519-6247 ADL 18746 4. Location of well at surface Dillon Pit. Leg #2, Slot #6 7. Unit or property name 11. Type Bond (SEE 20ACC25.025) 694' FSL & 1870' FWL SECTION 35, T8N, R13W, S.M. CHAKACHATNA UNITED PACIFIC INS. CO. At top of productive interval 9608' MD / 9350' 'I'VD 8. Well number Number 376' FNL & 435' FWL SECTION 2, 'I'TN, R13W S.M. Dillon #17 U62-9269 At total depth 11325' MD / 10027' TVD 9. Approximate spud date Amount 1239 FNL & 722' FEL SECTION 3, T7N, R13W, S.M. April 15, 1994 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (~ ~,,~ TVD) property line 4600 feet 4' @ SURFACE feet 3200_ 11326' MD / 10027' TTeet 16. To be completed for deviated wells 17. Anticipated Pressure(~ee 2o AAC 25.085 (e)(2)) Kickoff depth 3000 feet 91 Maximum hole angle M~d,,umsur~co 902 psig At total depth (l'VD) 4512 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) 24" 18-5/8" 97 X56 QTE60 1031 69 69 1100 1100 3000 cu.ft. 17-1/2" 13-3/8" 68 K55 BUTT 3431 69 69 3500 3497 3750 cu.ft. 12-1/4" 9-5/8" ,47 L80 BuI-r 9431' 69 69 9500 9246 2400 cu.ft. 8-1/2" 7" 29 L80 BUrl' 2125 9200 8958 11326 10027 800 cu.ft. -19. To be completed for Redrill, Re-entry, and Deepen Operations Present well condition summary Total depth: measured 317 feet Plugs (measured) true vertical 317 feet Effective depth: measured 317 feet Junk (measured) true vertical 317 feet Casing Length Size Cemented Measured depth True vertical depth Structural 259 30" DRIVEN 317 RKB (88' BML) Conductor Surface IntermediateR£C£1V£D Production Liner APR -7 1994 Perforation depth: measured true vertical A~j~sV,~ Liit& Gas Cons. C0mmissio~ Anchorage , , 20. Attachments Filing fee [~ Property plat J-J BOP SketchJ] Diverter Sketch J~ Drilling program J~ Drilling fluid program J~ Time vs depth plot J~ Refraction analysis J-J Seabed report J--J 20 AAC 25.050 requirements J-J 21 .I hereby c~fy~[~.~re~3~g, i<~jnd correct to the best of my knowledge Signed G. RUSSELL SCHMIDT Title Alaska Business Unit Drilling Manager Date Commission Use Only Permit Number J API number Approva,,l~:lat)~ See cover letter ~,~'-_ ~,~~ 50- 73',.~' --. ~.. ~ Z/',5" (~ N'//. ~/~Zv' for other requirements Conditions of approval Samples required [-] Yes ,~ No Mud Icg re'~ru[re~ ' /[~] Yes'-~ No Hydrogen sulfide measures ~ Yes ~:~ No Directional survey required ~ Yes [--1 No Required working pressure for DOPE'~ 2M; ]~ 3M; ~ SM; r-1 1OM; [] 15M Other: Uriginal Signed By by the order of Approved by '.~av,d W. Johnston Commissioner the commission Date ~'//.3 Form 10-401 Rev. 12-1-85 Submit in tri[ Dillon Well #17 March 29, 1994 Time Est. Preliminary Procedure: 1.5 1.5 1.5 2 3.5 2 1. MIRU, Leg #2, Conductor #7, Install 30" flow riser system. 2. Drill 17-1/2" hole to 18-5/8" csg point of+Il00'. 3. Open hole from 17-1/2" to a 24" section. 4. Run and cement 18-5/8" casing. Install 20" BOPE. 5. Drill 17-1/2" hole to 13-3/8" csg point ±3500' (ROP 700') 6. Run and cement 13-3/8" casing. Install 13-5/8" BOP 12 days total (Batch drilling) 7. Drill 12-1/4" hole to 9-5/8" csg. point at the top of the Hemlock; (ROP 275') KOP DLS Angle Range 22 3000' 2.0 0-17° 8. Run open hole logs. 9. Run and cement 9-5/8" casing to 9500' MD. 10. Drill 8-1/2" hole to TD; LWD will be utilized (ROP 225') KOP DLS Angle Range Tot. Dogleg TD ±9500' 6.94 1%90° 92° ±11350' 2 1.5 1.5 1 0.5 1 1 11. Run and cement 7" liner from TI) to 9200' MD. 12. Clean out inside liner. 13. Run SBT/GR log on 7" liner, optional on 9-5/8". 14. Change well over to 3% KCL fluid or diesel. 15. Run 4-5/8" TCP guns in combination with dual 3-1/2" tbg. 16. Run dual 3-1/2" tbg completion with KOBE BI-LA. 17. Set BPV, Rem BOPE, Install tree and surface equipment. 18. Release Rig. 19. Produce well to obtain underbalance, detonate TCP guns. 55 days total time Filename:Dillon~P017. doc RECEIVED APR - 7 1gq4 A~aska ~lt 8, Gas Cons. (3ommission Anchorage Depth 0 Dillon 17 NEW WELL Depth vs. Days March 30, 1994 Run 18-5/8" Csg (2,000) Avg ROP 700 FPD (4,000) Run 13-3/8" Csg (6,ooo) Avg ROP 275 FPD (8,000) (10,000) (12,000) I 10 , I , I 2O 30 Estimate Log & Run 9-5/8" Csg Avg ROP 225 FPD Run 7" Liner & Completion I ~ I , I ~ I 50 60 70 40 Days Actual Ga,~ Grins. Commissio~ Anchorage IKOBE BHA 30" Structural @ 88' BLM 18-5/8" Surface @ 1100' ~, 97#, X-56, QTE60 MISC. DATA RKB = 127' WATER DEPTH = 102' 13-3/8" Intermediate @ 3500' 68#, K-55, BTC COMPLETION DESCRIPTION 1) Dual 3-1/2", 