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Home My WebLink About204-183Regg, James B (CED) " t) GUy From: Henspeter, Mark A (DNR) n Sent: Tuesday, November 12, 2019 4:54 PM To: Regg, James B (CED) Cc: Laubenstein, Lou (CED) Subject: Threemile Creek DR&R aerial images Attachments: TMC3_reduced.jpg; TMC2_reducedjpg; TMC1_reducedjpg Hi Jim, Attached are three images from the Threemile Creek pads numbers 1, 2, and 3. These images were captured on October 24, 2019 as part of the Division of Oil & Gas Plan of Ops closure inspection. The final report for the inspection should be available on Friday. These attached images are a reduced file size so they can be inserted into a report for distribution. I am sending over the full -resolution images (as well as two oblique images) through our file transfer application. Please let me know if you need any other information. Hope that helps, -Mark Henspeter �s�chwl ��-- Natural Resource Specialist Division of Oil & Gas Permitting Section Phone: 907.269.8812 mark. henspeter@a laska.gov MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg ��(l lfit ii 1 DATE: 10/25/19 P. I. Supervisor FROM: Lou Laubenstein SUBJECT: Final Location Inspection Petroleum Inspector Three Mile Creek 1, 2 and 3 Cook Inlet Energy PTD 2041830, 2051430, 2110710 10/24/19: 1 traveled to Beluga for 3 final location inspections on the Three Mile Creek wells. Alaska Department of Natural Resources representative Mark Henspeter was also on location for these location inspections and used a drone to capture aerial images of each wellsite. There were no Cook Inlet Energy representatives on location at the time of these inspections. Three Mile Creek #1 (PTD 2041830) -' The location was clear of any signs of oil field equipment or debris, no visible leakage or spills could be seen on or off the pad. A large mound of dirt in the middle of the pad marks where the well was. Three Mile Creek #2 (PTD 2051430) The location was clear of any signs of oil field equipment or debris, no visible leakage or spills could be seen on or off the pad. A large mound of dirt in the middle of the pad marks where the well was. Three Mile Creek #3 (PTD 2110710) The location was clear of any signs of oil field equipment or debris, no visible leakage or spills could be seen on or off the pad. A large mound of dirt in the middle of the pad marks where the well was. Attachments: Photos (6) 2019-1024_Locatlon Tlhree Mile Creek 11.docx Page 1 of 4 a WT 01, STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. WeII Status: Oil ❑ Gas❑ SPLUG ❑ Other ❑ Abandoned ❑� • Suspended❑ 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAG[] WDSPL ❑ No. of Completions: 1b. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Cook Inlet Energy, LLC (a Glacier Oil & Gas Corp/Successor in interest to Forest Oil Corp) 6. Date Comp., Susp., or Aband.:- 6/18/2019 14. Permit to Drill Number / Sundry: . 204-183 ($ - 4 � 3. Address: 188 W. Northern Lights Blvd, Suite 510, Anchorage, AK, 99503 7. Date Spudded: 12/3/2004 15. API Numb r: 50-283-20108-00-00 4a. Location of Well (Governmental Section): Surface: 1504' FNL, 148' FWL, Sec. 35, T13N, R11 W SM Top of Productive Interval: 1420' FNL, 646' FEL, Sec. 34, T13N, R11 W SM Total Depth: 1540' FNL, 687' FEL, Sec. 34, T13N, R11 W SM 8. Date TD Reached: 12!21/2004 16. Well Name and Number: Three Mile Creek #1 ' 9. Ref Elevations: KB: 311' ' GL: 288' • BF: 17. Field / Pool(s): Three Mile Creek Field - Beluga Gas Pool 10. Plug Back Depth MD/TVD: • 5410' MD / 5243' TVD 18. Property Designation:" ADL 388233 • 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 286393.49 y- 2624191.03 Zone- 4 TPI: x- 285825.54 y- 2624413.82 Zone- 4 Total Depth: x- 285558.82 y- 2624170.42 Zone- 4 11. Total Depth MDfrVD: . 8180' MD / 8010' TVD 19. DNR Approval Number: N/A 12. SSSV Depth MD1TVD: N/A 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: Yes LJ (attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: 1 N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, 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 JUN 2 0 2010 AO 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE CASING FT SETTING DEPTH MD SETTING DEPTH TVD AMOUNT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 13-3/8" 48# H40 Surface 110' Surface 110' Driven N/A N/A 9-5/8" 40# K-55 Surface 2438' Surface 2327' 12 1/4" 254 bbls 14.5# G to surf. None 7" 26# N-80 Surface 8113' Surface 7943.6' 8 1/2" 1st: 189 bbls 13.5# G, 2nd: None 135 bbls 13.5# G 24. Open to production or injection? Yes ❑ No Q If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): cokoo Sl 6 ATE VRIF /ED 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 3-1/2" 3507' 2502'MD/2387'TVD 3455'MD/3303'TVD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes LJ No Per 20 AAC 25.283 (1)(2) attach electronic and printed information DEPTH INTERVAL (MD) 1AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: N/A Method of Operation (Flowing, gas lift, etc.): Date of Test: Hours Tested: Production for Test Period � Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Casinp Press: Calculated 24 -Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity- API (torr): RBDMSfWJ1JN 2 12019 /��'•%i v CJ 28. CORE DATA Conventional Corals): Yes ❑ No ❑ Sidewall Cores: Yes ❑ No ❑ 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. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑ If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval information, including reports, per 20 AAC 25.071. Formation at total depth: 31. List of Attachments: Wellbore schematic, Daily summaries, photos of abandonment. 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. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Stephen Ratcliff Contact Name: Stephen Ratcliff Authorized Title: VP of Drilling Contact Email: sratcliff@glacieroil.com Authorized Contact Phone: 907433-3808 Signature: Date: '20 9 INSTRUCTIONS General: 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 10407 well completion report and 10404 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. Item 1a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water-Altemating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: 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. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: 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. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: 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. Item 30: 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. 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. Form 10407 Revised 5/2017 Submit ORIGINAL Only GLACIER June 20'h, 2019 Jessie Chmielowski, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7s' Ave., Suite 100 Anchorage, Alaska 99501 Re: Well Completion Cook Inlet Energy, LLC: Three Mile Creek #1 JUN 2 U 20aq Permit to Drill NO: 204-183 API No: 50-283-20108-00-00 A Dear Commissioner, Cook Inlet Energy (CIE) hereby submits a Well Completion Report for the abandonment of Three Mile Creek #1. The work performed was covered under Approved Sundry 318-477. CIE requests the official status of Three Mile Creek #1 be changed to P&A. If you have any questions, please contact me at (907) 433-3808. Sincerely, Stephen Ratcliff Vice President — Drilling Cook Inlet Energy, LLC (a Glacier Oil & Gas Corp. owned company) 188 W. Northern Lights Blvd, Suite 510 Anchorage, AK 99503 10-407 Three Mile Creek #1 Daily Operations Summary API: 50-283-20108-00-00 PTD#:204-183 Date Activity 11 May 2019 RU hot oil truck. Fluid pack velocity string. Test velocity string against BST plug to 2000 psi for 15 minutes and chart same — good. Swap to VS x tubing IA = 1100 psi. Bullhead 95 bbls of water at 2.5 bpm, 1200 psi. Monitor well. Pressure decreased to 420 psi. RD hot oil truck. Secure well. Move in Coil tubing equipment. 12 May 2019 Continue RU coil tubing equipment. Remove well house. 13 May 2019 R/U Coil Unit and prep for BOPE Test. Coil Tubing Pressure at 0 psi and Coil by Tubing Annulus at 490 PSI. Test Coil BOPE at 250 psi low and 2,500 psi high and chart. Test witnessed by AOGCC Inspector Austin McLeod. Rig down test equipment and prep to kill IA. Mix and bullhead 110 bbls of 8.6 ppg brine down IA. Check pressure. Pressure dropped to 350 psi. 14 May 2019 Prep to mix and pump kill weight fluid. Mix and pump 60 bbls of 10.1 ppg brine. Bullhead down IA at 2.5 BPM. Stop pumps and monitor well. IA at 0 psi. R/U CTU and M/U Baker fishing latch tool. Test lubricator. Engage hanger and POH. Cut off latch tool and hangar and M/U coil connector. POH with coil string on reel. R/D CTU. 15 May 2019 R/D and Demob CTU. R/U slickline and test lubricator. RIH with 2.813" gauge ring to 3,425' SLM. RIH with shifting tool and confirm sleeve is closed at 3,405' and 2,799'. POH to 2,458' and shift sleeve open. Observe IA and tubing equalize. Change over to E -Line. RIH and set CIBP at 2,480' ELM. POH and R/D E -Line. R/U Hot oil pump on tree and perform Tubing -IA bundle pre-test to 1,500 psi for 30 minutes on chart. Good test. Pi'� 16 May 2019 R/U Hot oil pump and fluid pack tubing and annulus in preparation for state witnessed MIT Test. Perform MIT bundle test to 1,500 psi for 30 minutes, good test. Test witnessed by AOGCC Inspector Lou Laubenstein. R/U SLB Cementers and P -Test lines. Establish circulation and pump 98 bbls of 13.5 ppg Class G Cement — 323 sacks at 1.71 cubic ft/sack. CIP at 16:50. R/D and release SLB Cementers. 2 1 P a g e 17 May 2019 R/D Equipment and complete load out of SLB. Clean out cellar box. Excavate around well and prep for welder. Cut wellhead and tree from casing stub and dress off casing 6' below original ground level. R/U cement mixer and chute for top job. Mix and pour 31 sacks of 80 \ Ib. sack-crete. Wait on additional cement to complete top job. 18 May 2019 \ . Prep for top job with additional cement. Observed well percolating in Q_ the 9- OA. Prep for plan forward while WOO from town to 7 discuss with AOGCC. Complete top lob. Locate and mobilize 9-5/8" wellhead from Vetco to location. Assemble, install, and weld 9-5/8" ®P casing head and dry hole tree. Shut in tree and prep for wellhead test. _ a� LX 19 May 2019 Wellhead pressure built to 240 psi at 0500. Pressure test between lower seal and weld to 1,000 psi for 10 minutes, good test. Test above�� seal and casing head body and valve to 2,000 psi. Unable to pressure test past 280 psi with no visible leaks. R/D Test equipment and secure well while waiting on cementing plan forward. Demob and load out surface equipment on pad. Check wellhead pressure at 440 psi at 1700. Secure well for night and monitor wellhead pressure. 20 May 2019 Monitor wellhead pressure at 0600 = 600 psi. Clear location of equipment, demob, and grade pad. Wellhead pressure at 1300 = 640 psi. Wellhead pressure at 1900 = 660 psi. 21 May 2019 Monitor wellhead pressure. Wellhead pressure at 0700 = 700 psi. Prep for cementers to perform injection test. Well pressure at 1930 = 750 psi. R/U cementers. Bleed off pressure to open top tank with AOGCC witness Adam Earl. Pressure bled to zero psi in 10 seconds with no fluid. Perform injection test. Pressured up to 1,000 psi. Shut in for 5 minutes and monitor bleed off. Pressure dropped to 780 psi in 5 minutes. Pressure up to 1,024 psi, shut in and bleed off to 844 psi in 5 minutes. Pressure up to 1,011 psi and drop to 914 psi. Pressure up to 1,100 psi and drop to 843 psi. Shut in and discuss results with AOGCC and engineers. Total volume pumped = 1/10 bbl. R/D SLB cementers. Prep to open well to open top tank and perform bubble test while monitoring results through the night. Wellhead pressure at 725 psi. Open well and bleed off to 0 psi in 5 minutes. Record and monitor results. 22 May 2019 Monitor wellhead pressure. Bleed off pressure. Open well through 2" HP hose to water filled open top tank for bubble test while monitoring every 2 hours. R/D 2" HP hose, install tree cap and gauge. Monitor wellhead pressure. 16:00 = 20 psi, 16:30 = 80 psi, 17:00 = 150 psi, 3 1 P a g e 17:30 = 200 psi, 18:00 = 240 psi, 18:30 = 260 psi, 19:00 = 280 psi, 19:30 = 300 psi, 20:00 = 320 psi, 20:30 = 330 psi, 21:00 = 350 psi. 23 May 2019 Monitor well. Wellhead pressure at 560 psi. Bleed off pressure through 2" HP hose to water filled open top tank. Pressure bleeds off in 3 seconds. Shut in well. Monitor, wellhead pressure at 310 psi in 2 hours. Bleed off pressure through 2" HP hose to water filled open top tank. Monitor well. 24 May 2019 Monitor well. Monitor bleed off of pressure through 2" HP hose to water filled open top tank. Monitor well. 25 May 2019 Monitor well. Monitor bleed off of pressure through 2" HP hose to water filled open top tank. Monitor well. 26 May 2019 Monitor well. Monitor bleed off of pressure through 2" HP hose to water filled open top tank. Monitor well. 27 May 2019 Monitor well. Monitor bleed off of pressure through 2" HP hose to water filled open top tank. Monitor well. 28 May 2019 Monitor well. Shut in well at 08:00 and monitor build up. 08:00 = 0 psi, 09:00 = 125 psi, 10:00 = 210 psi, 11:00 = 250 psi, 12:00 = 300 psi, 13:00 = 325 psi, 14:00 = 350 psi, 15:00 = 380 psi, 16:00 = 420 psi, 17:00 = 440 psi, 18:00 = 450 psi. Continue to monitor well. 29 May 2019 Monitor well. Continue shut in. 06:30 = 610 psi, 15:00 = 710 psi. Well stabilized. 18:00 = 710 psi. Continue to monitor well. 30 May 2019 Monitor well. WHP = 710 psi. Rig up flow meter and open well to meter. Pressure bled to zero in less than 1 minute. Monitor flow at less than 1 SCFH 31 May 2019 Monitor flow rate at less than 1 SCFH and 0 psi. 01 June 2019 Monitor flow rate at less than 1 SCFH. Flow very low and not measurable on meter. 02 June 2019 Monitor flow rate at less than 1 SCFH. Flow not measurable on meter. 03 June 2019 Monitor flow rate at less than 1 SCFH. Flow not measurable on meter. 04 June 2019 Monitor flow rate at less than 1 SCFH. Flow not measurable on meter. 41P�i�-e Receive approval from AOGCC, Guy Schwartz, to move forward with P&A plan. Excavate around well to approximately 10ft below original ground level. 05 June 2019 Monitor flow rate at less than 1 SCFH. Flow not measurable on meter. Complete excavation around well. Cut off wellhead at 8' below original ground level. Clean out cement between casings. Cut 7" casing and 3- 1/2" tubing 3" below stub. Cement in annuli witnessed by AOGCC Rep, r Austin McLeod. Weld 1" plate inside 9-5/8" casing down 3". Install bull plug in plate. Weld 5ft of 9-5/8" casing on to casing stub. Install swage and test to 1000 psi for 30 mins—troubleshoot issues with chart recorder and pump. 06 June 2019 Source new pump and chart recorder. R/U same. Test 9-5/8" casing stub and weld plate to 1000 psi for 30 mins, chart same — good test. Test witnessed by AOGCC Rep, Austin McLeod. R/D test equipment. Cut 9-5/8 casing stub 3' below original ground level. Fill casing with cement. 07 June 2019 Observe hard cement in 9-5/8" casing stub. Hard cement witnessed by AOGCC Rep, Austin McLeod, and verified P&A marker plate details. Authorization granted to weld marker plate on TMC -1. Weld marker plate in place on 9-5/8" casing. Well stub to be left uncovered for 7 days per AOGCC, Guy Schwartz. 17 June 2019 Waiting period complete. TMC 1 checked for hydrocarbon gasses in the wellhead area — none detected. Authorization to backfill approved by AOGCC Rep, Guy Schwartz. 18 June 2019 Back fill with dirt. Mound dirt over well. P&A Complete. 51Page ._Aurora Gas, LLC Circulate 98 bbls 1323 a Class G cement (13.5 ppg, 171 cf-sk) rims Sliding Sleeve at 2458' to surface and fr➢ both tubing and ar mdus- 3-12" CIBP at Upper Completion: Beluga peels at: 2570-94',2726-50'. 