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Home My WebLink About205-179Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~(~ ~- ~ ~ ~ Weil History File identifier Organizing (done> RESCAN ^ Color Items: ~Greyscale Items: ^ Poor Quality Originals: ^ Two-sided IIIIIIIIIIIIIIIIIII DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: R,.~a~~,.aea uumiiuiiiuiu OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: ^ Other.: ^ Other: NOTES: BY: ~ Mari Date: ~ ('~'~ n ~ !sl r Y ~~ Project Proofing III Ilfl~l 11111 II III BY: Maria Date: ~~ (~./~ ~ /s/ 1 ~ ~~ -T Scanning Preparation x 30 = + =TOTAL PAGES__~ (Count does not include cover sheet) BY: ~ Mari Date: ~ ~'. /~~ /s/ ~/'~ Production Scanning Stage 1 Page Count from Scanned File: ~~ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~ YES NO BY: Maria Date: ~I ~' ~~ !s/ ~~ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: !s! Scanning is complete at this point unless rescanning is required. III II'I~) I11II I I III ReScanned III IIlI1II1III IIIII BY: Maria Date: ls/ Comments about this file: Quality Checked III 111111 III 11'1111 10/6/2005 Well History File Cover Page.doc rw ^~w ^ ^ rr~wr. ..ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs_Liserts\Microfilm_Marker.doc Page 1 of 1 Okland, Howard D (DOA) From: Maunder, Thomas E (DOA) Sent; Monday, January 07, 2008 1:35 PM To: Ed Jones Cc: Okland, Howard D (DOA); 'Bruce D Webb' Subject: RE: Expired Drilling Permits Ed, If wells will be drilled, then new permits will need to be obtained. Since the existing permits have expired, we will append an "XX" to the Weil name in our records. You may use the same well names if desired. New API numbers will be issued as part of the permit process. Hopefully you wilt be able to drill the prospects in 2008. Call or message with any questions. Tom Maunder, PE AOGCC From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Monday, January 07, 2008 1:31 PM To: Maunder, Thomas E (DOA) Cc: Okland, Howard D (DOA); 'Bruce D Webb' Subject: RE: Expired Drilling Permits Tom, Locations were built (partial at Kaloa #3) and conductor was driven to 80' or so for both wc_lls . Otherwise, no work was done (i.e., we did not rig up a drilling rig on either well). We still have plans to drib both, possible in 2008--pisses let me know what we need to do (re-apply for the drilling permits before drilling; but anything else?). Thanks, Ed From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, January 07, 2008 4:13 PM To: Ed Jones Cc: Howard D Okland Subject: Expired Drilling Permits Ed, ! 1 q Our records show that the drilling permits for Three Mile Creek #3 (205-~'7) and Kaloa #3 (205-108) have expired. The expiration dates were November 5, 2007 and August 17, 2007 respectively. Would you please confirm that no work was done on either of these wells? Thanks in advance, Tom Maunder, PE AOGCC 1 /7/2008 ,.~ _ ~ ~ ~ FRANK H. MURKOWSK/ GOVERNOR - ~ , ~~ OII/ ~ ~S 333 W. T" AVENUE, SUITE 100 COI~TSER~'A'1`IO1Q CO1rII-IISSIOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 27&7542 J. Edward Jones Executive Vice President of Operations Aurora Gas, LLC 1400 W. Benson Blvd, Ste 410 Anchorage, AK 99503 Re: Three Mile Creek Unit No. 3 Aurora Gas, LLC Permit No: 205-179 Surface Location: 1244' FSL, 367 FEL, Sec. 34, T 13N, R 11 W, SM Bottomhole Location: 2287' FSL, 1538' FEL, Sec. 34, T13N, R 11 W, SM Dear Mr. Jones: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission. reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty- four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659- 3607 (pager). DATED this~day of November, 2005 cc: Department of Fish 8s Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. ~;nairman STATE OF ALASKA AL, OIL AND GAS CONSERVATION CO SION PERMIT TO DRILL 20 AAC 25.005 :~ V~;) l~ 1a. Type of Work: Drill ~ Redrill Re-entry ~ 1b. Current Well Class: Exploratory Development Oil ~ Multiple Zone Q Stratigraphic Test ~ Service ~ Development Gas Q Single Zone 2. Operator Name: Aurora Gas, LLC 5. Bond: Blanket ~ Single Well Bond No. NZS 429815 ~ 11. Well Name and Number: Three Mile Creek Unit No. 3 3. Address: 1400 W. Benson Blvd, Ste 410, Anchorage, AK 99503 6. Proposed Depth: MD: 5319' - TVD: 4900' 12. Field/Pool(s): 4a. Location of Well (Governmental Section): Surface: ' 1244'FSL, 367~FEL, Sec 34, T13N, R11W, SM ~ 7. Property Designation: ,_ ADL 3,9D5fU'~ ~~~~~~~ ~ l~~ i~~~~ Three Mile Creek Unit Top of Productive Horizon: 2263' FSL,1386' FEL, Sec 34, T13N, R11 W, SM 8. Land Use Permit: Unit Operating Agreement 13. Approximate Spud Date: 15-Nov-05 Total Depth: 2287 FSL, 1538' FEL, Sec 34, T13N, R11 W, SM 9. Acres in Property: 8080 acres in Three Mile Creek Unit 14. Distance to Nearest~~ Property: ~ ~~~;_„~r n 4b. Location of Well (State Base Plane Coordinates): NAD 27 Surface:x- 285835 ~ 2621670 ' Zone- Y- 4 10. KB Elevation 302' MLLW (Height above GL): 15' 15. Distance eares~Wel ~ ~~ ~~ `n ~~~ Within Pool: 16. Deviated wells: Kickoff depth: _ _ feet Maximum Hole An le: yx~r~ 9 /~Dfr.a. ,35 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) ~~~' ,~,~- p •g Downhole: 2597 psig Surface: 2058 s~ 18. Casing Program: Size Specifications Setting Depth Top Bottom Quantity of Cement c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 13 3/8" 72 K-55 Welded 80 15 15 95 95 Drilled and Driven 12 1/4" 9 5/8" 36 J-55 BTC 1000 surface surface 1000 975 120 bbls @ 100 % OH Excess 7 7/8" 5 1/2" 15.5 J-55 BTC 5319 surface surface 5319 4900 216 bbls @ 25% OH Excess 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured}: Casing Length Size Cement Volume MD TVD Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee ~ BOP Sketch Drilling Program ~ Time v. Depth Plot ~ Shallow Hazard Analysis Property Plat ~ Diverfer Sketch ~ Seabed Report ~ Drilling Fluid Program Q 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name J. Edward Jones Title Executive Vice President of Operations Signature Phone 907-277-1003 Date 29-Sep-05 Commission Use Only Permit to Drill ~p Number: Z~s~ ~ ~ / API Number: 50_ Z$ 3 - Z17 l ~ ~ "~~ Permit Approval Date: ~, • (~ See cover letter for other requirements. Conditions of approval S ple required Yes ~ No Mud log required Yes ~ No dro sulfide measures Yes ~ No Directional survey required Yes ~ No Other. S~G~~, ~`Uv~~`CJ . ~~ APPROVED BY Approv d by: .. THE COMMISSION Date: ~!v ~~ 9 Form -401 ev' ed 06/2004 ~ G I ~ ~ L Submit inDuplicate • • Auf•ora Gas, LLC. Drilling Program: Three Mile Creek Unit No. 3 TMCUNo. 3 Drilling Program 1. File and insure all necessary permits and applications are in place. 2. Mob in rig and RU. 13 3/8" conductor has been pre-installed. Install 13 5/8" 5M starting head. 3. Rig up diverter and mud loggers. Test and calibrate all PVT and gas ~ sensor equipment. Provide 24 hr notice to AOGCC inspectors for chance to witness diverter test. 4. Notify AOGCC and pertinent agencies when ready to start drilling operations. 5. Prepare spud mud system using recycled mud from previous drilling project, weight up to ~10 ppg. Load, strap and drift 9 5/8" surface casing. 