9.2#, L-80, SCBTC 2) KOBE BHA @ 9300' 3) TCP guns 4-5/8" OD net 1000' 9-5/8" Production @ 9500' 47#, L-80, BTC Hemlock @ Intervals + 1000' 7" Liner @ 11325' 29#, L80, BTC RECEIVE APR -7 199~ 0il & Gas Cons. Co~ Anchorage DILLON 17 PROPOSED COMPLETION UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 3-30-94 ~mission UNOCAL 800 'Created by : jones For: L LOHOEFERI Dote potted : 25-Mar-94 i Structure : DILLON Platform Well : 17 [Plot Reference is 17 Version #3. i I . iCoord~notes are in feet reference slot #2-6.i iTrue Vertical Depths are reference wellhead, i ~Field : Middle Ground Shoals Location : Cook Inlet, Alaska ~' ~ ~' WELL PROFILE DATA --- Baker Hughes INTEQ ....... ~e on 0 0.~ 235.28 O 0 0 0,~ IK~ ~ 0.~ 2~.28 ~ 0 0 0.~ End of 8ui~ 3840 1~.802~3.28 3828 -T3 -g8 2.00I RKB EL~ATION: 127' Torge[ 9608 1~.80233.28 g3~ -1070 -1~35 0.~ ]Target 10+16 72.8823~,28 1200 1600_ _ 2000_ L 18 5//8" Casing Pt 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 9600 10000i 10400 S 53.28 DEG W 3234' (TO TD) < - - W e s f Soo,e I : oo.oo 2800 2600 2400 2200 2000 1800 1600 1400 1200 1000 800 600 400 200 0 200 I I, I II II II II II II II II II II II II I I I 200 KOP SURFACE LOCATION: 4.00 BUILD 2 DEC / 100' 694' FSL, 1870' FWL / 8.00 R1 W /~' 1 13 3/8" Casing Pt SEC___~ 35, TSN,~ ~ 2 O0 EG Z 2000 TARGET #1 ~% 1 ' TARGET #1 -~ ~. BUILD 7 DEC /00' ~ N~' ~ =~ = BUILD 2 DEC / 100' ~~ TB / 7" Casing Pt 600 (~O 0 ~1o00 I =l=oo I RECEIVED 0 400 800 12 1 0 20 0 2400 3 3600 Scale 1 : 200.00 Vertical Section on 23.~.28 azimuth wlth reference 0.00 H, 0.00 E fram slot #2-6 FINAL ANGLE 91 DEC APR -7 1994 u',l & Gas Cons. 6ommissio~ Anchorage UNOCAL DILLON PLatform 17 slot #2-6 Middle Ground Shoals Cook Inlet, Alaska PROPOSAL LISTING by Baker Hughes INTEQ Your ref : 17 Version #3 Our ref : prop1032 License : Date printed : 25-Mar-94 Date created : 22-Mar-94 Last revised : 25-Mar-94 Field is centred on n60 50 4.803,w151 29 11.941 Structure is centred on n60 44 0.841,w151 31 22.418 Slot location is n60 44 7.674,w151 30 44.809 Slot Grid coordinates are N 2463865.846, E 229317.013 Slot local coordinates are 694.00 N 1870.00 E Reference North is True North RECEIVED APR - 7 19q4 Alaska Uti & Gas Cons. ~;ommission Anchorage UNOCAL DILLON Platform, 17 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 1 Your ref : 17 Version #3 Last revised : 25-Mar-94 Measured Inc[in. 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 I N A T E S Deg/lOOFt Sect 0.00 0.00 233.28 0.00 0.00 N 0.00 E 0.00 0.00 500.00 0.00 233.28 500.00 0.00 N 0.00 E 0.00 0.00 1000.00 0.00 233.28 1000.00 0.00 N 0.00 E 0.00 0.00 1100.00 0.00 233.28 1100.00 0.00 N 0.00 E 0.00 0.00 1500.00 0.00 233.28 1500.00 0.00 N 0.00 E 0.00 0.00 2000.00 0.00 233.28 2000.00 0.00 N 0.00 E 0.00 0.00 2500.00 0.00 233.28 2500.00 0.00 N 0.00 E 0.00 0.00 3000.00 0.00 233.28 3000.00 0.00 N 0.00 E 0.00 0.00 3100.00 2.00 233.28 3099.98 1.04 S 1.40 W 2.00 1.74 3200.00 4.00 233.28 3199.84 4.17 $ 5.59 W 2.00 6.98 3300.00 6.00 233.28 3299.45 9.38 S 12.58 ~ 2.00 15.69 3400.00 8.00 233.28 3398.70 16.67 S 22.35 W 2.00 27.88 3500.00 10.00 233.28 3497.46 26.02 S 34.89 U 2.00 43.52 3600.00 12.00 233.28 3595.62 37.42 S 50.18 ~ 2.00 62.60 3700.00 14.00 233.28 3693.06 50.87 S 68.22 W 2.00 85,10 3800.00 16.00 233.28 3789.64 66.34 S 88.96 ~ 2.00 110.98 3840.26 16.80 233.28 3828.26 73.14 S 98.08 ~ 2.00 122.34 4000.00 16.80 233.28 3981.18 100.75 S 135.10 W 0.00 168.53 4500.00 16.80 233.28 4459.83 187.17 S 250.98 W 0.00 313,09 5000.00 16.80 233.28 4938.48 273.59 S 366.86 W 0.00 457.65 5500.00 16.80 233.28 5417.12 360.01 S 482.74 U 0.00 602.21 6000.00 16.80 233.28 5895.77 446.43 S 598.63 ~ 0.00 746.76 6500.00 16.80 233.28 6374.42 532.86 S 714.51 ~ 0.00 891.32 7000.00 16.80 233.28 6853.06 619.28 S 830.39 U 0.00 1035.88 7500.00 16.80 233.28 7331.71 705.70 S 946.28 W 0.00 1180.44 8000.00 16.80 233.28 7810.36 792.12 S 1062.16 W 0.00 1325,00 8500.00 16.80 233.28 8289.00 878.54 S 1178.04 ~ 0.00 1469,56 9000.00 16.80 233.28 8767.65 964.96 S 1293.92 W 0.00 1614,12 9500.00 16.80 233.28 9246.30 1051.38 S 1409.80 W 0.00 1758.68 9608.33 16.80 233.28 9350.00 1070.10 S 1434.91 W 0.00 1790,00 9666.32 20.83 233.28 9404.88 1081.28 S 1449.90 W 6.94 1808.70 9766.32 27.78 233.28 9495.96 1105.88 S 1482.88 ~ 6.94 1849.84 9866.32 34.72 233.28 9581.40 1136.87 S 1524.44 ~ 6.94 1901.68 9966.32 41.66 233.28 9659.95 1173.81 S 1573.97 ~ 6.94 1963,47 10066.32 48.61 233.28 