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Home My WebLink About209-065 0 Ima a Project Well Histo File Cove . a 9 J rY e 9 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. R 0 7- 0 b..� Well History File Identifier Organizing (done) ❑ Two -sided 1111111111111111111 ❑ Rescan Needed 111111111111 111111 RESCAN DIGITAL DATA OVERSIZED (Scannable) ❑ Co r Items: ❑ Diskettes, No. ❑ Maps: Greyscale Items: ❑ Other, No/Type: ❑ Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non - Scannable) O Other: ❑ Logs of various kinds: NOTES: '� ❑ Other:: BY: ` Date: 3 1 / /s/ aif ..-----7 Project Proofing 1111111111111111111 BY: Date:3 g 1 1 /s/ NP Pre aration x 30 = + = Scanning p TOTAL PAGES, age BY: 4IMO Date: (Count does not include cover sheet) VII f � 8 /s/ ` Production Scanning 1311111 11111 Stage 1 Page Count from Scanned File: a, (Count does include cove ,sheet) Page Count Matches Number in Scanning Preparation: V YES NO BY: 44105 Date: 3/811 1 /s/ 04 r 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. 1 ReScanned 111 1111111111111 BY: Maria Date: /s/ Comments about this file: Quality Checked 111 111111111111111 10/6/2005 Well History File Cover Page.doc ==- - umra Gas, LI.0 www.aurorapower.com June 9, 2010 RECEIVED Mr. Steve Davies 2010 Alaska Oil and Gas Conservation Commission Alaska Oil ' Commission 333 West 7 Ave., Suite 100 t� ncher3ge Anchorage, Alaska 99501 RE: Cancellation of Permit to Drill No. (165: Moquawkie No. 5 Dear Mr. Davies: Aurora Gas, LLC ( "Aurora ") received a Permit to Drill on June 30, 2009 for an onshore gas finS exploration well in the Moquawkie Gas Field northwest of the village of Tyonek. The well was planned as a vertical well targeting the Upper Tyonek Formation to test for gas. Aurora has re- evaluated the drilling and development plans for this area of the Moquawkie Undefined Gas Field and has determined that the targeted reserves, specifically the Carya 2 -1 through 2 -1 sands, can be accessed by work -over operations on the Moquawkie No. 4 well. The concept of the Moquawkie No. 5 well was that of an acceleration well for production of the Upper Tyonek sands that are producible in the Moquawkie #3 well but appear to be fault separated, as indicated by seismic and confirmed by initial pressures in the No. 4. While a re- completion of the No. 4 will not accelerate the shallower reserves, it will access the reserves at a much lower cost, especially since remedial work must be performed on the No. 4 well anyway. Therefore, Aurora respectfully cancels its Permit to Drill for the Moquawkie No. 5 well. If you have any questions or require additional information, please contact me or Mr. Ed Jones at (907) 277 -1003. Sincerely, AURORA GAS, LLC :1; C4!( 4 -)066:' Bruce D. Webb Manager, Land and Regulatory Affairs 1400 West Benson Blvd., Suite 410 • Anchorage, AK 99503 • (907) 277 -1003 • Fax: (907) 277 -1006 6051 North Course Drive, Suite 200 • Houston, TX 77072 • (281) 495 -9957 • Fax: (281) 495 -1473 RBDMS JUN 0 9 2010 Siti s Iitar [E [F SARAH PALIN, 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 1400 West Benson Suite 410 Anchorage, AK 99503 Re: Moquawkie Undefined Gas, Moquawkie #5 Aurora Gas LLC Permit No: 209 -065 Surface Location: 1169' FNL and 1268' FEL Sec 1 T11N, R12W, SM Bottomhole Location: 1169' FNL and 1268' FEL Sec 1 T11N, R12W, SM Dear Mr. Webb: 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. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. Aurora Gas LLC assumes the liability of any protest to the spacing exception that may occur. 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659 -3607 (pager). Sincerely, Daniel T. Seamount, Jr. Chair DATED this3 r day of June, 2009 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. RGVC1 V GU STATE OF ALASKA JUN 1 0 2009 ALASIL AND GAS CONSERVATION COMMIOON PERMIT TO DRILL Alaska Oil & Gas Cons. Commission 20 AAC 25.005 Anchnrage 1 a. Type of Work: lb, Current Well Class: Exploratory ❑ Development Oil ❑ 1 c. Specify if well is proposed for: a Te-s'' Drill R Redrill [] Stratigraphic Test ❑ Service ❑ Development Gas R Coalbed Methane [ ea- as Hydrates ❑ Re -entry ❑ Multiple Zone ❑ Single Zone ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket 0 Single Well ❑ 11. Well Name and°Number: Aurora Gas, LLC Bond No. NZS 429815 • Moquawkie No.5 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 1400 W. Benson Blvd, Suite 410, Anchorage AK, 99503 MD: 2,400' ' TVD: 2,400' dls i , Hirt 4a. Location of Well (Governmental Section): 7. Property Designation: Moquawkie, as..Eiekr Surface: T. 11 N., R. 12 W., S.M., Section 1 C- 061390 . "toil M • 1,268 FEL and 1,169' FNL . 8. Land Use Permit: 13. Approximate Spud Date: Top of Productive Horizon: IrttA Tyonek Native Corp., # AR- 101765 7/1/2009 Total Depth: � 77/07 9. Acres in Property: 14. Dist. to Nearest Property: .2(0 9A/1, ' X 7,38.7 640 1,268' FEL and 1,169' FNL 4b. Surface Location of Well (State Base Plane Coordinates): 10. KB Elevation 299' MLLW 15. Distance to Nearest Well x= y- . zone: 4 (Height above GL): 16' feet Within Pool: 150' 16. Deviated wells: Kickoff depth: feet 17. Maximum Anticipated Pressures in psig (see 20 MC 25.035) Maximum Hole Angle: degrees Downhole: 1,397 psi . Surface: 1,157 psi (482 psi @ 660') 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD ND MD TVD (including stage data) Driven 13 -3/8" 68# K -55 BW 80' 16' 16' 95' 95' N/A 12 -1/4" 9-5/8" 53.5136# L- 80/K -55 BTC 635' 16' 16' 650' . 