6. PU 7 7/8" bit and drill pilot hole to 1000 ft; using 6 1/4" stabilized BHA. Watch for gas in shallow coals and sands. Attempt to TD casing landing point in siltstone or claystone, i.e. avoid surface TD in coal bed. If possible, plan TD to correlate with casing tally so when landed, cementing head is at floor level. 7. POOH LD 7 7/8" pilot hole BHA and PU 12 '/4" stabilized BHA or hole opener. Open 7 7/8" surface hole to 12'/4' to TD achieved in step 6. 8. Condition hole for running 9 5/8" surface casing, POOH, LD 12 1/4" BHA. 9. Run and cement (new) 9 5/8" 36 #!ft, K-55 BTC surtace casing at 1000' installing 1 centralizer /joint centered on 1st 4 joints above shoe, and 1 centralizer every 2nd joint there after, cement to surtace. ~~Shoe joint connection at float shoe and float collar must be Baker-Locked. Cementing will be du_ al stage with a i°t\~\~ ~~„~~~~mechanical stage tool set at 500 ft using 14.5 ppg gas block enhanced Type I cement at 100% excess volume for the bottom stage and 12.0 ppg enhanced Type I cement at 100% excess volume for the top stage. 10. RD cementers, nipple down diverter, cut casing and install 11" 3000 psi wellhead A section. 11. RU and test 11" 3M BOP stack and 5M choke manifold. Test stack and surface equipment to 3000 psi. Pressure test casing to 1500 psi for 15 minutes or as required on approved Permit to Drill. - 12. PU 8 %" bit, bit sub and RIH w/ 6 '/" collars, drill out float equipment and shoe. Condition /treat mud as needed for cement contamination, drill 20' OH. Pull back into shoe and perform FIT to 15.0 ppg MWE with {ow volume test pump. Record results. TOH, LD 6'/a" collars while POOH. 13. PU 4 3/4' directional drilling assembly w/ 7 7/8" bit, motor and DIR MWD assembly, non-mag DC's, jars and HWDP as specified by directional hand. 14. RIH and directionally drill 7 7/8" pilot hole to 5319'~MD (4900' TVD) TD per directional plan, or other as directed by Aurora Gas geologist. While drilling, load tally and drift Toad 5'/2" casing on racks. Monitor well and volumes carefully. Be prepared to shut well in and weight up immediately if flow or excessive gas build up in mud is noticed. Anticipated mud weights required are 9.5 - 10 ppg.'Do not ., exceed the minimium rock strength determined in step 12. Attempt to TD 7 7/8" Aurora Gus LLC.. Page 1 of 1 ~ Rev- 2.0 • Aurora Gas, ILC. TMC'tI No. 3 Dr•illtrzg Program production hole to correlate with casing tally so when landing pipe, cementing head is at floor level. 15. Condition hole, short trip and prepare for running wireline logs. 16. POOH, rack back drillstring and RU wireline BOP's and lubricator and logging tools. Log 9-5/8" cased hole section w/gamma ray sensor, Log OH section with logging suite as directed by Aurora Gas. RD wireline. 17. RIH w/ 7 7/8" drilling assembly to TD and condition hole for running 5'/2" casing. Ensure cementing head has proper connections or proper cross-over is available for quick rig up. 18. POOH while laying down drillpipe and BHA, RU to run casing. Verify cementer's equipment is ready. 19. Change out pipe rams for 5 %2" casing. 20. Run 5 '/2" 15.5# BTC K-55 casing installing 1 centralizer per joint centered on 1st 4 joints above shoe, and 1 centralizer every 2nd joint there after to 1 jt inside surface casing shoe. Install centralizers every 3rd joint there-after to surface. Shoe joint connection at float shoe and float collar must be Baker-Locked. While running casing, fill every 3rd joint. Be prepared to RU and wash to bottom. 21. RU cementers, cement per attached cementing program from TD back to `` surface. f A 12.7 ppg lead and 15.8 ppg Class G tail cement system will be used. Tail slurry to be of sufficient volume to cover 5 '/2" CH x 7 7/8" OH annulus to 1500 ft. See attached cementing info for preliminary volume estimates. While pumping cement, reciprocate pipe a minimum of 20 feet until cement goes around the shoe. Land casing within 2 - 5 ft of bottom if possible. Displace cement w/ brine to minimize contamination on clean-out. When displacement is finished, bump plug, check floats, drain and wash down stack, check annulus for flow, center casing w/ annular preventer and WOC. 22. RD cementers, nipple down stack, land casing in slips and cut casing. 23. Install 11" X 7 1/16" tubing spool, 7 1/16" X 11" DSA, mud cross and reinstall BOP stack. Pressure test BOP and surface equipment to 3000 psi. Pressure test casing to 2000 psi for 15 minutes and record results. 24. C/O 5'12" rams to 2 7/8" for workstring. PU bit and casing scraper and RIH with 2 7/$" tubing to top of float collar. After circulating out cement debris, clean brine for perforating by running through centrifuge and filtering. POOH, LD bit and casing scraper. Strap tubing on TOH to validate tally. 25. PU wireline BOP's, lubricator, pressure test all. PU perforating guns, RIH to depth as determined from OH logs and perforate zones of interest. Watch for pressures in casing after shooting. POOH, LD perf gun, RD wireline. 26. RU and RIH with test packer assembly on workstring. Connect to surface flow test equipment. RU and swab in well for flow test, record results. Kill well. 27. Repeat steps 24 and 25 until all zones of interest have been evaluated for production. Aurora Gas I.LC. Page 2 pf' 10 Rev. 2.0 • .4urnra Gas, LLC. TMCU No. 3 Drillir2g Program 28. POOH. 29. Pick up completion assembly which will use retrievable type packers, sand exclusion screens, sliding sleeves and other jewelry as necessary. Exact configuration to be determined by test results. Please see attached well schematic for proposed completion scenario. Packer is to be 75 ft minimum above upper-most screen. RIH with completion and set completion at appropriate depth. POOH. 30. RIH with 2 7l8" 6.5# EUE 8rd production tubing and seal assembly, space out and stab into packer, hang off in tubing head and lock down. Install blanking plug in profile nipple at bottom of tubing. Pressure test tubing to 2000 psi, pull blanking plug. 31. RU and swab in well, allow to clean up, record rates and pressures then shut in. 32. Install BPV at surface, nipple down and remove BOP stack. Install wellhead tree. RD and remove all rig equipment. 33. Prepare site for well testing and surface production facilities. 