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Home My WebLink About194-0571a. 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 30"83 18-5/8" X-57 1,131 13-3/8" K-55 3,639 9-5/8" L-80 9,469 7" P-110 10,008 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 11,703 9,342 9,794 9,785 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 6/26/2023 194-057 / 323-109 50-733-20459-00-00 S MGS Unit 16 ADL0018746 689' FSL, 1870' FWL, Sec 35, T8N, R13W, SM, AK N/A 4/18/1994 11,709 / 10,089 Surface 127' 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 229316.3114 2463860.9184 N/A 1096' FNL, 457' FWL, Sec 35, T8N, R13W, SM, AK CASING WT. PER FT.GRADE 7/11/1994 CEMENTING RECORD N/A N/A SETTING DEPTH TVD 2467387.4976 TOP HOLE SIZE AMOUNT PULLED N/A 227981.5631 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) 9,925 / 9,293 PACKER SET (MD/TVD) 3-1/2" SS 9,98732 Surf 47 Surf Surf 1,132Surf Surf 68 10,155 Surf Surf 97.7 83 Surf 3,640 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 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 11:53 am, Jul 03, 2023 Abandoned 6/26/2023 JSB RBDMS JSB 071223 xGBJM 8/14/23 DSR-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: 2023.07.03 07:19:54 - 08'00' Dan Marlowe (1267) WBD Di-16.doc JLL 06/30/23 Dillon Platform Di-16 Dillon Platform Well Di-16 Last Completed 7/20/94 Tubing 3 ½” Production 9.2#, L-80 Surface 9,794’ SCBTC / 2.992” Long String/ Internally coated tubing 3 ½” Production 9.2#, L-80 Surface 9,785’ SCBTC/ 2.992” Short String Casing and Tubing Detail Size Type Wt / Grade Top Btm CONN / ID Cement / Other 30Ǝ Surface 83’ 18 ǫƎ Surface 97.7# / X-57 Surface 1,132’ QTE60 / 17.653” 826sx lead & 630sx tail w/additives, good cement returns at surface 13 ǪƎ Intermediate 68#, K-55, BTC Surface 3,640’ K-55/12.415 373bbls Lead @12.9ppg & 74bbls Tail @15.8ppg w/additives, Calculated TOC=762’,(Incl.=0.6°) 9 ǫƎ Production 47# / L-80 Surface 10,155’ Butt / 8.68” 163 bbls premium w/ add @15.8ppg,CBL TOC @ 8,300’ 7Ǝ Liner 32#/P-110 9,987’ 11,703’ TKC-BTC / 6.094” 140 bbls @15.8 ppg w/ additives CBL TOC @ 10,150’ Dual String Jewelry Detail L O N G S T R I N G Depth (RKB) Lengt h ID Item 55’ 2.99 Cooper Dual Hanger 1 9,794’ 26.97’ 2.687” Trico Kobe Pump Cavity 2 9,836’ 3.56’ 2.56” S.Sleeve, HES RA SSD # 121RA25623 3 9,871’ 3.55’ 2.56” S.Sleeve, HES RA SSD # 121RA25623 4 9,890’ 3.29’ 2.56” HES “PRO” Safety valve Nipple 5 9,925’ 10.11’ 3.03” Locator Seal ASSY w/8.66’ of seals 6 9,925’ 6.04’ 3.88” HES VTL Retrievable Pkr. Sr# 12VTL96038-2 7 9,931’ 7.40’ 3.88” Seal Bore extension 8 9,938 .58’ 2.99” XO 9 10,002’ 1.47’ 2.56” Model “R” Profile Nipple 10 10,043’ .80’ 2.42” XO 3 ½” BTC box x 2 Ǭ” 8rd pin 31.67’ 2.441 1 jt 2 7/8” TBG cut @ 10,075’ S H O R T S T R I NG 55’ 2.99” Cooper Dual Hanger A 9,785’ .86’ 1.995”XO, 3 ½” x 2 ǪƎ B 9,786’ 10.09’ 1.995’ Tbg Pup jt C 9,794’ 26.97’ Trico Kobe Pump Cavity TD = 11,709’ TVD = 10,088’ PBTD = 11,602’ MAX HOLE ANGLE = 82O @ 11,650’ MD 7” CBL TOC 10,150’ 13 Ǫ” @ 3,640’ Oil Top=10,115’ MD Perfs 10150’ – 10718’ RKB-TH: 55’ KB 7” @ 11,703’ 7” TOL 9,987’ 1 18 ǫƎ@ 1132’ 9-5/8” @ 10,155’ 2 3 4 65 7 8 9 10 C B TOF @ 10,743’ A 13 ǪƎ TOC tagged @ Surface CBL TOC @ 8300’ 10 A Cement Plug #1: 7” Liner: Bottom of perfs @ 10,718’ MD to tubing tail @ 10,043’ MD IA: 9743’ MD to 5000’ MD (Est’d) SS: 9743’ MD to 5570’ (Tag 11/09/22) LS: 10,043’ MD to 5000’ MD (Est’d) Cement Plug #3: SS: 400’ MD to surface IA: 400’ MD to surface OA: 400’ MD to surface OOA: Squeezed from 400’ MD to 37’ MD (Tag 6/25/23) & top- jobbed from 37’ MD to surface Cement Plug #2: IA: 4500’ MD to 3000’ MD (Est’d) SS: 4500’ MD to 2839’ MD (Tag 5/27/23) LS: 4500’ MD to 400’MD (Est’d) Rig Start Date End Date Cmt Pump 5/16/23 6/26/23 Safety Meeting, discuss review JSA's on mixing chemicals and working with hardlines.,Rig up cement lines to SS and LS to circulate out freeze protect, and pump returns to diffuser tank Pre-Job Safety Meeting on cementing procedure, Load cement lines and test to 2000psi, bleed pressure back to diffuser tank. Mix 9 bbl. spacer @ 9.8ppg,Line up on SS taking returns up LS pump 20 bbl. KCL, reverse to pump down LS up SS pump 2 bbl. KCL, no returns, Contact Aras discuss plan forward. Line up on SS to Pump 10 bbl. spacer got full returns @ 7 bbl. in on spacer,Started to mix cement in batch tank, had to shut down to repair cement mixer,Pump 113 bbl. of 14ppg Class A+4%FCG+.3%FFL Down SS cement up in IA @ 4 bpm, shut down close IA, open LS pumped 13 bbl. down SS taking returns to LS, drop wiper ball, Displace SS with 26 bbl. 9.8 KCL @ 4bpm @ 500 psi caught up to 1300 psi. on cement truck. Final lift psi 500 returns from LS,136 bbl. returned no cement returns, Close SS/LS valves wash up lines across wellhead TOC LS surface, TOC SS 3000' TOC IA 3000' 05/18/2023 - Thursday Safety Meeting Working with Hardlines and Crane. Clean cuttings boxes, rig up pumps to move fluid. Transferred cement to make 3 useable silos. Perform maintenance on cement package. Rig down cement hardlines from Di-16. Rig up injection, skid to Di-17 for disposal from diffuser tank. Remove LS half flange on Di-16 verify cement @ surface. Pre-job safety meeting on injecting procedures and proper valve placement. Unload chemicals from ship, spot chemicals to mix NACL. Pressure test lines to 4100 on Fox injection pump, prepare to inject in the AM. 05/19/2023 - Friday Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 16 50-733-20459-00-00 194-057 05/16/2023 - Tuesday Safety meeting with all personal on mixing chemicals, working with crane, and working on flanges on well head. Mix 72 bbl. of 9.8 ppg KCL in mixing pit and moved to North Frac tank. Unload pallets of chemicals off Triton ship and spot, line up cement lines and hose to cement with. Service cement and fluid pumps. Roustabouts removed IA/OA/OOA flanges on upcoming wells to 1502 connections. Daily Operations: Safety Meeting- Injecting well fluid downhole. Inject 249 bbl. well fluid from DI-16 to DI-17 down LS while maintaining 2100 on IA, 2200 psi on Injection pump. Unload fuel from Boat. Rig up cement package on DI-11, make up KCL water,spot cuttings bins for cement returns. Mix gel for cement, pre-pare to cement in the AM. 05/17/2023 - Wednesday Pump 113 bbl. of 14ppg Class A+4%FCG+.3%FFL Down SS cement up in IA close IA, open LS pumped 13 bbl. down SS taking returns to LS, Rig Start Date End Date Cmt Pump 5/16/23 6/26/23 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 16 50-733-20459-00-00 194-057 Daily Operations: 06/10/2023 - Saturday Held PJSM meeting and discussed daily activities. Crew worked on housekeeping. R/d circ eq. off Di-18. Tore apart cement pump and changed bad valve. Off load 4 cement pods into #3 and #4 silos. R/u circulating eq. to SS, IA, OA and OOA.Held PJSM, Performed diagnostic on OOA, pump down SS return up OOA pressured up to 500psi held after 5mins pressure was 250psi. Bled off. Reversed circ down OOA and return up SS, pumped .4bbls and pressured up to 500psi and held for 5mins. Bled off. Pumped down SS up OOA injecting @ .3bpm/850psi pumped away 20bbls with drip returns at diffuser tank. SD pump. Lined up down SS returns up OA, circulated 2x BU @ 2.3bpm/450psi w/FIW (84bbls) and spotted 10bbls of surfactant wash. Lined up returns from IA and circ 2x BU @ 3bpm/150psi w/FIW (40bbls) and spotted 10bbls of surfactant wash. SD pump. Secured well. SDFN 06/06/2023 - Tuesday Opened up OOA to gauge. No pressure. Opened to frac tank and verified. Lined up and pumped 3.5 BBLS to 900 PSI at .5 BPM. Shut in pressure dropped to 0 PSI in 7 min. Pressured back up to 900 PSI pumping 2.5 more BBLS at .5 BPM. Pressure dropped to 100 PSI in 12 Min. Pressured up a 3rd time to 900 PSI pumping 2.2 more BBLS at .5 BPM. Pressure dropped to 100 PSI in 10 Min,Turned on pump at .25 BPM pressuring up to 600 PSI in 2.3 BBLS and pumped and additional 2.1 BBLS 600 PSI until pump cavitated. Total fluid down hole at this point is 12.4 BBLS. OOA was being monitored at all times as well. Swapped upright tanks.,Lined back up and brought pumps on at .5 BPM reaching 600 psi in .65 BBLS, slowed pump back down to .25 BPM and pumped 2 BBLS total at 600 PSI. Shut in and pressure bled back down to 100 PSI in 10 Min. Total fluid injected 14.4 BBLS,Rigged up on Di-11, circulated and spotted wash and cleaned out diffuser tank. See Di-11 report 6-7- 23,rest crew 05/27/2023 - Saturday Safety Meeting- working with wireline and pressure testing. Unload E Line unit from boat spot in place, Rig up E Line, make up 2" bailer, jars & wait bar, run in SS tag @ 2839', attempt to get sample, POOH with cement sample, sample was thick and mushy visual TOC surface in LS, Line up to test LS x IA Start psi 1776 end psi 1724 @ 30 min, Line up to test SS Start psi 1860 @ 15/min 1801 psi, 1801 psi @ 30/min 1782 -good test, Rig down move to DI-11. Perform testing on DI-11. Rig up, to run down SS with 2" 3 foot charges, set charges at 402', POOH, line up to verify circulation down the SS out the IA,OA,& OOA, Established circulation down the SS out the IA & OA 2bpm/200 psi, the OOA pressured up to 900 psi with 3 bbl. pumped did not circulate, pressure bled off. Rig Start Date End Date Cmt Pump 5/16/23 6/26/23 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 16 50-733-20459-00-00 194-057 Daily Operations: 06/23/23 - Friday Held PJSM and discussed daily activities. Continued cleaning and preparing well room to cut Di-16 wellhead off. Worked arranging deck and transferring fluid from returns tanks to ISO. Inventory and clean eq. and put away. 06/24/23 - Saturday Held PJSM, discussed daily ops. Arranged deck and prep eq to load on boat. Housekeeping and cleaning eq. Boat arrived with Alaska Concrete Sawing crew, spotted eq. lowered saw in well bay, hooked up hydraulic lines, wired in power pack. R/u saw to wellhead below OOA outlet. Held pre job, Started sawing off wellhead at 16:40hrs. Sawed through wellhead @ 20:30hrs. Pulled wellhead, saw and eq. up to top deck and put away. SDFN Ran borescope thru the OOA outlet down to ~120' with no evidence of cement. Removed OOA valve and tagged ~20' inside OOA outlet. Verified good cement at surface in LS, SS, IA, OA. 06/11/2023 - Sunday Held PJSM, discussed daily activities. Removed flange and bull plug from the LS, could not see cement at wellhead from previses cement job. Dropped plumb bob 200' in LS no tag. Contact OE and discussed. N/u flange and 1/2" HP hose to return tank. Lined up to pump down SS returns from LS. Pumped 4bbls away @ .5bpm/500psi with good returns from LS. R/u 1/2" hose and plumbed in a 2" kelly hose to LS to take returns for cementing. PJSM, PT lines to 1550psi-good test. Lined up to pump down SS returns up OA, mixed and pumped 4bbls 14ppg cement slurry. Closed OA and opened OOA. squeezed 5bbls away @ .5bpm/825psi. Pressure bled off to 300psi, squeezed another 5bbls away @ .5bpm/875psi. Drip returns coming from OOA. Closed OOA and opened OA, Pumped 26bbls of 14ppg slurry @ 2bpm/250psi with good cement returns at surface. Closed OA and opened IA. pumped 20bbl 14ppg slurry @ 2bpm/200psi with good cement returns at surface. Closed IA and opened LS, pumped 4bbls of 14ppg slurry with good cement returns at surface. Closed IA. Opened OOA, pumped 43bbls @ 1bpm/850psi, Hesitated once at 900psi, bled down to 150bbls. COnt pumping started taking injection @ 1bpm/600psi for 30bbls away and 500psi @ 43bbls away. SD pump bled to 0psi in 90secs. SI well. Performed sheen test all good. Washed up cementing eq. R/d form Di-16 well. Note: Opened OOA and didn't see and cement. Sent pictures to town. Injected 486 bbls of returns from Di-16 and Di-18 surface jobs into Di-17. Built 90bbls of 9.8 brine for Di-17 P&A 06/12/2023 - Monday 06/19/2023 - Monday Continued cleaning and preparing well room to cut Di-16 wellhead off. Closed IA and opened LS up to pump down SS returns up OA, Closed OOA and opened OA, Pumped 26bbls of 14ppg slurry Sent pictures to town pumped 4bbls of 14ppg slurry with good cement returns at surface. Closed OA and opened OOA. squeezed 5bbls away @ .5bpm/825psi. Opened OOA, pumped 43bbls @ 1bpm/850psi, Hesitated once at 900psi, bled down to 150bbls Ran borescope thru the OOA outlet down to ~120' with no evidence of cement mixed and pumped 4bbls 14ppg cement slurry Removed OOA valve and tagged ~20' inside OOA outlet. Verified good cement at surface in LS, SS, IA, OA saw to wellhead below OOA outlet Opened OOA and didn't see and cement COnt pumping started taking injection @ 1bpm/600psi for 30bbls away and 500psi @ 43bbls away Closed OA and opened IA. pumped 20bbl 14ppg slurry @ 2bpm/200psi with good cement returns at surface good cement returns at surface. Started sawing off wellhead at 16:40hrs. Sawed through wellhead Rig Start Date End Date Cmt Pump 5/16/23 6/26/23 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 16 50-733-20459-00-00 194-057 Daily Operations: 06/25/23 - Sunday Held PJSM, obtain PTW and discussed daily activities. Dropped weight and string down OOA and tagged 39' down. M/u 50' of 3/4" conduit, cut muleshoe on bottom. RIH down OOA and tagged 40', w/t pipe and POOH, recovered sample of what appears to be spud mud. RIH to 40', hooked up chugger pump and siphon fluid out of OOA to 27'. Continued with housekeeping, inventory and organized Cone, prep misc eq. for boat. 06/26/23 - Monday Held PJSM, discussed daily activities. Cont with housekeeping around platform and inventory eq. Boat arrived at 9am, off load ISO tanks, transfer fluid from the open top tanks to the 3 ISO, R/u vac unit and cleaned out mix tank to cut box. PJSM, r/u cement eq. Mix 6bbls of 14ppg cement slurry, top filled OOA up to surface with cement, pumped free water of of top of casing while slowly adding slurry until good 14ppg cement was at surface. Perform sheen test-no sheen, washed up cement eq. overboard. SDFN Mix 6bbls of 14ppg cement slurry, top filled OOA up to surface with cement, pumped free water of of top RIH down OOA and tagged 40', w/t pipe and POOH, recovered sample of what appears to be spud mud. Wellhead cutoff and top job approved by email from Bryan McLellan 6/26/23. -bjm RIH to 40', hooked up chugger pump and siphon fluid out of OOA to 27 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:NA Rig Elevation:NA Total Depth:11,709 ft MD Lease No.:ADL0018746 Operator Rep:Suspend:NA P&A:X Conductor:18-5/8"O.D. Shoe@ 1,132 Feet Csg Cut@ NA Feet Surface:13-3/8"O.D. Shoe@ 3,640 Feet Csg Cut@ NA Feet Production:9-5/8"O.D. Shoe@ 10,155 Feet Csg Cut@ NA Feet Liner:7"O.D. Shoe@ 11,703 Feet Csg Cut@ NA Feet TubingSS:3-1/2"O.D. Tail@ 9,785 Feet Tbg Cut@ NA Feet TubingLS:3-1/2"O.D. Tail@ 9,794 Feet Tbg Cut@ NA Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified LS Tubing Fullbore Bottom 11709 ft Surface SS Tubing Fullbore Bottom 11709 ft 2869 ft Wireline tag Initial 15 min 30 min 45 min Result Tubing (LS)1775 1739 1726 IA 1775 1739 1726 OA 0 0 0 Initial 15 min 30 min 45 min Result Tubing (SS)1860 1801 1782 IA 75 75 75 OA 0 0 0 Remarks: Attachments: SMGS 16 LS tubing had hard cement to surface. The SS had cement that looked like a sample of the Cook Inlet mud flats. May 27, 2023 Sully Sullivan Well Bore Plug & Abandonment S MGS Unit 16 Hilcorp Alaska, LLC PTD 1940570; Sundry 323-109 Photo of SS Tubing Cement Sample Test Data: P Casing Removal: Walter Waite P Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 11-28-18 2023-0527_Plug_Verification_SMGS_Di-16_ss                  Plug Verification - SMGS Dillon 16RD (PTD 1940570) 5/27/2023 Short String Tubing Cement Sample CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:McLellan, Bryan J (OGC) To:Aras Worthington Subject:Re: [EXTERNAL] RE: S MGS Unit 16 PTD# 194-057 Sundry #323-109 Date:Monday, June 26, 2023 2:12:01 PM Attachments:image002.png Aras, Hilcorp has approval to proceed with the top job on the OOA as described in your email this morning. Bryan Sent from my iPhone On Jun 26, 2023, at 9:08 AM, Aras Worthington <Aras.Worthington@hilcorp.com> wrote: Bryan, There is no bubbling and no change to fluid levels in either OA or OOA. Aras From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, June 26, 2023 8:59 AM To: Aras Worthington <Aras.Worthington@hilcorp.com> Subject: RE: [EXTERNAL] RE: S MGS Unit 16 PTD# 194-057 Sundry #323-109 Aras, Was there any sign of gas bubbling in the OA or OOA? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> From: Aras Worthington <Aras.Worthington@hilcorp.com> Sent: Monday, June 26, 2023 7:35 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: S MGS Unit 16 PTD# 194-057 Sundry #323-109 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Bryan, Over the weekend we cut off the wellhead of SMGS Unit 16 to access the OOA. Picture below. The TOC on LS, SS, and IA were all at surface. The OA TOC was 12” down from the cut. We were able to verify the tag in the OOA at 40’ MD with 3/4” threaded steel conduit on all sides of the OOA. We were able to hammer the conduit in a few inches and get a sample of what looked like spud mud but could not hammer in any deeper. We evacuated the OOA dry with conduit down to ~35’ MD. We request approval to perform a top job with cement to surface on the OOA. We will top job the OA to surface as well. Thanks and best regards, Aras <image002.png> From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 22, 2023 4:07 PM To: Aras Worthington <Aras.Worthington@hilcorp.com> Subject: [EXTERNAL] RE: S MGS Unit 16 PTD# 194-057 Sundry #323-109 Aras, Hilcorp has approval to proceed with cutting off the wellhead and attempt to find top of cement in the OOA. Discuss results and cementing plan with AOGCC before pumping any cement. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 <image001.jpg> 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: Aras Worthington <Aras.Worthington@hilcorp.com> Sent: Thursday, June 22, 2023 3:08 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: S MGS Unit 16 PTD# 194-057 Sundry #323-109 Bryan, We have installed all of the cement plugs in this well per Sundry. On the surface cement plug we did not get good circulation to surface out the OOA, although we squeezed ~53bbls of cement into the OOA with very minimal clear fluid returns from the OOA at surface during the job. We ran a borescope into the OOA to see what is in the OOA but we couldn’t see anything other than pipe and it didn’t appear to be going down the OOA, just coiling up in the OOA. We have tagged something at ~40’ below the OOA valves on both sides, but with string and a weight we have no way to get a sample and have no validation of a TOC of 40’ based on what we or the rig pumped when the well was constructed. We would like approval to cut the wellhead off and get full access to the OOA with small jointed pipe in an effort to either get a sample of what we are tagging and validate that it is cement, or failing that do a top job on the OOA from wherever the top of cement is. The OOA has been on an open bleed for five days now without any returns of any kind. Thanks and best regards, Aras Worthington Well Integrity Manager, PE Hilcorp Alaska LLC Aras.worthington@hilcorp.com 907-564-4763 907-440-7692 mobile The information contained in this email message is confidential and may be legally privileged and is intended only forthe use of the individual or entity named above. If you are not an intended recipient or if you have received thismessage 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 phonenumber 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 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: S MGS Unit 16 PTD# 194-057 Sundry #323-109 Date:Thursday, June 22, 2023 4:07:00 PM Aras, Hilcorp has approval to proceed with cutting off the wellhead and attempt to find top of cement in the OOA. Discuss results and cementing plan with AOGCC before pumping any cement. 