9730.45 1216.16 S 1630.76 W 6.94 2034.30 10166.32 55.55 233.28 9791.86 1263.29 S 1693.95 W 6.94 2113,14 10266.32 62.50 233.28 9843.30 1314.51 S 1762.64 W 6.94 2198.83 10366.32 69.44 233.28 9884.00 1369.08 S 1835.81 W 6.94 2290.11 10415.88 72.88 233.28 9900.00 1397.11 S 1873.40 W 6.94 2337.00 10456.79 73.70 233.28 9911.76 1420.54 S 1904.82 W 1.99 2376,19 10556.79 75.69 233.28 9938.16 1478.20 S 1982.13 W 1.99 2472.63 10656.79 77.68 233.28 9961.19 1536.37 S 2060.13 W 1.99 2569.94 10756.79 79.67 233.28 9980.83 1594.99 S 2138.73 W 1.99 2667,99 10856.79 81.66 233.28 9997.04 1653.98 S 2217.83 ~ 1.99 2766.66 10956.79 83.66 233,28 10009.82 1713.26 S 2297.33 W 1.99 2865.84 11056.79 85.65 233.28 10019.14 1772.78 S 2377.14 ~ 1.99 2965,39 11156.79 87.64 233.28 10025.00 1832.46 S 2457.16 U 1.99 3065.22 11256.79 89.63 233.28 10027.38 1892.22 S 2537.30 ~ 1.99 3165.18 11325.61 91.00 233.28 10027.00 1933.36 S 2592.46 W 1.99 3234.00 18 5/8" Casing Pt KOP 13 3/8" Casing Pt EOC 9 5/8" Casing Pt TARGET #1 TARGET #2 RECEIVED ALL data is in feet unless otherwise stated Coordinates from slot #2-6 and TVD from wellhead (127.00 Ft above mean sea level). Vertical section is from wellhead on azimuth 233.28 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL DILLON Platform, 17 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your ref : 17 Version #3 Last revised : 25-Mar-94 Comments in weltpath MD TVD Rectangular Coords. Comment 1100.00 1100.00 0.00 N 0.00 E 18 5/8" Casing Pt 3000.00 3000.00 0.00 N 0.00 E KOP 3500.00 3497.46 26.02 S 34.89 W 13 3/8" Casing Pt 3840.26 3828.26 73.14 S 98.08 W EOC 9500.00 9246.30 1051.38 S 1409.80 W 9 5/8" Casing Pt 9608.33 9350.00 1070.10 S 1434.91W TARGET #1 10415.88 9900.00 1397.11S 1873.40 W TARGET #2 11325.61 10027.00 1933.36 S 2592.46 ~ TD / 7" Casing Pt Casing positions in string 'A' Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing 0.00 0.00 O.OON O.OOE 1100.00 1100.00 O.OON O.OOE 18 5/8" Casing 0.00 0.00 O.OON O.OOE 3500.00 3497.46 26.02S 34.89W 13 3/8" Casing 0.00 0.00 O.OON O.OOE 11325.61 10027.00 1933.36S 2592.46W 7" Casing Targets associated with this wel[path Target name Position T.V.D. Local rectangular coords. Date revised 17 G-1 Possible not specified 10027.00 1933.36S 2592.46~ 22-Mar-94 17 Mid G-4a Possible not specified 9900.00 1397.11S 1873.40W 22-Mar-94 17 G-1 Possible not specified 9350.00 1070.10S 1434.91W 22-Mar-94 RECEIVED APR - 7 199~, Alaska Oil & Gas Cons. C0mmissio~ Anchorage All data is in feet unless otherwise stated Coordinates from slot #2-6 and TVD from wellhead (127.00 Ft above mean sea level). Bottom hole distance is 3234.00 on azimuth 233.28 degrees from wellhead. Total Dogleg for wetlpath is 91.00 degrees. Vertical section is from wellhead on azimuth 233.28 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL DILLON Platform, 17 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 1 Your ref : 17 Version #3 Last revised : 25-Mar-94 Measured Inc[in. 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 I N A T E S Deg/lOOFt Sect 0.00 0.00 233.28 0.00 694.00 N 1870.00 E 0.00 0.00 500.00 0.00 233.28 500.00 694.00 N 1870.00 E 0.00 0.00 1000.00 0.00 233.28 1000.00 694.00 N 1870.00 E 0.00 0.00 1100.00 0.00 233.28 1100.00 694.00 N 1870.00 E 0.00 0.00 1500.00 0.00 233.28 1500.00 694.00 N 1870.00 E 0.00 0.00 2000.00 0.00 233.28 2000.00 694.00 N 1870.00 E 0.00 0.00 2500.00 0.00 233.28 2500.00 694.00 N 1870.00 E 0.00 0.00 3000.00 0.00 233.28 3000.00 694.00 N 1870.00 E 0.00 0.00 3100.00 2.00 233.28 3099.98 692.96 N 1868.60 E 2.00 1.74 3200.00 4.00 233.28 3199.84 689.83 N 1864.40 E 2.00 6.98 3300.00 6.00 233.28 3299.45 684.62 N 1857.42 E 2.00 15.69 3400.00 8.00 233.28 3398.70 677.33 N 1847.65 E 2.00 27.88 3500.00 10.00 233.28 3497.46 667.98 N 1835.11 E 2.00 43.52 3600.00 12.00 233.28 3595.62 656.57 N 1819.82 E 2.00 62.60 3700.00 14.00 233.28 3693.06 643.13 N 1801.78 E 2.00 85.10 3800.00 16.00 233.28 3789.64 627.66 N 1781.04 E 2.00 110.98 3840.26 16.80 233.28 3828.26 620.86 N 1771.92 E 2.00 122.34 4000.00 16.80 233.28 3981.18 593.25 N 1734.90 E 0.00 168.53 4500.00 16.80 233.28 4459.83 506.83 N 1619.02 E 0.00 313.09 5000.00 16.80 233.28 4938.48 420.41 N 1503.14 E 0.00 457.65 5500.00 16.80 233.28 5417.12 333.99 N 1387.25 E 0.00 602.21 6000.00 16.80 233.28 5895.77 247.56 N 1271.37 E 0.00 746.76 6500.00 16.80 233.28 6374.42 161.14 N 1155.49 E 0.00 891.32 7000.00 16.80 233.28 6853.06 74.72 N 