34. File completion reports with proper agencies. Site Access: The TMCU No. 3 well will be accessible via a new gravel road that is approximately 100 feet in length and connected to Superior Road. Rig: Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the TMCU No. 3 well. The Alaska Oil and Gas Conservation Commission has information on this rig and equipment as it has been in use for the last (3) years on other Aurora Gas operations. The pits, BOP system and mud equipment configuration will be the same as that used for previous work. Survey Program: The 12 '/" surface hole will be drilled vertically to 500" and then drilled directionally to 1000 ft MD." The survey will be acquired while drilling the 7 7l8" pilot hole. The 7 7/8" production hole will be drilled directionally. For all directional work, weltbore surveys will be taken at maximum of 100 ft intervals, per AAC 25.050 f~ (a)(1) with intervals likely to be surveyed more frequent while steering. Logging Program: Aurora will have mud loggers on site for the duration of drilling activities and Schlumberger will provide wireline logging services. A gamma ray fog will be run across the surface casing interval. Proposed logs at this time are: TMCU No. 3 Proposed Logging Program Well Section De the ft OH CH Lo T e 12 1J4" Surface 0 -1000 NJA: No open-hole logs planned for surface at this time. GR onl in cased hole. 7 7/8" Production 1000 - Platform Express: Array Induction, Compensated / Hole 5319 Neutron, Litho-Density, SP, GR, DSI and FMI. Also MDT and Sidewall cores. 5 1!2" Int. Csg 1000 - GR/CBL/CCL 5319 Aurora Gar LLC. Page 3 of ~ 10 Re~~. 2.0 Aurora Gas, LLC. ~ T,~%1CII No. 3 Dr•illiia Pr•o rarn Surface - TD 0 - 5319 Mud Lo in Services BOP Equipment: Aurora Gas, LLC will use the same BOP system they have been using for the last (3) years which will consist of the following: 12 1!4" surface ho{e: While drilling the 12 1l4" surface hole, a 13 5/8" 5M annular w/ 13 5/8" diverter spool and 10"diverter line will be used. Information on this system is already on file at the AOGCC. Per 20 AAC 25.035 (c)(1)(A) there is a requirement that the diverter line outlet size be at least 16" in diameter or (B) at least as large as the hole size being drilled. Since Aurora does not have access to a diverter spool with an outlet line ID which fulfills this requirement, a 7 7/8" pilot hole will be drilled to 1000' and then opened to 12'/" prior to running 9 5/8" casing. ,/ 7 7/8" Production Hole: An 11" 3000 PSI WP Schafco (Shaffer Equivalent) BOP system will be used which is configured with an 11" 3000 PSI WP annular preventer, (1) 3000 PSI WP double gate with a set of pipe rams installed sized to fit the pipe being run and a set of blind rams and (1) 11" 3000 PSI WP rated drilling spool. BOP tests will be performed to 3000 psi. The annular preventer will be tested to 1500 psi. Again, this is the same equipment Aurora has been using all along and information on the system is on file at the AOGCC. Pressure Considerations: 12 1/4" surface hole: The maximum anticipated surface pressure (MASP) for this hole section is based on a 10 ppg formation pressure equivalent at 975' TVD. This results in ~ ~. Once the 9 5/8" casing is set, the MASP would be the frac gradient at the shoe which is estimated at 17 ppg equivalent less a gas column. The MASP for this situation is 761 psi. 7 7/8" Production Hole: Based on records from the original TMCU No. 1, a pressure - gradient of 0.46 to 0.53 psi/ft can be expected at TD. Using this information, the maximum anticipated bottom-hole pressure to be encountered would be expected at TD, 4900' TVD, with potential formation pressure of 2597 psi. Maximum anticipated surface pressure "MASP" can be calculated by subtracting the gas gradient of .11 psi/ft from pore pressure gradient of .53 psi / ft and multiplying by the total TVD depth. =>MASP = (.53 - .11) * 4900 = 2058 psi Drilling Fluids: The drilling fluids are being furnished by Baroid Drilling Fluids who has extensive experience with drilling activities in this area. An experienced mud engineer will be on site at all times while drilling to monitor rheologies and make recommendations. Surface Hole Recommendations Mud Type: 6%KCI, EZ Mud, or recycled mud from previous wells. Aurora Gas LLC'. t'age 4 of 10 Rev. 2.0 • Aurora Gas, L,LC. Properties: • TMCU No. 3 Drilling Program Density Viscosity Plastic Viscosity Yield Point API FL pH 0 - 1000' 10.0 ' 45 - 65 16 - 23 20 - 30 <5 8.5-9.5 System Formulation: 6°t°KCI, EZ Mud (if no used mud is available) Product Concentration Water 0.905 bbl KCI 19.8 ppb (30K chlorides} KOH 0.2 ppb (9 pH) BARAZAN D 1.25-1.5 ppb (as required 25 YP) EZ MUD DP 0.75 ppb (begin with .2 ppb) PAC-L or DEXTRID LT 1.5 to 2.0 ppb ALDACIDE G 0.1 ppb Barite As/if needed BARACOR 700 1 ppb BARASCV D 0.5 ppb add as the well spuds) • Mix in order as listed • Add polymers slowly to minimize fisheyes Recycle fluids as appropriate. No over pressured zones were encountered nor any major hole problems were seen on TMCU No. 1. Occasional short trips will be made to help alleviate any tight hole and hole cleaning problems. Production Hole Recommendations Mud Type: 6%KCI, EZ Mud Properties. Density Viscosit Plastic Viscosity Yield Point API FL pH 1000 - 5319' 9.8 - 10.0' 40-50 6 - 15 13 - 25 <5 8.5-9.5 System Formulation: 6%KCI, EZ Mud Product Concentration Water 0.905 bbl KCI 19.8 ppb (30K chlorides) KOH 0.2 ppb (9 pH) Barazan D 1.25 ppb (as required 13-20 YP) Dextrid 2-3 ppb EZ Mud DP 0.75 ppb Aldacide G 0.1 ppb Baroid as/if needed Baracor 700 1 ppb Barascav D 0.5 b maintain er dilution rate Drilling Fluid Handling System: Shale Shaker, Mud Cleaner, Centrifuge, PVT monitors ~r,~~ ~~~~S~v f/I Casing /Cementing Program: All casing is new. Analysis (attached) indicates casing program as designed provides adequate safety factors for this well. AI{ casing strings with the exception of the 13 3/8" conductor will be cemented in place using industry Aurora Gas .LI.C. Page .i of Ill Rev. 2.0 ,4urora Gas, LLC. ~ TMC'U No. 3 Drilling Pr~ogra~n standard casing cementing techniques utilizing a casing shoe, float equipment, top and bottom wiper plugs and centralizers installed as needed. TMCU No. 3, 13 3/8" 72# K-55 Conductor Analvsis and Cementing Program The conductor for TMCU No. 2 will be installed by driving the 13 3/8" pipe to 95' MD or drilled and driven to this depth. Joints will welded together and a drive shoe will be welded to the bottom joint. No cementing is required. TMCU No. 3, 9 5/8" 36# J-55 BTC Surface Casing Analvsis and Cementing Program The 9 5/8" surface casing will be cemented from the proposed setting depth of 1000' MD to surface with a dual s~ tag*e cement job with a manual stage tool set at 500'. A 14.5 ppg Type I, gas block enhanced cement system will be used for the bottom stage with a 12 ppg Type f upper stage. Where: 12 1/4" OH Capacity = .1458 bbllft 9 5I8" 36# Csg x 12 1/4" OH capacity = .0558 bbl / ft 9 5/8" 36# Csg capacity = .0773 bbl/ft OH x Csg: 500 ft x .0558 bbl / ft x 2 (100 % excess) = 55.8 bbls » Shoe Jt: 38ft x .0773 bbl/ft = 2.94 bbls `~~' Actual volumes to be re-calculated at time of running casing due to potential variation in actual depth from planned. The surface cement system to utilize alias-Block type additive to minimize potential for gas entrainment or channeling. Cement System Weight (ppg) Volume Required Bottom -Gas-Block enhanced Type I 14.5 60 bbls @ 100% excess'` Top -enhanced Type { 12 60 bbls @ 100% excess r/ Please see attached 9 5/8" surtace casing ana/ysis and specifications. TMCU No. 3, 5 1/2" 15.5# J-55 BTC Production Casing Cementing Program The 5 1/2" production casing will be cemented in fully from the proposed set depth of 5319' MD to surface. A 700', 12.7 ppg lead "G" cement followed with 800' of 13ppg "G" cement and a 15.8 ppg "G" tail cement system will be used. This program is designed to insure the intended perforating /production intervals are isolated with 15.8 ppg "G" cement while the surface casing shoe is covered with a fighter cement still of good compressive strength without breaking down the surface shoe. Where: ,~ 5 %" 15.5# csg capacity = .0238 bbl/ft Aurora Gas LLC. Page 6 of ~ t (J Rev. 2. ~ • • Aurora Gas, LLC. 71t~fCUNo. 