2948,1','_980-88', 3062-S" 315"2'.3170-78', 3302-17' Lower Completion Beluga Perfs: (original) 3530'- 3544', 3556'- 3566', 3662'- 3672', 36V- 3703' Added in 2011: 3728-38'. 1812-2V (Original) 4505'- 4.53F& 4576'- 4606' .Added in 2011': 4786-96'. 4874-78', 4884-94', 496'_-72' Beluga perforated 5606' - 5616 ,5668' -5698', 57,10' -5720'. (5439'-5553' TSD) Zone Tested, tigby trace gas, no water produced. Abandoned Upper Tyonek perforated at 7750' - 7779' MD (581' 7610' TSD). Zone Tested wet w! no gas. Chlorides 14,000 ppm ?Abandoned Three Mile Creek Unit No. 1 Final P&A Configuration As of 6/18/2019 ' 13 318" 489 H-40 conductor driven to 110 ft minimum 31}2" 9.38, 8rd ELT: tubing Cap = 0.0087 bbllft 11 TOC Iagged at 5410' Displaced 6.15 bbls "G' car 1 CaCI 7" CIBP set at - 5560' TOC Tagged at 75--4' Displaced 6.14 bbls "G" on top of retuwr 7" Retainer set at 7700' on 06 -Jan -05 to isolate Tyrona- perfs and was pressure tested to 3000 psi 7" 26k BTC N -W to 8113' \ff) (7944'111)) PBTD at Baffle Plate 8070' 9fD. 1" stage cemented W 189 bbls 13.5 ppg gas bloc}: type cement around shoe - 6lPage r 12114" bole directionally drilled to 2440' IIID (12329' TCD). 9 518" 40 -" - BTC K-55 Casing to 2438' ---_.� (Cemented with 254 bbls 14.5 ppg Gas- s Blocb cement slurry system to surface.) R HES iD SSD Sliding sleeves installed at 2458' (annulus), 2799', III t and 3405'. T' Halliburton PHIL hydraulic set retrievable production packrrs set at 250'_' and 345E wlmbing tail i II • l -tipple at 3498' (open) and 11T- entre grade below. a•� d Halhbmtm ES Cementer Stage collar installed in 7" casing at 3857'. Casing cemented in 2 stages_ Stage 2 - 135 a)r. bbls. 13-5 ppg gas -block cement - pumped with returns to surface. 11 TOC Iagged at 5410' Displaced 6.15 bbls "G' car 1 CaCI 7" CIBP set at - 5560' TOC Tagged at 75--4' Displaced 6.14 bbls "G" on top of retuwr 7" Retainer set at 7700' on 06 -Jan -05 to isolate Tyrona- perfs and was pressure tested to 3000 psi 7" 26k BTC N -W to 8113' \ff) (7944'111)) PBTD at Baffle Plate 8070' 9fD. 1" stage cemented W 189 bbls 13.5 ppg gas bloc}: type cement around shoe - 6lPage Three Mile Creek #1 —PTD 204-183 —Casing stub extension in place & cemented — 3ft below original 7IPat,c Three Mile Creek #1 —PTD 204-183 —Cement to Surface and Casing Cut —311 below original ground level. 8 r .� .:. ►'� .tet �. _ iii. �..._ � r +-. � - ` •� � � a s �� S 4 ��vv � �_ `c �. �` � - .� ""'�,�; - Three Mile Creek #1 — PTD 204-183 — Backfilled and dirt mound in place. lO1Page GLACIER Three Mile Creek #1— Remedial Welding P&A Program 06/03/2019 I. Notify AOGCC inspector of plans for remedial welding plugging operations w/ 48-hour notice 2. Remove flow gauge and hoses, pick and move wellhouse and cellar box, and prep for operations 3. Move in excavator and construction equipment 4. Excavate down 8' below native soil line a. Make slope so gradient is safe for working around for people and equipment S. Leave master valve open and monitor hose while prepping to remove dry hole tree 6. Remove dry hole tree from 9-5/8" Wellhead 7. Cut and remove 13-3/8" casing 8' below native soil line 8. Chip/Chisel cement so that 9-5/8" is fully visible and accessible 9. Make Cut on 9-5/8" Casing even with 13-3/8" cut 10. Chip/Chisel cement so that 7" is fully visible and accessible 11. Make Cut on 7" Casing to match 9-5/8" casing 12. Chip/Chisel cement so that 3-1/2" is fully visible and accessible 13. Make Cut on 3-1/2" Casing to match 7" cut 14. With all strings at same height, prep to chisel and cut 3-1/2" and 7" to 3" below 9-5/8" Stub 15. Make 7" Casing and 3-1/2" Tubing cut 3" below top of 9-5/8" casing 16. Prep casing and tubing for welding 8-1/2" diameter X 1" thick steel plate with 2" threaded connection a. 8-1/2" OD Plate to be pre -fabricated 1" thick with a 2" threaded hole and installed 2" X 4' snorkel pipe installed b. Once plate is installed the 2" X 4' snorkel will be removed for a 2" bull plug 17. Set 8-1/2" diameter steel plate 3" below top of 9-5/8" casing a. Plan to cement grout any honeycombs or void areas below plate 18. Weld 8-1/2" plate inside 9-5/8" Casing 19. Rernuve Lhe 2" X 4' Snorkei Pipe 20. Install 2" Bull Plug 21. Prep 9-5/8" casing for adding a 5' casing stub and collar 22. Weld on 5' long 9-5/8" casing stub to top of casing 23. R/D welders 24. Install 9-5/8" cement swage and prep for pressure test 25. R/U Hot Oil Truck to top of cement head and test pipe to 1,000 psi for 30 minutes a. Record results on chart recorder 26. R/D Test Equipment 1 GLACIER 27. Prep for cement work 28. Hand Mix 0.5 bbls of SLB cement 29. Pour / Shovel cement to top of 9-5/8" casing stub 30. Utilize pre -made 9-5/8" marker plate 31. Verify plate is %" steel marker -plate cap for 9-5/8" conductor casing, not to extend beyond casing OD Cook Inlet Energy Three Mile Creek No. 1 PTD# 204-183 API# 50-283-20108-00 32. Weld marker plate in place and take photos 33. Back fill, grade, and leave 3 ft mound to allow for settling a. Take photos of final pad area b. Submit to town for inclusion in final report 34. Dispose of any waste 35. Demob all support equipment and personnel 61 T en C uimEN T 1 f ,T Z-rl- CvT I 7u ri_31 , via I IST WaL�D IFREP Fath- 5Ec--c> LJS.LO u Q'tlZ'' }t \'� STEEb PMTE wt 21,yW saonuft 9tPE �2e SS., Rf Tts (I,oLx> ps', Gon- 3o rn.Norts I_ Cc.C, 5w�'E 1 " MLML I INA I- SC"f NkAnC CpnENc � ' �Tf BYLi flrY t) •- i • n PTE<<TD) 1" PI Afe (TtsTro 9 -"e" x 5' cAS.., sa4 WI CAS.NL CULbA (L �o 4•sd Tn.c.-1 - A"SArDavnte,vi VIA -a MEMORANDUM TO: Jim Regg P. I. Supervisor ( i State of Alaska Alaska Oil and Gas Conservation Commission C-Plil`I DATE: 6/10/19 FROM: Austin McLeod SUBJECT: Surface Abandonnent Petroleum Inspector Three Mile Creek #1 " Cook Inlet Energy LLC PTD 2041830; Sundry 318-477 6/5/19: Traveling to Beluga I met with Wes Jeardoe, a Glacier Oil representative. On 6/5 we drove to location to continue forward with the P&A of the well after the OA was "seeping" and building pressure to 700psi when shut in. All strings had been cut approximately 8 foot below ground grade. As per the approved sundry, the 7 -inch & 3'/z - inch strings were then cut approximately 3 inches down inside the 9 5/8 -inch string, making room for a 1 -inch plate with a 2 -inch threaded collar. There was no void with the 1 -inch plate sitting right on top of the 7 -inch and 3'/z -inch stubs. A 2 -inch bull plug was installed in the plate with a 9 5/8 -inch "pup joint" welded to the cutoff casing stub. Testing equipment was rigged up to attempt a 30min 1000psi test against the 1 -inch ✓ welded plate inside the casing with no success. 6/6/21: The operator opted to fly out proper handling/testing equipment to torque up necessary connections and to have more control during pressuring up. A passing 30min test to 1200psi was then accomplished. Once tested, 3 feet was cut off the 9 5/8 -inch "pup joint", putting the top of the 9 -5/8 -inch pipe 3 feet below ground grade, which was measured off the Typar observed. The inside of the casing was filled with cement and was given 12 hours to set up. 6/7/19: We traveled back to location to inspect the cement. I found it to be good, hard, set up cement. Verifying the marker plate was'/< -inch thick and had the proper information, I gave them the ok to weld the plate on. The well is not to be buried for 7 days. I found all strings to be cemented to surface, with only a small void on the 13 3/8 - inch x 9 5/8 -inch casing annulus which was topped off. Attachments: Pictures 2019-0607_Surface_Abandon _TMC-I_am.docx Page 1 of 5 Surface Abandonment — Three Mile Creek Unit #1 (PTD 2041830) Photos by AOGCC Inspector A. McLeod 6/7/2019 Casing cutting ops 7 -inch and 3.5 -inch cutoff depth inside 9 5/8 -inch casing 2019-0607_Surface_Abandon _TMC-1_am.docx page 2 of 5 7 -inch plate welded inside 9 5/8 -inch Pressure testing rig up casing with 2 -inch threaded collar for bull plug 2019-0607_Surface Abandon TMC-1_am.docx Page 3 of 5 7 l id 7 Final cutoff depth; arrow identifies original ground grade 2019-0607 Surface Abandon TMC-1_am.docx Page 5 of 5 Schwartz, Guy L (GED) From: Schwartz, Guy L (CED) Sent: Tuesday, June 4, 2019 9:57 AM To: Stephen Ratcliff Cc: Amanda Dial; Don Jones; Regg, James B (DOA) Oim.regg@alaska.gov) Subject: RE: Three Mile Creek 1 P &A Surface - PTD 204-183 (sundry 318-477) Stephen, You have approval to proceed with the attached program to complete the surface P & A of Three Mile Crk 1. The new modified procedure will stay under the exiting sundry 318-477. The AOGCC will require an inspector to witness the casing cutoff annuli just before welding the first plate. Also make use you have some way of tagging the OA TOC (7 x 9 5/8") if there does happen to be a void. Additionally, as we discussed the excavation should stay open for 7 days minimum before backfilling (after welding cap plate ) to make sure well caps have integrity after well repressures to 700 psi . Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 (Guv.schwartz@alasko.aov). From: Stephen Ratcliff <sratcliff@glacieroil.com> Sent: Monday, June 3, 2019 5:32 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Amanda Dial <adial@glacieroil.com>; Don Jones <djones@glacieroil.com>; Stephen Ratcliff <sratcliff@gla cie roi I.com> Subject: Re: Three Mile Creek 1- PTD 204-183 Guy, See attached for our meeting tomorrow. I have included stage schematics (rough and hand drawn) that I will also review with you tomorrow in our 8:30 meeting. Feel free to share with Jim and others. Thank you and see you tomorrow! Regards, Stephen Ratcliff Vice President—Drilling Glacier Oil and Gas Corporation 188 W. Northern Lights Blvd., Suite 510 Anchorage, AK 99503 O - (907) 433-3808 C - (907) 433-9738 From: "Schwartz, Guy L (CED)" <guy.schwartz@alaska.gov> Date: Monday, June 3, 2019 at 8:39 AM To: Stephen Ratcliff <sratcliff@Rlacieroil.com> Subject: RE: Three Mile Creek 1- PTD 204-183 External Sender: Proceed with Caution Just got in ... will review and get back with this morning. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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). If may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal low. If you are an unintended recipient of this a -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 (Guv.schwartz®aloska.gov). From: Stephen Ratcliff <sratcliff@glacieroil.com> Sent: Monday, June 3, 2019 8:32 AM To: Schwartz, Guy L (CED) <Ruy.schwartz@alaska.eov> Cc: Don Jones <diones@glacieroil.com>; Amanda Dial <adial@gIacieroil.com>; Stephen Ratcliff <sratcliff@Rlacieroil.com> Subject: Re: Three Mile Creek 1 - PTD 204-183 Guy, Good morning . Attached are the daily summaries through yesterday. As of this morning, we still have the well on the flow meter. It is not registering as the flow is less than 1 scf/hour. We would like to move forward with the welding abandonment procedure that we discussed last week. I am available to come in and discuss this morning if you would like further details on the procedure. Thank you and let me know if I can answer any questions. Regards, Stephen Ratcliff Vice President — Drilling Glacier Oil and Gas Corporation 188 W. Northern Lights Blvd., Suite 510 Anchorage, AK 99503 O - (907) 433-3808 C - (907) 433-9738 From: Stephen Ratcliff <sratcliff@glacieroil.com> Date: Thursday, May 30, 2019 at 9:20 AM To: "Schwartz, Guy L (CED)" <guy.schwartz@alaska.gov> Cc: Don Jones <d'ones@glacieroil.com>, Amanda Dial <adial@glacieroil.com>, Stephen Ratcliff <sratcliff@glacieroil.com> Subject: Three Mile Creek 1 - PTD 204-183 Guy, Please see the attached summary for yesterday on TMC -1. The well pressure is stable at 700 psi and was also confirmed this morning. We will finish up all activity today and be in a position to demob. If at all possible, it would be helpful to come to a conclusion before the weekend on how to move forward with respect to the abandonment. I'm okay with waiting on a decision, however, it may be after we finish up the Osprey work before we can get back there. If we can get to a decision today or tomorrow on how to proceed with the abandonment then we will hold our team on location and finish up with the abandonment work right away. If we are given approval to move forward then I would like to open up the well and monitor so that we can bleed off in preparation for the abandonment work. We will use a bubble hose and tank and also monitor it with a person on location. Feel free to call me with any questions and I can also come by the office today to visit on the procedure. Thank you! Regards, Stephen Ratcliff Vice President—Drilling Glacier Oil and Gas Corporation 188 W. Northern Lights Blvd., Suite 510 Anchorage, AK 99503 O - (907) 433-3808 C - (907) 433-9738 1 k; GLACIER Three Mile Creek #1— Remedial Welding P&A Program 06/03/2019 I. Notify AOGCC inspector of plans for remedial welding plugging operations w/ 48-hour notice 2. Remove flow gauge and hoses, pick and move wellhouse and cellar box, and prep for operations 3. Move in excavator and construction equipment 4. Excavate down 8' below native soil line a. Make slope so gradient is safe for working around for people and equipment 5. Leave master valve open and monitor hose while prepping to remove dry hole tree 6. Remove dry hole tree from 9-5/8" Wellhead 7. Cut and remove 13-3/8" casing 8' below native soil line 8. Chip/Chisel cement so that 9-5/8" is fully visible and accessible 9. Make Cut on 9-5/8" Casing even with 13-3/8" cut 10. Chip/Chisel cement so that 7" is fully visible and accessible 11. Make Cut on 7" Casing to match 9-5/8" casing 12. Chip/Chisel cement so that 3-1/2" is fully visible and accessible 13. Make Cut on 3-1/2" Casing to match 7" cut 14. With all strings at same height, prep to chisel and cut 3-1/2" and 7" to 3" below 9-5/8" Stub Make 7" Casin¢ a 16. Prep casing and tubing for welding connection )elow top of 9-5/8" ca_m diameter X 1" thick steel plate with 2" threaded a. 8-1/2" OD Plate to be pre -fabricated 1" thick with a 2" threaded hole and installed 2" X 4' snorkel pipe installed b. Once plate is installed the 2" X 4' snorkel will be removed for a 2" bull plug 17. Set 8-1/2" diameter steel plate 3" below top of 9-5/8" casing a. Plan to cement grout any honeycombs or void areas below plates 18. Weld 8-1/2" plate inside 9-5/8" Casing 19. Remove the 2" X 4' Snorkei Pipe 20. Install 2" Bull Plug LW 21. Prep 9-5/8" casing for adding a Lcasing stub and collar 22. Weld on 5' long 9-5/8" casing stu6'to top of casing 23. R/D welders 24. Install 9-5/8" cement swage and prep for pressure test 25. R/U Hot Oil Truck to top of cement head and test pipe to 1,000 psi for 30 minutes lck d - a. Record results on chart recorder 26. R/D Test Equipment f' j. GLACIER 27. Prep for cement work 28. Hand Mix 0.5 bbls of SLB cement 29. Pour / Shovel cement to top of 9-5/8" casing stub 30. Utilize pre -made 9-5/8" marker plate 31. Verify plate is Y4" steel marker -plate cap for 9-5/8" conductor casing, not to extend beyond casing OD Cook Inlet Energy N0-( Three Mile Creek No. 1 PTD# 204-183 p` API# 50-283-20108-00 32. Weld marker plate in place and take photos 33. Back fill, grade, and leave 3 ft mound to allow for settling a. Take photos of final pad area b. Submit to town for inclusion in final report 34. Dispose of any waste 35. Demob all support equipment and personnel K CkistaEf-1 S 1 frC.T Z'—' C.+T �— �u -fit 9.fiB rl rrr C1-f/e,i 13 /s Isr WELD FRCP €vn- SecwP lJt1.0 7." T Q -4z'' k �" STEED f,LwrE w/ Z" y y' $Non1cFL OfpE 1" PwL �2fsS�R-E TLs� FINAL 5cryfMATIC (1,000 ps'r God- 3o rn.Nu Rt 9 -"e' . 51 CAS' qti z LUI LAS, N4 CUL>A iLJ 9 sle TM6.