1039.61 E 0.00 1035.88 7500.00 16.80 233.28 7331.71 11.70 S 923.72 E 0.00 1180.44 8000.00 16.80 233.28 7810.36 98.12 S 807.84 E 0.00 1325.00 8500.00 16.80 233.28 8289.00 184.54 S 691.96 E 0.00 1469.56 9000.00 16.80 233.28 8767.65 270.96 S 576.08 E 0.00 1614.12 9500.00 16.80 233.28 9246.30 357.38 S 460.19 E 0.00 1758.68 9608.33 16.80 233.28 9350.00 376.10 S 435.09 E 0.00 1790.00 9666.32 20.83 233.28 9404.88 387.28 S 420.09 E 6.94 1808.70 9766.32 27.78 233.28 9495.96 411.88 S 387.12 E 6.94 1849.84 9866.32 34.72 233.28 9581.40 442.87 S 345.56 E 6.94 1901.68 9966.32 41.66 233.28 9659.95 479.81 S 296.03 E 6.94 1963.47 10066.32 48.61 233.28 9730.45 522.16 S 239.24 E 6.94 2034.30 10166.32 55.55 233.28 9791.86 569.29 S 176.04 E 6.94 2113.14 10266.32 62.50 233.28 9843.30 620.51 S 107.36 E 6.94 2198.83 10366.32 69.44 233.28 9884.00 675.08 S 34.19 E 6.94 2290.11 10415.88 72.88 233.28 9900.00 703.11 S 3.40 W 6.94 2337.00 10456.79 73.70 233.28 9911.76 726.54 S 34.82 W 1.99 2376.19 10556.79 75.69 233.28 9938.16 784.20 S 112.13 W 1.99 2472.63 10656.79 77.68 233.28 9961.19 842.37 S 190.13 W 1.99 2569.94 10756.79 79.67 233.28 9980.83 900.99 S 268.73 W 1.99 2667.99 10856.79 81.66 233.28 9997.04 959.98 S 347.83 ~ 1.99 2766.66 10956.79 83.66 233.28 10009.82 1019.26 S 427.33 ~ 1.99 2865.84 11056.79 85.65 233.28 10019.14 1078.78 S 507.14 W 1.99 2965.39 11156.79 87.64 233.28 10025.00 1138.46 S 587.16 ~ 1.99 3065.22 11256.79 89.63 233.28 10027.38 1198.22 S 667.30 W 1.99 3165.18 11325.61 91.00 233.28 10027.00 1239.36 S 722.46 ~ 1.99 3234.00 18 5/8" Casing Pt KOP 13 3/8" Casing Pt EOC 9 5/8" Casing Pt TARGET #1 TARGET #2 RECEIVED APR -7 1994 /.,,~:~ ~',~,~ ,,,, ~,. Ga.~ Cons. Commission Anchorage TD / 7" Casing Pt All data is in feet unless otherwise stated Coordinates from SW Corner of Sec. 35, T8N, R13W and TVD from wellhead (127.00 Ft above mean sea level). Vertical section is from wellhead on azimuth 233.28 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL PROPOSAL LISTING Page 2 DILLON Platform, 17 Your ref : 17 Version #3 Middle Ground Shoals,Cook Inlet, Alaska Last revised : 25-Mar-94 Comments in wellpath MD TVD Rectangular Coords. Comment 1100.00 1100.00 694.00 N 1870.00 E 18 5/8" Casing Pt 3000.00 3000.00 694.00 N 1870.00 E KOP 3500.00 3497.46 667.98 N 1835.11E 13 3/8" Casing Pt 3840.26 3828.26 620.86 N 1771.92 E EOC 9500.00 9246.30 357.38 S 460.19 E 9 5/8" Casing Pt 9608.33 9350.00 376.10 S 435.09 E TARGET #1 10415.88 9900.00 703.11S 3.40 W TARGET #2 11325.61 10027.00 1239.36 S 722.46 W TD / 7" Casing Pt Casing positions in string 'A' Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing 0.00 0.00 694.00N 1870.00E 1100.00 1100.00 694.00N 1870.00E 18 5/8" Casing 0.00 0.00 694.00N 1870.00E 3500.00 3497.46 667.98N 1835.11E 13 3/8" Casing 0.00 0.00 694.00N 1870.00E 11325.61 10027.00 1239.36S 722.46W 7" Casing Targets associated with this we[lpath Target name Position T.V.D. Local rectangular coords. Date revised 17 G-1 Possible not specified 10027.00 1239.36S 722.46W 22-Mar-94 17 Mid G-4a Possible not specified 9900.00 703.11S 3.40W 22-Mar-94 17 G-1 Possible not specified 9350.00 376.10S 435.09E 22-Mar-94 RECEIVED APR - ? 1994 Alaska Oil & Ca,~ C~s. C,~mmission Anchorage All data is in feet unless otherwise stated Coordinates from S~ Corner of Sec. 35, T8N, R13~ and TVD from wellhead (127.00 Ft above mean sea level). Bottom hole distance is 3234.00 on azimuth 233.28 degrees from wellhead. Total DogLeg for wel[path is 91.00 degrees. Vertical section is from wellhead on azimuth 233.28 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL DILLON Platform 17 slot #2-6 Middle Ground Shoals Cook Inlet, Alaska CLEARANCE REPORT by Baker Hughes INTEQ Your ref : 17 Version #3 Our ref : prop1032 License : Date printed : 30-Mar-94 Date created : 22-Mar-94 Last revised : 25-Mar-94 Field is centred on n60 50 4.803,w151 29 11.941 Structure is centred on n60 44 0.841,w151 31 22.418 Slot location is n60 44 7.674,w151 30 44.809 Slot Grid coordinates are N 2463865.846, E 229317.013 Slot local coordinates are 694.00 N 1870.00 E Reference North is True North ( WARNING: DATA BELOW IS A SUMMARY, DETAIL PROXIMITIES NOT TABULATED ) Object wellpath 18 Version #2,,18,DILLON Platform MSS <1245-10942'>,,D-6,DILLON Platform MSS <2020-10550'>,,D-4,DILLON Platform MSS <2150-10500'>~D-3,DILLON Platform MSS <1930 - 10750'>~D-7,DILLON Platform MSS <6770 - 10401'>,~D-2,DILLON Platform