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161-008
1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: __________________ 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): Swanson River Field GL:156.5' BF:156.5' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 (ft MSL) 22. Logs Obtained: 23. BOTTOM 20" - 31' 11-3/4" - 2,032' 7" N-80 4,489' 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 July 15, 1961 June 16, 1961 AKA028399 N/A N/A 4,489' MD / 4,489' TVDN/A N/A 10,875' MD / 10,875' TVD N/A Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: Oil-Bbl: suspension, or abandonment, 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 if necessary N/A N/A Water-Bbl: PRODUCTION TEST N/A Date of Test: Flow Tubing - 47# 31' Surface 4,489' Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 23-29# Surface DEPTH SET (MD) PACKER SET (MD/TVD) Surface CASING WT. PER FT.GRADE N/A 347200 TOP SETTING DEPTH MD Surface SETTING DEPTH TVD 2468634 BOTTOM TOP 9-7/8" Surface 16" HOLE SIZE AMOUNT PULLED 50-133-10160-00-00 KGSF 1 347200 2468634 N/A CEMENTING RECORD N/A 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 10/21/2020 2193' FSL, 516' FEL, Sec 28, T8N, R9W, SM, AK 2193' FSL, 516' FEL, Sec 28, T8N, R9W, SM, AK 161-008 / 320-357 Tyonek 64-5 Gas Storage 175' 4,489' MD / 4,489' TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas Cond Surface 2,032' 1290 sx - Stg1 - 600 sx Stg 2 - 1200sx N/A SIZEIf Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): 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 WINJ SPLUGOther Abandoned Suspended Stratigraphic Test No No (attached) No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment By Samantha Carlisle at 10:59 am, Nov 20, 2020 RBDMS HEW 11/30/2020 Abandonment Date 10/21/2020 HEW Swanson River MDG xGSFD 11/30/2020 DSR-11/30/2020 Abandoned gls 12/11/20 4,489' MD / 4,489' TVD Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD Top of Productive Interval N/A Hemlock 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Contact Email:cdinger@hilcorp.com Authorized Contact Phone: 777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: 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. 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). 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, 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. Formation at total depth: Wellbore Schematic, P&A Reports. Signature w/Date: 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. INSTRUCTIONS 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). Yes No Well tested? Yes No 28. CORE DATA If yes, list intervals and formations tested, briefly summarizing test results. Attach separate pages to this form, if needed, and submit detailed test information, including reports, per 20 AAC 25.071. NAME This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. Authorized Name: Monty Myers Authorized Title: Drilling Manager Permafrost - Base 29. GEOLOGIC MARKERS (List all formations and markers encountered): FORMATION TESTS Permafrost - Top No NoSidewall Cores: Yes No Form 10-407 Revised 3/2020 Submit within 30 days of Completion, Suspension, or Abandonment Digitally signed by Cody Dinger DN: cn=Cody Dinger, ou=Users Date: 2020.11.20 10:40:04 - 09'00' Cody Dinger Updated by DMA 02-06-20 SCHEMATIC Swanson River Field Well: KGSF #1 / PTD 161-008 API: 50-133-10160-00-00 Abandoned: 10-21-20 PBTD = 6,813’ TD = 10,875’ MAX HOLE ANGLE = 1.25° @ 4,565’ RKB = 15’ CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20” - - - 15’ 31’ 11-3/4” 47 - - 11.00 Surface 2,032’ 7” 29 N-80 BTC 6.184 Surface 243’ 7” 26 N-80 BTC 6.276 243’ 883’ 7” 23 N-80 BTC 6.366 883’ 4,489’ P&A’d JEWELRY DETAIL NO. Depth ID OD Item 1 6,167’ 2.867” 5.020” Chemical Inj Sub w ¼” control line 2 6,228’ 2.813” 4.540” Sliding Sleeve 3 6,244’ 2.870” 5.983” Baker Premier Packer 4 6,297’ 2.813” 3.940” X Nipple 5 6,356’ 2.992” 3.500” WLEG, Auto Release 6 ±6,507’ - 4.630” TCP Guns (length 32.76’) Gun release not verified ¼” SS control line w/ 41 tubing clamps (one every other joint) Clamp O.D. 4.76” PERFORATION HISTORY (Tyonek Perfs TDT Log Depth) Interval Accum. Date Zone Top Btm Amt spf Comments 9/8/2011 64-5 6,380'6,388'8'5 Reperf 4-5/8" Millenium TCP guns, 5spf, 60 deg 12/3/1998 64-5 6,380'6,388'8'4 1-11/16" Pivot, 180 deg. 7/26/1998 68-0 6,883'6,911'28'4 Abandoned 6/20/1961 - 10,615' 10,616' 1' 5 Abandoned 6/21/1961 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/1961 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/1961 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/1961 - 10,752' 10,754' 2' 5 Abandoned J D K F G H I Notes NO. Depth Item K 7,114’ 7” Stage Collar OLD ABANDONMENT DETAIL NO. Depth ID OD Item A 6,615’ - - EZ Squeeze Packer w/ 75’ cement on top B 6,652’ - - Fish: 2 Baker K-1 Retainers C 6,850’ - - PosiSet Plug w/ 37’ Cement D 9,015’ - - Tubing cut at 9,015’ WLM. E 9,733’ - - Top of Cement Plug. Pressure tested to 2,500 psi. F 10,473’ - - Camco “MM” Mandrel with CEV Valve G 10,519’ - - Brown CC Safety Joint H 10,530’ - - Brown, 2-7/8” x 7”, Type HS-16-1 Packer I 10,600’ - - Camco “D” Nipple J ? - - Venturi Shoe D E C TOC @ 9,100’ TOC @ 6,813’ 1 2 5 6 TOW @ 4,489’ 11-3/4” 4 Top of fill @ 6,655’ 3 A TOC @ 6,540’ B 64-5 TOC @ 5,619’ CIBP @ 4,507’ cut tubing at 6210 ft Cmt retainer @6167' (25 bbls below retainer 5 bbls above Activity Date Ops Summary 8/31/2020 Continue moving F/seaview T/ SR #1 All rig components at location at 1700 hrs R/U Pollard slick line unit and test lubrication 2500 psi all good Well pressure at 2250 psi p/u 2.80 drift RIH t/ 6330" no issues POOH and P/U pron RIH,set at 6317' SLM POOH and P/U PX plug RIH and set @ 6317' POOH R/D Slick line unit and Bleed pres of to 0 and no build up test for 30 mins all good secure well . 9/1/2020 PJSM w/crew Continue R/U Rig401 and spot Equipment , fill 3 1/2'Tubing tot 55 bbls produced water 8.4+ and test PX plug t/ 500 psi f/30 mins all good,Set BPV w/NOS well head hand . N/D tree, install test dart function test all locked down screws,N/U 7x11'spool adapter,add mud cross spool,double-gates and annular bag Continue welding up onthe modified landings and brace in carrier beam w/ engineer support.BOP Test (Witness Waived By AOGCC Jim Regg ) 9/2/2020 PJSM w/crew and Move in the 401 carrier over well ,spot mud pits and fill same with produced water 8.4+.,Finish tightening All BOP bolts , make up 2 7/8"and 3 1/2" test joints,Function test all ram body M/U and screw in the 2 7/8" test joint.,Continue Testing BOP t/250/2500PSI 5 min low,5 min high tested gas detector pit level indicators w/ quadco hand C/O 2 7/8'test joint and RIH w/3 1/2" test joint Tested 3 1/2" VBR All test Good R/D test Equipment ,Pull BPV and lay down Same secure well . 9/3/2020 PJSM Check well no pressure R/U Pollard Slick line test Lubricator 2500 psi ,RIH #1 to pull prong @ 6297'well w/ 500 psi POOH L/D same M/U retrieving tool RIH would no drift through pump in sub. with 500 PSI on well .Decision was made not to pump through plug , M/U Prong and RIH and set prong in plug @ 6297'POOH and test plug w/ 1000 PSI All good Bleed well t/0 R/D 3 1/2' pump in sub P/U 4 1/2" pump in sub 9/4/2020 PJSM / R/U landing joint ,and pollard slick line and test lubw/ 3' FOSV t/2500 psi Bleed down t/0 RIH t/ pull prong @ 6297' W/ 1500 PSI POH L/D prong M/U PX Plug retrieving tool RIH and Pull PX plug @6312' POOH R/D Slick line and set up e-line standby . W/ 1400 psi gas and bleed off slow through choke/ Shut in @1400psi,Bull Head 86 bbls of 8.6+@ 2-3 bbls w/ w/ start out 2300 psi after 20 bbls way pres @ 1500 psi @ 55 bbls way pres 500 psi Tot 85 bbls pump . Shut down Monitor well 30 mins pres bleed down t/ 0 open up well to choke manifold and Monitor well 30 mins and pres build up t/ 300 psi, Bluu head # 2 volume 84 bbls @ 3.5 bbls w/ 2400 PSI shut down monitor well 1 hr 10 PSI .,R/U Alaska E-line M/U Jet cutter and test lubricator 2500 psI , RIH and cut @ 6210" POOH R/D same and CBU @ 3.5 bbls @ 400 psi take returns to pit trough IA no back pressurei @ 3.5bbls min Shut down Monitor well 1 hr well static no issues . secure well for the night 9/5/2020 Initial well pressure 750 psi upon arrival. PJSM on monitoring well, pull hanger. Open to TBG, all fluid. Open to Annulus, partial gas and fluid. Circ tubing volume of 8.7ppg fluid from pits at 3 bpm, monitor, pressure increase. Circ all the way around, 8.7 ppg heavy in and out. Shut in, monitor, steady pressure increase and stabilized at 475 psi. Stage laydown machine, spooler.,Mobilize salt to location as contingency. Open well, fluid packed on tubing with 8.7 ppg heavy fluid. Open to Annulus, 8.7 ppg heavy with slight burping but not gas. Bleed through choke to 0 psi. Shut-in, slowly increase to 60 psi. Open Annulus, all gas bleed. Shut in, monitor, build to 10 psi but no more. Open, bleed to 0 psi and well seems static, circulate through Gas Buster while waiting on Wellhead rep.,Conduct PJSM for pulling hanger. Stop circulation, open to well and jumper line to Mud Gas Separator is jumping - suspect gas mixed in fluid returns. Close in, both Tubing and Annulus pressures start to rise fairly soon. NaCl has arrived on location, offload and separate in preparation to mix to raise fluid weight.,Discussed pressure situation with Field Operator, found that KGSF-7 is under gas injection. Coordinated shut-in, discussed options with ODE, coordinated delivery of material to weight up in preparation for weighting up fluids in the morning. 9/6/2020 Conduct PJSM on opening up well for monitoring, preparation for weighting up fluid system. Open up to well, initial well pressure 1055 psi. Gas bleed off Annulus, mixed fluid and gas from Tubing. Fluid weight pumped in previously at 8.7 ppg heavy.,Crew prepping location for arrival of portable 80-bbl mix hopper. Relocate pallets of NaCl and stage in Barite/polymer in preparation for mixing Barite system. Meet with Field Operator, agreed to shut-in injector influence. Well pressure bled down to 550 psi, pressure rose to 685 psi after closing in. Bleed again, all gas from Tubing. Bleed to 90 psi, fast increase to 370 psi.,Break circulation with 8.7 ppf fluid from pits at 3 bpm while waiting on mix hopper to arrive. Gas entrained returns.,Mix 11.0 ppg Barite fluid system,Displace well to 11.0 ppg system. No issues on displacement. Weigh fluids with return of mud, 10.9 ppg in, 10.7 ppg heavy out. Monitor flow, no fl ow. Close in well and monitor gauges, no increase in pressures after 30 minutes. Secure location. 9/7/2020 Morning safety meeting and PJSM for monitoring well, breaking circulation with new mud system, and pulling hanger. Open to well, static. Break circulation with no issues, crew mixing slug for upcoming tubing lay down. Down on pumps, well static.,Back out Lock Down Screws, pull hanger with 50k PUW. No issues on pulling. Lay down hanger. Mobilize in tongs, complete floor prep for pulling tubing string.,POH with the 3-1/2" tubing and 1/4" control line. Stand back tubing as it is pulled. Recover 41 Canon Clamps and all pins. Mix 20 bbls of 12.0 ppg mud push system.,PU and MU 7" cement retainer on 3-1/2" workstring,RIH with 7" cement retainer on 3-1/2" workstring to 2250'. Secure well and location. 9/8/2020 Conduct safety meeting with crew. Emphasis on opening up to well, inspecting lift equipment, and good discussion around pressure control for the upcoming cement job.,Open to well, static. RIH with 7" cement retainer on 3-1/2" workstring. Set retainer at ~6167' with ~7' of tubing stump up for cement operation. Set down with 40k, pick up with 40k over, confirmation of set. First Aid: one of crew reported to TP that while adjusting a valve, felt a pop in chest and was a little sore. Continued working, notifications were made, report accepted as First Aid with no limitations to work.,Rig Up cementers. Pressure test surface lines to 3500 psi. Conduct injectivity test, able to attain 2.0 bpm at 2400 psi. Good test.,PJSM on conducting cement job,Conduct 30 bbl 15.8 ppg cement squeeze against 7" cement retainer. Pump down 12.0 ppg mud push, followed by 25 bbls below retainer and 5 bbls above retainer and chased with 12.0 mud push and displaced with 10.7 ppg mud system. Pick up to clean and displace per plan. Cement in place at 1500 hrs, calculated TOC once pipe is picked up above ~6040'.,POH with workstring to 5700'. Prep surface lines, break circulation to clean workstring and displace 10.7 ppg mud system to 8.7 ppg clean water system (below where CIBP will be set in preparation for future sidetrack exit).,Conduct flow check while staging and rigging up lay down machine. Conduct well control drill, shut in well. Secure location. n (LAT/LONG): evation (RKB): 50-133-10160-01-00API #: Well Name: Field: County/State: SRF SRU KGSF #1A Swanson River Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Job Name:2013214P KGSF #1A PreDrill Spud Date: p system,Displace well to 11.0pp p p g pp ppg ppg system. No issues on displacement. Weigh fluids with return of mud, 10.9 ppg in, 10.7 ppg heavy out. Monitor flow, no flow. g gp e Testing BOP t/250/2500PSI 5 min low,5 min high tested gas detector pitj level indicators w/ quadco hand q C/O 2 7/8'test joint and RIH w/3 1/2 gp ,Conduct 30 bbl 15.8 ppg cement squeeze against 7"pj cement retainer. ppp /U Alaska E-line M/U Jet cutter and test lubricator 2500 psI , RIH and cut @ 6210" POOH Pull PX plug @6312' gj y 25 bbls below retainer and 5 bbls above retainer gp p set prong in plug @ 6297'POOH and test plug w/ 1000 PSI A pg ,POH with the 3-1/2" tubing and 1/4" control line. ppgp pgqpg pp RIH with 7" cement retainer on 3-1/2" workstring. Set retainer at ~6167' with ~7' of tubing stump up for cement operation. P/U PX plug RIH and set @ 6317' found that KGSF-7 is under gas injection. 2013214P KGSF #1A PreDrill 9/9/2020 Safety meeting with crew. Emphasis on sequence of events, rigging up and testing lubricator, conducting MIT. Open to well, slight vacuum on initial opening. Break circulation to fill, immediate returns.,POH laying down 3-1/2" tubing workstring. Break off cement retainer running tool.,Clear rig floor. RU lubricator and sheave for E-Line unit. Pressure test lubricator to 250 psi for 5 minutes, attempt to bring pressure up to 2500 psi but Annular started leaking at ~1000 psi.,Make notifications, mobilize out wellhead rep and BOP rep. Develop plan forward. Yellow Jacket rep determines O-ring in seal area will need to be replaced. Wait on hanger and TWC to arrive.,Pull pump-in sub and flange. Install hanger and TWC, run-in Lockdowns. Pressure up against TWC and Blinds to ensure integrity. Well secure. 9/10/2020 Safety meeting with crew on daily goal. Emphasis on working at heights and dropped objects since crew will be changing out Annular seal.,Raise rig floor platform to clear area around Annular. Remove flanges, swap out Adapter OD Seal O-ring. Pressure test seal to 250 psi low / 2500 psi high for 30 minutes.,Reinstall rig floor and stairs. ND flange on Annular in preparation to remove tubing hanger and TWC.,Pull hanger to f loor, lay down.,Prep for rigging up wireline sheave and lubricator. Conduct pressure test against cement plug to 1600 psi for 30 minutes. Test results: Initial test pressure 1800 psi, loss in first 15 minutes 30 psi, loss in second 15 minutes 10 psi. Good test.,PT lubricator to 2500 psi. MU weight bars, Bailer onto E-Line, ~300 lbs. RIH at 330 fpm, hard tag at 5619'. Pick up, check data for proper correlation. Run back down at 250 fpm, hard tag again at 5620'. ToC at 5619'. POH. Swap out to Gamma/CCL tool above CIBP. RIH, log Gamma log from 4300-4700', send to town for confirmation of correlation; -10' correct. Log CCL, collar at 4508'. Set CIBP at 4503' E-line depth. POH.,LD wireline tools. RIH with 16 joints of 3-1/2" Kill String (~503'), install hanger and run in LDS. Secure well. 9/11/2020 PJSM on preparing for and conducting rig move. Discussion focus on pressured lines, hand injuries, lifting equipment.,Circulate fresh water through all the lines to clean them up. Flush out pits.,ND BOP, NU Dry Hole Tree with TWC. Pressure test void to 5000 psi, pull TWC. SIMOPS: Stage pumps, support equipment for loading onto trucks.,Continue with Rig Down operations for move to KDU-10, Set CIBP at 4503' E-line depth. gp p g p pg ND flange on Annular in preparation to remove tubing hanger and TWC.,Pull hanger to floor, lay down.,Prep for rigging up g wireline sheave and lubricator. Conduct pressure test against cement plug to 1600 psi for 30 minutes. gpp gg pg Run back down at 250 fpm, hard tag again at 5620' Activity Date Ops Summary 10/7/2020 PJSM Rig personnel working day light tour. Break down rig 147 in Peaks yard and take to KGSF 1A Peak hauled Pits, Gen Mods, Skate, Choke House, Sub and misc equip . Lay Herculite and matt boards on 1A. Install flow box in cellar in Peaks yard. Crane off derrick in Peak yard and prep to move.;Shut down operations till day light. 10/8/2020 Waiting on daylight.;PJSM w/ rig crews and Peak. Set remaining rig mats and containment for catwalk. Spot sub over well. Set carrier. Crane and pin derrick.;Spot water tank/doghouse. Set pits. Set landings and walkways for modules. Scope up roof tops on pits and pin same. Set landing for pump mods and set both pump mods. Start hooking up innerconnects. Scope and pin doghouse. Set boiler mod.;PJSM Stand Derrick and pin. Install inner connects. Remove roof top F/ Pit skid #3. Install mud lines. Start rigging up pits. Install brake linkage centrifuge. Stage BOP components for N/U.;PJSM Hook up air, water & steam lines F/ Sub to Koomey. Remove bump stops between Sub, Pits & water tank. Install pop off lines and safety clamps. Install steam line to pits. N/U Annular, Double Gate, lift ring & Mud Cross. (R-54) 10/9/2020 PJSM Cont. install mud cross, inside manual choke & kill, HCR choke & kill and single gate on BOP. Cut corrugated rubber hose and install F/ mud pump suction. Lay felt, Herculite and matt boards for Skate. Spot Skate and raise beaver slide. Take on Fuel. Start cutting pins F/ mud pit roof over pits.;PJSM Completed N/U of BOP flanges. R/U air compressor. Filled Eaton W/ Glycol and checked all fluids. Unpin boom line and untie all lines and cables from mast. Make up snake on drilling line and snake drill line onto drum. Spool off old drill line and finish spooling on drill line in order to be;able to scope up Derrick. Removed premix roof post for repair. Set Gas Buster, R/U Glycol coolant Fan electrical.;PJSM Install upper turnbuckles on upper torque tube. Worked on seized becket on blocks, removed pin and cleaned. Unbridle and test run blocks/ Drawworks. Bridle up and scope up Derrick in short intervals to test run clutch and brakes under weight. Scope up Derrick to inspect bridle lines for;correct length. Engaged upper dogs and set down Derrick. Scoped up and released dogs. Scoped down Derrick and installed lower turnbuckles on upper section of torque tube. Cleaned all paint F/ torque tube pin holes and test fit pins. Clear Catwalk and stage lower torque tube section.;Test fit Hydraulic spacer blocks onto topdrive FWD/ REV control lines in Sub. Modification needed.;PJSM Clean, organize tools around rig and yard. R/U to lower torque tube section. P/U lower torque tube section W/ tugger’s and pin to upper section. Scope up Derrick tailing in lower torque tube section. Engage upper dogs and set down Derrick. Finish pinning torque tube and install.;Hook up weight bucket & Geronimo line. Install flow line F/ mud box to Possum belly. 10/10/2020 Install lights and handrails on catwalk / choke house. Continue wiring in misc lights throughout rig. Install panic line, mud line from choke to gas buster. M/U stand pipe on floor. Installed bleeder manifold. Hook up power to test pump and function same. N/U choke line @ catwalk side.;N/U kill line on block flange (upper cellar). Continue rigging up Pason equipment. Set pipe racks for skate. Load 70 bbls heated water and flush water tank. Install lower tq tube "T".;Spot TDS on floor. Hang TDS. Continue to work on Top Drive install. Secure tq tube with turnbuckles. R/U lines. Slip more drilling line on drum for a total of 15 wraps @ kelly down. Load 70 more bbls of heated water to flush and test PVT system. Pason continue installing equipment.;Install 60% of windwalls on pits. Hot bolt mud line from "U" tub to pits. Wire up centrifuge.;PJSM Cont R/U top drive. Run depth encoder cable for Pason to crown and dog house. Build hydraulic jumper lines for Iron Roughneck. R/U Torque bushing. Assist Pason W/ PVT and cables. Attempt to run top drive HPU, trouble shoot. Error code 8 and no power to drillers console. M/U Kelly hose to top.;Mount and R/U doghouse camera. Stage double ball valve and bales to rig floor. Test run rig water loop back to water tank. Cont. making misc air, water and steam jumpers.;PJSM Cont making misc air, water and steam jumpers around rig. Perform full Derrick inspection. Rotate 4” stand pipe valve to clear Kelly hose. Clean and organize mechanic/ fab shop. Install upper and lower IBOP & saver sub. (Not TRQ) Remove wind wall tarps F/ cutting box.;Install Centrifuge discharge line. Install bales on top drive. Grease choke manifold. Install flange gasket on Gas Buster. Add H2O to pill pit and start moving fluid through pits checking plumbing. 10/11/2020 Continue flushing mud lines and checking surface lines w/ heated fresh water. Replace leaking valve seals and adjust Jayco valves in pits. Replace leaking packing on mix and feed pumps, test same (good). Continue R/U test pump, replace plumbing, valves.;Modify and install encoder guard on drawworks. Terminate Sperry to encoder. Install secondary restraints on low and high psi lines throughout rig. Misc welding projects on going.;Electricians and mechanic continue troubleshoot TDS issues. Continue installing restraint cables on low/high psi mud lines. Finish Pason install on rig. Tested and verified by Mike Pomplin. R/U geronimo line. Stage sub racks. Continue replacing leaking valves in pits and adjust same as needed;PJSM Check well for Press 0 PSI, slight vac. Assist Vetco Grey install TWC. N/D Tree. Clean up ring groove and prep for N/U. Checked 8 rd threads in hanger, good. Check both IA 0 PSI and OA 180 PSI. Close and move OA gauge below grating.;PJSM Lift BOP and install studs. Set BOP on well head and N/U. Install choke line Ext leg for choke line mock up. Break BOP at mud cross and single gate. Rotate 1 hole to ODS for better choke alignment. Choke line Ext is to long. Rotate back and M/U. Need choke line Ext cut down. M/U kill line.;Cont testing mix/ charge pumps, manifolds and valves for leaks in pit mods. Repair valves or seals and repair leaks as needed. P/U tools, Equip and house cleaning around rig. PT test pump to 5,000 PSI, good. Function test Iron Roughneck could not operate through console.;Electrician and mechanic timed out for top drive resume in morning.;PJSM C/O 2” camlocks on hole fill line W/ 2” FIG 200 unions. Install Stuci’s on choke and kill HCR. Install secondary safety cables on turnbuckles for Trq Tube. Install ball valve, check valve & hose on bell nipple for hole fill. Cont housekeeping around rig and pad.;Gather and fab together test manifold and lines. Install choke line F/ catwalk to choke HCR Tee. Stage 3.5" test jnt and subs on walk. 18.5 n (LAT/LONG): evation (RKB): API #: Well Name: Field: County/State: KGSF 1 Swanson River Hilcorp Energy Company Composite Report , Alaska Contractor AFE #: AFE $: Hilcorp Rig 147 Job Name: Spud Date: 10/12/2020 Cont plumbing 1” condensate in sub. Pin derrick ladder. Function FH-80 F/ pedestal. Install Jay-Co valves in pits. Cont installing safety clamps & cables on choke, kill, Gas Buster and HP mud lines. Spot Peak drill support connex. Stage BOP test subs on rig floor. Install chain and binders on Stack.;Hold Pre Spud meeting with all personnel. Discussed drilling operation, safety and orientation for BLM.;Cont trouble shooting top drive controls and HPU. Assist welder W/ misc welding projects. Reroute hydraulic lines for FH-80. Trim and install C.O.M. toggle. Work on premix pit roof posts. Trouble shoot and function winch remote. M/U 2” bleeder line to flow line. Build test manifold and mock up;brackets and placement. Cut of old top drive FWD/RVS. Cut 12” riser for flow box/ bell nipple. Install hydraulic fitting on HCR’s. Pump out water tank and clean residual oil off. Refill water tank. Remove guards from FH-80 for modifications. Cont installing seals in pits. Work on pump inventory.;PJSM M/U Koomey control lines to Stack. Cont testing pit system, need correct shear pins for pop off for pumps. Repair valve stem on DS hydraulic pump. Repair shaker wind wall roof pocket and hook for proper fit. Install bell guide and wire up bolts. Energize Koomey and function test Stack valves;and rams. Bleed off Koomey and swap lines for correct alignment. Replaced washed out 4 way grease fitting. Refunction Koomey controls for proper alignment and operation, purging air out of system. Tighten Koomey #1 charge pump plate. Readjusted all suction handles to fit new seals.;Found plumbing alignment out on Hopper #2. Needs hanging bracket to relieve excess weight. Open Ram door and inspect cavity and body prior to testing. Attach M/U tong line to load cell in Derrick. Trouble shoot wireless remote for Catwalk, found wireless receiver was not getting signal.;PJSM Cont opening ram cavities and inspection. Install 1502 stand pipe bleeder on flow line. Install wind wall tarp lower carrier under drawworks. Air up flowline and transfer line boots between pit mod 1 & 2. Install SRL at derrick board. Run Tioga heater to choke room. Cont plumbing steam system.;Trouble shoot extend frame hydraulic cylinders. Removed cylinders and could not get frame extension to retract. Cont trouble shooting. Pull pins for frame extend arms. R/U for testing BOPE. 10/13/2020 C/O linkage on TD extend frame. Shut bline rams and open up to choke manifold. Purge with air and verify line is free of obstruction. Fill stack and purge lines. Start to shell test BOPE's working up to 3500 psi. Asst Mechanic with mix pump repairs. Assist electrician with TD HPU troubleshoot.;Cont. to plumb steam.;Cont. working on topdrive extend frame arm modifications. Drain rig HPU tank and replace equalizer valves. Wellhead Rep tighten LDS due to communication between IA and BOP.;Cont. troubleshooting TD robotic functions. Hang windwalls around rig. Swap extend frame hydraulic lines, charge system and move top drive from rig floor. Cont. to attempt to test BOPE's - observe communication to IA.;Open blinds and pull 2-way check and inspect, observed debris. Install new two way check. Cont. to test attempt and test BOPE. Observe BOP control screen choke and LPR's control operating one another, choke HCR open/closed are reversed. Observe chart recorder leaking at quick connect.;Continue pre-test with Pason system. Test choke manifold, HCR kill, and blinds. Charged TD compensators, reverse extend frame hyd. lines for proper orientations. Rig up and adjust link tilt arms accordingly. Replaced McDonald valve gasket and stage boilers up. Craned windwalls for pits.;Tested pits 2, 3, 5, 6. All premix pumps good. Rebuilt premix hopper. Hung steam heater in premix pit and plumbed. Continue working on steam loop around rig.;Adjust TD hydraulic hoses and install sock on TD service loop. Continue rigging up steam loop. Tighten fittings on FH-80, hang wind wall tarps on pits. Stage screens at shakers.;Install riser. Obtain RKB's. M/U dart, TIW, XO and side entry sub to test joint. Install test joint. Cont. pre-testing BOPE. 10/14/2020 Continue to pre-test BOPE's with 3-1/2" test joint 250/5000 psi. R/D test equipment and blow down lines. Continue to bring on steam throughout the rig. Change hopper valve on hopper #3. Remove hardline on bleeder at flowline and replace with 1502 swing.;Rig up make up tongs. Put away mud pump inventory. Assist electrician and mechanic with top drive HPU. Install lube pump on mud pumps. Empty gas buster. Primed boiler chemical pump. Continue fabricating and installing steam loop.;Continue troubleshooting TD rotary issues. Check all covers and connection on mud pumps. Run mud pump lube pump, and adjust for correct output pressure. Continue testing mix and charge pumps for leaks and repair as needed. Hang tongs and adjust weight buckets. Identify leaks on accumulator;system and repair. Continue plumbing steam loop.;Troubleshoot top drive functions after hoisting blocks from rig floor. Found robotics cable to be pulling tight, reposition cable. Observed hydraulic IBOP to be clocked incorrectly. Replace with spare IBOP, and test good. Install saver sub and clamps on top drive. Relax service loops and;re-install sock and kelly hose/whip check. Adjust grabber leg as needed for proper alignment.;Check top drive functions prior to hoisting. Observe hydraulic IBOP actuator ring to be leaking. Remove saver sub clamp in preparation for repair. Cont. prepping floor equipment. Attempt to start MP 1, would not start, troubleshoot.;Check rotary table fluid and lubricate rotary chain. Re-energize accumulator and inspect for leak.;Function test liner wash, charge pumps. Start mud pump 2 and attempt to commission. Rod wash pump stopped pumping. Start mud pump 1 to commission, unable to engage from rig floor. Trouble shoot mud pumps. Remove lower turnbuckles on torque tube and align over well center.;Continue plumbing in steam heater. Install heater by test pump. Function centrifuge, feed pumps, shakers, and caustic barrel. Finish bolting down hopper 1 mix table and pump through. 10/15/2020 Adjust lower section of TD rail. Break saver sub and Hyd IBOP f/ TD and re-install rebuilt IBOP and saver sub. Test operation and IBOP worked but it wouldn't let the TD rotate while in the closed position. Electrician working on issue. Re-route service loop to keep off derrick. Trouble shoot MP;and charge pump issues. Continue plumbing in steam heaters.;Electrician found issue and Got TD IBOP Operating correctly. He also got the safety working on #1 mud pump so it wouldn't turn on when the IBOP is closed. Had to replace jumper hoses from the charge pump to the mud pumps. Still plumbing steam heaters and prepping to circ through High press lines.;Install windwall on pits in front of shakers. Set max TD TQ. Shim brake handle. Installed new cable restraint for top drive cable.;Continue to make new jumper hoses from charge pumps to mud pumps. Cont. commissioning mud pump 1, while flooding lines observed 4" demco on MP 1 leaking. Replace lower face seal, stem and body. Attempt to pump down through choke manifold with MP 1, 4" standpipe conn leaking. Continue plumbing steam;Bleed off accumulator pressure. Install pulsation dampner, recharge accumulator pressure. Pick up 3-1/2" test joint. Pre-test LPR's 250/5000 psi - good. Attempt to pre-test superchoke, manual choke - failed. Trouble shoot chokes. Test lower and upper IBOP. Continue working on steam loop. 10/16/2020 RD test equip and LD test jt. Remove super choke actuator and found damaged seals in choke. Remove manual choke and found damaged seals in it to. Got 2 rebuilt chokes from town and replaced both chokes. Remove service loop wrap and remove 37 pin service loop from derrick. Found 6 pins that had been;pulled. Electricians building new service loop. Replace 1002 rubber in standpipe. RU to circ through chokes. Bonnet on 4" standpipe valve started leaking. Working on plumbing steam heaters. Racking and strapping DP.;Replace bonnet seal on stand pipe valve. RU and circ through chokes. Test mudline, standpipe, and TD hose to 3500 psi. The 1002 union on the mud manifold started leaking again. Broke union out and cleaned and inspected same. Install new rubber in union.;Electricians finished building new service loop. Install new 37 pin service loop. Function test TD. Had rotation in connection and drill mode but didn't have any of the other functions. Electricians troubleshoot top drive. Pump through choke manifold. PT superchoke - good. Attempt to PT manual;choke - fail. PT surface lines to 3500 psi - good. Working on housekeeping and rig heating issues.;Build blowdown line and blowdown stand pipe, mudlines and choke. Disassemble manual choke, teflon missing. Cont. housekeeping and work on rig acceptance checklist.;Continue working on steam loop. Install shaker rubbers. Work on rig acceptance checklist. Clean and organize accumulator room. Fixed sink supply hose in mud pits. Cleaned choke house. Plumb fuel lines Start to source parts/manual choke. 10/17/2020 Check TD counter balance precharge. Trouble shoot TD functions w/ electricians. Remove manual choke valve and rebuild. Re-install manual choke. Use vac to suck out stack and clean off hanger. PU 3 1/2 test jt and MU test equip. Blow air through stack and choke to ensure it's clear.;Flood lines and shut annular. Perform shell test. Worked on steam and winterizing rig.;Finish doing shell test to 3500 psi. Do function test on manual choke and it held press good. Test gas alarms and PVT.;Perform BOP test with both AOGCC (Lou Laubenstien) and BLM (Allie Schoessler) reps present. [Pull TD service loop back dn while testing. Re-wire plugs and hang it back in the derrick. Got TD back on line and fully functional.] Test annular to 250 low and 2500 psi high.;Test all other BOP equip to 250 low for 5 min and 3500 psi for 10 min, on 3 1/2 test jt. No failures. Accumulator drawdown test: starting pressure 2900 psi, after drawdown 1625 psi, first 200 psi recharge in 24 seconds, full recharge 87 seconds, (4) N2 bottles at 2575 psi average;Rig down testing equpiment. Break out side entry, TIW and dart from test joint. Pull test joint. Blowdown choke, gas buster, and mud lines.;Pick up T-Bar, pull TWC.;Mount link tilt cylinder to bales. Install hyd. IBOP actuator dogs. Finish bolting up top drive front guard. Install service loop sock and whip check on gooseneck to kelly hose. Clean and organize rig floor. Sim Ops: Mix spud mud.;Continue working on rig acceptance checklist. Commission top drive, function test at multiple heights. Tightened hydraulic hose fitting on frame extend. Observe float function not operational, trouble shoot and change out contact block on top drive control panel - good. Calibrate MWD encoder.;Set crown saver, 15' from top of blocks to bottom of bumper blocks. Rig accepted at 03:30;Rig up to pull tubing. Gather 3-1/2" handling equipment. Rig up Weatherford Power Tongs. Install landing joint. BOLDS. Pull hanger to rig floor, offseat at 15K (10K block Wt), PUW 15K. 10/18/2020 LD hanger and 3 1/2 landing jt. POH LD 16 jts of 3 1/2 tbg kill string. RD Weatherford equip.;RU to test BOPs. Test annular to 250 and 2500 psi, and test upper and lower pipe rams to 250 and 3500 psi w/ 4 1/2 test jt. 5 min low & 10 min high. RU 2 7/8 test jt and attempt to test from both sides due to jt not having a hole in it. LD test jt and when we did the skate functions started failing.;KR valve on annular started leaking by. Mech troubleshooting. Have electrician working on skate rig floor controls and Hands drilling hole in test jt. Also found keeper holder for dye on iron roughneck had broken.;Had welder come out and repair the iron roughneck. Electrician and mech still trouble shooting pipe skate issues. Noticed bad spoits in the drilling line. Have people looking for new KR valve.;Cut and slip drill line. Cut 963' to remove damaged line. Mechanic and Electrician resolved pipe skate issues.;Pason tech and Electrician troubleshooting rotary and torque issues with Pason. Calibrate block heights and depth with Pason. Pason tech troubleshooting power choke actuator settings.;Pason tech and driller troubleshooting power choke actuator settings and rotary torque issues.;Make up window milling / cleanout assembly per Baker fishing rep.;Run in the hole with window milling / cleanout assembly, picking up 4-1/2" drill pipe to 790'. Make up new pipe connections per recommended practice. 10/19/2020 RIH w/ clean our assem PU 4 1/2 DP t/ 1601. Using Hilcorp maintenance & care procedures for CDS 40 DP.;Elevator horns are rubbing on lower section of TD rail. Shut dn and adjust TD rail.;Continue RIH to 2833'. Encoder for Pason on the drwks came loose and winch on pipe skate got fouled.;Work on Pason encoder. Shaker bolts came loose and had to be re-torqued. Got cable on pipe skate winch.;Screw into pipe to circ and found out grabber dies are to thin so we cant make the TD up to torque specs. Made it up enough to circ and circ DP vol.;Work on encoders and got them working good. Pason and the electricians got the torque gauge working but they were still working on the RPMs. Crew working on lining up TD rail. Still not perfect but better than it was.;RIH with mill clean out assembly PU 4 1/2 CDS 40 DP Using Hilcorp maintenance & care procedures . Tag CIBP at 4507' MD. Set down 17K to verify plug per Baker.;CBU at 220 gpm, 365 psi. Pump 30 bbl High-Vis sweep at 250 gpm, 590 psi to cleanout pipe scale from hole. Monitor well for 10 min - static.;RU to test 7" casing. Verify lineup and fluid pack lines.;PT 7" casing to 1600 psi for 30 charted min. Stage up from 700 psi to 1650 psi in ~200 psi increments. Good test, lost <10 psi over 30 min. Pump 1.1 bbls / bled back 1.1 bbls.;Blow down and RD test equipment.;TOH with clean out assembly to 4400' 10/20/2020 Continue to TOH with cleanout assembly and lay down mills. No losses for trip.;MU Johnny Wacker and pick up 4-1/2" DP to 1781' using Hilcorp maintenance & care procedures for CDS 40 DP.;Change fuel filters and troubleshoot sluggish engine. Grease and inspect fluid levels on Drawworks, TD, Blocks, Crown, Driveshafts and Brake linkages. Pason install and calibrate Rotary Proximity sensor on TD.;Peak mechanic perform computer diagnostics on floor motor, indication of faulty injector. Mechanic replaced injector and found issue in wiring harness. Install Teflon bushing on torque bushing plate for extend frame rest. Insulate catwalk choke line.;Continue to pick up 4-1/2" DP to 3026' using Hilcorp maintenance & care procedures for CDS 40 DP.;POOH and rack back 38 stands.;Remove and replace leaking KR valve on accumulator with new rebuild. Energize Accumulator and function test KR valve from Accumulator and remote panel on rig floor.;MU Baker Whipstock and verify 3 shear screws in Trip Anchor and 35K shear bolt from mills to slide. RIH to 800'. 10/21/2020 Continue to TIH with Whipstock conveyed on 4 ½” DP out of Derrick f/1241’ to top of CIBP at 4507’. Set Whipstock on depth per Baker Rep with no issues.;Commission mud pumps individually and combined for pump rate comparison and efficiency, checking all lube pressures and such staging each pump to 300 gpm. No issues with mud pumps.;Hold PJSM. Pump 25 bbls hi vis sweep and displace well to 10.4 ppg 6% KCL/EZ Mud Drilling fluid at 295 gpm, 910 psi. Obtain SPR.;Mill 7” csg window per Baker at 300 gpm, 1010 psi, 90 rpm, 1-3 Klbs WOB, PU 67 Klbs, SO 68 Klbs, ROT 68 Klbs. No issues milling. TOW: 4489’, BOW: 4502’.;Drill/mill rathole from 4502' to 4525'310 gpm, 1010 psi, 90 rpm, 4-8 Kft-lbs torque and 5-8 klbs WOB. Drift window w/ and w/o pumps and rotation – clean.;Flush metal shavings from mud cross. Pump 20 bbl hi vis sweep and circulate hole clean prior to FIT. Pull up to 4474' and lay down working joint. Metal recovered on magnets: day 65 lbs, total 65 lbs.;Hold PJSM. Fluid pack lines and rig up and perform FIT. to 12.6 ppg EMW. Pressure up to 526 psi with test pump. 4489' MD/TVD, 10.35 ppg MW, pump 19 gal, bled back 18 gal. Blow down test equipment.;Monitor well for 10 min prior to pulling - static. Pull 2 stds - no swabbing. POOH to 4230' w/ hole fill. Good fill. Pump dry job and blow down TD and kill line. Continue POOH with mill ing assy to 2000'. KaSF ±"( Regg, James B (CED) From: Robert O'Neal - (C) <roneal@hilcorp.com> r Sent: Thursday, September 10, 2020 1:01 PM E , �t loo To: Mike Quick; Bixby, Brian D (CED); Regg, James B (CED) Subject: PT against plug, KGSF-1 Attachments: IMG_5546.jpg; ATT00001.txt 0 Attached is the pressure test chart against the cement plug in well KGSF-1. Rob Q<(-�(A�- The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. 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/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 10,875'±6,507 (TCP Guns) Casing Collapse Structural Conductor Surface Unknown Intermediate Production 3,830psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Mike Quick Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: August 28, 2020 3-1/2" 10,875' Perforation Depth MD (ft): See Attached Schematic 10,875' 10,875'7" 20" 11-3/4" 31' 2,032'Unknown 31' 2,032' 31' 2,032' 9.3# / L-80 TVD Burst 6,365' 6,340psi MDLength Size SIO - 2A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028399 161-008 50-133-10160-00-00 Swanson River KGSF 1 Swanson River / 64-5 Tyonek Gas Storage, Hemlock Oil, Tyonek Gas COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic mquick@hilcorp.com 10,875'6,507'6,507'1,311 psi N/A Baker Premier Pkr; N/A 6,244' MD/ 6,243' TVD; N/A, N/A Perforation Depth TVD (ft): Tubing Size: Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:23 am, Aug 24, 2020 320-357 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.08.22 15:23:48 -08'00' Taylor Wellman 10-407 (post sidetrack) Plug for Redrill DSR-8/24/2020 X DLB 08/24/2020 X gls 8/25/20 gls * 2500 psi BOPE test Type text here Comm 8/26/2020 dts 8/25/2020 JLC 8/26/2020 RBDMS HEW 8/28/2020 Well Prognosis Well: KGSF #1 Date: 08/20/2020 Well Name: KGSF #1 API Number: 50-133-10160-00 Current Status: Shut-In Gas Storage Well Leg: N/A Estimated Start Date: August 28, 2020 Rig: 401 Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 161-008 First Call Engineer: Michael Quick (907) 777-8442 (O) (907) 317-2969 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number: Current Bottom Hole Pressure: ~ 1,950 psi @ 6,387’ TVD (Based upon Estimated Bottom hole Storage Press. Max. Potential Surface Pressure: ~ 1,311 psi (Based upon Max. Expected BHP minus 0.1 PSI/ft. gas gradient to surface Brief Well Summary: KGSF # 1 is a gas storage well that that Hilcorp was flowing between 4 and 6 MMscfd this past January. On January 25, 2020 the well suddenly quit producing gas. A slickline tag found fill at 6,361’ (19 ft above the top perforation). In February of 2020 a coil tubing cleanout was performed. The well was cleaned out and blown dry to 6,493’. The well was opened and bled down to 576 psi, when the well reached 100% methane. The well was then SI and a buildup performed whereby the well gained 524 psi (to 1,100 psi.) in 6.5 hours. Slickline found a fluid level at 5,850’ and fill was tagged @ 6,388’. This indicates that water and fill are coming into the well (105’ of fill and 20.5 bbls of water). It is believed that this well has broken down to a channel behind casing. The purpose of this Sundry is to prepare the well for a rotary sidetrack by pulling the tubing, plugging the open perforations, and setting a CIBP for the kick off whipstock to be set on. Known Well Condition: x Fluid Level ~ 5,850’ (SLM) x Top of Fill ~ 6,388’ (SLM) PreRig Work 1. MIRU slickline, pressure test lubricator to 2,500 psi. 2. RIH and set retrievable PX plug in X nipple at 6,297’. 3. RD slickline. Rig 401 4. MIRU workover rig 401. 5. Notify AOGCC 24 hours in advance for witness of BOP test. 6. Lube and bleed lease water or similar fluid into the tubing string. 7. Set back pressure valve. 8. ND wellhead, NU 11” BOP stack and test to 250 psi low & 2,500 psi high, annular to 250 psi low & 2,000 psi high. Record accumulator pre-charge pressures and chart tests. pressure test PX plug to 500 psi.(15 min) set PX plug .23 psi /ft The purpose of this Sundry is to prepare the well for a rotary sidetrack by pulling the tubing, plugging the open perforations, and setting a CIBP for the kick off whipstock to be set on. BOPE test 2500 psi BPV Well Prognosis Well: KGSF #1 Date: 08/20/2020 a. Perform Test. b. Test VBR rams on 3-1/2” and 2-7/8” test joints. c. Pull BPV. d. Submit completed form 10-424 to AOGCC within 5 days of BOPE test. 9. Unseat hanger and hold tubing in tension. Be prepared to pump down back side if needed. 10. MIRU Slickline. Pressure test Lubricator to 2,500 psi. 11. RIH and pull PX plug from X Nipple at 6,297’. RDMO Slickline. 12. MIRU E-line. Pressure test Lubricator to 2,500 psi. 13. PU, RIH with tubing cutter. 14. Cut 3-1/2” tubing mid joint at +/- 6,200’. 15. RDMO E-line. 16. Pull hanger to floor. Lay down same. 17. Ensure well is static. Pump lease water or 8.4 ppg KCl brine as needed to maintain fluid level. 18. POOH With 3-1/2” tubing sideways while spooling up ¼” control line. Lay down tubing. 19. Notify AOGCC 24 hours in advance of pumping cement to witness plugging operations per 20 AAC 25.112 (h). 20. Pick up 7” cement retainer on 2-7/8” workstring and RIH. 21. Set 7” cement retainer at +/-6,175’. 22. Perform injectivity test to ensure cement will be able to be squeezed below retainer. Contingency: If adequate injection rate of at least 1.5 bbl/min at less than 2,000 psi is not reached, no cement will be squeezed below retainer, and a minimum of 75’ of cement will be placed on top of cement retainer per 20 AAC 25.112 (c)(1)(E). 23. Mix and pump 15 bbls of 15.8 ppg class G cement, squeeze 10 bbls of cement below the retainer (do not exceed 2,500 psi surface squeeze pressure), unsting from retainer and spot remaining 5 bbls of cement on top of retainer (minimum of 75’ per 20 AAC 25.112 (c)(1)(E)). 24. Pull up out of cement at least 300 ft and circulate pipe clean. 25. POOH, L/D workstring. 26. Pressure test 7” casing and plug to 1,600 psi for 30 minutes, chart test. (per 20 AAC 25.112 (g)(2) TOC at 6045’ x 0.25 psi/ft = 1,512 psi pressure test) 27. MIRU E-line. Pressure test Lubricator to 2,500 psi. 28. RIH and tag Top of Cement at +/-6,045’. 