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: Thursday, June 22, 2023 3:08 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: S MGS Unit 16 PTD# 194-057 Sundry #323-109 Bryan, We have installed all of the cement plugs in this well per Sundry. On the surface cement plug we did not get good circulation to surface out the OOA, although we squeezed ~53bbls of cement into the OOA with very minimal clear fluid returns from the OOA at surface during the job. We ran a borescope into the OOA to see what is in the OOA but we couldn’t see anything other than pipe and it didn’t appear to be going down the OOA, just coiling up in the OOA. We have tagged something at ~40’ below the OOA valves on both sides, but with string and a weight we have no way to get a sample and have no validation of a TOC of 40’ based on what we or the rig pumped when the well was constructed. We would like approval to cut the wellhead off and get full access to the OOA with small jointed pipe in an effort to either get a sample of what we are tagging and validate that it is cement, or failing that do a top job on the OOA from wherever the top of cement is. The OOA has been on an open bleed for five days now without any returns of any kind. Thanks and best regards, Aras Worthington Well Integrity Manager, PE Hilcorp Alaska LLC Aras.worthington@hilcorp.com 907-564-4763 907-440-7692 mobile The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: Middle Ground Shoal 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 11,709'N/A Casing Collapse Structural Conductor Surface 1,950psi Intermediate Production 4,760psi Liner 10,780psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Aras Worthington Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Aras.worthington@hilcorp.com 907 564-4763 Operations Manager 12,460psi Tubing Grade: Tubing MD (ft): 9,925 (MD) 9,293 (TVD) & N/A Perforation Depth TVD (ft): Tubing Size: 9.2# / L-80 (LS) & (SS) 9,785 (SS) & 9,794 (LS) 4/1/2023 HES VTL Ret. Packer & N/A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0018746 194-057 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99516 50-733-20459-00-00 Hilcorp Alaska, LLC N/A S MGS Unit 16 Middle Grnd Shoal Oil Same Length Size Proposed Pools: 83' 83' TVD Burst PRESENT WELL CONDITION SUMMARY 10,089' ~5,000 (LS) 5,570 (SS) 4,999 (LS) 5,564 (SS) ~3,435 See schematic 83' 30" 6,870psi MD 3,450psi 1,131' 3,639' 1,132' 3,640' 9,469'10,155' 18-5/8" 13-3/8" 1,132' 3,640' Perforation Depth MD (ft): See schematic 10,155' 7" See schematic 11,703'1,716' 3-1/2" (LS) & (SS) 10,088' 9-5/8" nnsns teee olooloo Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Meredith Guhl at 7:32 am, Feb 21, 2023 323-109 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2023.02.20 09:21:21 -09'00' Dan Marlowe (1267) X SFD 3/2/2023 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. Attempt to squeeze 5-10 bbls cement outside 9-5/8" casing through perfs at 2500' MD. DSR-2/22/23 Monitor and report fluid losses that occur while placing the deep cement plug. Provide 10 days notice for opportunity for AOGCC Wellsite inspection after this sundried work is complete, before September 30th, 2023. 10-407 BJM 4/6/23GCW 04/06/23 04/06/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.04.06 12:28:05 -08'00' RBDMS JSB 040623 P&A Sundry Well: Di-16 PTD #194-057 Well Name:S MGS UNIT (Dillon) 16 API Number:50-733-20459-00 Current Status:Shut-In Producer Rig:SL, EL, FB Estimated Start Date:April 2023 Estimated Duration:2 weeks 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):4358 psi @ 9229’ TVD (ca. 2011) Maximum Expected BHP:4358 psi Maximum Potential Surface Pressure: ~3435 psi Gas Column Gradient (0.1 psi/ft) Current Pressures LS/SS/IA/OA/OOA:0/0/0/0/75 History Di-16 was drilled in 1994 and completed as a Hemlock producer. The well was Shut-In in 2002. MITIAs in 2011 to 2400 psi failed, but the pressure loss was small (~150 psi/10 minutes). In 2022 the SS was punched and a reservoir cement plug was pumped per approved Sundry #322-068. This LSxSSxIA cement plug is ~5000’ in length and was tagged and MIT’d. The witnessed MIT was deemed inconclusive by AOGCC Inspectors. Approval from AOGCC was received to perforate the LSxSSxIA at ~4500’ MD in order to freeze- protect the well for the winter months of 2022-2023. This was performed in November of 2022 and the LSxSSxIA was freeze-protected with diesel to ~120’ MD. Current Status Reservoir is abandoned with a ~5000’ cement plug and tagged in the SS. LSxSSxIAxOA pressures have remained at 0 psi, validating that the reservoir cement plug has integrity. The OOA has low sustained casing pressure but has no injectivity. The TOC in the OOA was observed at the OOA gate valve outlet. The LS x SS x IA are perforated @ 4500’ MD via e-mail approval from AOGCC to freeze-protect the well for winter of 2022/2023. 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. Cementing reports indicate TOC in OOA is at 762' MD, which conflicts with recent observation of cement at the OOA gate valve when dropping a nut on a string into the OOA. Cementing reports did not indicate any cement returns to surface in OOA. -bjm The TOC in the OOA wasgp observed at the OOA gate valve outlet. Agreed on validity of reservoir cement plug. See attached pressure and bleed reports from Dec 22 - Feb 2023. -bjm Variance granted. -bjm LSxSSxIAxOApg gg pressures have remained at 0 psi, validating that the reservoir cement plug has integrity. pg gy P&A Sundry Well: Di-16 PTD #194-057 Procedural steps Fullbore 1. Verify circulation down the SS, up the IA and LS. 2. Pump SS x LS x IA intermediate cement plug as follows: ¾126 bbls 12 - 15.8 ppg Class G cement (down SS taking returns from the IA). i. When 113 bbls of cement are away SI returns from the IA and swap to taking returns from the LS. ii. Launch Foam Wiper Ball behind tail of cement. ¾26 bbls of 9.8 ppg brine displacement (puts TOC in SS @ ~3000’, equivalent with IA). ¾Verify good cement returns from the LS to surface Volumes ¾IA from 4500’to 3000’MD: 1500’x 0.0494 bpf =74 bbls ¾LS from 4500’to surface: 4500’x 0.0087 bpf = 39 bbls ¾SS from 4500’to 3000’MD: 1500’x0.0087bpf=13 bbls Total Cement Volume: 126 bbls ¾SS volume from 4500’MD to surface: 0.0087 bpf x 4500’=39 bbls ¾SS volume from 3000’MD to surface: 0.0087 bpf * 3000’=26 bbls Fullbore/Slickline/Eline 3. PT LSxIA to 1500 psi for 5 mins to verify hard bottom for surface cement job. 4. Tag TOC in SS, verify cement to surface in the LS. 5. Perforate the SS, 9-5/8”, and 13-3/8”casing @ ~400’MD. Fullbore 6. Verify circulation down the SS, out the IA, OA, and OOA (OOA may not circulate unless there is a channel). 7. Pump SSxIAxOAxOOA cement plug ¾30 bbls surfactant down SS (displace 10 bbls ea. Into IA, OA, and OOA) ¾Circulate 2x bottoms up from OOA, OA and IA (104 bbls, 48 bbls, and 40 bbls respectively). ¾100 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 OA (if circulation is established from the OOA). ii. Circulate out the OA until good cement returns are observed at surface then swap to taking returns from the IA iii. Circulate out the IA until good cement returns are observed at surface iv. SI IA, OA, and squeeze cement to 500 psi with the OOA open v. If cement returns to surface have been achieved from the OOA, then SI all annuli and squeeze cement to 500 psi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undry Well: Di-16 PTD #194-057 Volumes: ¾OOA from 400’to surface: 400’x0.13bpf=52 bbls ¾OA from 400’to surface: 400’x0.06bpf=24 bbls ¾IA from 400’to surface: 400’x 0.0494 bpf =20 bbls ¾SS from 400’to surface: 400’x 0.0087 bpf =3.5 bbls ¾Total Cement Volume: 100 bbls Attachments: Current Schematic Proposed Schematic 9HULILHGFHPHQWYROXPHVEMP P&A Sundry Well: Di-16 PTD #194-057 Dillon 16 Current: P&A Sundry Well: Di-16 PTD #194-057 Dillon 16 Proposed P&A: P&A Sundry Well: Di-16 PTD #194-057 Procedural steps Fullbore 1. Verify circulation down the SS, up the IA and LS. 2. Pump SS x LS x IA intermediate cement plug as follows: ¾ 126 bbls 12 - 15.8 ppg Class G cement (down SS taking returns from the IA). i. When 113 bbls of cement are away SI returns from the IA and swap to taking returns from the LS. ii. Launch Foam Wiper Ball behind tail of cement. ¾ 26 bbls of 9.8 ppg brine displacement (puts TOC in SS @ ~3000’, equivalent with IA). ¾ Verify good cement returns from the LS to surface Volumes ¾ IA from 4500’ to 3000’ MD: 1500’ x 0.0494 bpf =74 bbls ¾ LS from 4500’ to surface: 4500’ x 0.0087 bpf =39 bbls ¾ SS from 4500’ to 3000’ MD: 1500’ x 0.0087 bpf =13 bbls Total Cement Volume: 126 bbls ¾ SS volume from 4500’ MD to surface: 0.0087 bpf x 4500’ =39 bbls ¾ SS volume from 3000’ MD to surface: 0.0087 bpf * 3000’ =26 bbls Fullbore/Slickline/Eline 3. PT LSxIA to 500 psi for 5 mins to verify hard bottom for surface cement job. 4. Tag TOC in SS. 5. Perforate the SS, 9-5/8”, and 13-3/8” casing @ ~700’ MD. Fullbore 6. Verify circulation down the SS, out the IA, OA, and OOA (OOA is not likely to circulate unless there is a channel). 7. Pump SSxIAxOAxOOA cement plug ¾ 30 bbls surfactant down SS (displace 10 bbls ea. Into IA, OA, and OOA) ¾ Circulate 2x bottoms up from OOA, OA and IA (182 bbls, 84 bbls, and 70 bbls respectively). ¾ 175 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 OA (if circulation is established from the OOA). ii. Circulate out the OA until good cement returns are observed at surface then swap to taking returns from the IA iii. Circulate out the IA until good cement returns are observed at surface iv. SI IA, OA, and squeeze cement to 500 psi with the OOA open Volumes: ¾ OOA from 700’ to surface: 800 x 0.13 bpf =91 bbls ¾ OA from 700’ to surface: 700’ x 0.06 bpf =42 bbls ¾ IA from 700’ to surface: 700’ x 0.0494 bpf =35 bbls ¾ SS from 700’ to surface: 700’ x 0.0087 bpf =6 bbls ¾Total Cement Volume: 174 bbls Pump additional cement for squeeze and to continue pumping cement until cement is returned to surface in Long String. - bjm Superseded Tag TOC in LS and SS. Pressure test SS to 1500 psi. Provide 48 hrs notice for AOGCC to witness tags and PT -bjm. Attempt to squeeze 5-10 bbls cement through perf holes in casing at 4500'. -bjm Verified cement volumes. See note above about additional cement. -bjm Remove diesel from wellbore prior to cementing. -bjm Will have +/-1100 psi on IA and SS from U-tube of cement to surface in LS. -BJM P&A Sundry Well: Di-16 PTD #194-057 Attachments: Current Schematic Proposed Schematic Superseded P&A Sundry Well: Di-16 PTD #194-057 Dillon 16 Current: Superseded P&A Sundry Well: Di-16 PTD #194-057 Dillon 16 Proposed P&A: Superseded 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 11,709 feet See schematic feet true vertical 10,089 feet N/A feet Effective Depth measured ~5000 LS & 5570 SS feet 9,925 feet true vertical 4999 LS & 5564 SS feet 9,293 feet Perforation depth Measured depth 10,150 - 10,718 feet True Vertical depth 9,465 - 9,817 feet 3-1/2" SS 9.2# / L-80 9,785 (MD) 9,178 (TVD) Tubing (size, grade, measured and true vertical depth) 3-1/2" LS 9.2# / L-80 9,794 (MD) 9,186 (TVD) 9,925 (MD) Packers and SSSV (type, measured and true vertical depth) HES VTL Ret 9,293 (TVD) SSSV: N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: Middle Ground Shoal 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: 4,760psi 3,450psi 6,870psi 3,640 3,639 Burst Collapse 1,950psi measured TVD Production Liner 10,155 1,716 Casing Structural 9,469 7" 10,155 11,703 10,088 1,132 3,640 1,132Conductor Surface Intermediate 30" 18-5/8" 13-3/8" 12,460psi 9-5/8" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 194-057 50-733-20459-00-00 3. Address: Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0018746 Middle Ground Shoal / Middle Ground Shoal Oil S MGS Unit 16 Plugs Junk measured Length 83 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 83 N/A 0 Size 83 1,131 0 00 0 00 0 Sundry Number or N/A if C.O. Exempt: 32 -608 Sr Pet Eng: 10,780psi Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Aras Worthington Aras.Worthington@hilcorp.com 907 564-4763Operations Manager N/A pp kk tt Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2022.12.07 20:16:32 -09'00' Dan Marlowe (1267) WBD Di-16.doc JLL 12/02/22 Dillon Platform Di-16 Dillon Platform Well Di-16 Last Completed 7/20/94 Tubing 3 ½ Production 9.2#, L-80 Surface 9,794 SCBTC / 2.992 Long String/ Internally coated tubing 3 ½ Production 9.2#, L-80 Surface 9,785 SCBTC/ 2.992 Short String Casing and Tubing Detail Size Type Wt / Grade Top Btm CONN / ID Cement / Other 30 Surface 83 18 Surface 97.7# / X-57 Surface 1,132 QTE60 / 17.653 826sx lead & 630sx tail w/additives, good cement returns at surface 13 Intermediate 68#, K-55, BTC Surface 3,640 K-55/12.415 373bbls Lead @12.9ppg & 74bbls Tail @15.8ppg w/additives, Calculated TOC=762,(Incl.=0.6°) 9 Production 47# / L-80 Surface 10,155 Butt / 8.68 163 bbls premium w/ add @15.8ppg,CBL TOC @ 8,300 7 Liner 32#/P-110 9,987 11,703 TKC-BTC / 6.094 140 bbls @15.8 ppg w/ additives CBL TOC @ 10,150 Dual String Jewelry Detail L O N G S T R I N G Depth (RKB) Lengt h ID Item 55 2.99 Cooper Dual Hanger 1 9,794 26.97 2.687 Trico Kobe Pump Cavity 2 9,836 3.56 2.56 S.Sleeve, HES RA SSD # 121RA25623 3 9,871 3.55 2.56 S.Sleeve, HES RA SSD # 121RA25623 4 9,890 3.29 2.56 HES PRO Safety valve Nipple 5 9,925 10.11 3.03 Locator Seal ASSY w/8.66 of seals 6 9,925 6.04 3.88 HES VTL Retrievable Pkr. Sr# 12VTL96038-2 7 9,931 7.40 3.88 Seal Bore extension 8 9,938 .58 2.99 XO 9 10,002 1.47 2.56 Model R Profile Nipple 10 10,043 .80 2.42 XO 3 ½ BTC box x 2 8rd pin 31.67 2.441 1 jt 2 7/8 TBG cut @ 10,075 S H O R T S T R I NG 55 2.99 Cooper Dual Hanger A 9,785 .86 1.995XO, 3 ½ x 2 B 9,786 10.09 1.995 Tbg Pup jt C 9,794 26.97 Trico Kobe Pump Cavity TD = 11,709 TVD = 10,088 PBTD = 11,602 MAX HOLE ANGLE = 82O @ 11,650 MD 7 CBL TOC 10,150 13 @ 3,640 K C l Oil Top=10,115 MD Perfs 10150 10718 RKB-TH: 55 KB 7 @ 11,703 7 TOL 9,987 1 18 @ 1132 9-5/8 @ 10,155 2 3 4 65 7 8 9 10 C B TOF @ 10,743 Tag TOC SS @ 5570 ELM A 13 TOC tagged @ Surface CBL TOC @ 8300 10 AAA Tubing punch LSxSSxIA 4,500 MD 4,506 MD Cement Plug #1: 7 Liner: Tubing Tail to bottom of perfs @ 10,718 MD IA: Est. 5,000 MD LS: Est. 5,000 MD 9,794 MD SS: 5,570 MD - tubing punch 9,740 MD Rig Start Date End Date SL 10/30/22 11/11/22 11/02/22 - Wednesday PJSM, warmed and serviced eq. Removed snow drifts around equipment and cleared deck and walkways. Injected 172bbls of Brine returns from Di-16 circulation. Built 100bbls of 9.8 Brine, assist crane with arranging deck space. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 16 50-733-20459-00-00 194-057 11/01/22- Tuesday Held PJSM warmed and service checked eq. R/u circulating eq. to Di-17, injected 290bbls of brine/oil from Di-16 well circulation. R/u circulating eq. to SS/LS/IA. Pumped 85bbls of 9.8 brine down SS @ 3bpm/500psi, taking returns up IA. Shut-in the IA, pumped 44bbls of 9.8 brine, taking returns from the LS, Shut-in LS, continued pumping 206bbls of 9.8 brine, taking returns from the IA. Shut down pump. Monitored well static. Total brine pumped was 335bbls. Built 9.8 brine in H3 tank for upcoming fullbore cement job. Injected 150bbls of Brine/Oil into Di-17 disposal well. 10/31/22 - Monday R/U e-line w/1 9/16 tubing punch on SS, PT lubricator repair leaks as needed till good test 250/2500. RIh t/tag P/U t/9736 CCL depth, punched Tbg @ 9743'-46', POOH all shots fired. Pump down SS line up for returns up IA, pump 1.4 bpm 1000 psi had sporadic gas and oil returns. Circulated well w/483bbls of FIW down SS up IA @ 3bpm/500psi, swapped returns up LS and circulated tbg volume @ 3bpm/500psi. SD pump. Returns of oil gas and 9.2ppg brine. 10/30/22 - Sunday Mobe E-line crew to platform, orientate & PJSM,;R/U e-line w/1 9/16 tubing punch on SS, PT lubricator repair leaks as needed till good test 250/2500;RIh t/tag P/U t/9772 CCl placing shots @ 9776-9779, fire shots good indication shots fired, POOH all shots fired. pump down SS line up for returns up IA, pump 1.4 bpm 1000 psi had sporadic gas and oil returns. r/d e-line moved to Di-18 Rig Start Date End Date SL 10/30/22 11/11/22 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name S MGS Unit 16 50-733-20459-00-00 194-057 R/u testing eq, CMIT LSxSSxIA to 2500psi per Sundry, state inspector Austin McLeod witnessed test. Test inconclusive Pressures, Pre: 16psi Initial: 2693psi 15mins: 2639psi 30mins: 2598psi 45mins: 2565psi 60mins: 2525psi. R/u EL on SS, M/u 1.75" bailer, 1.69" weight bars x2 and CCL. RIH and tagged TOC @ 5570'elm, W/t and POOH no sample recovered. Tag witness by State inspector Austin McLeod 11/11/22 - Friday Received verbal approval from AOGCC to perforate LSxSSxIA for freeze protection and pressure monitoring. R/u EL, M/u weight bars, 1.69" CCL and 2"x6' gun (60deg phase) loaded with production charges. RIH and logged collar @ 4509', parked @ 4497' CCL depth (3 from top shot), fired gun @ 4500-06', good indication at surface gun fired. POOH all shots fired. R/d EL. R/u circulating eq. verified circulation with LS x IA @ 3bpm/400psi and LS x SS @ 3bpm/500psi. Freeze protected LS,SS,IA with diesel to 120' below wellhead. R/d circulating eq. 11/09/22 - Wednesday 11/05/22 - Saturday Warmed cement equipment. R/u and prepared to pump. Held PJSM, pumped 30bbls dn SS returns from IA to fluid pack well, shut in and PT iron t/ 3500psi-good test. Open IA pumped 10bbbls mud flush followed with 20bbls mud push, mixed and pumped 85bbls of cement then shut-in IA, bullhead 27bbls to formation .5bpm/1000psi, opened IA held 1000psi and worked rate up to 2bpm, after 200bbls away opened choke and worked rate up to 4bpm/400psi. Pumped 346bbls of cement. Shut-in IA open from LS, Launched ball displacement with 44bbls on 9.8ppg brine. Shut down. Performed static sheen test- no sheen observed, washed up cement over board, blow lines dry. 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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 Cc:Rixse, Melvin G (OGC) Subject:RE: Dillon 16 PTD 194-057 Sundry # 322-608 Date:Friday, November 11, 2022 9:47:00 AM Aras, Hilcorp has verbal approval to perforate the two tubing strings and the 9-5/8” casing at ~4500’ MD for the purpose of freeze protecting and pressure monitoring. A report of this work should be reported in the 10-407 for the P&A sundry #322-608. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Aras Worthington <Aras.Worthington@hilcorp.com> Sent: Thursday, November 10, 2022 4:54 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Dillon 16 PTD 194-057 Sundry # 322-068 Bryan, I left you a voicemail but not sure if you’re in the office today. We pumped the reservoir and TxIA plug on this well last Saturday. The cement job went well and we ended up injecting ~40 bbls of cement into the perfs (25 bbls was the volume needed to cover the perforations). Total cement pumped per plan was 346 bbls. We had a witnessed MIT on the reservoir plug in Dillon 16 yesterday that was deemed inconclusive. This is the last well that we need to perforate or punch for freeze-protecting purposes this season. Our witnessed tag of the TOC came in at 5570’ ELM in the SS (expected tag per plan was ~5000’ MD). We propose to perforate the SS @ ~4500’ MD to establish circulation to freeze-protect the LSxSSxIA. This will give us the option to pump and additional cement plug and MIT again next Spring, and then move uphole to the surface plug (perforations for that plug per approved sundry are ~700’ MD). Approved Sundry is attached for reference. We currently have EL on the platform and propose to execute these perforations in the morning and then de-mob EL for the final freeze-protection of the rest of the wells, then RDMO for the season. Thanks for your help, Aras Worthington Hilcorp Alaska LLC Senior Technical Advisor for Alaska Operations Aras.worthington@hilcorp.com 907-564-4763 907-440-7692 mobile 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. 