-1 - Ai3AYISOMIMINE RAQ' �_ �— � rt 5 CAS ✓sc SrU� �ESrW L y.s/e', S� C*f�J< ScVB -•• - TCSrLO w�LJ IZr Q�'V Ar fro) 2* e�lu-ice In �I I �TLSr[a IXI with cM EPSP -r,V% C. — I ?AD Zi The heaviest consentration of oil was from end of pit where arrows are going In two different directions. this was unseen from Sthe surface. 4, A 6 K 1- t 111 MEMORANDUM TO: Jim Regg J�ef9 gzzttq P.I. Supervisor FROM: Lou Laubenstein Petroleum Inspector Section: Drilling Rig: Operator Rep: 35 Township: NA Rig Elevation: Wes Jeardoe Casing/Tubing Data (depths are MD): Conductor: 13 3/8" O.D. Shoe@ Surface: 9 5/8" O.D. Shoe@ Intermediate: P ✓ O.D. Shoe@ Production: 7" O.D. Shoe@ Liner: 11W Meridian: Seward O.D. Shoe@ Tubing: 31/2" O.D. Tail@ Plugging Data: Test Data: State of Alaska Alaska Oil and Gas Conservation Commission Type Plug DATE: May 16, 2019 Verified SUBJECT: Well Bore Plug & Abandonment 2480 ft MD N/A Three Mile Creek #1 P ✓ OA Cook Inlet Energy 108 - 126 ' PTD 204-183; Sundry 318-477 13N Range: 11W Meridian: Seward NA Total Depth: 8180 ft MD Lease No.: 388233 Suspend: P&A: X Casing Removal: 110 Feet Csg Cut@ Feet 2430 " Feet Csg Cut@ Feet Feet Csg Cut@ Feet 8113 " Feet Csg Cut@ Feet Feet Csg Cut@ Feet 3498 - Feet Tbg Cut@ Feet Type Plug Founded on Depth Btm Depth To MW Above Verified Tubing Bridge plug 2480 ft MD N/A 1590 - P ✓ OA 84 108 - 126 ' iia ni 15 min 30 min 45 min Result Tubing 1610 , 1600 1600 A 1600 1590 - 1590 - P ✓ OA 84 108 - 126 ' Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: I witnessed a successful combination MIT TxIA on this well performed by Cook Inlet Energy. This combo test was performed by opening a sliding sleeve in the tubing, then setting a cast iron bridge plug (done before my arrival) in the tubing. I witnessed ✓ pressure applied by pumping down the tubing and communicating into the IA, against the CIBP plug in the tubing and the packer in the casing. Attachments: none rev. 11-28-18 2019-0516_Plug_Verification_TM C-1 _II ' R ECEI !/ ' STATE OF ALASKA OIL AND GAS CONSERVATION COMAION REPORTOF SUNDRY WELL OPERATIONS JAN 2 3 2018 1.Operations Abandon U Plug Perforations U Fracture Stimulate LI Pull Tubing LI A94 °wn Li Performed: Suspend [] Perforate LI Other Stimulate 0 After Casing LI Change ApprovedProgram 0 Plug for'Redrtil 0 Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well 0 Temporary Plug 0 2.Operator Aurora Gas,LLC 4.Wei Class Before Work: 7."Peres to Drl Number: Name: Development 0; Exploratory 0 204-183 Cr 51-‘e/ n.'4 /3.Address: 3705 ArcticBlvd.#2114 Anchorage,At<99503 Stratigraphic 0 Service Lj,'6.API Number: 283-20106-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 388233 Three Mile Creek#1 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): NA Three Mile Creek Beluga Gas 11.Present Well Condition Summary: 'l otalDepth ;n ensured IMO :feet :FTs .measured 40110=& 1ID `feet -true vertical 7990 feet Junk measured None feet /Effective Depth 'measured 5410 feet Padker „measured 2502-3455 feet true vertical 5304 feet tare vertical 2387-3303 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110 137/8.48#N40 410 410 ;1630 psi 520 psi Surface 2436 0518 40#k55 2436 2327 3950 psi, 2570 psi Intermediate Production, 81113 726#N80 8113 7944 7240psi 541x`=psi( Liner Perforation depth Measured depth 2570 4972 feet p P True•Vetticaf depth2459-47.01 ?feet Tubing(size,grade,measured and true vertical depth) 3 1/2 9.3#180 3496 3382 Packers and SSSV(type,measured and true vertical depth) 12.Stimulation or cement squeeze summary: Intervals treated(measured): NA Treatment descriptions including volumes used and final pressure: S NNE D •JAl'.. 3 'U 5 NA 13. Representative Daly Average Production=ar Injection Data. Oit-Bbt F Gas-Mcf Water-Bbt Casing Pressure Tubing Pressure , Prior to well operation: 80 0 130 Subsequent to operation: 0 0 0 14.Attachments(required per 20 AAC 25.070,25.071,&25.289) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory 0 Development 0 Service El Stratigraphic 0 •Copies of Logs and Surveys Run 0 16.Well Status after work: Oil 0 Gas 0 WDSPL 0 Printed and Electronic Fracture Stimulation Data 0 GSTOR 0 W1NJ u WAG _0 Gtld3 [il SUSP 0 SPLUG li, ,17.1 hereby certify that the foregoing is true and correct to the best of rimy knowledge. Sundry Number or NIA if C.O.Exempt: 317-284 Authorized Name: George Pollock Contact Name: Authorized Title: Man -Prod Ops&Eng Contact Email: gpollock(a,aurorapower.a Authorized Signature: <°` � `"" Dari 1123/2018 Contact Phone: 907.351.8286 Form 10.404 Revised 4/20172C ` R B D M S vi JA.!:, % 1;. 2618 Submit original Only ID 11111 Aurora-Gars.,-LLC Operations Summary—Set Temporary Plug Three Mile Creek#1Well July_.23,2017 WOO hours Mob from TMC2 1015 hours R/U WL, PT lubricator w/wellbore 1045 hours RIB_w/1.2",gattge ring to 8" KB,WT,,could_notpags,POOH, 001-1--mud 1115 hours RIH w/1.1"brush to 8',fall to 180%WT,fall to 250',WT,fall-to 300e,WT,falk to 600?,WT, fall to 4000'KB,brush nipple, POOH, OOH-soap 1245 hours RIH w/1" BST to 4000',WT, set Plug, POOH 1330-hours _Bleed off well, chec-k backside tubingpressure,690 psi, Pass 1400-hours RID WL,mob to LC4 • • Three Mile Creek Unit No. I .__ __.--.....,Aurora Gas, LLC Current Well Confipuration 13 5/W'5M x 11"5M vete MBS wellhead installed at surface with BPV installed,tree tested to 5000 psi. New perfs in 2011 I II Coiled Tubing Velocity String 2012 133/8"48811-40 conductor driven to 110 ft minimum. Displace 3 1/2"x 7"anatihn and id of 3%"tbg w/1%- 2%inhibited brine 3112"9.38,8rd EUE tubing. -120 bbls. ' 1 3 1/2"tbg x 7" 26#chg. annular Cap.=.0264 bblilt 1 . . , . . . 121/4"hole directionally drilled to 3 1/2"9.3#EUE Olga , „ 2440'MIT(2329'TVD).95/8"40# Cap= .0087 bbl/ft , , , BTC K-55 Casing to 2438'MD (Cemented with 254 bbls 14.5 ppg _. Gas-Block cement slurry system to 7" 26#casing Cap.=.03&3 A 1 '. surface. bbl/ft. I i 7"Halliburton PHL hydraulic set Winslimma relrievable-production packers set . 11111011111 . 2502'and 3455'w/ tubing tail, Upper Completion:Beings E-.4 X-nipple at 3498'(open)and WL perfsat:2570-94',2726-50', II '' entry guide below. HES TID SSD 2948-54',2980-88',3062412', „. I I VONsipswo, Sliding sleeves installed at 2458" 3156-62',3170-78',3302-17' 1 xditav"- (annulus),2799',and 3405' I .•"-*"': { _.,....... '1Halliburten ES Cementer Stage . i t ' collar installed in 7"casing at 3857'. t ..... Casing-cemented in two stages. 135 Lower Completion Beluga t mannams--=_" bbls 13.5 ppg gas-block cement Perfs:(original) i immon pumped*second stage with returns 3530'-3545',3556'-3566', '' to unlace. 3662'-3672%3683'-3703' I I __ _____,- Added in 2011:3728-38', Illii i. 1-1/2"coiled tubing(1.282"ID)w/ 3812-22' r • .. * ' (Original 4505'-4535'& 1_ 21'2-mr blast joint w/L05"profile i•tl. nipple on btu at 4000' 4576 -4606' ,. AIMS gsr @ 4000' Added in 2011':4786-96', llag 4874-78',488494', - TOC Tagged at 5410' 4962-72' -----r----''—'-- Displaced 6.15 bbls"0"w/1%CaCt i * 1 Beluga perforated 5606'- - : 7"C1BP set at -5560 5636',5668'-5698',5710' -5720'. (5439'-5553' 1,::..# TVD)Zone Tested,tight, Illoh TOC Tagged at 7554' trace gas,no water Displaced 6.14 bbis"G"on top of produced. Abandoned . f ..-• retainer - ' I 7"Retainer set at 7700'on 1 06-Jan-05 to isolate ar..-"11.All161111111111111w- . ., , Tyonek perfs and was Upper Tyonek perforated11W.V110101011WSI. pressure tested to 3000 psi at 7750'-7779'MD(7581' .. 7610'TVD). Zone Tested -{ 1111Mimilmilial wet w/no gas. Chlorides 7"26#RFC N-80 to MIT MD 14,000 ppm. Abandoned (7944'TVD)P11TD at Baffle Plate MIMI 8070'MD. l'i stage cemented w/189 bbls 13.5 ppg gas block type cement around shoe. • ‘•Or Ty I77:• THE STATE Alaska Oil and Gas f OA LAsKA Conse vation COmissi®n 1 1Commission s ' 333 West Seventh Avenue lify-MGOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 "'' Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Manager SCANNED J 12 5 20 17, Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Three Mile Creek Field, Beluga Gas Pool, Three Mile Creek 1 Permit to Drill Number: 204-183 Sundry Number: 317-284 Dear Mr. Pollock: 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. The Alaska Oil and Gas Conservation Commission(AOGCC)approves the setting of a temporary plug in this well to provide isolation from the reservoir as a short-term barrier. This work does not meet AOGCC's regulatory requirements for suspension or plugging and abandonment of this well. Prior to relinquishing the lease back to the landowner, the operator is required by law to properly plug and abandon this well. 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, Hollis S. French Chair DATED this day of July, 2017. RBDMS L JUL 1 1 2017 III Ill RECEIVE. • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION AA A 1 6 2017 APPLICATION FOR SUNDRY APPROVALS : G CC 20 AAC 25.280 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.Temporary Plug Q" 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. [JJ./c.._t:{-,., Aurora Gas,LLC ' Exploratory 111Development ❑ 204 183 5ter 1 3.Address: 1400 W.Benson Blvd.Suite 410 Stratigraphic ❑ Service ❑' 6.API Number: (\ 1,5A Anchorage,AK 99503 50-283-20108-00 , (\ 7.If perforating: 8.Weil Name and Number What Regulation or Conservation Order governs well spacing in this pool? NA Three Mile Creek#1 , Will planned perforations require a spacing exception? Yes ❑ No 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 388233 Three Mile Creek Beluga Gas . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total 4r T6/D(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 8180' , ' ,oK 5410' , 5304' i 650 psi 5410' None Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 133/8"48#H40 110' 110' 1530 psi 520 psi Surface 2438' 9 5/8"40#K55 2438' 2327' 3950 psi 2570 psi Intermediate Production 8113' 7"26#N80 8113' 7944' 7240 psi 5410 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 2570'-4972' ' 2459'-4701' 3 1/2" 9.3#L80 3498' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ttf: Halliburton PHL packers ' 2502'and 3455'(MD)/2387'and 3303'(TVD) 12.Attachments: Proposal Summary 0 Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0' Service ❑ 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑✓ r WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: George Pollock Contact Name: George Pollock Authorized Title: Manager-P O Contact Email: 000llock(a)aurorapower.corn Contact Phone: 907-277-1003 Authorized Signature: f Date: 16-Jun-17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 3i7- z,Q1--( Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: 4- 1 eIA tticty eLtAta t'tx^S 1.:C " M -1 �wcc' tO►,.>r tZC��.t12.CME1.s�s F'GiL CZ- p p, Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS C '. JUL 1 1 2017 Spacing Exception Required? Yes ❑ No Vf Subsequent Form Required: 10--404 APPROVED BY . I I Approved by: COMMISSIONER THE COMMISSION Date: 11 11( fM ?IsIo- 7 l l Form ��\�Form 10-403 Revised 4/2017 pIo3 44ttA{ aIid+NA for 12 months from the date of approval. Attachments in Duplicate v Aurora Gas, L L C June 16, 2017 RECEIVED Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission JUN 1 6 2 017 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Sundry Approval—Set Temporary Plug Three Mile Creek#1 Well PTD#: 204-183 API #: 50-283-20108-00 Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to set a temporary plug to secure this onshore development well in the Three Mile Creek Beluga Gas Field on the west side of Cook Inlet, northeast of the Village of Tyonek. This well is currently producing gas from multiple zones in the Beluga sands and is mechanically sound. Aurora Gas is currently in Chapter 11 bankruptcy protection while attempting to reorganize and emerge with new owners/investors. This application is being submitted as part of our Reorganization Plan filed with the bankruptcy court if liquidation actions are ordered. Aurora Gas, LLC will provide all potential new owners/investors notice of the impending action before on-site activity begins. A velocity string is present in this well from the surface to a depth of 4,000' which will not allow for mechanical isolation of the reservoir. The proposed work involves setting a plug via wireline within the profile nipple (1.05" ID) at a depth of 4000'. Both wing valves will be closed on the tree to provide mechanical isolation. Please find the attached information as required by 20 AAC 25.110 for your review: • Form 10-403 Sundry Application • Current wellbore diagram illustrating the current well configuration. • Slickline Temporary Plug Set—Generalized Procedure If you have any questions or require any further information, please contact me at(907) 277-1003. Sincerely, George Pollock Manager—Production Operations &Engineering 4645 Sweetwater Boulevard, Suite 200 * Sugarland,TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 * Anchorage, AK 99503 * (907) 277-1003 0 Three Mile Creek Unit No. 1 Aurora Gas, LLC Current Well Configuration 13 5/8"5M x 11"5M Vete()MBS wellhead installed at surface with A BPV installed,tree tested to 5000 psi. New perfs in 2011 • 1 Coiled Tubing Velocity String ; ' 4, • im" I. 2012 4d .., #4,...., " #e„,- " 13 3/8"48#H-40 conductor driven to 110 ft minimum. Displace 3 1/2"x 7"annulus s =� and id of 3 V:"tbg w/1%— ' = 2%inhibited brine — 3 1/2"9.3#,8rd ELSE tubing. —120bbls. ,' . ' .'• <.� .• Rs , 3 1/2"tbg x 7" 26#csg . ° ; *' :' annular Cap.=.0264 bbl/ft. -�.0* ' '— 1 4 12 1/4"hole directionally drilled to 3 1/2"9.3#EUE tbga '0 � . � "� 2440'MD(2329'TVD).9 518"40# Cap= .0087 bbl/ft `x' 4' +"0 ►''i BTC K-55 Casing to 2438'MD '. ,,.. '.'�, � ,$ (Cemented with 254 bbls 14.5 ppg Gas-Block cement slurry system to 7" 26#casing Cap.=.0383 Il P. surface. bbl/ft. '; '- ' 7"Halliburton PHL hydraulic set trievable production packers set Lipper Completion:Beluga " at 25(12'and 3455'w/ tubing tail, perfs at:2570-94',2726-50', .. "- t "fi r- X-nipple at 3498'(open)and WL 2948-54',2980-88',3062-82', .: Imo.— entry guide below. HES XD SSD 3156-62',3170-78',330247' ...,, ..- Sliding sleeves installed at 2458' �..•"` (annulus),2799',and 3405' ` f ' l ,. .4 collar installed in 7"casing at 3857'. Lower Completion Beluga Casing cemented in two stages. 135 Perfs:(original) „_ bbls 13.5 ppg gas block cement 3530'—3545',3556'-3566', ' pumped second stage with returns 3662'-3672',3683'—3703' `.,,. to s ce Added in 2011:3728-38', 3812-22' —+ 1 2"1-1/2"coiled tubing(1.28 m)w! (Original)4505'—4535'& { ,-. 21'2-1/8"blast joint w/1.05"profile 4576'—4606' 1'--a on him at 4000' l41.11 -3 lilim Added in 2011':4786-96', _� � ssali 111004— 4874-78',4884-94', �� TOC Tagged at 5410' 4962-72 „ .1*. 4 .. ,`cps Displaced 6.15 bbls"G"w/1%CaCI- 4s" =s ; ,jaws*a 4 Beluga perforated 5606'- . 0, • •'" . 7"CIBP set at 5560' 5636',5668'—5698',5710' `4 —5720'. (5439'—5553' .`,, TVD)Zone Tested,tight, —�' ! TOC Tagged at 7554' trace gas,no water ""., .'t"— Displaced 6.14 bbls"G"on top of produced. Abandoned ; .•�,/ retainer a* �, <4 ,+ ' 7"Retainer set at 7700'on ' 0' 06-Jan-05 to isolate O.400 ,4, Tyonek perfs and was Lipper Tyonek perforated ` r pressure tested to 3000 psi at 7750'—7779'MD(7581' .''' .s'+' 7610'TVD). Zone Tested """' wet w/no gas. Chlorides -f......1. 7"26#BTC N-80 to 8113'MD 14,000 ppm. Abandoned (7944'TVD)PBTD at Baffle Plate i 8070'MD. 1'i stage cemented w/189 bbls 13.5 ppg gas block type cement ▪ ,°. "."' around shoe. t, r►► i AURORA GAS, LLC Slickline Temporary Plug Set - Generalized Procedure June 2017 SUMMARY: This procedure describes the steps taken to set a temporary plug in wells operated by Aurora Gas, LLC to secure the well for a short term shut in. RIH with drift for the appropriate sized tool for the tubing, in most cases 2 7/8"tubing with 2.312" or 3 '/2"tubing with 2.812"X landing nipple profile. Set PXX plug in uppermost landing profile. If a profile is not available, RIH with tubing stop pack-off plug and set above uppermost packer. After plug is set, a negative pressure test will be performed to ensure the plug has isolated the productive intervals from the surface. Upon passing the negative pressure test,the wellhead will be secured. PROCEDURE: 1) AG Operators to shut-in well and monitor pressure while rigging up. 2) RU Pollard Wire Line and lubricator on tree after removal of tree cap. Open well to pressure test lubricator—have pressure gauge on lubricator. 