650' • 220 sx i 7 -7/8" 5 -1/2" 15.5/17# K- 55/N -80 BTC 2,385' 16' 16' 2,400' - 2,400' 353 sx K 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth ND (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth ND (ft): Junk (measured): Casing Length Size Cement Volume MD ND Conductor /Structural Surface Intermediate Production Liner Perforation Depth MD (ft): 'Perforation Depth ND (ft): 20. Attachments: Filing Fee ❑ BOP Sketch ❑ Drilling Program Time v. Depth Plot❑ Shallow Hazard Analysis ❑ Revised Property Plat El Diverter Sketch ❑ Seabed Report❑ Drilling Fluid Program❑ 20 MC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Printed Name Bruce D. Webb Title Manager, Land and Regulatory Affairs Signature ' ,,� L\. Phone (907) 277 -1003 Date June 10, 2009 Commission Use Only Permit to Drill _ APl Number: r , Permit Approval See cover letter for other Number: 2_09 -c- _, � 50 _ �� '��'') Dat requirements. me Conditions of approval: If box checked, well may not to explore for, test, or produce coalbed t nne, g by ates, or gas contained in sha s: ❑ Other: Samples req'd: Yes El No L Mud log req'd: Yes L No H measures: Yes❑ No [1 Directional svy req'd: Yes ❑ No i� 1G,G/, tiC t'�-/ A 4.. j6, Cc} ,) 0 APPROVED BY THE COMMISSION D DATE: , COMMISSIONER Form 10-401 Revised 12/2005 Submit in Du Iicate/ f r et. r11 ♦r lr1 r I SEC 36 F SEC 31 SEC 1 E SEC 6 GRID N:2589080.630 , GRID E:268206.140 A LATITUDE: 61°04'48.689"N Grid z LONGITUDE: 151 °18'33.093"W m PROPOSED LOCATION •- MOQUAWKIE #5 NORTH ASP NAD27 ZONE 4 PAD LIMITS N:2587938.797 E:266914.280 ELEV.: 299' NAVD88 MOQUAWKIE #4 010 1268' FEL Pipeline ACCESS ROAD Route CENTERLINE EXISTING NOTES MOQUAWKIE #3 1) BASIS OF COORDINATES IS ALASKA STATE MOQUAWKIE #1 PLANE NAD 27 ZONE 4 FROM DETERMINED BY AN OPUS SOLUTION AND CONVERTED TO NAD27 WITH NADCON. 2) BASIS OF ELEVATION IS NAVD88 COMPUTED USING GEIODO6 DETERMINED BY AN OPUS SOLUTION. 3) SECTION LINES SHOWN HEREON ARE SEC. 1 BASED ON PROTRACTED VALUES. J T11 N, R12W, S.M., AK (U.S. SURVEY NO. 1865); MOQUAWKIE NO. 5 WELL SURFACE LOCATION DIAGRAM APPLICANT: AURORA S LLC PROJECT NO. DRAWN BY: DATE: SEC. LINE LOCATION: JUNE 1, 09 OFFSETS: PROTRACTED SECTION 1 CAH 1169' FNL TOWNSHIP 11 NORTH, RANGE 12 WEST 1268' FEL SEWARD MERIDIAN, ALASKA Aurora Gas, LLCoquawkie #5 Drilling Plan MOQUAWKIE #5 DRILLING PLAN Moquawkie #5 is a grass -roots well targeting Beluga and uppermost Tyonek Gas Production. It is located in the Moquawkie Gas Field, drilled from the Moquawkie #4 pad, about 100' east of the #4 well. It will target Beluga Tsuga 2 -7 to the Upper Tyonek Carya 2 -3 sands that have • produced/are producing in the Moquawkie #3, and it will be drilled to collect data (cores) from and, possibly, test Beluga and Tyonek coal seams for CBM potential assessment. Pre Rig work 1. The site for the Moquawkie #5 is on the east end of the existing Moquawkie #4 well pad, which was constructed in 2008 and is about 1100' north of the Moquawkie Production Facility The location is in Sec. 1, T11N, R12W, and the GL is about 299'. 2. Extend the existing Moquawkie #4 gravel pad to the north and east 27' and 72', respectively. About 160' due east of the #4 well, drive 13 -3/8" 68# K -55 BFW conductor to +/ -80' below GL. Build sufficient emergency cuttings containment for planned drilling program on the Moquawkie Production Facility pad, and build containment for diverter line using silt fence. 3. Install cellar & mousehole. Cut off conductor as needed to accommodate diverter system. Drilling Procedure 1. File & insure all necessary permits and applications are in place. 2. MIRU AWS #1 in drilling configuration. Install 13 -5/8" VG LOK head. 3. Rig up diverter & mud loggers. Test & calibrate all PVT / gas sensor equipment. Provide / 24 -hr notice to AOGCC inspectors for chance to witness diverter test. 4. Notify AOGCC when ready to start drilling operations. 5. Prepare spud mud system / weight up to 10.5 ppg Load, strap & drift 650'+ of 9 -5/8" 36 & 40# K -55 BTC and 36# K -55 LTC surface casing —have LTC box X BTC pin cross -over, so BTC to be run on bottom. Note that BTC float shoe and float collar have been "bucked on" short joints in Kenai—locate and bring to location. 6. PU 12 -1/4" mill tooth bit & drill to –650', using 8" & 6 -1/2" stabilized BHA w/ float sub and drilling jars. Watch for gas in shallow coals and sands. Attempt to TD in siltstone or claystone, avoid setting surface shoe in a coal bed or sand. If possible, adjust TD to put cement head at floor. (Short joints are available to facilitate this). 7. Increase mud weight while circulating in the event of any significant mud log show. POH slowly to avoid swabbing. 