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: NA Rig Elevation: NA Total Depth: 11,709 ft MD Lease No.: ADL0018746 Operator Rep: Suspend: NA P&A: X Conductor: 18-5/8" O.D. Shoe@ 1,132 Feet Csg Cut@ NA Feet Surface: 13-3/8" O.D. Shoe@ 3,640 Feet Csg Cut@ NA Feet Production: 9-5/8" O.D. Shoe@ 10,155 Feet Csg Cut@ NA Feet Liner: 7" O.D. Shoe@ 11,703 Feet Csg Cut@ NA Feet TubingSS: 3-1/2" O.D. Tail@ 9,785 Feet Tbg Cut@ NA Feet TubingLS: 3-1/2" O.D. Tail@ 9,794 Feet Tbg Cut@ NA Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Balanced 10,743 ft 5,570 ft 9.8ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 2693 2639 2598 2565 IA 2693 2639 2598 2565 OA 315 310 305 300 60 min Result Tubing 2525 IA 2525 OA 295 Remarks: Attachments: Wade Hudgens F Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): I traveled to the Dillon platform to witness the tag and CMIT (combo mechanical integrity test) on well 16 after a cement plug was pumped on 11/5/2022 to abandon the well. Both tubing strings and the inner annulus were pressure tested to a target of 2500 psi. The test failed with no signs of stabilization after sixty-minutes. Next, they tagged TOC (top of cement) in the tubing (SS) with an E-line conveyed 1.75-inch bailer assembly at 5,570 ft MD. Two set downs at the same depth were made. No sample observed in bailer once at surface. November 9, 2022 Austin McLeod Well Bore Plug & Abandonment S MGS Unit 16 Hilcorp Alaska, LLC PTD 1940570; Sundry 322-608 none Test Data: Casing Removal: rev. 11-28-18 2022-1109_Plug_Verification_SMGS_Di-16_am 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 gg test failed with no signs of stabilization after sixty-minutes. James B. Regg Digitally signed by James B. 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XHVZE This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. //~/--//-~"TFile Number of Well History File PAGES TO DELETE Complete RESCAN Color items. Pages: Grayscale, halftOnes, pictures, graphs, charts- Pages: Poor Quality Original - Pages: [] Other- Pages: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED Logs of vadous kinds [] Other COMMENTS: scanned bY: Bevedy Diann~than Lowell TO RE-SCAN Notes: Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: ~si STATE OF ALASKA ALASKOL AND GAS CONSERVATION COMMIS, REPORT OF SUNDRY WELL OPERATIONS 1. Abandon U Repair Well U Plug Perforations U Stimulate LJ Other U Cancel Procedure Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Approved Change A Operat. Shutdown Ill Perforate ❑ Re -enter Suspended Well ❑ p 1 T' `r•` PP Program ❑ 9 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: 1 :4" ij Name: Development 0 Exploratory ❑ 194 -057 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic❑ Service ❑ 6. API Number: 50- 733 - 20459 -00 r ®O 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018746 (Dillon Platform) S MGS Unit 16 (Di -16) 9. Field /Pool(s): . Middle Ground Shoal Field / E F and G Oil Pool 10. Present Well Condition Summary: Total Depth measured 11,709 feet Plugs measured N/A feet true vertical 10,088 feet Junk measured 10,743 feet Effective Depth measured 11,602 feet Packer measured 9,925 feet true vertical 10,073 feet true vertical 9,292 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 83' 30" 83' 83' Surface 1,132' 18 -5/8" 1,132' 1,131' 2,740psi 880psi.__... , Intermediate 3,640' 13 -3/8" 3,640' 3,639' 3,450psi 1,950psi Production 10,155' 9 -5/8" 10,155' 9,468' 6,870psi 4,750psi Liner 1,716' 7" 11,703' 10,087' 12,460psi 10,780psi Perforation depth Measured depth 10,150'- 10,158', 10,164'- 10,170', 10,180'- 10,200', 10,230'- 10,718' True Vertical depth 9,465'- 9,470', 9,476- 9,479', 9,486- 9,500', 9,521'- 9,816' Tubing (size, grade, measured and true vertical depth) SS: 9,785' MD SS: 9,178' MD 3 -1/2" 9.2# L -80 LS: 9,794' MD LS: 9,185' MD Packers and SSSV (type, measured and true vertical depth) HES VTL Retrievable acker /NA EC � . ,p;sg5' MD (9,292' D) / N/A 11. Stimulation or cement squeeze summary: N/A :t �� Intervals treated (measured): J AN 2 7 2092 N/A Treatment descriptions including volumes used and final pressure: N/A Alaska Oil &Gas Cons. Comm 12. Representative Daily Average Production or Injection Data Ancjwr eye Oil -Bbl Gas -Mcf Pressure Tubing Pressure Prior to well operation: 0 0 0 500 psi 380psi / 1240psi Subsequent to operation: 0 0 0 550 psi 375psi / 1130psi 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory Development El " Service ❑ Stratigraphic❑ Daily Report of Well Operations Y 15. Well Status after work: Oil 0 Gas ❑ WDSPL 7 GSTOR ❑ WINJ ❑ 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 -063 Contact Hilcorp Drilling Dept. at 777 -8301 Printed Name Timothy C. Brandenburg Title Drilling Manager \ Signature �(----- ,4111 �!ri Phone 276 -7600 Date 1/25/2012 AN S rI Z � Form 10-404 Revised .! 11,Q_ S JAN 27 2012 .r 1 Z7. I /"G' Y;,. Original Only r @Vro Dillon Platform St Dillon Platfo Well Di 16 ``` - Last Completed 7/20/94 D� -16 Casing and Tubing Detail RKB -r14: 55' KB - _ ?. `—'� Size Type Wt / Grade Top Btm CONN 1 ID Cement / Other 30" Surface 83' 826sx lead & 630sx tail Y 18'/e" Surface 97 -7# l X -57 Surface 1.132' OTE60 / 17 .653" '^' s, good cement /additive returns at t6 -, surface 1132 : ; ' . ' 3'/.' 373bb1s Lead • (3 762 ; @12.9ppg & 14bbls A _c? 762' 68 #, K -55, 13 ; 13'/e" Intermediate Surface 3,640' K•55/12.415 rail @15.8ppg @1,610' BTC w /additives, Calculatec TOC= 762',(IncI. =0.61 163 bbls premium w/ 9 S /," Production 47# / L -80 Surface 10,155' Butt / 8.68" add @15.8ppg, CBL TOC @ 8,300' 140 bbls @15.8 ppg w/ 966 7" Liner 32 #/P -110 9,987' 11,703' TKC -BTC / 6.094" additives CRI TOC Cdl iG is rr 8 ; '' • @ 10,150' ��; 8301:' :• t • c ,. Tubing Sieves " Open Long String/ 3 4 ' - 3'/:" Production 9.2#, L -80 Surface 9,794' SCBTC 1 2.992" Internally coated tubing y 98T 3 W Production 9.2#, L 80 Surface 9,785' SCBTC/ 2.992' Short String 955.. Dual String ,o,us =ropPert1015o Jewelry Detail 7"CB1 7, L 0 N G S T R I N G Depth (RKB) Length ID Item TOC ' 101517 . _ _ _ _ 55 2.99 Cooper Dual Hanger 1 9,794' 26.97' 2.687" Trico Kobe Pump Cavity 2 9,836' 3.56' 2.56" s Sleeve, HES RA SSD # 121RA25623 _ 3 9,871' 3.55' 2.56" S.Sleeve, HES RA SSD # 121RA25623 4 9,890' 3.29' 2 56" HES "PRO" Safety valve Nipple :� Bern Per} 10,14' . - — 5 9,925' 10.11' 3.03" Locator Seal ASSY wl8.66' of seals 6 9,925' 6.04' 3.88" I IES VTL Retrievable Pkr. Sr* 12VTL96038 -2 , 7 9,931' 7.40' 3.88" Seal Bore extension 8 9,938 .58' 2.99" XO_ _ TOF 9 10,002' 1.47' 2.56" Mod_ el "R" Profile Nipple JVmm„ 10,7 10 10,043' .80' 2.42" X0 3 '/ :" BTC box x 2 W 8rd pin 31.67' 2.441 _Lit 2 7 /8" TBG cut @ 10,075' SHORTSTRING 55' 2.99" Cooper Dual Hanger A 9,785' .86' 1.995' XO, 3 W x 2'/a' 7 ;@ B 9,786' 10.09' 1.995' Tbg Pup t C 9,794' 26.97' _ Trico Kobe Pump Cavity ID = 11,709' TVD = 10,088' PBTD = 11,602' MAX HOLE ANGLE = 82 @ 11,650' MD Chevron • • Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original R KB (ft) Water Depth p ( ft ) 01-16 S MGS UNIT 16 ADL0018746 5073320459 QU1379 110.00 + yam, .. JOb$ _ 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 DI -16 507332045900 1940570 4/20/2011 00:00 - 4121/2011 00:00 Operations Summary Email to Jim Regg, AOGCC, 4/20 advising of upcoming MIT for Di -16. 4/21/2011 00:00 - 4122/2011 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 -16: Pressure test lubricator to 250 psi low, 3000 psi high. RIH w/ 2.83" OD gauge ring to 9817', POOH. RIH w/ 2.56" BO shifting tool to top sliding sleeve at 9855', work though to close sliding sleeve, RIH and locate bottom sliding sleeve at 9889', work through to close sliding sleeve, POOH. RIH w/ 2.5" GS w/ 2.84" OD isolation sleeve with solid bottom and set in Kobe cavity at 9792.5', POOH. Bleed gas cap on Di -16. Shut down for night. 4/22/2011 00:00 -4/23/2011 00:00 Operations Summary Jeff Jones with AOGCC waived witness of MIT's at 0850 4/22, per Jim Regg. Cont. to bleed gas cap from Di -16. RU on Di -16 and Pump FIW down 9 -5/8" casing x tubing annulus, pressure up to 2300 psi, lost 125 psi in 7 minutes. Second pressure test on Di -16: Pump FIW down 9 -5/8" casing x tubing annulus, pressure up to 2300 psi, lost 150 psi in 10 minutes. Third pressure test on Di -16: Pump FIW down 9 -5/8" casing x tubing annulus, pressure up to 2300 psi, lost 150 psi in 10 minutes. Fourth pressure test on Di -16: Pump FIW down 9 -5/8" casing x tubing annulus, pressure up to 2400 psi, lost 150 psi in 10 minutes . Fifth pressure test on Di -16: Pump FIW down 9 -5/8" casing x tubing annulus, pressure up to 2400 psi, lost 160 psi in 10 minutes, after 3 hours pressure dropped to 1700 psi. Shut down for night. 4/23/2011 00:00 - 4/24/2011 00:00 Operations Summary Sixth pressure test on Di -16: Pump FIW down 9 -5/8" casing x tubing annulus, pressure up to 2400 psi, lost 150 psi in 10 minutes. RU on Di -16, Pressure test lubricator to 250 psi low, 3000 psi high, RIH w/ 1" OD prong to 9839', work tools to knock out plugs, pressure increased from 1050 psi to 1410 psi, POOH. RIH w/ 2.5" GS to 9816', latch isolation sleeve, POOH. Secure well and depart platform. Cancel remaining procedure due to failed pressure test on 9 -5/8" casing. • • SUAITEE 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' August 15, 2011 Mr. Timothy C. Brandenburg Drilling Manager Union Oil Company of California (UNOCAL) _ >� ArJ Z" P.O. Box 196247 Anchorage, AK 99519 -6247 Re: South Middle Ground Shoal Unit 16 (194 -057) Request for Mechanical Integrity Test Variance for SMGS Unit 16 while Injecting Approved Wastes as Authorized by AIO 8.005 Dear. Mr. Brandenburg: In correspondence dated August 3, 2011 UNOCAL requested a waiver to the Mechanical Integrity Test (MIT) for SMGS 16 as required by AIO 8.005. UNOCAL submitted valid information demonstrating mechanical integrity (MI) by other means. The Commission ACCEPTS UNOCAL's submission. On April 12, 2011, the Commission issued AIO 8.005 granting approval for UNOCAL to employ two shut -in development wells on Dillon Platform for waste liquid disposal during circulation and plugging operations. Production operations on Dillon Platform were halted December 8, 2002 when UNOCAL determined that such operations were not economically viable. UNOCAL was required to demonstrate that the wells had mechanical integrity prior to injecting waste fluids. A standard pressure test of the tubing x casing annulus was successfully accomplished on SMGS 17; however a standard pressure test could not be accomplished on SMGS 16 due to pressure communication between the tubing and annulus. Alternate testing methods can be employed to demonstrate MI. UNOCAL has successfully demonstrated that the production casing of SMGS 16 is competent by setting a deep wireline plug and pressuring the wellbore to 2400 psi. Minimal pressure loss was observed during the 3.5 hour charted observation period. UNOCAL also performed a temperature survey of the well which did not exhibit any thermal anomalies which would indicate the casing was leaking. UNOCAL has complied with the requirements of Condition 1 of AIO 8.005. No variance is necessary. Sincerely, frr Daniel. eamount, Jr. Chair • • Chevron Timothy C Brandenburg Union Oil Company of California %101 Drilling Manager P.O. Box 196427 Anchorage, AK 99519 -6247 Tel 907 263 7657 Fax 907 263 78888 4 Email brandenburgt @chevron.com August 3, 2011 Commissioner i Alaska Oil & Gas Conservation Commission # t t 7i a 333 W. 7 Avenue Anchorage, Alaska 99501 HSS ian tT ti^ /t y... r Re: Request for Variance of the Mechanical Integrity Test required for Temporary Disposal in Di -16, PTD 194 -057 Dear Commissioner, Union Oil Company of California would like to request a variance of the Mechanical Integrity Test required by the Administrative Approval Area Injection Order 8.005 dated April 12, 2011, for the Dillon Platform, specifically regarding the well SMGS Unit 16 (Di -16), PTD 194 -057. Area Injection Order (AIO) No. 8, approved on December 8, 2002, authorized injection of non- hazardous oil field fluids for the purpose of fluid disposal into specific strata. On January 29, 2003, AIO 8.002 authorized disposal of 50,000 barrels of non - hazardous, Class 11 fluids generated by cleaning operations on Dillon Platform into the MGS A, B, C D, E, F, and G Oil Pools, within SMGS 12 and SMGS 14. Operations completed in 2009 injected a total of 7,960 barrels into SMGS 12 and SMGS 14, leaving 42,000 barrels for injection under the order. AIO 8.003 was approved on March 4, 2003, which authorizes the injection of storm water. On April 12, 2011, AIO 8.005 was approved and authorized the use of SMGS 16 and SMGS 17 for purposes of disposal of liquid wastes generated through the well circulation and abandonment operations. A Bundle (i.e. jug) MIT was completed on Di -16 on June 20, 2011, confirming the integrity of the casing and packer. Analysis of the static temperature survey completed on July 23, 2011, indicated the casing was not leaking. If approval is granted, Union Oil Company of California is prepared to comply with the remaining conditions of AIO 8.005 including monitoring wellhead pressures and injection rate continuously during injection, submittal of post- injection reports of injected fluid source, type, and volume by well, and will immediately shut in the well and notify the Commission if there is any change in the well's mechanical condition, etc. Please see the attachments containing information per 20 AAC 25.412. Please let us know if we can provide any further information by contacting myself at 263 -7657 or Nigel Bonnett at 263 -7853. Union Oil Company of California / A Chevron Company • • Chairman Daniel T. Seamount, Jr. Alaska Oil & Gas Conservation Commission January 22, 2009 Page 2 Sincerely, it Timothy C. Brandenburg Drilling Manager Attachments: Di -16 Bundle MIT Test dated 6/20/2011, Di -16 Temperature Survey dated 7/23/2011, Operations Summary, and Well Schematic. Union Oil Company of California / A Chevron Company • • hevro Dillon Platform Dillon Platform Well Di -16 ■'..., Di -16 Last Completed 7 /20/94 Casing and Tubing Detail R98-1'H: 55' 9 8 - - Size Type Wt / Grade Top Btm CONN / ID Cement / Other Y 30" Surface 83' 826sx lead & 630sx tail 18 5 /e" Surface 97.7# /X -57 Surface 1,132' QTE60 /17.653" w /additives, good cement returns at surface 18 e@ 1 13 �" 373bb1s Lead @12.9ppg & 1132' K -55, 74bbls Tail @15.8 ppg 13 3 /a' Intermediate 68 #, Surface 3,640' K- 55/12.415 @ ppg 0782' BTC w /additives, Calculated 13 i" TOC= 762',(Incl. =0.6 °) pg3a4o 163 bbls premium w/ add 9 %" Production 47 #/ L -80 Surface 10,155' Butt /8.68" @15.8ppg, CBL TOC @ 8,300' 140 bbls @15.8 ppg w/ COL TOC 7" Liner 32 #/P -110 9,987' 11,703' TKC -BTC /6.094" additives CBL TOC @ 0 8300' 10,150' +t 1 ! a . Tubing C 3 'A" Pr o d uc t ion 9 L - 80 Surface 9 SCBTC / 2.992" Long String/ Internally y; coated tubing i m 3 W Production - 9.2#, L -80 - Surface 9,785' - SCBTC/ 2.992" Short String ■ - 7 7 "TOL Dual String 1 .� In 9 9,987' Jewelry Detail • ss ® = L t0 0174-10,115• LONG STRING Depth (RKB) Length ID Item 10.155 - MD 55' 2.99 Cooper Dual Hanger E, 1 9,794' 26.97 2.687" Trico Kobe Pump Cavity - S.Sleeve, HES RA SSD # ~ P e n s 2 9,836' 3.56' 2.56' 121RA25623 - 10150'- 10718' 3 9,871' 3.55' 2.56" S.Sleeve, HES RA SSD # 121RA25623 4 9,890' 3.29' 2.56" HES 'PRO" Safety valve Nipple 5 9,925' 10.11' 3.03" Locator Seal ASSY w/8.66' of seals 6 9,925' 6.04' 3.88° HES VTL Retrievable Pkr. Sr# 12VTL96038 -2 7 9,931' 7.40' 3.88° Seal Bore extension 8 _ 9,938 .58' 2.99" X0 _ 9 10,002' 1.47 2.56" Model "R' Profile Nipple 10 10,043' .80' 2.42' X0 3 %2" BTC box x 2 W 8rd pin 31.67' 2.441 1 jt 2 7/8" TBG cut @ 10,075' TOF@ SHORTSTRING 10,743' - 55' 2.99° Cooper Dual Hanger A 9,785' .86' 1.995" X0, 3 '/s" x 2 3 / " B 9,786' 10.09' 1.995' Tbg Pup jt C 9,794' - 26.97' - Trico Kobe Pump Cavity 7 "@ 11,703 4_ Perforations TD = 11,709' TVD= 10,088' Zone Top Btm Ft Accum.SPF Date Comments j PBTD= 11,602' Hemlock 10,150' 10,158' 8' 4 5/10/2002 MAX HOLE ANGLE= 82 @ 11,650' MD Hemlock 10,164' 10,170' 6' 4 5/10/2002 Hemlock 10,180' 10,200' 20' 4 5/10/2002 Hemlock 10,250' 10,280' 30' 4 5/10/2002 Hemlock 10,348' 10,368' 20' 4 5/10/2002 Hemlock 10,428' 10,440' 12' 4 5/10/2002 Hemlock 10,580' 10,610' 30' 4 5/10/2002 Hemlock 10,665' 10,695' 30' _ 4 5/10/2002 Hemlock 10,230' 10,718' _ 488' 4 7/18/1994 TCP Note: • Re- perforated all Hemlock intervals, 05/09/02 • Both Sliding Sleeves closed 4/21/2011 ' • Jug Test Passed w/plug in tubing at 10,002' - LS= 2950psi, SS= 2400psi, 9- 5/8 "= 2400psi • Temp -Press Survey completed 7/23/2011 to 9843', could not pass. WBD Di- 16.doc AC 11 - 2010 • • Bundle (i.e. Jug) Test for Di -16 Completed on 6/20/2011. i / j. I 1 , F ''` I **XI' 4 1 , � \ wl *t•' • � y • s..,er . 4 f.1. 4,...4,001** AM , Mk MJe t-- 1 . .,. 1 1 • • 'Chevron 1 WeII:IDi - Long 1 Fierd:lDillon 107 -23 -2011 Pressure (psia) 1000 1500 2000 2500 3000 3500 4000 4500 5000 0 w Pressure- Temperature Profile 500 __ -= 1. Going in hole to 9844' woo 1500 • 2000 - - 2500 1 - 3000 3500 • • 4000 - 4' - a =: 4500 - c 2 5000 O. 5500 • a 6000 • 6500 • • 7000 7500 8000 8500 9000 • 9500 10000 1 1 I 1 1 I - 1 1 I 50 60 70 80 90 100 110 120 130 140 150 160 170 180 Temperature (Deg. F) — Pressure — 133/8" 7" —LS Tbg — 18 5/8" 9 5/8" —SS Tbg — Temperature Report date: 7/28/2011 • • Chevron • ka0 Chevron - Alaska Weekly Operations Report Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) DI -16 S MGS UNIT 16 ADL0018746 5073320459 QU1379 110.00 Jobs Primary Job Type Job Category Objective Actual Start Date Actual End Date Mechanical Integrity Test Well Services _ 6/20/2011 Primary Wellbore Affected Wellbore UWI Well Permit Number DI -16 507332045900 1940570 Daily Operations 6/20/2011 00:00 - 6/21/2011 00:00 Operations Summary Notified AOGCC Jim Regg 6/19/2011. R/U Slickline, pressure test lubricator to 250 psi low /3000 psi high. RIH w/2.5" GR to 10,034'. RIH w/ 2.5" R Xline Running tool and 2.56" PR plug body to 9,836', will not pass, POOH, redress. RIH w/ same to 10,002', set plug body. R/D Slickline. Pump filtered Inlet water (FIW) down annulus to 2400 psi. Allow annulus, LS, and SS to stabilize. MIT Bundle Pressure Test passed. Starting pressures: Long string: 1000psi Short string: 300psi 9 5/8: 400psi 13 3/8: 15psi 18 5/8: 250psi Stabilized pressures: Long string: 2950psi Short string: 2400psi 9 5/8: 2400psi 13 3/8: 60psi 18 5/8: 250psi , I� • ' Chevron 1110 Chevron - Alaska Weekly Operations Report Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) 01-16 S MGS UNIT 16 ADL0018746 5073320459 QU1379 110.00 Jobs Primary Job Type Job Category Objective Actual Start Date Actual End Date Mechanical Integrity Test Well Services 6/20/2011 Primary Wellbore Affected Wellbore UWI Well Permit Number 01-16 507332045900 1940570 Daily Operations 7/2312011 00:00 - 7/24/2011 00:00 Operations Summary RIH w /tandem pressure temp gauges. RIH to 9843', could not pass, POOH. R/D E -line, secure well. • • Page 1 of 3 Regg, James B (DOA) From: Brooks, Phoebe L (DOA) I\I.Z� II (14091: o Sent: Tuesday, April 26, 2011 2:07 PM C'( To: Quick, Mike [ASRC] P7') 11 57 0 Cc: Regg, James B (DOA); Maunder, Thomas E (DOA) ASS 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 ebe ou, Phoebe A APR 2 6 2Q ` Phoebe Brooks Statistical Technician 11 Alaska Oil and Gas Conservation Commission 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 +/-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 comps sible 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 e s of FIW in 54 minutes, pressuring the 9 -578" 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 +/- 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 Midcontinent/Alaska 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.regq(aDalaska.cov; doa .aoacc.prudhoe.bav @alaska.gov; phoebe.brooks(aDalaska.gov; tom.maunder ,alaska.Qov 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 O P.T.D. 1940560 Type test, P Test psi 2230.5 Casing 780 2,345 2,345 2,345' P/F P - Notes: AI0 8.005 authorizes injection; MITIA OA 38 55 55 55 • Prepare Di -17 well for disposal of fluids from decommissioning operations on platform; Iongstring tubing Well Di -16 • Type Inj. I TVD - 9,292' Tubing 1,240 Interval O 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); Iongstring tubing Well Di -17 - Type Inj. 