PGMS <0-10304'>,,D-2Rd,DILLON Platform MSS <7205-10537'>,,D-8,DILLON Platform PGMS <3200-10505'>,,D-8Rd,DILLON Platform MSS <3407 - 11325'>,,D-5,DILLON Platform MSS <7122-10900'>,,D-9,DILLON Platform PGMS <O-10554'>,,D-9Rd,DILLON Platform MSS <1958 - 2466'>,,D-lO,DILLON Platform GMS <O-10508'>~,D-11,DILLON Platform MSS <0-12000'>,,D-12,DILLON Platform PGMS <1280-10000'>~,D-13,DILLON Platform PGMS <0-10500'>,,D-14,DILLON Platform GMS <0-13133'>~,D-15~DILLON Platform 16 Version #4,,16,DILLON Platform Closest approach with 3-D minimum distance method Last revised Distance M.D. Diverging from M.D. 26-Jan-93 4.0 3000.0 11325.6 30-Mar-94 7.4 120.0 1860.0 30-Mar-94 72.8 180.0 700.0 30-Mar-94 98.2 680.0 8560.0 30-Mar-94 7.2 340.0 460.0 30-Mar-94 61.8 640.0 640.0 30-Mar-94 61.8 640.0 640.0 30-Mar-94 9.8 680.0 780.0 30-Mar-94 9.8 680.0 9460.0 30-Mar-94 110.7 860.0 11156.8 30-Mar-94 61.7 860.0 860.0 30-Mar-94 61.7 860.0 8700.0 30-Mar-94 75.7 60.0 120.0 30-Mar-94 10.8 300.0 300.0 30-Mar-94 108.6 340.0 11325.6 30-Mar-94 72.0 380.0 8980.0 30-Mar-94 59.8 3920.0 10399.4 30-Mar-94 107.6 100.0 11325.6 25-Mar-94 3.4 3066.7 3066.7 RECEIVED UNOCAL DILLON Platform 17 slot #2-6 Middle Ground Shoals Cook Inlet, Alaska CLEARANCE REPORT by Baker Hughes [NTEQ Your ref : 17 Version #3 Our ref : prop1032 License : Date printed : 31-Mar-94 Date created : 22-Mar-94 Last revised : 25-Mar-94 Field is centred on nGO 50 4.803,w151 29 11.941 Structure is centred on nGO 44 0.841,w151 31 22.418 Slot location is nGO 44 7.674,w151 30 44.809 Slot Grid coordinates are N 2463865.846, E 229317.013 Slot local coordinates are 694.00 N 1870.00 E Reference North is True North Main calculation performed with 3-D Minimum Distance method Object wellpath 18 Version #2,,18,DILLON P[atform MSS <3407 - 11325'>,,D-5,D[LLON Platform MSS <O-12000'>,,D-12,DILLON Platform MSS <2150-10500'>,,D-3,DILLON Platform PGMS <O-10500'>,,D-14,DILLON Platform GMS <O-13133'>,,D-15,DILLON Platform MSS <1245-10942'>,,D-6,DILLON Platform MSS <1930 - 10750'>,,D-7,DILLON Platform GMS <O-10508'>,,D-11,DILLON Platform PGMS <3200-10505'>,,D-8Rd,DILLON P[atform MSS <7205-10537'>,,D-8,DILLON Platform PGMS <1280-10000'>,,D-13,DILLON Platform PGMS <O-10304'>,,D-2Rd,DILLON Platform MSS <6770 - 10401'>,,D-2,DILLON Platform PGMS <O-10554'>,,D-9Rd,DILLON Platform MSS <7122-10900'>,,D-9,DILLON Platform MSS <2020-10550'>,,D-4,DILLON Platform MSS <1958 - 2466'>,,D-lO,DILLON Platform 16 Version #4,,16,DILLON Platform Closest approach with 3-D minimumdistance method Last revised Distance M.D. Diverging from M.O. 26-Jan-93 4.0 3000.0 11325.6 30-Mar-94 110.7 860.0 11156.8 30-Mar-94 108.6 340.0 11325.6 30-Mar-94 98.2 680.0 8560.0 30-Mar-94 59.8 3920.0 10399.4 30-Mar-94 107.6 100.0 11325.6 30-Mar-94 7.4 120.0 1860.0 30-Mar-94 7.2 340.0 460.0 30-Mar-94 10.8 300.0 300.0 30-Mar-94 9.8 680.0 9460.0 30-Mar-94 9.8 680.0 780.0 30-Mar-94 72.0 380.0 8980.0 30-Mar-94 61.8 640.0 640.0 30-Mar-94 61.8 640.0 640.0 30-Mar-94 61.7 860.0 8700.0 30-Mar-94 61.7 860.0 860.0 30-Mar-94 72.8 180.0 700.0 30-Mar-94 75.7 60.0 120.0 25-Mar-94 3.4 3066.7 3066.7 RECEIVED Anchorage scale ~ · ~o.oo Ea sf 1620 1 650 1680 171 0 1740 1770 --> 1800 1830 2200 1600 2000 ~oo ~'~°° ~8oo "'"'""'~600 ' -,,Oo 1200 120( 1400 1200 1000 4800 1000 UNOCAL Structure : DILLON Platform Well : 16 / 17 Fleld: Middle ground Shoal. Looatlon : Cook Inlet, No.ko 1200 1400 1400 1000 1400 1800 1860 1890 I I I 1400 1200 ~}oo 420 5200 1200 1920 ~870 84O 10 78O 63O /X I I Z 0 ,600 1800 !00 1800 1600 APR -7 1994 Oil & Gas Cons. Commission Anchorage UNOCAL DILLON PLATFOR~ WELL #16, #17 DEPTH CASING SIZE HOLE SIZE MUD TYPE + 1,100' 18-5/8" 17-1/2" Open Hole 24" F. I.W./Generic Mud #2 Notes: ANTICIPATED MUD PROPERTIES Mud Density Funnel Viscosity Plastic Viscosity Yield Point Gels Fluid Loss API pH 8.8 - 9.4 ppg 45 - 100 sec/qt 10 - 15 cps 10- 30 #/100 ft2 8 - 20 N.C. 8.5 - 9.5 Use bentonite prehydrated in freshwater and filtered inlet water. DEPTH CASING SIZE HOLE SIZE MUD TYPE + 3,500' 13-3/8" 17-1/2" F. I.W./Generic Mud #2 Notes: ANTICIPATED MUD PROPERTIES Mud Density Funnel Viscosity Plastic Viscosity Yield Point Gels Fluid Loss API pH 9.0 - 9.6 ppg 40 - 70 sec/qt 10 - 15 cps 10- 20 #/100 ft2 6 - 12 N.C. 8.5 - 11.0 Treat for cement contamination. RECEIVED APR - 7 1.9,o, 4 A~ska Oil & Gas Co~s, Oommi~ion DEPTH CASING SIZE HOLE SIZE MUD TYPE - 9,800' 9-5/8" 12-1/4" F. I.W./Generic (with