29. PU and RIH with 7” CIBP, log on depth with CCL and set 5’ above a casing collar at +/- 4,500’. This will be the base for the whipstock needed to sidetrack the well. 30. RDMO E-line. 31. Install Dry Hole tree and RDMO location. Attachments: Current Schematic Proposed Schematic Rig BOP Schematic RWO Sundry Revision Change Form Retainer @6175' cut tubing (forward chart to AOGCC) MIT plug Pressure test 7” casing and plug to 1,600 psi for 30 minutes, chart test. (f O CIBP @4500ft Updated by DMA 02-06-20 SCHEMATIC Swanson River Field Well: KGSF #1 / PTD 161-008 API: 50-133-10160-00-00 Last Completed: 09-09-11 PBTD = 6,813’ TD = 10,875’ MAX HOLE ANGLE = 1.25° @ 4,565’ RKB = 15’ CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20” - - - 15’ 31’ 11-3/4” 47 - - 11.00 Surface 2,032’ 7” 29 N-80 BTC 6.184 Surface 243’ 7” 26 N-80 BTC 6.276 243’ 883’ 7” 23 N-80 BTC 6.366 883’ 4,626’ 7” 26 N-80 BTC 6.276 4,626’ 6,470’ 7” 29 N-80 BTC 6.184 6,470’ 8,315’ 7” 29 P-110 8RD 6.184 8,315’ 10,875’ Tubing 3-1/2” 9.3 L-80 Hydril 503 2.992 Surface 6,356’ JEWELRY DETAIL NO. Depth ID OD Item 1 2,460’ 2.867” 5.020” Chemical Inj Sub w ¼” control line 2 6,228’ 2.813” 4.540” Sliding Sleeve 3 6,244’ 2.870” 5.983” Baker Premier Packer 4 6,297’ 2.813” 3.940” X Nipple 5 6,356’ 2.992” 3.500” WLEG, Auto Release 6 ±6,507’ - 4.630” TCP Guns (length 32.76’) Gun release not verified ¼” SS control line w/ 41 tubing clamps (one every other joint) Clamp O.D. 4.76” PERFORATION HISTORY (Tyonek Perfs TDT Log Depth) Interval Accum. Date Zone Top Btm Amt spf Comments 9/8/2011 64-5 6,380'6,388'8'5 Reperf 4-5/8" Millenium TCP guns, 5spf, 60 deg 12/3/1998 64-5 6,380'6,388'8'4 1-11/16" Pivot, 180 deg. 7/26/1998 68-0 6,883'6,911'28'4 Abandoned 6/20/1961 - 10,615' 10,616' 1' 5 Abandoned 6/21/1961 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/1961 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/1961 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/1961 - 10,752' 10,754' 2' 5 Abandoned J D K F G H I Notes NO. Depth Item K 7,114’ 7” Stage Collar ABANDONMENT DETAIL NO. Depth ID OD Item A 6,615’ - - EZ Squeeze Packer w/ 75’ cement on top B 6,652’ - - Fish: 2 Baker K-1 Retainers C 6,850’ - - PosiSet Plug w/ 37’ Cement D 9,015’ - - Tubing cut at 9,015’ WLM. E 9,733’ - - Top of Cement Plug. Pressure tested to 2,500 psi. F 10,473’ - - Camco “MM” Mandrel with CEV Valve G 10,519’ - - Brown CC Safety Joint H 10,530’ - - Brown, 2-7/8” x 7”, Type HS-16-1 Packer I 10,600’ - - Camco “D” Nipple J ? - - Venturi Shoe D E C TOC @ 9,100’ TOC @ 6,813’ 1 2 5 6 TOC @ 3,675’ 11-3/4” 4 Top of fill @ 6,655’ 3 A TOC @ 6,540’ B 64-5 Fill tagged at 6388’ set PX plug cut tubing Updated by MJQ 8-21-20 PROPOSED SCHEMATIC Swanson River Field Well: KGSF #1 / PTD 161-008 API: 50-133-10160-00-00 Last Completed: 09-09-11 PBTD = 6,813’ TD = 10,875’ MAX HOLE ANGLE = 1.25° @ 4,565’ RKB = 15’ CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20” - - - 15’ 31’ 11-3/4” 47 - - 11.00 Surface 2,032’ 7” 29 N-80 BTC 6.184 Surface 243’ 7” 26 N-80 BTC 6.276 243’ 883’ 7” 23 N-80 BTC 6.366 883’ 4,626’ 7” 26 N-80 BTC 6.276 4,626’ 6,470’ 7” 29 N-80 BTC 6.184 6,470’ 8,315’ 7” 29 P-110 8RD 6.184 8,315’ 10,875’ Tubing 3-1/2” 9.3 L-80 Hydril 503 2.992 Surface 6,356’ JEWELRY DETAIL NO. Depth ID OD Item 1 2 6,228’ 2.813” 4.540” Sliding Sleeve 3 6,244’ 2.870” 5.983” Baker Premier Packer 4 6,297’ 2.813” 3.940” X Nipple 5 6,356’ 2.992” 3.500” WLEG, Auto Release 6 ±6,507’ - 4.630” TCP Guns (length 32.76’) Gun release not verified ¼” SS control line w/ 41 tubing clamps (one every other joint) Clamp O.D. 4.76” PERFORATION HISTORY (Tyonek Perfs TDT Log Depth) Interval Accum. Date Zone Top Btm Amt spf Comments 9/8/2011 64-5 6,380'6,388'8'5 Reperf 4-5/8" Millenium TCP guns, 5spf, 60 deg 12/3/1998 64-5 6,380'6,388'8'4 1-11/16" Pivot, 180 deg. 7/26/1998 68-0 6,883'6,911'28'4 Abandoned 6/20/1961 - 10,615' 10,616' 1' 5 Abandoned 6/21/1961 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/1961 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/1961 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/1961 - 10,752' 10,754' 2' 5 Abandoned J D K F G H I Notes NO. Depth Item K 7,114’ 7” Stage Collar ABANDONMENT DETAIL NO. Depth ID OD Item A 6,615’ - - EZ Squeeze Packer w/ 75’ cement on top B 6,652’ - - Fish: 2 Baker K-1 Retainers C 6,850’ - - PosiSet Plug w/ 37’ Cement D 9,015’ - - Tubing cut at 9,015’ WLM. E 9,733’ - - Top of Cement Plug. Pressure tested to 2,500 psi. F 10,473’ - - Camco “MM” Mandrel with CEV Valve G 10,519’ - - Brown CC Safety Joint H 10,530’ - - Brown, 2-7/8” x 7”, Type HS-16-1 Packer I 10,600’ - - Camco “D” Nipple J ? - - Venturi Shoe D E C TOC @ 9,100’ TOC @ 6,813’ 2 5 6 TOC @ 3,675’ 11-3/4” 4 Top of fill @ 6,655’ 3 A TOC @ 6,540’ B 64-5 CIBP @ +/- 4500’ Retainer @ +/- 6175, 10 bbl cement below, 5 bbl cement on top 3-1/2” tubing cut at +/- 6200’ Fill tagged at 6388’ MIT casing to 1600 psi The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 11" Spherical Annular Height: 42" 11" LWS Double BOP 2-7/8" to 5" Multirams top Blind rams bottom Height:33" 11" Mud Cross W/ 4-1/16" Outlets Dual 2-1/16" Manual Gate Valves W/ DSA to 4-1/16" Width to flange: 34" 2-1/16" Manual Gate Valve & 2-1/16" HCR W/ DSA to 4- 1/16" Full Mud Cross Assy. width w/ valves installed Width: 96" Kill side Choke side BOP Stack Width: 96" @ valves Height Addition for Ring Gaskets: .75" BOP Total Height: 101.75" 11" 5m BOP Package W/ 2-1/16" Valves Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well KGSF 1 (PTD 161-008) Sundry #: XXX-XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date 1 Carlisle, Samantha J (CED) From:Mike Quick <mquick@hilcorp.com> Sent:Monday, August 24, 2020 3:21 PM To:Schwartz, Guy L (CED) Cc:Ted Kramer; Donna Ambruz Subject:RE: [EXTERNAL] RE: KGSF 1 (PTD161-008) HelloGuy– Followinguponourdiscussiontoday; x Thewellwillnotholdacolumnoffluid,wecannotfluidpackthetubing,thePXplugisjusttominimizetherisk ofgasbubblesbelowtheBPVthatcantakesometimetobleedoffbeforepulling. x Wemissedmarkingthewellassuspended,apologiesforthatone. x OnthepreͲrigkill,againbecausewewillnotgetafullcolumnbacktosurface,wewillknowthatweare pumpingawaybutdetermininganaccurateinjectionratewillbedifficult.Weplantoattempttocement squeeze,butwantedthecontingencyjustincaseitdoesnottakefluid. PleaseletmeknowifImissedsomething,orifyouwouldliketodiscussfurther. Thanksforyourtime, Mike From:Schwartz,GuyL(CED)[mailto:guy.schwartz@alaska.gov] Sent:Monday,August24,20202:43PM To:MikeQuick<mquick@hilcorp.com> Cc:TedKramer<tkramer@hilcorp.com> Subject:[EXTERNAL]RE:KGSF1(PTD161Ͳ008) OhandthepreͲrigkillcouldgiveyouanideaofyourinjectionratefortheupcomingcementplugthroughtheretainer. GuySchwartz Sr.PetroleumEngineer AOGCC 907Ͳ301Ͳ4533cell 907Ͳ793Ͳ1226office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From:Schwartz,GuyL(CED) Sent:Monday,August24,20202:39PM To:MichaelQuick<mquick@hilcorp.com> Cc:TedKramer<tkramer@hilcorp.com> Subject:KGSF1(PTD161Ͳ008) Mike, 2 Iamlookingthesundry320Ͳ357toplugbackthiswellforredrill/sidetrack. 1) Iamalittleconfusedontherigprepforthiswell.WhysetthePXplugifyouareonlygoingtopullitbefore cuttingthetubing?WhynothavethepreͲrigworkincludekillingthewellbyfloodingthetubingandthenhave SLopentheSSandcircaround.ThensetaTWC/BPVtorigupBOPE.Thegradientisonly.23psi/ft(you couldalsocutthetubingpreͲrigalthoughnotintension). 2) Thewellstatusshouldbe“suspended”ifyoupreppingforarigsidetrack. Regards, GuySchwartz Sr.PetroleumEngineer AOGCC 907Ͳ301Ͳ4533cell 907Ͳ793Ͳ1226office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: CTCO, N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10,875 feet N/A feet true vertical 10,875 feet ±6,507 (TCP Guns)feet Effective Depth measured 6,507 feet 6,244 feet true vertical 6,507 feet 6,243 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3#/L-80 6,365' MD 6,365' TVD Baker Premier Pkr; 6,244' MD 6,243' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 Unknown 3,830psi 2. Operator Name:Hilcorp Alaska, LLC tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 6,340psi 31' 2,032' 10,875' Collapse Unknown Casing Structural 20" 11-3/4" Length 31' 2,032' 10,875' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 1,350 Casing Pressure Liner 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-071 1,444 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 40 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 161-008 50-133-10160-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 0 Representative Daily Average Production or Injection Data 100 Swanson River KGSF 1 N/A FEDA028399 Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Swanson River / 64-5 Tyonek Gas Storage, Hemlock Oil, Tyonek GasN/A measured TVD Tubing Pressure 0 Oil-Bbl measured true vertical Packer 7"10,875' WINJ WAG 0 Water-Bbl MD 31' 2,032' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.04.16 09:30:58 -08'00' Taylor Wellman By Samantha Carlisle at 10:04 am, Apr 16, 2020 DSR-4/16/2020gls 4/17/20 CTCO, N2 SFD 4/23/2020RBDMS HEW 4/16/2020 Rig Start Date End Date 2/24/20 3/26/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SRU KGSF #1 50-133-10160-00-00 161-008 02/24/2020 - Monday PTW, JSA with SLB coil, Cruz construction, and HAK well site supervisor. Temp -12. Fire up SLB equipment. Lay pit liner, Move in Rig up SLB CTU unit dressed with 1.75" CT. Cruz crane. Remove snow from Methanol tank loading dock. Load and mix 20 bbls of 60/40 methanol water onto SLB pump truck displacement tanks. Remove well house to edge of location. 4-1/16" BOPE stack installed on tree. Grease lower master, upper master and swab valve. BOPE test SLB 4- 1/16" stack dressed with 1.75" blind/shear rams and 1.75" pipe slip rams. Fluid pack to return tank and BOPE night cap. Pressure test all rams and valves to 250/3,500 psi. Actual high PT was at 4K due to low volume and unable to catch a 3,500 psi PT. BOPE test complete. Fuel SLB equipment. Location walk around completed. SDFN. Daily Operations: PTW, JSA with SLB coil crew, cruz crane operator , cruz vac truck and Hilcorp rep. Fire equipment. Pick injector head. Stab 10' of lubricator. Make up BHA on 1.75" CT. 1.75" coil connector, 1.75" DFCV, 1.75" stinger, 2.25" Jet swirl nozzle. Stab on well. PT stack 250/3,500 psi. Bleed down. Open well. WHP 2,016 psi, IA 50 psi. RIH. Perform weight checks every 2,000'. Last well bore entry Slick line found fluid level at 4,900' to 4,980' and bailed to 6,170'. Cool down N2 and mix 10 bbl gel sweep. Tagged with CTMD at 6,146'. PU to tubing tail. PT N2 lines 250/3,500 psi.Online with N2 down coil at 1,000 scf/min. Crack choke and bleed WHP down from 2,042 psi to 450 psi. RIH and tag 6,146' solid tag. Slowly PU and POOH until fluid or N2 returns seen at surface. 3 bbls of dirty fluid to surface followed by 5 bbls of methanol from CT fluid spear. Start pumping fluid at .7 bbls/min. drop N2 rate to 700 scf/min. 19 minutes to fluid at nozzle. Start washing sand from 6,156' pump 3 bbl gel sweep. set down 3k 6,262'. Pick up and ran past tag depth without weight stack. Cleaned out to 6,493' and tagged fish. 7 bbl gel sweep pumped to nozzle with CT at 6,493'. Chase up hole and park CT at tubing tail. dirty sand returned to surface. Gel at surface. Well bore fluids cleaning up. Shut down fluid pump. Increase N2 rate to 1,100 scf/min. WHP 702 psi., 2,919 circ pressure, Blow well dry from 6,493'. Only N2 at surface. Close choke and attempt injection test at 2,300 scf/min in attempts to mimic last gas injection at 4 MCFD at 2,825 psi injection pressure. 2,300 scf/min at 1870 psi. N2 pump loosing prime. Out of N2. POOH to surface. 3,152 gallons of N2 pumped. 110 bbls pumped return strap 137 bbls. 27 bbls returned from well bore for entire job. Tagged up at surface. Close swab 1,830 psi SITP. Rig down CT. Leave BOPE stack, return iron to choke skid and return tank. Will attempt to flow well in the AM. 02/26/2020 - Wednesday 02/25/2020 - Tuesday PTW, JSA with SLB Coil crews, Cruz crane op and vac truck, and Hilcorp Rep. Fire equipment. Cruz vac truck load 185 bbls of produced water in supply tank. Air liquid on location to transfer 3,000 gallons of N2. Pick injector head. Make up roll on coil connector to 1.75" x .109 wall CT. Make up 1.75" DFCV, Stinger, and 2.125" jet swirl nozzle. Stab on well. Prep for BOPE test. Stripper/Pack off pressure will not increase above 1000 psi. SLB performing function tests on Pack of hydraulic circuit. Injector head pack off was changed out prior to this job with a slope replacement. Previous pack off assembly was due for annual inspection. Dispatched SLB mechanic to location with back up Haskel pump for pack off circuit. Pack off system tested and in working order. Wellhead secure. SDFN. Stripper/Pack off pressure will not increase above 1000 psi. Actual high PT was at 4K due to low volume and unable to catch a 3,500 psi PT. BOPE test complete. F Rig Start Date End Date 2/24/20 3/26/20 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SRU KGSF #1 50-133-10160-00-00 161-008 Daily Operations: 03/26/2020 - Thursday Discussed Well with Reservoir Engineer. Decided to not perform another coil cleanout at this time. Close Sundry. 02/27/2020 - Thursday Install calibrated digital gauge between choke and wellhead. Line up to return tank. Open well. Initial WHP 1,560 psi. (previous day N2 cap let SITP 1,850 psi) Start flowing well with choke cracked. 716 psi after 1 hr. 651 psi start getting some Gas readings on meter. 100 % gas at meter tubing pressure 576 psi. Shut in well to watch for buildup. 10:12 pressure built to 753 psi, 10:23 pressure up to 830 psi. SLB on location to rig down. Shut in well at 11:30 pressure is 1,000 psi. Rig down SLB equipment and park at edge of pad. Pick up pit liner and berms. Open well up to gauge. WHP 1,100 psi. Plan forward is to Run slick line to check for fluid level and tag. Updated by DMA 02-06-20 SCHEMATIC Swanson River Field Well: KGSF #1 / PTD 161-008 API: 50-133-10160-00-00 Last Completed: 09-09-11 PBTD = 6,813’ TD = 10,875’ MAX HOLE ANGLE = 1.25° @ 4,565’ RKB = 15’ CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20” - - - 15’ 31’ 11-3/4” 47 - - 11.00 Surface 2,032’ 7” 29 N-80 BTC 6.184 Surface 243’ 7” 26 N-80 BTC 6.276 243’ 883’ 7” 23 N-80 BTC 6.366 883’ 4,626’ 7” 26 N-80 BTC 6.276 4,626’ 6,470’ 7” 29 N-80 BTC 6.184 6,470’ 8,315’ 7” 29 P-110 8RD 6.184 8,315’ 10,875’ Tubing 3-1/2” 9.3 L-80 Hydril 503 2.992 Surface 6,356’ JEWELRY DETAIL NO. Depth ID OD Item 1 2,460’ 2.867” 5.020” Chemical Inj Sub w ¼” control line 2 6,228’ 2.813” 4.540” Sliding Sleeve 3 6,244’ 2.870” 5.983” Baker Premier Packer 4 6,297’ 2.813” 3.940” X Nipple 5 6,356’ 2.992” 3.500” WLEG, Auto Release 6 ±6,507’ - 4.630” TCP Guns (length 32.76’) Gun release not verified ¼” SS control line w/ 41 tubing clamps (one every other joint) Clamp O.D. 4.76” PERFORATION HISTORY (Tyonek Perfs TDT Log Depth) Interval Accum. Date Zone Top Btm Amt spf Comments 9/8/2011 64-5 6,380' 6,388' 8' 5 Reperf 4-5/8" Millenium TCP guns, 5spf, 60 deg 12/3/1998 64-5 6,380' 6,388' 8' 4 1-11/16" Pivot, 180 deg. 7/26/1998 68-0 6,883' 6,911' 28' 4 Abandoned 6/20/1961 - 10,615' 10,616' 1' 5 Abandoned 6/21/1961 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/1961 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/1961 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/1961 - 10,752' 10,754' 2' 5 Abandoned J D K F G H I Notes NO. Depth Item K 7,114’ 7” Stage Collar ABANDONMENT DETAIL NO. Depth ID OD Item A 6,615’ - - EZ Squeeze Packer w/ 75’ cement on top B 6,652’ - - Fish: 2 Baker K-1 Retainers C 6,850’ - - PosiSet Plug w/ 37’ Cement D 9,015’ - - Tubing cut at 9,015’ WLM. E 9,733’ - - Top of Cement Plug. Pressure tested to 2,500 psi. F 10,473’ - - Camco “MM” Mandrel with CEV Valve G 10,519’ - - Brown CC Safety Joint H 10,530’ - - Brown, 2-7/8” x 7”, Type HS-16-1 Packer I 10,600’ - - Camco “D” Nipple J ? - - Venturi Shoe D E C TOC @ 9,100’ TOC @ 6,813’ 1 2 5 6 TOC @ 3,675’ 11-3/4” 4 Top of fill @ 6,655’ 3 A TOC @ 6,540’ B 64-5 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Taylor Wellman Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www. oogcc. a laska. gov Re: Swanson River Field, 64-5 Tyonek Gas Storage, Hemlock Oil and Tyonek Gas Pools, Swanson River KGSF 1 Permit to Drill Number: 161-008 Sundry Number: 320-071 Dear Mr. Wellman: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, J e rice r DATED this 1�3 day of February, 2020. RBDMS�✓EEB 1 12020 RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION FEB 0 7 2020 APPLICATION FOR SUNDRY APPROVALS OTS Z//o/Zv 20 AAC 25.280 ^ n a (** (''� 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ ," `I!IpKt1Ws shutdown LJ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: CTCO, N2 ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑ Stratigraphic ❑ Service Q , 161-008 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-10160-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? SIO - 2A ❑ ❑Q Swanson River KGSF 1 Will planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028399 Swanson River / 64-5 Tyonek Gas Storage, Hemlock Oil, Tyonek Gas 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 10,875' 10,875' ' 6,507' 6,50T -2,745 psi N/A ±6,507 (TCP Guns) Casing Length Size MD TVD Burst Collapse Structural Conductor 31' 20" 31' 31' Surface 2,032' 11-3/4" 2,032' 2,032' Unknown Unknown Intermediate Production 10,875' 7" 10,875' 10,875' 6,340psi 3,830psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic I See Attached Schematic 3-1/2" 9.3# / L-80 6,365' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker Premier Pkr; N/A 6,244' MO/ 6,243' TVD; N/A, N/A 12, Attachments: Proposal Summary Q 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: February 20, 2020 OIL ❑ WINJ ❑ WDSPL Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑✓ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Taylor Wellman 777-8449 Contact Name: Ted Kramer Authorized Title, Operations Manager Contact Email:tkramer hilcoro.com Contact Phone: 777-8420 Authorized Signature: ./ Date: COMMIS&ION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: 3500 /0,5, /%n Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMSWA"1FEB 1 12010 L.� Spacing Exception Required? Yes ❑ No Subsequent Form Required: I I Q APPROVED BY Date: Approved by: COMMISSIONER THE COMMISSION a—IO-20 29Z� eg a- Ty `` } annlieafion is Osli� fo 2 I.Q. e to )d Submit Form antl pr.Val. Attachments in Duolicate [r 0 Hi1wra Alaska, Lb Well Prognosis Well: KGSF #1 Date: 02/06/2020 Well Name: KGSF #1 API Number: 50-133-10160-00 Current Status: Shut -In Gas Storage Well Leg: N/A Estimated Start Date: February 20, 2020 Rig: CTU Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 161-008 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (M) AFE Number: Current Bottom Hole Pressure: - 3,383 psi @ 6,387' TVD (Based upon 11-24-19 SI Press. And 0.1 psi/ft. Gradient to Bottom Perf) Maximum Expected BHP: - 3,383 psi @ 6,387' TVD (Based upon 11-24-19 SI Surf Press.and 0.1 psi/ft. Gradient to Bottom Perf) Max. Potential Surface Pressure: - 2,745 psi (Based upon SI Surface Tubing Pres 11-24-2019) Brief Well Summary: 1 �{ µ a, KGSF # 1 is a gas storage well that that Hilcorp was flowing between 4 and 6 MMscfd this past January. On January 25, 2020 the well suddenly quit producing gas. A slickline tag found fill at 6,361' (19 ft above the top perforation). Fill was bailed to 6,373' and became hard packed which stopped progress. After attempting to flow over night to loosen up the hard packed fill, fill was then tagged at 6,265' (108' higher than original tag). The purpose of this Sundry is to rig up coil tubing and RIH cleaning out fill to below the perforations. The well will then be jetted dry with nitrogen and placed back on production. .i Coiled Tubing Unit: 1. MIRU coiled tubing unit (CTU) onto the 3-1/2" tubing string. Pressure test BOPE to 250 psi low / 3,500 psi high. 2. RU Nitrogen pump. 3. RIH with 1.75" Coil with a jet nozzle and wash hard packed fill out of well down to 6,470'. j Note: Nitrogen will need to be used to lift well. —� A e u 14, /0 Z Sof . �� ✓a Note: There is a 32.76' fish (dropped TCP Guns) in the well below the perforations. 4. Blow well dry with Nitrogen and POOH with coil tubing. 5. RDMO Coil unit. 6. Turn well over to production. Attachments: Actual Schematic Coil BOPE Schematic Standard Nitrogen Use Procedure RWO Sundry Revision Change Form Swanson River Field SCHEMATIC Well: K1/PTD 161-008 API: 50-13-13 3--10160-00-00 Hncoru Alaska. LLC Last Completed: 09-09-11 RKB = 15' 3/4" 6 )f 4 Tubing 3-1/2" 9.3 L-80 Hydril 503 2.992 Surface 6,356' NO. Death CASING AND TUBING DETAIL JEWELRY DETAIL OD Item 1 2,460' SIZE WT GRADE CONN ID 6,228' TOP BTM. 20" - - - 5.983" 15' 31' 11-3/4" 47 - - 11.00 Surface 2,032' 7" 29 N-80 BTC 6.184 Surface 243' 7" 26 N-80 BTC 6.276 243' 883' 7" 23 N-80 BTC 6.366 883' 4,626' 7" 26 N-80 BTC 6.276 4,626' 6,470' 7" 29 N-80 BTC 6.184 6,470' 8,315' 7" 29 P-110 8RD 6.184 8,315' 10,875' Tubing 3-1/2" 9.3 L-80 Hydril 503 2.992 Surface 6,356' NO. Death ID JEWELRY DETAIL OD Item 1 2,460' 2.867" 5.020" Chemical Inj Sub w'/d' control line 2 6,228' 2.813" 4.540" Sliding Sleeve 3 6,244' 2.870" 5.983" Baker Premier Packer 4 6,297' 2.813" 3.940" X Nipple 5 6,356' 2.992" 3.500" WLEG, Auto Release 6 ±6,507' - 4.630" TCP Guns (length 32.76') Gun release not verified 'R' SS control line w/ 41 tubing clamps (one every otherjoint) Clamp O.D. 4.76" I PFRFORATION HICTORV tTvnnek Perfc TDT Lnv Denthl I ABANDONMENT DETAIL NO. Depth ID OD Item A 6,615' - - EZ Squeeze Packer w/ 75' cement on top B 6,652' - - Fish: 2 Baker K-1 Retainers C 6,850' - - PosiSet Plug w/ 37' Cement D 9,015' - - Tubing cut at 9,015' WLM. E 9,733' - - Top of Cement Plug. Pressure tested to 2,500 psi. F 10,473' - - Camco "MM" Mandrel with CEV Valve G 10,519' - - Brown CC Safety Joint H 10,530' - - Brown, 2-7/8" x 7", Type HS -16-1 Packer I 10,600' - - Cameo, "D" Nipple J ? - - Venturi Shoe 10,615' 10,616' 1' 5 Abandoned Notes NO. Denth Item K 7,114' 7" Stage Collar I PFRFORATION HICTORV tTvnnek Perfc TDT Lnv Denthl I PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE =1.25° @ 4,565' Updated by DMA 02-06-20 Interval Accum. Date Zone Top Btm Amt s f Comments 9/8/2011 64-5 6,380' 6,388' 8' 5 Reped'4-5/8" Mdlenium TCP guns, 5spt 60 deg 12/3/1998 64-5 6,380' 6,388' 8' 4 1-11/16"Pivot 180 deg. 7/26/1998 68-0 6,883' 6,911' 28' 4 Abandoned 6/20/1961 - 10,615' 10,616' 1' 5 Abandoned 6/21/1961 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/1961 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/1961 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/1961 - 10,752' 10,754' 2' S Abandoned PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE =1.25° @ 4,565' Updated by DMA 02-06-20 xu e WH P. 2" 1502 x 2-1/ Flanged Vi (Manta 2-1/161M 10K RaMg (Mai, Coil Tubing BOP Coiled Tubing HR$80 Injector Head & Gooseneck Weight = 12,850 Ibs d4-1116" 10K Comentional Stripper 5K C062 Lubricator 5K C062 x 4.1116" 10K Flange 4-1116" 10K Combi BOP Tap Set Rllndl6hear SermdSel:Pipe/Slip 4-1116" tOK Flow Cross Manual 2.2 Valve 1. 2" 1502 x 2-0/16" 10K Flange Manual 2)a Valve 2: 2-1/16" tOK x2 -1/16'10K Range Manual 2X2 Valve 12-1/16" tOK x 2-1/16" 10K Range Mental 2x2 Valve 4: 2" 1502 x2-1/16" 10K Range 4.1116" 10K x Wellhead Adapter Flange Wellhead STANDARD WELL PROCEDURE I1ilcorp:1laska. LLC NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL vl Page 1 of 1 ff Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for KGSF #1 (PTD 161-008) Sundry #: XXX -XXX Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) "first call" engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N -HA K Prepared By Initials HAK Approved By Initials AOGCC Written Approval Received (Person and Date) Approval: Prepared: Asset Team Operations Manager Date First Call Operations Engineer Date MEMORANDUM TO: Jim Regg �J { P.I. Supervisor FROM: Jeff Jones Petroleum Inspector Well Name SWANSON RIVER KGSF I Insp Num: mitJJ190423081834 Rel Insp Num: State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, April 23, 2019 SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC KGSFI SWANSON RIVER KGSF I Src: Inspector Reviewed By: P.I. Supry 13w— NON-CONFIDENTIAL Comm API Well Number 50-133-10160-00-00 Inspector Name: Jeff Jones Permit Number: 161-008-0 Inspection Date: 3/262019 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well KGSF I Type Inj G JTVD 6244 - Tubing 2440 - 2441 - 3439 2410 - 2441 2440 - PTD L_ 1610080 - IType Test SPT Test psi 1561 IA 1308 1855 185] - 1853 - 1855 -i 1853 BBL Pumped: 62 BBL Returned: 0.7 OA 510 510 510 510 - 510 510 _ Interval ! 4YRTST P/F P Notes: This test was extended an additional 15 minutes to further demonstrate integrity and ensure that thertnal expansion was not a factor. Final pressure data: Tubing - 2441, IA - 1855, OA - 510 Tuesday, April 23, 2019 Page 1 of I MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission To: Jim Regg -Pef� `tI7 I4k DATE: Tuesday, April 23, 2019 Integrity Tests P.I. Supervisor SUBJECT: Mechanical HILCORP ALASKA LLC KGSFI FROM: Jeff Jones SWANSON RIVER KGSFI Petroleum Inspector See: Inspector Reviewed By: P.I. Suprv.. b� NON -CONFIDENTIAL Comm Well Name SWANSON RIVER KGSF I API Well Number 50-133-10160-00-00 Inspector Name: Jeff Jones Permit Number: 161-008-0 Inspection Date: 3/25/2019 Insp Num: mitJJ190403181221 Rel Insp Num: Packer Depth Pretest Initial IS Min 30 Min 45 Min 60 Min Well Karr i "Type Inj 1 G -TVD 6244 Tubing 1-438 - za>s 24:2 u;i 2a;i PTD] 1610086 _ .TypeTest SPT Test psi 1561 -� IA 60 1644 ](,1"X616 (Sz - BBL Pumped: BBL Returned: OA 216 I , o 320 ;10 336 Interval 4vRTST p/F I ✓ Notes: The temperature differential between the 29 degree test Fluid and approx. 175 degree wellhead caused thermal effect preventing proper stabilization. This test was extended another 15 minutes to further demonstrate integrity, tubing and the pressure was left on the IA to equalize„ temperature. Tuesday, April 23, 2019 Page 1 of 1 • MEMORANDUM • State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg Inc?Jq `)- Z- D` i�; DATE: 12/24/15 P. I. Supervisor FROM: Brian Bixby SUBJECT: Site Visit Follow Up Petroleum Inspector Swanson River KGSF-1 Hilcorp Alaska PTD 1610080 12/21/15: This was a follow up site visit to go over the well safety valve systems at Hilcorp's storage wells and how they are set up when injecting and producing along with how the pilots are set up for each. My last trip here was to witness 180 -day SVS testing. While doing my report I had questions regarding the pilots and how often these wells are switched back and forth from injection to producing and if they send notification for AOGCC to witness each time the wells are switched. I met with Rick Musgrove at the office and we went to KGSF-1 which is one of four of their storage gas wells that they also produce gas from. He showed me the location of the pilot on the well (picture #1) which is set to trip at 1600 psi, then we looked at pilot for when the well is producing which is in a valve building downstream of the heater and the choke (picture #2). Picture #3 shows the heater and piping outside the building. The wells can be on injection for a few days and then producing for a few days. This raised a question on whether or not they are sending in a notification for us to witness and the answer was "NO". I believe if they are going to be switching back and forth that we test at a minimum both pilots every time we test these wells weather it is a Misc. or Routine test. I spoke with Bruce Hershberger and Joey Hensley (Production Foremen) and asked them to send a summary of how the wells are operated while on injection and also when producing. I also asked them to provide plots for all 4 wells, pictures and flow diagrams. Attachments: Photos (3) Computer Screen Snap Shot — Control Devices on KGSF-1 Volume Plot of well SCU 42-05X (PTD 2060740) SCANNED SEP 2 3 2016 2015-1221_SVS_SwansonRiver_Gas_Storage wells bb.docx Page 1 of 4 • Storage Injection Wells — Swanson River Field Photos by AOGCC Inspector B. Bixby 12/21/2015 e 2015-1221_SVS_SwansonRiver_Gas_Storage wells_bb.doex Page 2 of 4 Picture #1 showing the Pilots for when well is on injection. Which also stays on when well is producing. Picture #2 showing the pilot for when well is producing. 2015-1221 SVS SwansonRiver_Gas_Storage_wells_bb.docx Page 3 of 4 Picture #3 showing the heater and the choke Screen Snapshot — KGSF-1 control devices :I ZTV ',A I co- ",: =I mw� �Izmrg T4ZAM : kw44 W-7UN =;20:3 1;99:36 M 2015-1221 _SVS_SwansonRiver_Gas_Storage_wells_bb.docx Page 4 of 4 Volume Plot — SCU 42-05X Red — Production Blue - Injection 0 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, March 31, 2015 To: Jim Re gg �� I�I l7 P.I. Supervisor j�1 SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC KGSF I FROM: Bob Noble SWANSON RIVER KGSF I Petroleum Inspector Src: Inspector Reviewed B P.I. Supry J NON -CONFIDENTIAL Comm Well Name SWANSON RIVER KGSF 1 API Well Number 50-133-10160-00-00 Inspector Name: Bob Noble Permit Number: 161-008-0 Inspection Date: 3/23/2015 Insp Num: mitRCNI50324092532 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well KGSF 1 FType Inj N TVD I 6244 TUbIngT 2540 2540 2540 " 2540 PTD r ---1610080 Type Test SPT Nest pi — 1561 IA 1 918 1708 1696 1689 - -- -! -1 - - +- ---- t - Interval 4YRTST - -- - - P/F - --P " OA 0 0 - 0 0 Notes: SCANNED Tuesday, March 31, 2015 Page 1 of 1 THE STATE Alaska Oil and Gas 01ALA KA Ccneeli vatiGn Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 November 18, 2013 Mr. John Barnes Hilcorp Alaska LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: Notice of Violation dated September 30, 2013 5jD OCT 0 � 2014 Swanson River Field Dear Mr. Barnes: On September 30, 2013 the Alaska Oil and Gas Conservation Commission (AOGCC) issued a notice of violation to Hilcorp Alaska LLC (Hilcorp) for a defeated well safety valve system component on Swanson River KGSF #1 (PTD 1610080) and missing annulus pressure gauges on several Swanson River Field wells. Corrective actions were immediately implemented to resolve the defeated safety valve system and summarized in an email dated September 10, 2013. Hilcorp summarized its actions relating to the missing annulus valves in an email dated October 24, 2013. Hilcorp has satisfactorily addressed the regulatory concerns identified in the notice of violation. The AOGCC does not intend to pursue any further enforcement action regarding these compliance concerns. Sincerely, v /-'q qV---"r'04- Cathy P. oerster Chair, Commissioner cc: AOGCC Inspectors (via email) Mr. Keith Trichel November 18, 2013 Page 2 of 2 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 AOGCC grants for good cause shown, a person affected by it may file with the AOGCC 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 AOGCC 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 AOGCC 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 AOGCC mails, OR 30 days if the AOGCC 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 AOGCC grants an application for reconsideration, this order or decision does not become final. Rader, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC 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 AOGCC 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. THE STATE Alaska/Oil and GasI-1-LASKA GOVERNOR SEAN PARNELL 333 West Seventh Avenue Mr. John Barnes Hilcorp Alaska LLC P.O. Box 244027 Anchorage, AK 99524-4027 Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 November 15, 2013 RE: Notice of Violation dated September 30, 2013 KANNED OCT 0 2014 Swanson River Field Dear Mr. Barnes: On September 30, 2013 the Alaska Oil and Gas Conservation Commission (AOGCC) issued a notice of violation to Hilcorp Alaska LLC (Hilcorp) for a defeated well safety valve system component on Swanson River KGSF #1 (PTD 1610080) and missing annulus pressure gauges on several Swanson River Field wells. Corrective actions were immediately implemented to resolve the defeated safety valve system and summarized in an email dated September 10, 2013. Hilcorp summarized its actions relating to the missing annulus valves in an email dated October 24, 2013. Hilcorp has satisfactorily addressed the regulatory concerns identified in the notice of violation. The AOGCC does not intend to pursue any further enforcement action regarding these compliance concerns. Sincerely, "14 Cathy P. oerster Chair, Commissioner cc: AOGCC Inspectors (via email) Mr. John Barnes November 15, 2013 Page 2 of 2 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 AOGCC grants for good cause shown, a person affected by it may file with the AOGCC 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 AOGCC 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 AOGCC 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 AOGCC mails, OR 30 days if the AOGCC 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 AOGCC grants an application for reconsideration, this order or decision does not become final. Radler, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC 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 AOGCC 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 C E I V AUG 16 2013 AOGCC Hilcorp Alaska, LLC August 15, 2013 Mrs. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501-3539 �CO—� —UU"-6— Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777-8301 SC"E© OCT 6 N 201q RE: 2013 Annual Material Balance Calculations of Production and Iniection Volumes: Kenai Gas Storage Facility #1 (KGSF#1), Swanson River Field Dear Commissioner Foerster: Attached for Alaska Oil and Gas Conservation Commission (AOGCC) review is the 2013 annual material balance calculation of production and injection volumes for the Kenai Gas Storage Facility #1 (KGSF#1), as required per Storage Injection Order #2A. This material balance includes all primary production from the Tyonek 64-5 reservoir (via the SRU 43-28 wellbore), as well as all storage operations from the two gas storage wells, KGSF #1 and KGSF #7A. Primary production occurred from December 1998 through May 2001 and storage operations are on- going since June 2001. Gas storage production and injection volumes for KGSF #1 (formerly SRU 43-28) and KGSF #7A have been reported on a monthly basis to the state through July 31, 2013. Pressures from the Tyonek 64-5 reservoir have been measured/estimated from both downhole pressure buildups and from surface shut-in tubing pressures. The surface readings were then converted to downhole pressures at a common datum of 6,395 ft TVD. These data points are tabulated in Attachment #1 and plotted versus the net cumulative production (production less injection) on the standard P over Z plot, shown in Attachment #2. The P over Z plot, Attachment #2, shows that the 2012-2013 production and injection cycle followed the primary production profile as expected. This storage reservoir continues to show that the gas is contained within zone and is an important resource in helping meet peaking requirements during the winter season. If you or your staff has any questions regarding this annual report, please contact me at 777- 8440. Sincerely, A w-, Jeff Allen Petroleum Engineer Attachments: 1. Tyonek 64-5 Sand POZ Data 2. KGSF #1 Facility (Tyonek 64-5 Sand) - P/Z vs Cumulative Production Plot ATTACHMENT #1 -- KGSF POZ DATA (64-5 Sand) Parameter Value Units Gas Gravity 0.563 3306 Bench Datum 6369 ft (tvd) Datum Temp 122 °F Avg Temp. 102 of Primary Production 12/05/98 SITP 0 2850 Gauge 3306 0.0000 3765 07/27/99 SITP Wellname Date Test Type Te Duration Measured Pressure at Factor Datum Prressure, Cum Gas, bcf P/Z. Psia 0.8954 1100 1.0690 1229 Test Depth Test MTD, psia 0 540 0.9353 626 1.2700 669 06/09/01 (hrs) 0 380 0.9533 Psia 1.3390 463 2280 0.8551 2645 0.4000 (MTD),ft 07/12/02 SITP 0 2620 Primary Production 12/05/98 SITP 0 2850 0.8781 3306 0.0000 3765 07/27/99 SITP 0 1775 0.8529 2059 0.5610 2414 09/09/00 BHP buildup 6395 882 0.8954 1100 1.0690 1229 02/20/01 SITP 0 540 0.9353 626 1.2700 669 06/09/01 SITP 0 380 0.9533 441 1.3390 463 2001/2002 Iniection Cvcle 07/11/01 SITP 21 0 875 0.9018 1015 1.1480 1126 09/18/01 SITP 4 0 1820 0.8522 2111 0.6730 2477 09/20/01 SITP 24 0 1810 0.8524 2099 0.6780 2463 10/09/01 SITP 8 0 1980 0.8514 2297 0.5720 2698 04/05/02 SITP 15 0 2280 0.8551 2645 0.4000 3093 07/12/02 SITP 0 2620 0.8666 3039 0.1900 3507 07/26/02 SITP 0 2630 0.8671 3050 0.2000 3518 2002/2003 Production Cvcle 2003 Injection Cycle 12/29/03 ISITP 1 19 1 0 1 2440 1 0.8596 1 2829 0.2540 3291 2003/2004 Production Cycle 04/28/04 ISITP 1 24 1 0 1 2075 1 0.8518 1 2406 0.4450 2825 2004 Iniection Cvcle 12/05/02 ISITP 1 65 1 0 1 1415 1 0.8643 1 1641 1 0.7400 1 1899 12/05/04 07/25/03 ISITP I 1 0 1 224 1 0.9719 1 260 1 1.2520 1 268 2003 Injection Cycle 12/29/03 ISITP 1 19 1 0 1 2440 1 0.8596 1 2829 0.2540 3291 2003/2004 Production Cycle 04/28/04 ISITP 1 24 1 0 1 2075 1 0.8518 1 2406 0.4450 2825 2004 Iniection Cvcle 2004/2005 Production Cycle 06/08/05 ISITP 1 6 1 0 1 2080 1 0.8518 1 2412 1 0.3960 1 2832 2005 Iniection Cvcle 08/08/05 07/14/04 ISITP 12 1 0 2565 0.8643 2974 0.1530 3441 0.0220 1 12/05/04 ISITP 96 1 0 1 2865 0.8788 3322 -0.0820 3780 2004/2005 Production Cycle 06/08/05 ISITP 1 6 1 0 1 2080 1 0.8518 1 2412 1 0.3960 1 2832 2005 Iniection Cvcle 08/08/05 ISITP 1 1 1 0 1 2828 1 0.8768 1 3279 1 0.0220 1 3740 12/30/05 ISITP 1 72 1 0 1 2786 1 0.8746 1 3231 1 -0.0440 1 3694 2005/2006 Production Cycle 03/22/06 ISITP 1 24 1 0 1 1905 0.8515 1 2209 0.4208 2594 2006 Injection Cycle 07/10/06 SITP 240 0 2815 0.8761 3264 -0.0482 3726 08/14/06 SITP 456 0 2687 0.8697 3116 0.0303 3583 09/30/06 SITP 288 0 2815 0.8761 3264 -0.0678 3726 2006/2007 Production Cycle 12/04/06 SITP 18.5 0 2665 0.8686 3090 0.0329 3557 01/10/07 SITP 9 0 2450 0.8600 2841 0.0763 3304 03/26/07 SITP 96 0 2231 0.8540 2587 0.2442 3029 2007 Injection Cycle 04/27/07 SITP 192 0 2828 0.8768 3279 -0.0314 3740 06/04/07 SITP 120 0 2711 0.8708 3144 0.0206 3610 09/11/07 SITP 648 0 2717 0.8711 3151 -0.0028 3617 2007/2008 Production Cycle 12/02/07 ISITP 1 144 1 0 1 2604 1 0.8654 1 3005 0.0284 3473 ,)nnR Iniantinn Cvr.la 17Rn 05/02/08 01/17/08 SITP 192 1 0 1 2078 1 0.8517 1 2397 0.3056 2814 SITP 04/08/08 ISITP 888 1 0 1 1760 1 0.8534 1 2026 0.4748 2374 ,)nnR Iniantinn Cvr.la 17Rn 05/02/08 SITP 1320 0 1925 0.8515 2218 0.4086 2605 07/01/08 SITP 528 0 2643 0.8670 3049 0.0799 3517 07/28/08 SITP 528 0 2648 0.8673 3055 0.0728 3523 09/16/08 SITP 528 0 2664 0.8679 3073 0.0526 3541 09/30/08 SITP 120 0 2670 0.8682 3080 0.0482 3547 gnnR/7nn9 Prnrluctinn Cvcle 2009 Injection Cycle 06/14/09 SITP 240 0 2781 0.8736 3209 0.0388 3673 07/13/09 SITP 1008 0 2850 0.8772 3287 -0.0492 3747 08/10/09 SITP 552 0 2828 0.8760 3262 -0.0489 3724 2009/2010 Production Cycle 10/12/09 01/16/09 ISITP 60 1 0 1 1392 1 0.8661 1 1599 1 0.6279 1 1846 SITP 02/19/09 ISITP 24 1 0 1 1376 1 0.8782 1 1361 1 0.6830 1 1550 2009 Injection Cycle 06/14/09 SITP 240 0 2781 0.8736 3209 0.0388 3673 07/13/09 SITP 1008 0 2850 0.8772 3287 -0.0492 3747 08/10/09 SITP 552 0 2828 0.8760 3262 -0.0489 3724 2009/2010 Production Cycle 10/12/09 SITP 96 0 2630 0.8740 3218 -0.0552 3682 01/24/10 SITP 96 0 2528 0.8665 3036 0.0191 3504 03/08/10 SITP 24 0 2231 0.8624 2919 0.0842 3385 08/11/10 SITP 336 0 2313 0.8556 2671 0.2266 3122 2010 Injection Cycle 10/20/10 ISITP 168 1 0 1 3134 1 0.8948 1 3626 -0.3103 4052 gn1n/gn11 Prnriurtinn Cvrle 12/08/10 SITP 20 0 3021 0.8879 3500 -0.2949 3942 12/21/10 SITP 20 0 2727 0.8722 3176 -0.1455 3641 03/01/11 SITP 24 0 1123 0.8813 1310 0.5776 1486 KGSF#7A 03/21/11 PBU 48 5300 775 0.8904 1035 0.6857 1162 2011/2012 Iniection and Production Cvcle KGSF#1 05/20/11 PBU 528 6650 1119 0.8735 1445 0.6857 1654 KGSF#1 06/27/11 PBU 20 6376 2345 0.8588 2802 0.2062 3263 KGSF#1 07/04/11 PBU 72 5300 2856 0.8567 2720 0.1768 3175 KGSF#1 07/31/11 SITP 576 0 2395 0.8582 2777 0.1515 3236 KGSF#1 09/23/11 SITP 48 0 2596 0.8656 3010 0.0584 3478 KGSF#1 10/04/11 SITP 312 0 2585 0.8651 2998 0.0586 3465 KGSF#1 11/01/11 SITP 288 0 2758 0.8731 3198 -0.0417 3663 KGSF #1 12/20/11 SITP SITP 0 2869 0.8942 3266 -0.0666 3652 KGSF #1 02/01/12 SITP BHP 0 2185 0.8735 2491 0.2474 2852 KGSF #1 03/04/12 SITP 0 2358 0.8764 2688 0.1799 3067 KGSF #1 04/24/12 SITP 0 2004 0.8724 2284 0.3638 2618 KGSF #1 05/10/12 SITP 0 1963 0.8724 2237 0.3819 2564 KGSF#7A 05/31/12 PBU 24 6385 1917 0.8555 22470.4181 2627 KGSF #1 06/07/12 SITP 0 1934 0.8725 2204 0.4103 2526 9n19/7n13 iniertinn and Prnriurtinn CvrIp KGSF #1 07/25/12 SITP 0 2057 0.8725 2345 0.3677 2688 KGSF #1 07/27/12 PBU 696 0 2043 0.8516 2375 0.3679 2789 KGSF #1 10/29/12 SITP 0 2856 0.8937 3252 -0.0348 3639 KGSF #1 12/17/12 SITP 0 2193 0.8736 2500 0.2702 2862 KGSF #1 01/17/13 SITP 0 2523 0.8805 2950 0.1700 3351 KGSF #1 02/18/13 SITP 0 2394 0.8763 2801 0.2204 3196 KGSF #1 04/17/13 SITP 0 2892 0.8965 3372 -0.0034 3761 KGSF #1 05/11/13 SITP 0 2854 0.8946 3329 0.0020 3721 KGSF #1 07/13/13 BHP 6385 3311 0.8938 3309 0.0080 3702 V -T- -0.4 T-0.4 -0.2 0.0 0.2 OA O b J 8 1.0 1.2 Cum Gas Produced (BCF) Attachment #2 : 64-5 P/z vs Cumulative Gas Production Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp@chevron.com] Sent: Monday, November 07, 2011 4:21 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Subject: 2011 October's SRF Tyonek 64-5 Sand Storage Well Monitoring Report Page 1 of 2 Attachments: Master Well List TIO Report 2011 11 01.xls; Master Well List TIO Report 2011 11 01.xls Hi Tom & Jim, Here is October's monthly report for the wells requiring pressure monitoring near the SRF Tyonek 64-5 Sand Gas Storage reservoir. Just about ready to start using the storage wells for production. They are moving very little gas into them now and withdrawal should start this month. As this storage reservoir doesn't have any monitoring wells within a'/2 mile radius, this report is provided as a means of monitoring the storage wells themselves. Larry From: Maunder, Thomas E (DOA) [mailtotom.maunder@alaska.gov] Sent: Tuesday, October 11, 20113:29 PM To: Greenstein, Larry P Cc: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Subject: RE: Update on 64-5 Gas Storage Sand Larry and Chantal, Yes, we would like this information to be provided. Regardless of no proximate wells, it is important to see the performance of the storage wells. This is especially so give the recent concern with KGSF #1 and the need for the workover. Thanks for sending the information. Tom Maunder, PE AOGCC r- 0 J From: Greenstein, Larry P [mailto:Greensteinlp@chevron.com] Sent: Monday, October 10, 2011 1:53 PM To: Maunder, Thomas E (DOA) Cc: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Subject: Update on 64-5 Gas Storage Sand Tom, Based on this e-mail chain, it appears you would like a 64-5 sand gas storage report similar to the 77-3 sand gas storage report... even if there aren't any wells that can be used for monitoring purposes except the two storage wells themselves. 11/18/2011 • • Page 2 of 2 Is that right?? I didn't think you needed to see this report because there aren't any wells to monitor within 'h mile. Sorry for the omission. It would look something like this... Notice the gap in the KGSF #1 data while the well was being worked over. Larry 11/18/2011 Plot Pressure Rate vs Time - Well KGSF #1 ubing Tubing 2 VM-Inj 10000 3000 -- 2760 0 0 7" 50' - 0 2761 0 -9 5/8" 10/28/11 350 2500 -Tubing 0 10/27/11 350 2769 0 8000 10/26/11 Vol Inj 2767 0 0 -Vol Prod 50 2768 2000 _ -- -- -- 10/24/11 50 2770 0 0 6000 v 2772 0 0 10/22/11 50 2775 LL N � 10/21/11 50 C L a` 1500 - — — 10/20/11 350 2810 317 0 4000 1000 -- - __ _ _ 0 0 10/18/11 50 2813 2000 500 10/17/11 50 2823 0 N 65 O to I� O O O O O Q O 0 Date ubing Tubing 2 VM-Inj Vol Prod 10/31/11 2760 0 0 10/30/11 50' - 0 2761 0 0 10/28/11 350 0 2764 0 0 10/27/11 350 2769 0 0 10/26/11 50 2767 0 0 10/25/11 50 2768 0 0 10/24/11 50 2770 0 0 10/23/11 50 2772 0 0 10/22/11 50 2775 0 0 10/21/11 50 2779 10/20/11 350 2810 317 0 10/19/11 350 2813 0 0 10/18/11 50 2813 0 0 10/17/11 50 2823 0 0 10/16/11 00 2839 0 0 10/15/11 00 2877 4380 0 10/14/11 80 3025 9651 10/13/11 70 2854 4996 10/12/11 300 2703 2052 640 10/11/11 46 2741 1111 0 10/10/11 45 2747 3110 0 10/09/11 60 2902 8979 10/08/11 10 2820 9299 0 10/07/11 200 2541 2380 0 10/06/11 410 2569 852 10/05/11 50' 2595 504 2 10/04/11 50 2596 0 0 10/03/11 50 2597 0 0 10/02/11 0 2597 0 0 10/01/11 0 2599 0 0 09/30/11 0 2598 0 0 09/29/11 0 2599 0 0 09/28/11 0 2600 0 119 09/27/11 0 2601 0 51 09/26/11 2 0 0 09/25/11 0 0 11 /18/2011 8:43 AM - TIO Reports 7e.xls J J Dolan TIO Report Data Sheet KGSF #1 FLOWING Permit # 1610080 API # 50-133-10160-00 05/02/2011 to 11/01/2011 Master Well List TIO Report 2011 11 01.xis KGSF #1 Src: Inspector Reviewed By: P.I. Suprv, E1� '7//l NON -CONFIDENTIAL Comm Well Name: SWANSON RIVER KGSF 1 API Well Number: 50-133-10160-00-00 MEMORANDUM State of Alaska Permit Number: 161-008-0 Alaska Oil and Gas Conservation Commission TO: l Jim Regg 1 DATE: Thursday, October 20, 2011 P.I. Supervisor [ SUBJECT: Mechanical Integrity Tests Depth Pretest Initial UNION OIL CO OF CALIFORNIA Well KGSF 1 TI ype Inj. N i I— 1 t P.T.D. 161oos0TypeTest SPT Test psi p KGSF I FROM: Jeff Jones SWANSON RIVER KGSF I Petroleum Inspector Src: Inspector Reviewed By: P.I. Suprv, E1� '7//l NON -CONFIDENTIAL Comm Well Name: SWANSON RIVER KGSF 1 API Well Number: 50-133-10160-00-00 Inspector Name: Jeff Jones Insp Num: mitJJ111007071447 Permit Number: 161-008-0 Inspection Date: 9/28/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well KGSF 1 TI ype Inj. N i I— 1 t P.T.D. 161oos0TypeTest SPT Test psi p -- 6244 �� IEj 1561 OA 0 0 1770 10 1760 1757 10 10 ' - -- — -- — —1—O — InteryalINITAL P/F, P ' Tubing 2700 2700 2700 2700 Notes: Post RWO. I BBL diesel pumped. ' Thursday, October 20, 2011 Page 1 of 1 TE OF ALASKA • ALASKA OIL ANS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Li Repair Well Li Plug Perforations Li Stimulate Li Oth4,/j Install Isolation plug Performed: Alter Casing ❑ Pull Tubing ❑✓ Perforate New Pool ❑ Waiver ❑ Time Extensi❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑� Re-enter Suspended W❑ 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑ Stratigraphic ❑ Exploratory ❑ Service ❑r 161-008 3. Address: PO Box 196247, Anchorage, AK 99519 6. API Number: 50-133-10160-00 e Q 7. Property Designation (Lease Number): 8. Well Name and Number: FEDA028399 (Swanson River Unit) Swanson River KGSF#1 9. Field/Pool(s): Swanson River Field/ 64-5 Tyonek Gas Storage, Hemlock Oil & Tyonek Undef Gas Pools 10. Present Well Condition Summary: Total Depth measured 10,875 feet Plugs measured N/A feet true vertical 10,875 feet Junk measured +/-6,507(TCP Guns) feet Effective Depth measured 6,507 feet Packer measured 6,244 feet true vertical 6,507 feet true vertical 6,244 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 31' 20" 31' 31, Surface 2,032' 11-3/4" 2,032' 2,032' Intermediate Production 10,875' 7" 10,875' 10,875' 6,340psi 3,830psi Liner Perforation depth Measured depth 6,380-6,388 feet True Vertical depth 6,380-6,388 feet Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3#/L-80 6,356'(MD) 6,356'(TVD) 6,244'(MD) Packers and SSSV (type, measured and true vertical depth) Baker Premier Packer 6,244'(TVD) N/A Ift P- N/A 11. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A OCT 11 201 t Treatment descriptions including volumes used and final pressure: N/A Aloka Oil & G 12. Representative Daily Average Production or Injection t Oil -Bbl Gas-Mcf Water -Bbl Casing TIMFI-ImProve Tubing Pressure Prior to well operation: 0 0 0 30psi 2,400psi Subsequent to operation: 0 6,500 0 270psi 2,575psi 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory ❑ Development ❑ ServirE] Stratigraphic ❑ Daily Report of Well Operations X 15. Well Status after work: Oil El Gas WDSPL GSTOR Q ` WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 16. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 1311-239 Contact Chris Kanyer Phone: 263-7831 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature Phone 276-7600 Date 10/4/2011 _4✓ no REWS OCT 17 Z611 Form 10-404 Revised 10/2010 Submit Original Only Chevron • De th ID Swanson Oer 1 2,460' 2.867" 5.020" Chemical Inj Sub w'/4" control line 2 Well KGSF 41 2.813" 4.540" Sliding Sleeve 3 6,244' 2.870" Last Completed 9/9/2011 Baker Premier Packer 4 6,297' CASING AND TUBING DETAIL 3.940" X Nipple 5 RKB = 15' SIZE WT GRADE CONN ID 6 TOP BTM. 4.630" TCP Guns (length 32.76') Gun release not verified '/4" SS control line w/ 41 tubing clamps (one every other joint) Clamp O.D. 4.76" - 10,615' 10,616 20" - - 6/2:1/1961 H-1 15' 31' 14' 4 Abandoned 6/21/1961 H-2 10,642' 11-3/4" 47 4 Abandoned 11.00 Surface 2,032' 10,752' 88' 4 Abandoned 6/2:0/1961 - 1 7" 29 N-80 BTC 6.184 Surface 243' 7" 26 N-80 BTC 6.276 243' 883' , 7" 23 N-80 BTC 6.366 883' 4,626' 7" 26 N-80 BTC 6.276 4,626' 6,470' 7" 29 N-80 BTC 6.184 6,470' 8,315' 7" 29 P-110 8RD 6.184 8,315' 10,875' 3/4" Tubing 3-1/2" 9.3 L-80 Hydril503 2.992 Surface 6,356' I 3' NO. De th ID JEWELRY DETAIL OD Item 1 2,460' 2.867" 5.020" Chemical Inj Sub w'/4" control line 2 6,228' 2.813" 4.540" Sliding Sleeve 3 6,244' 2.870" 5.983" Baker Premier Packer 4 6,297' 2.813" 3.940" X Nipple 5 6,356' 2.992" 3.500" WLEG, Auto Release 6 ±6,507' - 4.630" TCP Guns (length 32.76') Gun release not verified '/4" SS control line w/ 41 tubing clamps (one every other joint) Clamp O.D. 4.76" N0. Psi) t h ABANDONMENT DETAIL ID OD Item A 6,615' - EZ Squeeze Packer w/ 75' cement on top B 6,652' - - Fish: 2 Baker K-1 Retainers C 6,850' - - PosiSet Plug w/ 37' Cement D 9,015' - - Tubing cut at 9,015' WLM. E 9,733' - - Top of Cement Plug. Pressure tested to 2,500 psi. F 10,473' - - Cameo "MM" Mandrel with CEV Valve G 10,519' - - Brown CC Safety Joint H 10,530' - - Brown, 2-7/8" x 7", Type HS -16-1 Packer I 10,600' - - Cameo "D" Nipple J ? - - Venturi Shoe Notes NO. Depth Item K 7,114' 7" Stage Collar I PF.R FOR ATInN HICTnRV (Tvnnek Perk TDT Loo Denth) I PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.25° @ 4,565' KGSF #1 WBD 9-28-2011.docm Revised by: CVK REVISED: 9-28-2011 Interval Accum. Date Zone op Btm Amt spf Comments 9/8/2011 64-5 6,380' 6,388' 8' 5 Reperf4-5/8" Millenimn TCP guns, 5spt; 60 deg 12!3/1998 64-5 6,380' 6,388' 8' 4 1-11/16" Pivot, 18C deg. 7/2:6/1998 68-0 6,883' 6,911' 28' 4 Abandoned 6/2:0/1961 - 10,615' 10,616 1' 5 Abandoned 6/2:1/1961 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/1961 H-2 10,642' 10,656 14' 4 Abandoned 6/2:1/1961 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/2:0/1961 - 1 10,752' 1 10,754' 2' S lAbandoned PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.25° @ 4,565' KGSF #1 WBD 9-28-2011.docm Revised by: CVK REVISED: 9-28-2011 Chevron Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RK B (ft) Water Depth (ft) KGSF #1 SWANSON RIVER KGSF 1 I FEDA028399 5013310160 QA5333 174.00 Jo Primary Job Type Job Category Objective Actual Start Date Actual End Date Well Preparation Well 8/7/2011 9/8/2011 Services Primary Wellbore Affected, Wellbore UWI Well Permit Number KGSF #1 501331016000 1610080 Daily Ooerations 0191201100:00 - 8/101201100:00 Operations Summary RU wireline, pressure test lubricator 250psi low/3,000psi high. RIH w/ 1-9/16" tubing punch and punch tubing below packer at 6,306'-6,312'. RD wirline. Secure well. 81101201100:00 - 81111201100:00 Operations Summary Preperation for Key Rig Mobe up. 81111201100:00 - 81121201100:00 Operations Summary Preperation for Key Rig Mobe up. 8/12/201100:00 - 81131201100:00 Operations Summary Continue mobilizing equipment. Rig up Key Rig #3. 