3) RIH with appropriate drift for X profile and sliding sleeves in upper profile. Pass through sleeve approximately 10' to insure safe operation of setting tool. POOH. 4) RIH with PXX Plug body on X-Line running tool. Set Plug body in upper most Sliding sleeve X profile above upper most production packer in well. 5) RIH with RB retrieval tool as running tool with prong. Set Prong in Plug body and POOH. 6) Record pressure and Bleed well bore to zero PSI, Monitor for 30 minutes recording pressure readings at 15 minute intervals. 7) Test successful if no pressure increase observed. If test fails,RIH and reset plug. 8) RDMO Pollard Wire Line. 9) Secure the wellhead. 10)Move to next well. 11)After 24 hours, a pressure reading will be obtained to ensure the integrity of the plug. ,Chyle Square(6/11/2017) i • • pp f I (�� E "C im Lz -, \ lia s ` � , ,. , , SEAN PARNELL, GOVERNOR v i- U IA ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMPIISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 George Pollock Manager, Production Operations 85 Engineerinh '°--3 Aurora Gas, LLC r1 b 4 1400 W. Benson Blvd., Suite 410 p� Anchorage, AK 99503 Re: Three Mile Creek Field, Beluga Gas Pool, Three Mile Creek #1 Sundry Number: 312 -336 r a a V Dear Mr. Pollock: K f ' , � „ , ,) b ;� - 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, 0 Daniel T:' eamount, Jr. Commissioner DATED this day of September, 2012. Encl. • Aikv/ RECEIVED STATE OF ALASKA C AUG 2 9 2012 ALASKA OIL AND GAS CONSERVATION COMMISSION AOGCC APPLICATION FOR SUNDRY APPROVALS � 20 ARC 25.280 1. Type of Request: Abandon ❑ Plug for RedriII [❑ 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 D Other: VELOCITY STRING INSTALL IS 2. Operator Name: AURORA GAS, LLC 4. Current Well Class: 5. Permit to Drill Number: Development 0. Exploratory ❑ 204-183 . 3. Address: 1400 W BENSON BLVD, SUITE 410 Stratlgraphic ❑ Service ❑ 6. API Number ANCHORAGE, AK 99503 50- 283 - 20108 -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 E'' THREE MILE CREEK #1 - 9. Property Designation (Lease Number): 10. Field / Pool(s): A) g,2-1 ADL- 388233 • THREE MILE CREEK GAS FIELD - BELUGA.I.� 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): 8,180' 8,016' • 5,410' 5,304' 5,410' NONE Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 13 -3/8" 48# H -40 110' 110' 1,530 psi 520 psi - Surface 2,438' 9 -5/8" 40# K -55 2,438' 2,327' 3,520 psi 2,020 psi Intermediate Production 8,113' 7" 26# N -80 8,113' 7.944' 4,270 psi 3,120 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 2,570' - 4,972' 2,453' - 4,785' 3 -1/2" L -80 3,498' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): HALLIBURTON PHL PACKEF 2,502' AND 3,455' MD / 2,387' AND 3,303' 1 12. Attachments: Description Summary of Proposal © 13. Well Class after proposed work: Detailed Operations Program Q BOP Sketch ❑ Exploratory ❑ Development IQ ' Service ❑ 14. Estimated Date for 5- Sep -12 15. Well Status after proposed work: Commencing Operations: Oil ❑ Gas El , WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact GEORGE POLLOCK Printed Name GEORGE POLLOC Title MANAGER, PRODUCTION OPERATIONS & ENGINEERING Signature Phone 907 - 277 -1003 Date 29- Aug -12 4 COMMISSION USE ONLY Conditions of approval: Notify Commission so th a representative may witness Sundry Number: 51 2, 33 Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: i ' j.) -c -1-c2 `t 5 - ( ' 0 r2 5-1 1 ` (9 Ai /1 JLi ,,,qc'z(( %j-,5 ( If, Subsequent Form Required: APPROVED BY Approved by: • ' COMMISSIONER TH COMMISSION Date: /4 11 2- riE 3 DMS EP 0 7 201? � f ` Z,..- ORIGINAL ,�, Form 10 -403 Revised 1/2010 i 7 ( i - v Duplicate • • AURORA GAS, LLC Three Mile Creek #1 Velocity String Install Scheduled September 2012 (8- 28 -12) CAPACITIES: 3 -1/2" 9.3# Tubing: 0.008 bbl /ft and 7" 26# Casing: 0.0382 bbl /ft 7" Casing X 3 -1/2" Annular Volume: 0.0264 bbl /ft. Casing ID/ Drift ID is 6.151 / 6.276 "; Tubing Volume to EOT AT 3499'= 30.4 bbl. Casing vol. pkr to deepest perf: 43.3 bbl. KB= 17.7 above GL (all depths from KB). PBTD =5410' MD TD= 8313'MD/ 7944' TVD TUBING /COMPLETION: Tubing ID= 2.992 ". Drift ID= 2.867" HES XD Sliding Sleeve at 2458'- 2.813" X profile— CLOSED (annulus) HES PHL Hydraulic Packer at 2502' HES XD Sliding Sleeves at 2799 and 3495 " - 2.813" X profile- -OPEN HES PHL Hydraulic Packer at 3455' w/ 48' stinger incl. 2.813" X nipple. Bottom of Tubing (Wire -line Entry Guide) - 3508'. EXISTING PERFS BELOW DEEPEST PACKER(MD): 3530' – 3545', 3556' – 3566', 3662' - 3672', 3683' 3703', 3728' - 3738', 3812' – 3822', 4505' - 4535', 4576' – 4606', 4786' - 4796' , 4884' – 4894', 4874' – 4878', 4962' – 4972' COILED TUBING: 1.50" OD w/ 0.109" wall thickness. ID= 1.282 ", Capacity= 0.0016 bbl /ft. PROCEDURE: 1) Remove Wellhouse. 2) Shut -in well and remove flowline to wellhead. 1 RU Vetco lubricator and install BPV in tubing hanger. g er. Y g 4) Bleed off wellhead, close master valve, remove the flow cross w/ wing valve and SSV and all above it (swab valve and tree cap). 5) Install CT tubing hanger/head on top of Master Valve. Install new 3 -1/8" Master Valve on CT hanger/head, and re- insta1T tee w/ wing valve, and safety valve and swab valve w/ tree cap. (CT head/hanger is also a "flow tee" —have 2 2- 1//16 ", API 5000 psi valves on it [for 3 -1/2" X 1.50" CT annulus]). 6) Pressure test new tree assembly. 7) Remove backpressure valve. 8) Grease Wellhead Valves really good. 9) MI and RU Coiled Tubing Unit and spot N2 unit. MU AG choke skid and flow back iron to SSV on wellhead or flowback tee on BOP skid and diffuser tank (Rain for Rent). Use PW from TMC 2 for well fluid. a) Fill coiled tubing reel noting volumes on Barrel counter / displacement tanks. Compare with theoretical coiled tubing reel volume. • • b) Make up coil connector and BHA with centralizers and pull test to 10,000 lb Pressure test connector to 200 PSI & 4,500 PSI for 10 and 10 minutes respectively. c) Make up BHA measure / record actual OD's, ID's, & lengths, ensure pump out sub is on bottom of completion. • Note: Ensure company rep verifies and is in agreement with BHA to be run. Compare maximum OD of tools with minimum ID of the well completion. d) Nipple up BOP stack to wellhead, on top of tree cap — 2- 9/16" 5000# RTJ Flange. Notify state 24 -48hrs prior to testing BOP's e) Pressure test via CT, pumps, stack, flow back manifold against crown valve to 200 PSI & 4,500 PSI for 10 and 10 minutes respectively. • Note: take care that excessive stripper pressure is not applied that can cause pipe collapse scenarios. f) On completion of all tests re- pressure up via coiled tubing to equalize to crown valve and open up tree valves g) Displace the coiled tubing to the fluid required for the job. Circulate fluid out of tubing volume with Nitrogen. 10) PU 1 jt (21') of 2 -1/8" Blast Joint with 10 Rd FJ connections (with pump -out plug on bottom to run dry), profile nipple, and cross -over onto CT connector. RIH and land bottom at approx. at 4000 ft of 1.50" Coiled tubing in the tubing hanger (Still reviewing optimum depth, will be no deeper and may be as shallow as 3650'). Be sure that seal assembly is correctly installed and centralizers are placed within 10ft of the tree to ensure good seal on tubing hanger. Pressure test the coil and tree to 2000 psi. Pump out plug at bottom of CT string (to shear at 2500 psi). 11) RU nitrogen and unload well to Rain for Rent diffuser tank. 12) RD CT and turn well over to operations. 13) Install new piping for well flow lines. Prefabricate these spools in town as much as possible. (Well configuration allows the gas to be flowed up the tubing or in the annular space, to flow them simultaneous a choke may need to be installed on the casing flow path). Chad Helgeson (05/16/12) Revised: Ed Jones (7/3/12) Revised: George Pollock (8/28/12) • 0 /4 , TItree lidik Creek Unit No. 1 A LL mara Gas, C Current Weil Configuration 7/ 5/ / i 13 5/8" 5M x 11" 5M. Vett() MKS # 3 In" 9.3, 8rd EDE tubing. wellhead installed at surface with BIN installed, tree tested to 5000 psi. 4 ; Displaced 3 1/2" x 7" annulus V and id of 3 '.,4" tbg w/ 1% - 13 3/8"3M 11-40 conductor :$ 214 inhibited brine driven to 110 ft Milliffill rit - 120 tibia , • „x• . A' , ## • „. .. * ' / ' # i 1 3' . ' Vel 12 I/4" hole directionally drilled to e : . 2440' MD (2329' WO), 9 5/8" 400 ,s. • liTC K-55 Casing to 2438' MD leek * (Cemented with 254 bids 14.5 ppg Gas-Block cement slurry system to surface, I 111" N- ' • —1‘-' ,,'' —`" ., Open Beluga Perr V s: } 7" Ilailihorton PHI. Bet/11yd set 2570' - 2594' kla IA* packers at 2501.6 ft and 3455 ft. 2726' - 2750' Sliding sleeves at 2458 ft, 2799 It 2948 - 2954' .d II and 3405 ft. "X „, nipple at 3498'. 2980' - 2188' 3062' - 3082' L Itra , . 3156' - 3162' Ma, M 3170' - 3178' „ .. 3302' - 3317' ft I At Hallibarton ES Cementer Stage „ f . Open Beluga Perfs; collar installed in 7” easing at 3857'. 3530' - 3545' to U "' ii 4*' Casing cemented in two stages. 135 3556' -3566' s4 bbis 13.5 ppg gas-block cement .., , 0'P .....v. 3662' - 3672' jar . ° ir ... ,.. -- . pumped (0 second stage with returns 3683' - 3703' WEI to sttrfave. 103 * . ,rel 4505' - 4535' Tt.X,' Tagge at 5410' 4576' 4606' , . - p ..., .1, ' viu . " 1 Displaced 6.13 bbl "G" w/ 1% CaCt 7i - Nem/ 8 - S45 3 12 2' 1 - 2 ,-...,,,,, / g0 1 ! ' / 7 '4' 94 '., g175 7,06,9-9 - ;z4 7" CHIP set at -5560' Beluga perforated 5606'. *0 •.",' 5636', 5668' -$698", 5710' he { woo 440 TOC Tagged at 7554' 5720', (5439' - 5553' .. Dispheed 6.14 hhh "(" on top of T) Zone Tested, tight, retainer trace met, no water produced, Abandoned 7" Retainer set at 7700' on 4„,76. linetmes „,,,.„,,. 06-.Jan-05 to latthite Tyonek pert.; and was Upper l'yonek perforated -,,/ 0 w er",,mt - mg roSNial.v 7," pressure tested to 3000 psi at 7750' - 7779' M.13 (7581" 7610' TVD). Zone Tested 10 , 721 wet w/ sto gas. Chlorkles 7" 26# BTC 74-80 to 8113' MD 14,000 ppm. Abandoned (7944' TVD) man at Baffle Plate V 4 8070' h4D. 1" stage cemented w/ 189 bids 13.5 ppg gas block type cement around Aloe. Aurora Gas, LLC • • Ferguson, Victoria L (DOA) From: Ed Jones [jejones @aurorapower.com] Sent: Friday, August 31, 2012 1:31 PM To: Ferguson, Victoria L (DOA) Cc: 'George Pollock' Subject: RE: Three Mile Creek #1 (PTD 204- 183,Sundry 312 -336) Attachments: TMC 1 Vel String Tree.pdf Victoria, Chad Helgeson passed along to me your inquiry of yesterday regarding the Three Mile Creek 1 velocity string installation that you had sent him. Here are our responses: For this velocity string install procedure could you please provide the following if available: 1. MPSP: the maximum surface pressure that we have seen recently (long -term SITP) has been 820 psig. Our best estimate of bhp at the lowest perforation is 1116 psig. With a gas gradient back to surface, it is estimated that our maximum surface pressure could be as high as 1000 psig, according to the Great Reservoir Engineering PresslnWellbore Excel template. 2. Wellhead schematic with CT tubing hanger /head. Will the existing SSV be utilized? Attached is a diagram of the wellhead /tree after the installation. Yes, we will utilize our existing SSV, basically just adding the CT head and another master valve to our existing master valve and re- installing the flow tee w/ wing valve and SSV and swab valve with tree cap above the new pieces. Please let me know if you need more information. Regards, Ed J. Edward Jones President Aurora Gas, LLC 6051 North Course Dr., Ste 200 Houston, TX 77072 281 -495 -9957 (0) 713 - 899 -8103 (C) 1 • 9 A (//ent2 iti 6 /7 6 '*.--,,/--.,.."' e..-::' e? /IO / / 5 7 ' 1/4' Z O( /7 V ,.-----' .' 0, il4: f r : ____.......„. 1(1 r . 1 , • ,,,,/ .' r1 .—./ LT V 1 • 7) r : fir ',/ - -' .....- -, 7 1 • . 1 3 ' 1 /,..,,, ( )-------- (5 r I i 't- 5/A t PIE I j 11' „ . ... ... , / .--, _ , mg - 7 , 7.1 . ' 2 . 1 - ' - - - r 11 5 "in Acifer ; yet , I k , e. ( E ' -` - ' 7 _____....• i „.....,....... _ .. ..,,- . , • , , ..... 1 . . . '---) I _ b Z I CA I ij > 1 1 1 I i ; 1 ii 1 1* -- I I il • Ferguson, Victoria L (DOA) From: Ed Jones [jejones @aurorapower.com] Sent: Friday, August 31, 2012 1:31 PM To: Ferguson, Victoria L (DOA) Cc: 'George Pollock' Subject: RE: Three Mile Creek #1 (PTD 204- 183,Sundry 312 -336) Attachments: TMC 1 Vel String Tree.pdf Victoria, Chad Helgeson passed along to me your inquiry of yesterday regarding the Three Mile Creek 1 velocity string installation that you had sent him. Here are our responses: For this velocity string install procedure could you please provide the following if available: 1. MPSP: the maximum surface pressure that we have seen recently (long -term SITP) has been 820 psig. Our best estimate of bhp at the lowest perforation is 1116 psig. With a gas gradient back to surface, it is estimated that our maximum surface pressure could be as high as 1000 psig, according to the Great Reservoir Engineering PresslnWellbore Excel template. 2. Wellhead schematic with CT tubing hanger /head. Will the existing SSV be utilized? Attached is a diagram of the wellhead /tree after the installation. Yes, we will utilize our existing SSV, basically just adding the CT head and another master valve to our existing master valve and re- installing the flow tee w/ wing valve and SSV and swab valve with tree cap above the new pieces. Please let me know if you need more information. Regards, Ed J. Edward Jones President Aurora Gas, LLC 6051 North Course Dr., Ste 200 Houston, TX 77072 281 - 495 -9957 (0) 713 - 899 -8103 (C) 1 . • • • 7 1 , -- (-- ..,-; ,,,,-, tvo / 1/4„-- 0,- 7 ,,,/ _.7 ,/,, /Ai ,----, ;VI 1 43 r . I- / r ,„- ,-, i--- - L y , cl ry:, -95in . : . ,..._ • . -,-; ,, : l', I P k . 14 , ..7 if cyyl 1 I \ • . . a r - ' „ _ ,:,19jr5' 3 co -..` - i -. ' X 1 /.- .„ ( i . .-------- /Vr A1 1— "*.'4 ( ,,, a +11111 1 41 % 4 L ) 1 ' - 4,4€, 1° • i e - .. (-5') /:-..ot" -TT. 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I ,....... ___.--- - , ( .2C- , q.s.• 1 x 7 7 : 7 ' -7r Aly„ • . ,-------: i — if.:-.) ., iio 2, J • II 4 11 ' - ' tni , 1 vis 1 * oi)-• / • -I L- - not , 1 ,.., , ,,, , ' ..,„,.. ........ ...11..., ; 1 ' -----/ S_H ; 1 "wilr________-_,.. - Tr - 1____________fl .01j_ Z -----. 5 - . i %A/ '-:--- ( ' ) t k - I 1 - — „_ ! - 1 — \ i - 7 \ ...." I i - . A -: — I •`19,>0%4' ., / 5L-'" I * — -• '' — 1 , 1.0.5 1% r i k si . .. 1.05 0(., :'. ' L ,,,/ ' , ' ■ / 12 - -r . / 1.1 0:7 1 1 !i Z s (7 /Y04.6 t v. /7 / v :At/ .5' 7// 7 ./..j - / •/"--/ - / JA• °AY -:,,, ..L.7. _.-,' ..-k _..,-.) , 7, «v ;7 -._-_-?,/ ik-i___/- :v9 ki ,:-. / (2 - 2/7) t/ • • . • re e M,( (r j I Pm 2r4reso Regg, James B (DOA) From: Regg, James B (DOA) Sent: Tuesday, August 28, 2012 12:14 PM To: 'George Pollock' 'a /t € I Z`)j ( v Cc: Ed Jones Subject: RE: Introduction & Clarification Thanks for your call and contact information. Sundry is required for installation of velocity string in TMC #1 (PTD 2041830) Jim Regg AOGCC MAY 2 {�+. 