8. Make wiper trip to conductor to condition hole for running 9 -5/8" surface casing, POOH, LD 12 -1/4" BHA. Prepared by Ed Jones Page 1 of 12 Rev. 1.0 Aurora Gas, LLC litoquawkie #5 Drilling Plan 9. Run & cement new 9 -5/8" 36 & 40# K -55 BTC & LTC casing @ +1 -650' (depending upon availability, some 53.5# L -80 may need to be used to give us enough)—LTC on top and BTC on bottom, installing 1 centralizer / joint centered on the 1s` 4 joints above shoe, & 1 centralizer every 2nd joint across the collars there after. Float collar is to be run one joint above shoe —both float and shoe will be BTC thread. Shoe joint connection at float shoe and float collar must be Baker - Locked. Cementing will be single stage using 13.0 ppg accelerated Type I cement at 100% excess volume. Overdisplace by 1 bbl if plug doesn't bump. Leave 6" to 18" of good cement in cellar to seal bottom. Be prepared to treat cement returns in mud pits or vac truck/super sucker with retarder. 10. RD cementers, nipple down diverter, cut casing and install 11" 3M wellhead. 11. RU and test 11" 3M BOP stack and 5M choke manifold. Test stack and surface equipment to 3,000 psi. Pressure test 9 -5/8" casing to 1,500 psi for 15 minutes or as / required on approved Permit to Drill. Mud weight to drill out should be at least 10.5 ppg at this point. 12. PU 7 -7/8" Mill Tooth Bit & 6 -1/2" & 4-3/4" stabilized BHA w/ float sub and drilling jas. RIH. Drill out shoetrack. Displace spud mud w/ 10.5 ppg LSND system. Drill P7, of new formation. Pull back into shoe & perform FIT / LOT up to 16.0+ ppg EMW 192 psi pump pressure at 670' w/ 10.5 ppg mud. 13. RIH and drill 7 -7/8" hole to about 1114' — watch for drilling break at top of coal. / (Geologist will be on site to direct). Circ bottoms up and condition hole, POH. PU 20' core barrel and RIH. Core coal 1114' to 1126', or as directed. POH and LD core — C 'te– special handling to be done by Terra Tek or other third party. 14. PU bit and RIH. Drill to 1890', or as directed by geologist. Circ bottoms up and condition hole, POH. PU 20' core barrel and RIH. Core coal 1890' to 1910', or as -- °v- directed. POH and LD core—special handling—to be done by Terra Tek or other third P g Y party. 15. PU bit and RIH. Drill to 2400' (MD /TVD) TD or other depth as directed by Aurora Gas geologist. 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. Monitor hole cleaning and drilling trends. 16. Drop single -shot survey every 0', and make wiper trips every 500' or so, as needed (back into shoe first time, then just above last wiper trip point thereafter, or as needed). Anticipated mud weights required are 10 ppg – 1 1.6 ppg. Do not exceed fracture gradient determined in step 11. 17. If possible, adjust TD to put cement head on floor. While drilling, load, tally & drift 5 -' /2" casing on racks. (If any BTC is run, will have short LTC box X BTC pin cross -over joint). 18. Condition hole, short (wiper) trip and prepare for running wireline logs. 19. POOH, rack back drillstring. 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 including resistivity and porosity logs as directed by Aurora Gas. RD wireline. Prepared by Ed Jones Page 2 of 12 Rev. 1.0 Aurora Gas, LLC • gloquawkie #5 Drilling Plan 20. RIH w/ 7 -7/8" drilling assembly to TD & condition hole for running 5 -%2' casing. Ensure cementing head has proper connections (8 Rd LTC) or proper cross -over and is available for quick rig up. 21. POOH while laying down drillpipe & BHA, RU to run casing. Verify cementer's equipment is ready. 22. Install 5 -V2" pipe rams. 23. Run 2400' of 5 -' /2" 17# N -80 LTC casing (also use any 15.5# K -55 BTC remaining from Kaloa 3 —run on bottom —a LTC box X BTC pin cross -over is available at Tuboscope), installing 1 centralizer per joint centered on 1 4 joints above shoe, 1 centralizer every 2nd joint in open hole & every 3 joint inside surface casing (use Turbolator centralizers below /thru each pay sand). Shoe joint connection at float shoe, float collar must be Baker - Locked (80' shoetrack). While running casing, fill every 3 joint. Be prepared to wash to bottom. 24. RU cementers, cement per attached cementing program from TD to surface. A sufficient amount of accelerated 12.0 ppg light weight Type I w/ 20% Poz Powder lead cement will be pumped to cover the annulus of 9 -5/8" to surface (from +/ -650' up). This will be followed by sufficient amount of 14.8 ppg Type I tail blend cement to cover from TD back to the 9 -5/8" shoe. Excess will be calculated using caliper log data. Plug will be bumped with clean NaCl/KC1 brine. If possible reciprocate pipe while displacing cement. Land casing & WOC. 25. RD cementers, nipple down stack, land casing in slips & cut casing. 26. 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 3,000 psi. Pressure test casing to 2,000 psi for 15 minutes and record results. 27. Install 2 -7/8" pipe rams. 28. RIH w/ bit & casing scraper on 2 -7/8" tubing to float collar. Displace well w/ filtered KC1/NaC1 brine (wt. to be determined from XPT data). Continue to clean brine for perforating by running through centrifuge & filtering. POOH. Strap tubing on TOH to validate tally. A MORE DETAILED PROCEDURE WILL BE PROVIDED AT THIS POINT INCLUDING PERFS 29. PU wireline BOP's & lubricator, pressure test all against casing to 1500 psi (or higher if XPT indicated higher gradients). PU GR/CBL /CCL & log 5 -1/2" casing to surface. LD logging tools & 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. 30. RIH w/ bit & casing scraper on 2 -7/8" tubing to float collar. Circulate perforating debris from hole. Continue centrifuging & filtering brine until cleaned up. POOH. LD bit & scraper. RU Aurora well test unit, including flare stack. 