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 OA 38 _38 38 38 Iongstring 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 1 = 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.xls 0 • MIT — S. Middle Ground Shoal Unit 17 Dillon Platform PTD 1940560 4/22/2011 . mil J i ,..11..r,;„ w4 1 ar r MITIA , H 22 r1 I w t'4 , �� 4n V. 11..0 Di- j 30 ,' 0C k A 4. y: t . e <$ `"�V $s �'..r#,,�! x � '`''SC �- X 4'.'..4..,- ,` 's � 2 i � , q pb k.µ P r. k w*...+c �u.. "i . ' ... . .. i . . D:II", D; . �trr ta LS . ., MITT F s ; toy 4. E Aid_ Ps A534 K1/4. , c \ . . - \ _ . : i • • SlfaTIE DIF ALASEA 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 Union Oil Company of California t a 617 P.O. Box 196247 t 1 Anchorage, AK 99519 Re: Middle Ground Shoal Field, E, F and G Oil Pool, S MGS Unit 16 (Di -16) Sundry Number: 311 -063 Dear Mr. Brandenburg: 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 . +:r eekend. gre, f Joh ' . or an iss ner DATED this 13 day of April 2011. Encl. • • Chevron Timothy C Brandenburg Union Oil Company of California %10111 Drilling Manager P.O. Box 196427 Anchorage, AK 99519 -6247 Fax 907 263 7657 Fax 907 263 78888 4 Email brandenburgt @chevron.com March 1, 2011 RECEIWC Commissioner o n Z(111 Alaska Oil & Gas Conservation Commission 333 W. 7 Avenue ° >:bt9 Anchorage, Alaska 99501 kg ! i! & 6 $ CMS Well Status Change Request PTD 194 -057 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 16 (Di -16) PTD 194 -057 from '1 -OIL' to 'WINJ'. 1 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, - C _ Timoth 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 iii' • c l • 04ps g um ■ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION (t (o APPLICATION FOR SUNDRY APPROVALS 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 II ' Exploratory ❑ 194 -057 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic ❑ Service El 6. API Number: 50- 733 - 20459 -00 » 0 0 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes El No El S MGS Unit 16 (Di -16) 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): 11,709' ' 10,088' ' 11,602' 10,073' N/A 10,743' (fish) Casing Length Size MD 1 TVD Burst Collapse Structural Conductor 83' 30" 83' 83' Surface 1,132' 18 -5/8" 1,132' 1,131' 2,740psi 880psi Intermediate 3,640' 13 -3/8" 3,640' 3,639' 3,450psi 1,950psi Production 10,155' 9 -5/8" 10,155' 9,468' 6,870psi 4,750psi Liner 1,716' 7" 11,703' 10,087' 12,460psi 10,780psi Perforation Depth MD (ft): j Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 10,150'- 10,158', 10,164'- 10,170', 9,465'- 9,470', 9,475- 9,479', 3 - 1/2" / 9.2# L - SS: 9,785' 10,180'- 10,200', 10,230'- 10,718' 9,486'- 9,500', 9,521'- 9,816' LS: 9,794' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): HES VTL Retrievable Packer / N/A 9,925' MD (9,292' TVD) / N/A 12. Attachments: Description Summary of Proposal El 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ❑ Service 0 r 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 21- Mar -11 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ el e 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 ' 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 1 Vo 3 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test lik Location Clearance ❑ RECEIVED' Other: 0 �rLi , �c�a.CS- c � W 1 AAP �tOdc �V. C� M 1 dr Subsequent Form Required: kACI VA /IF M 3 APPROVED BY lk u *: J OU Approved by: ' 1 MISSIONER THE COMMISSION Date: f,-/34..// ` G 1 N AA2 42011 / Form 10 -403 Revised 1/2010 Submit in Duplicate hevro ' Di -16 Dillon Platform Dillon Platform • Well Di -16 Last Completed 7/20/94 Casing and Tubing Detail RKB -TH: 55' KB - Size Type Wt / Grade Top Btm CONN / ID Cement / Other 30" Surface 83' 826sx lead & 630sx tail 18 %" Surface 97.7# / X -57 Surface 1,132' QTE60 / 17.653" w /additives, good cement returns at surface 18 / 1132' 13 %" 373bb1s Lead CaIc.TOC @12.9ppg & 74bbls 4 b, @ 762' 68 #, K -55, 13 r" 13 %" Intermediate BTC Surface 3,640' K- 55/12.415 Tail @15.8ppg @ 3,640' w /additives, Calculated TOC= 762',(IncI. =0.6 °) 163 bbls premium w/ 9 %" Production 47# / L -80 Surface 10,155' Butt / 8.68" add @15.8ppg, CBL TOC @ 8,300' 140 bbls @15.8 ppg w/ 95/8" n 7" Liner 32 #/P -110 9,987' 11,703' TKC -BTC / 6.094" additives CBL TOC CBL TOC rT B , @ 10,150' @ 8300' 1 °I: Tubing -� Sieves 2 _i Open Long String/ 3 = 4 3'/2' Production 9.2 #, L -80 Surface 9,794' SCBTC / 2.992" Internally coated tubing pa � 7 8 ° 3'/2" _ Production 9.2 #, L -80 _ Surface 9,785' SCBTC/ 2.992" Short String a R 9 9-5/8 " L. 10 Dual String 10,155' = Top Perf 10150' Jewelry Detail 7" CBL - L 0 N G S T R I N G Depth (RKB) Length ID Item TOC - 55' 2.99 Cooper Dual Hanger 10,150' 1 9,794' 26.97' 2.687" Trico Kobe Pump Cavity 2 9,836' 3.56' 2.56" S.Sleeve, HES RA SSD # 121RA25623 3 9,871' 3.55' 2.56" S.Sleeve, HES RA SSD # 121RA25623 = 4 9,890' 3.29' 2.56" HES "PRO" Safety valve Nipple - Btm Perf 10718' 5 9,925' 10.11' 3.03" Locator Seal ASSY w/8.66' of seals 6 9,925' 6.04' 3.88" HES VTL Retrievable Pkr. Sr# 12VTL96038 -2 7 9,931' 7.40' 3.88" Seal Bore extension 8 9,938 .58' 2.99" XO TOF @ 9 10,002' 1.47' 2.56" Model "R" Profile Nipple 10,743' 10 10,043' .80' 2.42" XO 3'/2' BTC box x 2 %e" 8rd pin 31.67' 2.441 1 jt 2 7/8" TBG cut @ 10,075' SHORTSTRING 55' 2.99" Cooper Dual Hanger 0 A 9,785' .86' 1.995" XO, 3 '/2' x 2 %" 7 " 0 4 � e B 9,786' 10.09' 1.995' Tbg Pup jt 11,703' C 9,794' 26.97' Trico Kobe Pump Cavity TD = 11,709' TVD = 10,088' PBTD = 11,602' MAX HOLE ANGLE = 82 @ 11,650' MD • • 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 Tess 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 II 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 W also confine the injection fluids to the Hemlock. 7. All Togs 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' 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). 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' TVD 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% 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 y 224080 226000 226000 230000 232880 2168857 I I I 2468857 r I 2458080 - + + + + DI + - 2458000 1 DI -18 DI -8 I DI -8 - ' DI -9RD I 1 ∎ I -4 . 0 I I 2466088- + + I + 1 — • 1 DI–F11 + - 2455880 I 1 DI -2 1 . I DI j ' + � Q I • I - t 1 2464000- + + MAS Sr. 574 / + + -2484000 I DI - 1 • A I • .., . I DI-1 —_ _ 1 – DI -17'' 1 I 2182080- + + ` I + � / t + + -2482008 I DI / I 1 I . I • 1 DI -5 I 2468800- + + 1 + + + -2468088 I I DI X12 . i 2458080 ---I— +— _ _ _ _ .4 + + + - 2450002 DI– = 1 ti I 1 • DI– ' 1 1 1 r 1 2458800- + + I + + + -2456808 I 1 1 I . I . DI– ;RD I 1 1 2454851 1 1 l • I 1 l 1 r 2454051 224808 226808 228088 238888 232808 Ocale • Dillon Platform 0 1000 2000 3000 4000 >A1eet, O :\NAU\MCBU\Alaska\Depts\Drilling \Users \TylerS\2009 Projects\z_ 2009_ Platform _Pressure_Mitigation\Platform & Well Data\Dillon Platform \! Dillon Platform Docs\ DillonPlatformSpiderMm.new.docx dolanij Page 1 3/2/2011 • • • MF.ChAR1CAL INTEGRITY R ORT t S r--t. 0 SPUD D::"_ . 4 /06_ c 1 L OPFR & FIELD 'S kA WI:LL DATA � �:: 1�'`t0� .. \a� . ; xn: kkw ? \0 :� tc Cass. g : _l Sb : (.tSS 1 _ ; DV • k - 10) `�� i Shoe: I, `14 k( '1TVD ; '=L? : c,cgl:.11) ,TI k% T Ubi ^g. � Packer ( S MD ahlTV1D; Set at an .._ �� ; Perfs �(��'� to t t ;'I GEAR iC 1 INTEGRITY - PART fl Annulus Press est LI ; 15 miu ; 30 miii Comments: • MECHANICAL INTEGRITY PART n Cement Volumes:, Amt. Liner W:, Geg12.7. ), Dv V4Ast, Czt vOl to cheer per<:,s , '! .vmi aaa •s. ■asn -wmwaa r-se v'La:ts-.s- m_a.:.'�on— _ _ • endL*... _ .. -- Theoretice.l TOG (N4 •,. -..� _ _-ate , : -_ _ : _: • ,: -- a e.�, -,. _... ._ Cement Bond. Log (TES or kto); In AOCCC File CSI. Evalu &tioo s zone above perfs k\ � Produc ion Log: Type ; Evalus.tion • • CONCLUSIONS: 5 art 1: �T ri� raz� -�•- • • (tt,----\". . . Chevron Timothy C Brandenburg Union Oil Company of California Drilling Manager P.O. Box 196427 Anchorage, AK 99519 -6247 Tel 907 263 7657 Fax 907 263 78888 4 Email brandenburgt @chevron.com • March 8, 2011 RECEIVEL Commissioner MAR 0 8 2U i l Alaska Oil & Gas Conservation Commission 333 W. 7 Avenue Masks OP & Oat Cons, Commission Anchorage, Alaska 99501 Ate* 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(achevron.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 UNOCAL • • Mi a Ground Shoal Field Di x. Platform Well Di -16 API# 50 -733- 20459 -00 CURRENT COMPLETION Completed 7/20/94 Casing & Tubing RIG to Tbg Hngr = 55' ( Size Wt Grade Thread ID Top Btm 30" Surface 83' 18 -5/8" 97.7# X -56 QTE60 17.653 Surface 1132' 13 -3/8" 68# K -55 BTC 12.415 Surface 3640' 9 -5/8" 47# L -80 BTC 8.681 Surface 10,155" Liner 7" 1 324 I P -110 I TKC -BTC 1 6.094 1 9988' 1 11,703' Tubing LS 3 - 1/2" 924 L -80 SCBTC 2.992 Surf 9794' ` SS 3 -1/2" 9.24 L -80 SCBTC 2.992 Surf 9796' Jewelry Item I Depth Length I ID ( Description LONG STRING 55' 299 Cooper 13 -5/8" 5k Dual Hanger 1. 9794' 2697' 2.687 Trico Kobe Pump Cavity 2. 9836' 3.56' 2.56 Sliding Sleeve, HES RA SSD # 121RA25623 t 3. 9871' 3.55' 2.56 Sliding Sleeve, HES RA SSD # 121RA25623 4. 9890' 329' 256 HES Model "RRO" Safety Valve Nipple 5. 9925' 10.11' 3.03 Straight Slot Locator Seal Assy w/ 8.66' of seals. 6. 9925' 6.04' 3.88 HES VTL Retrievable Pkr. Serial # 12VTL96038 -2 A 7. 9931' 7.40' 3.88 Seal Bore Extension B 8. 9938' .58' 2.99 Crossover 1 9. 10,002' 1.47' 2.56 Model "R" Profile Nipple MI in C 10. 10,043' .80' 2.42 Crossover 3 -1/2" BTC box X 2 -7/8" 8rd Pin 31.67' 2.441 1 Joint of 2 -7/8" Tubing. Cut (a) 10,075' 2 G U N F I S H Total Length of fish 11. 10,743' 1.67' 2.25 Mechanical Tubing Release 3 -. 4 94.80 2.441 3 Joints of 2 -7/8 ", 6.44, L -80, EUE 8rd Tubing 5 .42 1.995 Crossover, 2-7/8" EUE 8rd x 2 -3/8" 1 . 4.07 1.995 2 -3/8" Pup Joint 8 �� 1.38 1.79 Otis "XN" Nipple 9.89 1.995 2 -3/8" Pup Joint 9 .33 1.995 Crossover, 2 -3/8" x 2 -7/8" EUE 8rd 10 2.24 2.441 2 -7/8" Balanced Isolation Production Sub .42 1.995 Crossover, 2-7/8" EUE 8rd x 2 -3/8" 30.12 1.995 3— 2 -3/8" x 10' Pup Joints 5.51 1.57 Mechanical Firing head 4.15 — 4 -5/8" Gun Blank Toy 4 88.00 — 4 -5/8 ", 4 spf TCP Gun io,210' 1.54 4 -5/8" Gun Blank 1.10 — EDA 2.39 — Time Delay Firing Head Hemlock Btm of Fish @11,391' SHORT STRING 55' 2.99 Cooper 13 -5/8" 5k Dual Hanger "" 11 A. 9785' .86' 1995 Crossover, 3-1/2" x 2 -3/8" B. 9786' 10.09' 1995 Tbg Pup Jt. C. 9796' 26.97' — Trico Kobe Pump Cavity { Perforations Accum Zone Top Btm Ft SPF Date Comments Hemlock 10,150' 10,158' 8' 4 5/10/2002 Hemlock 10,164' 10,170' 6' 4 5/10/2002 - Hemlock 10,180' 10,200' 20' 4 5/10/2002 Hemlock 10,250' 10,280' 30' 4 5/10/2002 1, Hemlock 10,348' 10,368' 20' 4 5/10/2002 TD = 11,709' PBTD = 11,602' Hemlock 10,428' 10,440' 12' 4 5/10/2002 Max Deviation = 82° (x3 11,650' Hemlock 10,580' 10,610' 30' 4 5/10/2002 Hemlock 10,665' 10,695' 30' 4 5/10/2002 10,230' 10,718' 488' 4 7/18/1994 TCP Dillon 16 dwg 7 -20 -94 Revised 5/20/02 SLT Plot •sure & Rate vs Time - Well Di -16 • 1400 1200 1000 '9 5/8" 13 3/8" 800 20" w 26" 3 Tubing — Tubing 2 a` 600 . — _ f , o ..... • 1� 400 siii.■ — - 200 . _ c0 co N e0 co O O7 O> 07 O> W O O, O O O> Q> O O O O O O O O O O O O O O O O O O O O O O O O O O O O O ` O cn O) e0 e0 1- N co r r O O N V V t`0 M N \ C (�` N O 8> CB W W r 45 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 C 07 O N N Ch 7 Li, CO r W m O N N C) V l0 CO ` CO O O N N O O ,- .- .- O O O O O O O O O ,- O O O O O O O O O .- ,- .- O O Date 13 3/8" 20" 26" TIO Report 02/15/11 25 180 200 01/05/11 30 200 240 Data Sheet 12/14/10 30 200 240 11/17/10 30 200 240 10/29/10 35 210 240 Di -16 10/09/10 40 200 240 • 08/11/10 540 40 220 1250 380 07/14/10 540 40 220 240 1250 380 BOT HOLE HYD PUMP 06/16/10 530 40 200 220 1240 380 05/19/10 530 40 250 180 1240 370 04/21/10 530 40 70 100 1230 370 Permit # 1940570 03/24/10 530 40 60 100 1220 370 02/17/10 520 40 60 1210 360 01/20/10 520 50 60 90 1200 360 API # 50- 733 - 20459 -00 12/20/09 520 50 70 100 1200 360 11/25/09 520 60 60 100 1200 360 10/31/09 520 70 80 100 1190 350 08/30/2008 to 03/01/2011 10/30/09 520 75 80 1195 360 10/29/09 520 75 80 1195 360 10/28/09 520 75 80 1195 360 10/27/09 520 75 80 1190 360 10/26/09 520 70 80 1190 360 10/25/09 520 75 80 100 1190 360 10/24/09 510 0 90 1180 380 10/23/09 510 0 90 100 1180 380 10/22/09 510 0 90 100 1180 380 10/21/09 500 0 100 100 1180 370 10/16/09 560 0 100 120 1240 400 10/10/09 560 0 100 110 1230 380 10/02/09 560 0 100 120 1160 400 09/25/09 560 20 100 120 880 400 09/12/09 560 0 100 120 920 390 09/10/09 560 0 100 120 980 390 09/09/09 560 0 100 140 940 400 09/08/09 560 0 100 140 920 380 08/29/09 560 0 120 140 980 380 3/10/2011 8:44 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2011 03 01 (6).xls Di -16 • Plot Pressure & Rate vs Time - Well Di -16 1400 • 9 5/8" 13 3/8" 1200 26 • Tubing Tubing 2 1000 800 - w N N V. a` 600 400 — 200 0 r.... — , 8 8 8 8 m 2 m 8 2 co 8 2 0) o) o) o) o) o) o) 0) o) rn rn 8 o o O o 0 0 0 o o O O O 0 0 0 O o 0 o 0 0 0 0 0 0 0 0 o O 0 o o3 � 8 8 63 O O) O O) O) W 8 N N N N N N N co N co N N N N N N N C) N) N 0 0 O) N O O) 0) W CO .er M N en N N N N N N N N N N N N N N , - 17 N 77 N f+) V N (0 r N CO' O N `‘- M V N N N- W O O M N N ( 8 E, o O O O O O O O O O O O O O O O , O O O O O O O Date 13 3/8" 20° 26" TIO Report 07/14/10 40 220 240 06/16/10 40 200 220 Data Sheet 05/19/10 40 250 180 04/21/10 40 70 100 03/24/10 40 60 100 Di -16 02/17/10 40 60 01/20/10 520 50 60 90 1200 360 12/20/09 520 50 70 100 1200 360 BOT HOLE HYD PUMP 11/25/09 520 60 60 100 1200 360 10/31/09 520 70 80 100 1190 350 10/30/09 520 75 80 1195 360 Permit # 1940570 10/29/09 520 75 80 1195 360 10/28/09 520 75 80 1195 360 10/27/09 520 75 80 1190 360 API # 50- 733 - 20459 -00 10/26/09 520 70 80 1190 360 10/25/09 520 75 80 100 1190 360 10/24/09 510 0 90 1180 380 01/30/2008 to 07/31/2010 10/23/09 510 0 90 100 1180 380 10/22/09 510 0 90 100 1180 380 10/21/09 500 0 100 100 1180 370 10/16/09 560 0 100 120 1240 400 10/10/09 560 0 100 110 1230 380 10/02/09 560 0 100 120 1160 400 09/25/09 560 20 100 120 880 400 09/12/09 560 0 100 120 920 390 09/10/09 560 0 100 120 980 390 09/09/09 560 0 100 140 940 400 09/08/09 560 0 100 140 920 380 08/29/09 560 0 120 140 980 380 08/28/09 560 0 120 140 940 380 08/27/09 560 0 120 140 940 380 08/26/09 540 0 120 140 980 380 08/25/09 540 0 120 140 980 380 08/24/09 560 0 120 140 920 380 08/23/09 560 0 120 140 940 380 08/22/09 560 0 120 140 960 380 3/10/2011 9:32 AM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2010 07 31 (5).xls Di -16 • • • Plot Pressure & Rate vs Time - Well Di -16 1400 - 1200 -■...9 5/8" 1000 13 3/8" 20" 26" — Tubing 800 Tubing 2 d L 3 co N d L a 600 400 ...."•■■■ 'Nr---- 200 - - - -' 0 — LO CD CO CO CD N N- N- N- O O O o O O o p O N N N N N 0. 0 0 0 r 0 0 0 Date 13 3/8" 26" TIO Report 01/23/08 0 260 12/19/07 0 Data Sheet 11/21/07 0 250 10/17/07 480 0 250 260 920 320 09/12/07 480 0 260 260 900 310 Di -16 08/12/07 470 0 260 260 970 300 07/18/07 470 0 250 260 960 300 06/13/07 460 0 250 260 940 300 BOT HOLE HYD PUMP 05/16/07 460 0 230 240 940 290 04/18/07 450 0 220 230 920 280 03/22/07 440 0 280 300 910 280 Permit # 1940570 02/21/07 440 0 240 240 890 270 01/18/07 440 0 280 300 890 270 12/15/06 430 0 240 250 870 260 API # 50- 733 - 20459 -00 10/20/06 420 0 260 830 250 09/29/06 420 0 260 280 820 250 09/04/06 400 0 290 820 240 11/01/2005 to 01/31/2008 07/20/06 400 0 270 810 240 06/25/06 320 0 240 250 880 210 05/24/06 390 0 250 870 220 04/21/06 390 0 240 240 860 220 03/17/06 380 0 250 840 210 02/26/06 370 0 220 840 210 01/19/06 370 0 300 300 820 200 12/08/05 400 0 200 200 820 230 11/18/05 330 0 170 180 810 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 -16 • 0 Plot Pressure & Rate vs Time - Well Di -16 1400 �..-:...... ,., 1200 Tubing — Tubing 2 •••••••9 5/8" 13 3/8" 1000 20" 26" 800 a \ 600 I 400 i - '' 1141114 200 ' . pm - 0, 0 0 0 0 0 0 0 0 o N r . N 7- tt, Time "' E o DATE HRS ON Tubing Tubing 2 9 5/8" 13 3/8" 20" 26" 01/19/06 0 "820 )0 370 0 300 300 Wavered Well 12/08/05 0 820 2'4 400 0 200 200 11/18/05 0 180 810 330 0 170 Data Sheet 10/24/05 0 180 800 360 0 295 10/18/05 0 180 810 330 0 170 09/20/05 0 0 780 0 0 0 0 Di -16 08/20/05 0 175 760 340 0 275 07/21/05 0 720 120 240 0 240 07/02/05 0 180 740 340 0 260 Permit # 1940570 05/21/05 0 160 730 320 0 250 04/16/05 0 140 700 305 0 240 02/24/05 0 140 680 300 0 240 API # 50- 733 - 20459 -00 01/29/05 0 120 660 300 0 250 12/28/04 0 120 640 285 0 250 11/13/04 0 115 600 240 0 275 02/01/2004 to 01/31/2006 10/31/04 0 115 600 240 0 275 10/06/04 0 09/30/04 0 110 600 260 0 270 08/20/04 0 100 540 245 0 280 07/07/04 0 90 530 230 0 280 06/23/04 0 90 520 220 0 280 04/30/04 0 90 480 200 0 250 03/24/04 0 60 450 190 0 260 01/27/04 0 595 0 150 0 70 12/26/03 0 50 380 160 5 70 12/15/03 0 l 50 380 160 5 70 11/04/03 0 50 150 0 105 3/10/2011 9.24 AM - Wavered Wells Reports v7b.xls J J Dolan Wavered Well Report Jan 2006.xls Di -16 • • ALAzgA 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) P.O. Box 196247 " "° APR 2 ZO Anchorage, Ak 99501 '' Re: South Middle Ground Shoal Unit 16 (194 -057) J Sou OI1 le Ground Shoal Unit 17 (194 -056) 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 , chor . • e, Alas a and dated April 12, 2011. l it 4 " 157 . orman Cathy P. Foerster issi I r Commissioner i 4. `4' 4 ‘ • y `,1�. • i 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), "[t]he 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. e~d:fÆ~E :J !Æ~!Æ~~!Æ FRANK H. MURKOWSKI, GOVERNOR A.I1A.SIiA OIL AND 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: 333 w. 7TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 t Ct~~eS1 Trtis letter confirms your conversation with Conunission EngLl1eer 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 information should be ubmitted forthwith. . No an Daniel T. Seamount, Jr. Commissioner BY ORDER OF THE COMMISSION DATED this _day of November, 2004 Enel. SCANNE"'n, Nn'l ')."t. l~ ')00. ~ " e"", "\..r I f..; f r... .14- " "'. ..1' 1If" ( 1. Type of Request: 3. Address: 7. KB Elevation (ft): KB 127' above MSL 8. Property Designation: Dillon Platform 11. Total Depth MD (ft): 11,709' Casing Structural Conductor Su rface Intermediate Production Liner Perforation Depth MD (ft): 10,150' to 10,718' Packers and SSSV Type: STATE OF ALASKA ALASKA Oil AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROftECEIVE 20 AAC 25.280 Operational shutdown U Perforate U OCT 1 2J2JlMJ Annular Dispos. U Plug Perforations D Stin¡4Iat~ n .1 ril11J,e ~~~.sLO""',-t,,?: t, ",' Other 0 AI8SIdrtJI & uS..