3 Drilling Program 5 %"15.5# csg X 7 7/8" OH capacify = .0309 bbl/ft ~~ 5 %" 15.5# csg X 9 5!8" 36# annular capacity = . D479 bbl/ft 5 %" 15.5# csg displacement = .0056 bbl/ft Lead System 1: 9 5/8" CH x 5 %"Csg: = 1000 ft 700 ft x .0479 bblslft x 1 (0% excess= 33.5 bbls Lead System 2: 300 ft x .0479 bbls/ft x 1 (0% excess= 14.4 bbls 7 7/8" OH x 5 %" CSG: 1500 ft - 1000 ft = 500 ft 500 ft x .0309bbUft x 1.25 (25% excess) = 19.3 bbls Total Lead System = 67,2 bbls Tail System: 7 7/8" OH x 5 %" Csg: 5319 ft - 1500 ft = 3819ft 3819 ft x .0309 bbl/ft x 1.25(25% excess= 148 bbls Shoe Joint = 38' x .0238 bbl/ft = .9044 bbls Total Tail Cmt Volume = 149 bbls Cement System Type Cement Weight (ppQ~ Volume ~% Excess Lead "G" 13.5 68 bbls@ 25% OH Tail "G" 15.8 149 bbls ar7 25% OH Please see attached 5 1/2"production casing analysis and specifications. Drilling Hazards: Common known hazards for drilling in Cook Inlet Basin are as follows: Shallow gas: Shallow gas is a known hazard which exists throughout the area. ~" The northwest side of Cook Inlet is noteworthy for its shallow gas hazard. All responsible personnel will be made aware and a notice of such hazards will be posted in the rig doghouse. There is no record of H2S in the region, however; a gas detection system capable of detecting H2S as well as methane will be installed on the rig with detectors a~tFe'floor level, the shale shaker and in the cellar. Coal Seams: The Cook Inlet region is rich in coal seams, inter-bedded between the sands, gravels and shales that make up the Beluga and Tyonek formations. Drilling into a coal seam will appear to be a drilling break when drilled with a tri- cone bit. The major hazard of drilling into a coal seam without observing the proper response is the risk of stuck pipe. The proper course of action for preventing stuck pipe is two-fold. First, prior to drilling, insure the drilling fluid system is up to par, per recommendations from the on-site mud engineer. The second step to successfully drilling through coals in the Cook Inlet area is to not get greedy when coals are encountered. When a coal has been encountered, ,4 urara Gas I.I.C. Page 7 of ~ l ~ Rev. 2.0 ,4urora Gas, LI.C. TMCU No. 3 Drilling Program pull back above coal after drilling into it, and circulate, allowing the coal to stabilize. Re-enter, drill some more, and pull back out again. Continue in this fashion until successfully through the coal bed. The key word in successfully drilling the coal beds is patience. It should be remembered that coals behave plastically, and will flow under the weight of the overburden. The deeper the coal, the more pronounced this tendency becomes. For this reason it is critical to maintain the proper weight and viscosity of the drilling fluid to properly remove the coal cuttings, and to hold flowing coals in place. Again, heed the recommended drilling fluid program and advice offered by the on-site Mud Engineer. Nearby Well's: The TMCU No. 1 well is located 2540' away from the proposed - TMCU No. 3 well at the surtace. No collision risk with this well exists. Other: Sticky bentonitic clays, boulders, lost returns & differential sticking with overbalanced muds and gas influx while cementing or swabbing while tripping pipe. Aurora Gas L1:C'. Page S of'10 Rev. 2.0 ,4urora Ga.r, LLC. TMCU No. 3 I~f•illing Program TMCU No. 3 Summary of Drilling Hazards POST THIS NOTICE IN DOGHOUSE ~ There is potential for abnormal pressured shallow gas. '" ~ There is potential for stuck pipe in coals encountered while drilling from surface to TD. Be extra vigilant while performing hole opener run. S_ hort trip to be performed every 600 ft or 24 hrs whichever comes first. ~ There is no H2S risk anticipated for this well. ~ Due to potential for shallow gas kick, very little response time will ~° be afforded to respond. PVT and gas detection systems must be fully operational and functioning at all times, visual flow checks and pit level monitoring are critical CONSULT THE "TMCU No. 3" WELL PLAN FOR ADDITIONAL INFORMATION. ~4ur•ora Gar LLC'. Page 9 of 10 Rev. 2.0 Aurora Gas, LLC. • TMCtJ No. 3 Drilling Program Three Mile Creek Unit No. 3 Time vs Depth Plot 1000 2000 Depth MD 3000 4000 5000 Vertically drill 12.25" hole to 1000' MD, run and cement 9.625" casing, drill out, FIT to 15 ppg MWE. Directionally drill, TD at 5319' MD, OH ~ log well, run and cement 5.5" casing, cleanout, perforate, test and complete well. 0 5 10 15 20 25 30 Days ,4urora Gas I.LC• Page 10 ~f 10 Rev. 2.0 Aurora Gas, LLC Three Mile Creek Unit No. 3 Casing Prouerties and Desi n Verification Casing Performance Properties Internal Collapse Tensile Stren t~h int Body 3 D ign S Bety D FaCor* Size Weight Yield i Resistance si o 10001bs ft ~B ~~ ~ 1t I~B T in. lb/ft Grade Cnxn s 9-5/8 36 J-55 BTC 3,520 2,020 639 248 4900 5299 3 53 2.3 2.0 5-1/2 15.5 J-55 BTC 4810 4,040 300 * Tensile design safety factor for 5-1/2" and 9-5/8" casing strings is calculated using pipe weight less buoyancy. Burst design safety factor for the 5-1/2" and 9-5/8" casing strings is calculated from the MASP on the inside based on TMCU No. 1 data and zero backup on the outside at the surface. Colla se design safety factor for the 5-1/2" and 9-5/8" casing strings is calculated as t as s adient on the ins de. ~ expected mud p weight to be used at TD on the outside and the entire cased hole evacuated except or g gr i '.rperry Drilling ~it~rvice~ Aurora Gas, LLC Cook Inlet Three Mile Creek Unit TMCU #3 TMCU #3 Plan: TMCU #3 wp05 Standard Planning Report -Geographic 12 October, 2005 ~~~~~. Sperry L?ri4ting ~erviasla~ Start Build 6.00 ~ 5~~ 10° 20° 0 Start Hold 50.0 9O ``~_ _ _ Start DLS 6.00 TFO -0.08 Start Hold 1488.4 9 5/8" Casing ~~ SECTION DETAILS 1000 1250 1500 1750 c 2250 2500 t] 2750 r 2 30Do I- 3500- 3750 4000 4250 WELL DEI'AIIS: TMCU #3 ,~ +N/-S +E/-W Northing Ground level: 2760 Slot i Fasting Latittude Longitude ' 0.0 0.0 2621740.64 47.4S2W `_-,__ 285815.40 61°10'13.S89N 151°12 COMPANY DETAILS: Aurora Gas, LLC REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well TMCU #3, Grid North Drilling Vertical (TVD) Reference: WELL @ 343.Oft (Original Well Elev) Calculation Method: Minimum Curvature Measured Depfh Reference: WELL ~ 343.0(1 (Original Well Elev) Error System: tSCW5A Calculation Method: Minimum Curvature Scan Method: Trav. Cylinder North I Error Surface'. Elliptical Conic Warning Method: Rules Based Sec MD Inc Azi TVD +N/-S +E/-W Dl.eg TFace VSec Target 1 0 0 0 00 311.69 0.0 0.0 0.0 0.00 0.00 0.0 ' 2 . 450 0 . 0 00 311 69 450.0 0.0 0.0 0.00 311.69 0.0 3 . 1000 0 . 