8113/201100:00 - 81141201100:00 Operations Summary Continue mobilizing equipment. Rig up Key Rig #3. 81141201100:00 - 81161201100:00 Operations Summary Continue mobilizing equipment. Rig up Key Rig #3. 81151201100:00 - 81161201100:00 Operations Summary Continue mobilizing equipment. Rig up Key Rig #3. 8116/201100:00 - 81171201100:00 Operations Summary Continue mobilizing equipment. Rig up Key Rig #3. 81171201100:00 - 81181201100:00 Operations Summary Continue Rig up. RU slickline, pressure test lubricator 250psi low/3500psi high. Prepare to pump KW fluid. Notified AOGCC of upcoming BOP test. 8/181201100:00 - 81191201100:00 Operations Summary Bullhead CaCO3 pill and 8.8ppg 9% KCI down tubing. RIH w/ slickline and shift sliding sleeve open at 6,273'. Circulated well to 9% KCI. Installed BPV, ND tree, NU BOP. Notified BLM of upcoming BOP test. 81191201100:00 - 81201201100:00 Operations Summary Pressure test annular to 250psi low/2500psi high, BOPE and VBR to 250psi low/3000psi high, pull BPV, install TWC, pressure test blind rams to 250psi low/3000psi high. Pull TWC. MU landing joint, unseat hanger, rotate and release K-22 anchor from packer, and circulate well. Bob Noble of AOGCC waived witness of BOP test. 81201201100:00 - 8/21/201100:00 Operations Summary POOH with 6,287' of 3-1/2" L-80 tubing and LD same. PU 3-1/2" workstring and begin to RIH with 6" packer milling BHA. 8/211201100:00 - 8/22/2011 00:00 Operations Summary Mill on packer at 6,288' and packer fell free, begin to POOH. 8/221201100:00 - 8/231201100:00 Operations Summary POOH and LD milling BHA, packer and tailpipe, full recovery of completion. RIH with 6" bit, string mill, and magnet BHA to 6,650'. Circulate and begin POOH. 81231201100:00 - 81241201100:00 Operations Summary POOH with 6" bit, string mill, and magnet BHA to 5,980', milled tight spot from 5,980'-5,990', POOH and LD BHA. RU Eline, RIH with USIT cement and casing evaluation log to 6,650', POOH and RD Eline. 81241201100:00 - 8/261201100:00 Operations Summary RIH with 7" K-1 cement retainer on 3-1/2" workstring to 6,640', unable to set retainer, RIH and tag fill at 6,656', unable to set retainer. Notified the AOGCC & BLM of upcoming BOP test. Pulled up hole with retainer to 6,620', pulled wear bushing, made up hanger, and land same. Installed TWC. Pressure test annular to 250psi low/2500psi high, began pressure testing BOPE to 250psi low/3000psi high. Jim Regg of AOGCC & Tom Zelenka of BLM waived witness to BOP test. AWL Chevron Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI IChevNo Original RKB (ft) Water Depth (ft) KGSF #1 SWANSON RIVER KGSF 1 FEDA028399 5013310160 IQA5333 174.00 DailyOp6m0ons 81261201100:00 - 8128/2011 00:00 Operations Summary Continued pressure testing BOPE to 250psi low/3000psi high. Pull tubing hanger and LD same. POOH and LD partial recovery of cement retainer. RU Eline, begin RIH with 7" cement retainer. 81261201100:00 - 81271201100:00 Operations Summary Continue to RIH with 7" K-1 cement retainer and tag fish at 6,652, pull up hole to 6,640', attempt set w/ good indication of fire, pull up hole to 6,600', RIH and tagged up on retainer at 6,652'. no set of retainer. POOH, Retainer left in hole. PU 7" EZ Squeeze cement retainer on Eline, tagged fish at 6,654', pulled up hole and set retainer at 6,615', POOH and RD Eline. RIH with cement stinger assembly on 3-1/2" workstring, stabbed into retainer at 6,615', set down w/ 15K to confirm set, an pressure tested below retainer to 1500psi for 10 min. 8/271201100:00 - 81281201100:00 Operations Summary Unstab stinger assembly from retainer, RU cementing equipment, pressure test lines 1,000psi low/3,500psi high. mix and pump 5bbl 15.3ppg EasvBlok cement on toe of cement retainer, pulled up hole and reverse circulated. POOH. RIH with 6" bit, string mill, and 7" scraper BHA and tag cement stringer a , wash down and tag hard cement at 6,465', drilled hard cement from 6,465' to 6,500'. 81281201100:00 - 8129/201100:00 Operations Summary Continue to drill hard cement from 6 500' to 6,540', leaving 75' of cement on retainer. Circulate well clean with filtered 9% KCI. Begin POOH with 6" bit, string mill, and 7" scraper BHA, laying down workstring. 8/29/201100:00 - 81301201100:00 Operations Summary Continue to POOH with 6" bit, string mill, and 7" scraper BHA, laying down workstring. Begin RIH with 3-1/2" 9.3# L-80 TCP completion assembly. 81301201100:00 - 8/31/201100:00 Operations Summary Continue to RIH with 3-1/2" 9.3# L-80 TCP completion assembly, correlate nuns to regerforate 64-5 sand from 6.380'-6.388'. Space out, land hanger, and recorrelate with Eline. RD Eline. RU slickline, pressure test lubricator 250psi low/3500psi high. RIH and shift sliding sleeve closed at 6,228', POOH. RD slickline. Pressure tubing up to 4,000psi to set 7" Premier packer at 6,244', continue pressure test of tubing for 30min, bleed off same. Perform charted ressure test of 7" casing down to packer at 6 244' to 3 650 si, bleed off same. RU slickline, pressure test lubricator 250psi low/3000psi high. RIH and open sliding sleeve at 6,228'. RD slickline and prepare to displace packer fluid. 8131/201100:00 - 9111201100:00 Operations Summary Displaced 9% KCI with corrosion inhibitor into annulus. Install BPV. ND BOPE. Pull BPV, install TWC. NU tree and test same to 250psi low/5 QOOnci high. Pull TWC. Pump 10bbl diesel down tubing, taking returns out annulus. Begin RD and demobe of Key rig. 911/201100:00 - 912/201100:00 Operations Summary Continue demobe of equipment. 9121201100:00 - 9131201100:00 Operations Summary Spot equipment to displace diesel into tubing into annulus. 9131201100:00 - 9/41201100:00 Operations Summary RU slickline, pressure test lubricator 250psi low/3500psi high. Pressure up tubing with gas, RIH with sliding sleeve shifting tool, locate fluid level at 5,174', displace an additional fluid from annulus, locate fluid level at 5,635', closed sliding sleeve at 6224'SLM (6,228'RKB,, pressured up on annulus to 850psi, sliding sleeve closed, POOH. RD slickline. 9/41201100:00 - 9151201100:00 Operations Summary Waiting on facility repairs, prior to perforating. 9/8/201100:00 - 9191201100:00 Operations Summary RU lubricator, pressure test to 250psi low/3,000psi high, drop bar, positive indication of fire at surface, reperforated 64-5 sand from 6,380'-6,388' with 5s f 60deg phased 4-5/8" TCP guns. RD. Turn well over to production. 0 Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp@chevron.com] Sent: Monday, October 10, 2011 1:53 PM To: Maunder, Thomas E (DOA) Cc: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Subject: Update on 64-5 Gas Storage Sand Attachments: Master Well List TIO Report 2011 10 01.x1s Tom, • Page 1 of Y 1 �o —obC> Based on this e-mail chain, it appears you would like a 64-5 sand gas storage report similar to the 77-3 sand gas storage report... even if there aren't any wells that can be used for monitoring purposes except the two storage wells themselves. Is that right?? I didn't think you needed to see this report because there aren't any wells to monitor within % mile. Sorry for the omission. It would look something like this... Notice the gap in the KGSF #1 data while the well was being worked over. Larry o From: Maunder, Thomas E (DOA) [mailto;tom.maunder@alaska.gov] Sent: Friday, April 08, 2011 11:24 AM To: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Cc: Eastham, Kevin (KEastham); Greenstein, Larry P; Whitacre, Dave S Subject: RE: Update on 64-5 Gas Storage Sand Chantal, et al, Thanks for the information regarding "other penetrations". I would presume you have the injection/production pressure/rate information similar to what is submitted for Pretty Creek 4 and 42-05X and 42-05Y? That is the information I would like submitted. Thanks in advance. Tom Maunder, PE AOGCC From: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] [mailto.WalshC@chevron.co_m] Sent: Friday, April 08, 2011 11:15 AM To: Maunder, Thomas E (DOA) Cc: Eastham, Kevin (KEastham); Greenstein, Larry P; Whitacre, Dave S Subject: Update on 64-5 Gas Storage Sand Tom, 11/8/2011 0 • Page 2 of (D The data you requested for the wells around KGSF 1 doesn't exist. The wells in the 1/2 mile radius area are abandoned or isolated from the gas storage sand. We have finished our review of the spinner/temperature/pressure logs. We received input from Halliburton log specialists as well. The sticky substance in the well bore, combined with what we are calculating as a flow rate below the sensitivity of the production tools, renders the production logs inconclusive. This analysis gave us no insight to the wellbore. We are formulating a forward plan and will discuss with you prior to moving to the next step. The 64-5 sand is not currently being utilized for production or injection purposes. Chantal From: Eastham, Kevin (KEastham) Sent: Friday, April 08, 20118:21 AM To: Greenstein, Larry P Cc: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Subject: RE: wells around 64 5 That's correct, Larry. There are no wells within %2 mile that would work for monitoring the 64-5 sand. From: Greenstein, Larry P Sent: Friday, April 08, 20117:42 AM To: Eastham, Kevin (KEastham) Cc: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Subject: RE: wells around 64 5 What this tells me is that there aren't any wells within %2 mile that are connected to surface gauges to use for monitoring the 64-5 sand (unless a plug or cement has failed)... correct?? Larry From: Eastham, Kevin (KEastham) Sent: Thursday, April 07, 2011 1:19 PM To: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Cc: Greenstein, Larry P Subject: RE: wells around 64 5 At the 64-5 reservoir level, the following wells are within a % mile radius of KGSF #1 & #7A: Attached is a map showing wells and % mile radius. (All wells below are SRU) 34-28, 314-27, 41-28, 212-27, 12-27. Notes: KGSF 2 was sidetracked out of 12-27 targeting the 62-5 sand which is above the 64-5 storage sand in #1 & #7A. Also, 314-27, 41-28, and 12-27/KGSF 2 have all been P&A'd. Similar to KGSF 2, KGSF 3 is within % mile radius, but targeted the shallower 62-5 sand as well. In 212-27, the 64-5 is beneath a cemented -in packer and two plugs (w/ cement on top of each) In 34-28, the 64-5 is beneath a cement packer. 11/8/2011 Plot Pressure & ate vs Time - Well KGSF #1 3000 2500 7 10000 _9 5/8" 10/01/11 —Tubing 0 0 —Tubing 2 8000 0 Vol Inj 09/29/11 2599 —Vol Prod 0 2000-- 2600 0 119 09/27/11 6000 v 51 09/26/11 3 X1500 -- W � v CL` 2605 0 0 09/24/11 4000 1000 — ——.._..... 09/23/11 2612 0 2000 500 — — - 0 0 09/21/11 0 0 O O M M M a �n in co n ao m 0 0 0 0 0 0 0 09/20/11 Date Tubing Tubing 2 `moo inj Vow 10/01/11 2599 0 0 09/30/11 2598 0 0 09/29/11 2599 0 0 09/28/11 2600 0 119 09/27/11 2601 0 51 09/26/11 2602 0 0 09/25/11 2605 0 0 09/24/11 2609 0 0 09/23/11 2612 0 0 09/22/11 2620 0 0 09/21/11 2804 7563 09/20/11 2694 6853 09/19/11 2756 9328 09/18/11 2740 10300 09/17/11 2674 9035 09/16/11 2626 7190 09/15/11 2690 10464 09/14/11 2649 9240 09/13/11 2591 8698 09/12/11 2571 6511 0 09/11/11 2500 4715 0 09/10/11 2526 3341 0 09/09/11 2217 354 4918 08/26/11 0 08/16/11 0 08/15/11 0 08/14/11 0 08/13/11 0 08/12/11 0 08/11/11 0 08/10/11 0 08/09/11 2400 0 79 08/08/11 2400 0 82 08/07/11 2400 0 63 08/06/112400 0 34 08/05/11 2400 0 28 11/8/2011 1:59 PM - TIO Reports 7e.xls J J Dolan TIO Report Data Sheet KGSF #1 FLOWING Permit # 1610080 API # 50-133-10160-00 04/01/2011 to 10/01/2011 Master Well List TIO Report 2011 10 01.xis KGSF #1 0 • Maunder, Thomas E (DOA From: Greenstein, Larry P [Greensteinlp@chevron.com] Sent: Saturday, October 08, 2011 10:18 AM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Brooks, Phoebe L (DOA); DOA AOGCC Prudhoe Bay Cc: Walgenbach, Christopher P.; Myers, Chris S; Eastham, Kevin (KEastham) Subject: MIT—Swanson-09-28-11 Attachments: MIT—Swanson-09-28-11 .x1s, KGSF #1 Schematic 9-28-11.doc ©� MIT_Swanson_09-2<GSF #1 Schematic 8-11.x1s 9-28-1l.doc Here is the official report of the successful MIT performed and witnessed on KGSF #1 @ SRF on 09/28/11. The new schematic for this well wasn't available at the time of the MIT, so I've attached that to this e-mail for your records. Larry STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: iim.regg(a)alaska.gov; doa.aogcc.orudhoe.bav(d-)alaska.gov; phoebe brooks(a)alaska.gov tom.maunder(a)alaska.gov OPERATOR: FIELD / UNIT 1 PAD DATE: OPERATOR REP: AOGCC REP: Union Oil Company of California Swanson River Field / SRU / P & S Yard Pad 09/28/11 Steve Shultz Jeff Jones so Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well KGSF #1 1 Type In'. I N TVD 1 6,244' Tubin 2,700 2,700 2,700 2,700 1 Interval I P.T.D. 1610080 1 Type test P Test si 1561 Casin 0 1,770 1,760 1,757 P/F P Notes: 1 bbl Diesel pumped. Post WO MIT. OA 0 10 10 10 Well I Type In'. I I TVD Tubingl Interval P.T.D.1 I Type test I I Test psi Casing P/F Notes: OA Well I Type In'. I TVD I Tubing Interval P.T.D. I Type test I Test psi Casin P/F Notes: OA Well I Type In'. I TVD I Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: OA Weil I Type In'. I TVD I Tubingl Interval P.T.D. I Type test Test psi Casingi F Notes: OA TYPE INJ Codes D = Drilling Waste G=Gas I = Industrial Wastewater N = Not Injecting W = Water TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test Form 10-426 (Revised 06/2010) MIT _Swanson _09-28-11.x1s INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover O = Other (describe in notes) 1 0 MEMORANDUM TO: Jim Regg 'Q P.I. Supervisor �11 f df �FI FROM: Jeff Jones Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, October 07, 2011 SUBJECT: Mechanical Integrity Tests UNION OIL CO OF CALIFORNIA KGSF 1 SWANSON RIVER KGSF 1 Sre: Inspector NON -CONFIDENTIAL 0 Reviewed By: P.I. Suprvjj%� Comm Well Name: SWANSON RIVER KGSF 1 API Well Number: 50-133-10160-00-00 Insp Num: mitJJ111007071447 Permit Number: 161-008-0 Rel Insp Num: Inspector Name: Jeff Jones Inspection Date: 9/28/2011 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well KGSF 1 'Type Inj. N ' TVD 6288 ` IA 0 1770 1760 1757 P.T.D 1610080: TypeTest SFT Test psi 1572 OA 0 10 10 10 Interval INITAL P/F P - Tubing 2700 2700 2700 2700 Notes: Post RWO. 1 BBL diesel pumped. oo Friday, October 07, 2011 j Page 1 of 1 Chevron Swon River �.b 1610030 MA Well KGSF #1 W Last Completed 9/9/2011 RKB = 15' of i 5' C 0' NO. Ruth CASING AND TUBING DETAIL JEWELRY DETAIL OD Item 1 SIZE WT GRADE CONN ID TOP BTM. 20" - 3 6,244' 2.870" 15' 31' 11-3/4" 47 2.813" 3.940" 11.00 Surface 2,032' 7" 29 N-80 BTC 6.184 Surface 243' 7" 26 N-80 BTC 6.276 243' 883' 7" 23 N-80 BTC 6.366 883' 4,626' 7" 26 N-80 BTC 6.276 4,626' 6,470' 7" 29 N-80 BTC 6.184 6,470' 8,315' 7" 29 P-110 8RD 6.184 8,315' 10,875' 3/4" Tubing 3-1/2" 9.3 L-80 Hydril503 2.992 Surface 6,356' of i 5' C 0' NO. Ruth ID JEWELRY DETAIL OD Item 1 2,460' 2.867" 5.020" Chemical Inj Sub w'/4" control line 2 6,228' 2.813" 4.540" Sliding Sleeve 3 6,244' 2.870" 5.983" Baker Premier Packer 4 6,297' 2.813" 3.940" X Nipple 5 6,356' 2.992" 3.500" WLEG, Auto Release 6 ±6.507' - 4.630" TCP Guns (length 32.76') Gun release not verified '/4" SS control line w/ 41 tubing clamps (one every other joint) Clamp O.D. 4.76" NO. Depth Ill ABANDONMENT DETAIL OD Item A 6,615' EZ Squeeze Packer w/ 75' cement on top B 6,652' - Fish: 2 Baker K-1 Retainers C 6,850' - PosiSet Plug w/ 37' Cement D 9,015' Tubing cut at 9,015' WLM. E 9,733' - Top of Cement Plug. Pressure tested to 2,500 psi. F 10,473' - Camco "MM" Mandrel with CEV Valve G 10,519' - Brown CC Safety Joint H 10,530' - - Brown, 2-7/8" x 7", Type HS -16-1 Packer I 10,600' - Cameo "D" Nipple J ? - Venturi Shoe Notes NO Depth Item K 7,114' 7" Stage Collar DUDRnD A TinV 141QTnRV /TvnnA - Pprfe TIT Lnu Di -nth) PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.25° @ 4,565' KGSF #1 WBD 9-28-2011.doem Revised by: CVK REVISED: 9-28-2011 Interval ccum. Date Zone To Btm Amt s f Comments 9/8/2011 64-5 6,380' 6,388' 8' 5 Reperf 4-5/8" Millenium TCP guns, 5sp� 60 deg 12/3/1998 64-5 6,380' 6,388' 8' 4 1-11/16" Pivot, 180 deg. 7/26/1998 68-0 6,883' 6,911' 28' 4 Abandoned 6/20/1961 - 10,615' 10,616' 1' 5 Abandoned 6/21/1961 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/1961 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/1961 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/1961 10,752' 10,754' 2' 5 Abandoned PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.25° @ 4,565' KGSF #1 WBD 9-28-2011.doem Revised by: CVK REVISED: 9-28-2011 Chevron Chantal R Walsh Union Oil Company of California Petroleum Engineer, P.E. 3800 Centerpoint Dr., Suite 100 Anchorage, AK 99503 Tel: 907-263-7627 Email walshcalshc@thechevron.com VW August 12, 2011 AUG 1? 7.011 Mr. Dan Seamount, Chairman A6*8 ON & Ca$ Cdarc.. & Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 A MWW Anchorage, AK 99501-3539 RE: 2011 Annual Material Balance Calculations of Production and Infection Volumes: Kenai Gas Storage Facility #1 (KGSF#1). Swanson River Field Dear Commissioner Seamount: k (. \-ooh Attached for Alaska Oil and Gas Conservation Commission (AOGCC) review is the 2011 annual material balance calculation of production and injection volumes for the Kenai Gas Storage Facility #1 (KGSF#1), as required per Storage Injection Order #2A. This material balance includes all primary production from the Tyonek 64-5 reservoir (via the SRU 43-28 wellbore), as well as all storage operations from the two gas storage wells, KGSF #1 and KGSF #7A. Primary production occurred from December 1998 through May 2001 and storage operations are on-going since June 2001. Attachment #1 is a table of monthly gas production and injection volumes for KGSF #1 (formerly SRU 43-28) and KGSF #7A, from the commencement of primary production, through August 12, 2011. Pressures from the Tyonek 64-5 reservoir have been measured/estimated from both downhole pressure buildups and from surface shut-in tubing pressures. The surface readings were then converted to downhole pressures at a common datum of 6,395 ft TVD. These data points are tabulated in Attachment #2 and plotted versus the net cumulative production (production less injection) on the standard P over Z plot, shown in Attachment #3. As noted in previous Annual Material Balance reports, Attachment #3 shows that the early injection cycle pressures deviated above the straight line path established by the primary depletion pressure points. Following the primary production and injection cycle, the next two or three cycles (production & injection) show a consistent trend of the pressure/cumulative production data points migrating further left of the straight line path established by the primary depletion pressure points. Over the last four years, cycles from 2007 — 2010 were fairly consistent, indicating continued reservoir confinement of the gas storage volume. The last injection/production season, 2010 — 2011, showed a deviation from the previous years' trends. At the end of the production cycle the KGSF #1 well had water in the well bore which was not MidContinent/Alaska/Chevron North America Exploration and Production www.chevron.com present in the KGSF #7A well. This led us to suspect a mechanical issue with KGSF #1. We are currently working over this well, and hope to resolve the issues. If you or your staff has any questions regarding this annual report, please contact me at 263- 7627. Sincerely, (�" t/lJ IL Chantal Walsh Petroleum Engineer, P.E. Attachments: 1. KGSF #1 Facility Monthly production and injection volumes 2. Tyonek 64-5 Sand POZ Data 3. KGSF #1 Facility (Tyonek 64-5 Sand) - P/Z vs Cumulative Production Plot CC: Whitacre, Dave KGSF #1 Well File KGSF #7 Well File MidContment/Alaska/Chevron North America Exploration and Production http //www.chevron com ATTACHMENT #1 0:1NAU\MCBU\Alaska\Depts\AssetDev\ClGas\Gas Un0penmind\Swanson\Swanson RiverUnit\KGSF#1\Surveys\Pressures\AOGCC AMB Rpt\201 OWGSF #1 #7 8-12-11.xis KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES AMENDED - 08/18/11 SRU 43-281 KGSF #1 1 KGSF VA �1 Tyonek 64-5 Sand Totals Monthly Monthly Monthly Monthly Net Voidage Total Gas Gas Gas Gas Gas (Prod - Inj) Inventory Inj. Prod. Inj. Prod. Cum for POZ (Gas -in -Place) Month MCF MCF IJICF MCF MCF MCF 1,544,000 Dec -98 0 55,137 55,137 1,488,863 Jan -99 0 79,404 134,541 1,409,459 Feb -99 0 64,367 198,908 1,345,092 Mar -99 0 73,920 272,828 1,271,172 Apr -99 0 62,180 335,008 1,208,992 May -99 0 76,912 411,920 1,132,080 Jun -99 0 76,903 488,823 1,055,177 Jul -99 0 72,268 561,091 982,909 Aug -99 0 60,311 621,402 922,598 Sep -99 0 48,667 670,069 873,931 Oct -99 0 42,056 712,125 831,875 Nov -99 0 39,385 751,510 792,490 Dec -99 0 33,783 785,293 758,707 Jan -00 0 39,890 825,183 718,817 Feb -00 0 20,895 846,078 697,922 Mar -00 0 38,219 884,297 659,703 Apr -00 0 35,729 920,026 623,974 May -00 0 22,502 942,528 601,472 Jun -00 0 8,627 951,155 592,845 Jul -00 0 30,397 981,552 562,448 Aug -00 0 56,660 1,038,212 505,788 Sep -00 0 30,505 1,068,717 475,283 Oct -00 0 29,330 1,098,047 445,953 Nov -00 0 48,633 1,146,680 397,320 Dec -00 0 29,741 1,176,421 367,579 Jan -01 0 46,236 1,222,657 321,343 Feb -01 0 47,777 1,270,434 273,566 Mar -01 0 37,213 1,307,647 236,353 Apr -01 0 24,719 1,332,366 211,634 May -01 0 6,196 1,338,562 205,438 Jun -01 106,800 0 1,231,762 312,238 Jul -01 219,660 0 1,012,102 531,898 Aug -01 226,151 0 785,951 758,049 Sep -01 197,762 1,331 589,520 954,480 Oct -01 44,964 60,382 604,938 939,062 Nov -01 73,130 142,418 674,226 869,774 Dec -01 28,281 159,046 804,991 739,009 Jan -02 134,429 47,741 718,303 825,697 Feb -02 102,768 65,400 680,935 863,065 Mar -02 250,716 4,507 434,726 1,109,274 Apr -02 107,164 51,031 378,593 1,165,407 May -02 89,218 16,147 305,522 1,238,478 Jun -02 106,081 3,868 203,309 1,340,691 0:1NAU\MCBU\Alaska\Depts\AssetDev\ClGas\Gas Un0penmind\Swanson\Swanson RiverUnit\KGSF#1\Surveys\Pressures\AOGCC AMB Rpt\201 OWGSF #1 #7 8-12-11.xis ATTACHMENT #1 O:\NAU\MCBUWIaska\Depts\AssetDeviCIGas\Gas CFT\Openmind\Swanson\Swanson RiverUnit\KGSF#115urveys\Pressures\AOGCC AMS Rpt12010\KGSF #1 #7 8-12-11.xIs KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES AMENDED - 08/18/11 SRU 43-28 1 KGSF #1 (--KGSF #7A Tyonek 64-5 Sand Totals Monthly Monthly Monthly Monthly Net Voidage Total Gas Gas Gas Gas Gas (Prod - Inj) inventory Inj. Prod. Inj. Prod. Cum for POZ (Gas -In -Place) Month MCF MCF MCF MCF MCF MCF Jul -02 66,737 18,479 155,051 1,388,949 Aug -02 19,263 140,660 276,448 1,267,552 Sep -02 73,737 60,587 263,298 1,280,702 Oct -02 0 272,859 536,157 1,007,843 Nov -02 0 193,970 730,127 813,873 Dec -02 701 149,810 879,236 664,764 Jan -03 0 125,601 1,004,837 539,163 Feb -03 0 77,767 1,082,604 461,396 Mar -03 0 58,978 1,141,582 402,418 Apr -03 0 40,867 1,182,449 361,551 May -03 0 31,252 1,213,701 330,299 Jun -03 0 23,977 1,237,678 306,322 Jul -03 0 17,937 1,255,615 288,385 Aug -03 0 9,611 1,265,226 278,774 Sep -03 173,513 0 1,091,713 452,287 Oct -03 298,780 0 792,933 751,067 Nov -03 287,672 0 505,261 1,038,739 Dec -03 264,137 1,456 242,580 1,301,420 Jan -04 30,651 56,710 268,639 1,275,361 Feb -04 42,508 56,096 282,227 1,261,773 Mar -04 18,083 153,053 417,197 1,126,803 Apr -04 46,661 49,678 420,214 1,123,786 May -04 173,756 1,811 248,269 1,295,731 Jun -04 117,522 0 130,747 1,413,253 Jul -04 3,936 0 126,811 1,417,189 Aug -04 0 0 126,811 1,417,189 Sep -04 83,061 0 43,750 1,500,250 Oct -04 20,297 37,277 0 38,408 99,138 1,444,862 Nov -04 100,085 46,394 114,424 0 -68,977 1,612,977 Dec -04 1,372 5,222 1,523 3,687 -62,963 1,606,963 Jan -05 35,347 66,988 771 60,345 28,252 1,515,748 Feb -05 31,778 82,231 3,217 114,252 189,740 1,354,260 Mar -05 43,588 55,099 1,211 78,836 278,876 1,265,124 Apr -05 28,607 35,501 8,081 19,522 297,211 1,246,789 May -05 32,140 88,209 18,126 101,966 437,120 1,106,880 Jun -05 116,349 2,892 60,975 2,436 265,124 1,278,876 Jul -05 79,421 4,803 96,626 740 94,620 1,449,380 Aug -05 56,470 60,228 61,086 25,369 62,661 1,481,339 Sep -05 75,912 16,301 8,356 11,394 6,088 1,537,912 Oct -05 44,207 68,184 13,635 94,247 110,677 1,433,323 Nov -05 68,267 45,043 65,065 62,387 84,775 1,459,225 Dec -05 68,931 29,178 97,297 20,153 -32,122 1,576,122 Jan -06 24,400 154,713 21,678 176,620 253,133 1,290,867 Feb -06 123,934 83,744 191,098 99,388 121,233 1,422,767 O:\NAU\MCBUWIaska\Depts\AssetDeviCIGas\Gas CFT\Openmind\Swanson\Swanson RiverUnit\KGSF#115urveys\Pressures\AOGCC AMS Rpt12010\KGSF #1 #7 8-12-11.xIs ATTACHMENT #1 O:\NAU\MCBU\Alaska\Depts\AssetDevlClGas\Gas CFROpenmind\Swanson\Swanson RiverUnit\KGSF#1 \Surveys\Pressures\AOGCC AMB Rpt\2010\KGSF #1 #7 8-12-11.As KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES AMENDED - 08/18/11 SRU 43-281 KGSF #1-KGSF #7A 1 Tyonek 64-5 Sand Totals Monthly Monthly Monthly Monthly Net Voidage Total Gas Gas Gas Gas Gas (Prod - Inj) Inventory Inj. Prod, Inj. Prod. Cum for POZ (Gas -In -Place) Month MCF MCF MCF MCF MCF MCF Mar -06 54,898 145,807 3E,421 147,941 324,662 1,219,338 Apr -06 131,597 34,604 88,982 19,989 161,676 1,382,324 May -06 106,658 4,759 110,,253 26,840 -23,636 1,567,636 Jun -06 50,042 675 14,923 482 -87,444 1,631,444 Jul -06 0 79,130 0 36,777 28,463 1,515,537 Aug -06 63,182 130 1E,045 0 -50,634 1,594,634 Sep -06 45,366 0 1E,939 0 -114,939 1,658,939 Oct -06 18,013 58,243 42,099 7,334 -109,474 1,653,474 Nov -06 30,592 82,779 24,730 98,430 16,413 1,527,587 Dec -06 55,743 17,160 102,029 14,959 -109,240 1,653,240 Jan -07 21,586 59,415 34,936 91,755 -14,592 1,558,592 Feb -07 7,025 59,181 41,275 106,823 103,112 1,440,888 Mar -07 15,008 58,203 83,830 92,486 154,963 1,389,037 Apr -07 75,784 6,866 185,316 8,751 -90,520 1,634,520 May -07 8,872 23,772 32,655 55,100 -53,175 1,597,175 Jun -07 11,714 0 740 134 -65,495 1,609,495 Jul -07 7,350 0 0 0 -72,845 1,616,845 Aug -07 1,767 891 230 0 -73,951 1,617,951 Sep -07 0 253 0 240 -73,458 1,617,458 Oct -07 9,706 18,077 11,553 6,168 -70,472 1,614,472 Nov -07 13,638 40,135 7,563 8,237 -43,301 1,587,301 Dec -07 8,443 61,237 3,820 132,338 138,011 1,405,989 Jan -08 20,892 75,223 751 88,161 279,752 1,264,248 Feb -08 8,162 54,785 8,134 83,015 401,256 1,142,744 Mar -08 94 1,014 0 4,872 407,048 1,136,952 Apr -08 46,111 3,360 11,372 0 352,925 1,191,075 May -08 88,929 12,687 218,106 12,037 70,614 1,473,386 Jun -08 20,487 4,309 32,741 0 21,695 1,522,305 Jul -08 8,057 0 2,181 0 11,457 1,532,543 Aug -08 19,270 484 0 0 -7,329 1,551,329 Sep -08 5,064 1,530 0 820 -10,043 1,554,043 Oct -08 15,323 46,294 2,459 5,913 24,382 1,519,618 Nov -08 3,361 95,514 0 82,213 198,748 1,345,252 Dec -08 10,856 92,077 7,285 162,128 434,812 1,109,188 Jan -09 25,898 54,278 31,732 114,632 546,092 997,908 Feb -09 26,994 50,408 42,968 76,145 602,683 941,317 Mar -09 25,801 14,995 10,298 22,451 604,030 939,970 Apr -09 158,105 989 236,991 608 210,531 1,333,469 May -09 36,786 103 134,138 27 39,737 1,504,263 Jun -09 43,429 519 103,093 299 -105,967 1,649,967 Jul -09 0 0 0 274 -105,693 1,649,693 Aug -09 0 39,305 45,129 228 -111,289 1,655,289 Sep -09 0 25,743 24,073 146 -109,473 1,653,473 Oct -09 0 0 28,450 271 -137,652 1,681,652 O:\NAU\MCBU\Alaska\Depts\AssetDevlClGas\Gas CFROpenmind\Swanson\Swanson RiverUnit\KGSF#1 \Surveys\Pressures\AOGCC AMB Rpt\2010\KGSF #1 #7 8-12-11.As ATTACHMENT #1 KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTIO14 AND INJECTION VOLUMES AMENDED - 08/18111 Month SRU 43-281 KGSF #1 Monthly Monthly Gas Gas Inj. Prod. MCF MCF KGSF #7A = Monthly Monthly Gas Gas Inj. Prod. MCF MCF Tyonek 64-6 Sand Totals Net Voidage Total Gas (Prod - Inj) Inventory Cum for POZ (Gas -In -Place) MCF MCF Nov -09 550 15,175 34,114 33,063 -124,078 1,668, 078 Dec -09 137 8,539 11,074 66,621 -60,129 1,604,129 Jan -10 10,556 36,797 0 12,397 -21,491 1,565,491 Feb -10 0 48,589 17 2,232 29,313 1,514,687 Mar -10 0 64,473 0 54,969 148,755 1,395,245 Apr -10 0 13,709 135 19,853 182,182 1,361,818 May -10 0 15,589 10,554 27,926 215,143 1,328,857 Jun -10 384 4,530 189 7,769 226,869 1,317,131 Jul -10 1,616 0 0 490 225,743 1,318,257 Aug -10 101,371 0 100,659 0 23,713 1,520,287 Sep -10 139,173 100 164,053 86 -279,327 1,823,327 Oct -10 55197 12608 45,549 8,241 -359,224 1,903,224 Nov -10 56236 46322 46,917 40,527 -375,528 1,919,528 Dec -10 15497 137723 25,327 165,640 -112,989 1,656,989 Jan -11 3983 187449 7,665 194,272 257,084 1,286,916 Feb -11 0 113321 0 158,649 529,054 1,014,946 Mar -11 0 20680 0 92,628 642,362 901,638 Apr -11 6736 1922 0 502 638,050 905,950 May -11 0 0 52,265 0 585,785 958,215 Jun -11 0 0 444,594 0 141,191 1,402,809 O:WAU\MCBU\Alaska\Depts\AssetDev\C]Gas\Gas CFT\Openrnind\Swanson\Swanson Rive rUnit\KGSF#1\Surveys\PressureAAOGCC AMB Rpt\2010\KGSF #1 #7 8-12-11.xis • ATTACHMENT #2 • Tyonek 64-5 Sand POZ DATA Kenai Gas Storage Facility 41 (KGSF #1) Wells: KGSF #1 & KGSF #7A 2001 INJECTION CYCLE 6/9/2001 SITP 0 1339 380 441 09566 461 SITP 7/11/2001 SITP 0 1 148 875 1015 0.9078 1118 21 hr SIT? after 618 hr in ecrion 9/18/2001 SITP 0 0.673 1820 2111 0.8578 2461 4 hr SITP prior to flow due to SITP ESD 9/20/2001 SITP 0 0 678 1810 2099 08580 2447 24 hr SIT? after I da of flow on 9/19 at 5.5 nrmcfd 10/9/2001 SIT? 0 0 572 1980 2297 1 08562 2682 8 day SITP during C12 restaging 2002 INJECTION CYCLE SITP 1 0 1 0 167 1 2231 1 2587 1 08576 1 3017 10/9/2001 SITP 0 1 21751 1980 2297 0.8562 2682 8 da SITP duringC12 restaging 4/5/2002 SITP 0 0 40 2280 2645 0 8584 3081 115 hour SITP 7/12/2002 SITP 0 1 0 190 1 2620 1 3039 1 0.8680 1 3501 ISITI, 7/26/2002 SITP 0 1 0200 1 2630 1 3050 1 08684 1 3513 ISITP 2002/2003 PRODUCTION CYCLE 7/26/2002 SITP 1 0 1 0200 1 2630 3050 1 08684 1 3513 1SITP 12/5/2002 SITP 1 0 1 0 740 1 1415 1641 1 0.8709 1 1884 1 SITP 65 hr SI 7/25/2003 SITP 1 0 1 1 252 1 224 260 1 09739 1 267 1 SITP from surf PBU 2003 INJECTION CYCLE 7/25/2003 SITP 0 1 1 252 1 224 1 260 1 09739 1 267 1 SITP from surf PBU 12/29/2003 SITP 0 1 0 254 1 2440 1 2829 1 08620 1 3282 ISI duration = 19 firs At shut in = 2 Ins, 2440 psig SITP; Ignores FL 2003/2004 PRODUCTION CYCLE 12/29/2003 SITP 0 0.254 2440 2829 08620 3282 SI duration = 19 firs At shut in = 2 hrs, 2440 si SITP, Ignores FL 4/28/2004 SITP1 0 1 0 445 1 2075 1 2406 1 0.8562 1 2810 1 SITP - 24 hr 20041NJEULION CYCLE 4/28/2004 SITP i 0 1 0 445 1 2075 1 2406 1 08562 1 2810 1 SITP - 24 hr 7/14/2004 SITP 1 0 1 0.153 1 2565 1 2974 1 08660 1 3435 1 SITP - 12 day 12/5/2004 SITP 1 0 1 -0082 1 2865 1 3322 1 08789 1 3780 1 SITP-4day 2004/2005 PRODUCTION CYCLE 12/5/2004 SITP 0 -0082 2865 3322 08789 3780 SITP-4da 6/8/2005 SITP 0 1 0 396 1 2080 1 2412 1 0.8562 1 2817 ISLIP - 6 hr 1 12/30/20051 1 0 1 -0044 1 2786 1 3231 1 08751 1 3692 1SITP - 3 days I 2005/2006 PRODUCTION CYCLE 12/30/2005 0 -0044 2786 3231 0.8751 3692 SITP - 3 days 3/22/2006 SITP 1 0 1 0 396 1 1905 1 2209 1 08567 1 2579 SITP - < I day (KGSF#7a) IMI 2007 INJECTION CYCLE 3/26/2007 SITP 1 0 1 0 167 1 2231 1 2587 1 08576 1 3017 1 SITP -4 da KGSF#I 4/27/2007 SITP 0 -0117 2828 3279 0.8771 3739 SITP -8 da KGSF#I 6/4/2007 SITP 0 -0065 2711 3144 1 08717 1 3606 1 SITP -5 da GSF41 9/11/2007 SITP 0 -0088 2717 3151 1 08720 1 3598 ISITP -27 da GSF91 2007/2008 PRODUCTION CYCLE 9/11/2007 SITP 0 -0.088 2717 3151 0.8720 3598 SITP -27 da GSF#1 12/2/2007 SITP 0 -0.043 2604 3005 0.8669 3466 SITP - 6 days(KGSF #7A - PMW 1/17/2008 SITP 0 0 243 2078 2397 08562 2800 1 SITP - 8 days KGSF #7A 4/8/2008 SITP 0 0.407 1760 2026 08592 2358 1 SITP - 37 days KGSF #7A 2008 INJECTION CYCLE 4/8/2008 SITP 0 0 407 1760 2026 08592 2358 SITP - 37 days KGSF #7A 5/2/2008 SITP 0 0 353 1925 2218 0.8566 2567 SITP - —2 months(KGSF 47A 7/1/2008 SITP 0 0.022 2643 3049 08694 3494 SITP - 22 da KGSF#I 7/28/2008 SITP 0 0 015 2648 3055 0.8686 3517 SITP - 22 days KGSF #1 9/16/2008 SITP 0 -0005 2664 3073 0.8692 3535 SITP - 22 days(KGSF #1 9/30/2008 SITP 0 4010 2670 3080 0.8694 3543 SITP - 5 days (KGSF #1) 8/15/201112'54 PMO'WAUIMCBU\Aluka\Depts\AssetDev\CIGas\Gas CFnOpenound\Swanson\Swanson RiverUmt\KGSF41\Surveys\Pressures\AOGCC AMB Rpt\2011\KGSF#1 & 47A 64-5 Sd ALL POZ 7-11- 1 l.x1s64-5 POZ Data 0 ATTACHMENT #2 • Tyonek 64-5 Sand POZ DATA Kenai Gas Storage Facility 91 (KGSF #1) Wells: KGSF #1 & KGSF #7A Date IType Test I Gauge De th, ft I Cum, bcf I ThgP, psia I Res P, psia I Z I P/Z lCumments 2008/2009 PRODUCTION CYCLE 9/30/2008 SITP 0 1 -0.010 2670 3080 0.8694 3543 SITP - 5 days(KGSF #1 1/16/2009 SITP 0 0.576 1392 1599 08728 1832 SITP - 2,5 days KGSF 41 2/19/2009 SITP 0 0,626 1376 1579 08737 1807 SITP - 24 hr SI (KGSF 91 & #7A) 2009 INTFCTION CYCLE 2/19/2009 SITP 0 0,626 1376 1579 1 08737 1 1807 SITP - 24 hr SI (KGSF #1 & #7A) 6/14/2009 SITP 0 -0065 2781 3209 1 08742 1 3671 SITP - 10 days SI(KGSF 41 7/13/2009 SITP 0 -0106 2850 3287 1 08774 1 3746 1 SITP - 14 days SI(KGSF #1 8/10/2009 SITP 0 -0 106 2828 3262 1 08764 1 3722 ISITP - 42 days SI (KGSF 47A) 7009/2010 PRODT IC.TION CYCI.F 10/12/2009 SITP 0 -0109 2774 3218 08746 3680 SITP - 23 days(KGSF #7A 1/24/2010 SITP 0 -0012 2630 3036 08679 3498 SITP - 4 days KGSF #1 3/8/2010 SITP 0 0.035 2528 2919 08644 3377 1 SITP - 4 &y SI KGSF #1 & 47A 5/13/2010 SITP 0 0.181 2231 2576 1 08575 3004 ISITP - 24 firs SI (KGSF #1) 2010 INTFCTION CYCT F 5/13/2010 SITP 0 0 181 2231 2576 08575 3004 SITP - 24 hrs SI(KGSF 41 8/11/2010 SITP 0 0.176 2313 2671 0.8588 3110 SITP - 14 days SI KGSF #1 10/20/2010 SITP 0 -0.359 3134 3626 0.9042 4009 2010/2011 PRODUCTION CYCLE 10/20/2010 SITP 0 -0359 3134 3626 08842 4009 12/8/2010 SITP 0 -0349 3021 3500 0.8775 3895 SITP - 24 hours 12/21/2010 SITP 0 -0200 2727 3176 0.8626 3577 1 day Si 3/1/2011 SITP 0 0 533 1123 1310 0.8799 1472 48 hr SI 3/21/2011 Gua a PBU 5300 0 643 1171 0.8895 1316 2011 INJECTION CYCLE 3/21/2011 JG.t,PBU 1 5300 0643 1171 0.8895 1316 7/4/2011 Gua'e PBU 5300 0 092 2720 1 0.8628 1 3152 172 hour shut in 7/31/2011JWHP 1 0 1 0092 1 2395 1 2796 1 0.8644 1 3235 13 weeks shun In 8/15/201112 54 PMO\NAUUNCBU\Alwka\Depts\AssetDev\CIGas\Gas CFT1Openmmd\Swanson\Swanson RiverUnit\KGSF41\Surveys\Pressures\AOGCC AMB Rpt\2011\KGSF91 & #7A 64-5 Sd ALL POZ 7-11- 11 x1s64-5 POZ Data ATTACHMENT #3 KGSF #1 FACILITY (Tyonek 64-5 Sand) - P/Z vs Cumulative Production Plot 4500 - -0 Primary 4000 . . ..... — ------- —,Or—'01 l.j cycle --*--03 Prod Cycle 3500 --E--03 Inj Cycle 0 08 Prod Cycle 3000 6 08 Inj Cycle 2500 0 09 Prod Cycle 6 09 Inj Cycle 2000 — 10 Prod Cycle 1500 10 Inj Cycle I I Prod/Inj Cycle 1000 500 ------ 0 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 Cumulative Gas Produced (Bcf) 0:\NAU\MCBU\Aiaska\Depts\AssetDev\ClGas\Gas CFT\Openmind\Swanson\Swanson RiverUnit\KGSF# I \Surveys\Pressures\AOGCC AMB Rpt\201 I \KGSF# I & 47A 64-5 Sd ALL POZ 7-11-1 1.x1s Page 1 of Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, August 12, 2011 1:18 PM To: 'PORHOLA, STAN T'; Regg, James B (DOA); Aubert, Winton G (DOA) Cc: Menapace, Michael Sam; Sunderland, Sloan [Swift Technical Services]; Leslie, Mike; Lott, James C. [Swift Technical Services]; Nienhaus, Doug R; Kanyer, Christopher V; Chanley, Clint M [APRS] Subject: RE: Change to BOPE on Sundry 311-239, KGSF #1 (PTD 161-008) Thanks much Stan. I do not see an issue with the substitution. Tom Maunder, PE AOGCC From: PORHOLA, STAN T[ma iIto: stan.porhola@chevron.com] Sent: Friday, August 12, 2011 1:15 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Aubert, Winton G (DOA) Cc: Menapace, Michael Sam; Sunderland, Sloan [Swift Technical Services]; Leslie, Mike; Lott, James C. [Swift Technical Services]; Nienhaus, Doug R; Kanyer, Christopher V; Chanley, Clint M [APRS] Subject: RE: Change to BOPE on Sundry 311-239, KGSF #1 (PTD 161-008) Tom, The accumulator sizing calculations are as follows: Pre -charge pressure: 1,000 psi Operating pres sure: 3,000 psi Min Operating Pressure: 1,200 psi Bottle volume (total): 15 gallons/bottle Bottle volume (useable): 7.5 gallons/bottle # of Bottles: &nbs p; 16 bottles Useable fluid (total): 16 bottles x 7.5 gallons/bottle = 120 gallons Volume to close Annular: 18.67 gallon Volume to close Pipe Ram: 8.23 gallon Volume to open HCR: & nbsp; 1.00 gallon Total volume required: 18.67 + 8.23 + 1.00 = 27.9 gallons Volume required per 25.286 150% = 27.9 gallons x 1.5 = 41.85 gallons Let me know if you need any additional information. Stan Porhola00 Drilling Engineer MidContinent/Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Dr. Suite 100 Anchorage, AK 99503 Tel 907 263 7640 Fax 907 263 7884 Cell 907 229 1769 stan.porhola@chevron.com llail Confirloilial Footer Privileged/Confidential information may be contained in, or attached to, this message. If you are not the addressee i ndicated in this message (or responsible for delivery of the message to such person), you may not copy, forward, disclose, deliver, or otherwise use 8/12/2011 Page 2 of Y3 this message or any part of it in any form whatsoever. If you receive the message in error, you should destroy this message after notifying me immediately by replying to the message or contacting me at (907) 263-7640. From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, August 12, 2011 12:38 PM To: PORHOLA, STAN T; Regg, James B (DOA); Aubert, Winton G (DOA) Cc: Menapace, Michael Sam; Sunderland, Sloan [Swift Technical Services]; Le slie, Mike; Lott, James C. [Swift Technical Services]; Nienhaus, Doug R; Kanyer, Christopher V; Chanley, Clint M [APRS] Subject: RE: Change to BOPE on Sundry 311-239, KGSF #1 (PTD 161-008) Stan, Neither Winton nor Jim is here today. Would you provide the accumulater sizing calculations to demonstrate the requirements of 20 AAC 25.286 (d)(4)(A) are met? Thanks, Tom Maunder, PE AOGCC From: PORHOLA, STAN T [mailto:stan.porhola@chevron.com] Sent: Friday, August 12, 2011 12:30 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA); Aubert, Winton G (DOA) Cc: Menapace, Michael Sam; Sunderland, Sloan [Swift Technical Services]; Leslie, Mike; Lott, James C. [Swift Technical Services]; Nienhaus, Doug R; Kanyer, Christopher V; Chanley, Clint M [APRS] Subject: Change to BOPE on Sundry 311-239, KGSF #1 (PTD 161-008) Tom, Jim, and Winton, Per the approved Sundry 311-239 for well KGSF #1 (PTD 161-008), we had planned to use an 11" BOP stack with an 11" Hydril GK Annular Preventer. Based on equipment availability from Weatherford, we are requesting approval to use an 11" Shaffer LWS Annular Preventer in place of the Hydril GK Annular Preventer. B oth are rated at 5,000 psi. Our accumulator system has sufficient capacity to accommodate the change in hydraulic fluid requirements for the Shaffer vs. the Hydril GK. For comparison, the Hydril GK volumes to close and open on open hole are 9.81 and 7.98 gallons respectively. For the Shaffer LWS, volumes to close and open on open hole are 18.67 and 14.59 gallons respectively. The accumulator size is 240 gallons made up from 16 each 15 gallon bottles, with a 462 gallon reservoir. We plan to use this same BOPE setup for other wells at Swanson River using the Key Energy Pulling Unit Rig #3. We would also request approval to use the 11" Shaffer LWS Annular Preventer for the sundry submitted on 8/04/2011 for well SRU 32A-33 (PTD 191-014). No other changes are planned for the BOPE setup at this time. Union Oil Company of California will be submitting additional sundries for work at Swanson River that will reflect this change. If you have any questions, please let me know. Stan Porhola*• Drilling Engineer Mid Continent/Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Dr. Suite 100 Anchorage, AK 99503 Tel 907 263 7640 Fax 907 263 7884 Cell 907 229 1769 stan.pgtola@qhevron.com 8/12/2011 zu ED ALASEA / SEAN PARNELL, GOVERNOR Timothy C. Brandenburg Drilling Manager Union Oil Company of California A.AAMW A G 0,� !? P.O. Box 196247 Anchorage, AK 99519 (� Re: Swanson River Field, Hemlock Oil Pool, Swanson River KGSF # 1 Sundry Number: 311-239 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 or weekend. Sincerely, (Z) Daniel T. Seamount, Jr. h J Chair DATED this 2. day of August, 2011. Encl. yott STATE OF ALASKA �J .�• �' !-! i `� i 1 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS rtb : ission in ajar, ,>r onnri 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate Q Pull Tubing ❑✓ Time Extension ❑ Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Install Isolation Plug Q 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development ❑ Exploratory ❑ Stratigraphic ❑ Service ❑✓ 161-008 - 3. Address: 6. API Number: PO Box 196247, Anchorage, AK 99519 50-133-10160-00 - 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No ❑� Swanson River KGSF#1 - 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028399 (Swanson River Unit) Swanson River Field/ 64-5 Tyonek Gas Storage, Hemlock Oil & Tyonek Undef Gas Pools 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): 1 Effective Depth TVD (ft): Plugs (measured): 1 1 Junk (measured): 10,875 10,875 6,653 6,653 6,813' 6,653' (Fill) Casing Length Size MD / TVD Burst Collapse Structural Conductor 31' 20" 31' 31' Surface 2,032' 11-3/4" 2,032' 2,032' Intermediate Production 10,875' 7" 10,875' 10,875' 6,340psi 3,830psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: ubing MD (ft): 6,380-6,388 6,380-6,388 13-1/2" 19.3* L-80 T6,354 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker SAB -3 Packer and N/A 6,288'(MD)/ 6,288'(TVD) and N/A ' 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑� Exploratory ❑ Development ❑ Service ❑Q 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/10/2011 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ 16. Verbal Approval: Date: Commission Representative: N/A GSTOR SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chris Kanyer 263-7831 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature Phone 276-7600 Date 7/26/2011 COMMISSION USE ONLY Notify Commission that may witness Sundry Number: Conditions of approval: so a representative Plug Integrity ❑ BOP Test [011" Mechanical Integrity Test Location Clearance ❑ Other: t eS� vOP� l0 3d00 Well o�P+-✓�,. � t4 C. �e ;►1 auordat.�e�t wci{ S{'arac�t y h._ ✓d�tY �O• 7• Subsequent Form Required: j D — Lf D . APPROVED BY �7 / Approved by: COMMISSIONER THE COMMISSION Date: V __Form 10-403 Revised 1/2 M6 -V16 AUG 0 2 2011 Submit in Duplicate Chevron is Swon River We on River #1 Last Completed 7/27/09 RKB = 15' 3/4" A f' PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.251 @ 4,565' KGSF #1 Actual WBD 7-19-201 l.docm Revised by: CVK REVISED: 7-19-2011 % I PERFORATION HISTORY T onek Perfs TDT Lo CASING AND TUBING DETAIL JEWELRY DETAIL NO. De th SIZE WT GRADE CONN ID 6,273' TOP BTM. 20" - 6,287' 2.992 3.500 15' 31' 11-3/4" 47 - Baker SAB -3 Permanent Packer 11.00 Surface 2,032' 7" 29 N-80 BTC 6.184 Surface 243' 7" 26 N-80 BTC 6.276 243' 883' 7" 23 N-80 BTC 6.366 883' 4,626' 7" 29 N-80 BTC 6.184 4,626' 5,013' 7" 26 N-80 BTC 6.276 5,013' 6,470' 7" 29 N-80 BTC 6.184 6,470' 8,315' 7" 29 P-110 8RD 6.184 8,315' 10,875' Tubing Brown, 2-7/8" x 7", Type HS -16-1 Packer G 10,600' - - Camco "D" Nipple 3-1/2" 9.3 L-80 Hydril503 2.992 15' 6,354' PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.251 @ 4,565' KGSF #1 Actual WBD 7-19-201 l.docm Revised by: CVK REVISED: 7-19-2011 % I PERFORATION HISTORY T onek Perfs TDT Lo Depth) JEWELRY DETAIL NO. De th ID OD Item 1 6,273' 2.813 3.500 XD Sliding Sleeve (Opens Down) [Closed 7/26/091 2 6,287' 2.992 3.500 K-22 Anchor 3 6,288' 3.250 5.687 Baker SAB -3 Permanent Packer 4 6,344' 2.813 3.500 X Nipple 5 6,354' 2.992 3.500 Wireline Entry Guide 1' 5 Abandoned 6/21/61 H-1 10,617 10,631' 14' ABANDONMENT DETAIL NO. De th ID OD Item A 6,850' - - PosiSet Plug w/ 37' Cement B 9.015' - - Tubing cut at 9,015' WLM. C 9,733' - - Top of Cement Plug. Pressure tested to 2,500 psi. D 10,473' - - Camco "MM" Mandrel with CEV Valve E 10,519' - - Brown CC Safety Joint F 10,530' - - Brown, 2-7/8" x 7", Type HS -16-1 Packer G 10,600' - - Camco "D" Nipple H ? - - Venturi Shoe Notes NO. De th Item I 7,114' 7" Stage Collar PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.251 @ 4,565' KGSF #1 Actual WBD 7-19-201 l.docm Revised by: CVK REVISED: 7-19-2011 % I PERFORATION HISTORY T onek Perfs TDT Lo Depth) Interval Accum. Date Zone Top B m Amt s f Comments 12/3/98 64-5 6,380' 6,388' 8' 4 1-11/16' Pivot, Iso deg. 7/26/98 68-0 6,883' 6,91 F 28' 4 Abandoned 6/20/61 - 10,615' 10,616' 1' 5 Abandoned 6/21/61 H-1 10,617 10,631' 14' 4 Abandoned 6/21/61 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/61 H 4/5 10664' 10,75T 88' 4 Abandoned 6/20/61 - 10,752' 10,754' T 5 Abandoned PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.251 @ 4,565' KGSF #1 Actual WBD 7-19-201 l.docm Revised by: CVK REVISED: 7-19-2011 % I Chgvron PROPOSED RKB = 15' 3/4" I of i 5' 0' Sw on River Wel KGSF #1 Last Completed 7/27/09 DTi A1MV ATi(1N 177CT(10V /Tvnnok Parfe TILT I.no ilenthl CASING AND TUBING DETAIL JEWELRY DETAIL �O. De th SIZE WT GRADE CONN ID ±2,468' TOP BTM. 20" _ _ _ 3.500" 15' 31' 11-3/4" 47 5.983" - 11.00 Surface 2,032' 7" 29 N-80 BTC 6.184 Surface 243' 7" 26 N-80 BTC 6.276 243' 883' 7" 23 N-80 BTC 6.366 883' 4,626' 7" 29 N-80 BTC 6.184 4,626' 5,013' 7" 26 N-80 BTC 6.276 5,013' 6,470' 7" 29 N-80 BTC 6.184 6,470' 8,315' 7" 29 P-110 8RD 6.184 8,315' 10,875' Tubing Camco "MM" Mandrel with CEV Valve F 10,519' - - Brown CC Safety Joint 3-1/2" 9.3 L-80 Hydril503 2.992 15' 6,354' DTi A1MV ATi(1N 177CT(10V /Tvnnok Parfe TILT I.no ilenthl nterva JEWELRY DETAIL �O. De th ID OD Item 1 ±2,468' 2.867" 4.760" Chemical Inj Sub 2 ±6,237' 2.813" 3.500" Sliding Sleeve 3 f�' 6 Z 63 2.870" 5.983" Baker Premier Packer 4 ±6,305' 2.813" 3.500" X Nipple 5 ±6,355' 3.780" 2.990" Auto Release 6 ±6,524' - 4.630" TCP Guns 4 Abandoned 6/21/1961 H-2 10,642' 10,656' 14' 4 ABANDONMENT DETAIL NO. De , ID OD Item A ,640'-'/- 6/20/1961 - CIBP w/ 75' cement on top B -6AW - - PosiSet Plug w/ 37' Cement C 9,015' - - Tubing cut at 9,015' WLM. D 9,733' - - Top of Cement Plug. Pressure tested to 2,500 psi. E 10,473' - - Camco "MM" Mandrel with CEV Valve F 10,519' - - Brown CC Safety Joint G 10,530' - - Brown, 2-7/8" x 7", Type HS -16-1 Packer H 10,600' - - Cameo "D" Nipple I ? - - Venturi Shoe Notes \O. De th Item 1 7,114' 7" Stage Collar DTi A1MV ATi(1N 177CT(10V /Tvnnok Parfe TILT I.no ilenthl PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE =1.25° @ 4,565' KGSF #1 Proposed WBD 7-25-2011.docm Revised by: CVK REVISED: 7-25-2011 nterva ccum. Date Zone Top Btm Amt spf Comments 12/3/1998 64-5 6,380' 6,388' 8' 4 1-11/16" Pivot, 180 deg. Proposed Reperf 7/26/1998 68-0 6,883' 6,911' 28' 4 Abandoned 6/20/1961 - 10,615' 10,616' 1' 5 Abandoned 6/21/1961 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/1961 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/1961 114/5 10,664' 10,752' 88' 4 Abandoned 6/20/1961 - 10,752'10,754' 1 2' 1 S jAbandoned PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE =1.25° @ 4,565' KGSF #1 Proposed WBD 7-25-2011.docm Revised by: CVK REVISED: 7-25-2011 Chevron • • Swanson River KGSF #1 7/26/2011 OBJECTIVE: • Recover existing 3-1/2" completion, install plug, rerun 3-1/2" completion and reperforate 64-5 sand. Current BHP: 2,750 psi @ 6,384' TVD Max Dow o Pressure: 2,750 psi @ 6,384' TVD (Based on current SITP) MASP: ,335 psi (Based on actual reservoir conditions of the 64-5 sand and dry gas (0.56 sp gr) gradient (0.0 Spsi/ft) to surface) PROCEDURE SUMMARY: 1 MIRU Key Energy Rig #3. 2 Kill well with 8.8ppg 9% KCL. Install BP ; ND tree. 3 NU BOPE & test same 250psi low/ , Poopsi high, Test annular to 250psi low/ 1,500psi high. 4 Release K-22 anchor and recover 3-1/2" tubing down to packer at 6,288'. 5 RIH w/ packer milling BHA, mill Baker SAB -3 permanent packer, recover packer and tail assembly. 6 RIH w/ 7" casing scraper to fill at (+/-) 6,653'. POOH. 7 RU E -line. 8 RIH w/ casing and cement evaluation log above and below 64-5 sand at 6,380'-6,388'. 9 RD E -line. 10 RIH and set 7" cement retainer at (+/-) 6,640' on DP. Tag cement retainer w/ 10k to confirm set 11 Unstab from retainer, mix and pump 5 bbl (+/-) 15.3 ppg cement and spot on top of cement retainer. 