- l;Û,l.h ",'iJrï~'''"b..¡,k., Perforate New Pool D Re-enter Suffte,~ed Well C Monitor Frequency . .m:..~~~~ß 4. Current Well Class: 5. Permit to [)rill Number: ,>, Suspend U Repair well D Pull Tubing D P. O. Box 196247 Anchorage, Ak. 99519-6247 Development Stratigraphic Q] D Abandon U Alter casing D Change approved program D 2. Operator Name: Union Oil of California aka Unocal Exploratory D 94-57 Service D 6. ~, Number: /..Sét733-20459 ,,/~' ;,,,,.,,..'" // / // 9. Well Name and Number: Di-16 10. Field/Pools(s): Total Depth TVD (ft): 10,089' Length MGSIE,F&G Pools PRESENT WELL CONDITION SUM ARY Effective Depth MD (ft): 10,230' Size MD 262' 1,259' 3,767' 30" 10,285" 185/8" 133/8" 95/8" 1,715' 7 Perforation Depth TVD (ft): 9465 to 9816' Plugs (measured): Junk (measured): TCP gun @ 10,743 Collapse TVD Burst 317' 1,131' 2,250' 630 psi 3,450 psi 1,950 psi 6,870 psi 4,760 psi 8,160 psi 7,020 psi Tubing MD (ft): 3,639' 9,470' 10,087' Tubing Grade: LS : 9,935' SS : 9796' LS 3-1/2" SS 3-1/2" Both 9.2# L-80 SCBTC Packers and SSSV MD (ft): 12. Attachments: Description Summary of Proposal ~ Detailed Operations Program D BOP Sketch D 14. Estimated Date for Commencing Operations: 16. Verbal Approval: Commission Representative: 10,075' 13. Well Class after proposed work: Exploratory D Development 15. Well Status after proposed work: OilQ] GasD WAG D GINJ D Date: Q] Service D Plugged WINJ D D D D Abandoned WDSPL 17. I hereby certify that the foregoing is true and c rect to the best of my knowledge. Contact Title Oil Team Supervisor 907-263-7805 Date COMMISSION USE ONLY Printed Nam}7 ~ Cole Signature~JI(/'á~ Phone Conditions of approval: Notify Commissi so that a representative may witness Plug Integrity D Other: Subsequent Form Required: Mechanical Integrity Test D 28-Sep-2004 Sundry Number: SOC¡//¿J-O Location Clearance D RBDMS BFL NOV 2 2,.2P¥- 'I ~~ J GIN A L APPLICATION RETURNED 11/17/04 . NOT APPROVED BY COMMISSION COMMISSIONER Approved by: Form 1 o-~vised 12/2003 BY ORDER OF THE COMMISSION Date: Submit in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Performed: Alter Casing 0 Change Approved Program 0 2. Operator Union Oil of California Name: aka Unocal Suspend RepairWell 0 Pull Tubing 0 Operation Shutdown Plug Perforations 0 Perforate New Pool 0 4. Current Well Class: Development 0 Stratigraphic 0 {::"/"-"¡ (" ~ .'., '~'.,., ~,,!j1'.9 "" ¡ ~ llf'" ~..... '.~~ .' \l \~...... I '~\ Perforate Wai~ Ii Other ..¡ Stimulate 0 Ti~e: Extension ~tl{jtZOQ4t secure Re-enter SJ~p~nd~lW ell 0./, ",,,, '-'. ~', 5. Permit to Drill Nt¡lffiþ~r: "'. ". ;t;¡:t):~.~¡I)i1 Exploratory 0 94-57 . , . ,r¡r'~r:-- Service 0 6. API Number: 50-733-20459 9. Well Name and Number: Di-16 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 11,709' feet true vertical 10,088' feet Effective Depth measured 11,602' feet true vertical 10,073' feet Casing Length Size MD Structural 210 3O" 83' Conductor 1,259 18 5/8" 1,132' Surface 3,767' 13 3/8" 3,640' Intermediate Production 10,285" 9 5/8" 10,155' Liner 1,715' 7 11 ,703 Plugs (measured) Junk (measured) fish @ 10,743' TVD 83' 1,131' 3,639' Burst Collapse 9,468' 10,087' Perforation depth: Measured depth: 10,150'-10,158', 10,164'-10,170', 10,180'-10,200', 10,250'-10,280', 10,348'-10,368', 10,428'-10,440', 10,580'-10,610', 10,665'-10,695', 10,230'-10,718' True Vertical depth: 9465-9470',9475-9479',9486-9500', 9535-9556', 9601-9614', 9653-9600',9744-9760',9790-9805',9512-9816' Tubing: (size, grade, and measured depth) LS 3-1/2" 9.2# L-80 SCBTC @9794', SS 3-1/2" 9.2# L-80 SCBTC @ 9796' Packers and SSSV (type and measured depth) HES VTL Retrievable Packer @ 9,925' 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: 60 21 718 90 Subsequent to operation: This well was shut-in subsequent to operations 14. Attachments: 15. Well Class after proposed work: Copies of Logs and Surveys Run Exploratory 0 Development 0 Daily Report of Well Operations 16. Well Status after proposed work: Oil0 Gas 0 WAG 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Tubing Pressure 80 Service 0 GINJ 0 WINJ 0 WDSPL 0 Sundry Number or N/A if C.O. Exempt: Contact Printed Name P. M. Ayer Signature Title Petroleum Engineer 'c:\ ~u~cD MAR 16 2004 Phone ~18fL. Form 10-404 Revised 12/2003 nQlh1~1^, I UNOCAL8 API# 50-733-20459-00 Middle Ground Shoal Field Dillon Platform Well Di-16 Completed ¡CURRENT COMPLETION 7/20/94 RKB to Tbg Hngr = 55' C & T b c Hemlocl{ Dillon 16 dwg 7-20-94 aSln2 u i n 2 Size Wt Grade Thread ID Top Btm 30" Surface 83' 18-5/8" 97,7# X-56 QTE60 17,653 Surface 1132' 13-3/8" 68# K-55 BTC 12.415 Surface 3640' 9-5/8" 47# L-80 BTC 8.681 Surface 10,155" Liner 7" 32# P-IIO TKC-BTC 6,094 9988' 11,703' Tubine LS 3-1/2" 9.2# L-80 SCBTC 2.992 Surf 9794' SS 3-1/2" 9.2# L-80 SCBTC 2.992 Surf 9796' J ewe ry Item Depth Leneth ID Description LONG STRING 55' 2.99 Cooper 13-5/8" 5k Dual Hanger 1. 9794' 26,97' 2.687 Trico Kobe Pump Cavity 2, 9836' 3,56' 2.56 Sliding Sleeve, HES RA SSD # 121RA25623 3, 9871' 3,55' 2.56 Slidine: Sleeve, HES RA SSD # 121RA25623 4, 9890' 3,29' 2,56 HES Model "RRO" Safety Valve Nipple 5, 9925' 10,11' 3,03 Straie:ht Slot Locator Seal Assy wi 8,66' of seals, 6. 9925' 6,04' 3,88 HES VTL Retrievable Pkr. Serial # 12VTL96038-2 7. 9931' 7.40' 3,88 Seal Bore Extension 8. 9938' ,58' 2,99 Crossover 9. 10,002' 1.47' 2,56 Model "R" Profile Nipple 10, 10,043' ,80' 2.42 Crossover 3-1/2" BTC box X 2-7/8" 8rd Pin 31.67' 2.441 1 Joint of 2-718" Tubing, Cut (ä) 10,075' GUN F ISH Total Len2th offish=648' 11. 10,743' 1.67' 2,25 Mechanical Tubing Release 94,80 2.441 3 Joints of2-7/8", 6.4#, L-80, EVE 8rd Tubing .42 1.995 Crossover, 2-7/8" EVE 8rd x 2-3/8" 4.07 1.995 2-3/8" Pup Joint 1.38 1.79 Otis "XN" Nipple 9.89 1.995 2-3/8" Pup Joint .33 1.995 Crossover, 2-3/8" x 2-7/8" EVE 8rd 2.24 2.441 2-7/8" Balanced Isolation Production Sub .42 1.995 Crossover, 2-7/8" EVE 8rd x 2-3/8" 30.12 1.995 3- 2-3/8" x 10' Pup Joints 5,51 1.57 Mechanical Firing head 4.15 - 4-5/8" Gun Blank 488,00 - 4-5/8", 4 spf TCP Gun 1.54 - 4-5/8" Gun Blank 1.10 - EDA 2.39 - Time Delay Firing Head Btm ofFish @ 11,391' SHORT STRING 55' 2.99 Cooper 13-5/8" 5k Dual Hanger A. 9785' .86' 1.995 Crossover, 3-1/2" x 2-3/8" B. 9786' 10.09' 1.995 Tbg Pup .It. C. 9796' 26.97' - Trieo Kobe Pump Cavity Perforations Accum Zone Top Btm Ft SPF Date Comments Hemlock 10,150' 10,158' 8' 4 5/10/2002 Hemlock 10,164' 10,170' 6' 4 5/10/2002 Hemlock 10,180' 10,200' 20' 4 5/10/2002 Hemlock 10,250' 10,280' 30' 4 5/10/2002 Hemlock 10,348' 10,368' 20' 4 5/10/2002 Hemlock 10,428' 10,440' 12' 4 5/10/2002 Hemlock 10,580' 10,610' 30' 4 5/10/2002 Hemlock 10,665' 10,695' 30' 4 5/10/2002 10,230' 10,718' 488' 4 7/18/1994 TCP Revised 5/20/02 SLT DILLON PLATFORM API # 50-733-20459-00 S. MGS UNIT # 16 WELL HISTORY LAST WORK: 10n/98 Well #16 DATE COMPLETED EVENT 1994 7/22 Completed as an Oil Well. 1998 10/7 Pulled Kobe standing valve from 9821'. Ran Kobe standing valve to 5720', shook off, POOH. 1999 5/14 Asphaltene Solvent and Xylene overflush sqz. 2001 6/12/01 Coil tubing push TCP guns/Reperf Hemlock 2002 12/1012002 This well was shut in and isolated at the surface with multiple flanges to isolate the well from surface flow lines. Di#16HistlO-7-98.doc, last revised 2/18/2004 page 1 DI-5 -;:: I:;:' ~ DI-3 20 x 13 5/8 0.1815 300 54.45 3 1/2 tbg. 0.0087 300 2.61 18 5/8 x 13 3/8 0.1291 300 38.73 2 7/8 tbg. 0.00579 300 1.737 13 3/8 x 9 5/8 0.0671 300 20.13 I~ 858 334 9 5/8 x dual 3 1/2 0.OH7 300 15.21 355 9 5/8 x dual 2 7/8 0.0571 300 17.13 pump limit 21 psi 9 5/8 x 3 1/2 0.0626 300 18.78 Don Sta œ;ROOM" 1-' iIIi------ ~:x951r Ë3I~ 1-4 15.5bb1s 30 bbIs !!:!..- . ~~.- I. . ~10 DI-13 œ; ROOM 112 _I DI-18 1.2 bbI 2fI)bIs DI-17 0.75 bbls 15.5bb1s 20 bbls DI-16 15 bbIS 2fI)bIs DI-l1 7:4bÞIs ~ 25l:)t)1s !?!:L ~-. lEG ROOM .4 wen 82 wellM wen n Wen # 10 Wen #13 Wen 87 Wen 118 Wen 811 wen #16 Wen 17 Wen # 18 well 83 We" #5 Wen." 12 Wen 11114 wen 11115 WELL BAY # 1 Pumped down tbg.tbg on vac, bled down 9 5/8 x tbg. Pumped 28 bbls. Gas still at surface. Pumped down 2Ox135/8 2bbIs 100 psi. 20 bbls in 133/8, Try to pull eclipse paker with wire line could not get out. Well had 180 on annulus and 150 on tbg would not bleed down, Tryied pumping down short side old pump In hole could not pump. Put 30 bbls of 9.8 in annulur 9 5/8x tbg. Pumped down 1.5. tbg. Retumed up short side 100 bbIs. Put 15 bbls In 13 5/8x9 5/8. 4 bbls in 20" ann. Hook up to 20" took approx 1 bbl with charge press on ann. 133.8)( 9 5/8 RumP and bleed 3 bþls i~ an~. 9 5/8xtbg fluid packed with oil. 14.4 bblsin tbg. well 10 Is abondoned Fill 20" ann 2 bbls, tbg on vac 7bbls in 13 3/8 x 9 5/8 28 bbls 9 5/8 x tbg. 5 1.5. 5 s.s.bbls down short side did tbg. And ann same time WELL BAY # 2 20" fluid packed,13 3/8 x 9 5/8 2 bbls and started getting diesel fluid back to surface. Pumped SbbIs in Ibg.' 20 bbls in 9 5/8 ann.Annulus and tbg. Have oil returns 0 press on well. 20" fluid packed,13 3/8 x 9 5/8 2 bbls and started getting diesel fluid back to surface. Pumped 5bbIs in Ibg.' 20 bbls in 9 5/8 ann.Annulus and Ibg. Press up to 500 psi. on both tbg. Strings had oil to top no press on Ibg. Pumped and bled 7bb1s in Ibg. Annulus. When annulus was fluid packed. Oil at surface.5 bbls in 13518 x 95/8 press limit. .5 bbls In 20" Well had SOpsl. On 13 3/8x 9 5/8 bleed down to 20psl put bbls of 9.8 fluid, 95/8onn. 20 bbls fluid, tbg.5bbls each, wells 185/8 has 110 psi. bled off and fluid packed with press limit of 50 psl..75 of a bbl. Well had loopsl. On 13 3/8x 9 5/8 bleed down to 20psi put 15bb1s of 9.8 fluid, 95/8onn. 20 bbls fluid, tbg.5bbls each, wells 185/8 has 60 psi. bled off and fluid packed ann with .75 bbls. Well had 150psl. On 13 3/8x 9518 bleed down to 20psi put20bbls of 9.8 fluid, 95/8onn. 20 bbls fluid, tbg.5bbls each, wells 185/8 has25 psi bled off and fluid packed with 9.8 salt took 1.2 bbls. WELL BAY # 4 Rig up pump 4 bbls 1.5. 4 bbl 5.5. 9 5/8 x tbg. 25 bbls, 13 3/8 x 9 5/8 fluid packed wI 12 bbls, 20" ann. 2 bbIs. Fluid packed Pumped 4 bbls 1.5. tbg. 4 bblss.s.R/u to 9 5/8 x 3 1/2 ann. Pumped 15 bbls fluid packed oil to surface. Pumped 4bbls down tbg Is. 4 bbls 5.5. both went on vac. Pumped 15 bbls 95/8 x31/2. Wtth50 psi press limit 0 bbls in 13 3/8x 95/8 fluid packed 20x 133/82 bbls, fluid packed 13 3/8x9 5/812 bbls press up to 200 psi and held. Rig up pump 5 bbls I.s. 25 bbl S.s. Be: 9518 x tbg. 8 bbls fluid packed 011 to surface 13 5/8x9 5/8, RIU to 20" ann fluid pack 5 bbls. Press limit 20 psi. PERMI'T 9z~-~057 9/~--' 057 9~-057 9b-057 9z~.--057 DATA ~.~C/'AC/G R/CAL C'~,.DL/CNL/GR/CAL Z/CN/6 Are dr'y d~'tch samples Was the well cor'ed? AOGCC Indi' v~' dua'l / e o '1 o g i c a 'I M a t e r' i' a '1 s T DATA_PLUS I~verI Jr'y Page: 1 Date: 04/ 14/96 RUN DATE .... RECVD L 36~1~'10178 1 L 0-Y10178 1 L 36~1-10178 1 T 0~'11571 comp L 8~00-11575 1 r'equ'ired? yes ~~d r'ece~s yes ~~Ana'lysi's & descr'~,'p.+.~:on r'e.ce'ived? ~'- Rece~'ved?_ yes no-- Ar'e well tests required? yes We'll ~s ~n comp'l~ance COMMENTS 07/25/9z~ 07/25/94 07/25/94 0t05/9 , 10/05/94 no yes no Unocal Energy Resourcf'~vision Unocal Corporation 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL~ DOCUMENT TRANSMITTAL Alaska September 16, 1994 TO: Larry Grant FROM: Vince LeMieux 3001 PORCUPINE DRIVE ANCHORAGE, AK 99501 ALASKA OIL & GAS CONSERVATION COMM P.O. BOX 196247 ANCHORAGE AK 99519 UNOCAL TRANSMITTING AS FOLLOWS 1 Blueline and sepia each MIDDLE GROUND SHOAL :~_/~..//~ SBT / GR I Neutron Tape. and lis~ting...~ MIDDLE GROUND SHOAL DILLON 18 % °Croa ~~" %%/o, PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY OF THIS DOCUMENT TRANSMITTAL TO: DEBRA CHILDERS CIO UNOCAL P.O. BOX 196247, AI)ICI-~RAGE, AK 99519 Recieved by: Date: ~ ~/ ALA~, OIL AND STATE OF ALASKA ~ GAS CONSERVATION CON I~S~ON YELL COMPLET, N OR RECOMPLETION , PORT AND LOG _. status of Well Classification of Service Well OIL ~ GAS ~-] SUSPENDED ~-~ ABANDONED[--] SERVICE r-~ 2. Name of operator 7. Permit Number UNION OIL COMPANY OF CALIFORNIA (UNOCAL) 94-57 3, Address 8. APl Number P.O. BOX 196247 ANCHORAGE, AK 99519 50-733-20459 4. Location of well at surface Dillon Platform, Leg #2, ~1 9. Unit or Lease Name 696' ESL & 1867' FWL Section 35, T8N, R13W, SM[ "'"~"'"~ ' ~u~lI~ AtTop Producing Interval 10230' MD/9522'TVD i~ '[~lll~llll~.' lO. Well Number At Total Depth 11709' MD/' 10089' 'FVD "i'1. Field and Pool 1080' FNL & 454' FWL SECTION 35, TSN, R13W, SM. ' ' Middle Ground Shoal E, F, & G Pools 5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation and Serial No. 127'KBI ADL 18746 12. Date Spudded04/18/94 13. Date T.D. Reached07/11/94 114' Date C°mp" Susp' °r Aband' 115' Water Depth' if °ffsh°re 116' N°' °f C°mplefl°ns07/22/94 102 Feet MSL 1 19. Directional Survey [20. Depth where SSSV set 121. Thickness of Permafrost 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) YES I~ NO I~I 9890 11709' / 10089' N/A feet MDI N/A 22. Type Electric or Other Logs Run DII./G R/SP/CN/AC/FMS/AIT/ASTM/SBT 23. CASING. LINER AND CEMENTING RECORD CASING SIZE Wl'. PER FT. GRADE TOP ~ BO3'I'OM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 18-5/8" 97 X-56 69' 1132' 24" 2375' cu. ft. - - - 13- 3/8" 68 K- 55 68' 3640' 17-1/2" 251 O' cu. ft. - - - 9-5/8" 47 L-80 68' 10155' 12-1/4" 915 cu. ft. - - - 7" 29 L- 80 9988' 11703' 8-1/2" 985 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 @ 10075' PACKER @ 9924' TOP SHOT '10230' MD / 9522' TVD BOTTOM SHOT '10718' MD / 9820' TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. 4 SPF WITH 32 GM. CHARGE DEPTH INTERVAL (MD) I AMOUNT & KIND OF MATERIAL USED NA 27 PRODUCTION TEST Date First Production I Method of Operation (Flowing, gas lift, etc.) N/A I Date of Test Hours Tested PRODUCTION FOF OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO TEST PERIOD ............ FlowTubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OILGRAVlTY-API (corO Press. 24-HOUR RATE ............ 28. CORE DATA Brief description of lithology, porosity, fractUres, apparent dips and presence of oil, gas or water. Submit core chips. RECEIVED ORIGINAL Alaska ljtl & Gas Cons, Commission Anchorage Form 10-407 Submit in duplicate rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAM E Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. 31. LIST OF ATTACHMENTS Signed G. RUSSELLSCHMIDT Title DRILLING MANAGER Date 07/25/94 _ 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'. KOBE BHA 8 30" Structural @ 83' BLM 18-5/8" Surface @ 1132' 97#, X-56, QTE60 13-3/8" Intermediate @ 3640' 68#, K-55, BTC COMPLETION DESCRIPTION 1) Dual 3-1/2", 9,2#, L80, SCBTC 2) Kobe BHA F/9794'-9821' 3) 3-1/2" "RA" sleeve @ 9836' 4) 3-1/2" "RA" sleeve @ 9871' 5) Otis 3-1/2" RRO SSSV @ 9890' 6) Otis "VLT" Packer @ 9924' 7) 3-1/2" "R" landing nipple @ 10002' 8) 1/4" SS control line 9) One jt. 3-1/2" tbg F/10003'-10034' 10) Pup jt 3-1/2" F/10035'-10042' 11) Crossover 3-1/2" x 2-7/8" 12) Jt 2-7/8" F/10043'-10075' 13) Mech. Tbg Release @ 10075' (ID=2.25") 14) TOF @ 10954' (2-7/8" tbg) 15) Btm of Fish @ 11602' (Total Length of fish = 648') RKB = 127' TOL @ 9988' 9-5/8" Production @ 10155' 47#, L-80, BTC Hemlock Perfs F/10230'-10718' Fish; 4-5/8" OD TCP guns "spent" and released ETD @ 11602' 7" L@ 11703' 29#, L80, TKC-BTC RECEIVED JUL 2 9 1994 Alaska 0il & Gas Cons. Commis Anchorage DILLON 16 ACTUAL COMPLETION UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 7-25-94 FILE: DIL16.drw ~ion UNOCAL DILLON PLATFORM DILLON #16 523'/(379') DAY 1 (04/18/94) COMMENCE OPS 1200 HRS 04/18/94. INSTALLED RISER AND BELL-NIPPLE. RAN "CENTER-PUNCH" ASSEMBLY AND TAGGED @ 144'. CLEANED OUT 30" CSG 144' TO SHOE @ 261'. DRILLED 17-1/2" PILOT HOLE 281'-322'. TRIPPED FOR DRILLING ASSEMBLY. DIRECTIONALLY DRILLED 17-1/2" HOLE 322'-523'. DAY 2 (04/19/94) DRILLED 17-1/2" PILOT HOLE 523'-1160'. TRIP F/HOLE OPENER. OPEN 17- 1/2" HOLE TO 24" F/322' TO 900'. DAY 3 (04/20/94) OPEN 17-1/2" HOLE TO 24" F[900' TO 1146'. CIRC CLEAN. TOH. RIH W(1~- 5/8" CSG, SHOE @ 1133'. CIRC CLEAN. LAND CSG. R~H W/tNNF_R CNtTG STRING. CMT 18-5/8" CSG W/826 SX LEAD F/B 630 SX TAIL. CIRC CMT TO SURF. TOH W/INNER CMTG STRING. CIP @ 1710 HRS. ND 30" RISER. DAY 4 (04/21/94) NU 20" RISER & BOPE. CIO DAMPNER BLADDER #1 & LINERS ON PUMPS. TEST BOPE. RING ON ANNULAR FLANGE LEAKING. DAY 5-7 (04/22-24/94) REPLACE RING ON ANNULAR FLANGE & TEST. INSTALL WEAR RING. L/D 24" HOLE OPENER ASSBLY. P/U 17-1/2" DRLG ASSY. RIH, DRILL CMT TO FC @ 1097'. PRESS TEST CSG TO 2000 PSI F/30 MINS, OK. DRILL CMT, FLOAT EQUIP, & NEW HOLE TO 1171'. PERFORM LOT TO 18.1 PPG EMW. DRILLED 17-1/2" HOLE F/1171'-1845', MWD FAILURE. POOH. REPLACE MWD & RIH. DRILLED TO 17-1/2" HOLE F/1845'-3650', CSG PT. ST TO CSG SHOE. CBU, PLUG FLOWLINE SECT. CONT CCH F/CSG. POOH. DAY 8 (04/25/94) POOH, PREP TO RUN 13-3/8" CSG. RIH W/13-3/8", 68#, K-55 CSG TO BTM, PPG. CIP @ 1725 HRS. FLOATS NOT HOLDING. HOLD 500 PSI SI PRESS & WOC APPROX 5.5 HRS. 1 RECEIVED JUL 2 9 1994 Alaska ~il & (]as Cons. Commission Anchorage UNOCAL DILLON PLATFORM DILLON 16 DAY 9 (04/26/94) BLEED PRESS & 0.4 BBLS MUD, FLUID LEVEL STATIC. RIG DN CMT EQUIP. RIH W/WASH TOOL & C/OUT WH. INSTALL PACKOFF, TEST W/20K OVERPULL & PRESS TEST TO 3000 PSI F/30 MINUTES, OK. ND BOPE. PACKOFF & SNAP RING F/WH NOT FULLY ENGAGED. REPAIR SAME & TEST TO 3M, NEG. REDRESS SEALS & SEAL AREA. A3-rEMPT TO PRESS TEST, NEG. PUMP PLASTIC PAKCING & TEST TO 3M, OK. PREP TO INSTALL "B" SECTION OF WH, NEG. MODIFY "B" SECT OF WH. RIG RELEASE @ 1800 HRS. DAY 10 (6/15/94) 18-5/8" @ 1132' 13-3/8" @ 3640' 9.0 PPG ACCEPTED RIG F/DILLON #17 @ 1800 HRS 6-15-94. SKIDDED RIG OVER WELL #16. NIPPLED UP BOP'S. TESTED BOP'S AS PER AOGCC. DAY 11 (6/16/94) 18-5/8" @ 1132' 13-3/8" @ 3640' 9.1 PPG COMPLETED BOP TEST. VALVE LEAKED. CHANGED OUT. RETESTED-OK. MADE UP ROTARY BHA TO DRILL OUT. PU HWDP. COMPLETED BOP TEST. RIH. TAGGED TOC @ 3506'. TESTED CASING TO 2700 PSI. DRILLED CEMENT TO SHOE @ 3641'. DRILLED NEW FORMATION TO 3670'. CBU. CONDUCTED LOT-15 PPG EMW. ROTARY DRILLED F/3670'-4125'. DAY 12-14 (6/17-19/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9.4 PPG DRILLED 12-1/4" HOLE F/4125'-5005'. POOH F/BHA CHG. MU BHA & RIH. DRILLED F/5005'-6006'. POOH, CHG OUT FAILED MOTOR & BIT. MU BHA & RIH. DRILLED TO 6022'. RECEIVED JUL 2 9 1994 Alaska Uil & Gas Cons. Commission Anchorage UNOCAL DILLON PLATFORM DILLON 16 DAY 15 (6/20/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9.4 PPG DRILLED 12-1/4" HOLE F/6022'-6336', MOTOR FAILURE. MOTOR & MWD. MU BHA & RIH. DRILLED TO 6345'. POOH. CHG OUT DAY 16 (6/21/94) 18-5/8"@ 1132' 13-3/8" @ 3640' 9.4 PPG DRILLED F/6345'-6412', MOTOR FAILURE. POOH. PU NEW MOTOR & RIH W/SAME. DRILLED F/6412'-6700'. DAY 17 (6/22/94) 18-5/8"@ 1132' 13-3/8"@ 3640' 9.2 PPG DRILLED F/6700'-7087'. POOH. PERFORM BOPE TEST. MU BHA & RIH. DAY 18 (6/23/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9.2 PPG DRILLED 12-1/4" F/7087'-7435'. POOH DUE TO LOW ROP. RIH, DRILLED TO 7450'. DAY 19-21 (6/24-26/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9.2 PPG DRILLED 12-1/4" F/7450'-7906' (ROTARY BHA), POOH. MU BHA (MOTOR) & RIH. DRILLED F/7906'-8531'. POOH, CHG OUT MOTOR & BIT. RIH, DRILLED F/8531'-8593'. RECEIVED JUL 2 9 1994 Alaska Oil & Gas Con;. Commission Anchorage UNOCAL DILLON PLATFORM DILLON 16 DAY 22 (6/27/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9.3 PPG DRILLED F/8593'-8890'. DAY 23 (6/28/94) 18-5/8"@ 1132' 13-3/8"@ 3640' 9.3 PPG DRILLED 12-1/4" F/8890'-9297'. DAY 