00 33 311.69 970.1 102.5 -115.0 6.00 311.69 15A.1 4 . 1050 0 . 00 33 311.69 1012.0 120.6 -135.4 000. 0.00 IS1.3 5 . 1082 5 . 95 34 311.69 1038.9 132.6 -148.9 6.00 -0.08 199.4 6 . 2570 9 . 34.95 31169 2259.0 699.7 -785.7 0.00 0.00 1052.0 7 . 4318.3 0.00 31169 3900.0 1043.2 -117LS 2.00 18000 1568.6 6 TMCU #3 TD (wp05 00 1568 0 8 5318.3 0.00 311.69 4900.0 1043.2 . . -1171.5 0.00 WELC.BORE TARGET DETAILS Name TVD +N/-S +E/-W Shape 1500' Stand-Off 2525.0 1019.1 -800.4 Polygon TMCU #3 DD Poly 4900.0 1043.2 -1171.5 Poly@an TMCU #3 TD (wp05~900.0 1043.2 -1171.5 Circle (Radius: 125.0) CA SING DETAILS No TVD MD Name .Size 1 975.0 1005.9 9 5/8" Casing 9-S/8 2 4900.0 5318.3 5 1/2" Casing 5-1/2 Directional Difficulty Index = 4.57 ~~~ ~~ ~~~ G T Azimuths to Grid North 2000 True North: 1.06° ~~ } MMagnetic North: 21.05° Magnetic Field Slrength:55618.4nT 1750 Dip Angle: 73.91 ° Dale: 7/20/2005 Model: BGGM2005 4000 5° 0° Start Hold 1000.0 5 1/2" Casing \ ~ 319 ....................................................... TMCU #3/TMCU #3 wp05 -500 -250 0 250 500 750 1000 1250 1500 1750 2000 2250 Verfir.:~~~( St~zs;tinn ~€ 3?1 .0~1° (7;;€l;titn} 1500 TMCU #3fIMCU #3 wp05 ~ 0 7-MCU #3 Dll Pely 1250 TMCU #Y3 TD (wp05) `~ )1/ o~ ~ Apo _ -1000 0 Statt Hold 1000.0 .~ l5(i0' Star:d-Off ~ ~ p~ ~ 5 112" Casing ~'~ - ~ --750 v Start Drop -2.00 'Y~ O soo ~ 5~ ~ ~ 9 5/8" Casing ~ 250 Start Hold 1488.4. _ _ i` Start DLS 6.00 TFO A.08 " _ , - ~~ ~ Start Hold 50.0 0 Start Build 6.00 -250 -1750 -1500 -1250 -1000 -750 -500 -250 0 250 West(-)/Fast(+) (750 ft/in) LEGEND -e-- TMCU #3 wpG5 i Plan: TMCU #3 vpOS (TMCU #3tTMCU #3) -_-_ _~ Created By: Cary Taylor Date: 5/20/2005 Checked: Date: Reviewed: Date. Approved: Date: • • ~ ~-~-~p Hailiburton Energy Services Planning Report -Geographic Sperry Dr iliir~~ Services Database: EDM 2003.11 Single User Db Local Co-ordinate Reference:. Weii TMCU #3 WELL @ 343.Oft (Original Weil Elev) Coin an p y' Aurora Gas, LLC ND Reference: MD Reference: WELL @ 343.Oft (Original Well Elev) Project: Site: Cook inlet Three Mile Creek Unit North R®ference: Grid Well: TMCU #3 Survey Calculation Method: t~~inimum Curvature Wellbore: TMCU #3 Desian: TMCU #3 wp05 Project Cook Inlet, USA Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Map Zone: Alaska Zone 04 Using geodetic scale factor __ - __ __ Site Three Miie Creek Unit Site Position: Northing: 2,624,191.02ft Latitude: From: Map Easting: 286,393.49ft Longitude: 0 ft SI t Radius• 0" Grid Convergence: TFO Position Uncertainty: .0 0 - -_: Well TMCU #3 I~ Well Position +N/-S 0.0 ft Northing: 2,621,740.84ft Latitude: 61°10'13.589"N 452" W ~. 2' 47 ° +E/-W 0.0 ft Easting: 285,815.40 ft Longitude: . 151 1 i 0.0 ft Position Uncertainty Wellhead Elevation: ft Ground Level: 276.Oft - __l _ _ -- - Wellbore TMCU #3 - _-- - _ Magnetics- Model Name ' Sample Date Declination Dip Angle Field Strength. BGGM2005 I 7/20/2005 19.98 73.91 _ 55,618__. i --' ~ ___ _ __ -- ___ Design TMCU #3 wp05 ___- Audit Notes: 0 0 Phase: PLAN Tie On Depth: Version: +N/-S +E/-W Direction Vertical Section: Depth From (TVD) (ft) (ft) (ft) (°) p 0 0.0 0.0 359.99 ~ _ _- r-- Plan Sections Measured Vertical.. Dogleg Depth Inclination Azimuth Depth +NI-S +EI-W Rate ° (ft) (°) (°) (ft) Ift) (ft) 1100ft) ( 0.0 0.00 311.69 0.0 0.0 0.0 0.00 450.0 0.00 311.69 450.0 0.0 0.0 0.00 1,000.0 33.00 311.69 970.1 102.5 -115.0 6.00 1,050.0 33.00 311.69 1,012.0 120.6 -135.4 0.00 1,082.5 34.95 311.69 1,038.9 132.6 -148.9 6.00 2,570.9 34.95 311.69 2,259.0 699.7 -785.7 0.00 4,318.3 0.00 311.69 3,900.0 1,043.2 -1,171.5 2.00 5,318.3 0.00 311.69 4,900.0 1,043.2 -1,171.5 0.00 10/12/2005 1:51:47PM Page 2 of 6 Build Turn Rate Rate (°/100ft) (°1100ft) 0.00 0.00 0.00 0.00 6.00 0.00 0.00 0.00 6.00 -0.01 D.00 0.00 -2.00 0.00 0.00 0.00 61°10'37.818"N 151 ° 12' 36.591 " W -1.06 ° __ J (°) Target 0.00 311.69 311.69 0.00 -0.08 0.00 180.00 0.00 TMCU #3 TD (wp0`. COMPASS 2003.11 Build 48 ~~"~"~ ~per•ry Rrillir~g a'~-rervices Database: EDM 2003.11 Single User Db Company: Aurora Gas, LLC Project: Cook Inlet Site: Three Mile Creek Unit Well: TMCU #3 Welibore: TMCU #3 Design: TMCU #3 wp05 Planned Survey Local Co-ordinate Reference: ND Reference: MD Reference: North Reference: SurveyCalcutation Method: Halliburton Energy Services Planning Report -Geographic Measured Vertical Depth inclination .Azimuth Depth +NI-S 1ft) 1°) ~°) (ft} (ft) 0.0 0.00 311.69 0.0 100.0 0.00 311.69 100.0 200.0 0.00 311.69 200.0 300.0 0.00 311.69 300.0 400.0 0.00 311.69 400.0 i 450.0 0.00 311.69 450.0 Start Build 6.00 500.0 3.00 311.69 500.0 550.0 6.00 311.69 549.8 600.0 9.00 311.69 599.4 650.0 12.00 311.69 648.5 700.0 15.00 311.69 697.2 750.0 18.00 311.69 745.1 800.0 21.00 311.69 792.2 850.0 24.00 311.69 838.4 900.0 27.00 311.69 883.5 950.0 30.00 311.69 927.5 1,000.0 33.00. 311.69 970.1 Start'Hold 50.0 1,005.9 33.00 311.69 975.0 9 518" Casin g 1,050.0 33.00 311.69 1,012.0 Start DLS 6. 00 TFO -0.08 1,082.5 34.95 311.69 1,038.9 Start Hold 1 488.4 1,100.0 34.95 311.69 1,053.3 1,200.0 34.95 311.69 1,135.3 1,300.0 34.95 311.69 1,217.3 1,400.0 34.95 311.69 1,299.2 1,500.0 34.95 311.69 1,381.2 1,600.0 34.95 311.69 1,463.2 1,700.0 34.95 311.69 1,545.1 1,800.0 34.95 311.69 1,627.1 1,900.0 34.95 311.69 1,709.1 2,000.0 34.95 311.69 1,791.0 2,100.0 34.95 311.69 1,873.0 2,200.0 34.95 311.69 1,955.0 2,254.9 34.95 311.69 2,000.0 TMCU#3 T1 wp04 2,300.0 34.95 311.69 2,036.9 2,400.0 34.95 311.69 2,118.9 2,500.0 34.95 311.69 2,200.9 2,570.9 34.95 311.69 2,259.0 Start Drop -2.00 2,595.4 34.46 311.69 2,279.1 Tsuga 2-4 2,600.0 34.37 311.69 2,282.9 2,700.0 32.37 311.69 2,366.4 2,800.0 30.37 311.69 2,451.8 2,884.1 28.68 311.69 2,525.0 1500' Stan d-Off 2,900.0 28.37 311.69 2,539.0 3,000.0 26.37 311.69 2,627.8 3,100.0 24.37 311.69 2,718.1 3,200.0 22.37 311.69 2,809.9 3,300.0 20.37 311.69 2,903.0 3,400.0 18.37 311.69 2,997.4 10/12!2005 1:51:47PM 0.0 0.0 0.0 0.0 0.0 0.0 C: Weli TMCU #3 WELL @ 343.Oft (Original Well Elev) WELL @ 343.Oft (Original Well Elev) Grid - Minimum Curvature Map +EI-W Northing (ft) (ft) 0.0 2,621,740.84 0.0 2,621,740.84 0.0 2,621,740.84 0.0 2,621,740.84 0.0 2,621,740.84 0.0 2,621,740.84 Map Fasting (ft) 285,815.40 285,815.40 285,815.40 285,815.40 285,815.40 285,815.40 Latitude 61°10'13.589"N 61°10'13.589"N 61 ° 10' 13.589" N 61°10'13.589"N 61°10'13.589"N 61°10'13.589"N Longitude 151 ° 12' 47.452" W 151 ° 12' 47.452" W I 151 ° 12' 47.452" W 151 ° 12' 47.452" W 151 ° 12' 47.452" W 151 ° 12' 47.452" W O,g -1.0 2,621,741.71 285,814.42 61 ° 10' 13.598" N 623" N 61° 10' 13 151 ° 12' 47.472" W 'I 151° 12' 47.533" W ` 3.5 -3.9 8 8 2,621,744.31 65 748 621 2 285,811.49 285,806.62 . 61° 10' 13.665" N 151° 12' 47.634" W " ' ° 7,g 13.9 - . -15.6 . , , 2,621,754.71 285,799.81 61° 10' 13.723" N 798" N 61 ° 10' 13 47.775 W 12 151 151 ° 12' 47.955" W 21.6 -24.3 34 9 2,621,762.48 771 92 621 2 285,791.10 285,780.50 . 61 ° 10' 13.889" N 151 ° 12' 48.175" W " ' ° 31.1 42 2 . - -47.4 . , , 2,621,783.02 285,768.03 61° 10' 13.996" N " ' ° 48.433 W , 12 151 729" W ~ 151° 12' 48 . 54.9 -61.6 77 7 2,621,795.74 06 810 621 2 285,753.75 285,737.68 N 14.119 10 61 61° 10' 14.257" N . 