31. Pick up & assemble completion assembly which will consist of mechanical set packer w/ on -off tool for sump packer to be set above deepest perforated zone, then 2 (or possibly Prepared by Ed Jones Page 3 of 12 Rev. 1.0 Aurora Gas, LLC uawkie #5 Drilling g Plan 3) hydraulic packers w/ sliding sleeves between packers —all sliding sleeves are to be closed and a pump -out ball -seat below deepest packer. RIH with completion on new 2- 7/8" 6.5# J -55 8 rd tubing & set completion at appropriate depth, filling tubing as running. Space out, hang off in tubing head & lock down. Drop ball and pressure tubing to 3000 psi (or as required) to test and to set packers. Increase pressure and shear out ball. 32. Install BPV. ND BOP. NU and test tree. Pull BPV. 33. RU & swab in deepest zone. After well cleans up, perform flow test —get stabilized rate (1 hour minimum). Shut in well & record pressure buildup until stabilized with no change in one hour. DO NOT KILL, but run blanking plug on Pollard slickline and set in X nipple below deepest packer. 34. Add needed KC1 water cushion to tubing (amount to be determined). Open deepest sliding sleeve. Test well as per Step 29. DO NOT KILL, but close sliding sleeve. 35. Repeat Step 30 for remaining shallower intervals (1 or 2). 36. Open zones for initial production (depending upon pressures and test results — likely all Carya 2 perfs) —flow to clean up. Shut in. Set BPV in tree. Release rig, RD, and move rig. 37. Pull BPV. Run 4 -point test of initial production zone as per Procedure provided at that time. RD test unit. 38. Clear & clean location. Hand well over to production. 39. File completion reports with proper agencies. Site Access Moquawkie #5 will be accessible via existing gravel roads to the #4 well pad. Rig Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the Moquawkie #5 well. The Alaska Oil & Gas Conservation Commission has information on this rig and equipment as it has been in use for the last (6) years on other Aurora Gas operations. The pits, BOP system & mud equipment configuration will be the same as that used for previous work. Survey Program The 12-1/4" surface hole and the 7 -7/8" production hole will be drilled vertically, and the survey program will consist of single -shot surveys as required to be obtained at 500' intervals in accordance with rules laid out in 20 AAC 25.050 (a) (1) & (2). Logging Program Prepared by Ed Jones Page 4 of 12 Rev. 1.0 Aurora Gas, LLC Ioquawkie #5 Drilling Plan Mud loggers will be on site for the duration of drilling activities. Schlumberger will provide wireline logging services as proposed below: Kaloa #3 Proposed Logging Program Well Section Depths (ft) OH CH Log Type 12 -1/4" Surface 0' — 650' Al N /A: No open -hole logs planned for surface at this time. GR only in cased hole. 7 -7/8 ' Production 650' —3400' \I Platform Express: Array Induction, Compensated Neutron, Hole Litho- Density, SP, GR, and possibly DSI and/or FMI/DM.. Also XPT and, possibly, Sidewall cores. 5 -1/2" Int. Csg 650' —3400' GR/CBL /CCL Surface — TD 94' — 3400' Mud Logging Services BOP Equipment Aurora Gas, LLC will use the same BOP system they have been using for the last 6 years (except that 12" diverter line was added in 2008), which will consist of the following: 12 - 1/4" Surface Hole While drilling the 12 -1/4" surface hole, a 13 -5/8" 5M annular w/ 13 -5/8" diverter spool & r diverter line will be used: an exception to 20 AAC 25.035 (c)(1)(A), requiring that the diverier -X- line outlet size be at least 16" diameter or (B) at least as large as the hole size being drilled, will be requested. 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. Drilling Fluids The drilling fluids will be furnished by Baroid, 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 properties and make recommendations. Drilling Fluid Properties While Drilling 12 - 1/4" interval to 650' Beluga Formation Base Fluid Fres �-ar produced water Density 10 -11 ppg Prepared by Ed Jones Page 5 of 12 Rev. 1.0 Aurora Gas, LLC Ioquawkie #5 Drilling Plan PV 10.30 YP 30-40 API Filtrate not controlled Total Solids 15 — 25 % Bentonite Gel (Aquagel) mud system Drilling Fluid Properties While Drilling 7 - 7/8" interval to 3400' Beluga and Tyonek Formations Base Fluid 3% Kc1 Density 9. 2 0 ppg ✓ PV 6 -15 YP 13 -20 API Filtrate < 5 Total Solids 10 —15 % Low Solids Non - Dispersed (LSND) System Drilling Fluid Handling System Shale Shaker, Mud Cleaner, Centrifuge, PVT monitors Drilling Waste Disposal The cuttings will be mixed with Portland cement, put into Super Sacks and transported to the Kenai Borough landfill on the Kenai Peninsula. Drilling mud will be held in tanks for reuse or injection at the Aspen Disposal Well. Brine will be placed in tanks for use in future wells. Casing / Cementing Program All casing is new. Analysis (attached) indicates casing program as designed provides adequate safety factors for this well. All casing strings with the exception of the 13 -3/8" conductor will be cemented in place using industry standard casing cementing techniques utilizing a casing shoe, float equipment, top and bottom wiper plugs and centralizers installed as needed. 