333 W. 7th Ave, Suite 100 SCANNED MA r 0 2 �u i Anchorage, AK 99501 907 - 7934236 From: George Pollock [ mailto :gpollockPaurorapower.com] Sent: Tuesday, August 28, 2012 10:39 AM To: Regg, James B (DOA) Cc: Ed Jones Subject: Introduction & Clarification Jim, As I mentioned in our brief discussion, I have recently joined Aurora Gas, LLC as the point of contact in our Anchorage office. In this capacity I will be providing the requested information for the UIC Cost of Compliance reporting. Additionally, we are preparing to install a velocity string on our Three Mile Creek #1 (API 50- 283 - 20108 -00) in early September. Can you confirm if a Sundry Application is required for this activity? Let me know if you require any further information. Regards, George Pollock Manager, Production Operations & Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277 -1003 Main (907) 351 -8286 Cell 1 SatTE OF ALASKA '' r.:: r ALASKA OIL AND S CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS NOV 2 2011 1. Operations Abandon U Repair Well U Plug Perforations U Stimulate Li s '!!bh l bad (Ago. t uflutlrSSt T Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool El Waiver Li Time Extension ❑An chore ge Change Approved Program ❑ Operat. Shutdown El Perforate 0 . Re -enter Suspended Well El 2. Operator AURORA GAS, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development p Q • Exploratory❑ 204 -183 3. Address: 1400 WEST BENSON, STE. 410, Stratigraphic❑ Service El 6. API Number: ANCHORAGE, AK 99503 50 -283- 20108 -00 — 00 • 7. KB Elevation (ft): 9. Well Name and Number: 333 THREE MILE CREEK #1 ` • 8. Property Designation: V. Field /Pool(s): .1' ADL- 388233 Three Mile Creek Gas Field -- Beluga U �ned Gas Pool ° 11. Present Well Condition Summary: 0 V Total Depth measured 8016 tC tr feet Plugs (measured) true vertical 8180 L feet Junk (measured) Effective Depth measured 5410 feet true vertical 5304 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' a 3..3 c 110' 110' 1530 psi 520 psi Surface 2438' 9 -5/8" 2438' 2438' 3520 psi 2020 psi Intermediate Production 8133' 7" 8113' 7944' 4270 psi 3120 psi Liner Perforation depth: Measured depth: 2570' - 4972' '" '-_ ::- b } ' '.` 16 : ' True Vertical depth: 2453' 4785' Tubing: (size, grade, and measured depth) 3 - 1!2" L -80 3498' Packers and SSSV (type and measured depth) LIES PI Pa ~Yers 2502' & 3455' 12. Stimulation or cement squeeze summary: Intervals treated (measured): None. Treatment descriptions including volumes used and final pressure: Added perforations at 4962 -72', 4874 -68', 4884 -94', 4786 -96', 3812 -22', and 3728 -38' MD (4805 -3568' TVD). No other treatment. 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 130 0.2 0 80 Subsequent to operation: 0 295 2 0 130 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory ❑ Development 0 ' Service ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ❑ Gas El - WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 311 -209 Contact Ed Jones Printed Name J. Edward Jones ��AI Title President Signature 11, ��I `i�!�1��/ Phone 281 -495 -9957 Date 11/17/2011 \.\ Form 1 Revised 04/2006 t S Orignal Ony ' JMS NOV 2 8 �Ot Original l X07 / • • �1a Gas, LLC k November 17, 2011 �. ,6, , } ' Mr. Daniel T. Seamount, Jr., Chair '_ , Alaska Oil and Gas Conservation Commission `F �.. "� 333 West 7 Avenue, Suite 100 �� 4': , "'r� Anchorage, AK 99501-3539 RE: Three Mile Creek Gas Field, Beluga Undefined Gas Pool, TMC #1 Sundry Number: 311 -209 Form 10 -404 Report of Sundry Well Operations Dear Mr. Seamount: Enclosed is the Form 10 -404, Report of Sundry Operations for the subject approved Sundry Application for the Three Mile Creek #1 well, with a Daily Operations Summary attached. Please let me know if you need additional information. Sincerely, mmori . Edward Jones i ''' President Cc: Patricia Bettis, Petroleum Land Manager, Department of Natural Resources David Hall (and Pirtle Bates via email), Cook Inlet Energy Greg Jones (and Mike Franger via email), Alaska Mental Health Trust Attachments (2) 6051 North Course Drive, Suite 200 • Houston, Texas 77072 • (281) 495 -9957 • Fax (281) 495 -1473 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277 -1003 • Fax (907) 277-1006 . . Aurora Gas, LLC THREE MILE CREEK #1 OPERATIONS SUMMARY ADDING PERFORATIONS TO LOWER COMPLETION (July 2011) KB= 17.7 above GL (all depths from KB). PBTD =5410' MD TD= 8313'MD/ 7944' TVD 3 -1/2" TUBING /COMPLETION: Tubing ID= 2.992 ". Drift ID= 2.867" HES XD Sliding Sleeve at 2458'- 2.813" X profile— CLOSED (annulus) HES PHL Hydraulic Packer at 2502' HES XD Sliding Sleeves at 2799 and 3495 " - 2.813" X profile HES PHL Hydraulic Packer at 3455' w/ 48' stinger incl. 2.813" X nipple. Bottom of Tubing (Wire -line Entry Guide)- 3508'. EXISTING PERFS BELOW DEEPEST PACKE -LOWER COMPLETION (MD): 3530- 45', 3556 -66', 3662 -72', 3683 - 3703', 4505 -35', & 4576- 4606'. June 30, 2011 -- RU Pollard Wireline and RIH w/ shifting tool. FL at 2650' (WLM). Could not close sleeves. Ran brush on slickline thru sleeves to 2807' and 3418'several times. Close sleeves at 2799' and 3495'. Fluid level not apparent above 3500'Ran bailer to 5334' KB —fluid level not apparent— recover some thick mud. Release Pollard. . Pump in sufficient produced water to bring the fluid level up to +1- 2800'. Calculate using Capacities above and attached well bore diagram. Recheck FL with Pollard. When fluid level is at that level (or slightly higher), release Pollard. (Production before: 102 mcfpd at 80 psi; production after shifting sleeves: 227 mcfpd at 80 psi). June 7, 2011 - -RU Expro and ran Pressure - temperature log. Tag at 5308'. Log out of hole. Fluid level at 2844'. RD for night. July 8, 2011 —RU Expro with 3000 -psi lubricator on and pressure test to 2500 psi using pressure washer pump. RIH with GR/CCL and correlate to open -hole "Platform Express" logs of 12/18/04 and cement bond log. Reviewed CBL and determine cement at 4500 -3850' is questionable, so did not perforate 3 sands in that interval that were planned (4418 -26', 4012 -20', & 3990 - 4000'). Perforate the following intervals with 2- 1/2" ShoGun strip gun with 4 SPF w/ 26.4 gm NTX II Raptor charges in 5 runs: i. 4962 -72' (SIP before -300 psi, after -300 psi); ii. 4874 -78' and 4884 -94' (one 20' gun) (SIP before -320 psi, after -320 psi); iii. 4786 -96' (SIP 340 psi before, after -490 psi); iv. 3812 -22' (SIP before -690 psi, after - - -650 psi); and v. 3728 -38' (SIP before -640 psi, after 630 psi).. POOH w/ last gun. RD Expro. Put well on production, flowing about 300 mcfpd at 150 psi w/ 5 bbl water in 12 hours. July 11 -16, 2011 —flowed well to sales at an average rate of 302 mcfpd at 185 psi. A • • . turn Gas, LLC November 17, 2011 r r -!if 1 per Mr. Daniel T. Seamount, Jr., Chair � +�`i� ka C Alaska Oil and Gas Conservation Commission Con s. �'v r, 333 West 7 Avenue, Suite 100 tiPissio Anchorage, AK 99501 -3539 RE: Three Mile Creek Gas Field, Beluga Undefined Gas Pool, TMC #1 {��o Sundry Number: 311 -209 pc") Form 10 -404 Report of Sundry Well Operations Dear Mr. Seamount: Enclosed is the Form 10 -404, Report of Sundry Operations for the subject approved Sundry Application for the Three Mile Creek #1 well, with a Daily Operations Summary attached. Please let me know if you need additional information. Sincerely, 41 . Edward Jones President Cc: Patricia Bettis, Petroleum Land Manager, Department of Natural Resources David Hall (and Pirtle Bates via email), Cook Inlet Energy Greg Jones (and Mike Franger via email), Alaska Mental Health Trust Attachments (2) 6051 North Course Drive, Suite 200 • Houston, Texas 77072 • (281) 495 -9957 • Fax (281) 495 -1473 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277 -1003 • Fax (907) 277 -1006 • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon I__ _I Repair Well Li Plug Perforations u Stimulate (J Other U Performed: Alter Casing ❑ Pull Tubing [J Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate ® Re -enter Suspended Well ❑ 2. Operator AURORA GAS, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development p Q Exploratory 204 -183 4 3. Address: 1400 WEST BENSON, STE. 410, Stratigraphic❑ Service ❑ 6. API Number: ANCHORAGE, AK 99503 50 -283- 20108 -00 00 7. KB Elevation (ft): 9. Well Name and Number: 333 THREE MILE CREEK #1 8. Property Designation. 10. Field /Pool(s): ADL- 388233 Three Mile Creek Gas Field— Beluga Undefined Gas Pool 11. Present Well Condition Summary: Total Depth measured 8016 feet Plugs (measured) true vertical 8180 feet Junk (measured) Effective Depth measured 5410 feet true vertical 5304 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 110' 110' 1530 psi 520 psi Surface 2438' 9 -5/8" 2438' 2438' 3520 psi 2020 psi Intermediate Production 8133' 7" 8113' 7944' 4270 psi 3120 psi Liner Perforation depth. Measured depth. 2570' - 4972' True Vertical depth: 2453' 4785' Tubing: (size, grade, and measured depth) L -80 3498' Packers and SSSV (type and measured depth) 2502' & 3455' 12. Stimulation or cement squeeze summary: Intervals treated (measured): None. Treatment descriptions including volumes used and final pressure: Added perforations at 4962 -72', 4874 -68', 4884 -94', 4786 -96', 3812 -22', and 3728 -38' MD (4805 -3568' TVD). No other treatment. 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 130 0.2 0 80 Subsequent to operation: 0 295 2 0 130 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development 0 Service ❑ Daily Report of Well Operations X 16. Well Status after work: Oil U Gas j WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 311 -209 Contact Ed Jones Printed Name J. Es and Jones Title President Signature ' l�Jj S Phone 281- 495 -9957 Date 11/17/2011 Form 1 !Revised 04/2006 ', I Submit Original On RBDMS Nov 2 2 2011 , 9 Only • • Aurora Gas, LLC THREE MILE CREEK #1 OPERATIONS SUMMARY ADDING PERFORATIONS TO LOWER COMPLETION (July 2011) KB= 17.7 above GL (all depths from KB). PBTD =5410' MD TD= 8313'MD/ 7944' TVD 3 -1/2" TUBING /COMPLETION: Tubing ID= 2.992 ". Drift ID= 2.867" HES XD Sliding Sleeve at 2458'- 2.813" X profile— CLOSED (annulus) HES PHL Hydraulic Packer at 2502' HES XD Sliding Sleeves at 2799 and 3495 " - 2.813" X profile HES PHL Hydraulic Packer at 3455' w/ 48' stinger incl. 2.813" X nipple. Bottom of Tubing (Wire -line Entry Guide) - 3508'. EXISTING PERFS BELOW DEEPEST PACKE -LOWER COMPLETION (MD): 3530- 45', 3556 -66', 3662 -72', 3683 - 3703', 4505 -35', & 4576- 4606'. June 30, 2011 -- RU Pollard Wireline and RIH w/ shifting tool. FL at 2650' (WLM). Could not close sleeves. Ran brush on slickline thru sleeves to 2807' and 3418'several times. Close sleeves at 2799' and 3495'. Fluid level not apparent above 3500'Ran bailer to 5334' KB fluid level not apparent— recover some thick mud. Release Pollard. . Pump in sufficient produced water to bring the fluid level up to +/- 2800'. Calculate using Capacities above and attached well bore diagram. Recheck FL with Pollard. When fluid level is at that level (or slightly higher), release Pollard. (Production before: 102 mcfpd at 80 psi; production after shifting sleeves: 227 mcfpd at 80 psi). June 7, 2011 - -RU Expro and ran Pressure - temperature log. Tag at 5308'. Log out of hole. Fluid level at 2844'. RD for night. July 8, 2011 —RU Expro with 3000 -psi lubricator on and pressure test to 2500 psi using pressure washer pump. RIH with GR/CCL and correlate to open - hole "Platform Express" logs of 12/18/04 and cement bond log. Reviewed CBL and determine cement at 4500 -3850' is questionable, so did not perforate 3 sands in that interval that were planned (4418 -26', 4012 -20', & 3990 - 4000'). Perforate the following intervals with 2- 1/2" ShoGun strip gun with 4 SPF w/ 26.4 gm NTX II Raptor charges in 5 runs: i. 4962 -72' (SIP before -300 psi, after -300 psi); ii. 4874 -78' and 4884 -94' (one 20' gun) (SIP before -320 psi, after -320 psi); iii. 4786 -96' (SIP 340 psi before, after -490 psi); iv. 3812 -22' (SIP before -690 psi, after - - -650 psi); and v. 3728 -38' (SIP before -640 psi, after 630 psi).. POOH w/ last gun. RD Expro. Put well on production, flowing about 300 mcfpd at 150 psi w/ 5 bbl water in 12 hours. July 11 -16, 2011 —flowed well to sales at an average rate of 302 mcfpd at 185 psi. v • • Three Mile Creek Unit No. I Aurora Gas, LLC Current Well Configuration 7/ 5//I I 13 5/8" 5M x 11" 5M Vetco MBS wellhead installed at surface with BPV installed, tree tested to 5000 psi. Displaced 3 1/2" x 7" annulus and id of3'A tbg w/ 1 %- 13 3/8" 48# H -40 conductor 2% inhibited brine driven to 110 ft minimum. - 120 bbls. 3 1/2" 9.3 #, Srd EUE tubing. 12 1/4" hole directionally drilled to 2440' MD (2329' TVD). 9 5/8" 40# BTC K -55 Casing to 2438' MD (Cemented with 254 bbls 14.5 ppg IbL — Gas -Block cement slurry system to surface. III Open Beluga Perfs: 7" Halliburton PHL Ret/Hyd set 2570' - 2594' 1 packers at 2501.6 ft and 3455 ft. 2726' - 2750' — -__.__ Sliding sleeves at 2458 ft, 2799 ft 2948' - 2954' HI and 3405 ft. "X" nipple at 3498'. 2980' - 2988' ► 3062' - 3082' 3156' - 3162' 3170' - 3178' 3302'- 3317' S — ' III , Halliburton ES Cementer Stage Open Beluga Perfs: collar installed in 7" casing at 3857'. 3530' - 3545' r ' Casing cemented in two stages. 135 3556' - 3566' hbls 13.5 ppg gas -block cement 3662' - 3672' Illl ddddNNNN / pumped a second stage with returns 3683' - 3703' , / to surface. 4505' - 4535' TOC Tagged at 5410' /� /� 1 , , 4576' - 4606' Displaced 6.15 bbls "G" w/ 1% CaCI" / v W 3 72 8 -38; 3 li _ 22, P c r-'S : 4 / 7b6 - 96 ; 4 7 y_ 7g $y_y , !� 7" CIBP set at - 5560' Beluga perforated 5606'- 5636', 5668' - 5698', 5710' ► -(= or TOC Tagged at 7554' - 5720'. (5439' - 5553' ma's"" Displaced 6.14 bbls "G" on top of TVD) Zone Tested, tight, / retainer trace trace gas, no water produced. Abandoned 7" Retainer set at 7700' on 06- Jan -0S to isolate Tyonek perfs and was Upper Tyonek perforated pressure tested to 3000 psi at 7750' - 7779' MD (7581' 7610' TVD). Zone Tested ---► T �- wet w/ no gas. Chlorides �" mom 7" 26# BTC N -80 to 8113' MD 14,000 ppm. Abandoned (7944' TVD) PBTD at Baffle Plate ArillilliX 8070' MD. 1" stage cemented w/ 189 bbls 13.5 ppg gas block type cement around shoe. Aurora Gas, LLC • • sifErE 0[F a SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Bruce D. Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC 14- 13 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Three Mile Creek Gas Field, Beluga Undefined Gas Pool, TMC #1 Sundry Number: 311 -209 Dear Mr. Webb: m �� . �tNED JUL 7 201 u 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 (r. day of July, 2011. Encl. Cer • '1' 'I' , iii) STATE OF ALASKA `Y ' ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALSKit ¢il , , ;as , ` i{ ' lrllr�sssiott 20 AAC 25.280 ,)irk !� et0 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate MI - Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Aurora Gas, LLC Development El • Exploratory ❑ 204-183 • 3. A dd r es s: Stratigraphic ❑ Service ❑ 6. API Number: 1400 W. Benson Blvd., Suite 410, Anchorage, AK 99503 50 - 283 20108 - ' 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 El Three Mile Creek #1 • 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL- 388233. Three Mile Creek Gas Field - Beluga Undefined Gas 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): 8,180' • 8,016' . 