PHPA) Mud #2 Notes: ANTICIPATED MUD PROPERTIES Mud Density Funnel Viscosity Plastic Viscosity Yield Point Gels API Fluid Loss HPHT Fluid Loss 9.5 - 10.5 ppg 40 - 60 sec/qt 10 - 15 cps 10 - 25 #/100 ft2 4 - 12 8 20 Build new PHPA Generic Mud #2. DEPTH LINER SIZE HOLE SIZE MUD TYPE +- 11,800' 7" 8-1/2" F. I.W./Generic Mud #2 (with PHPA) NOtes: ANTICIPATED MUD PROPERTIES Mud Density Funnel Viscosity Plastic Viscosity Yield Point Gels API Fluid Loss HPHT Fluid Loss 9.5 - 10.5 ppg 45 - 80 sec/qt 10 - 15 cps 15 - 30 #/100 ft2 6 - 12 5 10 Treat for cement contamination. Increase yield point and gels in horizontal section. Add lubricants for torque and drag. RECEIVED APR -7 1.994 A!~3ska Oil & Gas Cons, Commission Anchorage Rotary Kelly Bushing (RKB) Drill Deck Level Production Deck Level Elev. 127' Elev. 87' Elev, 69' Sea Level (MLW) Elev. O' Mud Line Elev, -102' 30" Structural @ 317' RKB (88' BLM) 18-5/8" Surface @ 1100' 97#, X-56, QTE60 13-3/8" Intermediate @ 3500' 68#, K-55, BTC 9-5/8" Production @ 9800' 47#, L-80, BTC 7' Uner @ 11800' 29#, L-80, BTC RECEIVE[ APR - 7 1994 DILLON PLATFORM ELEVATION DIMENSIONS UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 3-21-94 FILE: DILELEV.drw ~ FLOW FILL-UP ~ ~ I MSP ANNULAR BOP 20~/4" 2000 psi { ' SPOOL _ I I ~'4~3000 p, si{ { DIVERTER SPOOL BLIND FLANGED DURING BOP OPERATIONS / I PIPE RAMS 20~/~' 3000 psi 3"- 10M BLIND RAMS 20~/4'' 3000 psi CHECK VALVE HC~ HCR _~ [~ MANUAL [DRILLING[ MANUAL [~ CH 0 KEsP°°t' LINE t/ ,', 3"-lOM 4"-lOM GATE VALVES [ PIPE RAMS J20%.3000 psiGATE VALVES RISER 203/4'' 3000 psi R E C E IV E D ~ APR -7 1994 Alaska 0il & Gas Cons. Commissio~ CHABKACHATNA RIG 428 OP/DIVERTER STACK 21 ~;' 2000psi/20;~' 3000psi FILL- UP %2> ~ 3"-10M CHECK VALVE KILL LINE ANNULAR BOP 135/~"5000 psi I I PIPE RAMS 135/~'§000 psi BLIND RAMS 135/e"5000 psi ~. HCR I I HCR ~ [~ MANUAL'{ DRILLING {'MANUAL [~ ~11 ~ I z3 y45ooo p~ 3"- 1OM '~I I 'X~ 4" GATE FLOW VALVES PIPE RAMS 13~/~"5000 psi I I CHOKE LINE~ -10M GATE VALVES RISER 13%" 5000 psi RECEIVED APR -7 1994 A.iaska Oil & Gas Cons. Commissior Anchorage CHAKACHATNA RIG 428 BOPE STACK 13 %' 500O psi VENT OUTSIDE OF WINDWALJ. S FLANGE ,~" PANIC LINE ,~' 5,000 PSi BALL 4 1/16-5M FLG. 514 TARGET BLIND HUB 3" RELIEF SET AT ,fO PSI VENT LINE BLINO HUB ADJ. CI.N. tP HUB CONNECTION BUFFE~ TANK MUD G4.S SEPEt~ATOR I ,,i Il 15o/b. eUNO FLANG£ (ne.] 10' 150 lb. FLAHGE SIPHON LIN£ 150 lb. FLANGE I! 1 ~,~R - 7 1994 .. ,~ .,:..~ ~,~ & Gas Cons. Oommisslol~ Anchorage 15 c~P ~/ exl~ 10, 000 PSl HYD. CHOKE TO PRODUC'IION SEPARATOR MUD RETURN UNE UNOCAl. CHOI~ t, MNIFOLD COOKINLET DEC 04-1:12592 '1 '" !" TRANSFER LINE TO / FROM PLATFORM MUD STORAGE LEGEND UN£ TYPE & ~ PIPE PIPE. RUN COLOR CODE COLOR THIS SHEET 14~KII~ BYP/GS LINE GRAY cmrPjFUC. E SUCTION DEG4SS~ SUClTOft DEGASS~ RETURN ....... DESANDE~ SUCTION ....... DES4NDE. R PRESSURE ....... HOPPER SUCTION ....... HOPPER PRESSURE ....... HOPPER RE1URN ....... IJUD CLEANER SUCTION ....... t4UD CLEANER PRESSURE ....... · .. MUD CLEANER RETURN ....... '* MUD C, UN SUC'IION ....... 14UD ~,JN PRESSURE ....... I~UO PUI~P SUCTION I, IUP PUMP SUCITON ~ 2 ....... MUD PUMP PRESSURE ....... TRANSFER UNE ~OLOR$ SHOVIN ON THIS SHEET ARE FOR ILLUSTRATION OF PIPE RUNS ONLY. CUT71NGS DISCHARGE LEGEND ALTERNATE HOPPER POSITION PILL PIT "~ ~ _.~.55BBL~, ~1 ! .~~ % MUD CL~ER I PIT 80 ~L/ · ~.. ~ ~__ ~ ...... I DE~NDER I~ i eo BBL I ~'- ~ ' . ~ PITDE*ASSER U lo5 BBL SAND ~P / LIOUIOS (.~-0 ! I ! I I I J J J : i i · ~ · ~ ~' ~ ~. .~ ~ ~ ~ ' . · . ...... ~..~ ._.~ ~P2 C~E i I ~ i ~ i I i PUMP I I I : I : i ~ ~ ~UD ' ~ TFI-16 ' ' ~ ~: ~ ~i ~! ~ ~. ~ ~u~ ~ o~o~ - ~ PUMP ~ ~ ~ ] : I , ~ ~111 ~ ~1 CL~m .......... ~ I ~ ....... ~ ~o ~. ',, L~,,/~,~ , ~ : '~ ~ ]88BED ~-~ PUMP '~ ~ ~ .............. ~ ~ .. R~W ~ .................... ~1 ~ ~ ~m~p~ ;, i PIONEER ~ i TS-6 O~NDER ~~~.~.~ ....... ~ ............... ~ ~ LC VALVE ---~ AflflUSTABLE MUD GUN MUD AGITATOR SUCTION VALVE E~UALIZER ~iEIR VAL W'. ! I I I '. i : I i DOWN __.._~_) rO DRAIN SYSTEM MUD PUMP J t OILWELL A- 1700PT i I ONLY I I -C".