13 -3/8" 68# K -55 Conductor Analysis and Cementing Program (Z 015 '7 The conductor for Kaloa #3 has been installed by drilling/driving the 13 -3/8" pipe to 80'GL/95' RKB. Joints are welded together and a drilling shoe was welded to the bottom joint. No cementing is required. 9 - 5/8" 36# K - 55 LTC Surface Casing Analysis and Cementing Program 1. V The 9 -5/8" surface casing will be cemented from the proposed setting depth of 650' to surface with an accelerated 13.0 ppg accelerated Type I cement system. Prepared by Ed Jones Page 6 of 12 Rev. 1.0 Aurora Gas, LLC • Ioquawkie #5 Drifting Plan Capacities: 9 -5/8" 36# Csg. Capacity = .0773 bbl/ft 9 -5/8" Csg X 13 -3/8" Conductor Capacity = 0.0597 bbl/ft 9 -5/8" Csg. x 12 -1/4" OH Capacity= .0558 bbl/ft System Volume: 9 -5/8" X 13 -3/8" Annulus: 80 X 0. 0597= 4.8 bbl 12 -1/4" OH x 9 -5/8" Csg: (650' -80) x .0558 bbl /ft x 2 (100 % excess) = 63.6 bbls Shoe Jt: 43' x .0773 bbl/ft = 3.3 bbls Total Surface Cement Volume =71.7 bbl Actual volumes to be re- calculated at time of running casing due to potential variation in actual depth from planned. Cement System Weight(ppg) bbl cf sx Accelerated LW Type I �13.(' 71.7 / - 220 Yield 1.83 cf /sx Please see attached 9 -5/8" surface casing analysis and specifications. 54/2" 17# N -80 LTC Production Casing Cementing Program The 5 -1/2" production casing will be cemented in fully from the proposed set depth of 3400' to surface. A 12.0 ppg accelerated lead light- weight (20% poz powder) Type I cement followed with a 14.8 ppg Type I tail cement system will be used. (The top of the tail may be adjusted upward following the logging program, dependent upon the location of upper most potential v' pay). This program is designed to insure the intended perforating / production intervals are isolated with tail blend. Capacities: / 5 -' /2" 17# csg capacity = .0232 bbl/ft 5 - /2" 17# csg X 7 -7/8" OH capacity = .0309 bbl/ft 5 - /2" 17# csg X 9 -5/8" 36# annular capacity = .0479 bbl/ft " Lead System: 9 -5/8" x 5 - "Csg: 650' 650' x .0479 bbls /ft x 1 (0% excess) = 31.1 bbls Lead Cement Volume = 31.1 bbl Tail System: 7 -7/8" OH x 5 -1/2' Csg: 249&650' = 1750' 1750' x .0309 bbl/ft x 1.25(2 5% excess) =67.6 bbls Shoe Joint: 85' x .0232 bbl/ft 2.0 bbls Total Tail Cement Volume = 69.6 bbls Actual volumes will be calculated at time of running casing due to potential variation in depth from planned. Prepared by Ed Jones Page 7 of 12 Rev. 1.0 Aurora Gas, LLC ito #5 Drilling Plan Cement System Type Cement Weight (ppg1 bbl cf sx Lead @ 2.86 cf/sx LW Type I 12.0 32 180 63 ' Tail @ 1.35 cf /sx Type I 14.8 69.6 390 v 290 ' Please see attached 5 1/2" production casing analysis and specifications. Pressure Calculations Maximum Anticipated Surface Pressure From offset wells in the immediate area and actual pressure data from the ney offset well, Moquawkie #4, maximum anticipated bottom -hole pressures should not exceedT39ypsi at 2,400 ft. Pressures (XP) Moquawkie measured at the Mo uawkie #4 well indicated a maximum gradient of —.582 psi /ft with a bottom-holepessure of 997 psi recorded at 1749'. However, the maximum pressure recorded in the #4 was 013' psi at 1904', as the gradients were decreasing with depth thereafter. Maximum anticipated surface pressures "MASP" can be calculated by subtracting the gas gradient of .1 psi /ft from pore pressure gradient of .582 psi / ft and multiplying by the total TVD depth. / Maximum Anticipated Surface Pressure = (.582 - .1) * 2400' = 1157 psi A formation integrity test to 16.2 ppg EMW @ 909' will be conducted while drilling Moquawkie #4, as this has become Aurora's standard test in this area. Assuming casing shoe strength of 16.2 ppg EMW (or 0.84 psi /ft) our estimated Maximum Allowable Surface Pressure during the 7 -7/8" interval is expected to be Maximum Allowable Surface Pressure = (.84 -.1) *660' =482 psi Drilling Hazards 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 at the 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, 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 Prepared by Ed Jones Page 8 of 12 Rev. 1.0 Aurora Gas, LLC •oquawkie #5 Drilling Plan 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. Well Proximity Risk There is one existing wellbores within 160' of this location, the #4. It was drilled as a straight hole with a maximum deviation of 2 degrees at 2074'. The survey deviations were: 0 deg. at 524', 0.75 deg at 868', 1.25 deg at 1350', 1.0 deg at 1572', 2.0 deg at 2074', and 2.0 deg at 2544'. If one assumes these deviations down to 2400' and assumes that they are coming toward the #5 surface location, the maximum displacement toward the #5 is 44'. If one assumes the same deviations in the #5, but in the opposite direction, i.e., toward the #4, the wellbores could come within 72' of each other (assuming a 160' surface separation, which is planned). However, in reality, the deviations will likely go the same direction, so the 160' separation should mostly be preserved. Thus, there some well proximity risk, but the regular surveys and prudent drilling practices should minimize these risks. Other Risks Sticky bentonitic clays, boulders, lost returns & differential sticking with overbalanced muds and gas influx while cementing or swabbing while tripping pipe. Prepared by Ed Jones Page 9 of 12 Rev. 1.0 Aurora Gas, LLC Ioquawkie #5 Drilling Plan 2 7/8 6.5# 8rd EUE J -55 Tubing ' ".