12 Wait on cement. 13 RIH w/ 7" casing scraper to top of cement and drill out same to (+/-) 6,565'. [(+/-) 75' cement on top of retainer] 14 RIH 3-1/2" completion with TCP assembly, and set packer at (+/-) 6,263'. 15 Pressure test annulus to Premier Packer at (+/-) 6,263' to a minimum of 1600psi for 30 min. 16 Displace packer fluid into annulus. 17 Set BPV. ND BOPE. Pull BPV. Set TWC. NU and test tree. 250psi Low/ 5,000psi High. Pull TWC. 18 Release Key Energy Rig #3. 19 Post -rig: Drop bar to fire TCP guns. Turn well over to production for gas storage operations. Note: Planned workover as indicated in Sundry, number 311-162, dated 5/10/2011. KGSF #1 REVISED BY: CVK 7/26/2011 Chevron . Summary of Key Energy Rig #3 Specifics KGSF#1 Replace failed ESP The SRU KGSF#1 workover will involve pulling 3-1/2" completion, install plug, rerun 3-1/2" completion and reperforate 64-5 sand. The rig specifics are for the planned rig up on this well and are likely to change from well to well. Proposed Configuration Rig Model The rig model is a Hopper Hydra -hoist, Back -model GXXTA. Drawworks The drawworks are GXXTA-MD 10x42; w/ Sand Drum 15,000 ft — 9/16" sand line. Derrick The derrick is a 102' tall telescoping double, with 260,000 Ib capacity, 30" crown sheaves and McKissick 30" 150 ton 73A traveling block. Pipe Handling The pipe handling system is a Pipe Wrangler, 45' long, 8.5' wide, 9' high. The base beam is internally guided and load bearing. The beam is load rated with 102' derrick and 10,000 of 2-7/8" tubing to 58 mph winds. BOP Specifications Annular, 5M 11" Hydril GK. Double gate, 5M, 11" Shaffer LWS w/ blind ram and pipe ram (3-1/2", or 2-7/8"x5" VBR rams). Mud Cross, 5M, 11" w/ 2 each 3-1/8" 5M x 2-1/16" 5M Double Studded Adapters. BOP Diagram See attached. Accumulator 240 gallon KOOMEY Accumulator System on an enclosed skid unit. Includes 7 functions with manual bypass and remote panel. Sixteen 15 gallon accumulator bottles. 462 gallon hydraulic tank with air operated hydraulic pump. Pits The pit consists of a 200 bbl tank partitioned into three isolatable compartments. An optional shale shaker is also available that is a 3'x4' Jr. Standard -hydraulic driven. Pumps The primary pump is a National JWS-400 7"x4.5" Triplex rated to 5,000 psi on an independent skid. A secondary pump is a Gardner Denver PAH 8"x4.5" Triplex rated to 4,000 psi on an independent skid. The primary pump will pull fluid directly from the pit. The discharge will be plumbed to kill line and an independent stand pipe line. The secondary pump will be used in conjunction with the primary pump as needed for increased flow rates and used for fluid disposal in well SCU 43-04WD (PTD 161-029). Kill Line Key Energy Rig #3 Specs (KGSF#1) rev0.doc 7/25/11 Chevron The Kill Line/Circulating Line consists of 2", 5,000 psi hose with Unibolt/Hub-flanged connectors. Kill Line Valves The kill line valves consist of 2 ea. manually operated, 2-1/16", 5M valves attached to the mud cross with co -flex hose with a Unibolt/Hub-flanged connectors. -- Choke Line The choke line consists of 2", 5,000 psi hose with Unibolt/Hub-flanged connectors. l Choke Line Valves The choke line valves consist of 1 ea. manually operated, 2-1/16" 5M valve and 1 ea. automatically operated HCR valve that is attached to the mud cross with co -flex hose with a Unibolt/Hub-flanged connectors. Choke Manifold See attached. Choke Return Line/Diffuser Line The diffuser line will consist of 2", 5,000 psi hose with Unibolt connections. The line will run from the choke manifold to the diffuser tank. Diffuser Tank A diffuser tank will be placed adjacent to the mud pits with the capability of fluid transfer to the circulating system. Trip Tank A trip tank will be placed adjacent to the rig with the capability of fluid transfer to the circulating system. Gas Detection There will be a gas LEL monitor and a H2S monitor placed at the work platform (rig floor), shale shaker, upper cellar area, and lower cellar area. PVT There is no PVT system for the circulation system on this workover rig, as is standard practice in this type of well service work. Key Energy Rig #3 Specs (KGSF#1) rev0.doc 7/25/11 0 ! Chavion Swanson River 2011 KGSF #1 06/27/2011 Swanson iver 2011 Choke Manifold 07/07/2011 Blooey Line To Gas Buster Unibolt Connection O 0 0 O0 • • OF, ALASKA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS333 W. 7th AVENUE, SUITE 100 CONSURTATION C011DUSSIOIQ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 David Whitacre Technical Team Lead J Union Oil Company of California (Union)''(' 3800 Centerpoint Dr., Suite 100 Anchorage, AK 99503 D Re: Swanson River Field, Tyonek 64-5 Pool, KGSF #1 Sundry Number: 311-162 Dear Mr. Whitacre: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Chair DATED this/ � day of May, 2011. Encl. STATE OF ALASKA `$`tt ALASKA OIL AND GAS CONSERVATION COMMISSION 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: Filling StcFhe 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Num r: Union Oil Company of California (Union) Development ❑ Exploratory ❑ Stratigraphic ❑ Service Q 11�l0k::P29 - 3. Address: 3800 Centerpoint Dr., Suite 100 6. API Number: Anchorage, AK 99503 111 50- 133-10160-00 . 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No O KGSF #1(formerly SRU 43-28 - 9. Property Designation (Lease Number): 10. Field/Pool(s): Swanson River Unit ;Qr2p,4Dol 99low, I Swanson River/ Tyonek 64-5 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): 6,813' 6,813' 6,813' 6,813' 6,813' ' (� - 1 ' l Casing Length Size MD TVD Burst Collapse Structural Conductor 31' 20" 31' 31' Surface 2,032' 11-3/4" 2,032' 2,032' Intermediate Production 10,875' 7" 10,875' 10,875' Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6,380' - 6,388' 6,380' - 6,388' r 3-1/2" L-80 6,354' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker SAB -3 Permanent Pkr 6,288' MD & TVD 1 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ❑ Service Q 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: June 1st, 2011 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ 16. Verbal Approval: Date: Commission Representative: GSTOR ❑� SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chantal Walsh 263-7627 Printed Name David Whitacre 263-7616 Title Technical Team Lead Signature Y\ n Phone Date -5-/1010 COMMISSION USE ONLY Sundry Number: &'r W Conditions of approval: Notify Commission so that a representative may witness E IV Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ tYPt� Ail i Other: Alaska Oil & 609 Cffi*- ?-ltii nissiOR !its 8 Subsequent Form Required: J APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 11 Form 10-403 Revised,010 01ORIGINAL Submit in Duplicate Chevron May 10, 2011 Chantal R. Walsh Petroleum Engineer, P.E Mid Continent/Alaska Mr. Winton Aubert Reservoir Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: KGSF #1— Planned well operations Swanson River Unit, Cook Inlet, Alaska Dear Mr. Aubert, • Chevron North America Exploration and Production 3800 Centerpoint Dr., Suite 100 Anchorage, AK 99503 Tel: (907) 263-7627 Email: WalshC@chevron.com 04.1 E V 11 Aja aka Oil ri& Com, � ;liSS104 Union Oil Company of California ("Union") operates the Swanson River Unit, KGSF #1 gas storage facility (SIO 002A), in the Tyonek 64-5 reservoir. There are currently two production/ injection wells in this storage facility, KGSF #1 and KGSF #7A. In March of 2011, Union recognized that the 64-5 storage reservoir had lower than anticipated reservoir pressure and that the KGSF #1 well had fluid in the wellbore above the Tyonek 64-5 perforations. There has been no sign of a fluid level in KGSF7 (similar TVD) above the perforations. It is currently Union's view that the water in the KGSF #1 wellbore is most likely due to a leaking PosiSet plug set below the 64-5 gas storage reservoir. This plug was set to isolate the Tyonek 68-0 sand, which flowed water to surface prior to Union perforating the 64-5 gas storage interval. A wellbore schematic is attached for your convenience. Recent testing and conclusions drawn: On April 2nd and 4th of this year, Union ran a series of pressure & temperature logs (with spinner surveys) in the KGSF #1 wellbore. These surveys were run during static, flowing, and injection phases of the storage well operations, in hopes of discovering the source of the water influx. Unfortunately, the pressure/temperature/spinner surveys were not conclusive. -Much of the log data was questionable (if not useless) as a result of an oily residue from the wellbore coating the logging tools and clogging the pressure and/or temperature ports. There was no observed change in temperature gradient below the 64-5 perforations, which would have suggested movement of fluid from below the PosiSet plug or from behind pipe. The spinner survey likewise did not yield definitive conclusions due to the tool threshold being too large to detect the relatively small amount of water entering the wellbore. Overall, it was difficult to draw any firm conclusions due to tool and well conditions. E 0 In addition to the pressure/temperature logs, several slickline tags have been recorded in the last couple of months. These tag runs may indicate movement of the PosiSet plug: 3/22/11 Tag depth = 6667' 3/30/11 Tag depth = 6669' 4/16/11 Tag depth = 6655' Union intends to continue to monitor the top of fill depth every few weeks to evaluate if the differences we have seen to date are truly changing tagged depths or are due to line stretch/field calibration errors. Reason for planned KGSF #1 workover: The goal of this proposed workover is to ensure the integrity of the 64-5 gas storage reservoir. Water in the KGSF #1 well and the inconsistency of the tag depths suggests the possibility that the PosiSet plug in KGSF #1 is not isolating the Tyonek 64-5 reservoir from the abandoned Tyonek 68-0 reservoir below. This 68-0 sand produced water to surface prior to the completion of the gas storage interval. During the proposed workover, a CIBP will serve as a permanent means to isolate the water sand below the plug eliminating the possibility of losing gas or flowing water into the wellbore from the water sand below the 64-5 reservoir. Circulation of fluids during the workover will help to improve wellbore conditions and re -perforating the 64-5 reservoir will increase the gas deliverability, by bypassing near wellbore damage. General plan forward: In light of the lower than anticipated 64-5 reservoir pressure and the observed water in the KGSF #1 wellbore, Union plans to work over the KGSF #1 well this summer. Prior to performing this workover, Union would like to partially re -pressure the 64-5 reservoir in order to minimize workover fluid loss into the reservoir. Once the reservoir has been re -pressured, the general workover plan (for KGSF #1) will be to isolate the storage reservoir with a CaCO3 pill and then pull the current completion. In order to clean the wellbore and test the existing casing, a casing scraper run will be made, the well circulated, and a casing inspection log run. Finally, the completion string will be re -run and the 64-5 interval re -perforated prior to bringing the well back on line. Tyonek 64-5 reservoir re -pressured to 2,750 psi: The Tyonek 64-5 reservoir is currently at a reservoir pressure of approximately 1,172 psia. In order to minimize the potential damage caused by heavy workover fluids entering the reservoir, Union plans to re -pressure the 64-5 reservoir to approximately 2,750 psia. This will help to minimize the amount of fluid lost into the reservoir during the workover, while allowing Union to use a non -damaging KCI fluid (which would be slightly heavier than the reservoir pressure gradient). Union does not propose taking the reservoir pressure back to the original pressure (3,306 psia), as this would require a much heavier fluid to kill the well during the workover. Tyonek 64-5 re -pressuring plans: Union plans to re -pressure the Tyonek 64-5 reservoir by injecting approximately 775 MMcf of gas into the KGSF #7A wellbore. The KGSF #7A wellbore will be used for injection, since there has been no water observed in that wellbore. The plan is to inject approximately 400 MMcf of gas into the reservoir and then monitor the reservoir pressure for approximately 3 days. Another 100-150 MMcf of gas will then be injected and once again the pressure monitored. This controlled and monitored fill -up will continue until the reservoir pressure is brought back up to approximately 2,750 psia. Note that each 100-150 MMcf volume of gas will be followed by a monitored shut-in period of approximately 3 days. Workover and Infection timing: Union currently plans to start the workover on KGSF #1 on August 15th, 2011, In order to inject 775 MMcf of gas (to re -pressure the reservoir to 2,750 psia) into the reservoir prior to the workover start date, Union plans to start injection into KGSF #7A prior to June 1 st. This will allow time to inject the necessary gas as well as time to monitor the reservoir pressure during fill -up. Upon completion of the KGSF #1 workover (estimated to be 9/1/11), injection into the 64-5 storage reservoir will continue in order to fill the reservoir prior to the winter withdrawal season. The target date for having the reservoir full is 10/1/11. Please note that prior to any actual workover operations on the KGSF #1 well, Union will file the appropriate well sundries with the AOGCC. This preliminary sundry is strictly to notify the State of Union's general plans and answer any questions from the State prior to commencing injection into the Tyonek 64-5 reservoir (via the KGSF #7A wellbore). can be contacted at 263-7627. Sincerely, Chantal R. Walsh Petroleum Engineer, P.E. Cc: Dave Whitacre, Chevron Kevin Eastham, Chevron Project File Chevron • SV*on River Well KGSF #1 Last Completed 7/27/09 RKB = 15' 3/4" 0' PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.25° @ 4,565' KGSF 41 Actual WBD 4-21-201 Ldocm Revised by: CVK REVISED: 4-21-2011 PERFORATION HISTORY T onek Perfs TDT Lo CASING AND TUBING DETAIL JEWELRY DETAIL NO. Depth SIZE WT GRADE CONN ID 6,273' TOP BTM. 20" - 6,287' 2.992 3.500 15' 31' 11-3/4" 47 5.687 - 11.00 Surface 2,032' 7" 29 N-80 BTC 6.184 Surface 243' 7" 26 N-80 BTC 6.276 243' 883' 7" 23 N-80 BTC 6.366 883' 4,626' 7" 29 N-80 BTC 6.184 4,626' 5,013' 7" 26 N-80 BTC 6.276 5,013' 6,470' 7" 29 N-80 BTC 6.184 6,470' 8,315' 7" 29 P-110 8RD 6.184 8,315' 10,875' Tubing Cameo "D" Nipple H ? - - Venturi Shoe 3-1/2" 9.3 L-80 Hydril 503 2.992 15' 6,354' PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.25° @ 4,565' KGSF 41 Actual WBD 4-21-201 Ldocm Revised by: CVK REVISED: 4-21-2011 PERFORATION HISTORY T onek Perfs TDT Lo Depth) JEWELRY DETAIL NO. Depth ID OD Item 1 6,273' 2.813 3.500 XD Sliding Sleeve (Opens Down) [Closed 7/26/091 2 6,287' 2.992 3.500 K-22 Anchor 3 6,288' 3.250 5.687 Baker SAB -3 Permanent Packer 4 6,344' 2.813 3.500 X Nipple 5 6,354' 2.992 3.500 Wireline Entry Guide 1' 5 Abandoned ABANDONMENT DETAIL NO. Denth ID OD Item A 6,850' - 10,642' PosiSet Plug w/ 37' Cement B 9.015' Abandoned - Tubing cut at 9,015' WLM. C 9,733' - - Top of Cement Plug. Pressure tested to 2,500 psi. D 10,473' - - Cameo "MM" Mandrel with CEV Valve E 10,519' - - Brown CC Safety Joint F 10,530' - Brown, 2-7/8" x 7", Type HS -16-1 Packer G 10,600' Cameo "D" Nipple H ? - - Venturi Shoe Notes NO. Depth Item 1 7,114' 7" Stage Collar PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.25° @ 4,565' KGSF 41 Actual WBD 4-21-201 Ldocm Revised by: CVK REVISED: 4-21-2011 PERFORATION HISTORY T onek Perfs TDT Lo Depth) Interval Accum. Date Zone Top Btm Amt s f Comments 12/3/98 64-5 6,380' 6,388' 8' 4 1-11/16" Pivot, 180 deg. 7/26/98 68-0 6,883' 6,91 P 28' 4 Abandoned 6/20/61 10,615' 10,616' 1' 5 Abandoned 6/21/61 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/61 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/61 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/61 10,752' 10,754' 2' 5 Abandoned PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.25° @ 4,565' KGSF 41 Actual WBD 4-21-201 Ldocm Revised by: CVK REVISED: 4-21-2011 Storage Injection Order No. 2 June 15, 2001 Page 3 14. The mechanical integrity of SRU #43-28 was demonstrated on May 15, 2001 in accordance with 20 AAC 25.412. 15. The fluid proposed for injection is predominantly methane produced from a liquid extraction plant for produced gas from the Hemlock Formation in the Swanson River Field. Specific gravity of the injected gas is expected to range from about 0.61 to 0.59 (air = 1.0). 16. Estimated maximum daily injection volume is 10 mmcfd, and expected wellhead injection pressure is 2400-2600 psi: Proposed maximum injection pressures will be maintained less than the original wellhead pressure of 2850 psi. 17. If the maximum injection pressure is limited to the original wellhead pressure of 2850 psi, fractures will not be propagated in the confining strata, as the sandface injection pressure will be less than the original reservoir pressure of 3300 psi for the 64-5 sand in the SRU #43-28 well. CONCLUSIONS: A 1. The proposed injection of natural gas into th ovqz� kso-s storage will not cause movement of hydrocarb 2. The proposed storage of natural gas in SRU behind casing beyond the approved storage zoo 3. The proposed storage of natural gas in well S - through the confining zones. 4. The proposed injection of natural gas into th storage will not cause waste, jeopardize con impair ultimate recovery. NOW, THEREFORE, IT IS ORDERED that the following rules, in addition to statewide requirements under 20 AAC 25 apply to the underground storage of hydrocarbons by injection in the SRU #433-28 well. RULE 1: STORAGE INJECTION The Commission approves the injection for storage of natural gas into the 64-5 sand of the Tyonek Formation, between the measured depths of 6375 and 6443 feet in SRU #43- 28. The Operator shall report disposition of production and injection as required by of 20 AAC 25.228, 20 AAC 25.230, and 20 AAC 25.234. RULE 2: CONTINUED MECHANICAL INTEGRITY This approval is conditioned on the operator's demonstrating the continued mechanical integrity of SRU #43-28 in accordance with 20 AAC 25.252 (d), (e) and (f). DOC BodyPage 11 0 Page 2 of 9 (9) evidence to support a commission finding that the proposed disposal or storage operation will not initiate or propagate fractures through the confining zones that might enable the oil field wastes or stored hydrocarbons to enter freshwater strata; (10) a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which disposal or storage is proposed; (11) a reference to any applicable freshwater exemption issued in accordance with 20 AAC 25.440; and (12) a report on the mechanical condition of each well that has penetrated the disposal or storage zone within a one-quarter mile radius of a disposal or storage well. (d) The mechanical integrity of a disposal or storage well must be demonstrated under 20 AAC 25.412 before disposal or storage operations are begun, after a well workover affecting mechanical integrity is conducted, and at least once every four years. To confirm continued mechanical integrity, the operator shall monitor the injection pressure and rate and the pressure in the casing -tubing annulus during actual disposal or storage operations. The monitored data must be reported monthly on the Monthly Injection Report (Form 10-406). (e) Ifwrinjection rate, operating pressure observation, or pressure test indicates pressure communication or leakage in any casing, tubing, or packer, the operator shall notify the commission by the next working day and shall implement corrective action or increased surveillance as the commission requires to ensure protection of freshwater. (f) The commission will require additional mechanical integrity tests if the commission considers them prudent for conservation purposes or protection of freshwater. (g) Modifications of existing or pending disposal or storage operations will be approved by the commission, in its discretion, under 20 AAC 25.507, upon application containing sufficient detail to evaluate the proposed modification. No modification will be approved unless the applicant proves to the commission that the modification will not allow the movement of fluids into sources of freshwater. (h) If wells, including freshwater wells or other borings, are located within a one-quarter mile radius of the disposal or storage well, are a possible means for oil field wastes or hydrocarbons to move into sources of freshwater, and are under the control of (1) the operator, the operator shall ensure that the wells are properly repaired, plugged, or otherwise modified to prevent the movement of oil field wastes or hydrocarbons into sources of freshwater; or (2) a person other than the operator, the commission will not issue an order under (a) of this section to the operator until the operator presents evidence to the commission's satisfaction that the person who controls the wells has properly repaired, plugged, or otherwise modified the wells to prevent the movement of oil field wastes or hydrocarbons into sources of freshwater. (i) The commission will publish notice of the disposal or storage application and will provide opportunity for a hearing in accordance with 20 AAC 25.540. 0) If disposal or storage operations are not begun within 24 months after the approval date, the injection approval will expire unless an application for extension is approved by the commission. http://www.legis. state.ak.uslbasislfolioproxy.asp?url=http://wwWinuO l .legis. state.ak.uslcgi... 5/16/2011 0 • Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, April 08, 2011 11:24 AM To: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Cc: Eastham, Kevin (KEastham); Greenstein, Larry P; Whitacre, Dave S Subject: RE: Update on 64-5 Gas Storage Sand Page 1 of 2 kc0�-ooh Chantal, et al, Thanks for the information regarding "other penetrations". I would presume you have the injection/production pressure/rate information similar to what is submitted for Pretty Creek 4 and 42-05X and 42-05Y? That is the information I would like submitted. Thanks in advance. Tom Maunder, PE AOGCC From: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] [mailto:WalshC@chevron.com] Sent: Friday, April 08, 201111:15 AM To: Maunder, Thomas E (DOA) Cc: Eastham, Kevin (KEastham); Greenstein, Larry P; Whitacre, Dave S Subject: Update on 64-5 Gas Storage Sand Tom, ,.A; AAUGU 3 01 Q The data you requested for the wells around KGSF 1 doesn't exist. The wells in the 1/2 mile radius area are abandoned or isolated from the gas storage sand. We have finished our review of the spinner/temperature/pressure logs. We received input from Halliburton log specialists as well. The sticky substance in the well bore, combined with what we are calculating as a flow rate below the sensitivity of the production tools, renders the production logs inconclusive. This analysis gave us no insight to the wellbore. We are formulating a forward plan and will discuss with you prior to moving to the next step. The 64-5 sand is not currently being utilized for production or injection purposes. Chantal From: Eastham, Kevin (KEastham) Sent: Friday, April 08, 20118:21 AM To: Greenstein, Larry P Cc: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Subject: RE: wells around 64 5 That's correct, Larry. There are no wells within Y, mile that would work for monitoring the 64-5 sand. From: Greenstein, Larry P Sent: Friday, April 08, 20117:42 AM To: Eastham, Kevin (KEastham) Cc: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Subject: RE: wells around 64 5 What this tells me is that there aren't any wells within '/z mile that are connected to surface gauges to use for 8/2/2011 0 monitoring the 64-5 sand (unless a plug or cement has failed)... correct?? Larry From: Eastham, Kevin (KEastham) Sent: Thursday, April 07, 2011 1:19 PM To: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Cc: Greenstein, Larry P Subject: RE: wells around 64 5 • Page 2 of 2 At the 64-5 reservoir level, the following wells are within a %: mile radius of KGSF #1 & #7A: Attached is a map showing wells and % mile radius. (All wells below are SRU) 34-28, 314-27, 41-28, 212-27, 12-27. Notes: KGSF 2 was sidetracked out of 12-27 targeting the 62-5 sand which is above the 64-5 storage sand in #1 & #7A. Also, 314-27, 41-28, and 12-27/KGSF 2 have all been P&A'd. Similar to KGSF 2, KGSF 3 is within % mile radius, but targeted the shallower 62-5 sand as well. In 212-27, the 64-5 is beneath a cemented -in packer and two plugs (w/ cement on top of each) In 34-28, the 64-5 is beneath a cement packer. Let me know if you need anything else. 8/2/2011 ..... . , , SC 13 32 - 04 , I A , / : , / . ' .. / f , i ..." / .. . . ' ., .' , I ., . . , . , I ... . f .' . 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L : .. . . . , U 3 L - :3 1 . ., _ .., _y,:.._f-t---------...-14a / ......---- ..„, ,.,. ..--- ..... .. . ....,, .., . ------- . . . • . . _.---- ..... . - • . .... . . _---- . • .---- i / ...----- ---•.„ ■ Or- .....-' __-------___ .......... _......._ _ ..---- . • • Page 1 of 2 Maunder, Thomas E (DOA) From: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] [WalshC @chevron.com] Sent: Tuesday, April 05, 2011 5:28 PM To: Maunder, Thomas E (DOA) Cc: Aubert, Winton G (DOA); Saltmarsh, Arthur C (DOA); Whitacre, Dave S; Eastham, Kevin (KEastham) Subject: Swanson River Gas Storage 64 -5 Sand Tom, In response to your initial questions (listed below): 1. Please keep us advised of the diagnostics. At a minimum, form 10 -404 plus attachments should be submitted to document the work accomplished. We have run pressure /temperature /spinner surveys on the well over the weekend and through yesterday. We made a series of static passes, a series of producing passes and a series of injection passes. The wellbore below the perforation interval has a sticky black substance that we are attempting to identify. The substance has been on the spinner /temp /and pressure tools when they have come out of the wellbore. It is detrimental to the log data we are attempting to gather, so analysis of this information may not be possible. 2. Do you have individual well pressure plots similar to what Larry sends for Swanson 77 -3 and Pretty Creek (example attached). If so, please provide the information for KGSF #1 and #7A for the last 2 years. Larry is out of the office until Thursday (April 7th). He will plot the KGSF #1 and #7 well information in the pressure plot format and forward it to you as soon as he is back. 3. You say you suspect that the water is possibly from the deeper, isolated interval. That would appear to be the 68 -0 sand. Are there any wells completed in the 68 -0? Do you have any water samples? The 68 -0 sand exists in Swanson River in two lobes. One of the lobes has an anomalous higher than normal gradient pressure and has only seen water. The other lobe has lower original reservoir pressure and has produced gas. It is believed the two lobes are not in communication. The high pressure lobe, in addition to KGSF #1 wellbore, is present in SRU 14 -15 (tested 22 BWPD and was described as tight), and SRU 32A- 15(wet, high pressure). The upper normally pressured 68 -0 sand lobe produced 2 BCF from the SRU 234 -15 well. The SRU 32A -15 well was also completed in this lobe (after the testing of the lower, wet 68 -0 lobe) it had 1156 psi static gas pressure with no flow and was assumed depleted from SRU 234 -15. We have not located a water sample for this interval. 4. On the P/Z plot, the latest injection cycle point plots higher and closer to the axis than previous cycles. Do you have an explanation for the difference? The 64 -5 sand had more gas than OGIP injected into the sand in the 2010 injection cycle. We filled the reservoir further than we have in past cycles but still within the constraints of our Gas Storage Order. 5. Has there been any water produced from KGSF #1? Our production records through end of February do not show any. No water production was noted. 6. Is the KGSF project still presently operating? Other than for testing purposes the 64 -5 reservoir, at this time, is not being utilized for production or injection. 7. Looking toward summer, what is the forward operating plan for KGSF? Understanding the source of the water is the highest priority. The operating plan will be adjusted to reflect that understanding. Do not hesitate to contact me if you have further questions. We will be submitting a 10 -404 for the production logging and slickline work we are doing on the well. I will keep you apprised of any findings we can draw from our investigation. Chantal 5/16/2011 • • Page 2 (4'2 Chantal Walsh Petroleum Engineer, P.E. Petrotechnical Resources Alaska walshc _ chevron.com Anchorage, AK Chevron North America Exploration and Production Midcontinent /Alaska SBU 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tel : 907 - 263 -7627 Mobile 907 227 0952 Mail Confidential Footer Privileged /Confidential information may be contained in, or attached to, this message. If you are not the addressee indicated in this message (or responsible for delivery of the message to such person), you may not copy, forward, disclose, deliver, or otherwise use this message or any part of it in any form whatsoever. If you receive the message in error, you should destroy this message after notifying me immediately by replying to the message or contacting me at (907) 263 -7892. 5/16/2011 • • Chevron Chevron - Alaska Report Date: 4/4/2011 ONO t _ DSM WO Report Report No.: 4 W % • 00 Days from Start: 2.69 Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) KGSF #1 SWANSON RIVER KGSF 1 FEDA028399 5013310160 QA5333 174.00 Job Category Primary Job Type Rig (Names) Area Field Name WI (%) Well Services Logging - Production Alaska Area SWANSON RIV UNIT 100.00 AFE Number Total AFE Amount Total AFE Sup Amount Total AFE i Sup Amount Daily Cost Total Cum Cost To Date AFE minus Field Estimate UWDAK- R0035 -EXP 426,150 426,150 49,925 124,422 301,728 Weather Temperature ( °F) Wave Conditions Wind Problem Hrs (hrs) Cum Problem Hr... Cum Prob Time (.. Head Count Days Sine... Cloudy/ Rain 38 Calm 5.0 4 Comments Pressure tested lubricator, Pump -N -Sub and Wireline valve 250/ 2500 psi. Made passes at 40, 80, 120 FPM while injecting at 15 MMSCFD and 2170 psi at well head. Made shut in passes 1 hr and 2 hr after shutting in Injection. Operations Summary Production injected at 5MMSCFD for 24 hours. RU Eline. Pressure test lubricator 250psi low /3000psi high. RIH with pressure, temperature, spinner log to 6,600', bring injection rate to 15MMSCFD, making several injection logging passes from tubing tail to tag depth, shut in well, and continue with several static logging passes at 1hour & 2 hours after well had been shut in. RD Eline. Status at Reporting Time Well turned over to production Projected Operations Well Turned over to Production Required Matls next day Weaver trucks to move Halliburton Equipment to there shop Dotty Contacts , Title Contact Office Drill Site Manager Joe Dalebout 283 -2536 ADS /Safety Observations Observation Typ No. Rats Comment JSA 5 2) Peak 3) Halliburton Safe Behavior 2 1) Peak operator put bigger pads under mast truck stabilizers. 2) Crew had hazord hunt before rigging up lubricator. SWA 1 1) noticed the safety latch on the crane hook was broke. Inspected and found sheared screw, stopped pin and replaced pin. Latch worked fine so continued job. Un -safe Condition 1 1) Hoses were causing a tripping hazord ( they were rerouted) Time Log Start UE Time UE Ref Time Dur (hrs) End Time Activity Comment (hrs) No. 00:00 5.50 05:30 INACTIVE Day 4 IFO Tubing 1700 psi Injecting 5 MMSCF /D Gas 7 "x 3.5" annulus 0 psi 11 3/4 "x 7" annulus 0 psi Fluid level shot 4/3/2011 at 6218' 05:30 1.00 06:30 HESMTG SIMOPS meeting w/ Production, Construction and Drilling. 06:30 4.00 10:30 PREPSITE Review procedure w/ Production flow rates and shut in passes. 10:30 1.00 11:30 HESMTG Prejob Safety Meeting, Review Injection Rates, Prejob safety checklist, Pressure test procedure. Fill out permits and write JSA's. 11:30 1.50 13:00 R/U Rig up lubricator, MU 1.69 "x 2' full bore spinner w /Cage, 1.69 "x 1.5' temp/ capasatence tool, 1.69 "x 2' centralizer, 2.19 "x 1.4' continuos spinner, 1.69 "x 2' centralizer, 1.69 "x 6" knuckle, 1.69 "x 1.6' pressure tool, 1.69 "x 6" knuckle, 1.69 "x 6.6' telemetry cartridge, 1.69 "x 10' wgt bar, 1.69 "x 20" Rope Socket. Check tool and Make up lubricator on tree. 13:00 0.50 13:30 LBRCTR Pressure test Lubricator 250/3000 psi. (good test). 13:30 5.00 18:30 LOGSROC RIH to 6200' correlated to SLB TDT log dated 26/July/1998. Log base line log at 40' min. from 6200' to 6600' down and 6600' to 6200' up while injecting at 5 MMSCF /D and 1700 psi on tubing. Park full bore spinner at 6275' and increase injection rate to 15 MMSCF /D pressure to 2170 psi. Rates stabilize after 35 minutes and begin injection passes at 40', 60', 80', 120' min. Production stop injection while performing station stop at 6374'. Wait one hour and perform 40' min passes up and ' down from 6374' to 6500' and 6250' to 6650' . Wait an additional hour and make 40' minute passes up and down from 6250' to 6650' . POOH 18:30 3.50 22:00 R/D Rig down Halliburton, All tools in good shape, (Tools are dirty almost like they had been in a oil well but no thick goo.) Button up equipment for transport to their shop. Secure well and PT night cap. 22:00 1.00 23:00 HESPRMT Turn in permits to Plant operator and travel to Halliburton shop. 23:00 1.00 00:00 INACTIVE crsongat Total Shift Duration Company Employee Type Note SSE Headcount (hrs) Tot Time (hrs) APRS Operator 1 16.00 16.00 Halliburton Chevron Other Contractors 3 12.00 36.00 Peak Oilfield Services Chevron Other Contractors 1 12.00 12.00 S /DdHsMslts/In troas' Date Tour Safety Check Description Comment 4/4/2011 Day Safety Meeting Prejob Safety Wellsite Safety meeting, Write JSA's and fill out Permit to work, Review Pre - Wireline safety Meeting checklist 4/4/2011 Day Safety Meeting Tail Gate Meeting DSM, Halliburton and Peak Mast truck Operator Discuss laying down Lubricator, Pump -N -Sub and Wireline valve and rigging down. urp� String ID String OD String Wt String Set Depth Casing Description (in) (in) (Ibs /ft) Grade (MD) (RKB) Comment Conductor 20 31 Surface Casing 11.000 11 3/4 47.00 J -55 2,032 Production Casing 6.366 7 23.00 N -80 10,875 BODE & Equ*pment Pressure Tests . Date (Test Type Test Fluid Type Failed? Comment 7/27/2009 Tree Water 250/3000 psi for 30 min each. WallheatPTres Install Date Make Type Max Pres (psi) WP (psi) Service Size (in) Shaffer R Page 1 of U • • Maunder, Thomas E (DOA) From: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] [WalshC @chevron.com] Sent: Tuesday, April 05, 2011 9:23 AM To: Maunder, Thomas E (DOA) Cc: Aubert, Winton G (DOA); Saltmarsh, Arthur C (DOA); Whitacre, Dave S; Eastham, Kevin (KEastham) Subject: RE: Swanson River Gas Storage 64 -5 Sand Tom, I am pulling together information to send your way. We ran pressure /temperature /spinner surveys on the well over the weekend and through yesterday. We made a series of static passes, a series of producing passes and a series of injection passes. Other than for testing purposes the 64 -5 reservoir is not being utilized for production or injection. We are working hard interpreting the data we are gathering, to try to both quantify the source of the problem and establish a baseline for future analysis once this issue is remediated. I will have a much more complete set of answers to you this afternoon. Chantal From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Tuesday, April 05, 2011 8:44 AM To: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Cc: Aubert, Winton G (DOA); Saltmarsh, Arthur C (DOA) Subject: RE: Swanson River Gas Storage 64 -5 Sand Chantal, Do you have any replies to our questions? Tom Maunder, PE AOGCC • : Maunder, Thomas E (DOA) Sent: - rsday, March 31, 2011 9:33 AM To: 'Walsh, - tal [Petrotechnical Resources of Alaska (PRA)]' Cc: Aubert, Winto - DOA); Saltmarsh, Arthur C (DOA) Subject: RE: Swanson - Gas Storage 64 -5 Sand Chantal, Thanks for the notice, interesting to say th - - - st. A couple • • uestions ... 1. Please keep us advised of the diagnostics. mi m, form 10-404 plus attachments should be submitted to document the work accomplished. 1. Do you have individual well pressure plot milar to wh- -rry sends for Swanson 77 -3 and Pretty Creek (example attached). If so, please provi• - e information for KG :1 and #7A for the last 2 years. 2. You say you suspect that the - -r is possibly from the deeper, iso - -d interval. That would appear to be the 68 -0 sand. Are there any w- = completed in the 68 -0? Do you have any w -: samples? 3. On the P/Z plot, the - -st injection cycle point plots higher and closer to the a an previous cycles. Do you have an explanati • • or the difference? 4. Has there - -en any water produced from KGSF #1? Our production records through en• • ebruary do not show a . 5. e KGSF project still presently operating? •. Looking toward summer, what is the forward operating plan for KGSF? 8/2/2011 • Page 1 of 1 A Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Thursday, March 31, 2011 8:46 AM To: Aubert, Winton G (DOA); Saltmarsh, Arthur C (DOA) Subject: FW: Swanson River Gas Storage 64 -5 Sand Attachments: Material Balance Analysis 03_2011.pdf Winton and Art, Here is a message from Chantal regarding the behavior of KGSF #1 during this last winter. Looking at the P/Z plot, the performance fine has moved to a new region of the plot. The P/Z value is shown to be at a new maximum at the end of the start of the latest production cycle. I wonder if this means that the maximum allowed pressure may have been exceeded. Increasing the maximum wellhead pressure from 2850 to 3584 was allowed in SIO 2a issued 6/25/2004. I reviewed the well file and it would appear that the plugging above the water wet 68 -0 sand in late 1998 should have been effective. I don't have other pressure /rate information for this project. The SIO does not have the monthly performance reporting requirement that the Swanson 77 -3 or Pretty Creek projects have. I can remain the contact with Chantal if desired or Winton can take the lead. Tom om: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] [mailto:WalshC ©chevron.com] Se • Wednesday, March 30, 2011 5:17 PM To: Ma • • er, Thomas E (DOA) Cc: Orr, Ga • .; Tyler, Steve L; Winslow, Paul [PRA]; Eastham, Kevin (KEastham); Branden • . g, Tim C; Haines, Dale A; Myers, • is S; Wright, Stephen (SSWR); Whitacre, Dave S Subject: Swanson °' er Gas Storage 64 -5 Sand Tom, The 64 -5 Gas Storage Sand in Swanso river has been monitored ove is past injection /production cycle. At the end of the injection cycle, both wells SF #1 and KGSF #7A) ere shut in for a short period of time (24 hours). A surface pressure was obtained and • - well went i • the winter season production cycle. Material balance analysis was applied to several additional p - sur •oints taken throughout the cold season (attached plot). In the last couple of weeks, KGSF #1 was unabl- • ow within the drawdown constraints established for the production of the well. A slickline tag showed . fluid lev- •f 5999' MD, — 380' above the top perforation. We conducted a pressure build up test by run g pressure gaug- 'n KGSF #7A (where there was no water) and derived a reservoir pressure of 1171 psia. We recognize that the 64 -5 stora: - sand has lower than anticipated reservoir • -ssure and KGSF #1 has fluid in the wellbore above the perfor. ions. We are in the process of running diagnostic p : sure /temperature logs, and bailing sand and fluid . mples in an attempt to identify if there is fluid movement fr. • below the isolation plug in the wellbore or •ehind pipe. Please let me ow if you have any questions and we will keep you apprised of diagnostic developme . Chant- antal Walsh Petroleum Engineer, P.E. Petrotechnical Resources Alaska walshc @chevron.com 8/2/2011 • • Page 1 of 2 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Thursday, March 31, 2011 9:33 AM To: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Cc: Aubert, Winton G (DOA); Saltmarsh, Arthur C (DOA) Subject: RE: Swanson River Gas Storage 64 -5 Sand Attachments: Master Well List TIO Report 2011 03 01.xis Chantal, Thanks for the notice, interesting to say the least. A couple of questions ... 1. Please keep us advised of the diagnostics. At a minimum, form 10 -404 plus attachments should be submitted to document the work accomplished. 1. Do you have individual well pressure plots similar to what Larry sends for Swanson 77 -3 and Pretty Creek (example attached). If so, please provide the information for KGSF #1 and #7A for the last 2 years. 2. You say you suspect that the water is possibly from the deeper, isolated interval. That would appear to be the 68 -0 sand. Are there any wells completed in the 68 -0? Do you have any water samples? 3. On the P/Z plot, the latest injection cycle point plots higher and closer to the axis than previous cycles. Do you have an explanation for the difference? 4. Has there been any water produced from KGSF #1? Our production records through end of February do not show any. 5. Is the KGSF project still presently operating? 6. Looking toward summer, what is the forward operating plan for KGSF? I look forward to your reply. Tom Maunder, PE AOGCC From: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] [mailto:WalshC @chevron.com] Sent: Wednesday, March 30, 2011 5:17 PM To: Maunder, Thomas E (DOA) Cc: Orr, Gary A.; Tyler, Steve L; Winslow, Paul [PRA]; Eastham, Kevin (KEastham); Brandenburg, Tim C; Haines, Dale A; Myers, Chris S; Wright, Stephen (SSWR); Whitacre, Dave S Subject: Swanson River Gas Storage 64 -5 Sand Tom, The 64 -5 Gas Storage Sand in Swanson River has been monitored over this past injection /production cycle. At the end of the injection cycle, both wells (KGSF #1 and KGSF #7A) were shut in for a short period of time (24 hours). A surface pressure was obtained and the well went into the winter season production cycle. Material balance analysis was applied to several additional pressure points taken throughout the cold season (attached plot). In the last couple of weeks, KGSF #1 was unable to flow within the drawdown constraints established for the production of the well. A slickline tag showed a fluid level of 5999' MD, 380' above the top perforation. We conducted a pressure build up test by running pressure gauges in KGSF #7A (where there was no water) and derived a reservoir pressure of 1171 psia. We recognize that the 64 -5 storage sand has lower than anticipated reservoir pressure and KGSF #1 has fluid in the wellbore above the perforations. We are in the process of running diagnostic pressure /temperature logs, and bailing sand and fluid samples in an attempt to identify if there is fluid movement from below the isolation plug in the wellbore or behind pipe. Please let me know if you have any questions and we will keep you apprised of diagnostic developments. 5/16/2011 • • Page 2 of 2 Chantal Chantal Walsh Petroleum Engineer, P.E. Petrotechnical Resources Alaska walshc@chevron.com Anchorage, AK Chevron North America Exploration and Production Midcontinent /Alaska SBU 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tel : 907 - 263 -7627 Mobile 907 227 0952 Mail Confidential Footer Privileged /Confidential information may be contained in, or attached to, this message. If you are not the addressee indicated in this message (or responsible for delivery of the message to such person), you may not copy, forward, disclose, deliver, or otherwise use this message or any part of it in any form whatsoever. If you receive the message in error, you should destroy this message after notifying me immediately by replying to the message or contacting me at (907) 263 -7892. 5/16/2011 KGSF #1 FACILITY (Tyonek 64-5 Sand) - P/Z vs Cumulative Production Plot (revised 3/29/11) 4500 [ 1 1 --0— Primary - --Cr 01 IN cycle , I 4000 1 —.— 07 Prod Cycle - --6— 07 lry Cycle , , - 08 Prod Cycle 3500 -- %. • ** 4 — - — — --et— 08 Ini Cycle N. AI 09 Prod Cycle • - , - 09 Inj Cycle 3000 --------- . I — Prod Cycle A — 1 0 Inj Cycle A -I 2500 —.40.—.11 Prod Cycle i N A e-, • 2000 - * f , '4111 am ,, 1500 - -- . — r , 1 .. 1000 - — - _______________N■ A , _ ._ _ • _ I I ....... .,...... i -0.4 -0.2 0 0.2 0.4 0.6 0.8 1 1.2 L4 L6 Cumulative Gas Produced (Bcf) 0:\NAMMCBU1Alaska\DeptslAssetDev\CIGas\Gas CFT\Openmind\Swanson\Swanson RiverUnit\KGSF#1 \Surveys\Pressures\AOGCC AMB Rpt\2010\KGSF#1 & #7A 64-5 Sd POZ 3-08-11.xls Plot Pressure & Rate vs Time - Well KGSF #1 3500 12000 10000 . - 7 11 • •9 5/8" 2500 - Tubing • Vol Inj i ) • 8000 ' Vol Prod 2000 / — II 3 I 1 • wil U N 6000 u O. i ill I -- 1500 I 1 � ' r tiL 4000 1000 - - -- - - - , � • 1 III I 1 P 2000 1 500 _ - li _ � i _ _ _ - - 1 o ' ! II` 1,1 I Iris ,I1 0 0 0 0 i N N N N N N N a, O �- N _ N M i Plot Pressure & Rate vs Time - Well KGSF #7A 3500 1 4000 3000 — — — — A — - 4 — 12000 �1 • 9 5/8" •Tubing 2500 I 1 • Vol Inj lk ,. •Vol Prod • 2000 — — — , 8000 's LL N V N a) CL. 1500 I 6 000 1000 - _ ' A 4000 I I \ I , 500 2000 t 1111.111w,milm ILI li 1 7+ - II A I -ff 11 0 0 0 0 am a a — i. co 00 N N N N N N N a, 8 r N N M STATE OF ALASKA ALASKAIOAND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Abandon U Repair Well LJ Plug Perforations 11 Stimulate U Other U Press/Temp /spinner log Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑ Exploratory ❑ 161 -008 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic❑ Service El 6. API Number:...: 50- 133 - 10160 -00 -" 00 7. Property Designation (Lease Number): 8. Well Name and Number: FEDA028399 [Swanson River Unit] Swanson River KGSF #1 9. Field/Pool(s): ... _ , Swanson River Field / 64 -5 Tyonek Gas Storage, Hemlock Oil & Tyonek Undef Gas Pools 10. Present Well Condition Summary: Total Depth measured 10,875 feet Plugs measured 6,813 (cement) feet true vertical 10,875 feet Junk measured 6,674 (fill) feet Effective Depth measured 6, 674 (fill) feet Packer measured 6,288 feet true vertical 6,674 (fill) feet true vertical 6,288 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 31' 20" 31' 31' Surface 2,032' 11 -3/4" 2,032' 2,032' Intermediate Production 10,875' 7" 10,875' !' 10,875' 9 3,830psi 6,340psi Liner ylll APR 2 5 ZU1 Perforation depth Measured depth 6,380' - 6,388' RECEIVED True Vertical depth 6,380'- 6,388' Tubing (size, grade, measured and true vertical depth) 3 -1/2" 9.3# L -80 Moka,! Packers and SSSV (type, measured and true vertical depth) Baker SAB -3 Perm Pack 6,288' MD/TVD N/A N/A 11. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 25psi (shut -in) 795psi (shut -in) Subsequent to operation: 0 0 0 Opsi (shut -in) 989psi (shut -in) 13. Attachments: Production, Injection, 14. Well Class after work: Copies of Logs and Surveys Run Static Togs Exploratory❑ Development ❑ Service El Stratigraph[J Daily Report of Well Operations X 15. Well Status after work: Oil ❑ Gas ❑ WDSPL ❑ GSTOR 0 ' WINJ ❑ WAG ❑ GINJ ❑ SUSPO 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: N/A Contact Chris Kanyer 263 -7831 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature Phone 276 -7600 Date 4/22/2011 Form 10-404 Revised 10/2010 411AS APR 2 5 Z Oi� °Y ubmitOriginal Only Chevron • • 1%0 Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) KGSF #1 SWANSON RIVER KGSF 1 FEDA028399 5013310160 QA5333 174.00 Primary Job Type Job Category Objective Actual Start Date Actual End Date Logging - Production Well Determine water influx. 3/30/2011 Services Primary Wellbore Affected Wellbore UWI Well Permit Number 1610080 3/30/2011 00 0 "'t' 00 :04bM,, " Operations Summary RU slickline. Pressure tested lubricator 250psi low /2500psi high. RIH w/ 2.73" GR and found fluid level at 5,920' and tagged fill at 6,669'. Made three runs w/2.25" drive down bailers and bailed fill from 6,669 to 6,674'. RIH and retrieve water sample at 6,365'. RD slickline. *1101 00 :00 - 4/2/2011 00 :00 Operations Summary RU Eline. Pressure test lubricator 250psi low /2500psi high. RIH with pressure, temperature, spinner log to 6,650', making several static logging passes from tubing tail @ 6,354' to 6,660'. RD Eline. 