151° 12' 49.062" W " 69.2 g5.1 . - -95.5 . , , 2,621,825.92 285,719.86 61 ° 10' 14.409" N 577" N 61° 10' 14 W 151 ° 12' 49.431 151° 12' 49.836" W 102.5 -115.0 2,621,843.30 285,700.36 . 104.6 -117.4 2,621,845.42 285,697.98 61° 10' 14.597" N 151° 12' 49.885" W ~ 120.6 -135.4 2,621,861.41 285,680.02 61 ° 10' 14.752" N 151 ° 12' 50.257" W 132.6 -148.9 2,621,873.47 285,666.48 61 ° 10' 14.868" N 151 ° 12' 50.538" W ' 139.3 -156.4 2,621,880.15 285,658.98 61 ° 10' 14.932" N 299" N 61 ° 10 15 151 ° 12' 50.693" W 151 ° 12' 51.580" W 177.4 -199.2 0 242 2,621,918.24 34 956 621 2 285,616.20 285,573.42 . 61° 10' 15.667" N 151° 12' 52.466" W " ' 215.5 253.6 . - -284.8 . , , 2,621,994.43 285,530.65 61 ° 10' 16.034" N 401" N 61 ° 10' 16 W 53.353 151 ° 12 151 ° 12' 54.239" W 291.7 -327.5 3 370 2,622,032.52 62 070 622 2 285,487.87 285,445.09 . 61 ° 10' 16.768" N 151 ° 12' 55.126" W " ' 329.8 367.9 . - -413.1 . , , 2,622,108.71 285,402.32 61° 10' 17.136" N 503" N 61° 10' 17 W 56.012 151° 12 151° 12' 56.899" W 406.0 -455.9 7 498 2,622,146.80 90 184 622 2 285,359.54 285,316.76 . 61° 10' 17.870" N 151° 12' 57.785" W " ' 444.1 482.2 . - -541.4 . , , 2,622,222.99 285,273.98 61 ° 10' 18.237" N 605" N 61 ° 10' 18 W 58.672 151 ° 12 151 ° 12' 59.558" W 520.3 -584.2 0 627 2,622,261.08 18 299 622 2 285,231.21 285,188.43 . 61° 10' 18.972" N 151° 13' 00.445" W " ' ° 558.4 579.3 . - -650.5 . , , 2,622,320.11 285,164.92 61° 10' 19.174" N W 00.932 13 151 596.5 -669.8 2,622,337.27 285,145.65 61° 10' 19.339" N 706" N 61 ° 10' 19 151° 13' 01.331" W 151 ° 13' 02.218" W 634.6 -712.6 3 755 2,622,375.36 46 413 622 2 285,102.88 285,060.10 . 61 ° 10' 20.073" N 151 ° 13' 03.104" W " ' 672.7 699.7 . - -785.7 . , , 2,622,440.46 285,029.77 61 ° 10' 20.334" N N 03.733 151 ° 13 708.9 -796.1 2,622,449.73 285,019.37 61° 10' 20.423" N 151° 13' 03.948" V1 710.7 -798.0 2,622,451.47 285,017.41 61 ° 10' 20.440" N 792" N 61 ° 10' 20 151 ° 13' 03.989" V 151 ° 13' 04.840" V 747.2 -839.1 0 878 2,622,488.04 65 522 622 2 284,976.35 284,937.48 . 61° 10' 21.126" N 151° 13' 05.646" V " ' 781.9 809.4 . - -908.9 . , , 2,622,550.22 284,906.52 61° 10' 21.392" N V 06.287 151° 13 814.5 -914.6 2,622,555.26 284,900.86 61° 10' 21.440" N 151° 13' 06.405" V 980 9 32 6$4 622 2 284,834.55 61 ° 10' 22.010" N 151 ° 13' 07.779" ~ " ° ' 873.5 899.9 - -1,010.5 . , , 2,622,640.69 08.393 13 284,804.93 61° 10' 22.264" N 151 497" N 151° 13' 08.957" 61° 10' 22 924.1 946.2 -1,037.7 -1.062.5 2,622,664.91 2,622,686.96 . 284,777.73 284,752.97 61° 10' 22.710" N 151° 13' 09.470" \ Page 3 of 6 ll /, J' J V V V V v N COMPASS 2003.11 Build 48 ~• - ' Halliburton Energy Services ~~ ~ ~;~ Planning Report - Geographic ~i~et"t"y Qt'illllll~ ~er"VlC6S Database: EDM 2003.11 Sing le User Db Local Co-ordinate Reference: .WELL @ 343Aft (Original Well Elev) Company: Aurora Gas. LLC TVD Reference: MD Reference: '- WELL 343.Oft (Original Well Elev), ~° Project: Site: Cook Inlet Three Mile Creek Unit North'Reference; Survey Calculatio n Method: `- Grid Minimum Curva ture Well: TMCU #3 Wellbore: TMCU #3 Design:' TMCU #3 wp05 _ _. - _- - Planned Survey Measured th Vertical Depth +N/-5 +~_~y Map Northing Map Fasting Latitude Longitude Depth Incli nation Azimu (~) (ft) 0 3 500 16.37 311.69 Og2.8 3, 966.0 -1,084.8 2,622,706.81 43 284,730.68 gg 71• 214 61° 10' 22.901" N 61° 10' 23.071" N 151° 13' 09.342" W 151° 13' 10. I . 3,600.0 14.37 311.69 3,189.2 983.6 999 0 -1,104.6 121 8 -1 2,622,724. 739.80 622 2 , , 284,693.63 61° 10' 23.219" N 151° 13' 10.700" W I " ° ' ! 3,700.0 12.37 311.69 3,286.5 2 297 . 000 1 6 . , 123 5 -1 , , 2,622,741.35 284,691.90 61° 10' 23.234" N W 10.735 13 151 3,710.9 12.15 311.69 . 3, . , . , Tsuga 2-5 0 800 3 10.37 311.69 3,384.5 1,012.1 -1,136.5 2,622,752.91 3 284,678.91 76 666 284 61° 10' 23.346" N 61° 10' 23.450" N 151° 13' 11.005" W 151° 13' 11.256" W I . , 3,900.0 8.37 311.69 3,483.2 4 2 1,022.9 5 1 031 -1,148.7 158 3 -1 2,622,763.7 622,772.25 2 . , 284,657.19 61 ° 10' 23.532" N 151 ° 13' 11.455" W " W ' ° 4,000.0 0 100 4 6.37 311.69 37 311.69 4 . 3,58 3,681.9 . , 1,037.7 . , -1,165.2 , 2,622,778.47 284,650.21 82 645 61° 10' 23.592" N 630" N 61° 10' 23 11.600 13 151 151° 13' 11.690" W . , 4,200.0 . 2.37 311.69 3,781.8 1,041.6 2 -1,169.6 171 4 1 2,622,782.38 96 783 622 2 . 284, 284,644.04 . 61 ° 10' 23.645" N 151 ° 13' 11.727" W " ' ° 4,300.0 0.37 311.69 3,881.7 900 0 1,043. 2 1 043 . , - 171.5 -1 , . , 2,622,784.00 284,644.00 61° 10' 23.645" N 11,728 W 13 151 4,318.3 0.00 311.69 . 3, . , , Start Hold 0 400 4 1Q00.0 00 311.69 0 3,981.7 1,043.2 -1,171.5 2,622,784.00 284,644.00 644 00 61 ° 10' 23.645" N 645" N 61° 10' 23 151 ° 13' 11.728" W 151° 13' 11.728" W . , 4,500.0 . 0.00 311.69 4,081.7 1,043.2 2 43 -1,171.5 171 5 -1 2,622,784.00 784.00 622 2 . 284, 284,644.00 . 61° 10' 23.645" N 151° 13' 11.728" W " ' ° 4,600.0 0 700 4 0.00 311.69 00 311.69 0 4,181.7 4,281.7 . 1,0 1,043.2 . , -1,171.5 , , 2,622,784.00 284,644.00 00 44 61 ° 10' 23.645" N 645" N 61° 10' 23 11.728 W , 13 151 151° 13' 11.728" W l . , 4,800.0 . 0.00 311.69 4,381.7 1,043.2 2 43 -1,171.5 5 171 -1 2,622,784.00 784.00 622 2 . 284,6 284,644.00 . 61° 10' 23.645" N 151° 13' 11.728" W " ' ° 4,900.0 0 000 5 0.00 311.69 00 311.69 0 4,481.7 4,581.7 . 1,0 1,043.2 . , -1,171.5 , , 2,622,784.00 284,644.00 44 00 61° 10' 23.645" N 645" N 61° 10' 23 11.728 W 13 151 151° 13' 11.728" W . , 5,100.0 . 0.00 311.69 4,681.7 1,043.2 43 2 1 -1,171.5 171 5 -1 2,622,784.00 784.00 622 2 . 284,6 284,644.00 . 61° 10' 23.645" N 151° 13' 11.728" W " ' ° 5,200.0 300 0 5 0.00 311.69 00 311.69 0 4,781.7 4,881.7 ,0 . 1,043.2 . , -1,171.5 , , 2,622,784.00 284,644.00 644 00 61° 10' 23.645" N 645" N 61° 10' 23 11.728 W 13 151 151° 13' 11.728" W . , 318.3 f' 5 . 0.00 311.69 4,900.0 - 1,043.2 -1,171.5 2,622,784.00 . 284, . , ~ TD at°5318.3 - 51/2".Casing - TMCU #3 TD (wp05) -TMCU #3 DD Poly _ Page 4 of 6 COMPASS 2003.11 Build 48 10/12/2005 1:51:47PM • • - Hailiburton Energy Services ~~~ ~ Planning Report -Geographic Sperry f~riitin+y Servirces - Database: EDM 2003.11 Single User Db Local Co-ordinate Reference: Well WEL TMCU #3 L @ 343.Oft (Original Well Elev) Aurora Gas, LLC Company: ND Reference: WELL @ 343.Oft (Original Well Elev) Project: Cook Inlet MD Reference: Grid Three Mile Creek Unit Site: 'North Reference: Survey Calculation Method: Mini mum Curvature Weft: TMCU #3 Wellbore: TMCU #3 Design: TMCU #3 wp05 ___ I Targets Target Name - hitlmiss target Dip Angle Dip Dir. +N/S +EJ-W ND ~ Northing Easting lft) (ft) - .;Latitude Longitude -Shape (°) (')' Iftl ft " 00 0 043.2 -1,171.5 2,622,784.00 0 1 900 4 W 284,644.00 61° 10' 23.645" N 151° 13' 11.728 . TMCU #3 DD Poly 0.00 , . , - plan hits target - Polygon 3 97.9 3 2,622,881.93 284,647.34 Point 1 . 5 93.8 22 2,622,877.82 284,666.51 Point 2 . 3 86.6 40 2,622,870.60 284,684.25 Point 3 . 3 76.6 56 2,622,860.61 284,700.30 Point 4 . 4 64.1 70 2,622,848.11 284,714.41 Point 5 . 82 4 49.3 2,622,833.31 284,726.37 Point 6 . 91 g 32.4 2,622,816.37 284,735.81 Point 7 . 3 13.5 98 2,622,797.52 284,742.26 Point 8 . 