` r 14 k - Aurora Gas LLC -'4,1i.-1 '. • r 4 � � � Moquawkie #5 13-3/8 68# K -55 Structural Proposed Configuration ,4- Conductor driven to 8o GL - 4. 44444%6 _ • �• Drill 12 -1/4" Hole to 650' - f � ' 9 -5/8" 36# K-55 & 53.5# L-80 it �,�� Surface Casing set at 650' 2-7/8" x 5 -'' /z" annulus to be n 4 Cement w /13.0 ppg Type I displaced over to inhibited packer i4t 1 Prospective Beluga Pays Tsuga 2 -7- 1050 - 1102,1182 -1192, 4 1;1; 1228-36' .,. Z .4 Tsuga 2 -8-- 1357 -87' :", w ProspectiveTyonek Pays Carya 2 -1.1— 1746 -86' Carya 2 -2.1— 1947 -88' ( ,__ _ , Hydraulic Set Packer @ 1000' Carya 2 -23 — 2106 -76" Carya 2 -3 — 2252 -86' * k t 1 Sliding Sleeves @ —1200' & 1400' Tsuga 2 -7 & 2 -8 L ' , 1; Perforation Intervals to be . _ ��i Hydraulic Set Packer @1700' ii A determined by open -hole logging. AA ti" Ni t,a1 Carya 2 -1.1 .' s � " s CR c! Sliding Sleeve @ —1990' MD Carya 2 -2.1 2 7/8" 6.5# EUE 8rd Tubing w/ On- r ---- �--- - ' Off Tool on Mechanical Packer @ ,' 2075' w/ 2.31 profile X nipple Ca ry a 2 -2.3 Carya 2 -3 i 4,:* ' :' ;, , 4 4 Drill 7 -7/8" Hole to 2400' y . MD /TVD �� ' 5 W' 15.5# K -55 & 17 # N-80 Casing to 2400' , (MD/TVD) Estimated PBTD @ 2315' Prepared by Ed Jones Page 10 of 12 Rev. 1.0 Aurora Gas, LLC 0 ioquawkie #5 Drilling Plan MOQUAWKIE 5 DRILLING TIME 0 r a . '� x '�V: r r t '�' a 3 � -+ k � .,,, w .f� 2-k ` „,.4V•44 �� 4'� a `4�r K �. `s � ! .S i� 4 � �"`' tt `' • ,� •ro b � "P ' 1 '' 41 ' �*+ M" v , g� Y ',1.0) r, tY . �,, 'N- - " "° t d - - x �' '' k , r 3m - ' z e� 4 r a s ,. rt • tea r i . d G i ;. .. d & 3 Z -500 4' } 1, ,4 7, 'r P * t '' ` 4 t1 j P P� . v � 1 5 ; . . w ` r �” i k' ° P ia, Ea -VIOL ° " �' a , n �°p- v w O F '' 'j , .�4. .3 n .: " '� i r� , '+ -1000 �.� � � � � �� r� � '-t u � '7 44, , 44 d~ .tea e � � � +� �� r : �� ` �r f i „ n r ,„ s 5. "` 1,7 ; c " . m. fi ' £ ' ; s S . wr- , ' - o f , ,, . t S ' , t `' ``' 6, .�1 F ' ''' ^ � -.` "` , " � e ' , ,� ` ..4,,- ,'..,/-:',,,-„,1,:.., a }. , `h i s ' n �': ` Yv" , EI S r '- ? X33 '7 w e b r4 4 t� � _ erieS1 a -7500 �. ,� orr y r s rr '� / ` -. + "` � " �- $ W - ,F h ap � a *' e *ire "r* r� , x 3 c 4 , , r s .. ;� y � �� v 3 '�. .�Y � Pe � a 4 n�"`�. #�i1 ' S " � 4,/ x• r' �' ° '� x ^,� � a -2000 "fix a x ' ' 0 a,„ -- -- i " " ' w :*' x„,2 ., F r s c a y it a , , , -�t '4 4 ' P ` `z � > ," 4 ". r.' �y � i ' t ,�, .4-,. .� .� � 4 � �i r L„ 'i 5 t� 7� ` , `FOP , �.y,TZw'� ,..0 R -'�"k ' e � � 'g 3 `d{ ' b S , } ':r ^&',f -w J � ro� [ W � # ry ''"' ass , d W t '` ,r st y a t� r r s ' k' + E�, s � a s, ' *fi Al.. '� %.:0=4',,61-4.,1,,,, h — 2500 e.w rs ' ; d i x n r . ' . • 4 , 5 a GF?x� u�3 ,� �' a`�w4 �'� s o�.�. � .t�.r ,� ,.��w�. ��a�.s 'Y�' s� �` � r "� • 3 40 , ::;:iz,;,,,,,z: :t� ',SF E � ,-�i ;,,,. i^,, 'p fr a� " , 4 µ, €4 xa -3000 DAY Days 1 -2: Drill 12-1/4" Hole Days 2 -4: Run and cement 9 -5/8" casing Day 4 -5: Test casing, drill out w/ 7 -7/8" bit and run SIT, drill 7-7/8" hole to first core point. Day 5 -6: Cut and lay down first core. Days 6 -9: drill 7 -7/8" hole to second core point Days 9 -10: Cut and lay down core #2 Days 10 -11: Drill to TD of 2400' Days 11 -13: Log Days 13 -14: Run 5 -1/2" casing and cement. Days: 15 - - -: Complete and test well. Prepared by Ed Jones Page 11 of 12 Rev, 1.0 Aurora Gas, LLC • •ouawkie #5 Drilling Plan MOQUAWKIE # 5 Summary of Drilling Hazards POST THIS NOTICE IN DOGHOUSE There is potential for abnormal pressured shallow gas. 1 Ai There is potential for stuck pipe in coals encountered while drilling from surface to TD. Short trips as dictated by drilling trends. .I There is no H2S risk anticipated for this well. Ai Due to otential for shallow gas kick, very little response time will p g � ry P 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 MOQUAWKIE #5 WELL PLAN FOR ADDITIONAL INFORMATION Prepared by Ed Jones Page 12 of 12 Rev. 1.0 MOQUAWKIE #5 Casing Properties and Design Verification Casing Performance Properties: Aurora Gas Moquawkie #5 Tensile Strength Section Internal Collapse Size Weight Yield Resistance TVD MD MW MASP (Inches) lb /ft Grade Cnxn (psi) (psi) Joint Body Length (ft RKB) (ft RKB) (pig) BF (psi) 9 -5/8" 53.5 L -80 BTC 7930 6620 1329000 1244000 650 650 650 10.5 0.84 482 9 -5/8" 36 K -55 LTC 3520 2020 489000 564000 650 650 650 10.5 0.84 482 5 -1/2" 15.5 K -55 BTC 4810 4040 300000 248000 2400 2400 2400 11.6 0.82 1156.8 5 -112" 17 N -80 LTC 7740 6280 348000 397000 2400 2400 2400 11.6 0.82 1156.8 Design Safety Factor* Size Tensile Burst Collapse 9 -5/8" 45.5 16.5 22.8 9 -5/8" 24.9 7.3 7.0 5.5, 15.5 9.8 4.2 3.3 5.5 17 N 10.4 6.7 5.2 ) * Tensile design safety factors are calculated using pipe weight less buoyancy. Burst design safety factors are calculated at the surface using zero backup on the outside and MASP on the inside. Collapse design safety factors are calculated at the casing shoe using the maximum expected mud weight to be used at the El shoe depth on the outside and the entire cased hole evacuated except for a gas gradient on the inside. Casing Setting Depth Rationale 9 -5/8" 650' MD / 650' TVD Surface casing to stabilize shallow formations provide an anchor for the BOP stack and provide shoe strength in the event of a kick. 5 -1/2" 2400' MD / TVD Production casing to stabilize and isolate producing interval for production operations. Ed Jones 6/9/2009 • • Aurora Well Service Rig No. 1: Proposed Surface Diverter System Bell Nipple Flow Line to Pits Fill Line 13 -5/8 ", 5000 psi WP Annular Preventer oy Operated 12 aloe 111 f I ® , i 1 _ 13 -5/8 ", 5M Drilling Spool / Mud Cross a" Diverter Vent Line 13-3/8" Conductor Pipe with 13 -5/8 ", 5000 psi WP Flange welded on top i 1 1 Aurora Well Service R bg No 1: Proposed 3M BOP Comfguration Bell Nipple with flow line to pits Fill Up Line i , '3M Schaffer Annular Preventer i ---1 1 Pipe Rams sized to work string. 