24 (6/29/94) 18-5/8"@ 1132' 13-3/8" @ 3640' 9.3 PPG DRILLED TO 9342'. CBU. POOH FOR BIT. & RIH. DRILLED TO 9485'. DAY 25 (6/30/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9.3 PPG DRILL 12-1/4" HOLE F/9485'-9855'. PERFORM BOPE TEST. MU BHA RECEIVED JUL 2 9 1994 Alaska 0il & Gas Cons. Commission Anchorage UNOCAL DILLON PLATFORM DILLON 16 DAY 26-29 (7/01-04/94) 18-5/8"@ 1132' 13-3/8"@ 3640' 9-5/8"@ 10155' 9.3 PPG DRILLED 12-1/4" HOLE F/9855'-9942'. POOH, CHG OUT BIT & MOTOR. MU BHA & RIH. DRILLED F/9942'-10211', CSG PT. ST TO 7500', RIH TO 10211', CCM. POOH. RU ATLAS WL, LOG RUN (GR/CN/CDU/AC/DIFL) F/10188' WLM TO SURFACE. CHG RAMS TO 9-5/8" & TEST SAME. RU & RIH W/9-5/8", 47#, L80 BU'I-i' CSG, BRK CIRC AT SHOE. RIH TO 10171', SET DN 27' HIGH. ATTEMPT TO WORK DN HOLE, NEG. ADJUST CSG AS REQ'D SHOE AT 10155' & RU CMT EQUIP. CCH, M&P 163 BBLS OF 15.8 PPG CMT W/ADDITIVES, RECIP CSG 100% W/NO FLUID LOSSES & FULL RETURNS. CIP AT 0540 HRS 7-4-94, TEST CSG TO 4800 PSI F/30 MINS. INSTALL CSG PACKOFF & TEST SAME TO 5000 PSI F/30 MINS. TEST DOPE. MU BHA, RIH & TAG PLUG AT 10059'. DRILL CMT & FLOAT EQUIP TO 10155', TEST CSG TO 3500 PSI, OK. CLEAN OUT TO 10211' & DRILL NEW HOLE TO 10221'. PERFORM FIT TO 14.2 PPG EMW. DRILL 8-1/2" HOLE TO 10252'. DAY 30 (7/05/94) 18-5/8" @ 1132' 13-3/8" @ 3640' 9-5/8"@ 0 55' 9.3 PPG DRILLED 8-1/2" HOLE F/10252'-10713'. DAY 31 (7/06/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9-5/8" @ 10155' 9.3 PPG DRILLED TO 10724'. POOH, CHG BIT & MOTOR. DRILLED F/10724'-10907'. RECEIVED JUL 2 9 1994 Alaska Oil & Gas Cons. Commissio. Anchorage UNOCAL DILLON PLATFORM DILLON 16 DAY 32 (7/07/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9-5/8" @ 10155' 9.3 PPG DRILLED 8-1/2" HOLE F/10907'-11152', HAD INCR PMP PRESS. POOH, MOTOR HAD FAILED. MU BHA & RIH. DAY 33-35 (7/08-10/94) 18-5/8"@ 1132' 13-3/8"@ 3640' 9-5/8"@ 10155' 9.3 PPG RIH TO 10962', REAM TO 11152' W/HIGH TORQUE & PACKING OFF. STUCK BHA AT 10962', PULLED FREE W/150K OVERPULL. DRILLED F/11152'-11178'. HAVING PMP PRESS INCR, POOH. (FOUND STATOR RUBBER IN BIT-MTR FAILURE). RAN NEW MTR. TAGGED BTM AND STARTED EXPERIENCING PLUGGING. DRLD 8-1/2" HOLE 11,178'-11,193'. TRIPPED DUE TO PLUGGING. (MTR FAILURE). RAN MTR FROM DIFFERENT SUPPLIER. DRLD 8-1/2" 11,193'- 11,300'. STUCK IN 2' COAL STRINGER. WORKED FREE BUT DAMAGED MUD MTR. POOH. RAN ROTARY BHA SPOT REAMED 10,529'-11,330'. DRLD 8-1/2" 11,330'-11,510'. DAY 36 (7/11/94) 18-5/8"@ 1132' 13-3/8"@ 3640' 9-5/8"@ 10155' 9.4 PPG DRILLED 8-1/2" HOLE FROM 11510' TO 11709'. NOT IN OIL PAY AS PLANNED CBU, POOH TO SHOE. RIH TO BTM CBU. POOH TO RUN DRILL PIPE CONVEYED LOGS. P/U SCHLUMBERGER LOGGING TOOLS, FMS-AIT-GR-SP- AMS. RECEIVED JUL 2 9 1994 Alaska Oil & Gas Cons. Commission Anchorage UNOCAL DILLON PLATFORM DILLON 16 DAY 37 (7/12/94) 18-5/8"@ 1132' 13-3/8"@ 3640' 9-5/8"@ 10155' 9.4 PPG FINISH P/U SCHLUMBERGER FMS-AIT-GR-SP-AMS DRILL PIPE CONVEYED LOGGING TOOL. RIH TO 10066'. R/U SIDE ENTRY SUB. RIH W/WIRELINE FOR WET CONNECT. CONT. RIH TO 11699' (LOGGING DOWN W/S/P). LOG UP FROM 11699' TO SHOE AT 10155'. POOH W/WIRE AND LOGGING TOOL. TEST BOP'S. DAY 38 (7/13/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9-5/8" @ 10155' 9.4 PPG RIH W/WIPER TRIP ASSY, (PRIOR TO RUNNING 7" LINER). REAM F/11,135'- 11,709'. POH. RIH W/7" LINER. LINER TOOK WT @ 11358'. WASHED LINER F/11358' TO 11516'. HAD TO WALK LINER F/11516'-11562'. LOST EXCESSIVE WEIGHT & GAINED PUMP PRESSURE @ 11562'. POH TO CHECK TOOLS. DAY 39 (7/14/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9-5/8" @ 0 55' 9.4 PPG POH TO CHECK TOOLS. LINER SETTING TOOL RELEASED FROM LINER HANGER, APPEARS TO BE UNDAMAGED. M/U FISHING TOOLS TO SPEAR LINER. RIH AND ENGAGE FISH AT 9846'. WORKED FISH LOOSE AND POH. LAY DOWN HANGER AND LINER. RIH WITH CLEANOUT ASSY. RECEIVED JUL 2 9 994 Alaska 0il & Gas Cons. Commission Anchorage UNOCAL DILLON PLATFORM DILLON 16 DAY 40-42 (7/15-17/94) 18-5/8"@ 1132' 13-3/8" @ 3640' 9-5/8" @ 10155' 7" @ 11703' TOL @ 9987' 9.4 PPG CONTINUE WIPER TRIP. RIH TO 11709'. CBU. POOH. RIH W/7" LINER COMPLETE W/TURBOLIZERS 2 PER JOINT. WITH SHOE AT 11703'. CEMENTED LINER WITH FULL RETURNS WHILE RECIPROCATING SAME. CIP 9:10 PM 7/15/94. SET HANGER AND LINER TOP PACKER REVERSE OUT 10 BBLS OF CEMENT. TOP OF LINER AT 9987'. POOH W/SE'I-rING TOOL. RIH CLEAN OUT ASSEMBLY 6" BIT W/9-5/8" AND 7" SCRAPERS. TAG CEMENT 11602. TEST CASING TO 3500 PSI. POOH. R/U AND GR-CCL-SBT NEUTRON LOG ON DRILL PIPE LOG FROM 11572' TO 8300'. POOH. L/D LOGGING TOOLS. L/D SOME BENT DRILLPIPE. RIH W/6" BIT 7" AND 9-5/8" SCRAPERS WHILE P/U 3-1/2" TUBING TO 11602. DISPLACE MUD WITH INLET WATER. DAY 43 (7/18/94) 18-5/8" @ 1132' 13-3/8" @ 3640' 9-5/8"@ 10155' 7" @ 11703' TOL @ 9987' 8.4 PPG 3% KCL CIRCULATE AND PUMP PILL TO CLEAN UP WELL, DISPLACE WELL TO 8.4 PPG 3% KCL WATER. POOH. P/U TCP GUN ASSY ON VST PACKER. RIH. DAY 44 (7/19/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9-5/8" @ 10155' 7" @ 11703' TOL @ 9987' 8.4 PPG 3% KCL PACKER TO 3000 PSI. POOH W/PKR S~ING TOOL. MU TEST STRING & RIH. STAB INTO PKR, OPEN DN HOLE SERVICE VALVE. RU SURFACE TEST EQUIP & TEST SAME. CONFIRM FLUID LEVEL & DESIRED UNDERBA~NCE. DROP FIRING BAR AND D~ONATE GUNS AT 1905 HRS, MONITOR FLUID LEVEL RISE TO 1988' F/5812', TERMINATE TEST AT 2100 HRS. RU WL, S~ "PX" PLUG IN "XN" NIPPLE AT 10184' WLM. POOH. ~ RECEIVED JUL 2 9 1994 Alaska 0il & Gas Cons. Commissior~ Anchorage UNOCAL DILLON PLATFORM DILLON 16 DAY 45 (7/20/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9-5/8"@ 10155' 7" @ 11703' TOL @ 9987' 8.4 PPG 3% KCL RIH, SET "PX" PRONG IN PLUG. A'I-I'EMPT TO PRESS TEST PLUG, NEG. OPEN BYPASS & REV CIRC OUT TEST FLUID. PULL OUT OF PKR. PRESS TEST CSG, PKR, AND PLUG TO 3000 PSI FOR 5 MIN, OK. RIG DN SURF EQUIP, POOH W/TBG TEST STRING. CHG RAMS TO DUAL 3-1/2". RIH W/DUAL 3-1/2" TBG COMPLETION & KOBE BHA. DAY 47 (7/22/94) 18-5/8" @ 1132' 13-3/8"@ 3640' 9-5/8"@ 7" @ 11703' TOL @ 9987' 8.4 PPG 3% KCL RIH W/WL, A'I-rEMPT TO PULL PLUG (3 A'I-rEMPTS) W/O SUCCESS. RIH, RELEASE TCP GUNS, OK. PREP TO INSTALL STANDING VALVE & JET PUMP. RELEASE RIG AT 1100 HRS. 7-22-94. RECEIVED JUL 2 9 1994 Alaska 0il & Gas Cons. Commission Anchorage Unocal North Amerk/T~ 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: Larry Grant FROM: Dan Seamount LOCATION: 3OOl PORCUPINE DRIVE ANCI-IOIL~GE, AK 99501 ALASKA Om & GAS CONSEaV^T~ON COMM. LOCATION:P.O.nOX 196247 ANCHORAGE AK 99519 TRANSMrrrlNG AS FOLLOWS 1 blueline and 1 sepia of each of the following MGS DILLON 16 /BHC Acoustilog/Gamma Ray/Caliper .,.-Compensated Densilog/Neutron/Gamma Ray/Caliper ,,,"Dual Induction Focused Log/Gamma Ray MGS DILIX)N 17 ~ Compensated Neutron/Gamma Ray/PCL 7" Casing /~Compensated Neutron/Gamma Ray 2~& ~ Dual Propagation Resistivity/Gamma Ray 5" PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY OF THIS DOCUMENT TRANSMITTAL TO D EBP~ CHILDERS. THANK YOU DATED: UNOCAL D]LLON Platform D-16 slot #2-7 Middle Ground Shoals Cook Inlet, Alaska SURVEY LISTING by Baker Hughes INTEQ Your ref : GSS <100 - 1112'> : PMSS <1237-11709'> Our ref : svy4367 License : Date printed : 15-Jul-94 Date created : 23-Apr-94 Last revised : 15-Jul-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 7.693,w151 30 44.869 Slot Grid coordinates are N 2463867.915, E 229314.060 Slot local coordinates are 696.00 N 1867.00 E Reference North is True North RECEIVED JUL 29 1994 ~,~aska O~l & Gas Cons. Commission Anchorage UNOCAL DILLON PLatform,D-16 Hidd[e Ground ShoaLs,Cook InLet, ALaska SURVEY LISTING Page 1 Your ref : PHSS <1237-11709'> Last revised : 15-Ju[-94 Heasured [nc[in. Azimuth True Vert. R E C T A N G U L A Depth Degrees Degrees Depth C 0 0 R D I N A T E R DogLeg Vert S Deg/lOOFt Sect 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 100.00 0.00 0.00 100.00 0.00 N 0.00 E 0.00 0.00 200.00 0.00 0.00 200.00 0.00 N 0.00 E 0.00 0.00 284.00 0.50 237.00 284.00 0.20 S 0.31 W 0.60 -0.08 297.00 0.50 228.00 297.00 0.27 S 0.40 W 0.60 -0.12 387.00 0.75 235.00 386.99 0.87 S 1.17 ~ 0.29 -0.42 477.00 1.75 270.00 476.97 1.21 S 3.03 W 1.35 -0.10 567.00 2.00 275.00 566.92 1.07 S 5.97 W 0.33 1.04 657.00 2.25 293.00 656.86 0.24 S 9.16 W 0.79 2.90 747.00 3.00 280.00 746.77 0.86 N 13.10 W 1.06 5.29 837.00 2.75 290.00 836.66 2.00 N 17.45 W 0.62 7.85 927.00 2.25 261.00 926.57 2.46 N 21.22 ~ 1.49 9.58 1017.00 2.75 264.00 1016.49 1.96 N 25.12 ~ 0.57 10.44 1112.00 3.00 255.00 1111.37 1.08 N 29.78 W 0.54 11.20 1237.00 2.10 250.00 1236.24 0.55 S 35.10 W 0.74 11.49 1335.00 1.10 196.00 1334.21 2.07 S 37.04 ~ 1.74 10.7'5 1425.00 0.60 230.00 1424.20 3.20 S 37.64 W 0.77 9.87 1520.00 0.30 86.00 1519.20 3.50 S 37.78~ 0.91 9.63 1614.00 0.43 59.60 1613.20 3.31 S 37.23 W 0.22 9.62 1800.00 0.65 52.70 1799.19 2.31 S 35.78 W 0.12 10.06 1889.00 0.57 79.50 1888.18 1.93 S 34.95 W 0.33 10.14 1982.00 0.10 139.00 1981.18 1.90 S 34.44 ~ 0.56 9.99 2075.00 0.22 37.60 2074.18 1.82 S 34.28 ~ 0.28 10.01 2168.00 0.22 112.00 2167.18 1.75 S 34.00 W 0.29 9.99 2262.00 0.19 236.90 2261.18 1.90 S 33.97 W 0.39 9.83 2356.00 0.25 223.59 2355.18 2.14 S 34.24 ~ 0.08 9.70 2449.00 0.13 221.00 2448.18 2.36 S 34.45 ~ 0.13 9.56 2540.00 0.19 85.00 2539.18 2.43 S 34.36 W 0.33 9.47 2634.00 0.26 191.10 2633.18 2.62 $ 34.25 ~ 0.38 9.25 2727.00 0.07 315.00 2726.18 2.79 S 34.33 W 0.33 9.12 2820.00 0.13 343.00 2819.18 2.65 S 34.40 ~ 0.08 9.28 2913.00 0.39 309.00 2912.18 2.35 S 34.68 W 0.31 9.65 3007.00 0.17 333.09 3006.17 2.02 S 34.99 ~ 0.26 10.07 3100.00 0.60 305.00 3099.17 1.62 S 35.45 W 0.49 10.60 3195.00 0.85 269.00 3194.16 1.35 S 36.56 W 0.53 11.24 3288.00 0.31 85.00 3287.16 1.34 S 37.00 ~ 1.25 11.40 3382.00 0.94 94.00 3381.16 1.37 S 35.98 ~ 0.68 11.02 3476.00 0.40 137.00 3475.15 1.66 S 34.99 W 0.75 10.40 3570.00 0.66 231.20 3569.15 2.24 S 35.19 ~ 0.85 9.93 3605.00 0.61 209.70 3604.14 2.53 S 35.44 W 0.69 9.74 3705.00 0.73 227.70 3704.14 3.42 S 36.17 W 0.24 9.16 3798.00 1.06 230.20 3797.13 4.37 S 37.27 ~ 0.36 8.64 3892.00 0.91 231.55 3891.11 5.39 S 38.52 W 0.16 8.11 3985.00 0.76 244.00 3984.10 6.12 S 39.66 W 0.25 7.81 4078.00 0.66 252.00 4077.10 6.56 S 40.72 W 0.15 7.76 4172.00 0.94 269.01 4171.09 6.74 S 42.00 ~ 0.39 8.04 4265.00 0.94 261.32 4264.07 6.86 S 43.52 W 0.14 8.43 4357.00 0.96 271.33 4356.06 6.96 S 45.04 ~ 0.18 8.86 4449.00 1.17 273.72 4448.05 6.88 S 46.74 W 0.23 9.52 4543.00 1.33 279.13 4542.02 6.65 S 48.78 ~ 0.21 10.44 RECEIVED JdL 2 9 1994 Gas Cons. Commission Anchorace ALL data is in feet unless otherwise stated Coordinates from slot #2-7 and TVD from weLLhead (127.00 Ft above mean sea LeveL). Vertical section is from weLLhead on azimuth 340.00 degrees. DecLination is 0.00 degrees, Convergence is -1.33 degrees. CaLculation uses the minimum curvature method. Presented by Baker Hughes [NTEQ UNOCAL DILLON Ptatform,D-16 Middte Ground Shoals,Cook Inter, Alaska SURVEY LISTING Page 2 Your ref : PMSS <1237-11709'> Last revised : 15-Jut-94 Neasured [nc[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 4637.00 1.45 284.50 4636.00 6.18 S 51.01 14 0.19 11.64 4730.00 1.53 286.03 4728.96 5.54 S 53.34 14 0.10 13.04 4871.00 1.45 282.50 4869.92 4.63 S 56.89 14 0.09 15.10 4975.00 1.61 285.95 4973.88 3.95 S 59.58 14 0.18 16.67 5035.00 3.08 336.41 5033.83 2.24 S 61.04 14 4.00 18.77 5149.00 7.20 356.01 5147.36 7.70 N 62.7614 3.88 28.70 5243.00 7.91 358.48 5240.54 20.04 N 63.34 14 0.83 40.50 5336.00 8.00 357.81 5332.65 32.91 N 63.7614 0.14 52.73 5430.00 8.39 357.07 5425.69 46.29 N 64.36 14 0.43 65.51 5524.00 8.37 355.64 5518.68 59.96 N 65.23 14 0.22 78.66 5618.00 8.24 355.22 5611.70 73.50 N 66.31 14 0.15 91.74 5724.00 9.36 354.74 5716.45 89.65 N 67.74 14 1.06 107.41 5805.00 11.32 351.83 5796.13 104.08 N 69.47 14 2.50 121.56 5899.00 13.14 348.31 5887.99 123.68 N 72.94 14 2.09 141.17 5993.00 14.08 347.84 5979.35 145.32 N 77.52 14 1.01 163.07 6087.00 16.14 345.54 6070.10 169.15 N 83.19 14 2.28 187.40 6180.00 17.71 342.61 6159.07 195.17 N 90.65 14 1.92 214.40 6274.00 20.19 341.52 6247.97 224.20 N 100.06 14 2.66 244.90 6368.00 22.95 340.55 6335.38 256.87 N 111.31 14 2.96 279.45 6461.00 25.14 341.12 6420.30 292.~ N 123.74 14 2.37 317.34 6553.00 27.41 342.63 6502.79 331.37 N 136.39 14 2.57 358.04 6647.00 29.43 342.81 6585.46 374.09 N 149.67 14 2.15 402.72 6741.00 31.77 343.02 6666.36 419.82 N 163.73 14 2.49 450.50 6836.00 34.40 343.03 6745.95 469.42 N 178.87 14 2.77 502.29 6905.00 35.59 341.80 6802.48 507.14 N 190.83 14 2.00 541.82 7024.00 35.04 343.27 6899.58 572.75'N 211.48 14 0.85 610.54 7123.00 35.25 343.34 6980.53 627.34 N 227.85 14 0.22 667.43 7217.00 35.30 343.38 7057.27 679.35 N 243.39 14 0.06 721.62 7311.00 36.14 343.41 7133.59 731.94 N 259.08 14 0.89 776.41 7499.00 35.67 344.17 7285.87 837.80 N 289.86 14 0.34 886.42 7592.00 33.83 344.76 7362.28 888.87 N 304.06 14 2.01 939.26 7687.00 32.18 345.68 7441.95 938.90 N 317.27 14 1.82 990.79 7782.00 31.08 345.40 7522.83 987.15 N 329.71 14 1.17 1040.38 7876.00 30.32 345.34 7603.66 1033.58 N 341.83 14 0.81 1088.16 7966.00 31.27 343.96 7680.97 1078.01 N 354.03 14 1.32 1134.08 8060.00 31.82 340.34 7761.08 1124.80 N 369.11 14 2.10 1183.21 8153.00 31.63 340.45 7840.19 1170.86 N 385.52 14 0.21 1232.11 8246.00 32.35 340.37 7919.07 1217.28 N 402.04 14 0.78 1281.38 8339.00 33.09 338.30 7997.31 1264.31 N 419.79 14 1.44 1331.64 8432.00 33.00 338.07 8075.27 1311.39 N 438.63 14 0.16 1382.32 8491.00 32.80 337.91 8124.80 1341.10 N 450.64 14 0.37 1414.35 8527.00 32.80 338.40 8155.06 1359.20 N 457.90 14 0.74 1433.84 8619.00 37.90 337.20 8230.08 1408.45 N 478.04 14 5.59 1487.01 8674.00 39.86 336.50 8272.89 1440.19 N 491.61 14 3.65 1521.48 8712.00 40.14 337.59 8302.00 1462.68 N 501.14 W 1.98 1545.87 RECEIVED 8805.00 38.08 338.08 8374.16 1517.01 N 523.2714 2.24 1604.49 8899.00 36.11 336.49 8449.14 1569.30 N 545.15 W 2.33 1661.12 J~JL 2 91994 8993.00 33.61 337.68 8526.26 1618.78 N 566.08 14 2.76 1714.77 9088.00 34.86 338.00 8604.80 1668.28 N 586.24 14 1.33 1768.17 ~kt(=~ka U~ & Gas Cons. Commission 9181.00 34.49 338.23 ~1.28 1717.37 N 605.96 N 0.42 1821.05 Anchorage Alt data is in feet untess otherwise stated Coordinates from stot #2-7 and TVD from wetthead (127.00 Ft above mean sea [eve[). Vertical section is from wellhead on azimuth 340.00 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-16 Middle Ground Shoats,Cook Intel, Alaska SURVEY LISTING Page 3 Your ref : PMSS <1237-11709'> Last revised : 15-Jut-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 9274.00 35.04 337.90 8757.68 1766.56 N 625.77 W 0.62 1874.05 9367.00 34.80 339.69 8833.94 1816.19 N 645.03 W 1.13 1927.27 9460.00 34.76 339.39 8910.33 1865.89 N 663.57 W 0.19 1980.32 9555.00 34.37 338.64 8988.56 1916.22 N 682.87 ~ 0.61 2034.21 9648.00 34.43 338.36 9065.29 1965.10 N 702.13 W 0.18 2086.73 9742.00 34.38 338.86 9142.85 2014.56 N 721.50 ~ 0.30 2139.83 9834.00 34.63 339.39 9218.66 2063.25 N 740.07 W 0.42 2191.94 9926.00 35.75 339.28 9293.85 2112.86 N 758.78W 1.22 2244.95 10020.00 39.79 339.21 9368.14 2166.68 N 779.18 W 4.30 2302.51 10115.00 42.72 340.63 9439.55 2225.52 N 800.66 ~ 3.24 2365.14 10171.00 44.04 340.91 9480.25 2261.83 N 813.33 ~ 2.38 2403.60 10295.00 47.26 339.07 9566.93 2345.12 N 843.70 ~ 2.80 2492.26 10387.00 49.77 337.38 9627.87 2409.11 N 869.28 ~ 3.06 2561.13 10481.00 52.57 337.12 9686.80 2476.63 N 897.60 W 2.99 2634.27 10575.00 55.47 338.02 9742.02 2546.94 N 926.61 W 3.18 2710.26 10669.00 59.24 338.09 9792.72 2620.34 N 956.18 ~ 4.01 2789.35 10760.00 61.54 337.01 9837.68 2693.45 N 986.40 ~ 2.73 2868.38 10854.00 65.39 335.~ 9879.67 2770.45 N 1020.16 W 4.29 2952.29 10946.00 68.73 335.37 9915.52 2847.54 N 1055.28 W 3.64 3036.74 11040.00 71.20 333.05 9947.72 2927.04 N 1093.70 W 3.50 3124.59 11134.00 73.38 332.70 9976.32 3006.73 N 1134.53 ~ 2.35 3213.44 11227.00 75.50 332.72 10001.26 3086.35 N 1175.60 ~ 2.28 3302.30 11361.00 78.68 331.43 10031.20 3201.73 N 1236.77 ~ 2.55 3431.64 11454.00 79.16 331.38 10049.07 3281.86 N 1280.45 W 0.52 3521.88 11548.00 80.85 326.75 10065.40 3361.24 N 1328.03 ~ 5.17 3612.74 11642.00 81.92 328.21 10079.48 3439.60 N 1377.99 11709.00 81.92 328.21 10088.89 3495.98 N 1412.94 1.91 3703.47 0.00 3768.40 Projected Data - NO SURVEY RECEIVED JUL 2 9 1994 Alaska 0il & Gas Cons. Commission Anchorage At[ data is in feet unless otherwise stated Coordinates from stol #2-7 and TVD from wet[head (127.00 Ft above mean sea [eve[). Vertical section is from wellhead on azimuth 340.00 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes [NTEQ UNOCAL SURVEY LISTING Page 4 DILLON Platform,D-16 Your ref : PMSS <1237-11709'> Middle Ground Shoals,Cook Inlet, Alaska Last revised : 15-Ju[-94 Comments in wellpath MD TVD Rectangular Coords. COherent 11709.00 10088.89 3495.98 N 1412.94 W Projected Data - NO SURVEY 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 3642.00 3641.14 2.87S 35.66~ 13 3/8" Casing 0.00 0.00 O.OON O.OOE 10155.00 9468.72 2251.36N 809.70~ 9 5/8" Casing Targets associated with this we[lpath Target name Position T.V.D. Local rectangular coords. Date revised 16 Mid G-4a not specified 9927.00 2856.66N 1039.74~ 4-Jan-94 16 Top G1 not specified 9197.00 2114.31N 769.54W 4-Jan-94 16 TD not specified 10127.00 3918.52N 1426.22W 22-Mar-94 RECEIVED JUL 2 9 1994 Alaska Oil & Gas Cons. Commission Ancfl0ra~e AL[ data is in feet unless otherwise stated Coordinates from slot #2-7 and TVD from wellhead (127.00 Ft above mean sea Level). Bottom hole distance is 3770.72 on azimuth 337.99 degrees front we[lheed. Vertical section is from wellhead on azimuth 340.00 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ ME'MORAND . State °, 'Alaska Alaska Oil and Gas Conservation Commission TO: . David John _~r1~, Chair~ Till{U: Blair Wondzell, ~ ~J~,~ P. I. Supervisor Fl{OM: ~ou Grimaldi, Petroleum Inspector DATE: June 16, 1994 FlEE NO: SUBJECT: AVDJFPBD.DOC BOP Test Pool rig #429 Unocal well # Dillon #16 Middle Ground Shoal Field PTD # 94-57 Wednesday, June 15, 1994: I traveled to Unocals Dillon platform in the Middle Ground Shoal field of Cook Inlet to witness the Initial BOP test on rig Pool rig #428. Thursday, June 16, 1994: The test was started shortly after midnight and went very well. All components were subjected to a proper function test and a Iow/high test of 250/5000 PSI. John McCoy (Pool Toolpusher) did a outstanding job of insuring a proper BOP test was accomplished, the Accumulator had a good recharge time of 1 minute and 28 seconds. There was one failure observed, this being the isolation valve downstream of the manual choke which leaked approximately 100 psi per minute. Summary: I witnessed the Initial BOP test on Pool rig #428. Test time 1.5 hours, one failure. · . ^ttachment: ^¥DJFPBD.XLS cc: Dan Williamson (drlg. supt.) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: X Drlg Contractor: Pool Arctic Operator: Unocal Well Name: Dillon #16 Casing Size: 13 3/8 Test: Initial X Workover: Rig No. Set ~ Weekly Other DATE: 6/16~94 428 PTD # 94-57 Rig Ph.# 776-6680 Rep.: Don Byrne/Larry McAIlister Rig Rep.: John McCoy Location: Sec. 35 T. 8N R. 13W Meridian 11, ,-- Seward TEST DATA MISC. INSPECTIONS: Location Gen.: OK Housekeeping: OK (Gen) Reserve Pit N/A I 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 250/3500 I 250/5000 I 250/5000 I 250/5000 I 250/5000 I 250/5000 I 250~5000 N/A N/A P/F P P P P P P P N/AI MUD SYSTEM: Visual Alarm Tdp Tank P P Pit Level Indicators P P Flow Indicator P P Gas Detectors P P FLOOR SAFETY VALVES: Upper Kelly I IBOP Lower Kelly / IBOP Ball Type Inside BOP Quan. 1 1 2 1 Test Pressure 250/5000 250~5000 250~5000 250~5000 P/F P P P P CHOKE MANIFOLD: No. Valves 16 No. Flanges 42 Manual Chokes 1 Hydraulic Chokes 2 Test Pressure 250/5000 250~5000 Function Function P/F F*I P P P ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure 0 System Pressure Attained 1 Blind Switch Covers: Master: Nitgn. Btl's: 12 Bottles 2400 Average 2,800 I P 1,800 P minutes 15 sec. minutes 28 sec. X Remote: X Psig. TEST RESULTS .... "'Number of Failures: 1 ' ,Test Time: 1 1~2 Hours. 