1 -6.8 101 2,622,777.18 284,745.13 Point 9 . 7 -28.0 99 2,622,756.05 284,743.71 Point 10 . 93 2 -48.6 2,622,735.41 284,737.18 Point 11 1 . 1 -66.8 81 2,622,717.22 284,725.12 Point 12 . 4 -80.7 64 2,622,703.30 284,708.35 Point 13 . 7 -89.5 44 2,622,694.55 284,688.66 w Point 14 . 23 g -93.3 2,622,690.74 284,667.90 Point 15 , 3 3 -92.8 2,622,691.23 284,647.34 Point 16 _16.2 -gg.5 2,622,695.50 284,627.77 ` i Point 17 3 -81.0 -34 2,622,703.00 284,609.66 Point 18 . 6 -70.6 -50 2,622,713.38 284,593.37 1 Point 19 . X4 9 -57.7 2,622,726.26 284,579.15 Point 20 . 7 -42.6 -76 2,622,741.42 284,567.28 Point 21 . _85 9 -25.4 2,622,758.61 284,558.12 Point 22 , _92 0 -6.5 2,622,777.51 284,552.00 Point 23 . _94 5 13,7 2,622,797.74 284,549.50 Poin124 i 8 34.6 -92 2,622,818.59 284,551.25 i Point 25 . 0 54.9 -86 2,622,838.86 284,558.04 Point 26 . -73.8 72.7 2,622,856.71 284,570.2 ~ Point 27 0 86.3 -57 2,622,870.32 284,587.04 Point 28 . 4 94.8 -37 2,622,878.82 284,606.64 Point 29 . 8 98.5 -16 2,622,882.50 284,627.15 Point 30 . 3 97.9 3 2,622,881.93 284,647.34 Point 31 ' . 171.5 2 -1 043 0 1 900 4 2,622,784.00 284,644.00 61° 10' 23.645" N 151° 13' 11.728" 1 0.00 TMCU #3 TD (wp05; 0.00 , . , . , - pion hiis targei - Circe (radius 125.0) 4 00 455 622 2 285,464.00 61 ° 10' 20.556" N 151 ° 12' 54.886" ' U# TMC . , , p n misses by 328.1 ft at 2254.9ft MD (2000.0 ND, 579.3 N, -650.5 E) - Circle (radius 20.0) 4 800 89 759 622 2 285,015.03 61° 10' 23.476" N 151° 13' 04.155" 1500' Stand-Off 0.00 0.00 . 2,525.0 1,019.1 - . , , - plan misses by 236.1ft at 2884.1ff MD (2525.0 ND, 809.4 N, -908.9 E) - Polygon 0 0.0 0 2,623,209.74 284,875.41 Pornt 1 . 6 56.2 -145 2,622,816.08 284,869.44 Point 2 . 3 133.4 -305 2,622,893.28 284,709.75 Point 3 . 9 208.8 -422 2,622,968.68 284,592.15 Point 4 . 0 298.3 -537 2,623,058.17 284,478.06 Point 5 . 9 208.8 -422 2,622,968.68 284,592.15 Point 6 . 3 133.4 -305 2,622,893.28 284,709.75 Point 7 o,...,F u . -145.6 56.2 2,622,816.08 284,869.44 _~ - Page 5 of 6 COMPASS 2003.11 Build 48 10/12/2005 1:51:47PM ~• - - - ~~~-~- Halliburton Energy Services Plannin Re ort -G 9 P eographic ~p+erry [7rillir~g ~ervicBt!~ Database: EDM 2003 .11 Single User Db Local Co-ordinate Reference: Well TMCU #3 WELL @ 343.Oft (Original Well Elev) Company: Aurora Gas, LLC TVD Reference: WELL @ 343.Oft (Original Wett Elev} Project: Cook inlet MD Reference:.., Grid Three Mile Site: Creek Unit North Reference: Surv®y Calculation Method: 'Minimum Curvature Well: TMCU #3 Welibore: TMCU #3 Design: TMCU #3 wp05 Casing Points Casing Hole ~ '~~ Measured Vertical Name i Diameter Diameter ' Depth Depth I ~,.~ (..~ (ft1 (ftl 9-5/8 12-1/4 1,005.9 975.0 9 5l8" Casing 1/2 7-7/8 5 5,318.3 „ 4,900.0 51/2 Casing --- Formations ~ .Dip M®asured Vertical h Name Litholo Dip Direction. 9Y ° ~ Depth Dept ~ ) 1 2,595.4 2,279.1 Tsuga 2-4 Clay 3,710.9 3,297.2 Tsuga 2-5 Clay 4,959.8 Tsuga 2-7 Clay 5,655.7 Tsuga 2-8 Clay 6,164.4 Tyonek Silt ~ 6,329.3 Carya 2-2 Silt 6,700.0 Carya 2-3 Silt 6,944.7 Carya 2-4 Silt 7,144.5 Carya 2-4.2 Sand ~ 7,194.5 Carya 2-5 Silt 7,342.3 Carya 2-5 Sands Sand Plan Annotations Measured Vertical Loca{ Coordinates +Ni-S +E!-W Comment Depth Depth lft~ (n) (ft) 1~) 0 450 450.0 0'0 A . 1 000.0 70.1 9 -115.0 102.5 6 -135.4 120 Start Hold 50 0.08 Start DLS 6.00 TFO 1,050.0 5 082 1 1,012.0 1,038.9 . 132.6 -148.9 Start Hold 1488.4 . , ~ 2,570.9 2,259.0 0 699.7 -785.7 171.5 2 -1 043 1 Start Drop -2.00 Start Hold 1000.0 4,318.3 5,318.3 3,900. 4,900.0 , , . 1,043.2 -1,171.5 TD at 5318.3 `____ -- Page 6 of 6 COMPASS 2003.11 Build 48 10/12/2005 1:51:47PM • • ;;Aurora Gas, LLC Displaced 2 7/8" x 5.5" annulus and tubing w/ 1%- 2% inhibited brine Three Mile Creek Unit No. 3 Anticipated Well Configuration Beluga Perfs Beluga Perfs 5.5", 15.5#, K-55 casi~ at 5300D 3 3/8" 72# H-40 conductor billed to 80't >. 7/8", 6.5#, 8rd EUE tubing 12 1/4" hole drilled to 500' MD TVD. 9.625" 36# BTC J-55 Casing to 500' MD, Cemented with 14.5 ppg Gas- Block Type I cement slurry system from shoe to 500' and a 12.0 Type I cement from 500' to surface 5.5" Ret/Hyd set packers Cemented with Class G back to surface • • Aurora Well Service Rig No. 1: Proposed 3M BOP Configuration Bell Nipple with flow line to pits 3M Schaffer Annular Preventer 11" 3M Double Gate w/ 3/12" pipe rams installed 11" 3M Mud Cross ~, 3" 5M Manual Valve (Kill Line) 3" 5M Hydraulic iy Valve (Kill line) Fluid flow direction ' While reverse circulating j 3" 5M Manual Valve (Choke Line) 3" 5M Hydraulic Valve ~~ ~/ (Choke Line) 2" 3M Manual Valves on Wellhead Aurora Well Service Rig iPraposed Choke/Kill Manifold Configuration All Valves are 3" rated at psi. Output to Pits Inlet h~ Choke Ire Line Flare Pit To Gas Buster "Atmospheric Degasser" E&P Services, -nc. ~ Rev No. 3 • November 9, 2005 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7~` Ave., Suite 100 Anchorage, Alaska 99501 Attn: Mr. Tom Maunder P.E. RE: Application for Permit to Drill: Three Mile Creek Unit No. 3 Dear Mr. Norman: On behalf of Aurora Gas, LLC, Fairweather E&P Services, Inc. hereby submits a Permit to Drill application for the Three Mile Creek Unit No. 3 natural gas development well on the northwest side of the Cook Inlet. The TMCU No. 3 well will be located approximately seven (7) miles north of Tyonek, Alaska. Aurora Gas, LLC proposes to spud the well on or about, November 10, 2005. The TMCU No. 3 well will be drilled from a new pad with access from the Superior Road which currently supports other production and development operations at the TMCU. Pertinent information in and attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill - 2 copies 2) Fee of $100.00 payable to the State of Alaska 3) Location As-Staked plat 4) Days vs. Depth drilling curve 5) Drilling Procedure 6) Wellbore Schematic 7) Pressure and casing design information. 8) Description of the BOP equipment to be used per 20 AAC 25.035 (a)(1) and (b) 9) Cement program description 10) Drilling fluid program description 11) A summary of potential well hazards. If you have any questions or require additional information, please contact the undersigned at 258-3446, or Mr. J. Edward Jones, Vice President Engineering and Operations, Aurora Gas, LLC at 277-1003. cere y, _ . -- J hn Breitmeier airweather E&P Services, Inc. Attachments cc: J. Edward Jones, Aurora Gas. LLC • ~ ~~ /y~rOra ~~„ ~p~Ce' LLC FIRST NATIONAL BANK ALASKA 11 O 5 O 1I/ ANCHORAGE, AK 99503 1400 W. BENSON BLVD., SUITE 4i0 89-6!1252 ANCHORAGE, AK 99503 (907) 277-1003 l 1!9/2005 I 4Y TO THE State of Alaska RDER OF ~ **100.06 ~' Otte Hundred and 00/100*~***#******~*****************~**************~*******~*********~~***~~*~****************~******* DOLLARS 8 a Statz of Alaska Three Mile Creek#3 P.O.D ~ _y ;MO_ ~OyP ~'li~ ~"~ ~P~ 1 1 11'0 i LO 50f1' X 1 2 5 200060: 3 ~~ t 020 329 311' • TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/pARAGR.APHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME ~Zi'~.e. " _ ` G ~~~~ PTD# 2,0 5--1'74 CHECK WHAT ADD-ONS "CLUE" i APPLIES (OPTIONS) it is for a new wetlbore segment of Th