-.. ~ I ~1~: ' PIONEER S-800 SIDEWINDER MUD HOPPER ) MUD PUMP ~12 OILWELL A-1700PT AI:x~ -7 1994 Gas Cons. Commission TRANSFER LINE ENTIRE DRAWING PER FIELD ASBUILT TO / FROM PLATFORM MUD STOP, AGE PRESSURE MUD SYSTEU 1~ EC' E1 V'E'b' ' CUTTINGS DISCHAROE UNOCAL CI.IAKACHATNA PROJECT - PM, RIG 428 III PLAN VIEW @ NORTHWEST LEG VIEW A-A j ! I FOR lNFO~jvjA'ii~[i P,4A RIP, 428 2o ,V4' BLOW-OUT PREVENTER STACK RSRRdS4 MAR 2 4 1994 POOL ARCTIC ALASKA NOTe.; REFERENCE DRAWING 428.5039 FOR FURTHER INFORMA770N PERTAINING TO DIV~RTER LINE SPOOLS. I -/'4 ~801 Sl~ ~18 DIVERTER UNE LAYOUT NORTHWESt LEG PosmoN POOL RIG 428 4 ! PLAN VIEW ON SO U'THI4rEST LEG VIEW A-A I I I I Il I ! I II ! ! ! ! ! ! ! ! II I FOR INFORMATt~ii ONLY ISSUED 1994 POOL ARCTIC ALASKA PLAN VIEW - TYP. BOTH EAST LEGS SHOWN ON NORTHEAST LEG REFERFJVCE DRAWING 428.5039 FOR FURTHER INFORMATION PERTAINING TO DIVERTER UNE SPOOLS. OIVERIER UNE LAYOUT SOUltlWE~ & EAST LEG POSITIONS POOL RIO 428 :1 .. I 3~I FL~ X HUB PLATFOR# BAKER RECEIVED APR. -7 ~994 oit & Gas Cons. Commissio~ Anchorage :! I , 13.~/8'.~ItS1VDXCOOPERFA.q'a. Ot~COHItEClDR,aIMPTOR(B)'I)OC) PLATFORMS DILLON/ANNA INFORHATION ONLY ISSUED MAR 2 4 1994 POOl. ARCTIC ALASKA IA I 18'-~ WAS 14'-0';4:83 WA~_ 3'-0';lg'-7 5/8' WAS I ODId I'ldUN93 I 19'-e';4~ was ~'-o';~7'-o' w~ ~+'-~'-~e'-7 ~/~';I I I ~e,-9' w~ _17'-2;19'-6 11/1~ WAS 19:-7 1/le"*; I I I 18'-3 13/16' w,~s le'-5 ~./16- J l cmI ~ I c.~' I ~ TI'DS DICSI(N4 I~ PE]AIISSIBL~ ONLY Ir )LZITK)RIZED IN WRITINO 9Y P.A.A. 6601 HICr-d.I PRESSURE RISERS LAYOUT DIVERTER STACK AND BOP STACK UOC: PLATFORMS BAKER, DILUON, & PM RIG 428 0~, ~ ~,~ ,/,~.1.-~ I -- I'~' I I CASING DESIGN WELL: 1. 2. 3. DILLON ~17 MUD WT. 8.8 PPG 9.0 PPG 10.0 PPG FIELD: CASING SIZE INTERVAL BOTTOM TOP 1. 18-5/8" 1100' 69' MD 1100' 69' TVD 2. 13-3/8" 3500' 69' MD 3497' 69' TVD 3. 9-5/8" 9500' 69' MD 9246' 69' TVD 4. 7" 11326' 9200' MD 10027' 8958' MD MIDDLE GROUND SHOAL DATE: MARCH 30~ 1994 DESIGN BY: C.L. LOHOEFER M.S.P. 385 psi 902 psi 601 psi WEIGHT TENSION MINIMUM COLLAPSE COLLAPSE W/ BF __ -TOP OF STRENGTH PRESS @ RESIST. BURST MINIMUM DESCRIPTION W/O BF X SECTION TENSION BOTTOM TENSION PRESSURE YIELD LENGTH WT. GRADE THREAD LBS -- LBS 1000 LBS TDF PSI* PSI CDF PSI** PSI BDF 1031 97~, X-56, QTE 60 100,000 SAME 1594 15.94 315 960 3.05 787 2630 3.34 3431' 68#, K-55, BTC 233,308 SAME 1069 4.58 1000 1950 1.95 2069 3450 1.67 9431' 47#, L-80, BTC 443,257 SAME 1086 2.45 2644 4750 1.80 2256 6870 3.04 2125' 29#, L-80, BTC 61,625 SAME 676 10.96 2868 7020 2.44 2256 8160 3.62 NOTES: , ** See attached for calculation of M.S.P. including assumptions & estimates. Collapse Pressure is calculated; Differance between w/two cmt slurries (i.e. Avg of a 15.8 ppg (tail) & 12 ppg (lead) = 14 ppg, subtract a mud of 9.5 ppg = 5.5 ppg = .286 psi/ft, gradient x TVD of the csg string). Burst pressure is calculated; (BHP @ depth next csg x TVD next csg) x (0.5 half evacuated). RECEIVED ~,~ - 7 1994 Gas Oo~s. Commissio~ Anchorage Leak Off Test (LOT) Data Cook Inlet, Alaska Unocal Energy Resources Alaska Well # Date Baker Platform Ba 28 Ba 30 Ba 30 Ba 28 Ba 29 Ba 29 Ba 30 Ba 28 Csg Size Shoe Depth Frae Grad. (TVD) Cpsi/i~.) EMW 10-10-93 24" 802' 0.94 18.10 10-24-93 24" 803' 0.83 15.90 10-28-93 18-5/8" 2011' 0.94 18.10 11-17-93 18-5/8" 2135' 0.75 14.50 12-17-94 18-5/8" 2054' 0.76 14.61 12-29-93 13-3/8" 5869' 0.85 16.33 01-27-94 13-3/8" 5467' 0.93 17.96 03-01-94 13-3/8" 3509' 0.75 14.40 Grayling Platform G40 G-40 Monopod Platform 01-24-90 A-lrd 04-04-91 A-8rd 07-01-89 A-20rd 03-30-90 A-20rd 04-13-90 A-28rd 11-20-89 A-28rd 11-27-89 Granite Point Platform ll-13rd 02-14-92 51 08.07-92 51 07-28-92 51 08-25-92 50 05-27-92 50 06-04-92 50 06-27-92 16" 1926' 0.96 18.46 13-3/8" 4977' 0.86 16.54 9-5/8" 1132' 1.07 20.57 9-5/8" 3760' 1.02 19.61 13-3/8" 755' 0.95 18.20 9-5/8" 1931' 0.85 16.30 20" 240' 0.75 14.42 13-3/8" 1140' 0.97 18.65 9-5/8" 9966' 0.96 13-3/8" 3803' 1.00 18-5/8" 1010' 0.87 9-5/8" 9592' 1.05 18-5/8" 982' 0.91 13-3/8" 4208' 0.84 9-5/8" 9877' 0.93 Filename A:Lotdata. doe 18.40 19.20 16.80 20.20 17.50 16.20 17.90 Dillon Platform Well # 17 South Middle Ground Shoals (SMGS) March 29, 1994 Hole Section 1 Depth Interval: 0 - 1100' 17-1/2" & 24" hole size 18-5/8" casing to 1100' Mud Weight: Shoe depth (18-5/8"): Est. fracture gradient of 18-5/8" shoe: BHP gradient: 8.8 ppg = 0.46 psi/ft. 1100' MD / 1100' TVD 0.80 psi/ft. 0.35 psi/ft The maximum surface pressure cannot exceed the maximum bottom hole pressure; MSP = 1100' x 0.35 psi/ft. = 385 psi Hole Section 2 Depth Interval: 1100' - 3500' 17-1/2" hole size 13-3/8" casing to 3500' Mud Weight: Shoe depth (13-3/8"): Est. fracture gradient of 13-3/8" shoe: Depth of next hole section (12-1/4"): BlIP gradient: Gas gradient (assume worst case) 9.0 ppg = 0.47 psi/ft. 3500' MD / 3497' TVD 0.80 psi/ft. 9500' MD / 9246' TVD 0.45 psi/ft 0.0 psi/fi. Gas kick situation in the wellbore, assume; 3/4 mud & 1/4 gas. MSP = BHP - Hydrostatic Pressure MSP = BHP - (3/4 mud + 1/4 gas) MSP = (9246' x 0.45 psi/fi) - ((0.75 (9246' x 0.47 psi/ft)) + (0.25 (9246' x 0.0 psi/ft.))) MSP = 902 psi Therefore, the hydrostatic pressure at the 13-3/8" shoe (HPsh) is the greatest when the gas (kick) bubble reaches the 13-3/8" shoe, ff a constant BHP is applied. A conservative estimate would be the MSP plus the hydrostatic pressure at the 13-3/8" casing depth (HPcsg). HPsh = MSP + HPcsg HPsh = 902 + (3497' x 0.47) HPsh = 2546 psi This (HPsh = 2546 psi)is less than the fracture pressure at the same shoe (FPsh) and thus ~e~~IYVL. ~[~,r~ handle the well kick scenario. . HPsh = 2546 psi < FPsh = 0.80 psi/ft x 3497' = 2798 psi. Gas Cons. Commission Anchorage Dillon Platform Well # 17 Pressure Calculations Hole Section 3 Depth Interval: 3500' - 9500' 12-1/4" hole size 9-5/8" casing to 9500' Mud Weight: Shoe depth (9-5/8"): Est. fracture gradient of 9-5/8" shoe: Depth of next hole section (8-1/2"): BHP gradient: Gas gradient (assume worst case) 10.0 ppg = 0.52 psi/f[. 9500' MD / 9246' TVD 0.85 psi/f[. 11326' MD / 10027' TVD 0.45 psi/f[ 0.0 psi/f[. Gas kick situation in the wellbore, assume; 3/4 mud & 1/4 gas. MSP = BHP - Hydrostatic Pressure MSP = BHP - (3/4 mud + 1/4 gas) MSP = (10027' x 0.45 psi/fO - ((0.75 (10027' x 0.52 psi/f[)) + (0.25 (10027' x 0.0 psi/f[.))) MSP = 601 psi Therefore, the hydrostatic pressure at the 9-5/8" shoe (HPsh) is the greatest when the gas (kick) bubble reaches the 9-5/8" shoe, if a constant BHP is applied. A conservative estimate would be the MSP plus the hydrostatic pressure at the 9-5/8" casing depth (HPcsg). HPsh = MSP + HPcsg HPsh = 601 + (9246' x 0.52 psi/fi) HPsh = 5409 psi This (HPsh = 5409 psi) is less than the fracture pressure at the same shoe (FPsh) and thus adequate to handle the well kick scenario. HPsh = 5409 psi < FPsh = 0.85 psi/f[ x 9246' = 7859 psi. Additionally, HPsh - Pore Pressure at shoe < Internal Yield of the 9-5/8" casing 5409 - (9246' x 0.45 psi/f[) < 6870 psi 1248 psi < 6870 psi Filename:AOGCCkDi 17¢al¢.doo RECEIVED APR -7 19o.4 Alaska (~ & Gas C~ns ~mnis~io~ WELL PERMIT CHECKLIST ~MINISTRATION =ENGINEERING 1. 2. 3. 4. 5. 6. "7. 8. 9. 10. 11. 12. 13. Permit. fee at~ached .................. .~ Lease number appropriate ............... ~ ~.1 Unique ~ell name and number .............. Well located in a defined ~ool ............. Well located proper distance from drlg unit boundary.'.l.YI Well located proper distance from other wells ..... Sufficient acreage available in drilling unit ..... t YI If deviated, is wellbore plat included ........ Operator only affected party .............. Operator has appropriate bond in force ......... J.Y~ Permit can be issued without conservation order .... Permit can be issued without administrative approval Y Can permit be approved before 15-day wait ....... ~fY~ · · N N N N N N N N N N N PROG~R: exp [] dev I~1 redr11 [] serv [] . DATEw '" GEOLOGY 14. Conductor string provided ............... ~ N 15. Surface casing protects all known USDWs ........ .y~ N 16. CMT vol adequate to circulate on conductor & surf csg. N 17. CM~ vol adequate to tie-in long string to surf csg . . . 18. CMTwill cover all known productive horizons ...... ~ N 19. Casing designs adequate for C, T, B & permafrost.... ~ N 20. Adequate tankage or reserve pit ............. ~y/ N 21. If a re-drill, has a 10-403 for abndnmnt been approved. 22. Adequate wellbore separation proposed .......... ~ N 23. If diverter required, is it adequate ........... Y~N 24. Drilling fluid program schematic & equip list adequate .~ N 25. BOPEs adequate ............... ~ ..... ~ N 26. BOPE press rating adequate~ test t° ~/~sig.~ N 27. Choke manifold complies w/API RP-53 (May 84) ...... ~ N 28. Work will occur without operation shutdown.. , .... 29. Is presence of H2S gas probable ........... 31. Data presented on potential overpressure zones ..... Y ~/ 32. Seismic analysis of shallow gas zones .......... Y/~ 33. Seabed condition survey (if off-shore) ......... y N 34. Contact name/phone for weekly progress reports .... / N [exploratory only] GEOLOGY: ENGINEERING: COMMISSION: RP~.__ BEW DWJ~ TAB Comments/Instructions: Z 0 '"'W/Jo - A:~FORMS~cheklist rev 03/94