5,410' 5,304' 5,410' none Casing Length Size MD TVD Burst Collapse 7 Structural Conductor 110 13 -3/8" 48# H -40 110' 110' 1,530 psi 520 psi Surface 2,438' 9 -5/8" 40# K -55 2,438' 2,327' 3,520 psi 2,020 psi Intermediate Production 8,113' 7" 26# N - 80 8,113' 7,944' 4,270 psi 3,120 psi Liner Perforation Depth MD (ft): (Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 2,570' - 4,606' MD / 2,453' - 4,439'TVD / 3 - 1/2 " 9.3# 8rd 3,438' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Haliburton PHL Ret/Hyd set 2,502' and 3,455' MD / 2,387' and 3,303' TVD 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory ❑ Development El - Service ❑ 14. Estimated Date for 15. Well Status after proposed work: July 10, 2011 Commencing Operations: OtS■Q' Oil ❑ Gas 0 • WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chad Helgeson 907 277 - 1003 Printed Name Bruce D. Webb Title Manager, Land and Regulatory Affairs Signature /. cb . , \ Phone 907 277 - 1003 Date June 28, 2011 C COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31 l ...gcy:it Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: ( 0 — j oci. APPROVED BY G `/ / Approved by: � • / // COMMISSIONER THE COMMISSION Date: 7 1 JUL 0 7 201% 22 �� Form 10 -403 Revised 1/2010 ORIGINAL .1 Submit iri Duplica� te • • Aurora Gas, LLC THREE MILE CREEK #1 2011 NON -RIG WORKOVER: PERFORATING PROCEDURE Version 1.1 (6/28/2011) CAPACITIES: 3 -1/2" 9.3# Tubing: 0.008 bbl /ft and 7" 26# Casing: 0.0382 bbl /ft 7" Casing X 3 -1/2" Annular Volume: 0.0264 bbl /ft. Casing ID/ Drift ID is 6.151/6.276 "; Tubing Volume to EOT AT 3499'= 30.4 bbl. Casing vol. pkr to deepest perf: 43.3 bbl. KB= 17.7 above GL (all depths from KB). PBTD =5410' MD TD= 8313'MD/ 7944' TVD TUBING /COMPLETION: Tubing ID= 2.992 ". Drift ID= 2.867" HES XD Sliding Sleeve at 2458.'- 2.813" X profile — CLOSED (annulus) HES PHL Hydraulic Packer at 2502' HES XD Sliding Sleeves at 2799 and 3495 " - 2.813" X profile - -OPEN HES PHL Hydraulic Packer at 3455' w/ 48' stinger incl. 2.813" X nipple. Bottom of Tubing (Wire -line Entry Guide)- 3508'. EXISTING PERFS BELOW DEEPEST PACKER(MD): 3530 -45', 3556 -66', 3662 -72', 3683- 3703', 4505 -35', & 4576- 4606'. 1) Prior to moving in Expro perforators, RU Pollard and close sleeves at 2799' and 3495' and determine fluid level. Wait an hour and recheck fluid level. If it has changed more than 100', wait another hour and recheck. Repeat until stable within 100'. 2) Pump in sufficient produced water to bring the fluid level up to +/- 2800'. Calculate using Capacities above and attached well bore diagram. Recheck FL with Pollard. When fluid level is at that level (or slightly higher), release Pollard. 3) RU Expro with 3000 -psi lubricator on and pressure test above 5000 -psi X 3 -1/2" tree tree to 2500 psi. (Max BHP is 2473 psi at 4970', from open -hole MDT). 4) RIH with GR/CCL and correlate to open -hole "Platform Express" logs of 12/18/04. 5) Perforate the following intervals with 2 -1/2" ShoGun strip gun with 4 SPF w/ 26.4 gm NTX II Raptor charges: i. 4962 -72', ii. 4874 -78' and 4884 -94' (one 20' gun), iii. 4786 -96', - iv. 4418 -26', v. 4012 -20', vi. 3990 - 4000', vii. 3812 -22', and - viii. 3728 -38' • • (80' of perfs, 8 gun runs). Monitor and record pressure before and after firing ,i each gun. 6) POOH w/ last gun. RD Expro. Call in results. 7) AG operators to flow well to production facility ASAP — monitor pressure and rates (avoid damaging Barton flow meter with high pressures and higher -than- current rates — change orifice plate as needed). Continue to monitor well until rates and pressures stabilize— record hourly rates and pressures. Ed Jones 6/27/11 Rev 6/28/11 • • Three Mile Creek Unit No. 1 Aurora Gas, LLC Current Well Configuration 05 /20/05 See attached completion As -Built for specific Information -- 13 5/8" 5M x 11" 5M Vetco MBS wellhead installed at surface with BPV installed, tree tested to 5000 psi. Displaced 3 1/2" x 7" annulus and id of3''A" tbg w/ 1 %- 13 3/8" 48# H -40 conductor 2% inhibited brine driven to 110 ft minimum. -120 bbls. 3 1/2" 9.3 #, 8rd EUE tubing. ) 12 1/4" hole directionally drilled to 2440' MD (2329' TVD). 9 5/8" 40# BTC K -55 Casing to 2438' MD (Cemented with 254 bbls 14.5 ppg Gas -Block cement slurry system to — surface. III Open Beluga Perfs: 7" Halliburton PHL Ret/Hyd set 2570' - 2594' 12r:=11.-- packers at 2501.6 ft and 3455 ft. 2726' - 2750' allIN — unis.,._ Sliding sleeves at 2458 ft, 2799 ft 2948' - 2954' 111 and 3405 ft. "X" nipple at 3498'. 2980' - 2988' I 3062' - 3082' ® 111,111,-.� Please see Attachment I for 3156' - 3162' 1151 ' '' completion detail 3170' -3178' OM t 3302' - 3317' -_°"` -- i . 111 Halliburton ES Cementer Stage Open Beluga Perfs: collar installed in 7" casing at 3857'. 3530' - 3545' Casing cemented in two stages. 135 3556' - 3566' Ed bbls 135 ppg gas -block cement 3662' - 3672' pumped (k second stage with returns 3683' - 3703' f - to s Open Beluga Perfs: L 4505' - 4535' TOC Tagged at 410'% 4576' - 4606' Displaced 6.15 G" w/ 1% cacr 7" CIBP set at - 5560' Beluga perforated 5606'- 5636', 5668' - 5698', 5710' —► . e TOC Tagged at 7554' - 5720'. (5439' - 5553' Displaced 6.14 bbls "G" on top of TVD) Zone Tested, tight, retainer trace gas, no water produced. Abandoned 7" Retainer set at 7700' on -_�_Mit— 06- Jan -05 to isolate Tyonek perfs and was Upper Tyonek perforated %MN , pressure tested to 3000 psi at 7750' - 7779' MD (7581' 7610' TVD). Zone Tested J am wet w/ no gas. Chlorides 1 7" 26# BTC N -80 to 8113' MD 14,000 ppm. Abandoned (7944' TVD) PBTD at Baffle Plate 8070' MD. 1'' stage cemented w/ 189 bbls 13.5 ppg gas block type cement around shoe. FIGURE 1 Aurora Gas, LLC Page 7 of 7 s • • ? , k` Engineered Perforator Analysis EPA ' Owen Performance Report Owen A CURL LABORATORIES MINT h CORE IAUUMTURU:S COMPANY Company: EXPRO GROUP Engineer: ED HAWKER GENERAL INFORMATION Well: Unknown Field: Unknown Depth to Top Shot: 3700.0000 (ft) Borehole Dia: 8.5000 (in) Fluid Weight: 8.3380 (ppg) Fluid Description: Fresh Water Casing Position: Centered Gun Position: Eccentered # of Strings: 1 Prepared By: JIM HOLT Formation: Consolidated Sandstone (CSS) .. (17 -23% Por) .. (5 -11K Cs) .. (5500.0000 psi) Special Notes: If Preferred Explosive differs from Explosive Type please specify! GUN SYSTEM System Description: 2 1/2" SHOGUN NTX 11 RAPTOR, 4 SPF 60 DEG. Gun Type: Shogun Gun Size Spf Phase Charge Charge Charge PN Explosive (in) Type Gram Wt Type 2.5000 4 S /60/60 DP 26.4000 STP- 2500 -401 NTX I 1 HMX Recommended Detonating Cord: 80 HMX XHV HMX I CHARGE DATA API API Sec 1 Concrete API Sec 1 Concrete Mild Steel Mild Steel Hole Test Ed Penetration (in) Strength (psi) Penetration (in) (in) RP19B I 32.6200 7042.0000 9.6090 0.4000 TUBULAR DATA Tubular Size Weight Grade Sheath Fluid Weight Cem Str String (in) (lb/ft) Mat (ppg) (psi) Large 7.0000 26.0000 N -80 Cement N/A 6000.0000 Results apply to Owen systems only. Do not substitute components. The results in this report are based on the Method of Equivalents (E.A. Colle, K.D. Honeycutt), which uses both observed and calculated data. The results are provided as is" and without warranty of any kind, expressed, or implied. Owen Oil Tools PO Box 40666 20 May, 2011 Fort Worth, TX 76140 Reference: Phone: 1-817-551-0540 Print: 1629 Fax: 1- 817 - 551 -0795 Page 1 of 2 Email: epa@corelab.com • • h ,,, Engineered Perforator Analysis EPA Owen Performance Report A MK Owen A MBE LABORATORIES [IMPART LARORATRA113 OMIT 1 I Formation 4.1 EPA ! ! Cement - Ni Phase Diagram ! I Casing 28.1 26.1 20 May 2011 ! ! Fluid 24.1 177 Gun rPell 22 20.1 18.1 16.1 14.1 12 1 6 2 l tg.t 6.1 4.1 21 - 0.1 10.1 12.1 - 14.1 3 • - 16.1 5 - 10.1 20.1 - 22.1 - 24.1 26.1 Shogun 125001 28.1 DP I HMX r STP- 2500.411NTX I I - 30.1 Calculation Basis: 9241 Formation Compressive Strength , 34.1 5500.00 (psi) Entrance Hole Size (in) Penetration (in) Pos Clearance Inner Not Not Formation Total Target (in) String Used Used Penetration Penetration 1 3.7760 0.2643 0.0000 0.0000 29.0028 30.1148 2 2.3724 0.3208 0.0000 0.0000 29.3775 30.6221 3 0.4844 0.3940 0.0000 0.0000 30.2332 31.4777 4 0.0000 0.4070 0.0000 0.0000 30.7141 31.8261 5 0.4844 0.3940 0.0000 0.0000 30.2332 31.4777 6 2.3724 0.3208 0.0000 0.0000 29.3775 30.6221 AVG 1.5816 0.3502 0.0000 0.0000 29.8231 31.0234 Results apply to Owen systems only. Do not substitute components. The results in this report are based on the Method of Equivalents (E.A. Cole, K.D. Honeycutt), which uses both observed and calculated data. The results are provided as Is" and without warranty of any kind, expressed, or implied. Owen Oil Tools PO Box 40666 20 May, 2011 Fort Worth, TX 76140 Reference: Phone: 1- 817- 551 -0540 Print: 1629 Fax: 1 -817- 551 -0795 Page 2 of 2 Email: epa @corelab.com • • Halliburton Global Company: Aurora Gas, LLC Date: 4/25/2005 Time 11 :15 :33 Page: I Field: Cook Inlet Co- ordinate(NE) Reference: Well: TMCU #1, Grid North Site; Three Mile Creek Unit Vertical (TVD) Reference: TMCU #1: 326.5 Weil; TMCU #1 Section (VS) Reference: Well (0.00N,0.00E,268.59Azi) Wellpatk: TMCU #1 Survey Calculation Method: Minimum Curvature Db: Oracle Survey: Start Date: Company: Engineer: Tool: Tied -to: Field: Cook Inlet USA Map System:US State Plane Coordinate System 1927 Map Zone: Alaska, Zone 4 Geo Datum: NAD27 (Clarke 1866) Coordinate System: Well Centre Sys Datum: Mean Sea Level Geomagnetic Model: bggm2004 Site: Three Mile Creek Unit Site Position: Northing: 2624191.02 ft Latitude: 61 10 37.818 N From: Map Easting: 286393.49 ft Longitude: 151 12 36.591 W Position Uncertainty: 0.00 ft North Reference: Grid Ground Level: 0.00 ft Grid Convergence: -1.06 deg Well: TMCU #1 Slot Name: Well Position: +N / -S 0.00 ft Northing: 2624191.02 ft Latitude: 61 10 37.818 N +E / -W 0.00 ft Easting : 286393.49 ft Longitude: 151 12 36.591 W Position Uncertainty: 0.00 ft Wellpath: TMCU #1 Drilled From: Well Ref. Point 502832010800 Tie -on Depth: 15.50 ft Current Datum: TMCU #1: Height 326.50 ft Above System Datum: Mean Sea Level Magnetic Data: 12/4/2004 Declination: 20.09 deg Field Strength: 55627 nT Mag Dip Angle: 73.89 deg Vertical Section: Depth From (TVD) +N / -S +E / -W Direction ft ft ft deg 15.50 0.00 0.00 268.59 Survey Program for Definitive Wellpath Date: 12/30/2004 Validated: Yes Version: 3 Actual From To Survey Toolcode Tool Name ft ft 279.00 8091.00 TMCU #1 (279.00- 8091.00) MWD MWD - Standard Survey MD Ind Azim TVD Sys TV» N/S IUW MapN MapE Tool ft deg deg ft ft ft ft ft ft 15.50 0.00 0.00 15.50 - 311.00 0.00 0.00 2624191.02 286393.49 TIE LINE 279.00 6.95 323.71 278.35 - 48.15 12.87 - 9.45 2624203.89 286384.04 MWD 374.93 9.17 321.18 373.33 46.83 23.50 -17.68 2624214.52 286375.81 MWD 467.14 11.83 320.09 463.99 137.49 36.48 -28.35 2624227.50 286365.14 MWD 558.43 15.02 319.57 552.77 226.27 52.66 -42.03 2624243.69 286351.46 MWD 650.59 18.93 318.51 640.90 314.40 72.96 -59.68 2624263.98 286333.81 MWD 746.45 23.72 318.29 730.17 403.67 99.02 -82.82 2624290.04 286310.67 MWD 842.23 25.12 317.79 817.38 490.88 128.46 - 109.30 2624319.48 286284.19 MWD 938.18 23.36 317.00 904.87 578.37 157.46 - 135.96 2624348.47 286257.53 MWD 1033.89 21.51 316.52 993.33 666.83 184.07 - 160.98 2624375.08 286232.52 MWD 1 1129.43 19.68 316.43 1082.76 756.26 208.44 - 184.12 2624399.45 286209.38 MWD 1222.39 17.92 316.58 1170.76 844.26 230.17 - 204.74 2624421.18 286188.76 MWD 1316.15 18.98 315.27 1259.70 933.20 251.48 - 225.39 2624442.49 286168.11 MWD 1411.88 19.26 307.72 1350.16 1023.66 272.20 - 248.83 2624463.21 286144.67 MWD 1507.44 18.80 300.29 1440.51 1114.01 289.61 - 274.60 2624480.62 286118.90 MWD 1603.09 18.35 290.72 1531.20 1204.70 302.71 - 302.00 2624493.72 286091.50 MWD 1698.72 17.95 282.06 1622.09 1295.59 311.12 - 330.49 2624502.13 286063.01 MWD 1794.52 17.17 273.23 1713.44 1386.94 315.00 - 359.05 2624506.01 286034.45 MWD 1890.42 15.91 262.57 1805.39 1478.89 314.10 - 386.23 2624505.11 286007.28 MWD I • • • Halliburton Global Company: Aurora Gas, LLC Date: 4/2512005 Tiute: 11:15:33 Page: 2 Mid: Cook Inlet Co- ordinate(NE) Reference: Well: TMCU #1, Grid North Site: Three Mile Creek Unit Vertical (TVD) Reference: TMCU #1: 326.5 Weil: TMCU #1 Section (VS) Reference: Well (0.O0N,0.00E,268.59AZi) WeOpath: TMCU #1 Survey Calculation Method: Minimum Curvature Db: Oracle Survey MD Ind Aziww TV» SysTVD NiS E/W MapN MapE Tool ft deg deg ft ft ft ft ft ft 1986.10 16.02 250.19 1897.41 1570.91 307.93 - 411.66 2624498.94 285981.85 MWD 2081.89 17.35 240.13 1989.18 1662.68 296.33 - 436.49 2624487.34 285957.02 MWD 2177.74 18.39 239.37 2080.41 1753.91 281.51 - 461.89 2624472.52 285931.62 MWD 2273.57 17.91 241.24 2171.47 1844.97 266.72 - 487.82 2624457.73 285905.69 MWD 2369.50 18.70 241.74 2262.54 1936.04 252.34 - 514.29 2624443.35 285879.22 MWD 2462.55 18.35 240.94 2350.77 2024.27 238.16 - 540.23 2624429.18 285853.28 MWD 2558.50 16.21 241.15 2442.39 2115.89 224.36 - 565.17 2624415.38 285828.34 MWD 2654.21 15.96 239.08 2534.35 2207.85 211.16 - 588.16 2624402.17 285805.36 MWD 2749.75 16.02 239.88 2626.19 2299.69 197.79 - 610.83 2624388.81 285782.69 MWD 2845.71 15.45 239.72 2718.56 2392.06 184.70 - 633.32 2624375.72 285760.20 MWD 2941.47 16.32 241.34 2810.66 2484.16 171.82 - 656.14 2624362.83 285737.37 MWD 3037.20 16.14 240.26 2902.58 2576.08 158.76 - 679.50 2624349.78 285714.02 MWD 3132.76 15.66 239.99 2994.48 2667.98 145.73 - 702.20 2624336.74 285691.32 MWD 3228.41 15.46 237.95 3086.62 2760.12 132.50 - 724.19 2624323.52 285669.34 MWD 3324.04 15.36 236.91 3178.82 2852.32 118.82 - 745.60 2624309.84 285647.92 MWD 3419.84 15.86 239.51 3271.08 2944.58 105.26 - 767.51 2624296.28 285626.01 MWD 3515.74 15.33 236.64 3363.45 3036.95 91.64 - 789.39 2624282.66 285604.13 MWD 3611.42 15.20 236.93 3455.76 3129.26 77.84 - 810.47 2624268.86 285583.06 MWD 3707.21 14.61 235.03 3548.33 3221.83 64.06 - 830.89 2624255.08 285562.64 MWD 3803.06 12.44 237.70 3641.51 3315.01 51.61 - 849.52 2624242.64 285544.00 MWD 3898.89 10.28 235.43 3735.46 3408.96 41.24 - 865.29 2624232.27 285528.24 MWD 3994.82 8.37 235.99 3830.12 3503.62 32.48 - 878.13 2624223.50 285515.40 MWD 4090.52 5.84 250.22 3925.08 3598.58 26.94 - 888.49 2624217.96 285505.04 MWD 4186.27 4.30 248.57 4020.46 3693.96 23.98 - 896.41 2624215.00 285497.12 MWD 4282.11 3.75 247.99 4116.06 3789.56 21.49 - 902.66 2624212.51 285490.87 MWD 4377.89 3.56 244.38 4211.64 3885.14 19.03 - 908.25 2624210.05 285485.28 MWD 4473.64 3.48 240.39 4307.21 3980.71 16.31 - 913.46 2624207.33 285480.08 MWD 4569.37 3.71 239.13 4402.76 4076.26 13.28 - 918.64 2624204.31 285474.89 MWD 4665.21 3.46 240.16 4498.41 4171.91 10.25 - 923.81 2624201.28 285469.72 MWD 4760.89 3.36 233.51 4593.92 4267.42 7.15 - 928.57 2624198.17 285464.96 MWD 4856.38 2.13 234.83 4689.30 4362.80 4.46 - 932.27 2624195.49 285461.26 MWD 4952.06 0.98 217.03 4784.94 4458.44 2.79 - 934.22 2624193.81 285459.32 MWD 5047.73 1.05 193.89 4880.60 4554.10 1.28 - 934.92 2624192.31 285458.61 MWD 5143.41 1.13 187.22 4976.26 4649.76 -0.51 - 935.25 2624190.52 285458.29 MWD 5239.22 0.86 169.94 5072.05 4745.55 -2.15 - 935.24 2624188.87 285458.29 MWD 5334.90 0.93 172.29 5167.72 4841.22 -3.63 - 935.01 2624187.40 285458.52 MWD 5430.69 0.96 151.97 5263.50 4937.00 -5.11 - 934.53 2624185.92 285459.00 MWD 5526.26 1.26 155.27 5359.05 5032.55 -6.77 - 933.71 2624184.26 285459.82 MWD 5621.82 1.42 149.83 5454.59 5128.09 -8.75 - 932.68 2624182.28 285460.85 MWD 5717.56 1.34 146.50 5550.30 5223.80 -10.70 - 931.47 2624180.32 285462.07 MWD 5812.57 1.42 141.13 5645.28 5318.78 -12.55 - 930.11 2624178.48 285463.42 MWD 5908.88 1.22 127.44 5741.57 5415.07 -14.10 - 928.55 2624176.93 285464.98 MWD 6004.15 1.56 127.21 5836.81 5510.31 -15.50 - 926.71 2624175.53 285466.82 MWD 6099.94 1.94 120.65 5932.55 5606.05 -17.12 - 924.28 2624173.91 285469.25 MWD 6195.62 1.88 112.80 6028.18 5701.68 -18.55 - 921.44 2624172.48 285472.09 MWD 6291.62 2.11 108.88 6124.12 5797.62 -19.73 - 918.32 2624171.29 285475.22 MWD 6387.55 2.12 100.96 6219.99 5893.49 -20.64 - 914.90 2624170.39 285478.63 MWD 6483.25 2.48 100.49 6315.61 5989.11 -21.35 - 911.13 2624169.67 285482.40 MWD 6579.00 2.45 98.32 6411.27 6084.77 -22.03 - 907.07 2624169.00 285486.46 MWD 6674.84 2.26 93.96 6507.03 6180.53 -22.45 - 903.15 2624168.57 285490.38 MWD 6770.62 2.34 96.00 6602.73 6276.23 -22.79 - 899.33 2624168.24 285494.21 MWD 6866.37 2.45 94.51 6698.40 6371.90 -23.15 - 895.34 2624167.87 285498.19 MWD • 1 • Halliburton Global Company: Aurora Gas, ILC Date: 