4/212011 00:00. 4/3/2011 '610 Operations Summary RU Eline. Pressure test lubricator 250psi low /2500psi high. RIH with pressure, temperature, spinner log to 6,650', begin producing well at 2MMSCFD, making several flowing logging passes from tubing tail to tag depth, shut in well, and continue with several static logging passes at 1 hour & 2 hours after well had been shut in. RD Eline. *4401I000 4/5/20111, 00;00 z= .,. . � �, . , . Operations Summary Production injected at 5MMSCFD for 24 hours. RU Eline. Pressure test lubricator 250psi low /3000psi high. RIH with pressure, temperature, spinner log to 6,600', bring injection rate to 15MMSCFD, making several injection logging passes from tubing tail @ 6,354' to 6,660', shut in well, and continue with several static logging passes at 1 hour & 2 hours after well had been shut in. RD Eline. Chevron • Silson River MOO Well KGSF #1 %. Last Completed 7/27/09 CASING AND TUBING DETAIL RKB = 15' SIZE WT GRADE CONN ID TOP BTM. ;.,..k,` 20" 15' 31' 11 -3/4" 47 11.00 Surface 2,032' 7" 29 N -80 BTC 6.184 Surface 243' 7" 26 N -80 BTC 6.276 243' 883' .. 7" 23 N -80 BTC 6.366 883' 4,626' 7" 29 N -80 BTC 6.184 4,626' 5,013' 7" 26 N -80 BTC 6.276 5,013' 6,470' "' 7" 29 N -80 BTC 6.184 6,470' 8,315' 7" 29 P -110 8RD 6.184 8,315' 10,875' 11 -3/4" Tubing 3 -1/2" 9.3 L -80 Hydril 503 2.992 15' 6,354' TOC @ JEWELRY DETAIL `+r" �- 3,675' NO. Depth ID OD Item 1 6,273' 2.813 3.500 XD Sliding Sleeve (Opens Down) [Closed 7/26/09] 2 6,287' 2.992 3.500 K -22 Anchor 1 i ? 3 6,288' 3.250 5.687 Baker SAB -3 Permanent Packer 4 6,344' 2.813 3.500 X Nipple 2 - ♦ a 5 6,354' 2.992 3.500 Wireline Entry Guide 3-■ �1 is 4 -► s', I 5 ---► Top of ABANDONMENT DETAIL TOC _ } - ` 1 1 -fill @ NO Depth ID OD Item @ _* -� „ 6,674' A 6,850' - - PosiSet Plug w/ 37' Cement 6,813' B 9.015' - - Tubing cut at 9,015' WLM. A 44 C 9,733' - - Top of Cement Plug. Pressure tested to 2,500 psi. u , y D 10,473' - - Camco "MM" Mandrel with CEV Valve E 10,519' - - Brown CC Safety Joint VV' F 10,530' - - Brown, 2 -7/8" x 7 ", Type HS -16 -1 Packer I G 10,600' - - Camco "D" Nipple B - -' TOC H ? - - Venturi Shoe C - * " t-- @ 9,100' - t., Notes 1 NO. Depth Item I 7,114' 7" Stage Collar D -♦ E _* '" PERFORATION HISTORY (Tyonek Perfs TDT Log Depth) Interval Accum. F -* , Date Zone Top Btm Amt spf Comments 12/3/98 64 -5 6,380' 6,388' 8' 4 1 -11/16' Pivot, 180 deg. 7/26/98 68 -0 6,883' 6,911' 28' 4 Abandoned C _Hp. 6/20/61 - 10,615' 10,616' 1' 5 Abandoned HI 6/21/61 H -1 10,617' 10,631' 14' 4 Abandoned 6/21/61 H -2 10,642' 10,656' 14' 4 Abandoned 6/21/61 11-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/61 - 10,752' 10,754' 2' 5 Abandoned H , PBTD = 6,813' TD = 10,875' q MAX HOLE ANGLE = 1.25° @ 4,565' / KGSF #1 Actual WBD 4- 21- 2011.docm Revised by: CVK REVISED: 4 -21 -2011 • Page 1 of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) �.. ,, t ( l — 0 b Sent: Monday, February 07, 2011 2:04 PM To: McMains, Stephen E (DOA) Cc: Davies, Stephen F (DOA) Co 3 Subject: 77 -3 Gas Storage at Swanson River -Pool Code 772805 Steve, Further to the work begun earlier regarding the appropriate pool classification of Tyonek gas associated with the 64 -5 and 77 -3 storage projects, the 64 -5 [772803] and 77 -3 [772805] are distinct Tyonek sand intervals so the volume accounting needs to be separate. The matter is a little further complicated since there also is an undefined Tyonek pool code at Swanson [772500]. So far as I am aware, the only wells remaining to be reconciled are 42A -05 (180 -106) and 42B -05 (182 -199). Both wells were originally Hemlock oil producers and the Hemlock was plugged with the wells being completed in the 77 -3 sand. 42B -05 was converted to GSTOR 11/7/05. First storage injection is reported in 12/05. First gas production is reported 11/05. All gas volumes are reported to the 64 -5 pool, this should be changed to the 77 -3. 42A -05 is a little more complicated. There is no record of any gas having been injected for storage. The Hemlock was plugged and the well perforated in the 77 -3 in June 2004. It appears that all gas produced from then until the well was converted to GSTOR on 10/1/05 was credited to the undefined Tyonek Pool code [772500]. Fairly regular /continuous production is reported up through 11/05 (14 days). No production is reported in 12/05 and only 7 days in 01/06. Again, all Tyonek gas from this well should be against the 77 -3 pool code [772805]. Please let me know if further information is needed. It is probably appropriate to put a copy of this message in each well file. Tom Maunder, PE Sr. Petroleum Engineer 3/7/2011 Maunder, Thomas E (DOA) rage i of 1 From: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] [WalshC@chevron.com] Sent: Monday, September 27, 2010 10:27 AM To: Maunder, Thomas E (DOA) Cc: Whitacre, Dave S; Greenstein, Larry P Subject: RE: KGSF Annual Report Attachments: KGSF 2010 Revised POZ.pdf; KFSF #1 #7 9-27-10.pdf Tom, Thank you for your patience. The data differences that you noted are the daily numbers not corrected to the official monthly values for the months of June and July 2010. 1 have included a new copy of the production volumes corrected for this data (KGSF #1 #7 9-27-10.pdf). The additional production data value that you questioned, the November 2004 KGSF #1, was originally submitted with the volume of 99404, and then a revision was issued by Unocal to the corrected value of 100085. 1 have a copy of the submitted letter should you not be able to find it in your records. The P/Z plot has been reconstructed to show the last 4 cycles plus the original cycle (KGSF 2010 Revised POZ.pdf). Please find attached. Let me know if you have any further questions. Chantal From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Friday, September 24, 2010 3:02 PM To: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Subject: RE: KGSF Annual Report Hi Chantal, Have you had an opportunity to look into the KGSF stuff? Tom From: Maunder, Thomas E (DOA) Sent: Thursday, August 19, 2010 9:39 AM To: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Cc: Greenstein, Larry P; Whitacre, Dave S Subject: RE: KGSF Annual Report Nota problem on time to look. I like your idea about the cycles. I think having a new "4 +1" plot would be helpful if you can provide it. Electronic is fine. Tom From: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] [mailto:WalshC@chevron.com] Sent: Thursday, August 19, 2010 9:23 AM To: Maunder, Thomas E (DOA) Cc: Greenstein, Larry P; Whitacre, Dave S 9/30/2010 rage z- of • i Subject: RE: KGSF Annual Report Tom, I was thinking the same thing with the limiting of the cycles. I think the original cycle should stay on the plot, and then plot the last 4 cycles. I played around with the plot for internal purposes and that seemed to capture the sense of how the current year cycle was responding to historical trends. Let me know if you want that plot for this year or I will place this note in the file so next year the plot is limited. I will dig into the data and see why we are not matching on the exact values for production. Because we watch this data daily, the June 2010 data is likely due to not updating the daily values with the official monthly numbers. But give me a little time to address, these especially the November 2004 data. Chantal From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Thursday, August 19, 2010 9:08 AM To: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)] Subject: KGSF Annual Report Chantal, I have been reviewing the submitted report and have some questions. 1. 1 did a comparison of the volumes in and out for both wells and identified some differences with the "official" numbers for KGSF #1 that we have in our data base. Here are a listing of the discrepancies, not a lot of volume however there is a difference. KGSF #1 (161-008) June 2010 Production Chevron # 4517 AOGCC # 4530 delta = 13 KGSF #1 (161-008) June 2010 Injection Chevron # 370 AOGCC # 384 delta = 14 KGSF #1 (161-008) November 2004 Injection Chevron # 100085 AOGCC # 99404 delta = 681 Could you check what information you might have regarding the numbers? 2. The P/Z plot is getting very busy. I would like to propose limiting the number of cycles shown on a given plot so it "reads easier". I'm not sure what the number should be. Does having no more than 4 or 5 cycles on a plot with the latest data shown against the last 4 or 5 years make sense? Let me know your thoughts. Call or message with any questions. I look forward to your reply. Tom Maunder, PE AOGCC 9/30/2010 4000 3500 3000 2500 2000 ATTACHMENT #3 (revised 9/20/10) KGSF #1 FACILITY (Tyonek 64-5 Sand) - P/Z vs Cumulative Production Plot � --a— Pnmary 'O1 Inj cycle *- 07 Prod Cycle I t . 07 Inj Cycle 08 Prod Cycle 08 Inj Cycle 09 Prod Cycle i 09 Inj Cycle 10 Prod Cycle 10 Inj Cycle p" 1500 1000 500 0 -0.2 0 0.2 0.4 0.6 0.8 1 Cumulative Gas Produced (Bcf) 1.2 \\Anc380ntdfsl.anc380.chevrontexaco.net\share\NAU\MCBU\Alaska\Depts\AssetDev\CIGas\Gas CF nOpenmind\Swanson\Swanson RiverUnit\KGSF# I \Surveys\Pressures\AOGCC Annual Mat Bal Rpt\20IO\KGSF#1 & VA 64-5 Sd P07, 8-11-10.x1s • E • ATTACHMENT #1 • KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES SRU 43-28 KGSF #1 1 KGSF #7A T onek 64.5 Sand Totats \lAnc380ntdfsl.anc380.chevrontexaco.netlshareWAU\MCBU\AlaskalDepts\AssetDev\CIGas\Gas CFTlopenmind\Swanson\Swanson RiverUnRXKGSF#1\Surveys\Pressures\AOGCC Annual Mat Bat Rpt\2010\KGSF #1 #7 9-27-10.xis Monthly Monthly Monthly Monthly Net Voidage Total Gas Gas Gas Gas Gas (Prod - Inj) Inventory Inj. Prod. Inj. Prod. Cum for POZ (Gas -In -Place) Month MCF MCF MCF MCF MCF MCF 1,544,000 Dec -98 0 55,137 55,137 1,488, 863 Jan -99 0 79,404 134,541 1,409,459 Feb -99 0 64,367 198,908 1,345,092 Mar -99 0 73,920 272,828 1,271,172 Apr -99 0 62,180 335,008 1,208,992 May -99 0 76,912 411,920 1,132,080 Jun -99 0 76,903 488,823 1,055,177 Jul -99 0 72,268 561,091 982,909 Aug -99 0 60,311 621,402 922,598 Sep -99 0 48,667 670,069 873,931 Oct -99 0 42,056 712,125 831,875 Nov -99 0 39,385 751,510 792,490 Dec -99 0 33,783 785,293 758,707 Jan -00 0 39,890 825,183 718,817 Feb -00 0 20,895 846,078 697,922 Mar -00 0 38,219 884,297 659,703 Apr -00 0 35,729 920,026 623,974 May -00 0 22,502 942,528 601,472 Jun -00 0 8,627 951,155 592,845 Jul -00 0 30,397 981,552 562,448 Aug -00 0 56,660 1,038,212 505,788 Sep -00 0 30,505 1,068,717 475,283 Oct -00 0 29,330 1,098,047 445,953 Nov -00 0 48,633 1,146,680 397,320 Dec -00 0 29,741 1,176,421 367,579 Jan -01 0 46,236 1,222,657 321,343 Feb -01 0 47,777 1,270,434 273,566 Mar -01 0 37,213 1,307,647 236,353 Apr -01 0 24,719 1,332,366 211,634 May -01 0 6,196 1,338,562 205,438 Jun -01 106,800 0 1,231,762 312,238 Jul -01 219,660 0 1,012,102 531,898 Aug -01 226,151 0 785,951 758,049 Sep -01 197,762 1,331 589,520 954,480 Oct -01 44,964 60,382 604,938 939,062 Nov -01 73,130 142,418 674,226 869,774 Dec -01 28,281 159,046 804,991 739,009 Jan -02 134,429 47,741 718,303 825,697 Feb -02 102,768 65,400 680,935 863,065 Mar -02 250,716 4,507 434,726 1,109,274 Apr -02 107,164 51,031 378,593 1,165,407 May -02 89,218 16,147 305,522 1,238,478 Jun -02 106,081 3,868 203,309 1,340,691 \lAnc380ntdfsl.anc380.chevrontexaco.netlshareWAU\MCBU\AlaskalDepts\AssetDev\CIGas\Gas CFTlopenmind\Swanson\Swanson RiverUnRXKGSF#1\Surveys\Pressures\AOGCC Annual Mat Bat Rpt\2010\KGSF #1 #7 9-27-10.xis • ATTACHMENT #1 0 KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES Month SRU 43-281 KGSF #1, Monthly Monthly Gas Gas Inj. Prod, MCF MCF KGSF #7A - Monthly Monthly Gas Gas Inj. Prod, MCF MCF F-ryonelk 64.5 Sand Totals Net Voidage Total Gas (Prod - Inj) Inventory Cum for POZ (Gas -In -Place) MCF MCF Jul -02 66,737 18,479 155,051 1,388,949 Aug -02 19,263 140,660 276,448 1,267,552 Sep -02 73,737 60,587 263,298 1,280,702 Oct -02 0 272,859 536,157 1,007,843 Nov -02 0 193,970 730,127 813,873 Dec -02 701 149,810 879,236 664,764 Jan -03 0 125,601 1,004,837 539,163 Feb -03 0 77,767 1,082,604 461,396 Mar -03 0 58,978 1,141,582 402,418 Apr -03 0 40,867 1,182,449 361,551 May -03 0 31,252 1,213,701 330,299 Jun -03 0 23,977 1,237,678 306,322 Jut -03 0 17,937 1,255,615 288,385 Aug -03 0 9,611 1,265,226 278,774 Sep -03 173,513 0 1,091,713 452,287 Oct -03 298,780 0 792,933 751,067 Nov -03 287,672 0 505,261 1,038,739 Dec -03 264,137 1,456 242,580 1,301,420 Jan -04 30,651 56,710 268,639 1,275,361 Feb -04 42,508 56,096 282,227 1,261,773 Mar -04 18,083 153,053 417,197 1,126,803 Apr -04 46,661 49,678 420,214 1,123,786 May -04 173,756 1,811 248,269 1,295,731 Jun -04 117,522 0 130,747 1,413,253 Jul -04 3,936 0 126,811 1,417,189 Aug -04 0 0 126,811 1,417,189 Sep -04 83,061 0 43,750 1,500,250 Oct -04 20,297 37,277 0 38,408 99,138 1,444,862 Nov -04 100,085 46,394 114,424 0 -68,977 1,612,977 Dec -04 1,372 5,222 1,523 3,687 -62,963 1,606,963 Jan -05 35,347 66,988 771 60,345 28,252 1,515,748 Feb -05 31,778 82,231 3,217 114,252 189,740 1,354,260 Mar -05 43,588 55,099 1,211 78,836 278,876 1,265,124 Apr -05 28,607 35,501 8,081 19,522 297,211 1,246,789 May -05 32,140 88,209 18,126 101,966 437,120 1,106,880 Jun -05 116,349 2,892 60,975 2,436 265,124 1,278,876 Jul -05 79,421 4,803 96,626 740 94,620 1,449,380 Aug -05 56,470 60,228 61,086 25,369 62,661 1,481,339 Sep -05 75,912 16,301 8,356 11,394 6,088 1,537,912 Oct -05 44,207 68,184 13,635 94,247 110,677 1,433,323 Nov -05 68,267 45,043 65,065 62,387 84,775 1,459,225 Dec -05 68,931 29,178 97,297 20,153 -32,122 1,576,122 Jan -06 24,400 154,713 21,678 176,620 253,133 1,290,867 Feb -06 123,934 83,744 191,098 99,388 121,233 1,422,767 t\Anc380ntdfsl.anc380.chevrontexaco.nettshareV"\MCBUWiaska\DeptsiAssetDevlClGas\Gas CFT\0penmind%$wanson\Swanson RiverUnd\KGSF#1\Sunreys\Pressures\AOGCC Annual Mat Bal RptV010WGSF #1 #7 9-27-10.xis • ATTACHMENT #1 • KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES SRU 43-281 KGSF #1 7 rKGSF #7A -1 Tyonek 64-5 Sand Totals \Wnc380ntdts1.anc380.chevrontexawo netlshareWAUWCBUVUaska\Depts\AssetDev\ClGas\Gas CFTWpenmind\SwansonlSwanson RiverUnit\KGSF#11Surveys\pressures\AOGCC Annual Mat Bal Rptt2010%GSF #1 #7 9-27-10.xis Monthly Monthly Monthly Monthly Net Voidage Total Gas Gas Gas Gas Gas (Prod - Inj) Inventory Inj. Prod. Inj. Prod. Cum for POZ (Gas -In -Place) Month MCF MCF MCF MCF MCF MCF Mar -06 54,898 145,807 35,421 147,941 324,662 1,219,338 Apr -06 131,597 34,604 85,982 19,989 161,676 1,382,324 May -06 106,658 4,759 110,253 26,840 -23,636 1,567,636 Jun -06 50,042 675 14,923 482 -87,444 1,631,444 Jul -06 0 79,130 0 36,777 28,463 1,515,537 Aug -06 63,182 130 16,045 0 -50,634 1,594,634 Sep -06 45,366 0 18,939 0 -114,939 1,658,939 Oct -06 18,013 58,243 42,099 7,334 -109,474 1,653,474 Nov -06 30,592 82,779 24,730 98,430 16,413 1,527,587 Dec -06 55,743 17,160 102,029 14,959 -109,240 1,653,240 Jan -07 21,586 59,415 34,936 91,755 -14,592 1,558,592 Feb -07 7,025 59,181 41,275 106,823 103,112 1,440,888 Mar -07 15,008 58,203 83,830 92,486 154,963 1,389,037 Apr -07 75,784 6,866 185,316 8,751 -90,520 1,634,520 May -07 8,872 23,772 32,655 55,100 -53,175 1,597,175 Jun -07 11,714 0 740 134 -65,495 1,609,495 Jul -07 7,350 0 0 0 -72,845 1,616,845 Aug -07 1,767 891 230 0 -73,951 1,617,951 Sep -07 0 253 0 240 -73,458 1,617,458 Oct -07 9,706 18,077 11,553 6,168 -70,472 1,614,472 Nov -07 13,638 40,135 7,563 8,237 -43,301 1,587,301 Dec -07 8,443 61,237 3,820 132,338 138,011 1,405,989 Jan -08 20,892 75,223 751 88,161 279,752 1,264,248 Feb -08 8,162 54,785 8,134 83,015 401,256 1,142, 744 Mar -08 94 1,014 0 4,872 407,048 1,136,952 Apr -08 46,111 3,360 11,372 0 352,925 1,191,075 May -08 88,929 12,687 218,106 12,037 70,614 1A73,386 Jun -08 20,487 4,309 32,741 0 21,695 1,522,305 Jul -08 8,057 0 2,181 0 11,457 1,532,543 Aug -08 19,270 484 0 0 -7,329 1,551,329 Sep -08 5,064 1,530 0 820 -10,043 1,554,043 Oct -08 15,323 46,294 2,459 5,913 24,382 1,519,618 Nov -08 3,361 95,514 0 82,213 198,748 1,345,252 Dec -08 10,856 92,077 7,285 162,128 434,812 1,109,188 Jan -09 25,898 54,278 31,732 114,632 546,092 997,908 Feb -09 26,994 50,408 42,968 76,145 602,683 941,317 Mar -09 25,801 14,995 10,298 22,451 604,030 939,970 Apr -09 158,105 989 236,991 608 210,531 1,333,469 May -09 36,786 103 134,138 27 39,737 1,504,263 Jun -09 43,429 519 103,093 299 -105,967 1,649,967 Jul -09 0 0 0 0 -105,967 1,649,967 Aug -09 0 39,305 45,129 228 -111,563 1,655,563 Sep -09 0 25,743 24,073 146 -109,747 1,653,747 Oct -09 0 0 28,450 271 -137,926 1,681,926 \Wnc380ntdts1.anc380.chevrontexawo netlshareWAUWCBUVUaska\Depts\AssetDev\ClGas\Gas CFTWpenmind\SwansonlSwanson RiverUnit\KGSF#11Surveys\pressures\AOGCC Annual Mat Bal Rptt2010%GSF #1 #7 9-27-10.xis • ATTACHMENT #1 0 KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES SRU 43.28 ! KGSF #7 r—KGSF WA T onek 64-5 Sand Totals \\Anc380ntdfsl.anc380.chevrontexaco.net\shareWAUNCBU\AIaske Depts\AssetDevVGastGas CFT10pennnind%Swanson\Swanson RiverUnk%KGSF#11Surveys\Pressures\AOGCC Annual Mat Bal Rpt\2010\KWF #1 #7 9.27-10.xls Monthly Monthly Monthly Monthly Net Voidage Total Gas Gas Gas Gas Gas (Prod - Inj) Inventory Inj. Prod. Inj. Prod. Cum for POZ (Gas -In -Place) Monti MCF MCF MCF MCF MCF MCF Nov -09 550 15,175 34,114 33,063 -124,352 1,668,352 Dec -09 137 8,539 11,074 66,621 -60,403 1,604,403 Jan -10 10,556 36,797 0 12,397 -21,765 1,565,765 Feb -10 0 48,589 17 2,232 29,039 1,514,961 Mar -10 0 64,473 0 54,969 148,481 1,395,519 Apr -10 0 13,709 135 19,853 181,908 1,362,092 May -10 0 15,589 10,554 27,926 214,869 1,329,131 Jun -10 384 4,530 189 7,769 226,595 1,317,405 Jul -10 1,616 0 0 490 225,469 1,318,531 \\Anc380ntdfsl.anc380.chevrontexaco.net\shareWAUNCBU\AIaske Depts\AssetDevVGastGas CFT10pennnind%Swanson\Swanson RiverUnk%KGSF#11Surveys\Pressures\AOGCC Annual Mat Bal Rpt\2010\KWF #1 #7 9.27-10.xls • Chevron August 13, 2010 Chantal R Walsh Petroleum Engineer, P.E. 0 Union Oil Company of California 3800 Centerpoint Dr., Suite 100 Anchorage, AK 99503 Tel: 907-263-7627 Email walshc@chevron.com Alaska,5 gas Ca M Cvnmissiori Mr. Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501-3539 RE: 2010 Annual Material Balance Calculations of Production and Infection Volumes: Kenai Gas Storage Facility #1 (KGSF#1), Swanson River Field Dear Commissioner Seamount: Attached for Alaska Oil and Gas Conservation Commission (AOGCC) review is the 2010 annual material balance calculation of production and injection volumes for the Kenai Gas Storage Facility #1 (KGSF#1), as required per Storage Injection Order #2A. This material balance includes all primary production from the Tyonek 64-5 reservoir (via the SRU 43-28 wellbore), as well as all storage operations from the two gas storage wells, KGSF #1 and KGSF #7A. Primary production occurred from December 1998 through May 2001 and storage operations are on-going since June 2001. Attachment #1 is a table of monthly gas production and injection volumes for KGSF #1 (formerly SRU 43-28) and KGSF #7A, from the commencement of primary production, through August 12, 2010. Pressures from the Tyonek 64-5 reservoir have been measured/estimated from both downhole pressure buildups and from surface shut-in tubing pressures. The surface readings were then converted to downhole pressures at a common datum of 6,395 ft TVD. These data points are tabulated in Attachment #2 and plotted versus the net cumulative production (production less injection) on the standard P over Z plot, shown in Attachment #3. As noted in previous Annual Material Balance reports, Attachment #3 shows that the early injection cycle pressures deviated above the straight line path established by the primary depletion pressure points. Following the primary production and injection cycle, the next two or three cycles (production & injection) show a consistent trend of the pressure/cumulative production data points migrating further left of the straight line path established by the primary depletion pressure points. The last two or three cycles (2007 — 2010) have been fairly consistent, indicating continued reservoir confinement of the gas storage volumes. MidContinent/Alaska/Chevron North America Exploration and Production www.chevron.com • Note that due to very, little gas drawn out of storage in the 2009/2010 winter season, the injection cycle for 2010 has limited data points, as we just started refilling the reservoir in July. Additionally, the final 2008/2009 pressure/cumulative production data point (taken 2/19/09), was corrected in the spreadsheet and the corrected value is reflected in this year's plot. If you or your staff has any questions regarding this annual report, please contact Chantal Walsh at 263-7627. Sincerely, f t Chantal Walsh Petroleum Engineer, P.E. Attachments: 1. KGSF #1 Facility Monthly production and injection volumes 2. Tyonek 64-5 Sand POZ Data 3. KGSF #1 Facility (Tyonek 64-5 Sand) - P/Z vs Cumulative Production Plot CC: Whitacre, Dave KGSF #1 Well File KGSF #7 Well File MidContinent/Alaska/Chevron North America Exploration and Production http://www.chevron.com ATTACHMENT #1 0 KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES SRU 43-28 / KGSF #1 1 1 KGSF #7A I r Tyonek 64-5 Sand Totals C:\Users\walshc\Desktop\KGSF #1 #7 Production Data 8-11-10.xis Monthly Monthly Monthly Monthly Net Voidage Total Gas Gas Gas Gas Gas (Prod - Inj) Inventory Inj. Prod. Inj. Prod. Cum for POZ (Gas -In -Place) Month MCF MCF MCF MCF MCF MCF 1,544,000 Dec -98 0 55,137 55,137 1,488,863 Jan -99 0 79,404 134,541 1,409,459 Feb -99 0 64,367 198,908 1,345,092 Mar -99 0 73,920 272,828 1,271,172 Apr -99 0 62,180 335,008 1,208,992 May -99 0 76,912 411,920 1,132, 080 Jun -99 0 76,903 488,823 1,055,177 Jul -99 0 72,268 561,091 982,909 Aug -99 0 60,311 621,402 922,598 Sep -99 0 48,667 670,069 873,931 Oct -99 0 42,056 712,125 831,875 Nov -99 0 39,385 751,510 792,490 Dec -99 0 33,783 785,293 758,707 Jan -00 0 39,890 825,183 718,817 Feb -00 0 20,895 846,078 697,922 Mar -00 0 38,219 884,297 659,703 Apr -00 0 35,729 920,026 623,974 May -00 0 22,502 942,528 601,472 Jun -00 0 8,627 951,155 592,845 Jul -00 0 30,397 981,552 562,448 Aug -00 0 56,660 1,038,212 505,788 Sep -00 0 30,505 1,068,717 475,283 Oct -00 0 29,330 1,098,047 445,953 Nov -00 0 48,633 1,146,680 397,320 Dec -00 0 29,741 1,176,421 367,579 Jan -01 0 46,236 1,222,657 321,343 Feb -01 0 47,777 1,270,434 273,566 Mar -01 0 37,213 1,307,647 236,353 Apr -01 0 24,719 1,332,366 211,634 May -01 0 6,196 1,338,562 205,438 Jun -01 106,800 0 1,231,762 312,238 Jul -01 219,660 0 1,012,102 531,898 Aug -01 226,151 0 785,951 758,049 Sep -01 197,762 1,331 ✓ 589,520 954,480 Oct -01 44,964 60,382 604,938 939,062 Nov -01 73,130 142,418 674,226 869,774 Dec -01 28,281 159,046 804,991 739,009 Jan -02 134,429 47,741 718,303 825,697 Feb -02 102,768 65,400 680,935 863,065 Mar -02 250,716 4,507 434,726 1,109,274 Apr -02 107,164 51,031 378,593 1,165,407 May -02 89,218 16,147 305,522 1,238,478 Jun -02 106,081 3,868 203,309 1,340,691 C:\Users\walshc\Desktop\KGSF #1 #7 Production Data 8-11-10.xis CAUsers\walshc\Desktop\KGSF #1 #7 Production Data 8-11-10.x1s • ATTACHMENT #1 • KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES SRU 43-28 / KGSF #1 KGSF #7A Tyonek 64-5 Sand Totals Monthly Monthly Monthly Monthly Net Voidage Total Gas . Gas Gas Gas Gas (Prod - Inj) Inventory Inj. Prod. Inj. Prod. Cum for POZ (Gas-In-Place) Month MCF MCF MCF MCF MCF MCF Jul-02 66,737 18,479 155,051 1,388,949 Aug-02 19,263 140,660 276,448 1,267,552 Sep-02 73,737 60,587 263,298 1,280,702 Oct-02 0 272,859 536,157 1,007,843 Nov-02 0 193,970 730,127 813,873 Dec-02 701 149,810 879,236 664,764 Jan-03 0 125,601 1,004,837 539,163 Feb-03 0 77,767 1,082,604 461,396 Mar-03 0 58,978 1,141,582 402,418 Apr-03 0 40,867 1,182,449 361,551 May-03 0 31,252 1,213,701 330,299 Jun-03 0 23,977 1,237,678 306,322 Jul-03 0 17,937 1,255,615 288,385 Aug-03 0 9,611 1,265,226 278,774 Sep-03 173,513 0 1,091,713 452,287 Oct-03 298,780 0 792,933 751,067 Nov-03 287,672 0 505,261 1,038,739 Dec-03 264,137 1,456 242,580 1,301,420 Jan-04 30,651 56,710 268,639 1,275,361 Feb-04 42,508 56,096 282,227 1,261,773 Mar-04 18,083 153,053 417,197 1,126,803 Apr-04 46,661 49,678 420,214 1,123,786 May-04 173,756 1,811 248,269 1,295,731 Jun-04 117,522 0 130,747 1,413,253 Jul-04 3,936 0 126,811 1,417,189 Aug-04 0 0 126,811 1,417,189 Sep-04 83,061 0 43,750 1,500,250 Oct-04 20,297 37,277 0 38,408 99,138 1,444,862 Nov-04 -►100,085 46,394 114,424 0 -68,977 1,612,977 Dec-04 1,372 5,222 1,523 3,687 -62,963 1,606,963 Jan-05 35,347 66,988 771 60,345 28,252 1,515,748 Feb-05 31,778 82,231 3,217 114,252 189,740 1,354,260 Mar-05 43,588 55,099 1,211 78,836 278,876 1,265,124 Apr-05 28,607 35,501 8,081 19,522 297,211 1,246,789 May-05 32,140 88,209 18,126 101,966 437,120 1,106,880 Jun-05 116,349 2,892 60,975 2,436 265,124 1,278,876 Jul-05 79,421 4,803 96,626 740 94,620 1,449,380 Aug-05 56,470 60,228 61,086 25,369 62,661 1,481,339 Sep-05 75,912 16,301 8,356 11,394 6,088 1,537,912 Oct-05 44,207 68,184 13,635 94,247 110,677 1,433,323 Nov-05 68,267 45,043 65,065 62,387 84,775 1,459,225 Dec-05 68,931 29,178 97,297 20,153 -32,122 1,576,122 Jan-06 24,400 154,713 21,678 176,620 253,133 1,290,867 Feb-06 123,934 83,744 191,098 99,388 121,233 1,422,767 CAUsers\walshc\Desktop\KGSF #1 #7 Production Data 8-11-10.x1s CAUsers\walshc\Desktop\KGSF #1 #7 Production Data 8-11-1O.As 9 ATTACHMENT #1 • KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES SRU 43-28 / KG SF #1 KGSF #7A r Tyonek 64-5 Sand Totals Monthly Monthly Monthly Monthly Net Voidage Total Gas Gas Gas Gas Gas (Prod - Inj) Inventory Inj. Prod. Inj. Prod. Cum for POZ (Gas -In -Place) Month MCF MCF MCF MCF MCF MCF Mar -06 54,898 145,807 35,421 147,941 324,662 1,219,338 Apr -06 131,597 34,604 85,982 19,989 161,676 1,382,324 May -06 106,658 4,759 110,253 26,840 -23,636 1,567,636 Jun -06 50,042 675 14,923 482 -87,444 1,631,444 Jul -06 0 79,130 0 36,777 28,463 1,515,537 Aug -06 63,182 130 16,045 0 -50,634 1,594,634 Sep -06 45,366 0 18,939 0 -114,939 1,658,939 Oct -06 18,013 58,243 42,099 7,334 -109,474 1,653,474 Nov -06 30,592 82,779 24,730 98,430 16,413 1,527,587 Dec -06 55,743 17,160 102,029 14,959 -109,240 1,653,240 Jan -07 21,586 59,415 34,936 91,755 -14,592 1,558,592 Feb -07 7,025 59,181 41,275 106,823 103,112 1,440,888 Mar -07 15,008 58,203 83,830 92,486 154,963 1,389,037 Apr -07 75,784 6,866 185,316 8,751 -90,520 1,634,520 May -07 8,872 23,772 32,655 55,100 -53,175 1,597,175 Jun -07 11,714 0 740 134 -65,495 1,609,495 Jul -07 7,350 0 0 0 -72,845 1,616,845 Aug -07 1,767 891 230 0 -73,951 1,617,951 Sep -07 0 253 0 240 -73,458 1,617,458 Oct -07 9,706 18,077 11,553 6,168 -70,472 1,614,472 Nov -07 13,638 40,135 7,563 8,237 -43,301 1,587,301 Dec -07 8,443 61,237 3,820 132,338 138,011 1,405,989 Jan -08 20,892 75,223 751 88,161 279,752 1,264,248 Feb -08 8,162 54,785 8,134 83,015 401,256 1,142,744 Mar -08 94 1,014 0 4,872 407,048 1,136,952 Apr -08 46,111 3,360 11,372 0 352,925 1,191,075 May -08 88,929 12,687 218,106 12,037 70,614 1,473,386 Jun -08 20,487 4,309 32,741 0 21,695 1,522,305 Jul -08 8,057 0 2,181 0 11,457 1,532,543 Aug -08 19,270 484 0 0 -7,329 1,551,329 Sep -08 5,064 1,530 0 820 -10,043 1,554,043 Oct -08 15,323 46,294 2,459 5,913 24,382 1,519,618 Nov -08 3,361 95,514 0 82,213 198,748 1,345,252 Dec -08 10,856 92,077 7,285 162,128 434,812 1,109,188 Jan -09 25,898 54,278 31,732 114,632 546,092 997,908 Feb -09 26,994 50,408 42,968 76,145 602,683 941,317 Mar -09 25,801 14,995 10,298 22,451 604,030 939,970 Apr -09 158,105 989 236,991 608 210,531 1,333,469 May -09 36,786 103 134,138 27 39,737 1,504,263 Jun -09 43,429 519 103,093 299 -105,967 1,649,967 Jul -09 0 0 0 0 4.- -105,967 1,649,967 Aug -09 0 39,305 45,129 228 -111,563 1,655,563 Sep -09 0 25,743 24,073 146 -109,747 1,653,747 Oct -09 0 0 28,450 271 -137,926 1,681,926 CAUsers\walshc\Desktop\KGSF #1 #7 Production Data 8-11-1O.As . 0 ATTACHMENT #1 0 KENAI GAS STORAGE FACILITY #1 (KGSF#1) MONTHLY PRODUCTION AND INJECTION VOLUMES SRU 43-28 / KGSF #1 1 r--'KGSF #7A r Tyonek 64-5 Sand Totals Monthly Monthly Monthly Monthly Net Voidage Total Gas Gas Gas Gas Gas (Prod - Inj) Inventory Inj. Prod. Inj. Prod. Cum for POZ (Gas -in -Place) Month MCF MCF MCF MCF MCF MCF Nov -09 550 15,175 34,114 33,063 -124,352 1,668,352 Dec -09 137 8,539 11,074 66,621 -60,403 1,604,403 Jan -10 10,556 36,797 0 12,397 -21,765 1,565,765 Feb -10 0 48,589 17 2,232 29,039 1,514,961 Mar -10 0 64,473. 0 54,969 148,481 1,395,519 Apr -10 0 13,709 135 19,853 181,908 1,362,092 May -10 0 15,589 10,554 27,926 214,869 1,329,131 Jun -10 -Sc6y 370 4,517 189 7,769 226,596 1,317,404 Jul -10 1,616 0 0 490 225,470 1,318,530 C:\Users\walshc\Desktop\KGSF #1 #7 Production Data 8-11-10.x1s ATTACHMENT #2 • Tyonek 64-5 Sand POZ DATA Kenai Gas Storage Facility #1 (KGSF #1) Wells: KGSF #1 & KGSF #7A Date IType Test Gauge Depth, It I Cu.,, bcf I IbgP, psia I Res. P, psia I Z I P/Z lCommmts ■ 6/9/2001 SITP ry 12/5/1998 SITP .v 0 0 2850 3306 1 0.8782 1 3764 ISITP 1.148 7/27/1999 STTP 6395 0.56169 1775 2059 0.8586 2398 STIP 2111 9/9/2000 BHP buildu 6395 1.0 882 I I00 0.9017 1220 PBU w/ Gauges FL - 6195' 2447 2/20/2001 STIP 0 1.270 540 626 1 0.9396 1 667 ISITP 3322 6/9/2001 STIP 0 1.339 380 441 1 0.9566 1 461 1 SITP ■ 6/9/2001 SITP 1 0 1 1.339 1 380 1 441 1 0.9566 1 461 STT? 7/11/2001 SIT? 0 1.148 875 1015 0.9078 1118 21 hr STEP after 618 hr injection 9/18/2001 STIP 0 0.673 1820 2111 0.8578 2461 4 hr SIT? prior to flow due to SEP ESD 9/20/2001 SITP 0 0.678 1 1810 2099 0.8580 2447 124 hr SIT? after 1 day of flow on 9/19 at 5.5 mmcfd 10/9/2001 SITP 0 0.572 1 1980 2247 0.8562 2682 18 day SITP during C12 restagi.n 2002 INJECTION CYCLE 10/9/2001 STIP 0 0.572 1980 2297 0.8562 2682 8 da SITP duringC12 restaging 4/5/2002 STIP 0 0.400 2280 2645 0.8584 3081 15 hour SM, 7/12/2002 1 SITP 1 0 1 0.190 1 2620 1 3039 1 0.8680 1 3501 1 STIP 7/26/2002 SLIP 1 0 1 0.200 1 2630 -1 0.8684 1 3513 1 SIT? 2002/2003 PRODUCTION CYCLE 7/26/2002 STIP 2003 INJECTION CYCLE 7/25/2003 STIP 0 1.252 224 260 0.9739 267 SIT? from surf PBU 12/29/2003 STTP1 0 1 0.254 1 2440 1 2124 1 0.8620 1 3282 ISI duration = 19 hrs. At shut in = 2 hrs; 2440 psig SLIP; Ignores FL�1. 2003/2004 PRODUCTION CYCLE 4, G 7/14/2004 STIP 0 0.153 2565 2974 0.8660 2358 S1"1"Y - 12 Aa v 12/5/2004 SITP 0 -0.082 2865 3$� ` 0.8789 3783435 0 STTP- 4day T 4/27/2007 STIP 0 -0.117 2828 3279 0.8771 3739 STT? -8 da GSF#1 2004/2005 PRODUCTION CYCLE 0 -0.065 2711 1 3144 1 0.8717 1 3606 ISITP-5 da G81741 12/5/2004 STIP 0 -0.082 2865 3322 0.8789 3780 SITP-4da GSF#1 6/8/2005 STIP1 0 1 0.396 1 2080 1 2412 1 0.8562 1 2817 ISITP - 6 hr�b�` 2005 INJECTION CYCLE 6/8/2005 STT? 0 0.396 2080 2412 0.8562 2817 SLIP - 6 hr 8/8/2005 STIP 0 0.022 2828 2828 3279 3279 ^ 8771 0.8771 3739 . 739 STIP - 1 hr 2005/2006 PRODUCTION CYCLE 12/30/2005 0 -0.044 2786 3231 0.8751 3692 snT - 3 days 3/22/2006 STIP1 0 1 0.396 1 1905 1 2209 1 0.8567 1 2579 1 SIT? - < 1 day (KGSF#7a) 6/Na17 PRnnrTCTION CYC1.F 9/30/2006 STTP 1 0 1 -0.127 1 2815 1 3264 1 0.87643725 STTP-12 da GSF#1 TIP 12/4/2006 S 0 -0.049 2665 3090 0.8698 3553 SITP -18.5 hrs KGSF#7a 1/10/2007 STTP 0 -0.003 2450 2841 0.8623 1 3295 1 SIT? -9 firs GSF#1 3/26/2007 SITP 1 0 1 0.167 1 2231 1 2587 1 0.8576 1 3017 1 SLIP 4 da GSF#1 2007 INJECTION CYCLE 0 0.407 1760 2026 0.8592 2358 SITP - 37 days(KGSF 47A 5/2/2008 SITP 3/26/2007 SITP 1 0 1 0.167 1 2231 1 2587 1 0.8576 3017 ISTIP -4 da GSF#1 4/27/2007 STIP 0 -0.117 2828 3279 0.8771 3739 STT? -8 da GSF#1 6/4/2007 SITP 0 -0.065 2711 1 3144 1 0.8717 1 3606 ISITP-5 da G81741 9/11/2007 STIP 0 -0.088 2717 1 3151 1 0.8720 1 3598 ISITP-27 da GSF#1 2007/2008 PRODUCTION CYCLE 0 0.407 1760 2026 0.8592 2358 SITP - 37 days(KGSF 47A 5/2/2008 SITP 9/11/2007 SITP 1 0 1 -0.088 1 2717 1 3151 1 0.8720 3598 1ITP -27 da GSF#1 12/2/2007 SITP 0 -0.043 2604 3005 0.8669 3466 SITP - 6 days(KGSF #7A - PMW 1/17/2008 STIP 0 0.243 2078 2397 0.8562 2800 SITP - 8 days(KGSF #7A 4/8/2008 SITP 0 0.407 1760 2026 0.8592 2358 Isrrp - 37 days(KGSF #7A 2008 INJECTION CYCLE 4/8/2008 SITP 0 0.407 1760 2026 0.8592 2358 SITP - 37 days(KGSF 47A 5/2/2008 SITP 0 0.353 1925 2218 0.8566 2567 SITP - -2 months(KGSF 97A 7/1/2008 SIT? 0 0.022 2643 3049 0.8684 3494 SIT? - 22 da GSF#1 7/28/2008 SITP 0 0.015 2648 3055 0.8686 3517 SIT? - 22 days(KGSF 91 9/16/2008 STTP 0 -0.005 2664 3073 0.8692 3535 SIT? - 22 days(KGSF 91 9/30/2008 SIT? 0 -0.010 2670 0.8694 3543 SIT? - 5 days (KGSF #I) 8/13/20102:26 PNC\Anc380ntdfsl.anc380.chevrontexaco.net\share\NAU\MCBLAAlwka\Depts\AssetDev\CIGas\Gas CFAOpmmind\Swanson\Swanson RiverUnit\KGSF#1\Surveys\Pressmr \AOGCC Annual Mat Bal Rpt\2010\KGSF#1 & #7A 64-5 Sd POZ 8-11-10.xls64-5 POZ Data 0 ATTACHMENT #2 0 Tyonek 64-5 Sand POZ DATA Kenai Gas Storage Facility #1 (KGSF #1) Wells: KGSF #1 & KGSF VA Date IType Test I Gau a th, 7r Cum, bcf I ThgP, psia I Res. P, psia I Z P/Z jcommmtg 2008/2009 PRODUCTION CYCLE 9/30/2008 STTP 0 -0.010 2670 3080 0.8694 1 3543 1 SITP - 5 days(KGSF #I (/16/2009 SITP 0 0.576 1392 1599 0.8728 1 1832 ISITP - 2.5 days(KGSF #1 2/19/2009 SITP 0 0.626 1376 1579 0.8737 1 1807 1 STIP - 24 hr SI (KGSF #1 & #7A) 2009 INJECTION CYCLE 2/19/2009 SITP 0 0.626 1376 1579 0.8737 1807 STIP - 24 hr SI (KGSF #1 & 97A) 6/14/2009 SITP 0 -0.065 2781 3209 0.8742 3671 SITP - 10 days SI(KGSF #1 7/13/2009 SIT? 0 -0.106 2850 3287 0.8774 3746 SITP - 14 days SI(KGSF #1 8/10/2009 SITP 0 -0.106 2828 3 0.8764 3722 SIT? - 42 days SI (KGSF #7A) 2009/2010 PRODITMom CYCi F 10/12/2009 SIT? 0 -0.109 2774 1 3218 1 0.8746 1 3680 -ITP-23da s(KGSF #7A 1/24/2010 STIP 0 -0.012 2630 3036 0.8679 3498 SIT? - 4 days KGSF #1 3/8/2010 STIP 0 0.035 2528 1 2919 1 0.8644 3377 SITP - 4 day SI KGSF #1 & #7A 5/132010 SITP 0 0.181 2231 1 2576 1 0.8575 3004 1 STIP - 24 hrs SI (KGSF #1) 2010 INJECTION CYCLE 5/13/2010 SIT? 0 1 0.181 2231 1 2576 1 0.8575 1 3004 SITP - 24 hrs SI GSF #1 8/11/2010 SIT? 0 1 0.176 2313 1 X71 0.8588 1 3110 ISITP - 14 days SI KGSF #1 8/13/20102:26 PM\Anc380ntdfsl.anc380.che ntexaco.net\share\NAU\MCBUWaska\Depts\AssetDev\CIGas\Gas CMOpwnund\Swanson\SwansonRivaUnit\KGSF#1\Surveys\Pressures\AOGCCAnnual Mat Bal Rpt\2010\KGSF#1 & #7A 64-5 Sd POZ 8-11-10.x1s64-5 POZ Data \\Anc380ntdfsl.anc380.chevrontexaco.net\share\NAU\MCBU\Alaska\Depts\AssetDev\CIGas\Gas CFT\Openmind\Swanson\Swanson RiverUnit\KGSF#1\Surveys\Pressures\AOGCC Annual Mat Bal Rpt\20IO\KGSF#1 & #7A 64-5 Sd POZ 8-11-10.x1s 0 0 ATTACHMENT #3 KGSF #1 FACILITY (Tyonek 64-5 Sand) - P/Z vs Cumulative Production Plot 4000 +Primary x'01 Inj cycle --0—'02 Inj cycle 3500 0 '02 Prod cycle t '03 Inj Cycle 04 Prod Cycle 3000 - \ 04 Inj Cycle 2010 Injection 0 05 Prod Cycle data very limited —� 05 Inj Cycle 2500 f 06 Prod Cycle —3- 06 Inj Cycle 0 07 Prod Cycle ^,2000 —3N— 07 Inj Cycle 'A ¢ `.-08 Prod Cycle N —�- 08 Inj Cycle a" 1500` . -f-- 09 Prod Cycle ` 09 Inj Cycle 10 Prod Cycle 1000 -t 10 Inj Cycle 500 0 -0.2 0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 Cumulative Gas Produced (Bcf) \\Anc380ntdfsl.anc380.chevrontexaco.net\share\NAU\MCBU\Alaska\Depts\AssetDev\CIGas\Gas CFT\Openmind\Swanson\Swanson RiverUnit\KGSF#1\Surveys\Pressures\AOGCC Annual Mat Bal Rpt\20IO\KGSF#1 & #7A 64-5 Sd POZ 8-11-10.x1s 0 0 MIT_Swanson River 09-17-09• • Page 1 of 2 Regg, James B (DOA) ~ ~ ~ ~-C)c~ From: Regg, James B(DOA) ~~Q~Q l~~ ~ `~i a Sent: Wednesday, September 23, 2009 1:46 PM To: 'Greenstein, Larry P' Cc: DOA AOGCC Prudhoe Bay; Fleckenstein, Robert J(DOA) Subject: RE: MIT_Swanson_River_09-17-09 We will change packer ND on our copy of the MIT report; you do not need to resend it to us. You also do not need to retest. You might consider for future MITs to test to a higher pressure than the bare minimum - most tests on injectors are done to a higher than minimum likely for this very reason (mistake on packer depth that affects test pressure). Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 , ~ r; j q ~~~~1~ 4~`..~;.k~a~§~~w; ',a, t, , _ ~.~ From: Greenstein, Larry P [mailto:Greensteinlp@chevron.com] Sent: Wednesday, September 23, Z009 1:20 PM To: Fleckenstein, Robert J(DOA); Regg, James B(DOA); Maunder, Thomas E(DOA); DOA AOGCC Prudhoe Bay Cc: Merle, Greg L; Walgenbach, Christopher; Bush, Robert E; Musgrove, Richard L; Winslow, Paul M; Myers, Chris S; Santiago, Johnny T; Brown, Glynn B; Hershberger, Bruce A.; Tanner, Steve L Subject: RE: MIT_Swanson_River_09-17-09 Sarry for the mistake, Bob. With the new tubing installed this summer, the new packer v,ras installed at 6288' as you have referenced. The 5030' packer depth was for the old completion in this well. Jim, with the TVD of the new packer in the calculation, the testing pressure for the MIT becomes about 30# higher than the testing pressure we used. Do yau need us ta redo this MIT with the 30# higher test pressure, or will the documented test prove sufficient meehanical integrity for this wel!?? La rry From: Fleckenstein, Robert J (DOA) [mailto:bob.fleckenstein@alaska.gov] Sent: Wednesday, September 23, 2009 12:51 PM To: Greenstein, Larry P; Regg, James B(DOA); Maunder, Thomas E(DOA); DOA AOGCC Prudhoe Bay Cc: Merle, Greg L; Walgenbach, Christopher; Bush, Robert E; Musgrove, Richard L; Winslow, Paul M; Myers, Chris S; Santiago, Johnny T; Brown, Glynn B; Hershberger, Bruce A.; Tanner, Steve L Subject: RE: MIT_Swanson_River_09-17-09 Larry, I show the PKRTVD for well # KGSF #1 PTD 1610080 to be 6288 as reported on a 10-404 dated 9/9/09 and received by the agency on 9/14/09. However, you show the ND to be 5030. Please advise which depth is correct. 9/23/2009 MIT_Swanson_River_09-17-09~ ~ Page 2 of 2 BobF Robert J. Fleckenstein Statistical Technician II Alaska Oil and Gas Conservation Commission Office: 907-793-1242 Fax: 907-276-7542 *Please z~o[e ne~~ emai:t ac~dress bob.fleclzenstein(~a,alaska. ov From: Greenstein, Larry P [mailto:Greensteinlp@chevron.com] Sent: Wednesday, September 23, 2009 12:15 PM To: Regg, )ames B(DOA); Maunder, Thomas E(DOA); Fleckenstein, Robert J(DOA); DOA AOGCC Prudhoe Bay Cc: Merle, Greg L; Walgenbach, Christopher; Bush, Robert E; Musgrove, Richard L; Winslow, Paul M; Myers, Chris S; Santiago, Johnny T; Brown, Glynn B; Hershberger, Bruce A.; Tanner, Steve L Subject: MIT_Swanson_River_09-17-09 Here is the official report of the MITs for KGSF #1 and KGSF #7A performed and witnessed at Swanson River Field on 9-17-09. «MIT Swanson River 09-17-09.x1s» 9/23/2009 STATE OF ALASKA ALAS~IL AND GAS CONSERVATION COMMIS N REPORT OF SUNDRY WELL OPERATIONS wc~a- 4~l~f~Za°t 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ Run 3-1/2" tubing Performed: Aiter Casing ^ Pull Tubing Q PerForate New Pool ^ Waiver ^ Time E~ension ^ Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well ^ 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ^ Exploratory ^ 161-008 ~ 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic^ Service ^~ 6. API Number: ~ 50-133-10160-00 ' 8. Property Designation (Lease Number): 9. Well Name and Number: ?~ ~ ~ ;, ~, s ..° " ~ ~ FEDA028399 [Swanson River Unit] , _ Swanson River KGSF#1 '~ 10. Field/Pool(s): , i=' , ~ ) ~ ~ ^ ~ Swanson River Field / Tyonek Gas Storage & Tyonek Undef Gas 9'~!~/~ 11. Present Well Condition Summary: Total Depth measured 10,875 ~ feet Plugs (measured) 6,813 feet ~ true vertical 10,875 feet Junk (measured) 6,813 feet Effective Depth measured 6,813 feet Packer (measured) 6,288 feet true vertical 6,813 feet (true vertical) 6,288 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 31' 20" 31' 31' Surface 2,032' 11-3/4" 2,032' 2,032' °"' Intermediate Production 10,875' 7" 10,875' 10,875' 3,830psi 6,340psi Liner PerForation depth: Measured depth: 6,380'-6,388' r ~ ~f~S,F ~ ~, +~, ~ '',..~..~..• ,: ~, - , True Vertical depth: 6,380'-6,388' Tubing (size, grade, measured and true vertical depth): 3-1/2" 9.3# L-80 6,354' 6,354' Packers and SSSV (type, measured and true vertical depth): Baker SAB-3 Perm Paker 6,288' N/A N/A 12. Stimulation or cement squeeze summary: Intervais treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 950psi 2,900psi Subsequent to operation: 0 8000 0 800psi 2,574psi 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory^ Development ^ Service ^~ Daily Report of Well Operations X 16. Well Status after work: Oil Gas WDSPL GSTOR ^~ WAG ^ GINJ ^ WINJ ^ SPLUG ^ 17. I hereby certiTy that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 309-221 Contact Stan Porhola 263-7640 Printed N~~jTimothy C. Brandenburg Title Drilling Manager ! Signature ,~ -~ (~ ~--- Phone 276-7300 Date 9/9/2009 Form 10-404 Revised 7/2009 ~~~,. S~~ ~ ~' ?~(~~ Submit Original Only • ~ ~Chevron ~ Chevron - Alaska ~ Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) KGSF #1 , SWANSON RIVER KGSF 1 :'"i" .:~z;. . FEDA028399 5013310160 R'.$..n , .;_, h QA5333 174.00 ..~ w., . r . ~ t~. ~~ ~~ .. . . ,~ Primary Job Type Job Category Objective Actual Start Date Actual End Date Well Preparation Well Services 7/6/2009 7/7/2009 Primary Wellbore Affected Wellbore UWI Well Permit Number SRU 43-28 5013310160-00 1610080 ~. ._ r ~ ~.~~. ~ . < ~' ~ ,~ ," b0:00 - 7!'7l2009 00:00 ~ .: ,., ~ :~ ~ ~ ~ ; ~ ~ ,, ' ~ ~ ~ Operations Summary Perform MIT on 7"x 2 3/8" Annulus to 2500 psi for 45min. RU Slickline, Pressure test lubricator 250psi low/3500psi hoigh. RIH w/ GR & fluid sampler to 6,750' SLM. POOH. RD slickline. ~Chevron Chevron - Alaska ~ Daily Operations Summary Well Name Legal Welt Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) KGSF #1 SWANSON RIVER KGSF 1 FEDA028399 5013310160 OA5333 174.00 ~ ~ ~, xs. •.~ _~. _ ~~.;~ ; . ~~ ~, ~~,~ . r _ . ,. Primary Job Type Job Category Objective Actual Start Date Actual End Date Tubing Repair Major Rig Replace existing 2-3/8" tubing w/ new 3-1/2" tubing. 7l17/2009 7/29/2009 Work Over (MRWO) Primary Wellbore Affeded Wellbore UWI Well Permit Number KGSF #1 5013310160-00 1610080 ~ _ ~, _ _~ .~~' ~~ %~~ s ~~ 7~17f2~09 QO:~ ~,t~ ~ Operations Summary Conduct PJSM. AOGCC inspector Lou Grimaldi onsite for rig inspection. Conduct pre-spud and SIMOPS meeting on location. Mix 10.2 ppg NaCI/NaBr brine. Shutdown for the night. Operating daylight hours only. 7/18/2009 00:04 - 7/18/2009 00:00 Y.~ ,.~t' "' ' Operations Summary Conduct PJSM. Continue to mix 10.2 ppg NaCI/NaBr brine and 10.2 ppg CaC03 pill. R/U to circ down tubing. Test lines to 4000 psi - OK. Bullhead 33 bbl 10.2 ppg CaC03 pill at 3 bpm. Bullhead 43 bbl 10.2 ppg brine at 3 bpm. ICP = 600, FCP = 2500 psi. Shutdown w/ SITP = 2300 psi. Monitor for 15 min, SITP = 2280 psi. Open well and bleed back 13 bbl @ 1 bpm FCP = 100 psi. Close well, SITP = 650 psi. Circ 29 bbl 10.2 ppg brine at 2.0-2.5 bpm w/ FCP = 3350 psi. Shutdown w/ SITP = 2750 psi. Open well and bleed back 12 bbl. Close well, SITP = 2350 psi. Monitor for 5 min, SITP = 2380 psi. Open well, flowing gas.Close well, SITP = 2300 psi. Monitor for 1 hour, SITP = 2500 psi. Open well and bleed down to 0 psi. Recovered 4 bbl brine. Close well, SITP = 300 psi. Monitor well for 30 min, SITP = 350 psi. Secure well. Shutdown for the night. Operating daylight hours only. <, ~~'~9/2009 00:00 - 7/20/3009 00:00 ,"_ ' ~ '~ ; Operations Summary Conduct PJSM. SITP = 2250 psi. Open well, flowing gas. Fluid to surface w/ ICP = 1600 psi, FCP = 2000 psi, then turned to dry gas. Continue flowing well w/ ICP = 150 psi, additional fluid to surface at 0.5 bpm. Close well. Monitor for 5 min, SITP = 625 psi. At 10 min, SITP = 725 psi. Contact town and discuss plan forward. Prep to perform lube & bleed. Open well, ICP = 1650 psi. Bleed gas down to 1400 psi, fluid to surface. Shut-in well. Contact town. Conduct monthly safety meeting w/ rig crews. Open well, ICP = 1850 psi. Gas and fluid returns turning to dry gas. Shut-in well, SITP = 2750 psi. Recovered +/- 76 out of 105 bbl pumped (brine + pill). Mix new brine and CaC03 pill and increase weight to 10.6 ppg. Secure well. Shutdown for the night. Operating daylight hours only. ~ ~, , 8 Qf1"~4~i~r ~ ~~ ~, :~~ :: >; ~ , ,. , ~~k ~fi: ~ ~ ~ m > . ~ ,..~ rr Operations Summary Conduct PJSM. Build 10.6 ppg brine and CaC03 pill. Test lines to 4000 psi - OK. SITP = 2850 psi, Csg Press = 710 psi. Bullhead 40 bbl 10.6 ppg CaC03 pill and displace w/ 29 bbl 10.6 ppg brine at 2.7 bpm, ICP = 2850 psi, "A" annulus = 670 psi. FCP = 3400 psi, "A" annulus = 710 psi. Close well, SITP = 2700 psi. Monitor for 5 min, SITP = 2520 psi, at 30 min SITP = 2500 psi, at 1 hour SITP = 2460 psi. Open well and bleed pressure to 2050 psi w/ 4 bbl brine returns. Close well and monitor for 5 min, SITP = 2095 psi, at 30 min SITP = 2150 psi. Open well and bleed pressure to 1590 psi w/4 bbl brine returns. Close well and monitor for 5 min, SITP = 1600 psi, at 30 min SITP = 1750 psi. Open well and bleed pressure to 1440 psi w! 6 bbl brine returns. Close well and monitor for 5 min, SITP = 1500 psi, at 1.5 hours SITP = 1950 psi. Call town and discuss plan forward. Pump 19 bbl brine w/ ICP = 2700 psi. ,~w ;~k•~ 7/21t2009 OOs00 - 7/22I200& OOt00 «.v ~ 3 . ,, ~: Operetions Summary SITP = 2900 psi. Bleed 0.5 bbl brine, turning to gas. Close well, SITP = 2600 psi. Conduct PJSM. SITP = 2730 psi. Bleed gas, SITP = 2710 psi. Fluid pack pump. Conduct PJSM. Lube & Bleed well. Initial SITP = 2650 psi. Lube & Bleed in 1.5 hr increments to allow brine and gas to swap. Total 12.35 bbl brine lubed in, bleeding off dry gas. As of midnight, SITP = 1250 psi. r., ~ ~:. 7/2 ~2~Q&~ ~,s00 - 712~~ OQ;04 . - ~ , ~, u. , ,, r.v..~ ~~4~~ ~~~ ~~~r~r>~ as. ,,::< Operations Summary Bleed well to 800 psi. Lube in 3.8 bbl brine. SITP = 1050 psi. Wait 2.75 hrs for fluid to swap. Bleed well from 1420 psi to 400 psi. Lube in 3.8 bbl brine. SITP = 670 psi. Wait 1.75 hrs for fluid to swap. Bleed well from 980 psi to 40 psi, fluid returns at surface. SITP = 40 psi. Monitor for 1.25 hrs. SITP = 100 psi. Bleed well and monitor, slight flow on tubing. PJSM w/ slickline crews. SITP = 70 psi. Bleed well to 0 psi and monitor for 30 min. SITP = 60 psi. R/U slickline lubricator and test to 250/2500 psi - test OK. SITP = 150 psi. RIH w/ slickline latch. Found fluid level at 155'. Latch into chemical injection mandrel and sheared tool. POOH. R/D lubricator. Re-pin latch. R/U lubricator and test to 250/2500 psi - test OK. RIH and pull dummy valve at 4,983'. POOH. R/D slickline. SITP = 290. SICP = 500 psi. Circ 10.6 ppg brine down tubing taking returns up the annulus. SITP = 60 psi. SICP = 35 psi. Bleed tubing to 0 psi, slight flow. Circ additional brine. Flow check well, no flow. Install BPV. N/D tree. N/U BOPE. Pull BPV. Close annular, secure well for the night. Rest crews. z , , ~ ~ .,~ ~ ~..a . .. ~,W. 3, 7/23/2009 OQt00 - 7t2412009~~00:00 ~ ~ ` °~ ~ ~ ` ~~ `` ~ Operations Summary Conduct PJSM. SITP = 0 psi, SICP = 0 psi. R/U Key Energy Rig #3. Test BOPE to 250/3000 psi - test OK. Test witnessed by John Crisp with AOGCC. Greg Noble with BLM waived witness. P/U tubing handling equipment. P/U tubing hanger and pull packer toose at 78k. Close annular. R/U and reverse circulate 50 bbls 10.6 ppg brine. No gas in returns. Close 2-3/8" pipe rams. Secure well for the night. Rest crews. ~ 1 ~4Q9 ~iOQ.:,:~:~~f:tl~1 •.,i~{#rA ' ~ ;{~~A, ~ ;~~ ~7 ~ ~„ : ,. , ,~~-~ , ~ ~ ~ . ~~ . _ . . r. ~. ~_ w ~~ .. Operations Summary Conduct PJSM. SITP = 0 psi. SICP = 0 psi. Reverse circ well 45 bbl 10.6 ppg brine. Monitor well. P/U and L/D tubing hanger and 2-3/8" tubing and jewelry. R/U 3-1/2" handling equipment. P/U 5-7/8" bit, 7" casing scraper, sub and X/0 to 3-1/2" 9.3# L-80 Hydril 503 tubing. RIH U 2480'. Close 3-1/2" pipe rams. Secure well for the night. Rest crews. ~Ch Chevron - Alaska ~ ~ Daily Operations Summary Weil Name Legal Well Name Lease Surface UWI ChevNo Origina! RKB (ft) Water Depth (ft) KGSF #1 SWANSON RIVER KGSF 1 FEDA028399 5013310160 QA5333 174.00 ,w. .. , ~ n~ ~ ~tF ,~~ - ~ ,~ t~„~ .. ~ ~t~ ~~~ ~ ~~ ~~ ~,~ ~ ~~ ~~ ~` ^ 7/26/2009 00:00 - 7/26/2005 00:00 Operations Summary Conduct PJSM. SITP = 0 psi. SICP = 0 psi. Open pipe rams. Circ btms up at 4 bpm. Flow check well - no flow. RIH w/ bit and scraper U 6335'. Circ btms up at 4 bpm. Flow check well - no flow. POOH. UD bit and scraper. P/U packer and tail pipe. Begin RIH w/ 3-1l2" completion U 1585'. Close 3-1/2" pipe rams. Secure well for the night. Rest crews. 7t26l3tX09~lIfi:00`~..