MULTI e perm LATERAL existing well , Permit No, API No. (If API number Production should continue to be reported as ' last two (2) digits a function of .the original API number stated are between 60-69) above. PILOT HOLE In accordance with 20 AAC 25.005(f), all (ply records, data and logs acquired for the pilot hole must he clearly differentiated in both name (name on permit plus PH) and API number (50 - 70/80) from records, data and togs acquired for well (name on permit}. ~ SPACING The permit is approved subject to full EXCEPTION compliance with 20 AAC 25.055. Approval to perforate and produce/infect is contingent upon issuance of a conservation order ~ ~ approving a spacing exception. (Company Name) assumes I - the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the SAMPLE Commission must be in no greater than 30' ~ ~ ~ sample intervals from below the permafrost or from where samples are first caught and ~ __ 10' sample intervals through target zones. Rev: 04/01/05 C\jody\transmittal_checklist WELL PERMfT CHECKLIST Field & Pool THREE MILE CK, BELUGA UNDFGAS - 776500 Well Name: THREE MILE CK UNIT 3 Program DEV _ Well bore seg ^ PTD#: 2051790 Company AURORA GAS LLC Initial Class/Type DEV / PEND GeoArea 820 Unit 12040 OnlOff Shore On_, Annular Disposal ^ Administration 1 Permit_fee attached - Yes - - - 2 Lease number appropriate- _ - . - . - No- _ _ - Corrected error on 10-407. form: well lies_e_ntirely within ADt, 388233. - - - 3 Uni-quewell_nameandnumber_--_.-_--___._-__- Yes_ ______________-________._._______._.. 4 Well located in a_definedpool- - . - Yes - _ - _ _ THREE MILE CK, BELUGA GAS - 776500, governed by CO 558 that was issued 101712005. - _ - - - - . - - 5 Well located proper distance_f[om drilling unit-boundary_ _ - - - _ - _ Yes - _ - CO 558 specifies.1500'cet-back_from-external boundary-wheCe_ownership/landownership changes, Well conforms. 6 Well located proper distance-from other wells- . _ Yes . _ . - _ This proposed-welt conforms to the 60-acre spacing required by CO 558. _ , 7 Sufficient acreageavail_ablein-d_ril_lingunit__ ________________. __._.__-_Yes_ _-___Nearestwell-withinpoolis-1,810'_away._____-_._-_.-____-.._-_-.__-__- 8 If_deviated,is-wellboreplat.included-_-_- -__,__.___-__-___. _-______Yes- _____-___-____--_ 9 Operator only affected party- - - - Yes -------------------------- - - - - - - - - 10 Ope[atorhas.appr9priate_bondinforCe ----- -- --- ---- -- ----Yes- - - - - - - ---- --------- ---- - ------ --- - -~ --- -~ --- 11 Pe[mitcanbeissuedwithoutconservationorder-_,__--_---__ -_- ___---_Yes_ _______________-_,___-__--_.__-___.__-_-_-,__.-_-_._.-_._.____---_._._ Appr Date 12 Permit can be issued without ad_minisi[ative-approval - - - - - - - - - - - - - - Yes - - 13 Can permit be approved before 15-day wait Yes SFD 11/1412005 14 Well located within areaand_sirataauthorizedhy_InjectionO[de[#(put_IO#in_comments)_(For_NA__ _________________._-_--_._--_-_-_-_-_-_-__-__.____. _. _.-__.__--___-,_ 15 All wells-within1/4_milearea ofreyiewidentified(Forservieewellonly)______ _________NA._ _-.,__--__,_-_-__._.__--._____.___- 16 Pre-produced injector duration_of pre production less than_ 3 months_ (For service well only) - NA- - - - , - - _ - _ - - - 17 ACMP-Finding of Consistency-has been issued-for this project - - NA_ - - _ ACMP review no longer affects-permit to d[ill_approyal process.- _ _ - _ _ - - Engineering 18 Conductor string_provided - - Yes _ - - - - - - - - - - 19 Surface casing protects altknown- USDWS _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - _ _ _ _ - _ Surface & productipn casing will be cemented back_t4 surface toprotect anyp9tential freshwater, SFD - _ - - _ - - 20 CMT-v_oladequate_toci[c_ulate_onconductor&surfcsg______________ _____ __Yes- ________-_-_______..___.____-___ 21 CMT_vol adequate_to tie-in long string to surf csg- Yes 22 CMT_will coyer all known-productive horizons- - - - - - - - - - - - - - - _ _ _ _ - _ _ Yes - - _ - - - - - _ - - 23 Casing designs adequate fo[C,T,6&pe[mafrost__-.__.___ --------Yes- ------------------------------------------.-----------.------------ - _-- 24 Adequate tankage_or reserve pit - - - - - _ - _ - - _ . Yes - . Rig is-equipped with steel-pits. _Although relatively small, Aurora has successfully drilled similarwells 25 If-a_re-drill, has-a 1.0-403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ - _ - _ _ _ using this rig. Drilling waste likely handled via Enyi[otech._ - - _ _ _ _ _ - - . _ - _ _ . - _ - - _ - - _ _ - - _ _ - 26 Adequatewellboreseparatjon_proposed_______________________ -.__.__-_Yes_ ___.--There are no wellsp[oximate,_.-_._.-_____.____.-._____-.__.-_ 27 If-diverter required, does it meet regulations- - - . - . - - - - . - Yes . - _ Aurora plans to dril a-pilot-hole due to the_ 10" diverter linesfze.- _ - _ - - - Appr Date 28 Drillingfluid-program schematic & equip list adequate_ _ - - _ - _ _ Yes - _ . _ -Maximum expected f_o[mation pressure 1Q,2 EMW._ Mud plansp[oyfde for maintaining overbalanced_ conditions._ . TEM 11/15/2005 29 BdPEs,.dotheymeetregulation __________________________ - --_.__Yes_ _----_.-_-______----_-_-_--__--_-_--____-__-_-__-_-__--___-___-. 30 BOPE-press rating appropriate; test to-(put prig in comments)- - - - - - - - - - - - - - -Yes - _ _ . MASP calculated at 2058 psi: 3000_ps%BOP testplanned, _ _ . _ _ _ _ _ _ . _ , . _ _ . _ _ _ _ _ . _ _ _ _ _ . _ _ _ , (((///"""y 31 Choke.manifcldcomplies_wIAPI-RP-53(M_ay84)_----._--__---__-- _------,Yes- _-,-_-_----_-__--__ 32 Work will occur without operationshutdown_____ ________________ _-_--_..Yes_ _____--_-___-__-__-_, _-_______. -__-_._---_-_-_- 33 Is presenee_ of H2S gas- P-robable No - - - - - - - - - - 34 Mechanical-condition of wellswfthinAORyeritied(Forservicewellonly)-____ ---_-__NA_ ___.---_-__________._______.__-___.___.___-._ Geology 35 Permit. can be issued w1o hydrogen_sulfide measures _ _ _ _ - . - - - - - -Yes . _ _ _ - . None measured in offset wells.- _ - - - _ - - _ . - ---------------------- 36 Aata-presented on-potential overpressure zones- - - _ - - - . - _ - -Yes - - - - - _ Expected reservoirpressure is between-8.9 and-10.2 ppg EMW based on recently drilled. offset wel_Is. - - _ _ . _ - - Appr Date 37 Seismic analysis-of shallow gas-zones_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ - _ _ , _ _ Potential for encountering-shallowgas; wel) will be mudlogged during all drilling operations-& gas sensors - , - - - SFD 11114/2005 38 Seabed conditionsurvey_(ifoff-shore)--_-_--________________ __ ____. NA-- __ _-will beused.__-_--_.___.- - - - - 39 _ Contact nam_elphone for_weekly progress-reports [exploratory only)- , , _ - - NA- Geologic Engineering P ~ Date Date: Date Potential to encounter shallow gas is emphasized in the Summary of Drilling Hazards. "Pressure considerations" section of Commissioner: Commissioner: io r application discusses expected pressure gradients, Well will be mudlogged during all drilling operations and gas sensors will r 1 ~ r., D ~`s j~ f Is~,~ ~,,,~~ ~ it ~I s~~~ / ~ be used. SFD /- ~"~~- s •