4/25/2005 Time 11 ;15:33 Page; 3 Field: Cook Inlet Co-ordinate(NE) Reference: Welt TMCU #1, Grid North Site; Three Mile Creek Unit Vertical (TVD) Reference: TMCU #1: 326,5 Weil: TMCU #1 Section (VS) Reference; Wen (0,0ON,0,00E,268,59Azi) Wellpath: TMCU ##1 Survey Calculation Method; Minimum Curvature Db: Oracle Survey MD fuel Azim TVD Sys TVD N/S E/W MapN MapE Tool ft deg deg ft ft ft ft ft ft 6962.10 2.54 92.24 6794.04 6467.54 -23.40 - 891.18 2624167.63 285502.35 MWD 7057.94 2.60 94.27 6889.78 6563.28 -23.64 - 886.89 2624167.38 285506.64 MWD 7153.62 2.73 94.32 6985.36 6658.86 -23.98 - 882.46 2624167.05 285511.07 MWD 7249.11 2.82 91.37 7080.74 6754.24 -24.20 - 877.84 2624166.82 285515.69 MWD 7344.79 2.63 84.93 7176.31 6849.81 -24.07 - 873.30 2624166.96 285520.23 MWD 7440.46 2.76 86.21 7271.87 6945.37 -23.72 - 868.82 2624167.31 285524.71 MWD 7536.14 2.65 82.54 7367.45 7040.95 -23.28 - 864.32 2624167.75 285529.21 MWD 7631.95 2.43 84.96 7463.16 7136.66 -22.81 - 860.10 2624168.21 285533.42 MWD 7727.63 2.47 86.39 7558.75 7232.25 -22.51 - 856.03 2624168.52 285537.50 MWD 7823.42 2.84 87.34 7654.44 7327.94 -22.27 - 851.60 2624168.76 285541.93 MWD 7918.99 2.70 82.16 7749.90 7423.40 -21.85 - 847.00 2624169.18 285546.53 MWD 8014.55 2.66 86.12 7845.36 7518.86 -21.39 - 842.56 2624169.63 285550.97 MWD 8091.00 2.65 83.76 7921.72 7595.22 -21.08 - 839.03 2624169.95 285554.50 MWD 8185.00 2.65 83.76 8015.62 7689.12 -20.61 - 834.71 2624170.42 285558.82 PROJECTED to TD . ~. . -~ , -:.:' Aurora Gas' L L wwwaurorapower.com October 27, 2006 Mr. William Van Dyke, Acting Director Department of Natural Resources Division of Oil and Gas 550 W 7`l' Avenue, Suite 1100 Anchorage, AK 99501-3560 Mr. Keith Sanders Sr. Vice President, Land and Legal Affairs Cu, ~1~ lnl~t u e~ion Incorporaicu 2525 `C' Street, Suite 500 P.O. Box 93330 Anchorage, AK 99509-3330 ~~ ~~~ ~ ~ ~D~~ RE: Three Mile Creek Unit Dear Mr. Van Dyke and Mr. Sanders: Due to unfavorable reservoir characteristics and drilling results, we can no longer justify the work commitment necessary to sustain this unit. Accordingly, the anticipated contraction of the Participating Area would result in the remaining acreage being less than the lease itself. Therefore, it is with deepest regrets that we must inform you that the Three Mile Creek Unit partners have decided to voluntarily dissolve this unit. Effective November 1, 2006. ~xre understa::d th~r date of Alaska oil and bas lease, P.DL 388233, will cor.±inue +o be ..w~ held by production, and that the remaining State and CIRI oil and gas leases, presently held by the unit, will ultimately expire, unless extended. It is our intention to continue production from the Three Mile Creek Unit No. I and No. 2 wells on a lease basis. Aurora Gas, LLC, as Unit Operator, hereby- accepts the responsibilities of the current unit operations as the Lessee and Notification Lessee of record. We respectfully request that the Unit Plan of Development be administratively transferred to a Lease Plan of Development. In conjunction with this request, as of November 1, 2006, we will be operating under a Lease Plan of Development, as it pertains to the existing developments and present operations, and the existing Lease Plan of Operation approvals for the wells, pads, roads and pipelines. 10333 Richmond Avenue, Suite 710 • Housfon, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 • ~ f ~ Three Mile Creek Unit October 27, 2006 Page 2 Additionally, it is our understanding that the AOGCC Conservation Order No. 558, establishing rules for the Three Mile Creek Beluga Gas Pool, will remain in effect. Aurora Gas, LLC intends on continuing operations in accordance with these pool rules. Should circumstances improve in the future, we may revisit the possibility of unitization. Thank you for your time and attention to this matter. Should you have questions, please contact Mr. J. Edward (Ed) Jones at the Houston telephone number below. Sincerely, `~ Bruce D. Webb Manager, Land and Regulatory Affairs Concurrence by Forest Oil Corporation: ("~- ( ,~~~ , 0 ~~~~'~-~ `c-W 41 .~ y~_ dames D. Arlington Land Manager Cc: Mr. John K. Norman Chairman Alaska Oil and Gas Conservation Commission 333 W. 7`" Avenue, Suite 100 Anchorage, AK 99501 Mr. Matt W. Rader Natural Resource Specialist State of Alaska Division of Oil and Gas 550 W. 7t" Avenue, Suite 800 Anchorage, AK 99501-3560 • • MICROFILMED ~._ :~ ~~ ~~ _,. 03/01/2008 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:~LaserFichelCvrPgs_Inserts~Microfilm_Marker.doc . STATE OF ALASKA . ALA OIL AND GAS CONSERVATION COM ION GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1 a. Test: l.::J Initial U Annual U Special 1b. Type Test: U Stabilized U Non Stabilized l.::J Multipoint -"'"'" ..... ..-...... i.A ^V ') ß 'H\n7 D Constant Time D Isochronal D Other 2. Operator Name: ..... .... .-- 5. Date Completed: 11. Permit to Drill Number: Aurora Gas, LLC May 20. 2005 204-183 3. Address: 6. Date TD Reached: 12. API Number: 1400 West Benson Blvd, Suite 410 Anchorage AK 99503 December 24, 2004 50- 283-20108-00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 1504' FNL, 148' FWL, Sec35, T35N, R11W, SM 332' AMSL GL@ 315.3' Three Mile Creek Unit-1 Top of Productive Horizon: 8. Plug Back Depth(MD+ TVD): 14. Field/Pool(s): 3530' MD 1420' FNL, 646' FEL, Sec 34, T13N, R11W, SM 5410' MD, 5243' TVC Three Mile Creek Total Depth: 9. Total Depth (MD + TVD): 8185'MD 1540' FNL, 686' Fel, 8185' MD, 8,015.6' TVD 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 286393.49 y- 2624191.03 Zone- 4 ADL 388233 TPI: x- 285825.54 y- 2624413.82 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 285558.82 y- 2624170.42 Zone- 4 Multi Packer Selective Zone wI 17. Casing Size Weight per foot, lb. I.D. in inches Set at ft. 19. Perforations: From To 7" 26# 6.276 8113' 3430'-4606', Gross Interval-114' perfs 18. Tubing Size Weight per foot, lb. I.D. in inches Set at ft. 3-1/2" 9.3# 2.992 -2501 ' 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 2501.6' & 3455' NA None 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): D Tubing D Casing FO psia @ Datum TVDSS 14.65 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: I % CO2: %N2: % H2S: Prover: I Meter Run: I Taps: 3,600 3,450 0 1 0 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice Size (in.) Size (in.) psig Hw FO psig FO psig FO Hr. 1. X 1,115 42 2. X 635 44 3. X 440 44 4. X 340 44 5. X 389 44 Basic Coefficient Pressure Flow Temp. Gravity Factor Super Compo Rate of Flow No. (24-Hour) -I hwPm Pm Factor Fg Factor Q1 Mcfd Fb or Fp Ft Fpv 1. Calculated by PTS 412 2. 1,196 3. 1,414 4. 1,579 5. 1,841 Temperature for Separator for Flowing No. Pr Tr z Gas Fluid T Gg G 1. 2. 3. Critical Pressure 4. Critical Temperature 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SIDE Submit in Duplicate Pc 1,474 pc2 2,172,676. 1,620 pf 2,624,400 No. pt pf pc2 -pf Pw ~ PC2_~ Ps ps2 pf _PS2 1. 1,115 1 ,243,225 992,451 1,209 1,461,681 1,162,719 2. 635 403,225 1,796,451 686 470,686 2,153,714 3. 440 193,600 1,979,076 476 226,576 2,398,824 4. 340 115,600 2,057,076 369 136,161 2,488,239 5. 389 151,321 2,021,355 423 178,929 2,445,471 25. AOF (Mcfd) 1,942 Remarks: AOF calculated using Ryder Scott Software n I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed / / /.L./ / YJI1 ~ Title ,f'ð^ t'ñ,::/n~(j cr ~~.J Date >:ly(d7 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ -I hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= ~ dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back-pressure equation, dimensionless Pa Field barometric pressure, pSia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 I:» !\S Ryder Scott Reservoir Solutions (public) (Protected) 93 0.560 POINT NO. (Automatic) SHUT-IN 1 2 3 4 5 Q, Mcfld o 412 1,196 1,414 1,579 1,841 . WELL NAME: FIELD: LOCATION: RESERVOIR: SOUR GAS N2 CO2 H2S Options . THREE MILE CREEK UNIT NO.1 THREE MILE CREEK UNIT KENAI BOROUGH, ALASKA BELUGA-LOWER PERFS (3530-3703') (01/18/05) MOLE % 1.00 0.00 0.00 D Check, If Injection Well D Smooth Pipe Roughness RESULTS AOF, Mcf/d: C: BCPD o ~--~-- o o o o o 2.992 n: 1,942 0.000740 1.000000 10,000 ~- - - - - - . . . . - - -".III .1 , I , , , , , , . , , , , , , , , , , , , , , , BOTTOM HOLE TEMP, of: GAS GRAVITY: _J:!~ GRAVITY, Yw: CONDo GRAV., °API: TVD, FT: 3,450 MEAS. DEPTH, FT: 3,600 Condo Correl. (Y/N): N Corrected* Tc, oR: 343.63 Corrected* Pc, Psia: 671.94 Pressure Base, Psia: 14.650 TUBING ID, IN.: * Wichert-Aziz correction for contaminants, if any Test Data BWPD o o o o o o '? C> >< N", ,;; a.. 1,000 ~ e:- 100 100 1,000 Flow Rate, Mcf/d 10,000 FTP, Psia 1,474 1,115 635 440 340 389 WHT, of 44 42 44 44 44 44 FLOWING BHP, Psia 1,620 1,209 686 476 369 423 COMMENT SIBHP These results were prepared using Reservoir Solutions Software. This is not Ryder Scott work product, . . '¿Ø? PT. .:.." .. PrOdUCtIOn TestIng services COlOmbIa Job Review Client: Aurora Gas Well: Three Mile Creek Unit 111 Date: 24-Jan-Q5 Report No.: 240105 Operation: Operation Type: Equipment Type: Drill Stem Test and Data Acquisition FuR Bore DST with 20K electronic gauges State: Field: Well: Zone: Test RIg: Alaska Beluga Three Mile Creek Unit #1 Upper TyonekITyonekITsuga DSTIDAQ Nabors 129 Well site Infonnation: Aurora Co. Rep: Aurora Test Eng: PTS Supervisor: Date(s): J. Keener J.Keener/M. BeIgum R.HoffIA.GomezIG.Grimes 29 Dee 04 - 20 Jan 05 Packer SettIng Depth:- _..................... Run 1 1631 ft.MD Run 2 5488ft.MD Run 3 5473 ft. MD Run 4 4293 ft. MD Run 5 3400 ft. MD Deviation: All ZOI18$ +/.(J' @ peeker setting depth Packer: 7" HD with HHD Depth Reference: Drilling RKB Ground level: + 0 Feet Workover RT: + 17.0 Feet Correlation: Wireline Perforation Record: TyonekITsuga Run 1 7750-7779ft. MD Run 2 5606-5636, 5668-5698. 5710-5720 ft. MD Run 3 5606-5636. 5668-5698, 5710-5720 ft. MD Run 4 4505-4535. 4576-4606 ft. MD Run 5 3530-3545. 3556-3566, 3662-3672. 3683-3703 ft. MD ~ Well Parameters Run 1 Fluid Type: KCL Brine 9.6 ppg Est 8HT: 1-40" F BHT Test: 135" F Est. BHP: 3750 psi BHP Test: 3200 psi Run 2 Fluid Type: KCL Brine 10.2 ppg Est. BHT: 140" F BHT Test 105' F Esl BHP: 3750 psi BHP Test: 2200 psi Run 3 Fluid Type: KCL Brine 10.2 ppg Est. BHT: 140" F BHT Test: 101" F Est. BHP: 3750 psi BHP Test: 2200 psi Run 4 Auld Type: KCL Brine 10.2 ppg Esl BHT: 130" F BHT Test: 92" F e Est. BHP: 3250 psi BHP Test: 1800 psi Fluid Type: KCL Brine 10.2 ppg Est. BHT: 130" F BHT Test 75" F Est. BHP: 3250 psi BHP Test: 1800 psi Deviation: Dog Leg severity: Minimum 100s): Max. Dev. 25" @ 842' MD Max. Dogleg 5" @ 746' MD 6.27f!' ID 7" Production Uner Liner: Tubulars: 7" 26 #1ft BTC-M L-80 Production Uner See at1ached Schematics r-- Page 1 of 5 OST TCP Run #1 Summary: OST TCP Run #2 Summary: OST only Run #3 Summary: ~ . . Operations Summary: Ran test string and guns, pr-..re testing string 4000 psi against cIo8ed DHSV. WireIine correlation and set packer at 7631 ft. MD. Set packer using top drive, 11/2 turmI no residual torque, easy set. Made up surface pressure control and flow equipment Opened downhole valve, indication of valve open at 1500 psi applied annulus pressure, hold 1800 psi annulus pressure, Fire guns and close DHSV. Open MCV and dispIaoe +/- 50 bbI diesel cushion, close MCV No problems With cycling circulation valve or displacement Open DHSV In flow the well. Attempted In flow the well, 26 bbIs back after 30 m, Shut in well. reversed out tubing and rigged up In swab well in. No problems With çycIing DHSV or MCVor reversing Rigged up and swabbed well, 4 1/2 hrs 50 bbIs of KCL swabbed, no flow, Abandon swabbing, reveIW out well using MCV No problems With cyciing DHSVor MCV or reversing Unset and released packer With no problems Ran test string and guns, pressure UIstìng string 4000 psi against cIo8ed OHSV. Wireline correIaIion and set packer at 5488 ft. MD. Sat packer using top drive, 1 1/2 turns no residual torque, easy set. Made up surface pressure control and flow equipment Opened downhole valve, no surface indication valve opened Fire guns Guns fired confirming DHSV open Close DHSV and open MCV and dispIaoe +/- 43 bbI diesel cushion, close MCV Open DHSV In flow the well. Attømpted In flow the well, no clear indication DHSV opened Cycied DHSV several times With on clear indication valve open or well flowing or taking fluid Abandoned operations Reversed out string Unset and released packer With no problems On surfaœ DHSV in locked open position, cycled same and valve funetioned properly Ran test string With DHSV in the locked open position. No wìreIìne comtIation, spaced out with tubing strap and set packer at 5473 fl MD, Sat packer using top drive, 1 1/2 turns no residual torque, easy set. Made up surface pressure control and flow equipment Start swabbing operatiot IS Swabbed for 9 1/2 hrs +/- 50 bbIs swabbed with surf8ce pressure 0 psi, no flow Stopped swabbing and pumped 42 bbIs of KCL cbNn the tubing. Applied 1000 psi tubing pressure With no response Increased tubing pressure In 1500 psi and formation broke, injecting 2 bbIsImin at 1500 psi Rigged up to swab well in Swabbed for 8 1/2 m +/- 38 bbIs swabbed With surface pressure 0 psi, no flow Abandoned operations Reversed out string Unset and released packer With no problems Position packer below perforations and circulated string and annulus Pulled out of the hole On surface DHSV in locked open position, cycled same and valve functioned property Page 2 of 5 ~ OST TCP Run #4 Summary: 6TCP~ SUmmary: r" r . . Operations Summary: Ran tMt siring and guns, DHSV in closed position. Indication DHSV opened at +1- 3400 ft = 1800 psi Phyd Possible surge pressures or loss of nitrogen pre-çharge allowed valve to cycle to hold open position Wireline correlation and set peeker at 4294 ft. MD. Sat packer using top drive, 1 112 turns no residual torque, easy set. Made up surface pressure control and flow equipment Opened downhole valve, no surface indicatíon valve opened Fire guns Guns fired confirming DHSVopen Close DHSV and open MCVand disptace +1- 33 bbI diesel cushion, close MCV Open DHSV to flow the welt no clear indication DHSV opened Inject one bbI to confirm DHSVopen Well will not flow, rig up to swab Swab for 4 112 hrs, gas to surface Flowed well 15 hrs attempting clean up. Shut in well to inject treatment to clean up well Pumpecl30 bbI treatment and 40 bbI chaser at 1500-1700 psi Ended treatment and rigged up to swab Swabbed and attempted to flow well for 8 hIS Ended swabbing operations and reversed out the well Unset ønd released packer with no problems Position peeker below perforations and circula18d siring and annulus Pulled out of the hole On suñace DHSV in closed position, valve opened at 1200 psi to ensure no trapped gas below valve Ran test string and guns, DHSV and MCV not run. Wireline correlation Displaced 25 bbls of diMel and set packer at 3400 ft. MD, Set packer using top drive, 1 112 turns no residual torque, easy set. Made up surface pressure control and flow equipment Fire guns See Well Test Report for detailed deecription of clean up, flow and shut-in periods Flowed the well for clean up Cleaned up and flowed the well for 7 hIS. clean gas to surface Shut in well for buildup (+/- 5 hIS) Flowed the welt for +/- 7 hrs Shut in well for buildup (+/- 15 hrs) Flowed well for 5 hIS Shut in well, open reversing valve and reversed out tubing Unset and released packer with no problems Circulate well Pulled out of the hole Page 3 of 5 . . Observations: r- Run'" Make up of BHA was done quickly and efficiently by a good rig CrfIW Top drMI used to set packer, limited surface torque available due to dog leg severity and tubing limitation. However; packer setting went smoothly. Minor problems with flow head swivel, difficult to get the swivel to turn due to 18mperature. 