~'~~'X/~~99°OOs00~ ~ ::.; ~ ~~ ~~ :~ ~ ~ ~~ ~ Operations Summary Conduct PJSM. SITP = 0 psi. SICP = 0 psi. Continue RIH of 3-1/2" 9.3# L-80 completion f/1,585' t16,354'. Land tubing hanger. Test hanger to 2,000 psi for 5 min - test OK. R/U slickline. RIH w/ PX plug and set in X-profile at 6,344'. POOH. Pressure tubing to 4,000 psi to set SAB-3 packer at 6,288'. Test tubing to 4,000 psi for 30 min - test OK. Perform MIT test 7"x3-1/2" annulus to 2,500 psi for 30'min - test OK. RIH w/ SS latch tool and open sliding sleeve. POOH. Circ 180 bbl 8.5 ppg packer fluid (3% KCI + ~prrosion inhibitor), displace w/ 60 bbl 10.6 ppg brine. Circ 4 bbl freeze protect (diesel) down annulus. RIH w/ SS latch tool and close sliding sleeve. POOH. R/D slickline. Test tubing to 2500 psi for 5 min - test OK (confirm sleeve closed). Shut-in and secure weli for the night. Rest crews. 7/27/2009 00:00 - 712$i20i1~ A4:t~0 ~. < <~. Operations Summary Conduct PJSM. Set TWC. N/D BOPE. N/U tree. Test all tree components to 250/3000 psi for 30 min - test OK. Pull TWC. R/D Key Energy Rig #3. Release rig at midnight. Move rig to SCU 12A-04. T`/^~8/2Cki~9 Ot1:00`- 7~J29f2409 00:0l1 ~-< ;; ,t Operations Summary R/U slickline and test lubricator 250/2500 psi - test OK. Swab well to 2190'. RIH and pull PX prong and plug and flowback 54.5 BBLS of 10.6 Ib brine from tubing. Shut-in well and monitor tubing. SITP = 2730 psi. R/D slickline. Turn well over to production. Chevron ~ ~nson River ~ Well KGSF #1 ~ Actual Completion 7/26/09 CASING AND TUBINC DETAIL 3/4„ SIZE W'T GRADE CONN ID TOP BTM. 20" - - - 15' 31' 11-3/4" 47 - - 11.00 Surface 2,032' 7" 29 N-80 BTC 6.184 Surface 243' 7" 26 N-80 BTC 6.276 243' 883' 7° 23 N-80 BTC 6366 883' 4,626' 7" 29 N-80 BTC 6.184 4,626' S,013' 7" 26 N-80 BTC 6276 5,013' 6,470' T' 29 N-80 BTC 6.184 6,470' 8,315' 7" 29 P-110 8RD 6184 8,315' 1Q875' Tubing 3-1/2" 9.3 L-80 Hydri1503 2.992 15' 6,354' JEWELRY DETAIL NO. De th ID OD Item 1 6,273' 2.813 3.500 XD Sliding Sleeve (Opens Down) ~Closed 7/26/09~ 2 6,287' 2.992 3.500 K-22 Anchor 3 6,288' 3.250 5.687 Baker SAB-3 Permanent Packer 4 6,344' 2.813 3.500 X Nipple 5 6,354' 2.992 3.500 Wireline EnU-y Guide ABANDONMENT DETAIL N0. Dc th ID OD Item A 6,850' -. - PosiSet Plug w/ 37' Cement B 9.015' - - Tubing cut at 9,015' WLM. C 9,733' - - Top of Cement Plug. Pressure tested to 2,500 psi. D 10,473' - - Camco "MM" Mandrel wi[h CEV Valve E 10,519' - - Brown CC Safety Joint F 10,530' - - Brown, 2-7/8" x 7", Type HS-16-1 Packer G 10,600' - - Camco "D" Nipple H ? - - Venturi Shce Notes NO. De th Item ] 7,114' 7" Stage Collar PERFORATION HISTORY T onek Perfs TDT Lo De th Interval Accum. Date Zone To Btm Amt s f Comments 12J3/98 64-5 6 380' 6 388' 8' 4 1-11/16" Pivot, I80 deg. 7/26/98 68-0 6 883' 6 911' 28' 4 Abandoned 6/20/61 10 615' 10 616' 1' S Abandoned b/21/61 H-1 10 617' 10 631' 14' 4 Abandoned 6/21/61 H-2 10 642' 10 656' 14' 4 Abandoned 6/21 /61 H-4/5 10 664' 10 752' 88' 4 Abandoned 6/20/61 - 1Q752' 1Q754' 2' S Abandoned PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = 1.25° @ 4,565' KGSF #1 Actual WBD 7-26-09.docm Revised by: STP REVISED: 9/08/09 RKB = 15' • • MEMORANDUM . ~ ..~..~.-- .-State- -of AI as ka Alaska Oil and Gas Conservation Commission TO: Jim Regg ~ L~~-f (~ DATE: July 23, 2009 P. I. Supervisor FROM: John Crisp, SUBJECT: Rig Inspection Petroleum Inspector Key Energy #3 Workover UOCC KGSF 1 161-008 July 23, 2009: I traveled to Union Oil Company of California (UOCC)'s Swanson River Field to witness initial BOP test & perform Rig Inspection on Key Energy #3 Workover Rig. The BOPE test report is available in AOGCC RBDMS. Rig has variance granted to operate without PVT system. My first question to UOCC's Well Site Leader Mr. Floyd Hurt was hole fill for the de-complete. Mr. Hurt's reply was that a packoff type stripper would be utilized above the annular preventer to contain fluids & that hole fill would be supplied thru the kill line with the rig's charge pump. Only a variance from 20 AAC 25.285 would allow this practice (variance is provided in sundry 309-221). No flow line will be utilized & manual measurement of fluid in & out of the hole would be calculated from pit volume. There is no plan to have any pump stroke counters on this rig. No stroke counters to Swaco Super Choke Panel. Hydraulically operated super choke & manual choke will be utilized for this operation. I requested Operator to prove both chokes will choke flow as per API RP 53. Swaco super choke would choke flow to 3000 psi with no flow thru choke. The manual choke would choke flow at a maximum pressure of 1500 psi @ 18 gpm. UOCC Rep. stated they would pull plates on manual choke after the first workover for inspection. No free standing Gas Buster would be utilized for this workover - only a diffuser tank. This variance had not previously been approved but was verbally approved by Inspector Supervisor Jim Regg on 07/23/09. Great addition to the stack configuration was asingle-gate ram preventer dressed with 3'/2" rams. This would alleviate the necessity for ram change to complete the well. Gas detection will be accomplished with one sensing point at the work platform & one sensing point at their shale shaker or mud pit. Each sensing point will consist of one lighter-than-air sensor & one heavier-than-air sensor. This set up is consistent with variance granted by AOGCC. One problem noted: The visual alarms at the work platform consisted of methane strobe light in blue color & H2S Key Energy #3 Rig Inspection 07-23-09 jc.doc • • strobe light in red color. I talked with Rig Rep's & UOCC's Well Site Leaders & told them the requirements for Rigs working in State of Alaska had consistently been amber color for H2S & Red for Methane. I asked them to change strobes if possible or to communicate their concerns for change to the AOGCC due to fact that all their Hands are from down south and are possibly used to the gas detection set up. I requested that concerns be addressed ASAP or strobes changed. Full opening ball type safety valves were used & tested with 2 3/8" test joint & 3 '/2" test joint. I expressed concern for the OD of the 3'/2 floor safety valve due to the possibility of having to strip in the hole. The UOCC's Rep's were not sure if variance had been approved that would require them not to have IBOP valves for each string. API only requires crossovers be available & only one valve could possibly be utilized. After my inspection I sent Mr. Floyd Hurt (UOCC Well Site Leader) & Mr. Jim Regg (AOGCC Inspector Supervisor) an email expressing concerns for interpretation for the IBOP valves. After reviewing the last BOP test for Key Energy #3 it seems this issue is resolved. Well Control School Certification was presented whenever asked for by the Rig Operators & the Operators Representatives. If AOGCC requests full documentation of Well Control Certifications, Key Energy & UOCC would provide immediately when requested. Speakerphone conversation with AOGCC Inspector Supervisor Mr. Jim Regg & AOGCC Senior Petroleum Engineer Mr. Winton Aubert was conducted with UOCC Well Site Leader Mr. Floyd Hurt & myself. Conversation consisted of the necessity for UOCC to document accurately the equipment being used for AOGCC permitted work. Equipment utilized with variances from 20 AAC 25.285 & equipment utilized that does not require variance must all be documented accurately in Summary of Swanson River Workover Program from UOCC before the next workover begins. Summary: Very good function pressure test of secondary well control equipment performed & witnessed by AOGCC Inspector. Rig Inspection brought up concerns of regulatory compliance that will be clarified before next workover begins. Attachments: photos (9) Non-Confidential Key Energy #3 Rig Inspection 07-23-09 jc.doc • Rig Inspection -Key Energy Rig #3 Union Oil Company of California -KGSF #1 Photos by AOGCC Inspector John Crisp 7/23/2009 • Key Energy Rig #3; KGSF #1 ~-~ ~ ~: _ ~. .~:.. ~~ ~ ~~; ,,,z~ rte . ~ Yy ... r- - --. .. ~X ~~~+ ~, ~~ ~ ~ ~~f~~! t ~r _ ; Equipment layout Key Energy #3 Rig Inspection 07-23-09 jc.doc • BOPE stack ~~ f k¢ • ~ L ~~ 1 y ~ a ~~ aT !~ + sa ~M+~.s A r .~'. ~~Y ' ~'~ /~i~lll KM~Y~ifst5 us~i~~r w '! • w e b~ IAA. r v~ ' '.9'7 +~'7 +~gidr - a-.,,!!Anti ~. n~,}t kM_ arc Rs ~r .,_w ~ - . ~.~ :~- ~~ ~~ 4 ;:.. F ~}~ ~ ~ / ~' ~,,~-_°. t ~.~ti ,„..x~,. .4` 1' 't ~' 7` !T R... i-- r. A.:- w r .... r1. Aw Ar- ~ Remote BOPE panel Key Energy #3 Rig Inspection 07-23-09 jc.doc • Choke manifold Visual alarnis for gas detection; lights should be red (methane) and amber (H2S) Key Energy #3 Rig Inspection 07-23-09 jc.doc Gas Diffuser Tank (in background); alternate to free standing gas buster Internals of the Gas Diffuser Tank Test flow out of gas diffuser; performance te~tim~ choke Key Energy #3 Rig Inspection 07-23-09 jc.doc • • ~` '~l .r ' `a F z ~. ~ ~ ~ k~ F E : ~ a~ F ._ n {r ~~~ - "~ f u, F ~~9~u 't° ~ iqu k~ ,` ~ ~ h P i: t t l j a°Y ? . 6°a` ~" k~ ~~` k ; t F , a ~ -~ ; p ~ ~ ~~~, ~ ,~ I SARAH PALIN, GOVERNOR `~ ~_ ~ .. k "~_ ~e,~ ~; ~t ~_ .~~`~~_t5 ~~A ~ ~t w ~"~~ ~~" e ~ ~aS~ O~ ~ ~ ~gr ANCHORAGE,ALASKA~99501a3539 CO1~T5ERQATI011T COMDIIS51O1~T a~ pHONE (907) 279-1433 ~ FAX (907) 276-7542 Mr. Timothy C. Brandenburg Dx illing Manager Union Oil Company of California ~,` P.O. Box 196247 ~ ~ 6r~`~~~ Anchorage, Alaska 99519 ~...-•- _.. Re: Swanson River, Tyonek Gas Storage &~onek Undef Gas Swanson River KGSF # 1 Sundry Number: 309-221 ~ ~, ~~.~~`~ ~JU:.. ~ ~ 200~ 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. When providing notice for a representative of the Corrunission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Comrriission grants for good cause shown, a person affected by it may file with the Commission an application for r.ehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seamount, Jr. ~ Chair DATED this ~ day of July, 2009 Encl. ~ ~~ ~~1'~ + STATE OF ALASKA ALA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ~~~~~~~l.~i~~~ ~6 ~~ J~N ~ ~ ~QQ9 ~~rl~ 07/o~~2r,o~ ,~laska Oii R t;~~ rn~,w ~.---- • 1. Type of Request: Abandon^ Suspend ^ Operational shutdown ^ Perforate ^~ ~:~ Waiver f,~ Ot er ~~~~ ~ R~ Alter casing^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Ext nsion 3-1/2" tubing Change approved program^ Pull Tubing ^~ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development ~ Exploratory ~ 161-008 - 3. Address: Stratigraphic ~ Service ~ 6. API Number: PO Box 196247, Anchorage, AK 99519 50-133-10160-00 - 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ^ No ~ Swanson River KGSF #1 ' 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): FEDA028399 [Swanson River Unit] ~ 15' Swanson River / Tyonek Gas Storage & Tyonek Undef Gas 12• PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): l Total Depth ND (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 10,875 10,875 6,813 6,813 6,813' (cement) N/A Casing Length Size MD ND Burst Collapse Structural Conductor 31' 20" 31' 31' Surface 2,032' ~' 11-3/4" 2,032' ~ 2,032' Intermediate Production 10,875' 7" 10,875' 10,875' 3,830 psi 6,340 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6,380'-6,388' 6,380'-6,388' 2-3/8" 4.6# L-80 5,102' / Packers and SSSV Type: Packers and SSSV MD (ft): Baker FH Retrievable Packer / N/A 5,030' / N/A 13. Attachments: Description Summary of Proposal ^~ 14. Well Class after proposed work: Detailed Operations Program ^ BOP Skefch'; ~^ Exploratory ^ Development ^ Service ^~ - 15. Estimated Date for 7/20/2009 16. Well Status after proposed work: Commencing Operations: -° Oil ^ Gas ^ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ~..~{' WINJ ^ WDSPL ^ Commission Representative: Sj~ ~ t/ y~1~~- 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Nigel Bonnett 263-7853 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature 76-7600 Date 6/23/2009 ~, COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~„ Z2 Plug Integrity ^ BOP Test ~ Mechanical Integrity Test ^ Location Clearance ^ Other. r~1~ ~C~ ~/~ 'Z~. 2~~ 11~.~ , A-I.~~Yl~Gs~-~~ ~o~F" d S ~~pi"'~(~Gd , Subsequent Form Required: i O - t.~~C~ , ~ APPROVED BY ~ / ~ ~ Approved by: COMMISSIONER THE COMMISSION Date: '. ~..~~~I--3~~~~/~I, J Form 10-403 Revised O6/2006 Submit in Duplicate Chevron • ~wanson River ~ Well KGSF #1 ~ Actual Completion 12/3/98 CASING AND TUBING DETAIL 3/4" SIZE WT GRADE CONN ID TOP BTM. 20" - - - 3~' 1 l-3/4" 47 - - 1 L00 Surface 2,032' ~ 7" 29 N-80 BTG8rd LT 6.184 Surface 243' 7" 26 N-80 6.276 243' 883' T' 23 N-80 6366 883' 4,626' 7" 29 N-80 6.184 4,626' S,013' T' 26 N-80 6.276 S,Ol3' 6,470' 7" 29 N-80 6.184 6,470' 8,315' T' 29 P-110 6.184 8,315' 10,875' ~ Tubing 2-3/8" 4.6 L-80 Butt. SC 1.995 15' S,102' JEWELRY DETAIL NO. De th ID OD Item l 15' 2.195 7.027 Tubing Hanger, TC IA-EN-CL, 2-3/8" EUE 8rd Lift Thread x 2-3/8" Suspension Threads, Cameron Type 2 15.5' 1.995 2.375 Crossover, 2-3/8" EUE 8rd Pin x 2-3/8" Butt Pin 3 2,46T L901 4.812 Macco 2-3/8", SMO-1C[ Chemical [nj. Mandrel 4 4,983' L901 4.812 Macco 2-3/8", SMO-1 GLM w/ 1" Dummy 5 5,029' L995 2.850 Crossover, 2-3/8" Butt Box x 2-7/8" NU lOrd Pin 6 5,030' 2.441 5.983 Baker 2-3/8", 26#, Model "FH" Retrievable Packer 7 5,036' L995 2.850 Crossover, 2-7/8" NU l Ord Box x 2-3/8" Butt Pin 8 5,070' 1.875 2.90 X Nipple, (1.875") 9 5,102' L995 2.90 Wireline Entry Guide/Shear Out Sub ABANDONMENT DETAIL NO. De th ID OD Item A 6,850 - - PosiSet Plug w/ 37' Cement B 9.015' - - Tubing cut at 9,O l5' WLM. C 9,733' - - Top of Cement Plug. Pressure tested to 2,500 psi. D 10,473' - - Camco "MM" Mandrel with CEV Valve E 10,519' - - Brown CC Safety Joint F 10,530' - - Brown, 2-7/8" x 7", Type HS-16-1 Packer G 10,600' - - Camco "D" Nipple H ? - - Venturi Shoe Notes NO. De th Item I 7,1 l4' T' Stage Collar PERFORATION H[STORY T onek Perfs TDT Lo De th Interval Accum. Date Zone To Btm Amt s f Comments 12/3/98 64-5 6 380' 6 388' 8' 4 ~-i vie" e+~o~, tso a~. 7/26/98 68-0 6 883' 6 911' 28' 4 Abandoned 6/20/61 10 6l5' 10 6l6' 1' S Abandoned 6/2l/61 H-1 l0 6l7' 10 631' 14' 4 Abandoned 6/21/61 H-2 10 642' l0 656' 14' 4 Abandoned 6/21/61 H-4/5 10 664' l0 752' 88' 4 Abandoned 6/20/6l - 10,752' 10,754' 2' S Abandoned PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = Vertical SRU SRU KGSF #1 Act Draw (2).doc Revised by: BCA REVISED: 4/27/09 RKB = 15' Chevron ~ ~anson River ~ Well KGSF #1 ~ PROPOSED Completion 3/4" CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20° - - - 3l' ll-3/4" 47 - - ll.00 Surface 2,032' 7" 29 N-80 BTC/8rd LT 6.184 Surface 243' 7" 26 N-80 6.276 243' 883' 7" 23 N-80 6.366 883' 4,626' 7" 29 N-80 6.184 4,626' S,013' 7" 26 N-80 6.276 5,013' 6,470' 7" 29 N-80 6.184 6,470' 8,315' T' 29 P-110 6.184 8,315' 1Q875' Tubing 3-1/2" 9 2 L-80 H dri1503 2 992 15' +/-6 180' . y . , JEWELRY DETAIL N0. De th ID OD [tem 1 +/-6150' Sliding Sleeve 2 +/-6180' Baker SAB-3 Permanent Packer 3 +/-6220' 2.813 X Nipple 4 +/-6250' Wireline Entry Guide ABANDONMENT DETAIL N0. Dc th ID OD Item A 6,850 - - PosiSet Plug w/ 3T Cement B 9.015' - - Tubing cut at 9,O15' WLM. C 9,733' - - Top of Cement Plug. Pressure tested to 2,500 psi. D 10,473' - - Camco "MM" Mandrel with CEV Valve E 10,519' - - Brown CC Safety Joint F 10,530' - - Brown, 2-7/8" x T', Type HS-16-1 Packer G 10,600' - - Camco "D" Nipple H ? - - Venturi Shce Notes NO. De th Item 1 7,114' 7" 5tage Collar PERFORATION HISTORY T onek Perfs TDT Lo De th Interval Accum. Date Zone To Btm Amt s f Comments 1213/98 64-5 6 380' 6 388' 8' 4 i-iuib° r~~or, isoa~. 7/26/98 68-0 6 883' 6 911' 28' 4 Abandoned 6/20/61 10 615' 10 616' l' S Abandoned 6~/21/61 H-1 10 617' 10 631' 14' 4 Abandoned 6/21/61 H-2 10 642' 10 656' 14' 4 Abandoned b~/21/61 H-4/5 10 664' 10 752' 88' 4 Abandoned 6~/20/61 - 10,752' 1Q754' 2' S Abandoned PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = Vertical / KGSF #1 proposed completion 6-10-09.docm Revised by: MQ REVISED: 6/10/09 RKB = 15' Chevron ~ ~ OBJECTIVE: ~ Kenai Gas Storage Well # KGSF #1 6/22/09 • Pull 2-3/8" completion, run 3-1/2" completion, and reperforate Tyonek 64-5 zone. ~' PROCEDURE SUMMARY: 1 MURU Test BOPE 250psi low/3,OOOpsi high. ~ 2 RU & pull 2-3/8"tubing to shear FH packer, straight pull. POOH and lay down tubing. Contingency: (If packer does not shear) a. RU and RIH, cut off 2-3/8" tubing above packer at +/- 5,005' RKB and POOH w/ same. b. Fish packer, POOH 3 Prep 3 -1 /2" completion 4 P/U and RIH w/ 3 1/2"9.2# L-80 tubing & SAB-3 packer. Set packer at +/- 6,280' RKB. f 5 ND BOP, NLJ Tree. 6 MI/Spot and RU Eline. Test BOPE's 250psi low/3,OOOpsi high. 7 RIH reperfarate Tyonek 64-5 zone from +/-6,380' to +/-6,388' RKB. ~ 8 RD Eline Unit. Demobe ~ KGSF#1 REVISED BY: CVK 6-22-09 Chevron ( (o ~ ^ O O ~ BOPE Diagram - KGSF #1 Workover ~ O7/17/2009 Mnular preventer, Shaffer, 7 1/16 5M Flanged 2.58' I haffer Chasovoy 7 1/16 5 , 1.00~ stdd X 7 115M stdd ~ Pipe Ram 7.16 I haffer Chasovoy 7 1/16 5 Pipe Ram stdd X 7 1 5M stdd 1.75' ~o Blind Ram OO Mud Cross, 7 1/16 5M FE X 7 1l16 5M FE w/ 2 1/16 5M X 3 1/8 5M EFO Kill line 2 1/16 5M - Choke line 2 1l16 5M 1.83' e Ili - e e~ ee Unibolt ~ HCR Unibolt I DSA ~ 3 1/8 5M X 2 1/16 5M ~~A,NIVED AUG 0 7 2005 ~~q- zz i r~r-ooF {GSF #1 Line Line Side of Drilling Spool rrom ~nvKe 1-•, ~nn, uniaoit, Hose From c;noKe • • Chevron Swanson River ~ 2009 Workover Program ~ 06/24/2009 ~ Annular preventer, Shaffer, 7 1/16 5M ' Flanged 2.58' Double gate, Shaffer Chasovoy 7 1/16 5M stdd X 7 1/16 5M ~ stdd 1.75' I ~ I Kill line 2 1/16 o° 0 1.83' ~ o ~ 1502 Union ~ Mud Cross, 7 1/16 5M FE X 7 1/16 5M FE w/ 2 /16 5M X 3 1/8 5M EFO Choke line 2 1/16 5M ~- ~~ 1502 union ~ DSA ~J 3 1/8 5M X 2 1/16 bM Hose ~~~ J~ ay~ C~ ,~o ~ Chevron ~ ~ Timothy C Brandenburg Driiling Manager June 23, 2009 Commissioner Alaska Oil & Gas Cansenration Commission 333 W. 7~' Avenue Ancho~age, Alaska 99501 Re: Swanson River Workover Program Variance Request Dear Commissioner, • Union Oil Company of Caiitomia A.O. Box 195427 Anchorage,AK 99519-6247 Tel 907 263 7657 Fax 907 263 7884 Email brandenburqt@chevron.com '~~. - ~'~ _ '; ~ '~~~sha ;~~: ~ ~~ ~.c~~=;~ ,., r::~i>.~~~;; ~ncta~r~~~ UOCC is ~equesting a variance of 20 AAC 25.285 (c) (9) and (10) for well service work in the Swanson River Field. UOCC is preparing to perForm well intervention work with a"well servicing unit" provided by Key Energy. Key Energy is mobilizing the workover unit here from the Rocky Moun#ain area. After reviewing the BOPE rig up and equipment as used in UOCCs last Swanson River workover campaign in 2004, we feel that the proposed system is fif for pu~pose in well control capabilities and mobility to other BOPE configurations for this ~ well service work. As in this same configuration successfully used in 2U04, UOCC is asking for a variance of the kill tine and choke line configuration and the choke manifold equipment requirements. We consider the app~ication of this and all BOP configurations to be a well bore specific concem and do not intend or desire to consider this as an area wide or unilaterally applied configuration. UOCC appreciates your consideration of this proposal and looks forvvard to meeting with you to discuss any questions with the proposed configuration. Attached is a brief desc~ption of the wells to be woriced on, the calculated maximum anticipated surface pressure {MASP), and the proposed BOP configuration and schematic. Please let us know if we can provid+e any further information by contacting myself at 263- 7657 or Evan Hamess at 263-7932. Sincerely, , ~ "-%' i ~,. _-.- : Timot y . Brandenburg " Drilling Manager Union Oil Company of Caltfornia / A Chevron Company ~ ~ Chevron ~ Summarv of Swanson River Workover Pros~ram Well Work Inventorv 1 ea. Gas Re-completions (Tyonek) Plan is to change the tubing string in a gas storage well from 2- 3/8" to 3-1/2" tubing to increase deliverability. (KGSF #1) J 3 ea. Oil Re-completions (Hemlock Oilj Plan is to recomplete Hemlock with optimized gas lift designs. (SCU 12A-04, SRU 21A-34, SRU 21-27) 1 ea. Rod Pump Repair / Re-completion (Hemlock Oil) Plan to retrieve rods, pull and replace tubing and change out pump. (SCU 33-33) Additionai potential for several wells #o P&A Hemlock horizons. Reservoir The planned recampletian of the gas storage well wil! be after the storage well is "full", with a maximum BHP of 3300 psi @ 6,388' TVD {Tyonek). Fully evacuated, the MASP would be as fo(tows: 3300 psi BHP -(6,388' ND x.1 psi/ft Gas Gradient) = 2,661 psi MASP. ~" The highest BHP of the oil weUs to be worked on at this time is 3120 psi @ 1Q,994' ND (Hemlock) which is equivalent to a.272 psi/ft gradient. Fully evacuated, the MASP would be as #ollows: 3120 psi BHP -{10,994' ND x.1psi/ft Gas Gradier~#) = 2,020psi MASP. ~ ~ A 3,000 psi BOPE configuration is su~cient fo~ all planned well worlc. ~ Proposed Confis~uration BOP's ~ Annular, 5M 7-1/16" Hydril or 11" 5haffer ~:~~ Double gate, 5M, 7-1/16" Hydril or 11" Shaffer Mud Cross, 7-1/16" and 11" (optional based on BOP height) Accumulator 140 gallon KOOMEY Accumulator System. 5 functions with manual bypass and remote panel. Fourteen 11 gailon accumutators with four 91 Gallon Nitrogen Bottles for backup. 210 gallon hydraulic tank with air operated hydraulic pump. Pits The pi# consists of a 200 bbl tank partitioned into three isolatable compartments. Pump The pump is a National JWS-400 Triplex on an independent skid. The pump will pull fluid directly from the pit. The discharge will be plumbed to kill line and an independent stand pipe line. Kill Line ,~ The Kill Line/Circulating Line wiil consist af 2", 5~0 psi Iron w 2", 5000 psi hoses with integral Fig;~502 Unions. ` ~ Chevron ~ ~ Kill Line Valves The kill line vaives will consist af, at a minimum, 2 ea. manually operated, 2-1/16", 5M valves attached to either the mud cross or the tubing spool annulus valve. Choke Line Valves The choke line valves will consist of, at a minimum, 2 ea. manually operated, 2-1/16" 5M valves that wil! be attached to e~ther the outlet below the lower rams on the double gate or the mud cross. Choke Line The choke line will consist of 5,000 psi hoses with integral Fi 1502 Unions. ~ ~ Choke Manifold The choke manifold is 3-1/8", 5M with two manual choke as nd five valves. There are two valves upstream of each choke. Choke Return Line/Gas Buster Line The gas buster line will consist of 2", 5000 psi hose with integral Fig 1502 Unions. The line will run from the choke manifold to the gas buster. Gas Buster A free standing gas bus#er will be placed adjacent to the mud pits. Gas Detection We are proposing that a singte gas LEL monitor and a single H2S monitor be placed at the work ~` platform; and a single gas LEL monitor and a single H2S monitor be placed at the shale shaker (if used). PVT We are proposing to work with-out a PV7 system as the circulation system on this workover rig, as is standard practice in this type of well service work. Unocal Alaska Union Oil Company of California 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone: (907) 263-7662/276-7600 Facsimile: (907) 263-7828 UNOCAL August 14, 2003 Re: Commissioners: Mr. Randy Ruedrich Mr. Dan Seamount Ms. Sarah Palin Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501-3539 ANNUAL MATERIAL BALANCE CALCULATIONS OF PRODUCTION AND INJECTION VOLUMES FOR KGSF #1, SWANSON RIVER FIELD Dear Commissioners: Attached for your review is the second annual material balance calculation of production and injection volumes for KGSF #1, as required per Storage Injection Order #2. This material balance covers the primary production period, as well as the June 15, 2001 through July 31,2003 storage operation period. Attachment #1 is a table of gas production and injection volumes for the KGSF #1 well beginning with the commencement of primary production through the first year of storage operations, ending with the data for July 2003. Note that the July 2003 values are estimated from the daily metered volumes. Reservoir pressure estimates were obtained through surface shut-in tubing pressure readings which were converted to bottomhole pressures. In addition, a pressure transient test was conducted in July 2003 with surface gauges and doWnhole gauges were run to mid-perforation to confirm the surface recorded pressures. These data points are tabulated in attachment #2 and plotted on the standard POZ plot in attachment #3. KGSF #1ANNUAL MATERIAL BALANCE 8/14/03 Note that the injection cycle pressures deviate above the straight line path established with the primary depletion points, as expected (Attachment #3). The production volumes also deviate below this path as is normally seen. The last data point, however, departs from the straight line more than expected. We are currently in the process of reviewing our metering records to assure accuracy of the reported volumes. If any inaccuracies are found, we will submit a revised annual material balance report in addition to reporting the corrected production volumes. Please contact Jeff Smetanka at 263-7622 if you have any questions regarding these calculations. Sincerely, Jeff Smetanka Consulting Reservoir Engineer 8/14/2003 DATE Dec-98 Jan-99 Feb-99 Mar-99 Apr-99 May-99 Jun-99 Jul-99 Aug-99 Sep-99 Oct-99 Nov-99 Dec-99 Jan-00 Feb-00 Mar-00 Apr-00 May-00 ATTACHMENT #1 - KGSF #1 PRODUCTION AND INJECTION VOLUMES All Gas volumes calculated at 14.65 psi pressure base Gas Monthly Cum Gas Inj Monthly Cum Rate Gas Gas Rate Gas Gas (CD) Prod Prod (CD) Inj Inj Mcf/d Mcf Mcf Mcf/d Mcf Mcf Jun-00 Jul-00 Aug-00 Sep-00 Oct-00 Nov-00 Dec~00 Jan-01 Feb-01 Mar-01 Apr-01 May-01 Jun-01 Jul-01 Aug-01 Sep-01 Oct-01 Nov-01 Dec-01 Jan-02 Feb-02 Mar-02 Apr-02 May-02 Jun-02 Jul-02 Aug-02 Sep-02 Oct-02 Nov-02 Dec-02 Jan-03 Feb-03 Mar-03 Apr-03 May-03 Jun-03 Jul-03 1,779 2,561 2,299 2,385 2,073 2,481 2,563 2,331 1,946 1,622 1,357 1,313 1 ,O9O 1,287 721 1,233 1,191 726 288 981 1,828 1,017 946 1,621 959 1,491 1,706 1,200 824 200 1,948 4,747 5,131 1,540 2,336 145 1,701 521 129 596 4,537 2,020 8,802 6,466 4,833 4,052 2,777 1,903 1,362 1,008 799 574 55,137 79,404 64,367 73,920 62,180 76,912 76,903 72,268 60,311 48 667 42 056 39 385 33 783 39 890 20 895 38 219 35 729 22 502 8,627 30 397 56,660 30,505 29,330 48,633 29,741 46,236 47 777 37,213 24,719 6,196 60 382 142 418 159 046 47 741 65 400 4 507 51,031 16 147 3 868 18,479 140,660 60,587 272,859 193,970 149,810 125,601 77,767 58,978 40,867 31,252 23,977 17,782 55,137 134,541 198,908 272,828 335,008 411,920 488,823 561,091 621 402 670 069 712 125 751 510 785 293 825 183 846 078 884 297 920,026 942,528 951,155 981,552 1,038,212 1,068,717 1,098,047 1,146,680 1,176,421 1,222,657 1,270,434 1,307,647 1,332,366 1,338,562 1,338,562 1,338,562 1,338,562 1,338,562 1,398,944 1,541,362 1,700,408 1,748,149 1,813,549 1,818,056 1,869,087 1,885,234 1,889,102 1,907,581 2,048,241 2,108,828 2,381,687 2,575,657 2,725,467 2,851,068 2,928,835 2,987,813 3,028,680 3,059,932 3,083,909 3,101,691 3,560 7,086 7,295 6,592 1,450 2,438 912 4,336 3,670 8,088 3,572 2,878 3,536 2,153 621 2,458 . . 23 106,800 106,800 219,660 326,460 226,151 552,611 197,762 750,373 44,964 795,337 73,130 868,467 28,281 896,748 134,429 1,031,177 102,768 1,133,945 250,716 1,384,661 107,164 1,491,825 89,218 1,581,043 106,081 1,687,124 66,737 1,753,861 19,263 1,773,124 73,737 1,846,861 - 1,846,861 - 1,846,861 701 1,847,562 - 1,847,562 - 1,847,562 - 1,847,562 - 1,847,562 - 1,847,562 1,847,562 1,847,562 (Prod -Inj) Cum for POZ plotting Mcf 55,137 134,541 198,908 272,828 335,008 411,920 488,823 561,091 621,402 670,069 712,125 751,510 785,293 825,183 846,078 884,297 920,026 942,528 951,155 981,552 1,038,212 1,068,717 1,098,047 1,146,680 1,176,421 1,222,657 1,270,434 1,307,647 1,332,366 1,338,562 1,231,762 1,012,102 785,951 588,189 603,607 672,895 803,660 716,972 679,604 433,395 377,262 304,191 201,978 153,720 275,117 261,967 534,826 728,796 877,905 1,003,506 1,081,273 1,140,251 1,181,118 1,212,370 1,236,347 1,254,129 Total Gas Inventory Mcf 1,338,562 1,283,425 1,204,021 1,139,654 1,065,734 1,003,554 926 642 849 739 777 471 717 160 668 493 626 437 587,052 553,269 513 379 492 484 454 265 418 536 396 034 387 407 357 010 300 350 269 845 240 515 191 882 162 141 115 905 68 128 30 915 6,196 . 106,800 326,460 552,611 750 373 734 955 665,667 534,902 621,590 658 958 905 167 961 300 1,034,371 1,136,584 1,184,842 1,063,445 1,076,595 803,736 609,766 460,657 335,056 257,289 198,311 157,444 126,192 102,215 84,433 X:\Swanson\KGSF#1 storage balance accounting.xls ATTACHMENT #2 -- KGSF #1 POZ DATA Data SG 0.56 Datum, ft 6395 Temp, F 122 Temp, °R 582 PRIMARY PRODUCTION Date Type Test Gauge Depth, fi Cum, bcf TbgP, # Res. P, # Z P/Z Comments 12/5/1998 SITP 0 0 2850 3306 0.8812 3751 SITP 7/27/1999 SITP 6395 0.561 1775 2059 0.8664 2376 SrI'P 9/9/2000 BHP buildup 6395 1.069 882 1100 0.9082 1211 PBU w/Gauges FL N 6195' 2/20/2001 SITP 0 1.27 540 626 0.9432 664 SITP 6/9/2001 SITP 0 1.33856 380 441 0.9535 462 SITP 2001 INJECTION CYCLE 7/11/2001 SITP 0 1.148 875 1015 0.9140 1110 21 hr SITP after 618 hr injection 9/18/2001 SITP 0 0.673 1820 2111 0.8655 2439 4 hr srrP prior to flow due to SHP ESD 9/20/2001 SITP 0 0.678 1810 2099 0.8656 2425 24 hr SHI' after 1 day of flow on 9/19 at 5.5 mmcfd 10/9/2001 SITP 0 0.572 1980 2297 0.8634 2660 8 day SITP during C12 restaging 2002 INJECTION CYCLE 4/5/2002 SITP 0 0.400 2280 2645 0.8644 3059 15 hour SITP 7/12/2002 SITP 0 0.190 2620 3039 0.8723 3484 SI'I't' 7/26/2002 SITP 0 0.200 2630 3050 0.8726 3496 S1TI-' 2002 PRODUCTION CYCLE I : / / oo21SlT 7/25/2oo31SITP [ 0.7401 14151 1641 0.8789 I 1867 ISrlt' (65 hr SI) 1.250[ 2241 260 0.9757 266 KGSF#1_poz.xls 8/14/2003 2000 ATTACHMENT #3 -- KGSF #1 P/Z vs Cumulative Production Plot , ~Primary !~'0I Inj cycle &'02 Inj cycle ©'02 >rod cycle 4000 Point of Max Fillup in 2001 End of Primary Production ~ 11/8/01 6/9/01 3000 2500 1500 1000 '',,~ 500 r 0 0.5 I 1.5 2 Cum Gas Produced, bcf KGSI'# t ~poz.xls PUD DAT-- -rG RELEAZE' - M~--~CEANICAL ittTEGRITY ~PORT' ~T~T NU~BEK :~,;LL DATA T~: /0, 9757~. _'fVD; ?BTD: .MD ?VD Casing: ~ 0 Shoe: MD TVD; DV: ~ · ,_Tv"D .... = !-~ _~ner: Shoe: ~ ?ZD; :~. : TVD ubin_: . _ _ - ' =_ Packer ?D TVD; Ce~ a~ · . Hole Size and ; Perfs To iNTEGRITY - P.~T $ ! Annulus Press Tesu.P~.P .wZCI~-NiCAL ilqTEGKT_TY - PART Cemenu Volumes :-~m=. Liner CmE vol ~o cover oerfs ; Csg ; DV Theoretical TOC Cement Bond Log (Yes or No) ~ CBL Evaluation, none above perfs ; In AOGCC File · Production Log: Typ. e ; EvaluaUion CONCLUSIONS: Par~ fl: ?art ~2: Unocal Alaska Union Oil Company of California 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 July 8, 2002 Ms. Camille Oechsli Taylor Mr. Dan Seamount Ms. Julie Heusser AK Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501-3539 Re' CHANGE THE NAME OF WELL SRU 43-28 TO KGSF #1, SWANSON RIVER FIELD, KENAI GAS STORAGE FACILITY Dear Commissioners: This letter is to inform you of the name change of gas storage Well SRU 43-28 to KGSF #1 (Kenai Gas Storage Facility #1). This name change will help differentiate the gas storage well from the oil and gas production wells. Please contact Gary Orr at 263-7658 if you have any questions or require any more information. Sincerely, Gary ~rr Advising Reservoir Engit~eer RECEIVED JUL 9 2002 Alaska 0il & Gas C0fl~. [;ommm~iu, Anchorage (June 19S0) D=~A~T~.~T 0]~ TH~ Ii~TERIO~t SUNDRY NOTICES AND REPORTS ON WELLS Do not use this form for proposals to drill or to deepen or reentry to a different reservoir. Use 'APPLICATION FOR PERMIT-" for such proposals SUB~IT IN TRIPLICATE . - - ~ I i 11 11 · i11 i ~- 111 · i ii ...... 1.~pe of'~eIt ...... 011 . Gas X _ Other (Gas Storage) 2. Name of Operator UNOCAL _ , i ............... · ,, ' L - 3' A~i~lreg and Telephone N~. · - - P'O' Bo, x~ 19~247 Anchor.a.~e;,Ala_ska 99519-8247 (907) 276-7600. 4. Location of Well (Footage, Se°., T., R., M., or Survey Descrlplion) 2130' FSI. & 550' FEL, Sec. 28, TSN, RgW, SewOrd SE ~'HEC~.Ai~i~F~OPRiA. i.~'- TYPE OF SUBMISSION ~ Nollee ol Intent ~ s~uem ~n [~ Flnal Abandonment Notk~ FORM APPROVED Budget Bureau No. 1004-0135 F..xplrea: March 31, 1993 Lease DeslgnMIon and Se~al No. 6. if Indian, Altoltee or Tdbe Name 7. If Unit or CA, Agreement Designation Swanson River Unit a. Well Name end No. SCU 43-28 9. ~1 Well No. $0-133-10160-00 10. Field and Pool, or Explomto~ Ama Swanson 11, County or Parish, Slate Alaska , T~'INDIc~TE NATURE OF NOTICE, REPORT, 0R OTHER DATA TYPE OF ACTION g] Chalrlge'ol pllma' E~ New OonMmcUon r-l-water Shut*Off D Co.veralolt to InJecUolt ~ ~r-We# N~_C~nao {N~t~: Report results of multiple co~n ~ Well or form.) 13. Des~e Pro~s~ or C~et~ Operatbns (C~ ~te ~ ~d~nt ~t~le, ~d ~e pedant daeo, ~lu~ ~1~ ~e of ~lng any pm~ wo~. If well Is dlmctlonally ddlled, give subsurface locations and meaSUred and hue vertical depths for ali ma~era and zonea pennant to this work,) unocal requests BLM approval to change the name of Well SRU 43-28 to KGSF #1 (Kenla Gas Storage Facility #1). This name change will help differentiate the gas storage well from the oii and gas production wells. .. RECEIVED JUL 9 2002 ~o 16 U.S.O. 8~lm 1~1, is # u ~mo tot any ~on ~1¥ ~ MIIIully to le to any delar~an! m egun~ of ~o Un~ Steer ~ lisa, flW~ or truu~ ~atem~, STATE OF ALASKA ALASKA OiL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown: Stimulate: Plugging: Perforate: Pull tubing: Alter casing: Repair well: Other: X (Convert to Storage well) 2. Name of Operator 5. Type of Well: 6. Datum elevation (DF or KB) Union Oil Company of California (UNOCAL) Development: 174' RKB MSL feet 3. Address Exploratory: 7. Unit or Property name Stratigraphic: P.O. Box 196247, Anchorage, AK 99519 Service: X Swanson River Unit 4. LocalJon of well at surface 8. Well number 2,130' FSL, 550' FEL, Sec. 28, T8N, R9W, SM SRU 43-28 At top of productive interval 9. I~,~r~t number/~.proval number At effective depth 10. APl number Same 50- 133-10160-00 At total depth 11. Field/Pool Same Swanson River/Tyonek 64-5 12. Present well condition summary - Total depth: measured 10,875' feet Plugs (measured) PosiSet Bridge @ 6,850' / Cement @ 6,813' true vertical 10,875' feet 9733' Cement Effective depth: measured 6.850' feet Junk (measured) true vertical 6,850' feet Casing Length Size Cemented Measured depth True vertical depth Structural Conductor 30' 20" Yes 30' 30' Surface 2,032' 11-3/4" 1,290 sx Intermediate Production 10,875' 7" 1 stg 600 ax, 1,200 sx @ DV 10,875' 10,875' Liner Scab Liner Perforation depth: measured Open: 6,380'-6388' Abandoned: 6,883'-6911 '; 10,615'-10,616'; 10,617'-10,631'; 10,642'-10,656'; 10,664'-10,752'; 10,752'-10,754' true vertical 6,380'-6388' Abandoned: 6,883'-6911'; 10,615'-10,616'; 10,617'-10,631'; 10,642'-10,656'; 10,664'-10,752'; 10,752'-10,7~' E C E I V ED Tubing (size, grade, and measured depth) 2-3/8", 4.6~, L-80, Buttress SC @ 5,102' Packers and SSSV (type and measured depth) AUG 0 9 200] Baker Mod. "FH" Retrievable @ 5,030' 13. Stimulation or cement squeeze summary AlaskaO~ &_~,~,l ~t~ Commission N/A- No physical subsurface work performed-initiated gas injection into reservoir on 6/15/01 BLM storage agreemen,,.o,,,~,,,,,, Intervals treated (measured) ' ~ncn0rage N/A Treatment description including volumes used and final pressure N/A 14. Representative Daily Average Production or Injection Data OiI-BBL Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 6/9/2001 0 0 0 0 380 Subsequent to operation 6/21/01 0 7.8 mmcfd inj 0 600 1,120 15. Attachments: 18. Status of well classification as: Copies of Logs and Surveys run: Daily Report of Well Operations: Oil: Gas: Suspended: Service: X (Gas Storage) 17. I hereby certify that the foregoing is true and correct to the best of my knowledge: Signe~~,~~illiamson Title: Drilling Manager Date: Form 1 0-404 Rev 06/15/88 ORIGINAL SUBMIT IN DUPL STATE OF ALASKA "-'" ALASKA OIL AND GAS CONSERVATION COMMISSION Cr , APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon: Suspend: Operation shutdown: Re-enter suspended well: Alter casing: Repair well: Plugging: Time extension: Stimulate: Change approved program: Pulltubing: Variance: X Perforate: Other: X 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Union Oil Company of California (UNOCAL) Development: 174' RKB above MSL feet 3. Address Exploratory: 7. Unit or Property name Stratigraphic: P.O. Box 196247 Anchorage, AK 99519 Service: X Swanson River Unit 4. Location of well at surface 8. Well number 2,130' FSL, 550' FEL, Sec. 28, T8N, R9W, SM SRU 43-28~-~o,~/ At Samet°P of productive interval 9. Permit~(~number~ ,. (~(,.r.~ ~-~" At effective depth 10. APl number Same 50- 133-10160-00 At total depth 11. Field/Pool Same Swanson River Field / Tyonek 64-5 sand 12. Present well condition summary Total depth: measured 10,875' feet Plugs (measured) 6,850' PosiSet plug and Cement true vertical 10,875' feet 9,733' Cement Effective depth: measured 6,850' feet Junk (measured) true vertical 6,850' feet Casing Length Size Cemented Measured depth True vertical depth Structural Conductor 30' 20" Yes 30' 30' Surface 2,032' 11-3/4" 1,290 sx Intermediate Production 10,875' 7" 1 stg 600 sx, 1,200 sx @ DV 10,875' 10,875' Liner F \? Perforation depth: measured Open: 6,380'-6388' ~' i ~- ~ 0~ Abandoned: 6,883'-6911'; 10,615'-10,616'; 10,617'-10,631'; 10,642'-10,656'; 10,664'-10,752'; 10,752'-10,~, ' true vertical Open: 6,380'-6388' ~ias~-a 'i ~ ~:.~ ~ :. ~ ,' Abandoned: 6,883'-6911'; 10,615'-10,616'; 10,617'-10,631'; 10,642'-10,656'; 10 664'-10 75z"1~,/ ~-., · Tubing (size, grade, and measured depth) 2-3/8", 4.6#, L-80, Buttress SC @ 5,102' Packers and SSSV (type and measured depth) Baker Mod. "FH" Retrievable @ 5,030' , 13. Attachments Description summary of proposal: X Detailed operations program: BOP sketch: Conversion to gas storage well 14. Estimated date for commencing operation 15. Status of well classification as: 06/05/01 16. If proposal well verbally approved: Oil: Gas: Suspended: Name of approver Date approved Service: Gas Storage Well 17. I hereby~LS'i'ti,fy that the ~)re.~ing is true and correct to the best of my knowledge. Sign ed~ h/~O~~William so n Title: Drilling Manager Date: ~----~:~-/'~l v- .... - -' , FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness I Approv~ No. , Plug integrity.__ BOP Test Location clearance I , '~'~/' -- Mechanical Integrity Test Subsequent form required lo- QRIGINAL SIGNED BY Approved by order of the Commissioner D Taylor Seamount Commissioner Date Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE SIO2 - E-mail correspondence Subject: SIO2 - E-mail correspondence Date: Fri, 15 Jun 2001 12:48:37 -0800 From: Jane Williamson <Jane_Williamson~admin.state.ak.us> Organization: Alaska Oil & Gas Conservation Commission To: Jody J Colombie <jody_colombie@admin.state.ak.us> Jodie, This is correspondance to Unocal for SIO#2. Just wanted to pass on, in case you wished to have in the files? Thanks, Jane Subject: Re: SRF Gas Injectivity Test Date: Fri, 15 Jun 2001 10:20:02 -0800 From: Jane Williamson <Jane_Williamson~admin.state.ak.us> Organization: Alaska Oil & Gas Conservation Commission To: "Whitacre, Dave S" <whitacred@unocal.com> Sorry, forgot the attachment. Here it is. Jane Williamson wrote: Dave, Here's a scan of the signed Storage Injection Order 2. Please review the order for rules specific to this project. You have approval to proceed with the gas injection per this order. We also have a 403 which will be sent to you. You do not need any further approval from AOGCC to proceed, though we would be interested in results of your injectivity test, if you could just copy us when you send to BLM, I'd appreciate. Good luck with your project. Jane Williamson Petroleum Engineer AOGCC "Whitacre, Dave S" wrote: > Jane, > Unocal has received approval from the BLM to conduct an injectivity test on > SRU well No. 43-28. The facility changes are complete and the well is ready > to take gas. The test will provide important rate and pressure information > that can be used to estimate reservoir fill up time for the gas storage > project that is currently pending BLM and AOGCC approval. The test will > commence immediately after the appropriate approvals are received and is > expected to last 30 days. Metered gas volumes and flowing tubing pressure > will be recorded daily during the test. > > The source of the injection fluid will be the Hemlock formation at Swanson > River (Rental gas). > > I am still not clear on the question of if the AOGCC needs to approve this > test or if they need to be notified of the test. Unocal did a similar gas > injectivity test in 1996 on SCU 341-4 and as best I can tell from the 1 of 2 6/15/01 1:31 PM SIO2 - E-mail correspondence wellfile, we requested approval from the BLM but not from the AOGCC (AOGCC was sent a sundry notice of the test, however). I would greatly appreciate it if you could explain our intentions to the appropriate people at the AOGCC to see if they have any concerns about our proceding with the injectivity test. As you know, we are way behind schedule on getting this project started. would really like to start this test prior to the weekend. If you could give me verbal approval tomorrow, we can do that. I appreciate all the leg work you are doing to help get this project approved. Thanks for all your help. Regards, Dave ~ SI02final.doc Name: SIO2final.doc ] Type: WINWORD File (application/msword) Encoding: base64 2 of 2 6/15/01 1:31 PM May 25, 2001 Unocal Alaska Resources Unocal Corporation 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCALe RECEIVED 2 5 2001 Alaska 0il & (~a~ ~ns. C0mmia~im, Anchorage Cammy Oechsli Taylor, Chair Alaska Oil and Gas Conservation Commission 333 West 7Th Avenue, Suite 100 Anchorage, AK 99501 Unocal's Application for Swanson River SRU 43-28 Gas Storage Dear Commissioner Taylor: Union Oil Company of California has filed an application with the Alaska Oil and Gas Conservation Commission (Commission) seeking approval of an injection order for gas storage purposes into Swanson River, SRU 43-28. Cook Inlet Region, Inc. (CIRI) and the United States Department of the Interior, Bureau of Land Management (BLM) are royalty owners in the Swanson River Field. Unocal is the sole working interest owner under the Swanson River Field oil and gas leases, administered by the BLM on behalf of CIRI. In the federal land grant under which CIRI reCeived its interest in the subject lands, the BLM was tasked with administration of the oil and gas leases and related agreements on behalf of itself and CIRI. Unocal pays the royalties due under the leases directly to CIRI and the BLM in accord with their interests. In response to the Commission's notice for public comment regarding the requested injection order, CIRI submitted a letter to the Commission asking for clarification of the accounting of the purposed storage agreement. On May 24, 2001, I spoke with Candace Beery, Land Manager for CIRI, to discuss CIRI's issues. Ms. Beery acknowledged that the BLM administers the leases on behalf of CIRI but was unaware of the fact that Unocal had negotiated a storage lease for the reservoir with the BLM on behalf of both CIRI and the BLM. After we discussed the details of the lease, and, in particular, how the-accounting for the storage gas and royalties will operate, Ms. Beery was satisfied. I requested permission to represent to the AOGCC that CIRI's concerns had been addressed to its satisfaction. She agreed. By copy of this letter to CIRI, Unocal Alaska Oil and Gas Commission May 25, 2001 Page 2 represents to the Commission a) CIRI's concerns regarding the proposed storage project have been satisfaction, b) CIRI understands the production accounting methodology applicable to gas storage at Swanson River, and c) ClRI no longer is requesting action by the Commission. Unocal further represents that, in acCordance with the terms of the storage agreement and the rates set forth therein, Unocal will pay CIRI directly for CIRI's proportionate share of fees associated with the injection and withdrawal of gas from the subject lands based on CIRI's working interest. Due to the fact that CIRI filed the only comments regarding the proposed injection order, and that the comments have been fully addressed to CIRI's satisfaction, I respectfully request the Commission approve the injection order as filed without a public hearing. Very Truly Yours, UNION OIL COMPANY OF CALIFORNIA Dan~el-'B, Thomas - ' - Its Land Advisor Cc; CoOk Inlet Region, Inc., Candace Beery (wi copy of storage agreement) Bureau of Land Management MEMORANDUM TO: THRU: FROM: Julie Heusser Commissioner State of Alaska Alaska Oil and Gas Conservation Commission DATE: May 15, 2001 SUBJECT: Mechanical Integrity Tests Tom Maunder Unocal P.I. Supervisor'"" ~-- ' SRU 43-28 ~t%"°\ Swanson River Field/SRU Jeff Jones Petroleum Inspector NON- CONFIDENT, IAL ~ ~.~,, Packer Depth Pretest Initial 15 Min. 30 Min. ~~~[1~/~[I G I T.V.D. 15030 I~ubingl 280 '1 2801280 I28° I'nterva'l I"' ~~,e*'~e-;tl' P I T,~st, psil 12581 c~Singl I ~S00",l 1590"1 .1.590 I ,PIF I--P Notes: P.T.D. Notes: ' Well P.T.D.,I Notes: ,P.T.,D. Notes: P.T.D. Notes: I Type InJ. I I P'a~kerl I Tubing I I" I I ' I~nterVa~l ' Typetestl ' ITestpsil "lcasingl 'I I I .... IPIF I I Type Inj. I I I 'l'Tubing I ' I ' I I ' I lnterVall '" Type testI ,' ,'. I Test pSi l I c'asing I I ' I I '," ! P/i: I I TypelnJ. I' I I ITubingI I '1 ' '1 ' I lnterVall " TYpe testl ' IT.est P,sil ,I casing.I I I I ', I P/F I' " I Type INJ. Fluid Codes F = FRESH WATER 1NJ. G = GAS INJ. S = SALT WATER INJ. N -- NOT INJECTING Type Test M= Annulus Monitoring P= Standard Pressure Test R= Intemal Radioactive Tracer Survey A= Temperature Anomaly Survey D= Differential Temperature Test Interval I= Initial Test 4= Four Year Cycle V= Required by Vadance W= Test during Workover O= Other (describe in notes) T~t's De'tails Tuesday~ ~ 15. 20,~1: I traveled to Unocal's Swanson River Field to witness an initial MIT on well 43-28. Unocal Representative Bruce Hershberger performed the tests. The pretest pressures were observed to be stable and the standard annulus pressure test was then performed and the well passed the 30 minute pressure test. Summ.ary: I witnessed a successful MIT on Unocal's Swanson River Unit well 43-28. M.I.T.'s performed: 1_ Attachments: Number of Failures: _0 Total Time during tests: 2 CC-' MIT report form 5/12/00 L.G. MIT SRF 43-28 5-15-01 JJ 5/18/01 UNC )I\L ALASKA RESOURC[ ) WELL SERVICE REPORT ----- ------_.---- -....-. Well Number: Location: AFE # J PO #: Wiroline Crew: . Total Wireline Miles: Fill Tagged at (KB): ' Well KB: Max Tool Str~~~~ O~D. ---..-- -- Operation Details J-1:!- - D .s(~ '/0 " ,5,")0 Sc. <1/) i1..u;I'ý'e d , .t(~ f? I h1,ø7f , I I Lo60 ~(.~ (, 5' d b0 It? I Itl~T( \ . I~C j/.pDó ~(!, 0.>5 I< I (poò ¡, &,j- ~4c1'.2B ~KF' Date: Wireline Company: Work Being Done:. M;: I Present Operations: .;5fµ.r I"') _____ Unocal Supervisor: ß¿L-((!.e__ß~¿s)f6c"¡¿rr'/!::. Wireline Unit NUl11ber: Zero Wireline at: ._!~~.~~~g.t!,~!!º~~.__~~'=.==~_~ M!ni~ul11 Tub!l~g ~.D. !í-/S--DI -....------.--- Time 2:30 sÎdJ2../- 2' ~D . Z3 1 /2,')¡;¿ - ,6 ~ 00 ! 3,100 - 3: /5 3: /s - .? 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(~2'3S-~ SlJlJECT 43 -~8 , 5wN-.)'St)}..J í2;i V2? 5.LA~ '~e l~I\EO 8Y C~ÇI;XEO BY ) Calculation Reco' ) UNOCALe l~ ~PQ~~ ~cY¡- It ~ ~~, N.C. / ( ~~f. c)110 y..c., ~/ " ~~ ~/ ~\µV èf.N.Q ~ ~ !1tc{!t.t/.. -.-' ~ ~.J ~ ~~" þ. Ò~ "",<..\..A.. ~ ~) . 4-3-d.-<6 ( vJt~ \ ,^-e..a.ð v L ÍNt.t... Q1C1-+t:. \Jo. \ 'Jl. Proposed Dn"ec.-h-U'A aÇ ç:lo"W W,^W\ <jOÚA~ to ~~~ ~ >-<: I ~ LJ..) I <;> ~ V:J! c:::: z ~ --'"' LJ..) <Jl :> is=: c:::: Z C> ~ > _'t:'""'"'"" . ExGlí~; \À\'"'tGrO"l\ '* Row W"'-f...AI\ :+aK'-M5 ÇrljW\ ~t~-~t., ~- / >-z:I > :>< ~ '-C> c:> -..:] r--J co LJ..) r--J <Jl <Jl c:> --- >--cJ :> ~ t:rj r--J ~.o. '00 l'14.S ~~ tJ/0JI +- ~ ~I I (] ~ÙJ- ~ t ~MqW 2t.µ. · ~ I tkoc.k ; MQ ,~ ~ ~~ · · ~cluI"*- ~\eA. N~~ 1QSS I· j î ..... ~ O Lt3-~ _ vJt.