'Number of"~/alves'tested 29 Rel~air or Replacement of Failed Equipment will be made within 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: '1) Valve downstream of manual choke leaked. Repair and retest, notify Lou ~ 776-5402 or AOGCC at 279-1433 when repaired. Otherwise outstanding test and well maintained rig. Distribution: orig-Well File c - Oper./Rig c - Database c - Trip Rpt File c- Inspector FI-021L (Rev. 2/93) ' STATE WITNESS REQUIRED? '" YES NO X 24 HOUR NOTICE GIVEN YES NO X Waived By: Witnessed By: AVDJFPBD.XLS Louis R. Grimaldi ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HIC, KEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279.1433 TELECOPY: (907) 276-7542 April 15, 1994 G. Russell Schmidt Alaskas Business Unit Drlg Mgr Union Oil Company of California (UNOCAL) P O Box 196247 Anchorage, AK 99519-6247 Re: Chakachatna Dillon #16 UNOCAL Permit No: 94-57 Sur. Loc. Dillon Pit. Leg #2, Slot #7, 696'FSL & 1867'FWL, Sec. 35, T8N, R13W, SM Btmhole Loc. 11957'MD/10127'TVD, 665'FNL, 441'FWL, Sec. 35, T8N, 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 drill does.not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below the surface casing shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission at 279-1433. · Chairman BY ORDER OF THE COMMISSION dlf/Enclosures CC: Depadment of Fish & Game, Habitat Section w/o encl. Depadment of Environmental Conservation w/o encl. Unocal Energy Resource~,"~ision Unocal Corporation I ~ 909 West 9th Avenue, RO. Bu~, 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 MII~DLE GROUND SHOAL 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-ifDwe~v~-. - APR - 8 1994 Naska 0il & Gas Cons. Commission 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. . 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. Sincere~ly, /2 Danie T. Seam~'"-~nu~ Geologic Development Advisor DTS:dma RECEIVED APR -8 1994 Alaska Oil & Gas Cons. Commission Anchorage Unocal North America~'~ Oil & Gas Division I ' Unocal Corporation 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 +1100' with a flow nipple then install a 20- 3/4" 3M BOPE stack on the 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/Il. 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 tree fracture gradients ranging from 0.75 - 0.94 psi/ft. In both wells at Dillon the maximum surface pressure 0VISP) 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. 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 lffi 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 ~:3500'. ffyou 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. G. Russell Schmidt Drilling Manager CLL/cll enclosure: - 7 1994 ,~aska 0il & Gas Cons. Commissio~ Anchorage Memorandum State of Alaska Oil and Gas Conservation Commiasion To: Commission-P,~ April 11, 1994 J. Hart~ Fm; Subj: Unocal Request for Diverter Waiver and Batch Drilling Middle Ground Shoal Platform Dillon Wells 16 and 17 Unocal has requested a waiver of diverter re/q~lremptits on the subject wells. They propose to drill the conductor hole to 1100' with a ilo/v4 nii~ then drill the surface hole to 3500' with a 20 3/4" 3000 psi. BOPE system. They st~.Afftheir 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 n_o shallow gas kicks, abnormal pressure or lost circulation noted in the wells reviewed. PlatformDill°n 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 giv~.__en 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. sehce batch drilling procedure should be approved with a stipulation that each casing segment be ured 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. STATE OF ALASKA co.s v^ lO, co ss o. PERMIT TO DRILL 20 AAC 25.005 la. Type of work Drill [] Redrill [~ 1 lb. Type of well. Exploratory 0 Stratigraphic Test [--] Development Oil ~ Re-Entry [~ Deepen ~I Service 0 Development Gas [--] Single Zone [-'] Multiple Zone 0 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 #7 7. Unit or property name 11. Type Bond (SEE2OACC~.0~) 696' FSL & 1867' FWL SECTION 35, T8N, R13W, S.M. CHAKACHATNA UNITED PACIFIC INS. CO.i At top of productive interval 9702' MD / 9197' TVD 8. Well number Number 2810' FSL & 1097' FWL SECTION 35, T8N, R13W, S.M. Dillon #16 U62-9269 At total depth 11957' MD / 10127' TVD 9. Approximate spud date Amount 665' FNL & 441' FWL SECTION 35, T8N, 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 ez)=~'rv~) property line 4600' feet 4' @ SURFACE feet 3200 11957 MD / 10127' %feet 16. To be completed for deviated wells 17. Anticipated Pressure(=~. 2o AAC 25.~.~ (,)(2)) Kickoff depth 4000 feet 92 Maximum hole angle a~,,u,,su,~. 897 p,~Atto~,~w,th (WD) 4557 ps~g 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade i 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 BU'I-I' 3431 69 69 3500 3500' 3750 cu.ft. 12-1/4" 9-5/8" 47 L80 BUTt 9631 69 69 9700 9195' 2800 cu.ft. 8-1/2" 7" 29 L80 TKCBUT 2557 9400 8926' 11957 10127' 800cu.ft. ~ i 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 Intermediate RECEIVED Production Liner APP - 7 1994 Perforation depth: measured Atss~ 0il & Gas Cons. C0mmlssi0a true vertical ,~cllorage 20. Attachments Filing fee [~ Property plat ~ BOP Sketch[~ Diverter Sketch [~: Drilling program E~ Drilling fluid program ~ Time vs depth plot [~: Refraction analysis [-1 Seabed report ~ 20 AAC 25.050 requirements ~ 21 .I hereby Cerl~~n~ect to the best of my knowledge &/,~(.. ~el,~. Signed G. RUSSELL SCHMIDT Title Alaska Business Unit Drilling Manager Date Commission Use Only Permit Number I API numberI Approva¢~ate. _ I See cover letter ~' .~"- ~' 7, 50- Z,.~,.~ '"' ~-' O ~/",.5' ? I -"'~. --/,,5' - ~'~" Jfor other requirements Conditions of approval Samples required r-'J Yes ~ No Mud log required r'-] Yes .~ No Hydrogen sulfide measures [] Yes ~ No Directional survey required :~ Yes ]'-] No Requireclworking pressure forBOPE [-] 2M; ~ 3M; ~ SM; ~ 10M; I-] 15M Other: · ~riginal Signed By by the order of Approved by ~,,h.I ,.~, ,..~._.,_~ Commissioner the commission Date ~_//./~/~'~ Form 10-401 Rev. 1~"-"'1"--~ Submit in triplicate Dillon Well #16 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+1100'. 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 d: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 23 4000' 2.0 0 - 26° 8. Run open hole logs. 9. Run and cement 9-5/8" casing to 9700' MD. 10. Drill 8-1/2" hole to TD; LWD will be utilized (ROP 225') KOP DLS Angle Range Tot. Dogleg TD 10.5 +9700' 3.78 26-90° 92° +12000' 2 1.5 1.5 1 0.5 1 1 11. Run and cement 7" liner from TD to 9400' 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-IA. 17. Set BPV, Rem BOPE, Install tree and surface equipment. 18. Release Rig. 19. Produce well to obtain underbalance, detonate TCP guns. 58 days total time Filename:Dillon~P016. doc RECEIVED APR -7 1994- /kiaska 0ii & Gas Cons. Commission Anchoralto Depth 0I Dillon 16 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 (6,000) Avg ROP 275 FPD (8,000) (10,000) Log & Run 9-5/8" Csg Avg ROP 225 FPD (12,000) 10 I ~ I 2O 3O Estimate , I 4O Days Actual Run 7" Liner & Completion 50 60 70 RECEIVED APR -7 1994 Alaska 0il & Gas Cons. Commission Anchorage IKOBEBHA 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 @ 9500' 3) TCP guns 4-5/8" OD net 1000' 9-5/8" Production @ 9700' 47#, L-80, BTC RECEIVED Hemlock @ Intervals +1000' APR - ? 1994 Ataska 0ii & Gas Cons. Commissior Anchorage '7" Liner @ 12000' 29#, L80, BTC DILLON 16 PROPOSED COMPLETION UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 3-30-94 Created For: L LOHOEFER by jones ; Date plotted : 25-Mar-g4 j j Plot Reference is 16 Version #4. Coordinates are in feet reference slot #2-7.j True Vertical Depths are reference wellhead. --- Baker Hughes INTEQ J V 1200 20O0 2800 4400 4800 5200 5600 6000 8400 10000 RKB ELEVATION: 127' L 18 5/8" Casing Pt ,L 13 3/8" casing Pt KOP 2.00 6.00 10.00 BUILD 2 DEC / 100' 14.00 18.00 22.00 26.00 EOC UNOCAI Structure : DILLON Platform Well : 16 N 20 DEG W 4170' (TO TD) Field : Middle Ground Shoals Location : Cook Inlet, Alaska Point .... InC Dir 1VD NorthBoat Oeg/100J JT~e on 0,000.00 0 0 0 0.00J ErdCfKOP 4000 0.00340.00 4000 0 0 o,0oJ Build 5322 26.44 340.00 5278 282 -102 2.00I / Target 9702 26.44 340.00 9197 2114 -770 0.00J Target 1(]80168.08 340,00 9927 2857 --IO40 5.79I Target 11957 91.84 .._ 4~3~.~. 0 _ JTD LOCATION: 665' FNL, 441' FWL SEC. 35, TSN R13W TANGENT ANGLE 26.44 DEG TARGET #1 LOCATION: 2810' FSL, 1097' FWL SEC. 35, TSN, R13W <-- West 1600 1400 1200 1000 800 600 400 200 I I I I I I I I I t I I I I I RECEIVED APR -7 1994 Alaska Oil & Gas Cons. Commission Anchorage \'5'~' 5 ~ k\ .~ BUILD 3.8 DEO/ 100' FINAL ANGLE 91.84 DEG / 7" Casing Pt t I I I I I0 / I I I I i I I 28100 I I I I i I I I 0 400 800 12 0 1600 2000 2400 3200 3600 4000 4400 Scale 1 : 200.00 Vertical Section on 340.00 azimuth with reference 0.00 N, 0.00 E fromslot #2-7 Scale I : 100.00 0 200 4000 3800 3600 3400 3200 .3000 2800 2600 _ .2400 _2200 2000 1800 _ _1600 _ _1400 _ _1200 1000 800 600 400 200 0 200 A I I Z O SURFACE LOCATION: 696' FSL, 1867' FWL SEC. 55, TSN, R15W UNOCAL D[LLON Platform 16 slot #2-7 Hiddle Ground Shoals Cook Inlet, Alaska PROPOSAL LISTING by Baker Hughes INTEQ Your ref : 16 Version #4 Our ref : prop958 License : Date printed : 25-Mar-94 Date created : 4-Jan-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 7.693,w151 30 44.869 Slot Grid coordinates are N 2463867.915, E 229314.060 Slot local coordinates are 696.00 N 1867.00 E Reference North is True North RECEIVED APR -7 1994 Alaska Oil & Gas Cons. Commission Anchorage UNOCAL DILLON Platform, 16 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 1 Your ref : 16 Version #4 Last revised : 25-Mar-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 0.00 340.00 100.00 0.00 N 0.00 E 0.00 0.00 200.00 0.00 340.00 200.00 0.00 N 0.00 E 0.00 0.00 300.'00 0.00 340.00 300.00 0.00 N 0.00 E 0.00 0.00 400.00 0.00 340.00 400.00 0.00 N 0.00 E 0.00 0.00 500.00 0.00 340.00 500.00 0.00 N 0.00 E 0.00 0.00 600.00 0.00 340.00 600.00 0.00 N 0.00 E 0.00 0.00 700.00 0.00 340.00 700.00 0.00 N 0.00 E 0.00 0.00 800.00 0.00 340.00 800.00 0.00 N 0.00 E 0.00 0.00 900.00 0.00 340.00 900.00 0.00 N 0.00 E 0.00 0.00 1000.00 0.00 340.00 1000.00 0.00 N 0.00 E 0.00 1100.00 0.00 340.00 1100.00 0.00 N 0.00 E 0.00 1200.00 0.00 340.00 1200.00 0.00 N 0.00 E 0.00 1300.00 0.00 340.00 1300.00 0.00 N 0.00 E 0.00 1400.00 0.00 340.00 1400.00 0.00 N 0.00 E 0.00 1500.00 0.00 340.00 1500.00 0.00 N 0.00 E 0.00 1600.00 0.00 340.00 1600.00 0.00 N 0.00 E 0.00 1700.00 0.00 340.00 1700.00 0.00 N 0.00 E 0.00 1800.00 0.00 340.00 1800.00 0.00 N 0.00 E 0.00 1900.00 0.00 340.00 1900.00 0.00 N 0.00 E 0.00 2000.00 0.00 340.00 2000.00 0.00 N 0.00 E 0.00 2100.00 0.00 340.00 2100.00 0.00 N 0.00 E 0.00 2200.00 0.00 340.00 2200.00 0.00 N 0.00 E 0.00 2300.00 0.00 340.00 2300.00 0.00 N 0.00 E 0.00 2400.00 0.00 340.00 2400.00 0.00 N 0.00 E 0.00 2500.00 0.00 340.00 2500.00 0.00 N 0.00 E 0.00 2600.00 0.00 340.00 2600.00 0.00 N 0.00 E 0.00 2700.00 0.00 340.00 2700.00 0.00 N 0.00 E 0.00 2800.00 0.00 340.00 2800.00 0.00 N 0.00 E 0.00 2900.00 0.00 340.00 2900.00 0.00 N 0.00 E 0.00 3000.00 0.00 340.00 3000.00 0.00 N 0.00 E 0.00 3100.00 0.00 340.00 3100.00 0.00 N 0.00 E 0.00 3200.00 0.00 340.00 3200.00 0.00 N 0.00 E 0.00 3300.00 0.00 340.00 3300.00 0.00 N 0.00 E 0.00 3400.00 0.00 340.00 3400.00 0.00 N 0.00 E 0.00 3500.00 0.00 340.00 3500.00 0.00 N 0.00 E 0.00 3600.00 0.00 340.00 3600.00 0.00 N 0.00 E 0.00 3700.00 0.00 340.00 3700.00 0.00 N 0.00 E 0.00 3800.00 0.00 340.00 3800.00 0.00 N 0.00 E 0.00 3900.00 0.00 340.00 3900.00 0.00 N 0.00 E 0.00 0.00 0.00 18 5/8" Casing Pt 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 13 3/8" Casing Pt 0.00 0.00 0.00 0.00 4000.00 0.00 340.00 4000.00 0.00 N 0.00 E 0.00 0.00 KOP 4100.00 2.00 340.00 4099.98 1.64 N 0.60 W 2.00 1.74 4200.00 4.00 340.00 4199.84 6.56 N 2.39 W 2.00 6.98 4300.00 6.00 340.00 4299.45 14.75 N 5.37 W 2.00 15.69 4400.00 8.00 340.00 4398.70 26.20 N 9.54 ~ 2.00 27.88 4500.00 10.00 340.00 4497.46 40.90 N 14.88 ~ 2.00 43.52 4600.00 12.00 340.00 4595.62 58.83 N 21.41 ~ 2.00 62.60 4700.00 14.00 340.00 4693.06 79.96 N 29.10 W 2.00 85.10 4800.00 16.00 340.00 4789.64 104.28 N 37.96 ~ 2.00 110.98 4900.00 18.00 340.00 4885.27 131.76 N 47.96 ~ 2.00 140.21 RECEIVED APR -7 1994 Alaska Oil & Gas Cons. Commission Anchorage All data is in feet unless otherwise stated Coordinates from slot #2-7 and TVD from wellhead (127.00 Ft above mean sea level). Vertical section is from wellhead on azimuth 340.00 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, 16 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your ref : 16 Version #4 Last revised : 25-Mar-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 5000.00 20.00 340.00 4979.82 162.35 N 59.09 W 2.00 172.77 5100.00 22.00 340.00 5073.17 196.02 N 71.35 W 2.00 208.60 5200.00 24.00 340.00 5165.21 232.74 N 84.71 ~ 2.00 247.67 5300.00 26.00 340.00 5255.84 272.45 N 99.16 W 2.00 289.93 5322.19 26.44 340.00 5275.74 281.66 N 102.52 W 2.00 299.74 EOC 5500.00 26.44 340.00 5434.95 356.07 N 129.60 W 0.00 378.92 6000.00 26.44 340.00 5882.64 565.30 N 205.75 W 0.00 601.58 6500.00 26.44 340.00 6330.32 774.53 N 281.91 W 0.00 824.24 7000.00 26.44 340.00 6778.01 983.76 N 358.06 W 0.00 1046.90 7500.00 26.44 340.00 7225.70 1193.00 N 434.21 W 0.00 1269.56 8000.00 26.44 340.00 7673.38 1402.23 N 510.37 W 0.00 8500.00 26.44 340.00 8121.07 1611.46 N 586.52 W 0.00 9000.00 26.44 340.00 8568.75 1820.69 N 662.68 ~ 0.00 9500.00 26.44 340.00 9016.44 2029.92 N 738.83 ~ 0.00 9700.00 26.44 340.00 9195.52 2113.61 N 769.29 ~ 0.00 9701.47 26.44 340.00 9196.83 2114.23 N 769.52 W 0.00 9701.66 26.44 340.00 9197.00 2114.31 N 769.54 W 2.00 9703.41 26.51 340.00 9198.57 2115.04 N 769.81 ~ 3.79 9803.41 30.29 340.00 9286.52 2159.73 N 786.08 W 3.79 9903.41 34.08 340.00 9371.14 2209.78 N 804.29 W 3.79 10003.41 37.87 340.00 9452.05 2264.96 N 824.38 W 3.79 10103.41 41.65 340.00 9528.91 2325.05 N 846.25 W 3.79 10203.41 45.44 340.00 9601.38 2389.78 N 869.81 ~ 3.79 10303.41 49.23 340.00 9669.14 2458.86 N 894.95 W 3.79 10403.41 53.01 340.00 9731.90 2532.00 N 921.57 ~ 3.79 10503.41 56.80 340.00 9789.38 2608.87 N 949.55 W 3.79 10603.41 60.59 340.00 9841.33 2689.15 N 978.77 W 3.79 10703.41 64.37 340.00 9887.53 2772.47 N 1009.10 ~ 3.79 10801.34 68.08 340.00 9927.00 2856.66 N 1039.74 ~ 3.79 10890.05 69.90 340.00 9958.80 2934.48 N 1068.06 W 2.06 1492.22 1714.88 1937.54 2160.20 2249.26 9 5/8" Casing Pt 2249.92 2250.00 TARGET #1 2250.78 2298.34 2351.59 2410.32 2474.27 2543.15 2616.67 2694.50 2776.30 2861.73 2950.40 3040.00 16 Mid G-4a 3122.81 10990.05 71.96 340.00 9991.47 3023.29 N 1100.39 W 2.06 3217.32 11090.05 74.02 340.00 10020.72 3113.15 N 1133.09 W 2.06 3312.94 11190.05 76.07 340.00 10046.52 3203.93 N 1166.13 W 2.06 3409.55 11290.05 78.13 340.00 10068.85 3295.52 N 1199.47 ~ 2.06 3507.02 11390.05 80.18 340.00 10087.66 3387.81 N 1233.06 ~ 2.06 3605.23 11490.05 82.24 340.00 10102.93 3480.67 N 1266.86 ~ 2.06 3704.05 11590.05 84.30 340.00 10114.65 3573.99 N 1300.82 W 2.06 3803.36 11690.05 86.35 340.00 10122.80 3667.64 N 1334.91 W 2.06 3903.02 11790.05 88.41 340.00 10127.37 3761.50 N 1369.08 ~ 2.06 4002.91 11890.05 90.46 340.00 10128.35 3855.46 N 1403.27 ~ 2.06 4102.90 11957.17 91.84 340.00 10127.00 3918.52 N 1426.22 ~ 2.06 4170.00 TD / 7" Casing Pt RECEIVED APR -7 1994, Aiaska Oil & Gas Cons. Commission Anchorage ALL data is in feet un[ess otherwise stated Coordinates from slot #2-7 and TVD from wellhead (127.00 Ft above mean sea level). Vertical section is from wellhead on azimuth 340.00 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, 16 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 3 Your ref : 16 Version #4 Last revised : 25-Mar-94 Comments in wellpath MD TVD Rectangular Coords. Comment 1100.00 1100.00 0.00 N 0.00 E 18 5/8" Casing Pt 3500.00 3500.00 0.00 N 0.00 E 13 3/8" Casing Pt 4000.00 4000.00 0.00 N 0.00 E KOP 5322.19 5275.74 281.66 N 102.52 W EOC 9700.00 9195.52 2113.61N 769.29 W 9 5/8" Casing Pt 9701.66 9197.00 2114.31N 769.54 W TARGET #1 10801.34 9927.00 2856.66 N 1039.74 W 16 Mid G-4a 11957.17 10127.00 3918.52 N 1426.22 ~ 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 3500.00 O.OON O.OOE 13 3/8" Casing 0.00 0.00 O.OON O.OOE 9700.00 9195,52 2113.62N 769.29~ 9 5/8" Casing 0.00 0.00 O.OON O.OOE 11957.17 10127.00 3918.52N 1426.22~ ?" Casing Targets associated with this wel[path Target name Position T.V.D. Local rectangular coords. Date revised 16 Mid G-4a not specified 9927.00 2856.66N 1039.74W 4-Jan-94 16 Top G1 not specified 9197.00 2114.31N 769.54W 4-Jan-94 16 Td not specified 10127.00 3918.52N 1426.22W 22-Mar-94 RECEIVED APR -7 1994 Alaska Oil & Gas Cons. Commission Anchorage All data is in feet unless otherwise stated Coordinates from slot #2-7 and TVD from wellhead (127.00 Ft above mean sea level). Bottom hole distance is 4170.00 on azimuth 340.00 degrees from wellhead. Total Dogleg for wet[path is 91.85 degrees. Vertical section is from wellhead on azimuth 340.00 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, 16 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 1 Your ref : 16 Version #4 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 0.00 0.00 696.00 N 1867.00 E 0.00 0.00 100.00 0.00 340.00 100.00 696.00 N 1867.00 E 0.00 0.00 200.00 0.00 340.00 200.00 696.00 N 1867.00 E 0.00 0.00 300.00 0.00 340.00 300.00 696.00 N 1867.00 E 0.00 0.00 400.00 0.00 340.00 400.00 696.00 N 1867.00 E 0.00 0.00 500.00 0.00 340.00 500.00 696.00 N 1867.00 E 0.00 0.00 600.00 0.00 340.00 600.00 696.00 N 1867.00 E 0.00 0.00 700.00 0.00 340.00 700.00 696.00 N 1867.00 E 0.00 0.00 800.00 0.00 340.00 800.00 696.00 N 1867.00 E 0.00 0.00 900.00 0.00 340.00 900.00 696.00 N 1867.00 E 0.00 0.00 1000.00 0.00 340.00 1000.00 696.00 N 1867.00 E 0.00 0.00 1100.00 0.00 340.00 1100.00 696.00 N 1867.00 E 0.00 0.00 1200.00 0.00 340.00 1200.00 696.00 N 1867.00 E 0.00 0.00 1300.00 0.00 340.00 1300.00 696.00 N 1867.00 E 0.00 0.00 1400.00 0.00 340.00 1400.00 696.00 N 1867.00 E 0.00 0.00 1500.00 0.00 340.00 1500.00 696.00 N 1867.00 E 0.00 0.00 1600.00 0.00 340.00 1600.00 696.00 N 1867.00 E 0.00 0.00 1700.00 0.00 340.00 1700.00 696.00 N 1867.00 E 0.00 0.00 1800.00 0.00 340.00 1800.00 696.00 N 1867.00 E 0.00 0.00 1900.00 0.00 340.00 1900.00 696.00 N 1867.00 E 0.00 0.00 2000.00 0.00 340.00 2000.00 696.00 N 1867.00 E 0.00 0.00 2100.00 0.00 340.00 2100.00 696.00 N 1867.00 E 0.00 0.00 2200.00 0.00 340.00 2200.00 696.00 N 1867.00 E 0.00 0.00 2300.00 0.00 340.00 2300.00 696.00 N 1867.00 E 0.00 0.00 2400.00 0.00 340.00 2400.00 696.00 N 1867.00 E 0.00 0.00 2500.00 0.00 340.00 2500.00 696.00 N 1867.00 E 0.00 0.00 2600.00 0.00 340.00 2600.00 696.00 N 1867.00 E 0.00 0.00 2700.00 0.00 340.00 2700.00 696.00 N 1867.00 E 0.00 0.00 2800.00 0.00 340.00 2800.00 696.00 N 1867.00 E 0.00 0.00 2900.00 0.00 340.00 2900.00 696.00 N 1867.00 E 0.00 0.00 3000.00 0.00 340.00 3000.00 696.00 N 1867.00 E 0.00 0.00 3100.00 0.00 340.00 3100.00 696.00 N 1867.00 E 0.00 0.00 3200.00 0.00 340.00 3200.00 696.00 N 1867.00 E 0.00 0.00 3300.00 0.00 340.00 3300.00 696.00 N 1867.00 E 0.00 0.00 3400.00 0.00 340.00 3400.00 696.00 N 1867.00 E 0.00 0.00 3500.00 0.00 340.00 3500.00 696.00 N 1867.00 E 0.00 0.00 3600.00 0.00 340.00 3600.00 696.00 N 1867.00 E 0.00 0.00 3700.00 0.00 340.00 3700.00 696.00 N 1867.00 E 0.00 0.00 3800.00 0.00 340.00 