00whh0Ie valves and an tools functioned properly. Difficult to 888 surface indicators to confirm DHSV operationIposition. RFT log information suggested we should have good surface indicators. Rig pump sys1øms required using low volume prMSUr8 test pump at times to apply or maintain applied pressures, Run#R. No problems with make up of BHA Top drive used to set packer, limited surface torque available due to dog leg ~ and tubing limitation. However; packer setting went smoothly. No problem with flowhead, preheat on surface prior to picking up, Valves functioned properly but difficult to 888 surface iI'Idication DHSV opening. Guns fired confirming DHSV opened and in the proper position. Spotted diesel cuehion with MCV normal openI\ion. No formation or tubing response confirming DHSV re-opened after spotting of cushion. Aborted test due to no indication DHSV was open or tubing had no plugged off after guns fired. Again RFT information suggested there should have been good surface indications confirming valve position, Pulled out of the hole and cycled DHSV on surface with normal function. Gauge data confirmed DHSV cycled properly down hole. Run tt3 Re-ran BHA with DHSV in locked opened position and without gum¡ to re-test zone No problems with make up of BHA Top drive used to set packer, limited surface torque available due to dog leg severity and tubing limitation. However; packer setting went smoothty. Swabbed well with no gas to surface. Injected to confirm DHSV was open, required 1500 psi pump in pressure with full string. Swabbed well with no gas to surface. Bottomhole gauges report 500 psi bottomhoIe pressure. Either no zone or very tight formation. Closed DHSV and opened MCV to reverse out well. Valves functioned property. Pulled out of the hole and cycled DHSVon surface with normal function. Gauge data confirmec MCVand DHSV cycled property down hole, r Run'" No problems with make up of BHA DHSV opened to lock open position at +/- 3400 ft. = 1800 psi Phyd Opened possibly from surge pressures while nmning in or loss of nitrogen reference pressure Confirmed DHSV in open position and continued trip in CirculatBd string ønd fired guns confirming DHSV in the open position Normal MCV operation to spot cushion, no clear surface indication DHSV re-opened after spotting. Injec:lød into the form8Iion to confirm valve open. Injection pressure +/- 1400 psi applied surface confirm valve open and tight formation Swabbed well and gas to surface with reported 400 psi bottomhole pressure from gauges. Tight??? Pumped treatment and swabbed well attempting to stimulate zone. No improvement, 0 psi surface flowing pressure, Reversed out well with single shot reversing valve, repositioned packer below perforations to circulate well PuHed out of the hole and DHSV in closed position confirming valve function down hole. Opened same to confirm no gas below valve. DHSV functioned at +1- 1200 psi indication of low or loss of nitrogen reference downhole or during trip out of the hole. '~ with guns and with out DHSV and MCV Spotted cushion with packer unset, set packer and trapped diesel cushion Fired guns and cleaned uplflowed well with no problems Opened single shot reversing valve to reverse out tubing All Runs A vary capable and cooperative rig CffM made operations much easier than expectvd. TCP personnel were very helpful in ensuring a successful operation. Page 4 of5 . . Suggested Improvements for futurø operaUons: r-- Suggested PTS 1ICtIo1I$: A complete and extønsive pre-job meeting wi\tl1he client should be done prior to equipment selection and test design. Preliminary pre-job meeting information led to equipment and test design for a 3 zone campaign @ 735(). 7650 ft wi\tI expected BHT of 150 deg F and BHP of 4000 psi dry gas Actual operations were conducted at shallower depths and lower temperatures and pressures 1han anticipated, Downhole tool set up specífically rupture discs (ratings too high for upper zones) should be examined closely. Equipment selection and set up should be based on all possible downhole conditions ~. Formation pressures and temperatures, contingency plans such as swabbing and stimùlation operations Investigate rig capabilities, speoificaJIy pump system, to design efIic:ient operations procecÌures. Applied annulus and Wbing pressures to cycle downhole valves required rerouting during operation to appty. maintain and monitor pressures, Required additional work by rig craws, Investigate rig facilities to improve equipment handling, rig up, operation and on site maintenance. Additional support equipment would have lessened rig support. Investigate climatic conditions and prepare contingency plans for equipment storage, maintenance and handling. Temperature effected flowhead causing delay in rig up Attachments: Downhole gauge data Surface pressure data Merged surface and downhole data Sequence of events Failure reports § .P1oœ and data pack Plots IPIots r- r--. Page 5 of5 I" J'" ¿~¥ FÞ1'1; .~ ."", .... . , OPERATIONS REPORT DST ~5 , .JS5()'- J7d~~ ~MD Client: Type of operation: Well: Formation: Aurora Gas DSTITCPIWT Three Mile Creek Unit #1 Tsuga Date: 17 Jan - 20 Jan 05 Rig: Nabors 129 Client Rep.: J. Keener Base: Anchorage PTS PERSONNEL: R. Hoff A. Gomez G. Grimes I""' ¿i....~ ...F..11~ ; .~..~ II. OPERA TIONS REPORT DST CLIENT: TYPE OF OPERATION WELL Aurora Gas DST/TCP/WT Three Mile Creek Unit #1 Date: Well: Rig Base: 17 Jan - 20 Jan 05 3 Mile Creek Nabors 129 Anchorage DATE I EVENTS TIME 17-Jan DST Run 5 TCP 0745 Safety meeting pre-guns rig up 0820 Starting Schlumberger guns rîg up 0945 Slart PTS-DST tools rig up 1050 RA Sub connected. Continue RIH. 1430 Running correlation. 1600 Spacing out, Pick up = 75k #. Slack off = 57k', 1700 Circulating 25 bls of diesel. 1750 Set packer @ 3400 ft MD 1800 Break off top drive 1830 Test packer seat 500 psi okay 1830-2130 Rig up surface equipment and test lines 2145 Gun pressure sequence test 2200 Fire guns 2105 Open well to flow 2105-2400 Clean up and flow well 18-Jan 0000-0400 Flow well 0400 Surface shut in 0900-1600 Flow well 1600 Surface shut in 19-Jan 0715 WHP= 1449 pSI 0716 Open well to flow through 12/64" adj choke 0726 Flow well through 16/64" adj. choke. 0730 Flow wen through 20/64" adj. choke, 0743 Flow well through 26t64" adj, choke 0803 Flow well through 32/64" adj, choke. 1246 Shut in well at choke manifold. 1340 Burst single shot disc 3600 psi applied annulus pressure, start reverse out string 1615 End reverse circulation of tubing 1700 Unseat the packer, reverse circulate well 1830 End circulation, layout flow head 1900 Start trip out of the hole 20-Jan 0015 At drill collars layout same 0200 All tools out of the hole, start layíng out guns 0300 End of Job PTS Re . Hoff/Lavine/Grimes Si nature Date: . J, Keener Jan 17-20105 Results Tsuga TMatch 36.1 (hr]--1 3530'-3545',3556'-3566', 3662'-36n', 3683'-3703' MD PMatch 5.29E-8 (psi2lcpJ**-1 SL2-Q02 C 0.0388 STB/psi 3380 ft MD skin 5.7 Delta P Skin 458.656 psi Pi 1619 psía k.h 69 md.ft k 1.5 md Rinv 150 ft Test. Vol. 1.04665E+5 Barrels þ 1/ ~ Company Aurora Well Three Mile Creek Test date I time Formation interval Perforated interval Gauge type I # Gauge depth TEST TYPE Standard Porosity Phi (%) Well Radius rw Pay Zone h Connate Water (%) Water Salt (ppm) Rock compr. Reservoir T ReservoirP 18 0.354167 ft 46ft 52 1 ??oo 3E-6 psi-1 SO OF 1600 psia FLUID TYPE Gas Gas Gas Gravity 0.565 Pseudo-Critical P 680.536 psis Pseudo-Critical T 340.81 OR Sour gas composition Hydrogen sulphide 0 Carbon dioxide 0 Nitrogen 0.01 Water Safinhy,ppm 1??oo WGR 102.7 bbllMMcf Reservoir T SO of Reservoir P 1600 psia Properties @ Re5eIVoir T&P Gas Z 0.830891 Mug 0.0145452 cp Bg 0.00792513 cf/scf Cg 6.97885E-4 psi-1 Rhog 0.0873175 glee Water Rsw 13.9785 cflbbl Bw 1.00017 BlSTB Cw 3.34873E-6 psi-1 Muw 0.967737 cp RIlow 1.00752 glee Total Compr. ct 3.17081E-4 psi-1 Selected Model Model Option Standard Model Well Storage + Skin Reservoir Homogeneous Boundary Infinite SOphIr 03.01.oø - 01-2001I--' DST4 ys 1 Field Beluga Test Name I # DST Zone#4 R. Vlllamizar - PTS Colombia Page 1 .Y Hist tings 'sys 1 Company Aurora Field Beluga Well Three Mile Creek Test Name / # DST Zone#4 Date ToD FP# Gas Rate Duration MsdlD hr 17101/2005 09:39:00 1 0 12.234 17101/2005 21 :53:02 2 1500 6.13769 18/01/2005 04:01:18 3 0 4.05024 18/01/2005 08:04:19 4 200 0.578088 18/01/2005 08:39:00 5 410 1.25 18/01/2005 09:54:00 6 1180 1.61001 18/01/2005 11 :30:36 7 1400 1.23956 18101/2005 12:44:58 8 1580 2.03207 18/01/2005 14:46:54 9 1700 1.312 18/01/2005 16:05:37 10 0 15.1934 19101/2005 07:17:13 11 1527 5.49489 19101/2005 12:46:55 12 0 3.43404 SIIp/ir v3.01.0I·01_~DS1'4 R. VHlamlzar - PTS Colombia Paae 2 Company Aurora Well Thme Mile Creek Test Name I #: DST Zone#4 3500 Pmssum Ges Rate 1-1 'ù m "Ç RUNS-Tubî #2 Rate 0 Rate 1700 MscflD 407.967 Pi 1619 0.1 Line (RUNS-Tubl build-up #2) From 38.4494 hr To 43.40221u 2. î 7195E+ 7 Intercept 2.25895E+8 ResefIfoir Boundary 5.28E-8 k.h 69 md.ft k 1.5 md 1619.2 psia 5.63 Delta P Skin 452.033 psi Selected Mode! Model Standard Model + Skin Results TMatch 36.1 PMatd1 C skin Delta P Skin Pi Ich It: Rim' Test. Vol. 0.0388 5.1 458.656 1619 69 1.5md 150ft 1.04665E+5 Barrels s.phir vMí,OII-OI-2005In_.io1t!:.sn R Villamizar· PTS Colombia Page 3 1E.g "ã: 1E+a-: u ('J ]. ã: E ~ ~ Ii 1E+~ ã: ~ 1E+6 I 1E.... Log ot Company Aurora Welt Three Mile Creek I· I I t I II} 1E-3 I It IIIII 0.01 RUN5- Tub1 build-up #2 Rate 0 Mscf/O Rate Change 1700 Mscf/O P@dt=O 407.967 psia Pi 1619 psia Smoothing 0.1 Selected Model Model Option Standard Model Welt Storage + Skin Reservoir Homogeneous Boundary Infinite Results TMatch 36.1 (hr)** -1 PMatch 5.29E-8 [psi2Jcp)....-1 C 0.0388 STBlpsi skin 5.7 Delta P Skin 458.656 psi Pi 1619 psia k.h 69 md.ft k 1.5 md Rinv 150 ft Test. Vol. 1.04665E+5 Barrels SaIir t4111.G11·01-2005~DST4 Field Beluga Test Name I # OST Zone#4 , I 1'11111 0.1 dt [hr) R. ViHamlzar - PTS Colombia I I t t tlI 1 . ys 1 t Illtlt '10 I II I' 1()0 Page 4 UE+8 Company Aurora Well Three Mile Creek lIE.¡.ì RUN5- Tub1 #2 Rate 0 Rate 1100 Mscf/D 407.967 psia Pi 1519 psia 0.1 Selected Model Model Standard Model + Skin Reservoir Results TMatch 36.1 PMatch C skin Daita P Skin Pi k.h k Rift\! Test Vol. Saphi, v3.01.03·01·2005In_OOT4 0.0388 5.7 458.656 1619 59 1.5 fI'Id 150 ft 1.04665£:+5 Barrels 1 Field Test Name I 1# DST Zone#4 time lírle 38.4494I1r To 43.402211r 2. 17795£:+ 7 2.05152£:+8 5.28£:--8 k.h 59 k 1.5 md 1619.2 psis 5.63 Delta P Skin 452.033 R. VlllamiZar - PTS Colombia Paae 5 ./ Com Company Aurora Well Three Mile Creek s1 Field Beluga Test Name I # D5T Zone#4 The simulated model of reservoir that fit graphicaly better with respect to test data was two porosity reservoir model. However this kind of tests are short time duration and the investigation ratio is low, therefore it is too soon to find out exactly the type of reservoir model. Another important point is that pressure has an abnormal trend at 1.5 hours after buildup started generating a deep fa" in derivative plot before it reachs radial flow zone. This is a source of error since it could affect the global shape of derivative plot. Therefore a basic homogeneous reservoir model acting infinite was used. The main results of the interpretation are: K: 1.5md 5:5.7 C : 0.0388 STBlpsi Ratio of investigation: 150 ft Pi: 1619 psi at 3380 ft - gauge depth (Extrapolating to mid point of perforations - 3617 ft - with gas gradient = 0.0377 psiIft, then Pi = 1628 psi) SopNr ¥lU1.G1- 01-2110I5 -..-. DST4 R. VlllamiZar- PTS Colombia PageS .. STATE OF ALASKA . ALAYA OIL AND GAS CONSERVATION COM SION GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: l.::J Initial U Annual U Special 1b. Type Test: U Stabilized U Non Stabilized l.::J Multipoint D Constant Time D Isochronal D Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Aurora Gas, LLC May 20.2005 204-183 3. Address: 6. Date TD Reached: 12. API Number: 1400 West Benson Blvd, Suite 410 Anchorage AK 99503 December 24, 2004 50- 283-20108-00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 1504' FNL, 148' FWL, Sec 35, T35N, R11W, SM 332' AMSL GL@ 315.3' Three Mile Creek Unit-1 Top of Productive Horizon: Ot)1 8. Plug Back Depth(MD+ TVD): 14. Field/Pool(s): 3530' MD 1420' FNl, 646' FE~~'íw"',:} 2 5410' MD, 5243' TVC Three Mile Creek Total Depth: S 9. Total Depth (MD + TVD): 8185'MD 1540' FNL, 686' Fel, 8185' MD, 8,015.6' TVD 4b, Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 286393.49 y- 2624191.03 Zone- 4 ADL 388233 TPI: x- 285825.54 y- 2624413.82 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 285558.82 y- 2624170.42 Zone- 4 Multi Packer Selective Zone 17. Casing Size Weight per foot, lb. I.D. in inches Set at ft. 19. Perforations: From To 7" 26# 6.276 8113' 2570'-3317', Gross Interval-111' 18. Tubing Size Weight per foot, lb. I.D. in inches Set at ft. 3-1/2" 9.3# 2.992 -2501' 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 2501' & 3455' NA None 0.562 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): D Tubing D Casing 73 FO 1 ,196 psia @ Datum 2,796' TVDSS 14.65 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: I % CO2: % N2: % H2S: Prover: I Meter Run: I Taps: 2,926' 2,796 0 1.2 0 Daniel Sr. 4.061" Flange 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice Size (in.) Size (in.) psig Hw FO psig FO psig FO Hr. 1. 4 X 1-1/2" 1,134 50 .75 hrs. 2. 4 X 1-1/2" 1,092 45 1.5 hrs. 3. 4 X 1-1/2" 1,036 40 .75 hrs. 4. 4 X 1-1/2" 979 35 .5 hrs. 5. X Basic Coefficient Pressure Flow Temp. Gravity Factor Super Compo Rate of Flow No. (24-Hour) -I hwPm Pm Factor Fg Factor Q1 Mcfd Fb or Fp Ft Fpv 1. 70.68 Calculated using Daniel Sr. 886 2. 71.3 Orifice Meter Readings 1,372 3. 71.6 1,917 4. 71.3 2,341 5. Temperature for Separator for Flowing No. Pr Tr z Gas Fluid T Gg G 1. 2. 3. Critical Pressure 4. Critical Temperature 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SIDE Submit in Duplicate Pc 1,125 pc2 1 ,265,625. 1,196 pf 1,430,416 No. pt pe pc2_pf Pw ~ PC2_~ Ps PS2 pf _PS2 1. 1,067 1,138,489 127,136 1,134 1,285,956 144,460 2. 1,025 1,050,625 215,000 1,092 1,119,464 310,952 3. 970 940,900 324,725 1,036 1,073,296 357,120 4. 918 842,724 422,901 979 958,441 471,975 5. 25. AOF (Mcfd) 5,940 Remarks: AOF calculated using Ryder Scott Software. n 0.824935 I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Øð~ Title I11t/. ¿::¡'~tl1r;"'I1~ ð- 0f~h'¡\'1;Ç Date G77¥"7 ¡ DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero pSia Fb Basic orifice factor Mcfd/ -I hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= ~ dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psi a Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 pSia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 Three Mile Creek Unit October 27, 2006 Page 2 • Additionally, it is our understanding that the AOGCC Conservation Order No. 558, establishing rules for the Three Mile Creek Beluga Gas Pool, will remain in effect. Aurora Gas, LLC intends on continuing operations in accordance with these pool rules. Should circumstances improve in the future, we may revisit the possibility of unitization. Thank you for your time and attention to this matter. Should you have questions, please contact Mr. J. Edward (Ed) Jones at the Houston telephone number below. Sincerely, ~~~ Bruce D. Webb Manager, Land and Regulatory Affairs Concurrence by Forest Oil Corporation: ~~w r ,@ }} ,~~~ mes D. Arlington Land Manager Cc: Mr. John K. Norman Chairman Alaska Oil and Gas Conservation Commission 333 W. 7tt, Avenue, Suite 100 Anchorage, AK 99501 Mr. Matt W. Rader ~,Tatural Resource Specialist State of Alaska Division of Oil and Gas 550 W. 7th Avenue, Suite 800 Anchorage, AK 99501-3560