\. \ ,^~ð v STATE OF ALASKA ALASKA oIL AND GAS CONSERVATION CO vIMISSlON REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown: Stimulate: Plugging: X Perforate: X Pull tubing: Alter casing: Repair well: Other: 2. Name of Operator 5. Type of Well: 6. Datum elevation (DF or KB) Union Oil Company of California (UNOCAL) Development: X 174' RKB MSL feet 3. Address Exploratory: 7. Unit or Property name Stratigraphic: P.O. Box 196247, Anchorage, AK 99519 Service: Swanson River Unit 4. Location of well at surface 8. Well number 2,130' FSL, 550' FEL, Sec. 28, T8N, R9W, SM SRU 43-28 At top of productive interval 9. Permit number/a, gproval number Same At effective depth 10. APl number Same 50- 133-10160-00 At total depth 11. Field/Pool Same Swanson River/Hemlock/Tyonek 12. Present well condition summary Total depth: measured 10,875' feet Plugs (measured) Cement @ 9,733' true vertical 10,875' feet PosiSet Bridge @ 6,850' / Cement @ 6,813' Effective depth: measured 10,708' feet Junk (measured) true vertical 10,708' feet Casing Length Size Cemented Measured depth True vertical depth Structural Conductor 30' 20" Yes 30' 30' Surface 2,032' 11-3/4" 1,290 sx Intermediate Production 10,875' 7" 1 stg 600 sx, 1,200 sx @ DV 10,875' 10,875' Liner Scab Liner Perforation depth: measured Open: 6,380'-6388' Abandoned: 10,615'-10,616' (sqzd); 10,617'-10,631'; 10,642'-10,656'; 10,664'-10,752'; 10,752'-10,754' (sqzd); 6,883'-6911' true vertical 6,380'-6388' Abandoned: 10,615'-10,616' (sqzd); ' ' ' 10,617-10,631; 10,642-10,656; 10,664,10,752, 10,752'-10,754' (sqzd); 6,883'%6~)11' O Tubing (size, grade, and measured depth) 2-3/8", 4.6#, L-80, Buttress SC @ 5,102' Packers and SSSV (type and measured depth) Ar~Chora~Te--"' Pr._o,,,~ Baker Mod. "FH" Retrievable @ 5,030' 13. Stimulation or cement squeeze summary N/A Intervals treated (measured)ORIGINAL N/A Treatment description including volumes used and final pressure N/A 14. Representative Daily Avera.qe Production or Injection Data OiI-BBL Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 11/20/98 0 0 0 0 700 Subsequent to operation 12/3/98 0 2 mmcfd 0 0 2,750 15. Attachments: 16. Status of well classification as: Copies of Logs and Surveys run: Daily Report of Well Operations: X Oil: Gas: X Suspended: Service: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge: Signed: i Dan W, lhamson Title: Drilling Manager Date: ~2.-- ~--~ Form 10-404 Rev 06/15/88 SUBMIT IN DUPLICATE Work Summary Swanson River Unit, Well 43-28 11/23/98 - 12/3/98 DAY 1 (11123/98) RU SCHLUMBERGER E-LINE UNIT. PRESSURE TEST LUBRICATOR TO 4,500 PSI. OK. RIH WITH POSISET PLUG. SET PLUG AT 6,850' WLM. POOH. SHUT DOWN. DAY 2 ('11124/98) RESUME OPERATIONS. RIH WITH 1-11/16" E,LINE BAILER TO 6,850'. ATTEMPT TO DUMP BAILER. NO INDICATION OF DUMP. POOH. SHEAR SCREW DID NOT SHEAR. DUMP CEMENT AT SURFACE. RE-FILL BAILER, RIH ATTEMPT NO. 2. SAME RESULTS. POOH. SHEAR SCREW NOT SHEARED. SHUT DOWN. DAY 3 (11125/98) RESUME OPERATIONS. FILL BAILER. RIH AND TAG POSISET PLUG AT 6,850'. DUMP BAILER. GOOD INDICATION OF DUMP. POOH. RUN FIVE RUNS WITHOUT PROBLEMS FOR A CEMENT TOP AT 6,841.5'. SHUT DOWN. DAY 4 (11/28198) RESUME OPERATIONS. FILL BAILER. RIH AND DUMP. APPEARED FROM WEIGHT LOSS THAT ONLY HALF OF CEMENT DUMPED. POOH. FOUND ACTUATOR HAD FAILED. REPAIR SAME. RUN SIX CONSECUTIVE BAILER RUNS FOR A CEMENT TOP OF 6,828.5' DAY 5 (11129198) RESUME OPERATIONS. PERFORM THREE ADDITIONAL RUNS FOR A CEMENT TOP AT 6,813'. DAY 6 (11130198) PRESSURE TEST PLUG TO 2,500 PSI FOR 30 MIN. BLED 100 PSI (4%). TEST O.K. BLEED TUBING TO ZERO. DAY 7 (1212198) RU BRAIDEDLINE. PRESSURE TEST LUBRICATOR TO 1,000 PSI. SWAB WELL TO 709' FOR UNDERBALANCE. RD BRAIDEDLINE. TUBING PRESSURE ZERO. DAY 8 ('1213198) RU SCHLUMBERGER E-LINE UNIT. TUBING PRESSURE ZERO. ARM GUNS. PRESSURE TEST LUBRICATOR TO 2,500 PSI. RIH AND PERFORATE 6,380' TO 6,388' WITH 1-11/16" PIVOT GUNS, 4SPF, 180 DEG PHASING. POOH. TUBING PRESSURE INCREASED FROM 0 TO 200 PSI. RIG DOWN. UNLOAD WELL. WELL MAKING 2MMCF/D AT 2,750 PSI TUBING PRESSURE. UNOCAL A B C D E F G H TOC 6,813' ~'Wanson River ~ ~ ell SRU 43-28 Actual Completion 1.2/3/98 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20" - - 31' 11-3/4" 47 - - 11.00 Surface 2,032' 7" 29 N-80 BTC/8rd LT 6.184 Surface 243' 7" 26 N-80 6.276 243' 883' 7" 23 N-80 6.366 883' 4,626' 7" 29 N-80 6.184 4,626' 5,013' 7" 26 N-80 6.276 5,013' 6,470' 7" 29 N-80 6.184 6,470' 8,315' 7" 29 P-110 6.184 8,315' 10,875' Tubing 2-3/8" 4.6 L-80 Butt. SC 1.995 15' 5,036' JEWELRY DETAIL NO. Depth II) OD Item 1 15' 2.195 7.027 Tubing Hanger, TC 1A-EN-CL, 2-3/8" EUE 8rd Lift Thread x 2-3/8" Suspension Threads, Cameron Type H 2 15.5' 1.995 2.375 Crossover, 2-3/8" EUE 8rd Pin x 2-3/8" Butt Pin 3 2,467' 1.901 4.812 Macco 2-3/8", SMO-1CI Chemical/nj. Mandrel 4 4,983' 1.901 4.812 Maeco 2-3/8", SMO-1 GLM w/1" Dummy 5 5,029' 1.995 2.850 Crossover, 2-3/8" Butt Box x 2-7/8" NU 10rd Pin 6 5,030' 2.441 5.983 Baker 2-3/8", 26#, Model "FH" Retrievable Packer 7 5,036' 1.995 2.850 Crossover, 2-7/8" NU 10rd Box x 2-3/8" Butt Pin 8 5,070' 1.875 2.90 X Nipple, (1.875") 9 5,102' 1.995 2.90 Wireline Entry Guide/Shear Out Sub ABANDONMENT DETAIL NO. Depth ID OD Item A 6,850 B 9.015' C 9,733' D 10,473' E 10,519' F 10,530' G 10,600' ? NO. Depth Item I 7,114' 7" Stage Collar PosiSet Plug w/37' Cement Tubing cut at 9,015' WLM. Top of Cement Plug. Pressure tested to 2,500 psi. Camco "MM" Mandrel with CEV Valve Brown CC Safety Joint Brown, 2-7/8" x 7", Type HS-16-1 Packer Camco "D" Nipple Venturi Shoe Notes PERFORATION HISTORY (Tyonek Perfs TDT Log Depth) Interval Accung Date Zone Top I Btm Amt spf Comments 12/3/98 64-5 6,380' 6,388'., 8' 4 1-11/16. Pivot, 180 deg. 7/26/98 68-0 6,883' 6,911' 28' 4 Abandoned 6/20/61 10,615' 10,616' 1' 5 Abandoned 6/21/61 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/61 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/61 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/61 10,752' 10,754' 2' 5 Abandoned PBTD = 6,813' TD = 10,875' MAX HOLE ANGLE = Vertical 43-28 Act Draw.doc DRAWN BY: tcb REVISED: 12/7/98 Unocal Corporation P.O. Box 196247 Anchorage, Alaska 99519 907-263-7660 UNOCAL October 26, 1998 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Attn: Commissioner David Johnston Subject: Swanson River Unit Well No. 43-28 APl No. 50-133-10160-00 Form 10-403, Proposal to Plug back and Perforate Dear Commissioner Johnston: Unocal proposes to abandon Tyonek 68-0 sands, which were found to be wet and non hydrocarbon bearing, and perforate the Tyonek 64-5, 62-5 sands in Swanson River Unit Well No. 43-28. Unocal proposes to isol~ate the lower wet Tyonek sands via the setting of an E-Line conveyed, through tubit~g "PosiSet" Plug and dump bailing cement on top of the plug. The new Tyonek gas zone will then be perforated with through-tubing guns. Attached in triplicate are the 10-403 form with a procedure and schematics. Estimated start date is November 9,1998. Please direct any questions to Tim Brandenburg at 263-7657. Sincerely, Dan Williamson Drilling Manager -" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon: Suspend: Operation shutdown: Re-enter suspended well: Alter casing: Repair well: Plugging: X Time extension: .Stimulate: Change approved program: Pull tubing: Variance: X Perforate: X Other: 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Union Oil Company of California (UNOCAL) Development: X 174' RKB above MSL feet 3. Address Exploratory: 7. Unit or Property name Stratigraphic: P.O. Box 196247 Anchorage, AK 99519 Service: Swanson River Unit 4. Location of well at surface 8. Well number 2,130' FSL, 550' FEL, Sec. 28, T8N, R9W, SM SRU 43-28 At top of productive interval 9. Permit number Same At effective depth 10. APl number Same 50- 133-10160-00 At total depth 11. Field/Pool Same Swnason River Field / Hemlock 12. Present well condition summary ~.F. Total depth: measured 10,875' feet Plugs(measured) 9,733' Cement .. IVIED true vertical 10,875' feet Effective depth: measured 10,708' feet Junk (measured)--"~'0~'~ 2. ~ '~(~ true vertical 10,708' feet 0i~ & Gas ConS, ,, _ Casing Length Size Cemented Measured depth J~t$~(aTrue Structural Conductor 30' 20" Yes 30' 30' Surface 2,032' 11-3/4" 1,290 sx Intermediate Production 10,875' 7" 1 stg 600 ax, 1,200 sx @ DV 10,875' 10,875' Liner ORIGINAL Perforation depth: measured Open: 6,883'-6911' Abandoned: 10,615'-10,616' (sqzd); 10,617'-10,631'; 10,642'-10,656'; 10,664'-10,752'; 10,752'-10,754' (sqzd) true vertical Open: 6,883'-6911' Abandoned: 10,615'-10,616' (sqzd); 10,617'-10,631'; 10,642'-10,656'; 10,664'-10,752'; 10,752'-10,754' (sqzd) Tubing (size, grade, and measured depth) 2-3/8", 4.6#, L-80, Buttress SC @ 5,102' Packers and SSSV (type and measured depth) Baker Mod. "FH" Retrievable @ 5,030' 13. Attachements Description summary of proposal: X Detailed operations program: X BOP sketch: 14. Estimated date for commencing operation 15. Status of well classification as: 11/9/98 16. If proposal well verbally approved: Oil: Gas: X Suspended: Name of approver Date approved Service: 17.I hereb~certify that th~,,foregoing is true and correct to the best of my knowledge. Signe(~~l~{~:~ Dan Williamson Title: Drilling Manager Date: ~~/~22 FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness IApproval._.NQ. _, ..-, Plug integrity ~ BOP Test Location clearance I ~_~)2..-,::;~ .¥~1 Integrity Test Subsequent form required 10- David W. Approved by order of the Commissioner Commissioner Date Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE Unocal Alaska Business Unit Swanson River Well No. SRU 43-28 Prepared by: Tim Brandenburg Plug Back and Reperforate No. Preliminary Procedure Time CUM CUM Estimate Time Time (Hours) (Hours) (Days) Plug Back 1 MIRU Schlumberger E-Line. 4.0 4 0.2 2 Pressure test Lubricator to 4,000psi. . 1.0 5 0.2 3 Pick up PosiSet Plug for 7", 29# Casing. -- 1.0 6 0.3 4 RIH with CCL/PosiSet Plug. - . 2.0 8 0.3 5 Set Plug at 6,850' MD. , _ ,.t~,~. 2.0 10 0.4 6 POOH. ~q.~l ~,,' ~ ~,t ~ 0.5 11 0.4 7 1-11/16" Bailer/Mix Ceme~.'I~ ,,, 2.0 13 0.5 8 RIH making runs as requir~ dump bail, of cement. 12.0 25 1.0 9 Allow cement to cure for 24 hours. 24.0 49 2.0 10 Pressure test plug to 2,500 psi. 1.0 50 2.1 11 Perform E-Line Tag prior to perforating. 1.0 51 2.1 Perforate 12 Swab well to achive 300# underbalance. 3.0 54 2:2 13 MU 1-11/16" guns, RIH and Perforate Tyonek (64-5) 6,380'-6,385' 1.0 55 2.3 14 POOH. 1.0 56 2.3 15 MU 1-11/16" guns, RIH and Perforate Tyonek (62-5) 6,256'-6,268' 1.0 57 2.4 16 POOH. 1.0 58 2.4 17 Rig Down. 3.0 61 2.5 43-28 Reperf Attach.xls Page 1 of 1 10/25/98 UNOCAL A B C D Fill Tagged ~ 10,708' 4/91. G Swanson River Well SRU 43-28 Actual Completion 7/27/98 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20" - 31' 11-3/4" 47 11.00 Surface 2,032' 7" 29 N-80 BTC/8rd LT 6.184 Surface 243' 7" 26 N-80 6.276 243' 883' 7" 23 N-80 6.366 883' 4,626' 7" 29 N-80 6.184 4,626' 5,013' 7" 26 N-80 6.276 5,013' 6,470' 7" 29 N-80 6.184 6,470' 8,315' 7" 29 P-Il0 6.184 8,315' 10,875' Tubing 2-3/8" 4.6 L-80 Butt. SC 1.995 15' 5,036' JEWELRY DETAIL NO. Depth II) OD Item 1 15' 2.195 7.027 Tubing Hanger, TC 1A-EN-CL, 2-3/8" EUE 8rd Lift Thread x 2-3/8" Suspension Threads, Cameron Type Iq 2 15.5' 1.995 2.375 Crossover, 2-3/8" EUE 8rd Pin x 2-3/8" Butt Pin 3 2,467' 1.901 4.812 Macco 2-3/8", SMO-1CI Chemical Inj. Mandrel 4 4,983' 1.901 4.812 Macco 2-3/8", SMO-1 GLM w/1" Dummy 5 5,029' 1.995 2.850 Crossover, 2-3/8" Butt Box x 2-7/8" NU 10rd Pin 6 5,030' 2.441 5.983 Baker 2-3/8", 26#, Model "FH" Retrievable Packer 7 5,036' 1.995 2.850 Crossover, 2-7/8" NU 10rd Box x 2-3/8" Butt Pin 8 5,070' 1.875 2.90 X Nipple, (1.875") 9 5,102' 1.995 2.90 Wireline Entry Guide/Shear Out Sub ABANDONMENT DETAIL NO. Depth II) OD Item A 9.015' B 9,733' C 10,473' D 10,519' E 10,530' F 10,600' G ? Tubing cut at 9,015' WLM. Top of Cement Plug. Pressure tested to 2,500 psi. Camco "MM" Mandrel with CEV Valve Brown CC Safety Joint Brown, 2-7/8" x 7", Type HS- 16-1 Packer Camco "D" Nipple Venturi Shoe NO. Depth Item I 7,114' 7" Stage Collar Notes PERFORATION HISTORY (Tyonek Perfs TDT Log Depth) hl~erval Accum. Date Zone Top Bim fiani spf Comments IIZ0/9?3 0?3.-0 0,5~53' 0,5t I 1' ZS' /4 1 -11 / 10" t'lVOt, 150 Deg. 6/20/61 - 10,615' 10,616' 1' 5 Abandoned 6/21/61 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/61 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/61 H-4/5 10,664' 10,752' 88' 4 Abandoned 6/20/61 - 10,752' 10,754' 2' 5 Abandoned PBTD = 9,733' TD = 10,875' MAX HOLE ANGLE = Vertical 243-28 Act Draw.doc DRAWN BY: tcb REVISED: 9/30/98 UNOCAL RKB = 15' A C I[lllllllll .. 'i'i'ri/l/11 .................................. I D E G Fill Tagged @ ~0,708' 4/91. Swanson River Well SRU 43-28 Proposed Completion CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20" - 31' 11-3/4" 47 - 11.00 Surface 2,032' 7" 29 N-80 BTC/8rd LT 6.184 Surface 243' 7" 26 N-80 6.276 243' 883' 7" 23 N-80 6.366 883' 4,626' 7" 29 N-80 6.184 4,626' 5,013' 7" 26 N-80 6.276 5,013' 6,470' 7" 29 N-80 6.184 6,470' 8,315' 7" 29 P-110 6.184 8,315' 10,875' Tubing 2-3/8" 4.6 L-80 Butt. SC 1.995 15' 5,036' JEWELRY DETAIL NO. Depth Il) OD Item 1 15' 2.195 7.027 Tubing Hanger, TC 1A-EN-CL, 2-3/8" EUE 8rd Lift Thread x 2-3/8" Suspension Threads, Cameron Type H 2 15.5' 1.995 2.375 Crossover, 2-3/8" EUE 8rd Pin x 2-3/8" Butt Pin 3 2,467' 1.901 4.812 Macco 2-3/8", SMO-1CI Chemical Inj. Mandrel 4 4,983' 1.901 4.812 Macco 2-3/8", SMO-1 GLM w/1" Dummy 5 5,029' 1.995 2.850 Crossover, 2-3/8" Butt Box x 2-7/8" NU 10rd Pin 6 5,030' 2.441 5.983 Baker 2-3/8", 26#, Model "FH" Retrievable Packer 7 5,036' 1.995 2.850 Crossover, 2-7/8" NU 10rd Box x 2-3/8" Butt Pin 8 5,070' 1.875 2.90 X Nipple, (1.875") 9 5,102' 1.995 2.90 Wireline Entry Guide/Shear Out Sub ABANDONMENT DETAIL NO. Depth ID OD Item A 6,850 B 9.015' C 9,733' D 10,473' E 10,519' F 10,530' G 10,600' ? NO. Depth Item I 7,114' 7" Stage Collar Proposed PosiSet Plug w/20' Cement Tubing cut at 9,015' WLM. Top of Cement Plug. Pressure tested to 2,500 psi. Camco "MM" Mandrel with CEV Valve Brown CC Safety Joint Brown, 2-7/8" x 7", Type HS-16-1 Packer Camco "D" Nipple Venturi Shoe Notes PERFORATION HISTORY (Tyonek Perfs TDT Log Depth) Interval Accum. Date Zone Top Btm Amt spf Comments 62-5 6,256' 6,268' 12' Proposed 64-5 6,380' 6,385' 5' Proposed 7/26/98 '68-0 6,883' 6,911' 28' 4 Propose Abandoned 6/20/61 - 10,615' 10,616' 1' 5 Abandoned 6/21/61 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/61 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/61 H-4/5 10,664' 10,752' 88' 4 Abandoned H PBTD = 9,733' TD = 10,875' MAX HOLE ANGLE = Vertical 243-28 Prop PB Draw.doc DRAWN BY: tcb REVISED: 9/30/98 ' STATE OF ALASKA ALASKA O1 . ,- ND GAS CONSERVATION Cu. IMISSlON WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL: GAS: X SUSPENDED: ABANDONED: SERVICE: 2. Name of OperatOrcompany (Unocal) 7. Permit Number/~. Union Oil of California ::-3~"_. :~ 3. Address 8. APl Number P.O. Box 196247 Anchorage, Alaska, 99519-6247 50-1733-20047-00 4. Location of well at surface , =..,,..~.i=...,~, 9. Unit or Lease Name 2,130' FSL, 550' FEL, Sec. 28, T8, R9W, SM !U:~I~(~_ Swanson River Unit At Top Producing Interval ~fii 10. Well Number Same (Vertical) No. 43-28 At Total Depth 11. Field and Pool Same (Vertical) Swanson River Field/Tyonek 5. Elevation in feet (indicate KB, DF, etc.) I 6. Lease Designation and Serial No. I 174' RKB above MSL 12. Date Spudded N/A 13' Date T'D' Reached I 14' Date C°mp" Susp' °r Aband' I 15' Water Depth' if °fish°re N/A 7~27~98 N/A feet MSL 16. No. of Completions 1 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) 19. DirectionalSurvey 120. Depth where SSSV set 121. Thickness of Permafrost 10,875'MD / 10,875'TVD 9,733'MD / 9,733'TVD Yes: No: X N/A feet MD N/A 22. Type Electric or Other Logs Run None 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" Conductor 15' 31' Driven Yes N/A 11-3/4" 47 Unknown 15' 2,032' 16" 1,290 sx N/A 7" 29, 26, 23 N-80, P-110 15' 10,875' 9-7/8" 1 stg. 600 sx, 1,200 sx DV N/A 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 2-3~8", 4.6#, L-80 5,102' 5,030' 6,883' - 6,911' MD / 6,883' - 6,911' TVD 1-11/16", 4spf, 180 deg. Pivot Gun 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USEb N/A N/A 27. PRODUCTION TEST Date First Production I Method of Operation (Flowing, gas lift, etc.) 7127198I Flowing Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE I GAS-OIL RATIO 7-27-98 6 TEST PERIOD => 0 0 80 N/AI N/A Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (corr) Press. 180 0 24-HOUR RATE --> 0 0 320 N/A 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. None ORIGINAL .,.,u ! ,...: 3 t99 Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Tyonek, 68-0 6,883'-6,911' Same 31. LIST OF ATTACHMENTS Perforation Data Sheet, Activity Summary, Welbore Schematic 32. I hereby certify that the fore. g~ing is true and correct to the best of my knowledge 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 space 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 productin intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 UNOCAL C D Fill Tagged ® 10,708' 4/91. G Swanson River Well SRU 243-28 Actual Completion 7/27/98 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 20" - 31' 11-3/4" 47 - 11.00 Surface 2,032' 7" 29 N-80 BTC/8rd LT 6.184 Surface 243' 7" 26 N-80 6.276 243' 883' 7" 23 N-80 6.366 883' 4,626' 7" 29 N-80 6.184 4,626' 5,013' 7" 26 N-80 6.276 5,013' 6,470' 7" 29 N-80 6.184 6,470' 8,315' 7" 29 P-110 6.184 8,315' 10,875' Tubing 2-3/8" 4.6 L-80 Butt. SC 1.995 15' 5,036' JEWELRY DETAIL NO. Depth ID OD Item 1 15' 2.195 7.027 Tubing Hanger, TC 1A-EN-CL, 2-3/8" EUE 8rd Lift Thread x 2-3/8" Suspension Threads, Cameron Type 2 15.5' 1.995 2.375 Crossover, 2-3/8" EUE 8rd Pin x 2-3/8" Butt Pin 3 2,467' 1.901 4.812 Macco 2-3/8", SMO-1CI Chemical Inj. Mandrel 4 4,983' 1.901 4.812 Macco 2-3/8", SMO-1 GLM w/1" Dummy 5 5,029' 1.995 2.850 Crossover, 2-3/8" Butt Box x 2-7/8" NU 10rd Pin 6 5,030' 2.441 5.983 Baker 2-3/8", 26#, Model "FH" Retrievable Packer 7 5,036' 1.995 2.850 Crossover, 2-7/8" NU 10rd Box x 2-3/8" Butt Pin 8 5,070' 1.875 2.90 X Nipple, (1.875") 9 5,102' 1.995 2.90 Wireline Entry Guide/Shear Out Sub ABANDONMENT DETAIL NO. Depth ID OD Item A 9.015' B 9,733' C 10,473' D 10,519' E 10,530' F 10,600' G ? Tubing cut at 9,015' WLM. Top of Cement Plug. Pressure tested to 2,500 psi. Camco "MM" Mandrel with CEV Valve Brown CC Safety Joint Brown, 2-7/8" x 7", Type HS-16-1 Packer Camco "D" Nipple Venturi Shoe NO. Depth Item I 7,114' 7" Stage Collar Notes PERFORATION HISTORY (Tyonek Perfs TDT Log Depth) lnterv',d Accum. Daie Zone Top Bim Am~ sp£ Commeuls //20/~9~5 06-0 0,~5~53' 0,~911' 2/5' q l-I 1/l 0" _l"lVOt~ 115LI Deg. 6/20/61 - 10,615' 10,616' 1' 5 Abandoned 6/21/61 H-1 10,617' 10,631' 14' 4 Abandoned 6/21/61 H-2 10,642' 10,656' 14' 4 Abandoned 6/21/61 H-4/5 10,664° 10,752' 88' 4 Abandoned 6/20/61 - 10,752' 10,754' 2' 5 Abandoned PBTD = 9,733' TD = 10,875' MAX HOLE ANGLE = Vertical 243-28 Act Draw.doc DRAWN BY: tcb REVISED: 9/30/98 Workover Summary Swanson River Unit, Well 43-28 7/9/98- 7/27/98 DAY 1 (719198) RU SLICKLINE, RIH W/2.25 GAGE RING TO 10,600'. POOH. RD SLICKLINE. RU APRS E- LINE. PRESSURE TEST LUBRICATOR TO 2,500PSI. RIH TO 10,528' AND PERFORATE TUBING FROM 10,528' TO 10,534'. POOH. ALL SHOTS FIRED. RD E-LINE. SECURE WELL. DAY 2 (7110198) RU DOWELL CEMENT UNIT. TEST SURFACE LINES TO 4,500 PSI. OK. BREAK CIRCULATION PUMP 64 BBLS LEASE WATER WITH NO RETURNS. CONT. PUMPING. RETURNS W/102 BBLS AWAY. ANNULUS BUILDING PRESSURE TO 175. WELL OUT OF BALANCE. MIX 25 BBL SLURRY 130 SX G W/.19 GPS D-110, .20 GPS D-145A, .8 GPS D300 TO 15.8 PPG. PUMP 25 BBL SLURRY, 10 BBL. XANVIS RETARDER, 8BBLS WATER DISPLACEMENT. RD DOWELL AND SECURE WELL. DAY 3 (7111/98) RU BRAIDED LINE. RIH W/2.5 BRUSH AND 2.25 GAGE RING. UNABLE TO PASS GLM AT 5,276'. POOH. REMOVE GAGE RING AND RIH. TAG CEMENT AT 10,585'. POOH. RIH W/2.25 GAGE RING. TAG CEMENT AT 10,585'. POOH. RD WIRELINE. DAY 4 (7114198) BREAK CIRCULATION DOWN TUBING WITH LEASE WATER. IMMEDIATE AND FULL RETURNS. CIRCULATE ANNULUS VOLUME. DAY 5 (7115198) TUBING AND ANNULUS 0 PSI. SPOT AND RU DOWELL. MIX 20 BBL SLURRY 97 SX G CEMENT W/.01 GPS D-47, .01 GPS D-110, .05 GPS D-145A TO 15.8 PPG. PRESSURE TEST SURFACE LINES TO 4,500 PSI. PUMP 25 BBLS SLURRY, 10 BBLS XANVIS SPACER, 45 BBLS LEASE WATER. ALLOW PLUG TO EQUALIZE. WAIT ON CEMENT. RU SLICKLLINE. RIH WITH 2.5 BRUSH AND TAG CEMENT AT 9,733'. POOH. RIH W/2.25" GAGE RING AND TAG CEMENT AT 9,733'. PERFORM MIT OF PLUG AND WELL. AOGCC AND BLM DECLINED TO WITNESS. PRESSURE TUBING TO 2,500 PSI HELD FOR 30 MIN. NO BLEED OFF. RU APRS E-LINE. RIH WITH 2-1/4" JET CUTTER AND CUT TUBING AT 9,015' POOH. RD. DAY 6 (7116198) INSTALL BPV. PRESSURE TEST PLUG AND CASING TO 2,500 PSI FOR 30 MIN. NO BLEED OFF. GOOD MIT. MIRU NORDIC RIG NO. 5. DAY7 (7/17/98) CONT. RU OF NORDIC RIG 5. ACCEPT RIG AT 19:30 HOURS. NIPPLE DOWN TREE, NIPPLE UP 7-1/16", 5M, BOPE. INSTALL GAS AND H2S DETECTION EQUIPMENT. DAY 8 (7/18198) CONT. NU BOPE. PULL BP¥, INSTALL TWO WAY CHECK. ATTEMPT TO TEST BLINDS. FLANGES LEAKING. TIGHTEN SAME. TEST ALL BOPE TO 250/3,000 PSI. OK. PULL TWO WAY CHECK. ENGAGE HANGER WITH LANDING JOINT AND PULL HANGER FREE W/114 K. PULL HANGER TO FLOOR AND REMOVE. POOH LAYING DOWN 2-7/8" COMPLETION. SOME NORM PRESENT. DAY 9 (7/19198) CONT. POOH WITH COMPLETION LAYING DOWN JEWELRY AND STANDING BACK CLEAN (NORM FREE) TUBING FOR SCRAPER RUN. SERVICE RIG. PU BIT AND SCRAPER ASSEMBLY. RIH ON 2-7/8" TUBING TO 7,040'. MIX AND DISPLACE WELL TO 3% KCL AND CORROSION INHIBITOR. POOH LAYING DOWN 2-7/8" TUBING. DAY 10 (7/20198) CONT. LD 2-7/8" TUBING. LAY DOWN BHA. ND. BOPE. INSTALL 7-1/16", 5M X 7-1/16, 5M TUBING sPOOL. NU BOPE. CLOSE BLINDS AND TEST NEW SPOOL AND 7" CASING TO 2,500 PSI FOR 30 MIN. OK. RU AND PREP TO RUN COMPLETION. PU AND RUN 2-3/8" COMPLETION PER PROCEDURE. DAY 11 (7/21198) CONT. RUN COMPLETION TO DEPTH. MAKE UP HANGER AND LANDING JOINT. LAND COMPLETION. DROP 1.5" BALL. PRESSURE TUBING STRING TO 2,000 PSI TO SET BAKER RETRIVABLE PACKER AT 5,030'. CONT. PRESSURE UP TO 3,200 PSI TO SHEAR BALL. PRESSURE TEST TUBING STRING AND PACKER TO 1,500 PSI FOR 10 MIN. OK. BLEED TUBING PRESSURE. PRESSURE TEST ANNULUS AND PACKER TO 1,500 PSI FOR 10 MIN. OK. RIG DOWN LANDING JOINT. INSTALL TWO WAY CHECK. NIPPLE DOWN BOPE. INSTALL TREE. TEST TREE, SEAL FLANGE AND TUBING HANGER TO 5,000 PSI, OK. RIG DOWN. RIG RELEASED AT 24:00 HOURS. DAY 12 (7/23198) RU BRAIDEDLINE. PRESSURE TEST LUBRICATOR TO 2,500 PSI. OK. SWAB COMPLETION FLUID FROM TUBING TO 1,400' FOR UNDERBALANCE. DAY 13 (7/26198) MIRU SCHLUMBERGER. PRESSURE TEST LUBRICATOR TO 4,500 PSI. TUBING AND CASING PRESSURE 0 PSI. RIH W/TDT, GR, CCL. FOUND FLUID LEVEL AT 1,400' (SWAB DEPTH). TIE IN WITH SWS TDT LOD 8/16/96. LOG TDT FROM 7,200' - 5100' POOH. HOLD PERFORATING SAFTEY MEETING. ARM PIVIOT GUN HEAD. RIH WITH GUN RUN NO. 1, 1- 11/16", 4 SPF, 180 DEGREE PIVOT GUNS. SET ON DEPTH. ATTEMPT TO DEPLOY. NO-GO. REPAIR SOFTWARE PROBLEM. DEPLOY GUNS AND PERFORATE FROM 6,901 '-6,911 '. POOH. ALL SHOTS FIRED. TUBING PRESSURE BUILT TO 500 PSI. SECURE WELL AND SHUT DOWN FOR NIGHT. DAY '14 (7127198) TUBING PRESSURE AT 500 PSI. RIH WITH GUN NO. 2, PERFORATE FROM 6,891' - 6,901' POOH. RIH W/GUN RUN NO. 3 AND PERFORATE FROM 6,883'- 6,892'. POOH. RD SCHLUMBERGER E-LINE. ATTEMPT TO UNLOAD WELL. MAKING WATER. Unocal Corporation P.O. Box 196247 Anchorage, Alaska 99519 907-263-7660 UNOCAL ) June 25,1998 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 Attn: Commissioner David Johnston Alask3 Oil & (;~s C0~S. Subject: Swanson River Unit Well No. 43-28 APl No. 50-133-10160-00 Form 10-403, Proposal to Abandon Hemlock and Recomplete to Tyonek Gas Dear Commissioner Johnston: Unocal proposes to abandon Hemlock perforations in Swanson River Unit Well No. 43-28 and recomplete in a Tyonek gas interval. This well is currently shut-in due to high water production from the Hemlock. The proposed work will require abandoning the existing perforations by bullheading cement down the tubing to the perforations and circulating cement, via perforations above the production packer, to the tubing by casing annulus. After the abandonment, a workover rig will pull the old tubing and run a new 2-3/8" completion. The Tyonek gas zone will be perforated with through-tubing guns. Attached in triplicate are the 10-403 form with BOP schematic, detailed operations program and three schematics of the existing wellbore, the proposed abandonment and the proposed recompletion. Estimated start date is July 5, 1998 so your timely consideration of this proposal would be appreciated. Please direct any questions to Tim Brandenburg at 263-7657. Sincerely, Tim Brandenburg STATE OF ALASKA .ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon: Suspend: Operation shutdown: Re-enter suspended well: Alter casing: Repair well: Plugging: X Time extension: Stimulate: Change approved program: Pull tubing: X Variance: Perforate: Other: X 2. Name of Operator 5. Type of well: 6. Datum elevation (DF or KB) Union Oil Company of California (UNOCAL) Development: X 174' RKB above MSL feet 3. Address Exploratory: 7. Unit or Property name Stratigraphic: P.O. Box 196247 Anchorage, AK 99519 Service: Swanson River Unit 4. Location of well at surface 8. Well number 2,130' FSL, 550' FEL, Sec. 28, T8N, R9W, SM SRU 43-28 At top of productive interval 9. Permit number At effective depth 10. APl n-'b"mber Same 50- 133-10160-00 At total depth 11. Field/Pool Same Swnason River Field / Hemlock 12. Present well condition summary Total depth: measured 10,875' feet Plugs(measured)i ,ECEIVED true vertical 10,875' feet Effective depth: measured 10,708' feet Junk (measured) ,; L;;!2 ]998 true vertical 10,708' feet Alask~t 0il & Gas Cons. 6omm!s~ Casing Length Size Cemented Measured depth True ver¢8~ Structural Conductor 30' 20" Yes 30' 30' Surface 2,032' 11-3/4" 1,290 sx Intermediate Production 10.875' 7" I stg 600 cz. 1.200 sx @ DV /..,~ 1.1~8,5~, , I j~, 10.875' Liner Perforation depth: measured 10,615'-10,616' (sqzd); 10,617'-10,631" 10,642'-10,656'; 10,664'-10,752'; 10,752'-10,754' (sqzd) true vertical 10,615'-10,616' (sqzd); 10,617'-10,631" 10,642'-10,656'; 10,664'-10,752'; 10,752'-10,754' (sqzd) Tubing (size, grade, and measured depth) 2-718", 6.5#, N-80, EUE 8rd @ 10,696' Packers and SSSV (type and measured depth) None 13. Attachements Description summary of proposal: X Detailed operations program: X BOP sketch: X 14. Estimated date for commencing operation 15. Status of well classification as: 6/29/1998 16. If proposal well verbally approved: Oil: X Gas: Suspended: Name of approver Date approved Service: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed: /l'~ g&.O~ 0~- Dale Haines Title: Drilling Manager Date: FOR COMMISSION USE ONLY Conditions of approval: Notify Commission so representative may witness IApproval No...-~ Plug integrity 4,,'"" BOP Test ~ Location clearance I Mechanical Integrity Test Subsequent form required 10- I~ 0 7' Original Signeo ,j David W. J0hnst0i Approved by order of the Commissioner Commissioner Date Form 10-403 Rev 06/15/88 SUBMIT IN TI~.~PLICATE Unocal Alaska Business Unit Swanson River Well No. SRU 43-28 Prepared by: Tim Brandenburg Date: 6/17/98 No. Preliminary Procedure Time CUM CUM Estimate Time Time (Hours) (Hours) (Days) Prep Well for Workover 1 RU APRS E-Line Unit. 2 RIH perforate tubing above packer from 10,515'-10,505' 3 Rig up Dowell Batch Mixer/Pump. 4 Pressure test lines. 5 Establish injection rate with Production Casing shut in. 6 Establish circulation through perforations taking returns to annulus. 7 Batch Mix 25 bbls. Cement. 8 Bullhead cement down tubing string to perforations. 9 Pump 4 bbls below packer. 10 IOpen annulus valve and pump 21bbls to a balanced height of 9,929' 11 RU APRS, run gage ring to 9,020', POOH. 12 R1H, cut tubing at 9,000', POOH. 13 RD APRS. AlaSKa Oli A~nhorage 14 Pressure test plug to 2,500psi. Workover 1 MIRU Nordic Rig No. 5 0.0 0 0.0 2 ND Tree, NU BOP and Test 24.0 24 1.0 3 Engage hanger with Landing Joint 1.0 25 1.0 4 POOH laying down tubing. 21.0 46 1.9 5 PU BOP's 4.0 50 2.1 6 Install new Tubing Spool. 3.0 53 2.2 7 Set down BOP's. 4.0 57 2.4 8 Test BOP's. 3.0 60 2.5 9 Set wear bushing. 1.0 61 2.5 10 PU 3-1/2" Drill Pipe RIH with bit and scraper to 7,100' 15.0 76 3.2 11 Perform Integrity Test. 1.0 77 3.2 12 Circulate well to completion fluid. 2.0 79 3.3 13 POOH laying down drill pipe. 15.0 94 3.9 14 Retrieve wear bushing, set test plug. 2.0 96 4.0 15 Change rams, shell test BOP's 3.0 99 4.1 16 Prep to run 2-3/8" Completion. 2.0 101 4.2 SCU 43-28 Cap Rec AFE.xls Page 1 of 2 6/25/98 Unocal Alaska Business Unit Swanson River Well No. SRU 43-28 Prepared by: Tim Brandenburg Date: 6/17/98 UNOCAL ) No. Preliminary Procedure Time CUM CUM Estimate Time Time (Hours) (Hours) (Days) 17 Run 2-3/8" Completion to 5,100' 18.0 119 5.0 18 Land hanger. 1.0 120 5.0 19 Set packer, test packer, shear out ball. 3.0 123 5.1 20 LD landing joint, install two way check. 1.0 124 5.2 21 ND BOP's. 12.0 136 5.7 22 NU Tree, Test. 3.0 139 5.8 23 RD Workover Rig 0.0 139 5.8 Subtotal (Days) 5.8 Loss/Trble Time (11%) 0.6 Total Project Days 6.43 RECEIVED b'i,i 2 !998 Alaska 0il & 6as Cons. Com~,~issior~ Anchorage SCU 43-28 Cap Rec AFE.xls Page 2 of 2 6/25/98 j , · Unocal Alaska Business Unit Swanson River Well No. SRU 43-28 Prepared by: Tim Brandenburg Date: 6/30/98 ATTACHMENT TO PRELIMINARY PROCEDURE DATED 6/16/98 UNOCAL ) No.' Preliminary Procedure "' Time CUM CUM Estimate Time Time (ttours) ~ours) (Days) mi, · I IIII III. i Release R~g 24 I~U E-Line, Pefforat, Tyonek 6,380'-6,410' a~d 6,883'-6,911' 12 151 6.29 25 Release Well to Production. ,,,, i ' I. . I II III II Ill I Isubto~ ~ays) Loss/Trble Time (11%) ii Total Project Days 1998 $CU 43-28 Cap Rec AFE.xIs 7,/7, 'ri Page 1 of 1 'dHO3 3VOONA 6/30/98 866[ 'O(;'unf' 9 12 13 Swanson River Well SRU 43-28 Actual Completion 12/21/62 RKB = 15' A SIZE Tubic~g I 2 3 4 5 6 7 8 9 10 11 t2 t3 WT CASING AND TUBING DETAIL GR,M)E CONN ID TOP BTM. 47 29 26 23 29 26 29 29 6.5 12.750Stu%cc 2,()~2' N-80 6184 4,626' 5,01Y N~80 6.276 5,013' Depth _ 15' 1.438' 2.904' 4,210' 5,267' &226' 7,06? 7.770' 1047Y 10.519' 10,530' I 0,600' I0,696' JEWELRY DEl'AIL OD Item q ubing Hanger, "Landing Mandl~'l and Nipple" Camco "MM' Mandrel with "RI)" VaE~ (amco "MM" Mandrel with "RD" Valvc Camco "MM" M mdrcl with "RD' Valve (amco "MM" Mar<h'cl with "RI)" Valve (amco "MM' Mandrel with "RI)" Valve Camco "MM' Mandrel with "RD' Valve ramco "MM' Man&el with "RD" Valve Cm~co ;'MM" Mandrel wilt~ "RI)' Va/xz- B~x>wn (( Safety Joint Bmx~n, 2-7/g' x 7", Type HS 16-1 Packer Camco "D" Nipple Tubing ]'ail? (See "D" in notes hdow) A 7,114' B 10,105' C Notes 7" Stage Collai Obslmclion noted on wall Schematic oa Sun&y submiued 818186 Pcrt~'d Tail Pipe horn 10,6IT 10,62T and 10,642' 10,652', l spf. Hype[dome w/3.2 gm Venmri Shoe shot offoftubing tail July. 198I. Icngth offish uaknoun PBTD = 10,790' TD = 10,875' MAX HOLE ANGLE = Vertical 43-28Draw,d(,c DP, AWN BY: ich RI VlSI l): ~wallsO~l RJYer Well SRU 43-28 Proposed Abandonment 9 t0 11 RKB = 15' SIZE CASING AND TUBING DETAIL GRADE CONN ID TOP BTM. 20" Tt~bing 2-3/8" 29 26 23 29 26 29 29 4.6 N-80 N-80 N-80 N 80 N-80 Pdl0 1. 80 B FC/Srd LT Butt. S( 1.995 15' 5,038 NO. Depth __ 1 15' 2 1.438' 3 2,904' 4 4,210' 5 5.267' 6 6,226' 7 7,{~62' 8 7.770' 9 10,473' 10 10.519~ 11 10,530' 12 10,600' 13 t0.696' JEWELRY DETAIL OD Item Tubing Hanger. "Landing MandrcI and Nipple" Camco "MM" Mai~dreI with "R])" VaM, Camco "MM" Mandrel with "RD" Valve Camco "MM' Mandrd wilh "RD" Valve Camco "MM** Mandrel with "RD" Valve Camco 'MM' Mandrel with 'RD' Valve Cail~c43 "MM" Mandrel with ~RD" Valvc Camco MM' Mandrel wifl~ "RD" Valve (amco 'MM' Mandrd with "RD" Valve Biown CC Salbty Joint Biown. 2 7/8" x 7". Type HS-16 l Packer Camco "D" Nipple ['uhing ]k~il? (Sec *D* in No~es below) Notes NO. ~epth Item -T - 7.114'7" Stage ( ollar B 10S 05'Obsiructkm noted oll well Schematic on Sun<lo; submiu< d 8/8/86 C Perfkd Tail Pip< flora 10.61T 10,62T and 10,642' 10,652', lspf, 11 I/~6 Ilyperdome w/3.2 gill D VoBlUl'i Shoe sho~ off of robing tail July. 1981. 12 C 13 1) PBTD = 10,790' TD = 10,875' MAX HOLE ANGLE = Vertical 43-28Ab Draw2,doc 1)RAWN BY: tcb R V SE ): 6/23/( 8 Swanson River Well SRU 43-28 Proposed Completion A B C RKB = 15' SIZE wr CASING AND TUBING DETAII, GRADE CONN ID TOP BTM, 47 29 26 23 29 26 29 29 4.6 l 2 3 4 5 6 15' 2,500' 5 5,038' 5,070' JEWELRY DETAIL .ID OD Item Tubi~g flanger 1.995 2.90 Macco 2 3/8", SM() l( ( heroical Ini Man&el 1 995 2.90 Macco 2-3/8", SMO GI.M w/ l'~ Dmmr~y 2.441 5.983 Baker 23/8", 26~, Model 'IH" Reirievablc Packer 1.875 2.90 X Nipple 1.995 2,90 Wilelinc Italy Guidc/Shea~ Om Sub NO. Depth A l 0A73' B 10.519' C 10,530' D ~ ( 600' E ? ABANDONMENT DETAIL _ ~D OD Item (!imco ;;MM" Man&d wilh (EV Vah'c Brown CC Saik'ly Joint Bro~n, 2-7/8" x T', Type }tS-16-1 l~acker Camco "D" Nipple Ventmi Shoe Notes NO__..,...;._ Depth l~em A 7,114~ 7" Stage Collal 6.4 5 6,¢80' 6,4 ! 0' 30' 4 6/21/61 t I-2 10,642' 10,656' I ~' 4 ,~ ) n(k ~ ed 6/21/6 4/5 ),664' ,752' 88' 4 '~ & o3 6/20/6! [0,75? t0,754' 2' 5 Aban~med D ]PBTD = 10,790' TD = 10,875' MAX HOLE ANGLE = Vertical 43--2gProp l)raw,doc I)RAg, N BY: lob Ri ]VlSI'it): 4/30/98 SWANSON RIVER BOP/WELLHEAD HOOKUP SRU 43-28 HYDRIL 7 ~" $000# ANNULAR HYDRIL 7 ~" 5000# DOUBLE GATE ~ UUUUU "5000~ CROSS "5000~ SPOOL t 52" 17" II 'Flow Level t SCHAFFER 'rBG. HEAD (6T55L1) 13 ~8 ' 3000# 13 ~" 3000# 11 {" K.D. HEAD 114~. # RECEIVED .... ' o ~ 1998 AJaska 0il & Gas Cons. Commission A,qchor~ge NOI~DIC WELL SEI~¢ICING RIG 5 MANIFOLD IS D~SIGN~.D WITH 3 1/8" x 5000 SHAFPER TYPE B T[~ROUGH LINE AND SHAFFE~ 2 1/16" x 5000 TYPE B SIDES. THE C[{OKES ARE TRI FLO 3" x 10,000 2" ORIFICE HYD. 2" x 5,0OO 1" ORIFICE MAN. VIEW AA DRWB. NO. NW$- 1/87 REF. DT. NO. $348 Form ~160-5 (JUNE 1990) UNITED c.. .rES DEPARTMENT OFTHE INTERIOR BUREAU OF LAND MANAGEMENT SUNDRY NOTICES AND REPORTS ON WELLS Do not use this form for proposals to drill or to deepen or reent~ to a different reservoir. Use 'APPMCATION FOR PERMIT-' for such proposals SUBMIT IN TRIFLICA TE 1. Type of Well Oil Gas [~: Well [~: Well I"'1 Other 2. Name of Operator Union Oil Company of California (dba Unocal) 3. Address and Telephone P. O. Box 196247, Anchoraqe, AK 99519 (907) 276-7600 4. Location of Well (Footage, Sec., T., R., M., or Survey Description) Swanson River Unit -- 14 Wells Soldotna Creek Unit -- 7 WelLs FORM APPROVED Budget Bureau No. 1004-0135 Expires: Man=h 31, 1993 5. Lease Designation and Sedai No. 6. If Indian, Nlottee or Tdbe Name 7. If Unit or CA, Agreement Designation Swanson River/ Soldotna Creek Units 8. Wetl Name and No. 9. APl Well No. 10. Field and Po<N, or Exploratory Area Swanson River Field 11. County or Parish, State Kenai, Alaska 12. CHECK APPROPRIATE BOX(s) TO INDICATE NATURE OF NOTICE, REPORT, OR OTHER DATA TYPE OF SUBMISSION TYPE OF ACTION Notice of Intent [] Subsequent Report Final Abandonment Abandonment Recompletion Plugging Back Casing Repair Altering Casing Other Temporarily Abandon [--] Change of Plans ~ New Construction [-] Non-Routine Fracturing r"] Water Shut-Off I-] Conversion to Injection [] Dispose Water (Note: Report results of multiple conmplefion on Well Completion or Recom~ Rep(xt and Log form.) 13. Descdbe Proposed or Completed Operations (Clearly state ali pertinent details, and give pertinent dates, including estimated date o~ stmlJng any Ixoposed work. If well is direcfionally drilled, give subsurtace locations and measured and true vertical depl~s for all markers and zone pertinent to I~is work.)* AS described in attached letter, Unocal requests that the following welLs have a temporarily abandoned status for the twelve month period, April 1,1996 to March 31,1997: Soldotna Creek Unit ~. j CJ SCU 21-8 /,~i SCU 34-9 (.O4:~'J ~SRU 212-10 (o),.~SCU34-a l~scu41B-9 (,eO-~RU12-15 ~1~_~/ SCU243-81 ~U14-34 O0-,q~)SRU,4-15 ~SCU 13-9 k~ 6~"~'0 SRU41A-15 I~_~ SRU 43A-15 ~0 -/0'7'/ J ~ t? SBU 23-22 * High GOR well that may be produced intermittently Swanson River Unit SRU2 2-27 SRU 23-27 /eo - ~t '/ SRU33 -27 t I=IVED SRU 34-28 ~,.;- 7_ SRU43-28 (~1" ~ SRU 21-33WD & 3.-,-1. APR 0 SRU 24-33 -~ ;;Z.-'7 14. I hereby certify tl~ the foregoing is true and correct. / ...... /// I - (This space for Federal and~S~,~l~frme use) Dennis L Groboske 'tee Petroleum Engineer Da. 3/29/96 Approved by T~tle Dam Conclltlons o~ approval, if any: T~le 18 U.S.C. Section 1001, makes itt came for any person knowingly and willfully to make to any departmant or agency of the United States any false, fictitious (x i'laU_N,_~ _l~lt~ st~tL.,f~ Or re~___~-~ '_t~:~ls as to ~ ii~ff~.w_ within its juriacicfion. *See Instruction on Reverse Side Attachment No. 1 Swanson River Field Proposed Temporarily Abandoned Wells: Total 21 Wells Twelve Month Period: April 1, 1996 to March 31, 1997 Shut-in Wells under Evaluation for Rate Potential P & A Shallow Gas Potential and 'Hemlock Only' P&A SCU 34-8 SCU 243-8 SCU 13-9 SCU 41B-9 SRU 21-33WD SRU 34-28 SRU 43-28 SRU 212-10 SRU 212-27 SRU 12-15 SRU 41A-15 SRU 23-27 SRU 331-27 SCU 14-34 7 Wells 2 Wells 5 Wells ~.~ * ~.~h GOR well that may be produced intermittently Shut-in Wells during Field Blowdown Hemlock Producers Future Shallow Gas PrOducer with the Hemlock Abandoned SCU 21-8 SCU 34-9* SRU 14-15 SRU 43A-15 SRU 14-22 SRU 23-22 SRU 24-33 2 Wells 5 Wells ATTACHMENT 2 SWANSON RIVER FIELD Wells with Temporarily Abandoned Status Change Removed from 1996 TemPorarily Abandoned Status · SCU 34-4 Recompleted in Tyonek G1 and G2 zones · SCU 43A-4 Recompleted in Tyonek G1 and G2 zones · SCU 13-4 Workover to remove tubing fish. Currently producing from Hemlock · SCU 23B-3 Returned to full time production · SCU 314-3 Returned to full time production · SCU 43-9 Returned to full time production · SCU 23-15 Returned to full time production Additions to 1996 Temporarily Abandoned Status, · SCU 13-9 Recompleted in Tyonek G2 zone Iow rate oil producer. APR 0 Unocal North Ame.,-"'~ Oil & Gas Division Unocal Corporation -~ 909 West 9th Ave., P.O. Box 190247 Anchorage. Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL Alaska Region March 31, 1994 Mr. Joseph A. Dygas Bureau of Land Management Alaska State Office 222 West 7th Avenue #13 Anchorage, AK 99513-7599 Re: 1994 Sundry Notice Request for TA Wells in Swanson River Field Dear Mr. Dygas: Attached is a Sundry Notice, requesting approval to temporarily abandon (TA) 30 wells in the Swanson River Field for a period of 12 months. This Sundry Notice is being submitted to comply with 43 CFR 3162.3-4, paragraph (c) of the Bureau of Land Management Regulations. As shown on the Sundry Notice, we are requesting that the 12 month approval period for the proposed TA wells coincide with the Plan Period of the Thirtieth Plan of Development and Operations for the Swanson River Field; i.e. April 1, 1994 to March 31, 1995. Two information sheets are attached with this Sundry Notice request. Attachment 1 lists the proposed TA wells using the same. format as submitted last year. The two general categories are shut-in wells being held for evaluation for current uses or disposition and wells being held for future uses during field blowdown. Attachment 2 gives a brief explanation for each well that has been added or removed from the proposed Temporarily Abandoned List. Three wells SCU 24A-9, SCU 33-5, and SCU 21-3 were removed from the list while two wells SRU 12-15 and SRU 21- 33WD were added to the list. RECEIVED APR - 1 1994. Uil & Gas Cons. Commission Anchorage Form 3160- 5 (JUNE 1990) UNITE~,' ATES DEPARTMENT OF THE INTERIOR BUREAU OF LAND MANAGEMENT SUNDRY NOTICES AND REPORTS ON WELLS Do not use this form for proposals to drill or to deepen or reentry to a different reservoir. Use 'APPMCATION FOR PERMIT-' for such proposals SUBMIT IN TRIPLlCATE 1. Type of Well Oil Gas I-)] Well [] Well I-] Other 2. Name of Operator Union Oil Company of California (dba Unocal) 3. Address and Telephone P. O. Box 196247, Anchorage~ AK 99519 (907) 276-7600 4. Location of Well (Footage, Sec., T., R., M., or Survey Description) Swanson River Unit --- 19 wells Soldotna Creek Unit --- 11 wells FORM APPROVED Budget Bureau No. 1004-0135 Expires: Mm'eh 31~ 1993 5. Lease Designation and Serial No. 6. ff Indian, Nlottee or Tribe Name · . · o. 7. ff Unit or CA, Agreement Design~on Swanson River/ Soldotna Creek Units 8. Well Name and No. 9. APl Well No. 10. Field and Pool, or Exploratory Aree Swanson River Field 11. County or Parbh, State Kenal, Alaska 12.CHECK APPROPRIATE BOX(s) TO INDICATE NATURE OF NOTICE, REPORT, OR OTHER DATA TYPE OF SUBMISSION TYPE OF ACTION · Notice of Intent Subsequent Repo~ I-] Final Abandonment l"1 Abandonment I-1 Change of Plans I-I Recompletion I"1 New Construction !-] Plugging Back I-] Non-Routine Fracturing Fl Casing Repair I-] Water Shut-Off r"] Altedng casing I"] Conversion to Injection [] Other Temporarily Abandon I-] Dispose Water If well is tim~io~l¥ drilled, give mJbeurkoe Iocatiorm and m~cl ~ ~ ~ ~ tor ~11 ~ ~1 ~ p~ll~l ~ ~1~ wodc)* As described in attached letter, Unocal requests that the following wells have a temporarily abandoned status for the twelve month period, April 1994 to March 31, 1995: ~ I' * SCU 23B-3 ~ I SCU 13-4 <~l *SCU 21A-4 3; SCU 34-4 5' I * SCU 43A-4 / -,o//...* SCU 21-8 Soldotna Creek Unit scu 243-8 SCU 341-8 SCU 13-9 * SCU 34-9 SCU 14-34 *High GOR wells that may be produced Intermittently. Swanson River Unit ~'; SRU 212-10 ./-"SRU 14-22 $ / 8FIU 43-28 ~sF SRU 14-15 ~/-~/~uRU 12-15 ~ 18RU 14A-33 SRU 23-15 ~1 SRU 23-22Tu3pSRU 24-33 ~Su~SRU 34-15 ~1 SRU 23-27 · · SRU 32-33WD % 1 SRU 41A- 15 } r~SRU 212-27 SRU 21-33WD ~sJ~ SRU 43A-15,..%~ SRU 331-27 ~ u~e SRU 432-15 ~ ~ SRU 34-28 Approved by T~le Date Conc~tions of approval, if any: RECEIVED APR - 1 1994 T~le 18 U'S'C' ~ 1001' makes it a ~rne f°r any pers°n im°wingly and willfully !° make t° anY department °r agency ~ ~ Un~ ~~'~n$. C0mmissi0r *See Instruction on Reverse Side Al]Gh0rag8 Mr. Joseph A. Dygas March 31, 1994 Page 2 As was the case last year, SCU 43-4WD is not included on the proposed TA list since it is a standby water disposal well used only seasonally. If you have any questions concerning this Sundry Notice, please call me at 263-7816. DLG:dma · Yours very truly, /9 Dennis L. ,ske Petroleum Engineer Attachment CC: L. R. Dartez, Marathon Oil Company D. W. Johnston, Chairman, AOGCC Attachment No,. ! Swanson River Field Proposed Temporarily Abandoned Wells: Total 30 Wells Twelve Month Period: April 1, 1994 to March 31, 1995 Shut-in Wells under Evaluation for Shallow Gas Potential Rate Potential P & A and 'Hemlock Only' P & A "/5-t~ SCU 13-4 ~:~ -q~oSCU 34-4 (e~- '~, SCU 341-8 b:o--I~ SRU 212-10 (~[- °cS SRU 23-15 ~_-~o SRU 41A-15 ~;~-~? SRU 34-28 ~z--5~{ SRU 14-22 ~ ~-~ SRU 43-28 e0-['~ SRU 23-22 ~o~'[~r> SRU 32-33WD aI-~%SRU 212-27 ~%-b~ SCU 243-8 ~-~q~ SRU 331-27 (07_-Z SRU 21-33WD~-ZZ. SRU 12-15 Io0-~&SCU 14-34 ~0-qc/SRU 23-27 SRU 14A-33 Shut-in Wells during Field Blowdown Hemlock Future Shallow Gas Producer Producers with the Hemlock Abandoned SCU 21-8 ~ ~-iu~ SRU 14-15 SCU 13-9 (~0-u~[ SRU 34-15 SCU 34-9 ~ SRU 43A-15 SCU 23B-3~ %~t-bb SRU 432-15 SCU 43A-4~ -~-L-o-~SRU 24-33 SCU 21A-4~ 8 Wells 8 Wells 3 Wells 6 Wells 5 Wells ~High GOR wells that may be produced intermittently RECEIVED APR - ] 1994 Alaska {)ii & Gas Cons. Commission Anchorage Attachment 2 Swanson River Field Wells with Temporarily Abandoned Status Change Additions to 1994 Temporarily Abandoned Status · SCU 12-15' Shut-in gas lift producer with casing communication. Evaluate for repair or abandonment. · SCU 21-33WD' Shut-in due to wireline fish in tubing. Workover candidate, Removed from 1994 Temporarily Abandoned Status · SRU 24A-9: · SRU 21-3: · SRU 33-5' Returned to full time production after workover, Returned to full time production due commencement of Blowdown in field. Returned to full time production after workover. tO RECEIVED aPR - 1 1994 ~s~a u~l & Gas Cons. Commission Anchorage Alaska Region Unocal North Americar~'~ Oil & Gas Division Unocal Corporation x, .. P.O. Box 190247 C-OMM Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 COMM COMM _ RES ENG UNOCAL ) z . _. r-, ~ I SR Gi~OL--F-I ~,Z' I r*~'~''~ ._~EOLASSTI-I Mr. Joseph A. Dygas Bureau of Land Management Alaska State Office 222 West 7th Avenue #13 Anchorage, AK 99513-7599 Re: 1993 Sundry Notice Request for TA Wells in S.wanson::RiverFiel¢t Dear Mr. Dygas: Attached is a Sundry Notice, requesting approval to temporarily abandon (TA) 31 wells in the Swanson River Field for a period of 12 months. This Sundry Notice is being submitted to comply with 43 CFR 3162.3-4, paragraph (c) of the Bureau of Land Management Regulations. As shown on the Sundry Notice, we are requesting that the 12 month approval period for the proposed TA wells coincide with the Plan Period of the Twenty-Ninth Plan of Development and Operations for the Swanson River Field; i.e. April 1, 1993 to March 31, 1994. These concurrent time periods will greatly simplify future TA Sundry Notice and Plan of Development and Operations preparation. Two information sheets are attached with this Sundry Notice request. Attachment 1 lists the proposed TA wells using the same format as submitted last year by ARCO. The two general categories are shut-in wells being held for evaluation for current uses or disposition and wells being held for future uses under field blowdown. Attachment 2 gives a brief explanation for each well that has been added or removed from the proposed Temporarily Abandoned List. Two wells, SCU 243-8 and SCU 21-8 were added to the list while three wells, SRU 21-22, SRU 12A-14 and SRU 211-15 were removed from the list. RE£EIVED MAR 2 5 199;5 Alaska Oil & Gas Cons. commission Anchorage Mr. Joseph A. Dygas March 18 Page 2 As was the case last year, SCU 43-4WD is not included on the proposed TA list since it is a standby water disposal well used only seasonally. If you have any questions concerning this Sundry Notice, please call me at 263-7816. YOurs very truly, Petroleum Engineer DLG:sr Attachment cc: L.C. Smith, Chairman, AOGCC L. R. Dartez, Marathon Oil Company RECEIVED Alaska 0il & Bas Cons. C0mmissio[~ Anchorage ~?UND[:~Y' NOTICES AND F,~POi:~,T$ O~-~ WELL$ Do no! use this lorm tot proposals to drill or to deepen or reentry to a dillerent reser¥oir. Use "APPLICATION FOR PERMIT--" lot such proposals SUBMIT IN TRIPLICATE I. Tyl~ of Well [Oil Gas Well [=Xl Well r~ Other 2. Name of Opcralor Union Oil Company of California (dba Unocal) 3. Address and Telephone No. P. 0. Box 196247, Anchorage, Alaska 99519 (907) 276-7600 4. Location of Well (F~mge, S~., T., R., M., or Su~ey ~scription) Swanson River Unit 17 wells SOldotna Creek Unit 14 wells 12. TYPE OF SUBMISSION TYPE OF AOTION 7. If Unit or CA, Agreement Designation Swanson River/ Soldotna Creek Units 8. Well Name and No, 9. APl Well No. 10. Field and Pool, or Exploratory Area .Swanson River Fi eld Il. Count~ or Parish, State Kenai~ A1 aska CHECK APPROPRIATE BOX(s) TO INDICATE NATURE OF NOTICE, REPORT, OR OTHER DATA -X] Notice of Intent [--]Subsequent Report --]Final Abandonment Notice ---]Abandonment --] Reeompletion '--']Plugging Back ---]Casing Repair [~ Altering Casing [~] Omer Temporari 1 y Abandon --]Change of Plans ---]New Construction ---]Non-Routine Fracturing --']Water Shut-Off ---]Conversion to Injection F--] Dispose Water (Note: Report results of multiple completion on Well Completion or Rccomplction Report and Lo8 lotto.) 13. Describe Proposed or Completed Operations (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. If well is directionally drilled, give subsurface locations and measured and true vertical depths for all markers and zones pertinent to this work.}* As described in attached letter, Unocal requests that the following wells have a temporarily abandoned status for the twelve month period, April 1, 1993 to March 31, 1994' Swanson River Unit SCU 21-3 SCU 21-8*~ ~ SRU 212-10 SCU 23B-3~ SCU 243-8~ SRU 14-15' SCU 13-4 ~ SCU 341-8' SRU 23-15~ SCU 21A-4 SCU 13-9× SRU 34-15 SCU 34-4~ SCU 24A-9~ SRU 41A-15 SCU 43A-4- SCU 34-9'~ SRU 43A-15 SCU 33-5F SCU 14-34v' SRU 432-15 SRU 14-22~ Swanson River Unit SRU 23-22' SRU 23-27 ~ SRU 212-27~' SRU 331-27 SRU 34-28~ SRU.:43-28 ~ SRU 14A-33~ SRU 24-33~' SRU 32-33WD RECEIVED 5 Alaska Oil & Gas Cons. Anchorage * High GOR wells that may be produced intermittently. Signed /J~/~/"~ ;(~ ~ Titlc Petroleum Engineer ~ ~ for F~ or S~o~) Date. Approved by Title Date Conditions of approval, if any: 'itle 18 U.S.C. Section I001, makes it a crime for any person knowingly and willfully to make to any department or agency of the United States any false, fictitious or fraudulent statements *See Instruction on ~r~e Side Attachment No. 1 Swanson River Field Proposed Temporarily Abandoned Wells: Total 31 Wells Twelve Month Period: April 1, 1993 to March 31, 1994 Shut-in Wells under Evaluation for Shut-in Wells until the Field Blowdown Rate Potential P & A~ Shallow Gas Potential and 'Hemlock Only' P & A Hemlock Producers Future Shallow Gas Producer with the Hemlock Abandoned SCU 13-4 SCU 21A-4 SCU 34-4 SCU 43A-4 SCU 33-5 SRU 341-8 SRU 34-28 SRU 43-28 SCU 32-33WD SCU 243-8 SCU 21-3 SRU 212-10 SRU 23-15 SRU 41A-15 SRU 14-22 SRU 23-22 SRU 212-27 SRU 331-27 SCU 14-34 SRU 23-27 SRU 14A-33 SCU 21-8" SCU 13-9 SCU 24A-9 SCU 34-9" SCU 23B-3' SRU 14-15 SRU 34-15 SRU 43A- 15 SRU 432-15 SRU 24-33(2~ 11 Wells 7 Wells 3 Wells 5 Wells 5 Wells "~ Does not include SRU 211-15. Scheduled full P & A in March-April, 1993 (2~ Scheduled 'Hemlock Only' P & A in March-April, 1993. ' High GOR wells that may be produced intermittently. RECEIVED Alaska 0ii.