1 11" 3M Double Gate w/ 3/12" pipe rams installed. 11" 3M Mud Cross Blind Rams „ 3 5M Manual Valve (Kill Line) �3 5M Manual Valve (Choke Line) 3" 5M Hydraulic Valve (Kill Line) �� ■ 3" 5M Hydraulic Valve ori‘ Fluid flow direction „---w 'r.h 11N1pI I � 11. II III (Choke Line) while reverse circulating 11""X 3M Ell ; i 411'11N 1IR N f i�� =1I11N 2 , � 3M Manual Valves On Wellhead Braden Head Ali 9 5/8" Casing 13 3/8" Conductor • • • Aurora Well Service Rig No. 1 Proposed Choke / Kill Manifoiu Configuration All valves are 3" rated at 5000 psi. Inlet from Output to Pits Power Swivel (Reverse Circulation Mode) I ai, 2" 5M Rated i ® Valves ® 410 Hydraulic Remote Activated choke Inlet from BOP I 1 3 II Choke Line s IIIINME I 3" 5M Rated ® Valves �r mumem r� OPO _ .. ®L H 1�i �� I � I I _.. I 1-I Bleed Flare Line to ® ; 3" 5M Rated ill Flare Pit 3" 5M Rated ..1 Valves Valves E. minimm r MUM 1 NM ■ IIYII Ii®i1 � 1, Manual Choke Ida 2" 5M Rated V IW alves To Gas Buster "Atmospheric Degasser" • • = A urora Gas, LLC www.aurorapower.com June 10, 2009 RECEIVED Mr. Dan Seamount, Chair JUN 1 0 2009 Alaska Oil and Gas Conservation Commission 333 West 7`" Ave., Suite 100 Alaska Oil & Gas Cons. Commission Anchorage, Alaska 99501 Anchorage RE: Application for Permit to Drill: Moquawkie No. 5 Dear Mr. Seamount: Aurora Gas, LLC hereby applies for a Permit to Drill an onshore gas exploratior{well in the Moquawkie Gas Field northwest of the village of Tyonek. The well is planned as a vertical well targeting the Upper Tyonek Formation to test for gas. Aurora is proposing to also core and possibly test selected coal seams. Please refer to the attached Drilling Plan. The rig to be used is the AWS #1. The rig's well control systems are on file with the Commission. Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10 -401 Application for Permit to Drill. 2) A plat showing the surface location of the well. 3) A Time versus Depth plot. 4) Proposed casing program. 5) Proposed cementing program. 6) Proposed drilling fluid program. 7) Proposed summary drilling program. 8) Summary of Drilling Hazards. 9) Schematic of the proposed wellbore and completion. 10) Aurora Gas does not anticipate the presence of H2S in the formation to be encountered in this well. However, H2S monitoring equipment will be functioning on the rig at all times during drilling and completion operations. 11) The following are Aurora Gas' designated contacts for reporting responsibilities to the Commission: 1400 West Benson Blvd., Suite 410 • Anchorage, AK 99503 • (907) 277 -1003 • Fax: (907) 277 -1006 6051 North Course Drive, Suite 200 • Houston, TX 77072 • (713) 977 -5799 • Fax; (713) 977 -1347 • • Mr. Dan Seamount June 10, 2009 Page 2 1) Completion Report Ed Jones, Executive Vice President (20 AAC 25.070) (713) 977 -5799 2) Geologic Data and Logs Andy Clifford, VP - Exploration (20 AAC 25.071) (713) 977 -5799 Aurora submitted a Spacing Exception application on June 1, 2009, and a request for a gas well determination for the ADEC exemption from the C -Plan requirements on June 9, 2009. We respectfully request the approval of this Permit to Drill in advance of the AOGCC Spacing Exception authorization. We understand no testing of production of formation fluids may occur until such an exception is obtained. If you have any questions or require additional information, please contact me or Mr. Ed Jones at (907) 277 -1003. Sincerely, AURORA GAS, LLC - Lre'S Bruce D. Webb Manager, Land and Regulatory Affairs enclosures • Notice of Public Hearing and Comment Opportunity STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of Aurora Gas, LLC for a spacing exception under 20 AAC 25.055 to drill the Moquawkie No. 5 well. Aurora Gas, LLC (Aurora), by a letter received June 2, 2009 by the Alaska Oil and Gas Conservation Commission (Commission), requests an order for an exception to the spacing requirements of 20 AAC 25.055(a)(4) to drill the Moquawkie No. 5 vertical gas development well within the same governmental section as, and within 3,000 feet of, wells capable of producing from the same pool. The proposed surface and bottomhole locations of the Moquawkie No. 5 well are the same: 1,169 feet from the north line and 1,268 feet from the west line of Section 1, T11N, R12W, Seward Meridian (S.M.). A public hearing on the application is tentatively scheduled for July 21, 2009, at 9:00 a.m. at the Commission: 333 West 7 Ave., Suite 100, Anchorage, AK 99501. To request that the hearing be held, a written request must be filed by 4:30 p.m. on July 6, 2009. If a request is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold a hearing, call 907 -793- 1221 after July 9, 2009. Written comments regarding the application may be submitted to the Commission at the address above. Comments must be received by 4:30 p.m. on July 17, 2009, except that, if a hearing is held, comments must be received by the conclusion of the hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, call 907 - 793 -1221 by July 20, 2009. Daniel T. Seamount, Jr. Chair 1 TRANSMITTAL LETTER CHECKLIST WELL NAME MigialA) LI -e., A-5 PTD# 2, di /Deve lopment Service Exploratory Strati ra hic Test P P Y g P Non - Conventional Well FIELD: ff.