3800.00 696.00 N 1867.00 E 0.00 0.00 3900.00 0.00 340.00 3900.00 696.00 N 1867.00 E 0.00 0.00 4000.00 0.00 340.00 4000.00 696.00 N 1867.00 E 0.00 0.00 4100.00 2.00 340.00 4099.98 697.64 N 1866.40 E 2.00 1.74 4200.00 4.00 340.00 4199.84 702.56 N 1864.61 E 2.00 6.98 4300.00 6.00 340.00 4299.45 710.75 N 1861.63 E 2.00 15.69 4400.00 8.00 340.00 4398.70 722.20 N 1857.46 E 2.00 27.88 18 5/8" Casing Pt 13 3/8" Casing Pt KOP RECEIVED APR -7 1994 4500.00 10.00 340.00 4497.46 736.90 N 1852.11E 2.00 43.52 4600.00 12.00 340.00 4595.62 754.83 N 1845.59 E 2.00 62.60 Alaska Oil & Gas Cons. Commission 4700.00 14.00 340.00 4693.06 775.96 N 1837.90 E 2.00 85.10 4800.00 16.00 340.00 4789.64 800.28 N 1829.04 E 2.00 110.98 Anchorage 4900.00 18.00 340.00 4885.27 827.76 N 1819.04 E 2.00 140.21 Alt data is in feet un[ess otherwise stated Coordinates from SW Corner of Sec. 35, T8N, R13W and TVD from wellhead (127.00 Ft above mean sea [eve[). Vertical section is from wellhead on azimuth 340.00 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, 16 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your ref : 16 Version #4 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 5000.00 20.00 340.00 4979.82 858.35 N 1807.91 E 2.00 172.77 5100.00 22.00 340.00 5073.17 892.02 N 1795.65 E 2.00 208.60 5200.00 24.00 340.00 5165.21 928.74 N 1782.29 E 2.00 247.67 5300.00 26.00 340.00 5255.84 968.45 N 1767.84 E 2.00 289.93 5322.19 26.44 340.00 5275.74 977.66 N 1764.48 E 2.00 299.74 EOC 5500.00 26.44 340.00 5434.95 1052.07 N 1737.40 E 0.00 378.92 6000.00 26.44 340.00 5882.64 1261.30 N 1661.25 E 0.00 601.58 6500.00 26.44 340.00 6330.32 1470.53 N 1585.09 E 0.00 824.24 7000.00 26.44 340.00 6778.01 1679.76 N 1508.94 E 0.00 1046.90 7500.00 26.44 340.00 7225.70 1889.00 N 1432.78 E 0.00 1269.56 8000.00 26.44 340.00 7673.38 2098.23 N 1356.63 E 0.00 8500.00 26.44 340.00 8121.07 2307.46 N 1280.48 E 0.00 9000.00 26.44 340.00 8568.75 2516.69 N 1204.32 E 0.00 9500.00 26.44 340.00 9016.44 2725.92 N 1128.17 E 0.00 9700.00 26.44 340.00 9195.52 2809.61 N 1097.71 E 0.00 1492.22 1714.88 1937.54 2160.20 2249.26 9 5/8" Casing Pt 9701.47 26.44 340.00 9196.83 2810.23 N 1097.48 E 0.00 9701.66 26.44 340.00 9197.00 2810.31 N 1097.45 E 2.00 9703.41 26.51 340.00 9198.57 2811.04 N 1097.19 E 3.79 9803.41 30.29 340.00 9286.52 2855.73 N 1080.92 E 3.79 9903.41 34.08 340.00 9371.14 2905.78 N 1062.71 E 3.79 2249.92 2250.00 TARGET #1 2250.78 2298.34 2351.59 10003.41 37.87 340.00 9452.05 2960.96 N 1042.62 E 3.79 10103.41 41.65 340.00 9528.91 3021.05 N 1020.75 E 3.79 10203.41 45.44 340.00 9601.38 3085.78 N 997.19 E 3.79 10303.41 49.23 340.00 9669.14 3154.86 N 972.05 E 3.79 10403.41 53.01 340.00 9731.90 3228.00 N 945.43 E 3.79 2410.32 2474.27 2543.15 2616.67 2694.50 10503.41 56.80 340.00 9789.38 3304.87 N 917.45 E 3.79 10603.41 60.59 340.00 9841.33 3385.15 N 888.23 E 3.79 10703.41 64.37 340.00 9887.53 3468.47 N 857.90 E 3.79 10801.34 68.08 340.00 9927.00 3552.66 N 827.26 E 3.79 10890.05 69.90 340.00 9958.80 3630.48 N 798.93 E 2.06 2776.30 2861.73 2950.40 3040.00 16 Mid G-4a 3122.81 10990.05 71.96 340.00 9991.47 3719.29 N 766.61 E 2.06 3217.32 11090.05 74.02 340.00 10020.72 3809.15 N 733.91 E 2.06 3312.94 11190.05 76.07 340.00 10046.52 3899.93 N 700.86 E 2.06 3409.55 11290.05 78.13 340.00 10068.85 3991.52 N 667.53 E 2.06 3507.02 11390.05 80.18 340.00 10087.66 4083.81 N 633.94 E 2.06 3605.23 11490.05 82.24 340.00 10102.93 4176.67 N 600.14 E 2.06 3704.05 11590.05 84.30 340.00 10114.65 4269.99 N 566.18 E 2.06 3803.36 11690.05 86.35 340.00 10122.80 4363.64 N 532.09 E 2.06 3903.02 11790.05 88.41 340.00 10127.37 4457.50 N 497.92 E 2.06 4002.91 11890.05 90.46 340.00 10128.35 4551.46 N 463.73 E 2.06 4102.90 11957.17 91.84 340.00 10127.00 4614.52 N 440.78 E 2.06 4170.00 TD / 7" Casing Pt RECEIVED APR -7 1994 Alaska Oil & Gas Cons. Commission Anchorage 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 340.00 degrees. Declination is 0.00 degrees, Convergence is -1.33 degrees. Catculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL DILLON Platform, 16 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 3 Your ref : 16 Version #4 Last revised : 25-Mar-94 Comments in wellpath MD TVD Rectangular Coords. Co~ent 1100.00 1100.00 696.00 N 3500.00 3500.00 696.00 N 4000.00 4000.00 696.00 N 5322.19 5275.74 977.66 N 9700.00 9195.52 2809.61 N 9701.66 9197.00 2810.31 N 10801.34 9927.00 3552.66 N 11957.17 10127.00 4614.52 N 1867.00 E 18 5/8" Casing Pt 1867.00 E 13 3/8" Casing Pt 1867.00 E KOP 1764.48 E EOC 1097.71E 9 5/8" Casing Pt 1097.45 E TARGET #1 827.26 E 16 Mid G-4a 440.78 E TD / 7" Casing Pt 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Casing positions in string 'A' Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing 696.00N 1867.00E 1100.00 1100.00 696.00N 1867.00E 18 5/8" Casing 696.00N 1867.00E 3500.00 3500.00 696.00N 1867.00E 13 3/8" Casing 696.00N 1867.00E 9700.00 9195.52 2809.62N 1097.71E 9 5/8" Casing 696.00N 1867.00E 11957.17 10127.00 4614.52N 440.78E 7" Casing Targets associated with this wellpath Target name Position T.V.D. Local rectangular coords. Date revised 16 Mid G-4a not specified 9927.00 3552.66N 827.26E 4-Jan-94 16 Top G1 not specified 9197.00 2810.31N 1097.45E 4-Jan-94 16 Td not specified 10127.00 4614.52N 440.78E 22-Mar-94 REEEIVED APR -7 1994 Alaska Oil & Gas Cons. Commission Anchorage At[ data is in feet un[ess otherwise stated Coordinates from SW Corner of Sec. 35, TBN, R13W and TVD from wellhead (127.00 Ft above mean sea level). Bottom hole distance is 4170.00 on azimuth 340.00 degrees from wellhead. Total Dogleg for we[.tpath is 91.85 degrees. Vertical section is from wellhead on azimuth 340.00 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 16 slot #2-7 Middle Ground Shoals Cook Inlet, Alaska CLEARANCE REPORT by Baker Hughes I NTEQ Your ref : 16 Version #4 Our ref : prop958 License : Date printed : 30-Mar-94 Date created : 4-Jan-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 7.693,w151 30 44.869 Slot Grid coordinates are N 2463867.915, E 229314.060 Slot local coordinates are 696.00 N 1867.00 E Reference North is True North ( WARNING: DATA BELOW IS A SUMMARY, DETAIL PROXIMITIES NOT TABULATED ) Object wellpath 18 Version #2,,18,DILLON Platform 17 Version #3,,17,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 <0-10554'>~ MSS <1958 - 2466' GMS <0-10508'>, MSS <0-12000'>~ PGMS <1280-10000' PGMS <0-10500'>~ GMS <0-13133'>1 ,D-9Rd,DILLON Platform >,,D-lO,DILLON Platform ,D-11oDILLON Platform ,D-12,DILLON Platform >,,D-13,DILLON Platform ,D-14,DILLON Platform ,D-15,DILLON Platform Closest approach with 3-D minimum distance method Last revised Distance M.D. Diverging from M.D. 26-Jan-93 7.2 3100.0 3100.0 25-Mar-94 3.4 3100.0 3100.0 30-Mar-94 4.6 300.0 4433.3 30-Mar-94 69.3 200.0 7560.0 30-Mar-94 95.9 700.0 700.0 30-Mar-94 9.5 300.0 300.0 30-Mar-94 58.5 600.0 5980.0 30-Mar-94 58.5 600.0 8420.0 30-Mar-94 7.7 800.0 10957.9 30-Mar-94 7.7 800.0 10801.3 30-Mar-94 108.2 800.0 800.0 30-Mar-94 58.7 900.0 900.0 30-Mar-94 58.7 900.0 10578.2 30-Mar-94 72.4 100.0 200.0 30-Mar-94 10.6 300.0 300.0 30-Mar-94 106.2 300.0 300.0 30-Mar-94 68.4 400.0 4500.0 30-Mar-94 88.0 1500.0 1500~ APR -7 ]994 Alaska Oil & Gas Cons. Anchorage UNOCAL DILLON Platform 16 slot #2-7 Middle Ground Shoals Cook Inlet, Alaska CLEARANCE REPORT by Baker Hughes INTEQ Your ref : 16 Version #4 Our ref : prop958 License : Date printed : 31-Mar-94 Date created : 4-Jan-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 ?.693,w151 30 44.869 Slot Grid coordinates are N 2463867.915, E 229314.060 Slot local coordinates are 696.00 N 1867.00 E Reference North is True North Main calculation performed with 3-D Minimum Distance method Object wellpath 17 Version #3,,17,DILLON Platform 18 Version #2,,18,DILLON Platform MSS <3407 - 11325'>,,D-5,DILLON Platform MSS <Oo12000,>,,D-12,D[LLON Platform MSS <2150-10500'>,,D-3,DILLON Platform PGMS <0-10500'>,,D-14,DiLLON Platform GMS <O-13133'>,,D-15,D[LLON Platform MSS <1245-10942'>,,D-6,DILLON Platform MSS <1930 - IO?50'>,,D-?,DILLON Platform GMS <O-10508'>,,D-11,D[LLON P[atform PGMS <3200-10505'>,,D-CRd,DILLON P[atform MSS <?205-10537'>,,D-8,DILLON Platform PGMS <1280-10000'>,,D-13,DILLON Platform PGMS <O-10304'>,,D-2Rd,DILLON Platform HSS <5770 - 10401'>,,D-2,DILLON P[atform PGMS <O-10554'>,,D-gRd,DILLON Platform MSS <?122-10900'>,,D-9,DILLON Platform MSS <2020-10550'>,,D-4,DILLON Platform MSS <1958 - 2466'>,,D-lO,DILLON Platform Closest approach with 3-D minimum distance method Last revised Distance M.D. Diverging from M.D. 25-Mar-94 3.4 3100.0 3100.0 26-Jan-93 7.2 3100.0 3100.0 30-Mar-94 108.2 800.0 800.0 30-Mar-94 106.2 300.0 300.0 30-Mar-94 95.9 700.0 700.0 30-Mar-94 88.0 1500.0 1500.0 30-Mar-94 104.8 100.0 100.0 30-Mar-94 4.6 300.0 4433.3 30-Mar-94 9.5 300.0 300.0 30-Mar-94 10.6 300.0 300.0 30-Mar-94 7.7 800.0 10801.3 30-Mar-94 7.7 800.0 10957.9 30-Mar-94 68.4 400.0 4500.0 30-Mar-94 58.5 600.0 8420.0 30-Mar-94 58.5 600.0 5980.0 30-Mar-94 58.7 900.0 10578.2 30-Mar-94 58.7 900.0 900.0 30-Mar-94 69.3 200.0 7560.0 30-Mar-94 72.4 100.0 200.0 RECEIVED APR -7 1994 Alaska Oil & Gas Cons. Commission Anchorage Scale 1620 I I 1 ·30.00 1 650 1680 I I I 1710 I I 2200 2000 520O 5000 4600 4200 UNOCAL Struatum : DILLON Platform Well : 16 / 17 Field : Middle Ground Shool. I.o~oflon : Cook Inlet, No.ko 1800 Easf 1400 1740 1770 I I I --> 1800 1830 1860 1890 1920 1600 I I I I 1200 1800 1600 140( 1000 4800 1400 1200 1000 1200 1400 1000 1400 1800 I00 ;600 1800 1600 600 1400 1200 000 1200 ,400 3200 RECEIVED _570 ~o i _540 -- _ 0 · 0 _5100 870 _840 _810 _78O _75O _720 A I I _690 z - 0 _660 ~ _630 _600 APR -7 1994 Alaska Oil & Gas Cons. Commission Anchorage UNOCAL DILLON PI~TFOR~ 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. R'ECEIVED APR -7 1994 Alaska Oil & Gas Cons. Commission Anchorage DEPTH CASING SIZE BOLE 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 1994 Alaska 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. 0' 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 RECEIVED APR -7 1994 Oil & Gas Cons. Commission Anchorage DILLON PLATFORM ELEVATION DIMENSIONS UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 3-21-94 FILE: DILELEV.drw FILL-UP 3"-lOM CHECK VALVE KILL LINE /( ANNULAR BOP 20~/~" 2000 si SPOOL l{ I PIPE RAMS 20~'4"3000 psi BLIND RAMS FLOW DIVERTER SPOOL BLIND FLANGED DURING BOP OPERATIONS GATE VALVES 20%" 3000 psi _~ HCR { { HCR [~ MANUAL'{ DRILLING I' MANUAL [~ ,S.,~OOL ~>~o~/~ooo ~~<~>~f] CHOK~ B''- 10M *~ ~ I ~ 4"- 10M GATE VALVES [ PIPE RAMS ] 20~/g'3000 psi RISER zo~/~'' 3000 psi RECEIVED APR -7 1994 A.i~ska Oil & {]as Cons. Commission Anchorage CHAKACHATNA RIG 428 BOP/DIVERTER STACK 21 %1' 2000psi/20%~' 3000psi ) FLOW FILL- UP ANNULAR BOP 13~/~5000 psi PIPE RAMS 13%'5000 psi BLIND RAMS 3"- 10 M 136ye" 5000 psi CHECK VALVE HCR HCR KILL ~ LINE ~U ~~ooo ps~ CHOKE I , LINE--~ RISER ~3¥ 5000 psi RECEIVED APR -7 1994 Alaska Oil & Gas Cons. Commissio~ Anchorage CHAKACHATNA RIG 428 BOPE STACK 13 %' 5000 psi VENT OU'P31DE OF* WINDWALI~ ,~' PANIC LINE ~' 5,000 Psi BALL VALVE 1/16-5t.4 HUB 5M TARGET BUND HUB E=_ BUND W1L~S VENT UP DERRICK 3' RELIEF VALYE --~ SET AT 40 PS! ~ CLAklP HUB CONNECTION BUFFER TANK MUD GAS SEFERATOR 150 ~. FtANG£ SIPHON UNE ~5 CLA/dP I~// BX~55 I0, 000 PSi HYD. CHOKE TO PRODUCTION SEP,~,ATOR BUD RE[URN LINE UNOCAL CHOKE MANIFOLD COOKINLET DWC,. CM-1:12592 Ill L , : PLAN VIEW ~ NORTHWEST LEG WEW A-A ~ I I I I I P,M RIG 428 BLOW-OUT PREVEN1T. R STACK RSRRdSA, POOL ARC T'IC AL/',SHA NO~; REFERENCE DRAW/NC 428.5059 FOR FURTHER INFORI, fAI?ON PERTAINING TO DIYERTER LINE SPOOLS. DIVERTER UNE LAYOUT NORTHWEST LEG PosmoN POOL RIG 428 CASING DESIGN WELL: 1. 2. 3. CASING SIZE DILLON ~16 MUD WT. I 8.8 PPG 9.0 PPG 10.0 PPG INTERVAL BOTTOM TOP FIELD: MIDDLE GROUND SHOAL DATE: 1. 18-5/8" 1100' 69' MD 1100' 69' TVD 2. 13-3/8" 3500' 69' MD 3497' 69' TVD 3. 9-5/8" 9700' 69' MD 9197' 69' TVD 4. 7" 11957' 9400' MD 10127' 8926' MD MARCH 28, 1994 DESIGN BY: C.L. LOHOEFER M.S.P. 385 psi 897 Psi 608 psi WEIGHT TENSION MINIMUM COLLAPSE COLLAPSE W/ BF -TOP OF STRENGTH PRESS @ RESIST. BURST MINIMUM W/O BF X SECTION TENSION BOTTOM TENSION PRESSURE YIELD LBS LBS 1000 LBS PSI* p$~ CDF Psi** DESCRIPTION LENGTH WT. GRADE THREAD TDF 8D__F 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 9631' 47~, L-80, BTC 452,657 SAME 1086 2.40 2630 4750 1.80 2279 6870 3.01 2557' 295, L-80, BTC 74,153 SAME 676 9.12 2896 7020 2.42 2279 8160 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 APR -? 1994 Oil & Gas Cons. Commisslo. Anchorage Leak Off Test (LOT) Data Cook Inlet, Alaska Unocal Energy Resources Aloska_ Well # Date Baker Platform Ba 28 10-10-93 Ba 30 10-24-93 Ba 30 10-28-93 Ba 28 11-17-93 Ba 29 12-17-94 Ba 29 12-29-93 Ba 30 01-27-94 Ba 28 03-01-94 Grayling Platform G-40 01-24-90 G-40 Monopod Platform A-ltd 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 11-13rd 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 Csg Size Shoe Depth Fmc Grad. (TVD) msi/f~.) EMW 24" 802' 0.94 18.10 24" 803' 0.83 15.90 18-5/8" 2011' 0.94 18.10 18-5/8" 2135. 0.75 14.50 18-5/8" 2054' 0.76 14.61 13 -3/8" 5869' 0.85 16.33 13-3/8" 5467' 0.93 17.96 13-3/8" 3509' 0.75 14.40 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" 9966t 0.96 18.40 13-3/8" 3803' 1.00 19.20 18-5/8" 1010' 0.87 16.80 9-5/8" 9592t 1.05 20.20 18-5/8" 982° 0.91 17.50 13-3/8" 4208' 0.84 16.20 9-5/8" 9877' 0.93 17.90 Filename A:Lotdata. doc /~PR -'7 1994 oil 8, Gas Cons. Commissioe ~,nct~orage Dillon Platform Well # 16 South Middle Ground Shoals (SMGS) March 24, 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: BlIP 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"): BHP gradient: Gas gradient (assume worst case) 9.0 ppg = 0.47 psi/ft. 3500' MD / 3497' TVD 0.80 psi/ft. 9700' MD / 9197' TVD 0.45 psi/ft o.o psi/ft. Gas kick situation in the wellbore, assume; 3/4 mud & 1/4 gas. MSP = BHP - Hydrostatic Pressure MSP = BI-IP - (3/4 mud + 1/4 gas) MSP = (9197' x 0.45 psi/ft) - ((0.75 (9197' x 0.47 psi/ft)) + (0.25 (9197' x 0.0 psi/ft.))) MSP = 897 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, if a constant BHP is applied. A conservative estimate would be the MSP plus the hydrostatic pressure at the 13-3/8" casing depth (HPesg). HPsh = MSP + HPcsg HPsh = 897 + (3497' x 0.47) HPsh = 2540 psi This (HPsh = 2540 psi) is less than the fracture pressure at the same shoe (FPsh) and thus adequate to handle the well kick scenario. RECEIVED HPsh = 2540 psi < FPsh = 0.80 psi/ft x 3497' = 2798 psi. APR -7 1994 0il & Gas Cons. Commission Anchorage Dillon Platform Well #16 Pressure Calculations Hole Section 3 Depth Interval: 3500' - 9700' 12-1/4" hole size 9-5/8" casing to 9700' Mud Weight: Shoe depth (9-5/8"): Est. fracture gradient of 9-5/8" shoe: Depth of next hole section (8-1/2"): BlIP gradient: Gas gradient (assume worst case) 10.0 ppg = 0.52 psi/fL 9700' MD / 9197' TVD 0.85 psi/ft. 11957' MD / 10127' TVD 0.45 psi/ft 0.0 psi/ft. 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 = (10127' x 0.45 psi/~ - ((0.75 (10127' x 0.52 psi/R)) + (0.25 (10127' x 0.0 psi/ft.))) MSP = 608 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 0tPcsg). HPsh = MSP + HPcsg HPsh = 608 + (9197' x 0.52 psi/ft) HPsh = 5390 psi This (I-IPsh = 5390 psi) is less than the fracture pressure at the same shoe (FPsh) and thus adequate to handle the well kick scenario. HPsh = 5390 psi < FPsh = 0.85 psi/ft x 9197' = 7818 psi. Additionally, HPsh - Pore Pressure at shoe < Internal Yield of the 9-5/8" casing 5390 - (9197' x 0.45 psi/ft) < 6870 psi 1251 psi < 6870 psi Filename:AOGCC~Di 16c~¢.doo RECEIVED APR -'7 1994 0il & Gas Cons. Commission Anchorage ,dELL PERMIT CHECKLIST · Poo,. S WELL NAME GEOL AREA U~IT# PROGRAM: exp [] ,, der }~ redr11 [] serv [] ON/OFF SHORE <~ ADMINISTRATION 1. 2. 3. 4. 5. 6. 8. 9. 10. 11. 12. 13. Permit fee at~ached ................... Lease number appropria=e ............... Unique well name and number .............. Well located in a defined pool ............. Well located proper distance from drlg unit boundary. Well loca=ed proper distance from other wells ..... Sufficient acreage available in drilling unit ..... If deviated, is wellbore plat included ; ....... Opera,or only affected part~ .............. Operator has appropriate bond in force .......... Permit can be issued without conservation order .... Permit can be issued without adminis~ra~ive approval. Can permit be approved before 15-day wai~ ....... ENGINEERIN~ GEOLOGY 14. Conductor string provided ............... 15. Surface casing protects all known USDWs ........ 16. CM~ vol adequate to circulate on conductor & surf csg. 17. CM~ vol adequate to tie-in long string to surf csg . . 18. CMT will cover all known productive horizons ...... 19. Casing designs adequate for C, T, B & permafrost .... 20. Adequate tankage or reserve pi~ ............ 21. If a re-drill, has a 10-403 for abndnmnt been approved. 22. Adequate wellbore separation proposed .......... 23.. If diverter required, is it adequate .......... 24. Drilling fluid program schematic & equip list adequate 25. BOPEs adequate .............. ; ...... 26. BOPE press rating adequate; test to' ~/~ psig. 29.28' Work will occur without operation shutdoWnis presence of H2S gas probable ............ ....... APPR 30. 31. 32. 33. Permit can be issued w/o hydrogen sulfide measures .... Y {N~ Data presented on potential overpressure zones ..... Y/ Seismic analysis 9f shallow gas zones .......... Y /. Seabed condition survey (if off-shore)~ 2 ~ ; : : ~ : 'Z " [explo=ato=3ronly] tOW~o - A:~FORMS~cheklist rev 03/94 I-4 Well HistorY File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. UNOCAL DILLON 16 MIDDLE GROUND SHOAL KENA~£cEIV~,D ALASK~ 0 5 199,~ LIBRARY TAPE L/STING ATLAS WIRELINE SERVICES Anchorage, Alaska Tape Subfile 2 is type: LIS CN : UNOCAL WN - ' : DILLON #16 FN : MIDDLE GROUND SHOAL COUN : KENAI STAT : ALASKA LIS COMMENT RECORD (s) : Run 1 & Run 2 Spliced Data. Spliced as follows: GR at 10101 CN, CNC, CNCF, LSN, SSN, TTEN, & SPD at 10111 Run 1 data shifted uphole 4 ft to match Run 2 data * FORMAT RECORD (TYPE# 64) ONE DEPTH PER FRAME Tape depth ID: F 21 Curves: Name Tool Code Samples Units API API API API Log Crv Crv Size Length Typ Typ Cls Mod 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 AC AC 68 1 US/F 4 ACQ AC 68 1 4 BIT AC 68 1 IN 4 CHT AC 68 1 LB 4 SPD AC 68 1 F/MN 4 TTEN AC 68 1 LB 4 CAL CDL 68 1 IN 4 CORR CDL 68 1 G/C3 4 DEN CDL 68 1 G/C3 4 CN~ 2435 68 1 PU-L 4 CNC 2435 68 1 PU-S 4 CNCF 2435 68 1 PU-S 4 LSN 2435 68 1 CPS 4 SSN 2435 68 1 CPS 4 CCL 2435 68 1 4 GR 2435 68 1 GAPI ' 4 RFOC DIFL 68 1 OHMM 4 RILD DIFL 68 1 OHMM 4 RILM DIFL 68 1 OHMM 4 SP DIFL 68 1 MV 4 VILD DIFL 68 1 MV 4 4 48 852 89 1 4 81 285 47 0 4 28 038 50 5 4 95 558 30 1 4 61 094 30 1 4 95 558 30 1 4 87 374 67 0 4 34 168 75 6 4 59 047 24 5 4 52 326 75 5 4 98 211 23 1 4 98 211 23 1 4 84 023 70 1 4 83 368 34 1 4 90 640 78 6 4 08 501 10 0 4 27 515 24 6 4 04 903 06 0 4 06 213 78 0 4 53 419 67 0 4 04 522 10 6 84 * DATA RECORD (TYPE# 0) Total Data Records: 4208 974 BYTES * Tape File Start Depth = 11571.000000 Tape File End Depth = 0.250000 Tape File Level Spacing = 0.250000 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep. Code: 68 1018249 datums Tape Subfile: 2 4214 records... Minimum record length: Maximum record length: 62 bytes 974 bytes Tape Subfile 3 is type: LIS **** TAPE TRAILER **** 01 **** REEL TRAILER **** 94/ 7/28 01 Tape Subfile: 3 2 records... Minimum record length: 132 bytes Maximum record length: 132 bytes End of execution: Thu 28 JLY 94 ll:21a Elapsed execution time = 53.88 seconds. SYSTEM RETURN CODE = 0