& Gas Cons. Commission Anchorage Attachment 2 Swanson River Field Wells with Temporarily Abandoned Status Change (Based on 1992's TA Status - December 27, 1991) Additions to 1993 Temporarily Abandoned Status · SCU 243-8: · SCU 21-3: Shallow gas producer (Tyonek). Shut-in due to mechanical problems. Workover candidate. Shut-in due to current high GOR. Mechanical problems. Removed from 1993 Temporarily Abandoned Status · SRU 21-22: Returned to production after flowline repair. · SRU 12A-4: · 'SRU 211-15 Returned to full time production in 1992. Scheduled for full P & A MarCh-April, 1993. Waiting on personnel and rig. RECEIVED MAR ~ 5 '~99;~ Alaska 0il & Gas Cons. Anchorage -. ..... t'i~;~ ~,c. ,t)i~,.;6~; Anchorage: Alaska 99510-0360 Telephone 907' 276 1215 December 8, 1992 Commissioner Leigh Griffin Alaska Oil and Gas Conservation Commission 3001 Porcupine Dr. Anchorage, AK 99510 SR'~r~IG SR ENG ~"~" ENG ASST ENG ASST SR GEOL GEOL ASST GEOL ASST STAT TECHI STAT TECH FILE L.~~''''' Re: Transfer of Pending Sundry Applications to New Operator Dear Commissioner Leigh Griffin, With the transition of operatorship of the Swanson River Field and the King Salmon Platform from ARCO Alaska, Inc. to Unocal we are passing onto Unocal the existing work files of several projects that have Sundry Applications approved by your office. The following approved SUndries are being transferred: SRU 43-28 SRU 331-27 SRU 211-15 SRU 24-33 Convert Well to Water Injection. Convert Well to Water Injection. Plug and Abandonment Hemlock Only Abandonment Unocal, as operator, is assuming the respqnsibility of carrying out the work as approved by your office or canceling the existing Sundry Application and re-submitting revised work plans. In addition to the above there are pending operations on the King Salmon Platform that Unocal will carry out when they assume operatorship. This includes the 'No Flow Testing' on K-5, K-10rd, K-24 and K21rdS, and an MIT that is due on K-15. This work is currently scheduled to be completed when an inspector from your office is available to witness the testing. If you should have any questions concerning any of this work please do not hesitate to contact me at 263-4304 or you can contact Mr. Martin Morell with Unocal at 263-7805. Sincerely, Tom Wellman ' Transition Manager, Cook Inlet Engineering cc: Martin Morell Unocal ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieidCompar~y Alaska Oii & (~as Cons. Commission .... Anchorage ~RCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 Cook Inlet Engineering July 10, 1992 Mr. L. Smith Alaska Oil and Gas Conservation Commission 3001 Porcupine Dr. Alaska, Alaska 99501 Mr. Smith; Please find the attached Sundry Application which requests your approval to convert the shut-in producer SRU 43-28 into a water injector. If the conversion is successful, the well will subsequently be re-designated as SRU 443-28 to incorporate the field's well naming nomenclature for water injectors. BY injecting water into the producing Hemlock formation in this well ARCO hopes to provide pressure maintenance for the offset producers SRU 12-27 and SRU 41-33 thus increasing the ultimate oil recovery. Furthermore, by changing the sweep pattern in the fault block we hope to possibly move oil to SRU 34-28 which is currently shut-in because it produces at a high water cut. This work is being done in conjunction with our evaluation of converting SRU 331-27, a shut-in gas injector, into a water injector to provide additional pressure support to the eastern flank of the fault block. The Sundry for 331-27 has already approved and the work is currently ongoing. The results of the conversion of SRU 43-28 will directly impact the evaluation of the SRU 331-27 work. Pending a successful mechanical integrity test on the well the proposed work is consistent with the governing Area Injection Order # 13 regulating injection activity in the Swanson River Field. We will contact your office to arrange for scheduling a State Inspector to witness the MIT upon approval of the attached Sundry Application. If you have any questions concerning this work please do not hesitate to contact either Jim Zernell at 263-4107 or Janet Wiemer at 263-4797. Sincerely, J. C. Winn, Acting Regional Engineer JCW:JTZ:jlg:0154 Attachment RECEIVED CC: Mr. A. R. Kukla Mr. B. C. Dehn Marathon Oil Company UNOCAL Corporation ARCO Alaska, Inc. is a Subsidiary of Atlantic Richfield Company J U L 1 1992 Alaska Oil & Gas Cons. commission Anchorage STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon _ Suspend _ Alter casing _ Repair well Change approved program_ 2. Name of Operator ARCO Alaska. Inc. 3. Address P. O. Box 100360, Anchorage, AK 99510 Operation Shutdown _ Re-enter suspended well ~ Plugging _ Time extension_ Stimulate _ Pull tubing _ Variance _ Perforate _ Other ~ Well Conversion / MIT 5. Type of Well: Development _ Exploratory _ Stratigraphic _ Service ~X 4. Location of well at surface 2130' N, 550' W from SE corner Sec. 28, T8N, Rgw, SM At top of productive interval At effective depth 6. Datum elevation (DF or KB) RKB 174'. GL 159' 7. Unit or Property name Soldotna Creek Unit 8. Well number SRU 43-28 At total depth Straicjht Hole 12. Present well condition summary Total Depth: measured 1 0875' feet true vertical 10875' feet Effective depth: measured 1 0745' feet true vertical 1 0745' feet Casing Length Size Structural Conductor 31 ' 2 0" Surface 2032' 1 1-3/4" Intermediate 1 0875' 7" Production Liner Perforation depth: feet 9. Permitnumber ~,. 00DI~ 10. APl number so-133-1 01 60-00 11. Field/Pool Swanson River/Hemlock Plugs (measured) Junk (measured) Cemented 1 0790'- 1 0875' Measured depth True vertical depth Driven 31' MD 31' TVD 1290 sx 2032' MD 2032' TVD 1800 sx 10875' MD 10875' TVD 13. measured Current: 10617'-10631', 10642'-10656', 10664'-10752' MD true vertical Current: 10617'-10631', 10642'-10656', 10664'-10752' TVD Tubing (size, grade, and measured depth 2-7/8" 6.5# N-80 from 10696' to surface Packers and SSSV (type and measured depth) Packers: Brown HS-16-1 Packer ~ 10531' Attachments Description summary of proposal _..X_ RECEIVED J U L 1 3 1992 Alaska 0ii & Gas Cons. Commission Arich0raoe Detailed operation program_ BOP sketch _ 14. Estimated date for commencing operation July 19c,);~ 16. If proposal was verbally approved Name of approver Date approved 15. Status of well classification as: Oil __ Gas _ Suspended Service _~_ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sicjned ~ Title Cook Inlet Recjional Engr. FOR COMMISSION USE ONLY Date 7//~/~ "L Conditions of approval: Notify Commission so representative may witness Plug integrity_ BOP Test m Location clearance Mechanical Integrity Test _ Subsequent form require Approved by the order of the Commission Form 10-403 Rev 5/03/89 Ori{31nal Signed By David W. Johnston IApproval N~.~_~ --/ ~ ~ ~,~,.,Approvecl Cop~J 1 o- -.,,, ,-, Returned '7- ,~l- Commissioner Date ~7-I ~" c~ ~ SUBMIT IN TRIPLICATE Procedure to Convert SRU 43-28 to a Water Injector. , , 3, . , Perform MIT (to be witnessed by the AOGCC and BLM) in accordance with Area Injection Order # 13. If MIT is successful perform a step rate injection test to determine the injection vs. pressure profile for the well for evaluating its value as a water injector for the limited water flood project. The step rate test should be taken to pressures up to 2,000 psi to fully evaluate the wells potential as an injector. If the results from the step rate injectivity testing is satisfactory, perform the pipeline modifications and tie-ins necessary to route injection water to the well. All lines must be hydro-tested prior to putting the well into service. Put the well on continuous injection at the maximum rate available. Monitor daily rates and pressures. Submit the appropriate documentation to the AOGCC and BLM to re-name the well SRU 443-28 to designate it as a water injector. RECEIVED d U L 1 1992 Alaska Oil & Gas Cons. Commissiol, Anchorage · o o. oo )-*---.,'~- :,,,--,*-.,-..-,,,...:~,.. 'R ~ C E IV E D · :. --..-.---,,,~J,w~.. ',-Y'.,,w~ ~,',,~,~,~-.~ ......... .. J U L 1 ~ 1992 :. -~n, ...Alas~ Oil & Gas Cons, Commissio, i-----g .... " .... "' ' '- · ' Anchorage '-,. · -' ...... ~' ". ..... :'.?? ...... 'J ' "'" ' :"~'s,,,(o~"'"'~r ~ /4~/6".'.~ .- ~', '"~'~"~ ~,,,e~,,r' ~-.e,e~ -, ........... ;,;, ..... . · .~ H;."r~''''''''~'~'''~'''~'' ..................~:,.... . .' · ~ . 't ;*. · . o .. 'o · . · · ~. . ..'.~i, ..'t : '. ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 Cook Inlet Engineering December 27, 1991 COMM SR GE ~iLE Mr. J. A. Dygas Chief Branch of Lease Operations (AK-984) Bureau of Land Management 222 West 7th Avenue Post Office Box 13 Anchorage, AK 99513-7599 Subject: 1992 ~und.ry Notice ReqUest for TA Wells in Swanson River Field Dear Mr. Dygas: Attached is a Sundry Notice, requesting approval to temporarily abandon (TA) 32'.~ wells in the Swanson River Field for a period of 12 months. This Sundry Notice is being submitted to comply with Chapter II, Section 3162.3-4, paragraph (c) of the Bureau of Land Management Regulations. All 32 wells are expected 'to be shut-in for a period of at least 30 days during 1992. Several information sheets are attached with this Sundry Notice request. Attachment 1 lists the proposed TA wells and separates them into the following five categories: Shut-in wells under evaluation for: . rate potential, permanent abandonment (P & A), and shallow gas sand potential and 'Hemlock Only abandonment. RECEIVED DEC ~ 1 199t Alaska Oil & Gas Cons. Commissie~ Anchorage Mr. J. ^. Dy gas Page 2 December 27, 1991 Shut-in wells until field blow. d.own, including.'.. 4. Hemlock producers, and 5. wells with future shallow gas potential in which the Hemlock has been abandoned. The fifth category shown above is a new addition to this year's TA listing. This grouping is for the wells in 'which the Hemlock has been abandoned but the wellbore is being maintained for possible future shallow gas production. Four wells from last ye.ar's TA list were moved into this category. Attachment 2 gives a brief explanation for each well that has been added to or removed from the 1991 Temporarily Abandoned List (Ref: our letter of 12/28/90). Eight wells, SCU 12A-4, SCU 21-8, SCU 23B-3, SCU 43A-4, SCU 13-9, SRU 212-10, SRU 21-22 and SRU 212-27, have been added while two wells, SRU 21-15 and SRU 314-27, have been removed from the previous TA List. Attachment 3 is a list of shut-in wells that are not included in the '92 TA listing. Two of the wells mentioned above, SRU 21-15 and SRU 314-27, are not included because they are scheduled for P & A in the first quarter of 1992. This work is being done as part of the '91-'92 Swanson River Plan of Development. Also included in Attachment 3 is SCU 43-4WD, a standby water disposal well which is only.used seasonally. If you have any questions concerning this Sundry Notice request, please call Hyeh- Yeon Hoffer at 265-1355 or Jim Zernell at 263-4107. Sincerely, JJ C. Winn Acting Regional Engineer JTZ:jlg:0025 Attachment C~ L. C. Smith, Chairman AOGCC A. R. Kukla, Marathon Oil Company B. C. Dehn, UNOCAL Corporation R£C£ X/rr-D Alaska Oil & 6as Cons. gom~'lss~On Anchorage ORIGINAL Form 3150--$ (Novmber 1983) (Formerly 9.331) UNITED STATES (OUter DEPARTMENT OF THE INTERIOR BUREAU OF LAND MANAGEMENT SUNDRY NOTICES AND REPO'RTS ON WELLS (Ua not u~ this form for propo~ll to drill or to deep~m or plug back to R diVe.ut rmrvolr. UM "APPLICATION FOR PERMIT--" for lu~J Dr~im~.) NAMR O~' OPBRA'EOR ARCO Alaska, Inc. 3. Af)ORr~ OP P.O.Box 100360 Anchoraqe, AK 99510 LOCiTtOf~ Or WELL (Report lo~ttiol clearly iud In &ecordllce with uy Sta~e requlremen~.e See elsa st)ReP 17 below.) Form approved. Budget Bureau No. t004-OtS$ £xptrea Auguat 3t. t985 Soldotna Creek/Swanson Rv 8. PARM OR ~BARI N&MR ~. WELL Swanson River Unit 19wells Soldotna Creek Unit ...... 13 wells 1~. PRIMI~ MO. Swanson River Field ~UAVBT Kenai Alaska 16. NO~ICB aP IN~BNTION TO: Chec~c. Appropr, ate Box To Indicai*e Nature o1: Notice, Report, or ~ Data snoot oR AC~D~ZB REPAIR WILL CHANGE P[.A.~S (Other) _ . J .} (Other) TemporarY Abandon ?oR, rE: Report reeultm of ..dUpe eom~euo~ on wen REpletion or Recordpleflon ..Be. port and Lo~ foE.) 17. Df~SCBIBE I.aOPOSED Ok propooed work. Ir ,Nil L, directioneay drilled, wive miimurYm~.~ locations and mean,red and true vertical ~ep~ EOF mia muse,~ elm son# peru- · lent to ~ wo~k") · As decribed in the attached memo, ARCO Alaska, Inc. requests that the following wells have a temporaffiy abandoned status: Soldotna Creek l/nit Swanson River Unit SCU 23B-3 SCU 21-8 * SRU 212-10 SRU SCU 12A-4 SCU 341-8 SRU 14-15 SRU SCU 13-4 SCU I3-9 SRU 23-15 SRU SCU 21A-4 SCU 24A-9 SRU 34-15 SRU SCU 34-4 SCU 34-9 SRU 211-15 SRU SCU 43A-4 SCU 14-34 SRU 41A-15 SRU SC[3 33-5 SRU 43A-~5 SRU SRU 432-15 SRU SRU 14-22 SRU SRU * -High GaR weUs that may be produced intermittently. 21-22 23-22 23-27 212-27 331-27 34-28 43-28 14A-33 RECEiVE£ 32-33WD DEC 3 1 1991 Alaska Oil & Gas Cons. C0mmk TZTLE Actinq Reqional EnqineerD&Tm' (Thio il)ace rot Feder&t or 8mae o~c~ urn) APPROVED BY CONDITIONS O~' APPROVAL, LI* ~: TITLE DATE ~,e Inmucfions on Revmu Side Attachment 1 Swanson River Field Proposed Temporarily Abandon Wells: Total 32 Wells Shut-in Wells under Evaluation for ! Shallow Gas Potential Rate Potential P & A and 'Hemlock Only' P & A :!:i:!:i:!:i:i:i:i:i:i:i:i:i:i:i::;~:i:i:i:i:i:~:i:~:i:i:i:i:i:i:i:i:i:i:::i:i:i:i:i:i:i:i:i:i:~:i:i:i:i:~:i:i:i:i:~:i:i:i:i:i:~:i:~:!:i:i:i:i:i:~:i:i:i:i:~:i:i:i:i:i:i:~:i:i:i:i:~:~:i:i:i:i:i:i:~:i:i:i:i:i:::::::::::::::::::::::i:~:i:i:i:i:i:i:i~!:i:i:i:~:!:i:i:i:i:i:!:i:i:!:i:i;i:i:i:i:i..i~i:i:i:i:i:i:i:i:i:i:i:i:i:i:i:i:i:~:~::.:i~i:!:~:i~i:i;i:i:i:i:i:~:i:i:i:i:i:i: SCU 12A-4 SRU 212-10 SCU 13-4 SRU 211-15 SCU 21A-4 SRU 23-15 SCU 34-4 SRU 41A-15 SCU 43A-4 SRU 14-22 SCU 33-5 SRU 23-22 SCU 341-8 SRU 212-27 SRU 21-22 SRU 331-27 SRU 34-28 SRU 24-33 SRU 43-28 SRU 32-33WD SCU 14-34 SRU 23-27 SRU 14A-33 11 Wells 9 Well~ 3 Wells Shut-in Wells until the Field Blowdown Future Shallow Gas Producer Hemlock Producers with the Hemlock Abandoned SCU 21-8 * SCU 13-9 SCU 24A-9 SCU 34-9 SCU 23B-3 * SRU 14-15 SRU 34-15 SRU 43A-15 SRU 432-15 5 Wells 4 Wells * -High GOR wells that may be produced intermittently. For:. Temporarily Abandonment Sundry 12/27/91. Attachment 2 RECEIVED Swanson River Field Wells with Temporarily Abandoned Status Change (Based on 1991's TA Status; our letter 12/28/90) DEC 1 1991 Alaska Oil & Gas Cons. Commis$i Anchorage Added to 1992 Temporarily Abandoned Status: · SCU 23B-3 & · SCU 21-8: High GOR wells, maYbe produced intermittently, otherwise shut-in until blowdown. · SCU I2A-4: High GOR well, may be produce intermittently, This well is also being considered as a workover candidate. SCU 43A-4: Shut-in due to mechanical problems. Also being considered as a workover candidate for shallow gas. · SCU 13-9: High GOR well, shut-in until field blowdown. · SRU 212-10 & · SRU 212-27: High water rate shallow fuel gas well, currently not economic to produce based on current fuel gas needs. · SRU 21-22: Well currently shut-in due to problems with the flowline. Well will be returned to production when repairs have been completed. Removed from 1991 Temporarily Abandoned Status · SRU 21-15 & · SRU 314-27: Wells are scheduled for full P & A in 1st Quarter 1992 as part of the '91-'92 SRF Plan of Development. Note: 'Hemlock Only' abandonments were performed on SRU 14-15, $RU 34-15, SRU 43A-15 and SRU 432-15. These wellbores are being maintained for their future shallow gas potential and remain on the TA List for 1992. Attachment 3 Swanson River Field Shut-in Wells not on the 1992 TA Status List Wells with planned upcoming work: · SRU 21-15 & · SRU 314-27: Wells are scheduled for P & A in first quarter 1992. Wells that are used seasonally · SCU 43-4WD: This water/mud disposal well is a standby well and is only used on an 'as needed' basis. RECEIVED DEC 3 1 1991 Alaska Oil & Gas Cons. t, ummissio~, Anchoraoe ARCO Alaska, Inc. Post Office BOx 100360 Anchorage. Aiaska 995 ~0-,3360 Te,ec'~cne ~07 2-~ '2~5 ~ng~meer:mg December 29, 1989 Mr. J. A. Dygas, Branch Chief Division of Minerals Bureau of Land Management 6881 Abbott Loop Road Anchorage, Alaska 99507 Dear Mr. Dygas: Attached is a Sundry Notice requesting approval to temporarily abandon 31 wells in the Swanson River Field for a period of 12 months. This sundry is being submitted to comply with.Chapter H, Sec. 3162.3-4, paragraph C of the Bureau of Land Management Regulations. All 31 wells are expected to be shut-in for a period of at least 30 days. The wells arc separated into four categories: 1. Under evaluation for rote potential. 2. Under evalUation for P&A or future utility. 3. Inefficient producers. 4. Shut-in until blowdown. Several other items have been attached for your information. Brief explanations are given for each well that has been added or deleted from the temporarily abandoned status (Ref: your letters of 3/1/89 (3160 (984)) and 3/30/89 (3180 (984)) and our letter 12/28/88). In addition, a list of currently shut-in wells which have planned upcoming work that will enable their return to production is attached. If you have any questions concerning this Sundry Notice request, please call Stacy Strickland at 263-4914. Sincerely, Tom Wellman TW:SLS:jt:0016 Attachment cc: C.V. Chatterton, Chairman AOGCC A. R. Kukla, Marathon Oil Company S.W. OhnimUs, UNOCAL Corporation RECEIVED DEC2 1989 Alaska Oil & Gas Cons. CommissiQ Anchorage ~o,~ ~z6o-s L..,TED STATES (Noveml)4~ t9~3) (~o~.-~ 9-~) D~ARTMENT OF THE INTERIOR BUREAU.OF LANO MANAGEMENT SUNDRY NOTIC~ AND RE~R~ ON ~L~ Form approved, Budget Buru~u No. 1004--0135 F.,x~)tr~a &u&~mt 31. 1985 la. IJdJI OBll~ll&~'BOll &a~ IIBL&L 110. 1. N&IdB Ol' OPBLL1'q:)R ARCO Alaska, Inc. 3. ADDl~,ll Of OIl*aBa'LOt ?. oIIrff &GUOMBNT NAldl ~woaldotn~-Crook/, nson ~v~r, un,ts ~. ~AIM oa i.BAaa XAMa !0. f'ttLO AHD ~aGI, os VILOCA! Post Offi'ce Box 100360 Anchroage, AK 99510 4. LOCA?tO~ Of WELL (ge~orl: location clearly and tn accordance with &ay ISt&~e See 81so space 17 below.) Al: sur"ga~ Soldotna Creek Unit - 11 wells Swanson River Unit - 20 wells 14. PIIMI'I' NO. I Kena i Alaska 16. Check Ap~ooflate Box To Indicate Nature o~ Notice, Reno,t, or Other Dala NO~ICB Of INTBN~*ION TO: REPAIR WaLL CHA~GB PLAN8 (Other) Temporar i J y abandon (No, u: Re~ofl regalW .~. mulU~ie eomoleClou om Well Completion or Re~om~leuon Be~ort end Loqr form.) ,, lT. u~.,qc~snr Z'nO,OSEO oo COMPLETED OPEOATIO?;S (Clearly state all I~prtin~nt detail,, end ;lye IMrtlneut deteL laeludlne aRia&red date Of_ltirtlnf IaI ;,co~oe~-~ work. l! weal in diructiofmlly drilled, five oubeu~eee Iomfluno and mellured and true vertteM depUm for &il marlEero end ~oaee perU- nets ~ ~his work.) · As dcscribcd in thc attached memo, ARCO Alaska, Inc. requests that thc following wells have a temporarily abandoned status: $oldotna Creek Unit Swanson River Unit SCU 13-3 SCU 13-4 SCU 21A4 SCU 34-4 SCU 24-5 SCU 33-5 SCU 33-8 SCU 341-8 $CU 34-9 $CU 3 la-16 $CU 14-34 SRU 34-10 SRU 23-22 SRU 14-15 SRU 312-22 $RU 21-15 SRU 23-27 SRU 211-15 SRU 314-27 SRU 331-27 SRU 31-15 SRU 34-28 SRU 34-15 SRU 43-28 SRU 41A-15 SRU 14A-33 SRU 43A-15 SRU 24-33 SRU 32-33WD SRU 432-15 SRU 12-34 RECEIVEg 2 1 89 Alas~ 0il & Gas Cons. C0mmk Anchorage 18. ! berel)y certify *h°t the fore~olJ~ ts Crde end eorre~ TITLE Cook Inlet Enginerring Mana~ (Thio alMce for Feder~ or APPROVED BY CONDITION8 OIP APPROVAL. LI* A~r: TXTL~ DA~'B "See Insltwflm on Re,me Side Title tS U.S.C. Section t00l, makes it a crime for any person kno~Xngly and willfully to make to any department or agency of the Ufl[teci States any false, ~ictxtxous or fraudulent statements or represeflta~ons as to any matter wtthtn itS jUrtsdictio~ TEMPORARILY ABANDONED WELLS IN SRF Wells under Evaluation Rate Potential Wells being evaluated for p&A/Future~ Utility Wells SI for Inefficient .Production Wells SI until Blowdown 13-4 34-4 24-5 33-8 341-8 34-9 41A-15 23-22 23-27 13-3 14-15 21-15 211-15 31-15 34-15 432-15 31A-16 312-22 34-28 14A-33 32-33WD 12-34 14-34 21A-4 33-5 34-10 43-28 24-33 43A-15 314-27 331-27 For: Temporarily Abandonment of 12/29/89 .. .SWANSON RIVER FIELD Wells having Changed Temporarily Abandoned Status Added to Tem0orarily,,, Abandoned Status: SCU 21A-4: Well is temporarily abandoned due to inefficient production (high GOR). SRU 32-33 W D: Well is temporarily abandoned due to annulus communication problems. Removed from Tem_noraril¥ Abandoned Status: $CU 243-8: This shallow sands gas well has been returned production. SCLI 13-9: A workover is planned for this well which will enable this well to be retUrned to an active status. S,RU 212-10: This shallow sands gas well has been returned to production. $,RU 23-15: This gas-lifted well has been returned to production. SRU 21-34: A sidetrack is planned which will enable this well to be returned to an active status. RECEIVED Alaska Oil & Gas Cons. Commissio~ Anchorage For: Temporary Abandonment Sundry of 12/29/89 SWANSON RIVER FIELD WELL STATUS UPDATE Shut-in Wells with Planned Upcoming Work* SCU 32A-9: When on-line, this SI well produces gravel. A sidetrack is planned to return this well to active status. *Will not be placed'on temporarily abandoned statuettE/yED · O~c ~ 91,989 For: Temporary Abandonment Sundry of 12/29/89 UNITED STATES DEPARTMENT OF ]'HE iNTER:OR GEOLOGICAL SURVEY Anchorage A-028399 Swanson ~ver Unit LESSEE'S M N _ - 0 TH[,Y REPORT OF OPERAT.=O, JS Alaska {%?.nt'!! .K.ena.i. Pe. ni..nsula >-.,.. ,,,~ .. Swanson River December ,.:. 62 . . . ?. O. Box 7-839 Anchorage, Alaska BRoadway 7-6.201 Swanson River Unit ,,,,,~,:.,,..,..STANDARD OIL CO. OF CALIF. W.O.Io Ai::,,',/ C. V: ./~d, ,:~/'s t~ :,;,, District Superintendent \V ;,:I.1, ......... , } {IlL li~l~l~,-;{II'~,<)~ ' , ~ '* ........ t , ' ~ANSON ~R gNIT h3-28 (21) ~IAL WO~ ~medzal work ¢o~enced December 22, 1962. Killed well ~th B2ack ~gic mud, ~lled 2 7/8" tu~ing. ~n casing ~eraper. ~Rer~ 2 7/~" g~b~g equSpped w~h packer ~d 7 Camco ~ mndrels. L~ed tubing at 1~96'. ~moved DOPE and !nstalled x-~s ~tree~ D:ksplaced md with o~ S~ paeke~ a[ 105~1~. ~g released December 27, 1962 U.SoO.So ~ Mo H- Soyster State - r~ a. ~arshall .Richfieldt- C. !W. Perry R. ~R. RiOter Marathon :. George Sowards Union- H', M. ~ian Files - P~oduc~ng NoT~:..--There were .................................. rm~s or ,~,a, les of oil; ................. M cu. ft. of gas sold; ..................................................... runsor s~les~f<:t:;ol~neduring themonth. (Write "no" where No'rl~;.. [report on this forth is required for emJ~ calcmhtr month, rm4ardless of tho ~'..:,tus uf ,,i)erfttic~n:¢, ami mu~t duplicate wiLh the m~l)ervJsor by the 6d1 o[ *,he s,mcecdh~.g tnonth, ~121css ot,h(:rwise d{r,'ct,:i by t.):o n. lI)erv (Jartuury 19~}) to USTBG '8 SUBMIT IN DUI,-.~ATE* STATE OF ALASKA , OIL AND GAS CONSERVATION COMMITTEE :'~!" iii mi ii WELL COMPLETION OR RECOMPLETION REPORT A~D LOG* -~s. TYPE 0F WELL: u~h .~ ,;*s ~ xxEi. I. ~J WELL __ DRY ~ b. TYPE 0F COMPLE~ON: NKW ~ WORK ~ DEEP- ~ }'I UG ~ DIFF. . 2 NAb! E OF OPERATO![ ,~. ADDRESS OF OPERATOR 4. .o ','r r)x 0F w.~:r.L (Report location clearly and ill accordance with any State requirements)* At surface At tc, p prod. lnterval reported below At total depth DATE SPUDDED [14. DATE T.D. I~Ea%CI-IED !15. DAT~ COMP SUSP OR ABAND. FATAL DEPTH, MD & TVD[19.PLUG, BACK MD & TV'D~20. 1~ MiULTIPLE COIVLPL., ~OW ~Y* ROTARY TOOLg ........ PRODUCING !NT~HVAL(S), OF THIS CO,MP~TIO~TO,P, BOSOM, NAME (MD AND 5. APl NIsBL~2MCA~ CoDE ,.,4'6- t33 -- I d l t, O 6. LF~&SE DESIGNATION .~'XD SERL%L NO. 12. PEIL'~IT N'O, 16. E;LEVAq2IONS ¢DF, RKB, t~T, GR, ETC)*ll7. ELEV. CASINGHEAD ! INTERVALS DRILLED BY CABI,E TO(')I $ 2.'3. 'WAS DIRECTIONAL SU[I VEY MADE ,1 24. TYPEELEC'FNIC AND OTHER LOGS RUN 25. CASING R~C:ORD (Report all strings set in well) CASI24G SiZE WEIGIiT, LB,FT, CEi2LNTING RECO3~ AI,IOUNT PULLED .... H~/~ ~3~_ i~ 1 ............ I, - 1,' ' 28. PERFORATIONS OPEN TO PRODUC~ON (interval, size and nurnber) 29 -ACID, SHOT, Fi~A. iT[ URE, C~'iENT SQUL!gZ2, ~'TC. " DEPIIi INI~VAL (MD) AMOUNt 2~D I'2!ND OF MAI'EP~AL USED u, Pt~ODUCTION DATE P.[RST PR, ODUCTION ! P~ODUCTION MIL±HOD (Flowing, !.{a3 lif[, pdmping--size and type of pumP~ DATE GF TEST, ~iOURS 7EST~ ~CI!OI{E SIZE ]PBOD']{ FO~ OI~BEL. G-AS--5~CF. :~6iV~' t~;.r<mss. CASI. N G PRESSURE ,[fii-HOuRICALC~T~. RATE~ [OII~BBL. IGAS--MCr' ii I V,;ELL ST'ATUS (Producing or uP. ti t- in ) WATER--BBL. WAT'g~--B BL. ©AS-OIL RAT'IO lOlL GRAVITY-APl (COI:{P~,) t TEST WITNEgSEDBY ~2./.1STOF ATTACHMENTS ..... f;3. I hereby ce. rtify that the foregoing and attached information is complete and correct as deiermin}d from alI-Kviilable records ........ 7-~-7~ ....... *(See Instructions and Spaces Jar Additional Data on Reverse Side) INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report end log on all types of lands and leases in Alaska. Item: 16: Indicate which elevation is used as reference (where not otherwise shown) for depth measure- merits given in c, ther spaces on this form and in any attachmer~ts. Items 20, and 22:: If this well is completed for separate f'~rcd'~;ction from more than one i~terval zone (multiple completion), so state in item 20, and in iter~ 22 show the p~c.:tuci~g intcrval, or i~tervals, top(s), bottom(s) and name (s) (if any) for only the interv~J reported in iten~ 30. Submit a separate report (page) on this form, adequately identified, for each additio~l inte~wl to be seperately produce:J, show- ing the additional data pertinent to such interval. Item]6: "Sacks Cement": Attached supplemental records for this well shoulJ show the details of any mul- tiple stage cementing and the location of the cementing toot. Item 28: Submit a separate completion report on this form for each interval to be separately produc~l. (See instruction for items 20 and 22 above). "?~Y O1~ IPORMA'I'ION TESTS IN(~LUI)IN(; INT£RV~'L TESTED. t'HEF;.SURE DATA A.N'D RECOVERIES OF ()IL. GAS. 35. G IDOLOG If' M AR K1KIR~ WATI~R AND MUD NAM'E MEAs. DEPT~a. DA'I'Ai Aq'I~ACII'I~IHIEF EI~ll;~FIONS 'OF LIT}[OLOGY. AND :DETECt'ED $11OWS O~ OIL..G'~ COMPLETION REPORT - NEW WELL STANDARD OIL COMPANY OF CA, ~LIFO~,~IA~' .WESTERN ..,OPERATION. S~.' INC. - OPEPATOR AREA: Kenai Peninsula, Cook Inlet Area, Alaska LAND OFFICE: Anchorage PROPERTY: Swanson River Unit LEASE NO.: A-028399 WE'LL NO.: SRU 43-28 SEC. 28, T. 8 N., R. 9 W., Seward B & M LOCATI ON: ELEVATION: Surface: 2130' north and 550' west from southeast corner of Section 28. 174' K.B. K.B. is 15' above ground. October 20, 1961 BY: C. V. CHATTERTON C. V. CHATTERTON, District Superintendent DRILLED BY: Coastal Drilling Company DATE COMMENCED DRILLING: June 16, 1961 DATE COMPLETED DRILLING: July 22, 1961 DATE OF INITIAL PRODUCTION: July 27, 1961 PRODUCTION: Daily Average 565 B/~D Flowing Oil .......... 559 B/D Gravity... 35.0° Water ........ 6 B/D TP ....... l~O0 103 M~fD Bean 10/65" Gas ................ SUMMARY TOTAL DEPTH: 10,875 ' PLUGS: 10,790 - 10,875' JUNK: NONE CASING: 20" conductor pipe cemented at 31'. 11 3/4" casing cemented at 2,032' in one stage around shoe with 1290 sacks of cement. 7" casing cemented at ~10,875' in two stages with 1800 sacks; 600 sacks around shOe; 1200 sacks through DV at 7,100'. COMPLETION REPGRT - PACKER Ak~ GAS LIFT INSTALLATION STANDARD OIL COMPANY OF CALIFORNIA -~ESTERN OPEFaITIONS~ INC. -Operator AREA: Kenai Peninsula, Cook Inlet Area, Alaska PROPERTY: Swanson River Unit LAND OFFICE: Anchorage LEASE NO. A-028399 WELL NO. SRU 43-28 Section 28 T. 8 N., R. 9 W., Seward B & M LOCATION: Surface: 2130' North and 550' West from Southwest Corner of Section 28 ELEVATION: 174 ' K. B. DATE:· June 21, 1963 K. B. is 15' above ground. BY: '' HA'TER 0 , DiStridt S'~perintende~t CONTRACTOR: Santa Fe Drilling Company, Rig # 35 DATE COMMENCED REMEDIAL WORK: December 21, 1962 DATE COMPLETED REMEDIAL WORK: December 27, 1962 S~Y TOTAL DEPTH: 10, 875 ' PLUGS: 10,790' - 10,875' CASING: 20" cemented at 31' 11 3/4" cemented at 2032' 7" cemented at 10,875' COMPLETION REPORT - GAS LIFT AND ~ CKER INSTALLATION SWANSON RIVER UNIT 43-28 Section 28 T. 8 N.,. R 9 W.~ Seward B & M STANDARD OIL COMPANY OF CALIFORNIA~ WESTerN OPERATIONS, INC. - Operator December 21~ ...19.62 Commenced rigging up a t 9:00 P.M. December 22~ 1962 Conditioned Black Magic Mud. Killed well~ removed x-mas tree and installed BOPE. Pulled tubing loose, tagged bottom at 10,790' and circulated. Pulled 2 7/8" tubing out of hole. December 232 1962' Ran 7" casing scraper to 10,790' and circulated. Pulled and ran 2 7/8" tubing open ended. De~ember 24, 1962 Circulated at 10,790'. December 25~ 1962 Shut down for Christmas. December 26, 1962 Circulated and pulled out of hole. Reran tubing equipped with packer and mandrels. December 27, 1962 Ran a total of 334 joints 2 7/8", 6.5# N-80, EUE 8R R2 tubing. TUBING DETAIL K.B. Depth K. B. to ~onut Donut and nipple 45 joints 2 7/8" tubing Camco MM Mandrel w/RD (#1) 46 joints 2 7/8" tubing Csmco MM Mandrel w/RD (#2) 41 joints 27/8" tu~ing Camco MM Mandrel w/RD (#3) 33 joints 2 7/8" tubing Camco MM Mandrel w/RD (#4) 30 joints 2 7/8" tubing Camco MM Mandrel w/RD (#5) 26 joints 2 7/8" tubing Camco MM Mandrel w/RD (#6) 15.O0' 2.51' 17.51' ~421.o9' 1438.6o, 12.98' 1451.58' 1452.45' 2904.03' 12.96' 2916.99' 1293.92' 4210.91' 13.00' 4223.91' 1043.41' 5267.32' !3.00' 5280.32' 945.90' 6226.22' 12.9%' 6239.17' 822.87' 7062.04' 12.98' 7075.02' COMPLETION REPORT - PACKER AND GAS LIFT i~,~STALLATION SWANSON RIVEH L~IT 43-28 ~ Section 28 T. 8 N.,. R. 9 W.~ Seward B & ~ STAND~'RD bIL ~c'OMPA'~"'6~~ ~ALIF0~NiA~' ~'ST~._PJ~ OPE~-~A'i~IONS, INC. - Operator 22 joints 2 7/8" tubing Camco MM Mandrel w/RD (#7) 85 joints 2 7/8" tubing Camco MM Mandrel w/CEV (#8) I joint 2 7/8" tubing Brown CC Safety joint Pup joint Brown 2 7/8" X 7" HS-16-1 packer 2 joints 2 7/8" tubing Camco "D" Nipple 3 joints 2 7/8" tubing Venturi Shoe Tubing landed at 695.92' 7770.94' 13.02 i 7783.96' 2691.19' 10,475.15' 12,96' 10,488.11 ' 32.34 ' 10,519.45 ' 1.O6' 10,520.51 ' 10.14' 10,530.65' 6.02' 10,536.67' 63.44' 10, 600.11 ' · 95 ' 10,601.06' 94.75' 10,695.81 ' .68' 10,696.49' Removed BOPE and installed x-mas tree. at 10,531',, Rig released at 12:00 midnight. Displaced mud v~th oil and set packer S.R. HANSEN sat COMPLETION REPORT SWANSON RIVER UNIT 43-28 S C ,0N 9 W., SmWARD & ~TANDAED 0IL CO. OF CALIFOR~?IA, W. 0 'I. - OPERATOR Page 2. PERFOPATION RECORDS: 5 -½" holes at 10,615' 4 ½ -" holes/ft, over following intervals: 10,752 - 10,664' 10,656 - 10,642 ' 10,631 - 10,617 ' WELL SURVEYS: 1. Schlumberger Induction Electrical Log, interval 2,045 - 100' 2. Schlumberger Induction Electrical Log, interval 9, 356 - 2,030' 3. Schlumberger Induction Electrical Log, interval 10,876 - 9, 356' 4. Schlumberger Sonic Log, interval 2,040 - 100' 5- Schlumberger Sonic Log, interVal 9, 340 - 2,030' 6. Schlumberger Sonic Log, interval 10,515 - 9,340' 7. Schlumberger Microlog w/Caliper, interval 10,875 - 9,840'; 6,510 - 4,990' 8. Schlumberger Continuous Dipmeter, interval 10,874 - 2,030' 9. Schlumberger NeutrOn Collar LOg, interval lO, 789 - 9, 000' 10. Schlumberger Cement Bond Log, interval 10,780 - 3, 000' 11. Baroid Mud LOg, interval 10,875 - 9, 590' DRILL STEM TESTS: HCT W.S.O. Test ~1 on 5 ~" holes at 10,615' WSO HCT W.S.©. Test ~ on 4~-" holes/ft., inte~-'~-lO, 752 - 10,754' WSO COMPLETION REPORT SWANSON RIVER UNIT 43-28 SECTION 28, T._8..N,, R. 9 W~.~ SEWARD B & M STANDARD 0IL CO. OF CALIFORNIA, W.O.I. - OPERATOR Page 3. ..June..16, 1961 Spudded at 2 AM. Drilled 16" hole 0 - 1,851' 1,851' drilled June 17, 1961 _ Drilled 16" hole 73 - 74 pcf mud Reamed hole with 16" bit 0 - 618' 618' reamed 87 pcf mud Reamed hole with 15~2" reamer 618 - 2,045' 1, 427' reamed 83 pcf mud Ran Schlumberger Induction Electrical Log, interval 2,045 - 100' and Sonic Log, interval 2,040 - 100'. j~u~. e., !8, !961 Ran 11 3/4" casing and cemented at 2,032' as follows: CEMENTING DETAIL: Cemented 11 3/4" casing at 2,032' in 1 stage with 1290 sacks of cement treated with HR-4 using Halliburton power equipment. Used one top rubber plug. ls.t' .St.a...g~e around shoe with 1290 sacks of cement. Pumped 40 bbls. of water ahead, mixed 1290 sacks of cement in 35 mins. using Halliburton truck, displaced in 15 mins. using rig pumps. Average slurry weight ll6~. Bumped plug with 1750 Psi. Full circulation. Cement in place at 5:30 AM, 6-18-61 CASING DETAIL: 49 joints or 2,014.94' K.B. to top casing 17.00' Casing cemented at 2,031.94' Equipped with Baker guide shoe and flexi- flow float collar. 2, 032' Installed BOPE. Tested CS0, pipe rams, hydril, and Kelly Cock with 1500 psi 15 rains. - Held OK. 851 - 2, 045' 186' drilled 87 pcf mud COMPLETION REPORT SWANSON RIVER UNIT 43-28 SECTION 28, T. 8 N., R. 9 W.~...SEWARD B & M STANDARD OIL CO. OF CALIFOt~3%, W.O.I. - OPERATOR Page 4. June 19 - July 5, 1961 Drilled 9 7/8" hole 2~045 - 9, 242' Drilled 9 7/8" hole 9,242 - 9,359' Had significant water entry at 9,312' 7,197 ' drilled 117' drilled Built up mud weight to 96.5 pcf. interval 9,356 - 2,030', 7, Drilled 9 7/8" hole 9, 359 - 9,594' 71 - 95 pcf Mud volume increased 100 bbls. 95 - 96.5 pcf mud Baroid Mud Logger Unit started 12: 01, 7-8-61, logged from 9,590'. Drilled 9 7/8" hole 9,594 - 9,749' 155' drilled 96 pcf mud July 9 -,, !4, l?6,1 Drilled 9 7/8" hole 9,749 - 10,810' 1,071' drilled 96.5 - 97 pcf mud July 15· 1961 Drilled 9 7/8" hole lO, 810 - 10,875' T.D. 65' drilled 97 pcf mud Ran Schlumberger Induction Electrical Log: interval 10,875 - 9, 356'. Ran Continuous Dipmeter, interval 9,000 - 2,032'. Ran Microlog w/Caliper, interval 10~875 - 9~840' and 6,510 - 4,990'. 96.5 - 97 pcf mud 235' drilled Ran Schlumberger Induction Electrical Log Sonic Log, interval 9, 340 - 2,030' · COMPIETION REPORT SWANSON RTVER UNIT 43-28 ~C TI ON ~8 , r$ 8 ~N~ ~, ~ $ 9 w $1~ sE~~ B · ~ STANDARD OIL cb. OF CALIFORNIA, W.O.I. - OPERATOR Page 5. Reran bit and conditioned mud to run Sonic Log and Dipmeter below 9,000'. Attempted to run Dipmeter, stopped at 9,540'. Ran 9 7/8" bit with 8 3/4" Driltrol 860' above bit. Ran to bottom and conditioned mud. Ran Dipmeter interval. 10,875- 9, 000', Sonic Log 10, 515 - 9,340' , could not get to bottom. Reran~t to bottom and conditioned mud for 7" casing. Lsid down 4½" D.P. and drill collars. July 18.~ 1961 Ran 7" casing and cemented at 10,875' as follows: CEMENTING DETAIL: Cemented 7" casing at 10,875' in two stages with 1800 sacks of cement treated with O. ~ HR-4 using Halliburton power equipment. Used one top and one bottom rubber plug. 1st Stage around shoe with 600 sacks of cement. Pumped 60 bbls. of water ahead, mixed 600 sacks of cement in 30 mins. using Halliburton truck, dis- placed in 42m ins. using rig pumps. Average slurry weight ll6~. Bumped plug with 2000 psi. Full circulation. 2nd Stage through DV at 7,100'. Dropped DV bomb, opened DV ports in 30 mins. Pumped 40 bbls. of water ahead, mixed 1200 sacks of cement in 60 mins. using Halliburton truck, displaced in 28 mins. using rig pumps. Average slurry weight ll6~. Closed DV ports with 2500 psi. Full circulation. Cement in place at 2:15 PM. Hookload weight of casing before cementing w~s 220,000, after cementing before landing casing 190,000, at time of landing casing 200,000. Reciperacated casing while conditioning mud and first stage of cementing. Put Hydrozi~e mhea& of both cementing jobs. Good circulation. CASING DETAIL Con~i. nued~ on next page COMPLETION REPORT SWANSON RIVER UNIT 43-28 ~SECTI0~ 28,~ T. 8 N., .R....9 W,, SEWA~O B & M STANDARD 0IL CO. OF CALiFORNIA, W.O.I. - OPERATOR Page 6. July 18, 1961 Continued CASING DETAIL: 6 joints or 15 Joints or 88 joints or 9 joints or 34 joints or 15 joints or 258.12' 7", 29¢, N-80 6~6.35' 7", 26~, N-80 3, 736.63' 7", 23~, N-80 387.44' 7", 29~, N-80 1, 456.o9' 7", 26~, N-8o 644.74' 7", 2~, N-80 7,129.37' 1 DV Collar 28 joints or 2.oo, (~7, ll6' ~.~.) :!,199.05.' 7", 29~, N-80 8, 330.42' 1 X-over joint 54 joints or 6.82' 2,232.~9' 7", ~9~/, 8 rd, P-ll0 10, 569.53' 1 Marker Joint 14.05' 7 joints or 306.50' Total 258 joints or io,89b.o8' Above K · B. 15.08 ' Casing landed ~ 10,875.00' Tested tubing head with 300o~ psi in 30 mins. and blind rams in 15 rains. - OK. 95 pcf mud Picked up 2 7/8" tubing. Drilled out DV Collar and cleaned out cement from 10,752 - lO, 790'. Ran Neutron Collar Log, interval 10,789 - 9, 000'. Tested DV Collar with 2000~ psi. Held OK. Tested BOPE with 2000~ psi. Held OK. Shot 5 ½" holes at 10,615' for WSO Test 93 pcf mud Tool Assembly: 2 outside BT recorders, 4' of 2 7/8" perf'd, tail pipe, 7" Type "C" Hookwall Packer, VR safety joint, hydraulic Jars, 2 inside BT re- corders~ hydrospring testers and TC valve. Used 2,655' of W.C. Ran on 10,547' of 2 7/8" EUE tubing. CO~.F. TION REPORT SWANSON RIVER UNIT 43-28 SECTION 28, T. 8 N., R. 9 W., SE%.$YRD B & M STANDARD 0IL 'CO. OF CA'L~0RE~' W. 0 jI '. OPERATOR Page 7. July 20,;, 1961~ Continued Set packer at 10,566' with 17' of tail to 10, 583'. Opened tool to surface at 5:19 PM for 61 min. flow test. Immediate faint blow to dead in 1R rains. (5:31 PM) Dead throughout remainder of flow test. Shut in tool at 6:20 PM for 31 rains. FSI pressure. Pulled packer loose at 6:51 PM. Recovered 20' net rise, all drilling fluid. PRESSURE DATA' IH IF FF FSI FH Top Inside 6972 IR08 1208 1214 6972 Bottom Inside 6972 1180 1180 1187 6972 Top Outside 7082 1Rl~ 1212 IR20 7082 Bottom Outside 6991 1186 1186 llgl 6991 Charts indicate tool open. Tool might not have clo. sed for FSI indicated by slight build-up on charts. WSO - OK. shot 4 ½" holes/ft., interval 10,752 - 10,754' for WSO Test july, 21,, 196l Ran WSO Test ~2 on 5 ½" holes at 10,752 - 10,754'. Tool Assembly: 2 outside BT recorders, 4' of 2 7/8" perf'd, tail pipe, 7" Type "C" Hookwall packer, VR safety joint, hydraulic Jars, 2 inside BT recorders, hydrospring tester and TC valve. Used 2845' of W.C. Ran on 10,674' of 2 7/8" EUE tubing. Set packer at 10,693' with 17' of tail to 10,710'. No ISI pressure. Opened tool to surface at 7:41 A~ for 120 min. flow test. Immediate very faint blow to dead in 14 mins. (7:55)- Opened by-pass at 8:27 to wash perforations. Reopened tool to surface at 8: 37- Puff blow and dead. Shut in tool at 9:41 A~ for 30 min. FSI pressure. Pulled packer loose at lO:ll A~. Recovered 40' net rise, all drilling fluid. PRESSURE DATA: IH IF FF FSI FH Top Inside 7015 1290 1307 2309 7015 Bottom Inside 7007 1272 1288 2280 7007 Top Outside 7107 1301 1320 2338 7096 Bottom Outside 7018 IR75 IRgO 2301 7018 Charts indicate tool open. WSO - OK. Ran Schlumberger Cement Bond Log, interval 10,780 - 3, 000'. Ran carrier per- foration gun and perf'd, over following intervals with 4 ½" holes/ft.: 10,752- 10,66~'; 10,656- 10,642'; 10,631- 10,617'. COMPLETION REPORT SWANSON RIVER UNIT 43-28 SECTIO T...S.. SSWA a STANDA~ OIL CO. OF CALIFORNIA, W.O.I. - OPERATOR Page 8. Ran 2 7/8" tubing: TUBING DETAIL.: 339 joints 2 7/8" tubing = 10,705' i Pup Joint K.B. above tubing head 15' Tubing hung at ~' Installed X-mas tree and tested with 3800~ psi. Held OK. JulY ~2, 1961 Changed over from mud to Swanson River Unit crude oil. Flow tested well: COMPLETION DETAIL: Pumped 50 bbls. of water ahead, followed by 410 bbls. of crude oil. Stopped circulating at 1:30. Formation oil to surface at 2 PM. Started flowing to trap at 2 PM. Representative flow rate and cuts as follows: Flow Rates· Bean Tubing Casing Trap Flow Period 0il Gas Size Press. Press. Press. 1. 1 hr. 1395 B/D 235 MCF/D 16/.64 1030 810 60 2. ½ hr. 480 B/D 88 MCF/D 9/64 1400 1100 60 ~ Total Cut ~ Water ~ Emulsion ~ Sand & Mud Corr. 1. 1.2 0.6 -- 0.6 31.7 2. 0.6 0.3 0.3 0.0 35.3 Shut well in at 5 PM. Shut in pressures; tubing pressure 1575 psi~ casing pressure 1300 psi. Produced estimated 100 bbls. formation oil. Flowed 161 barrels to tank and estimated 0 barrels to sump. Installed Cosasco plug. Rig Re~easecl 7 PM, 7/~2/61. S .~~NSEN COMPLETION REPORT sm~so~ Rr~ u~ ~3-~ S~5~ OIL CO. OF CA~F0~, W.O.I. - OPE~TOR Page DEVIATION DATA Depth 500 ' 2,045 ' 3,700 ' 4, 565 ' 5,644 ' 8,277' Degrees 0° 30' 0° 30' 0° $5' 0° 15' 1° 15' 0° 0° PRODUCING DEPARTMENT TELEPHONE BRo 7--6201 C. V. CHATTERTON DISTRICT SUPERINTENDENT P. O. BOX 7-839 · ANCHORAGE · ALASKA October 27, 1961 CONFIDENTIAL Mr. D. D. Bruce State Department of Natural Resources Division of Mines & Minerals 929 Second Avenue Anchorage~ Alaska Dear Sir: Enclosed, herewith~ are the Completion Reports for Soldotna Creek Unit Well 21-9 and Swanson River Unit Well 4~-28 for your information and files. Very truly yours~ C. V. CHATTERTON Enclosures RECE'IVED AUG 22 196'1 UNITED SI'ATES DEPARTMENT Of THE INTERIOR gEOLOG!CAL SURVEY Budget Bureau No, 42-R350.5. Approval expires 12-31-60. L^ND OFFicE ..... Ancho?age ......... U,,T ............. _S__w.a._n__s_ p_ D__ ~.i_ v..~_r..__ Oil & Gas Section r~;,,isio,-- ~LMino~ and Minerals iI~7~~MO/~THLY REPORT OF OPERATIONS '/ State ...._A__l__{~-_k-a-_ .............. County __K__e__~__a__$__?_9__~___~_.~a_ ..... FZeld ............ $_w____a~_fi__o._~..~.~._~r ............................. 7'h,e followinrJ is a correct report of opcratioT~s a~d prod~etio'n (ineludin~ drillin.~ and pro(l~cin~ zoells) ]br the ~o~z,t'l, o,f ................ ~Y ........................ i,~.]. ........... _~_~_~P~_ _Ri~_r_.~ ............................... .g~eT~g', addres.~ ___P'..P,._B°~___7_,.8~7 ........................................ Com.a,..tST~.~.~ OIL CO. OF CALIFO~A "A hera la ska ~ ~ ':' Wes~~~~~~n~ ~g O~_ J'4 t I ' I } ]~I,1('O~ :~'() D [ ,,~.Iv. SO ftuto) ,l~;e ami r,.~ulteontent ''f of ~' Stgas)for , ........................................................................... . ....................... ] $.m 43-28 (21) I 28 8N ~ Drilled 9 7/8" hole 8277~ - 9359'0 H~ im lo~; 9356~ - ~03o~ ~d Sohio 169 9340' - 2o30~, Drilled 9 7/8" b;ole 9359~ - 10875~ T.D. NE~ Bakoid ~d-logger IUnig egarted at 9590~o !8~n I~ Lo~ 10,875~ - SEt 91~O'. Diameter ~OO0~ - 2032~0 ~cro Lo,~ 10,875' - 9800', and 6500' - 5000'. Condition,d hol~. H~ Dipneter, s~on:~ed ~ 9540~. 94~2~ -~9746'. Ran to bottom ~d e~nd. m~. H~ Dip~er 10,875' - 9000'. ~R~ Sonic iLog 10,5!5~ - 9340'o Smie tool wmld not go to bo[tom. ~ R~n and qenentgd 7" ca~g at 10,775~ in 2 ~tage,, 600 sacks ~b~d Shoe, 1200 ,saeks~rough DV Ooll~r ~t 71OO~o Ran Neutron ~o~1~ Log 9000' 4 1078P*. ~stab!ished ¥~0 ~ !O,615~. ~ mO BOP0'. Srerforated forbroductionl,ath h ~?' holes/foot over inbervai,: 107~2~- lO~6h', 106~' - 106h2~, and 10631' - R~ md~l~ded 2 ~/8" tgbi~ a 10~2'. I~stalled Sm tested tr~eo ~low teste4 we!l;. Iieor~e~tivo fl~ e~te:139~ B/D oil, a~ ~/~ cas, i~/6a,, bb~z, io3o~i'.?., 8ip~ c~c. ~ress. $~ trap ore~s~eo Total dui i.P%, 0.6{ w~zter. 0 kauisio~, 0.6~ S & ~. ~ ~Aska 0 & O CC ~ ~D. - C. W. ~erry R. R, Ritter Ohio Oil Co. - Gee ge So~mrd~ Union Oil Co~ - C.~ E. Smith · File~: Prod~c~g ~ ~pldratioh , NoTE.---There were ...................................... run. s or sales of oil; ............................................... M cu. ft. of gas sold; .............................................. runs or salcs of gasoline during the month. (Write "no" where applicr~ble.) NoTE.--l%eport on this form is required for each calendar month, regardless of the siatus cf operations, and muM; be flied in duplicate with ¢he supervisor by the B-th of thc succeeding month, unless otherwise direc~,cd by thc supervisor. ~orm 9-329 1fi---2570§-8 u. S GOV£RN~NT P.IN?ING OFFICE' (January 1950) Budget Bureau No. 42-11356.5. Approval expires 11-31~. JUL 28 19:ill UNITED STATES ~,o omcE ___Anchorage DEPARTMENT OF THE INTERIOR U~ASE NU~,B~,.[i,,',028399~ Oil & G:~s Section GEOLOGICAL SURVEY UNIT ........ S~O~._~a~ ........ Division of Niine~ and Min~s of MONTHLY REPORT OF OPERATIONS State ......... A'_l,~ki ............. County l{_(tli_Si_.P_.elliIl~_lL~_$ ...... F~eld ............. ~_w_..aD..$.o..o.._R..~.y__e._r ........................... '_/'he followin~ is a correct report of operations and production (incl~din~ drillin~ and prod~cin~ wells) ~or tl~c mo~z~k of J~e ~961 Sw~son River U~t ........................................... ~ t ....... ~ ............................................................................. d~en,~' ~ addres, .......... P.__0,..BOX_~,839 ............................. ~om pa.,~/ STA~A~__OIL.CO. ........................................... ~Ch~age, _Alaska .................... S~ncd ....._ _ ..-- z...~~_ ~es-ter?--~s '~ ' ~nc-"Z--,. 28 ~ 8N~ ~J SDudde~ J~e 16..iD~ill~ 16 ho~ 0 - Sgnic nbgs~ Oeme~%ed n-3/h" ~ ~o32' w/1290 sackso NE~ ~d %es~ed BOPEo 'iDPilled 10-~/8" hole 20~I - 3700'. 9-7/8" 8~ hdle 3?DO~ - 827?'. - ,, c¢~ U.$.GoS. - M~r~r~n H'~ Soyster (2) Alaska 0 & G,ICC -ID. D~' Brucb ! 1 R.R. ait ter O~io Oil Co.I - GeOrge Sowar~ U~ion Oil Cok - C~ Eo 'Smith Files: Pr ~cing[ ~ E~l~r'ati~n 1 NoTE.--There were ' run. s or sales of oil; ............................................... M cu. ft. of gas sold; ............................................. runs or sales of gasoline during the month. (Write "no" where applicable.) NoT~.--Report on this form is required for each calendar month, regardless of the status of opera,ions, and must be filed in duplicate with the supervisor by the 6th of the succeeding month, unless otherwise directed by thc supervisor. Forrrt 9-329 (January 1950) lC,--25766-$ u.s. t (SUIt3IIT IN: 'TRIPI.ICATE) UNITED STATEk$ DEPARTMENT OF THE INTERIOR GEOLOGICAL -c.U fq V i'-'~Y SUNDRY NOTICES AND REPORTS ON WELLS ' · rt~ . [], OR 01 ~ ft'r [)ARA ! WORK lo 3. 5. 6. to ~00', log ~tl cmn~ 11 ~f,~" ct~ll~, to ~trfa~e. X~etall a~d test requisite ~.'~ter, shat-offs. Well previously e~prove~ b~ U.$.G.8., Febr~axT 17, 1961. ~ats no'~ee s~-I~tted per U.$.G.S. 90 day approval ex~lratioa ef ort~L~aX ~otiee. B~ ~ ~ 0~' e, ALI~, ~otera Oper~tio!~s, ll~e, ........ P. 0, ~x 7-8:D Tit!e D~.etrte~.~ Ulql~ STATE~ ~ARTMENT OF' ~ INTLrlqlOR SUNDRY NOTICES AND REPORTS ON WELI~ DETAIi~ OF WORK to ~', :Log ~md ~lmeu~ il ~" ~~. l~~ ~ test =~ss III Bio.ut p~ntton ~~~. ~~~ Jet ~e~+~ att~cti~ ~ ~d ~st ~ ~ce~sa~. 7/8" ~b~ ~ ~~. FEB 18 GPO e 6~040 APPLICATION FOR PERMIT TO DRILL, DEEPEN OR PLUG BACK APPLICATION TO DFULi~ [~ DEEPEN' [] PLUG BACK [] NAME OF COMPANY OR OPERATOR S'~%RD 0IL CG~ OF CAI~FORNIA~ Address C~ty DESCRIPTION OF %VELL AND LEASE DATE ~ebruary 14, 19ol State Name of lease J ',Veil number Elevation (ground) s~anson River l~nit oRU 43-28 (19) 170' %Veil location (~ive footage from section lines) Section~township~ran~'e or block & survey A~mx. ~' N ~ ~' W ~ ~ ~es f~o~ Sg ~r~r Pm3. See. ~ T. g ~I., R. 9 W.~ Field & reservoir (If wildcat, so state) J County _ 5,~n ~r ~eld H~ock Re~olr ............ ~e~ Pe~ul~ .... Distance, in miles, and direction from nearest town or post office Nearest distance from proposed location Distance from proposed location to nearest drilling, to property or lease Hue: comDIeted or applied~for well on the same lease: g~,xi~~ ~ f~t A~'xltm~ly 2850 Proposed depth'. Rot4try or cable tools ll~O00' P~ota_r'y Approx. date work will start ~ar~ 20, l~l Number of acres in lease: Number of wells on lease, including this well, completed in or drilling to this reservoir: If lease, purchased with one or more wells drilled, from whom purchased: Name Address Status of bond No~ ~qut:eed. Remarks: (If this is an application to deepen or plug back, briefly describe work to be done, giving present producing zone and expected new producing zone) CERTIFICATE: I, the undersigned, state that I am the ~ m~-~- of the , [{~t~,.~?',t:% (~*~Z'~}g&iO~ Xlle, (company), and that I am authorized by said company to make this report; and that this report ~vas pre- pared under my supervision and direction and that the facts sta~;ed therein are true, correct and complete to the best of my' knowleclge. ~ T, CROOKER Approval Date Approved By: Notice: Bef-~o J~ J~'~ i~&-~ ~ci given all ~ . :. . . y correspond- enc~. ; ', '.. ' See Inst/a~l~6h~Zev~i's~ ~-' {: "i~kt~,'~'~ t~rces~ Signature Jo T. OIRO~R Alaska Oil and Gas Conservation Commission Application to Drill, Deepen or Plug Back Form No. P-1 Authorized by Order No. I Effective October 1, 1958