° MAI b POOL: n i l ccua,GOLCA, & (114- S Circle Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK ADD -ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well , (If last two digits in Permit No. , API No. 50- - - . API number are between 60 -69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well . SPACING The permit is approved subject to full • pliance with 20 AAC / EXCEPTION 25.055. Approval to perforate a i • roduce / in'ect is contingent V upon issuanc of a cons e,gation • . er a proving a spacing exception 1 v-64-- ` L_.�d assumes the liability of any protest to the spa/ / cinn exception t t m y occur. , --t 'cc 5� 4`7 / /2 L DRY DITCH All dry ditch sample ets submit d to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non - Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: 1/11/2008 WELL PERMIT CHECKLIST Field & Pool MOQUAWKIE, UNDEFINED GAS - 528500 Well Name: MOQUAWKIE 5 Program DEV Well bore seg ❑ PTD#: 2090650 Company AURORA GAS LLC Initial Class/Type DEV / PEND GeoArea 820 Unit On /Off Shore On Annular Disposal ❑ Administration 1 Permit fee_attached NA 2 _Lease number appropriate Yes CIRI lease C- Q61390 3 _Unique well name and number Yes 4 Well Jocated in a defined pool No MOQUAWKIE, UNDEFINED GAS - 52850Q .. _ 5 Well Jocated proper distance from drilling unit_boundary Yes Will be located. over _1 _mile from nearest property boundary where ownership changes 6 Well Jocated proper dlatance from other wefts No $PACING EXCEPTION NEEDED: _ looated_closer than 3000_ to nearest producer.. Hearing scheduled_7 /t 2(0$. 7 Sufficient acreage available in_ drilling unit No SPACING EXCEPTION NEEDED: _ 4th gasproducer in Section 1. 8 If_deviated, is yrellbore plat included NA Vertical well 9 _Operator_ only affectedparty Yes 10 Operator has appropriate bond in force Yes _ _ , _ _ _ _ NZ$429815 11 Permit can be_ Issued without conservaticnorder No SPACING EXCEPTION NEEDED Appr D ata 12 Permit can be Issued without administrativaapproval Yes SFD 6/26/2009 13 Can permit be approved before 15 day_walt Yes • 14 Well Jocated within area and strata authorized_py injection Order # (put 10# in_comments) _For _ _ _ NA 15 All wells within 1/4 mile area of review ldentltled_(For ,service well only) NA Well plan proposes coring oftwo 15 to 2Q- footthick coal seams at t11'_& t890' depth. _Nearest subsurface 16 Pre- produced_injector.. duration of pre- roductlon less than .3 months (For service welt only)_ NA water rights are for Dimond Chuitna_MlneHousing Facilities, located 3- 3/4miles to NNW_In Section14, T12N, 17 _Nonconven._gas conforms to A$31,Q5,030(j.1_.A),(j.2A -D)_ Yes R12W, SM. Coals will not be used as sources of drinking water, 18 _Conductor string provided Yes Driven to 95', Engineering 19 Surface casing protects all known USDWs Yes Set © 650', 20 _CMT_vol adequate to_clrculate on conductor_& surf csg Yes Adequate excess. 21 _CMTTvol_adequate to tie In long string to surf csg Yes Two cement stages, 22 _CMT_wIil coyer all known productive horizons Yes 23 Casing designs_ adequate for C. T, B.& permafrost Yes Safety factors adequate, 24 Adequate tankage or_reserve pit Yes AWS Rlg.1. 25 If a_re drill, has a 10-403 for abandonment been approved NA New well, 26 Adequate wellbore separation_proposed No Spacing exception. required. 27 If.dlverter required,.does_ft_meet regulations No Vent line variance required. Appr Date 28 DrWUing. fluid _ progr am.schematio8equipilst_adequate Yes Max MW 12.0ppg, WGA 6/18/2009 29 BOPEs, do they meet regulation Yes Apr.J /Of' 4.,1 P . /4.26,46 30 _BOPE_press rating_appropriate; test to_(put psig In comments) Yes MASP 1157 psi;_test rams 10 psi,_annular to_1500 psi. • 31 Choke_manifoJdcompiles w /API RP -53 (May 84) Yes 32 Work will occur.without operatlon_shutdown Yes 33 le presence of 1712$ gas probable No Monitors planned. 34 _Mechanical condition of wells within AOR verified (Foram. ice well only) NA Non - service well, 1 35 Permit can be Issued w/o hydrogen sulfide measures Yes No record of H2S Jn_shallow sands within_ this area. H2$ monitodng_equipment will be used. Geology 36 Data_presented_on potential overpressure zones Yes Well wii be mudlogged, Weft will be_drilled with 10.0 to 12.0 ppg. mud, Appr Date 37 Seismic analysis of shallow gas zones NA SFD 6/17/2009 38 Seabed condition_survey (if off- shore) NA 39 Contact name /phone_for weekly_progress reportsjexpioratory only] Yes Ed Jones 713 977 - 5799 Geologic Engineering ` SPACING EXCEPTION REQUIRED. Hearing scheduled for 7/12/2009. MUDLOGGERS AND GAS DETECTION EQUIPMENT Commissioner: Date: issione : Date C ,r/ i __ r Date REQUIRED due to shallow gas hazards in the area: Moquawkie 4 blew out; Moquawkie 1 had a blowout and fire caused by � shallow gas; and Moquawkie 3 flowed at 1020', 1258' & 1539'. r 30 -off