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Home My WebLink About212-135STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Armstrong Cook Inlet, LLC for an exception to the spacing requirements of 20 AAC 25.055 to drill and complete a development gas well within the same governmental section and within 3,000 feet of wells that are, or may be capable of, producing from the same pool. IT APPEARING THAT: Docket Number: CO-12-18 Conservation Order No. 660 North Fork Unit No. 33-35 Development Gas Well North Fork Undefined Gas Pool North Fork Unit Kenai Peninsula Borough, Alaska September 27, 2012 1. By letter received June 14, 2012, Armstrong Cook Inlet, LLC (Armstrong) requested an exception to the spacing provisions of 20 AAC 25.055 to allow drilling and completion of the North Fork Unit No. 33-35 (NFU 33-35) development gas well within the same governmental section and within 3,000 feet of wells that are, or may be capable of, producing from the same pool. 2. On August 6, 2012, by certified mail, Armstrong sent notice of the application to all owners, landowners, and operators of all properties within 3,000 feet of the planned NFU 33-35 well. Armstrong provided the AOGCC the notice, date of mailing, addresses to which the notice was sent, and proof of mailing. 3. Pursuant to 20 AAC 25.540, the AOGCC tentatively re -scheduled a public hearing for September 26, 2012. On August 21, 2012, the AOGCC mailed printed copies of the notice of the opportunity for public hearing to all persons on the AOGCC's mailing distribution list, published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On August 22, 2012, the notice was published in the ANCHORAGE DAILY NEWS. 4. No protest to the application or request for hearing was received. 5. The tentatively scheduled public hearing was vacated on September 13, 2012. 6. Because Armstrong provided sufficient information upon which to make an informed decision, the request can be resolved without a hearing. Order 660 September 27, 2012 Page 2 of 3 FINDINGS: 1. Armstrong is the operator of the North Fork Unit and the planned NFU 33-35 development gas well, which are located in the Kenai Peninsula Borough, Alaska. 2. NFU 33-35 will be an onshore, deviated development gas well with a surface location 588' from the south line and 1,513' from the east line of Section 26, T04S. R14W, Seward Meridian (S.M.). The estimated top of the productive interval is 1,530' from the south line and 2,165' from the east line of Section 35, T04S, R14W, S.M. The projected bottom -hole location is 1,530' from the south line and 2,165' from the east line of Section 35, T04S, R14W, S.M. 3. NFU 33-35 will be located within State of Alaska leases ADL-391210 and ADL-391211. 4. Other potentially affected owners, landowners, and operators --those within a 3,000-foot radius of the well —are the State of Alaska; Armstrong; Dale Resources Alaska, LLC; GMT Exploration Company LLC; Jonah Gas Company, LLC; and Nerd Gas Company, LLC. Armstrong sent notice of its application to these entities by certified mail on August 6, 2012. 5. Development gas well NFU 32-35 currently produces within 3,000 feet of, and within the same governmental section as, the planned well NFU 33-35. Armstrong plans to drill additional gas development wells within this same governmental section. 6. The reservoir sands accessed by NFU 33-35 are discontinuous fluvial sands. 7. The AOGCC received no comments, objections or protests in response to the public notice regarding NFU 33-35 or to the notification sent by Armstrong to all known owners, landowners and operators within 3,000 feet of NFU 33-35. CONCLUSIONS, 1. An exception to the well spacing provisions of 20 AAC 25.055(a)(4) is necessary to allow drilling and completion of the NFU 33-35 development well in gas reservoirs in order to maximize recovery of reserves, 2. NFU 33-35 will recover reserves that are not accessible to other existing wells. 3. A spacing exception to allow drilling and completion of NFU 33-35 is consistent with sound engineering and geoscience principles and will not result in waste or jeopardize correlative rights of adjoining or nearby owners. 4. An exception to the requirements of 20 AAC 25.055(a)(4) will not promote waste or jeopardize correlative rights. Order 660 September 27, 2012 Page 3 of 3 NOW THEREFORE IT IS ORDERED: Armstrong's June 14, 2012 application for an order granting an exception to the well spacing provisions of 20 AAC 25.055(a)(4) to allow drilling and completion of the NFU 33-35 development gas well is hereby approved. Armstrong may proceed with regular production as long as it complies with the terms of the North Fork Unit Agreement, applicable Alaska laws, and all other legal requirements. DONE at Anchorage, Alaska and dated September 27, 2012. Mi14 Cathy P Foerster Chair, Commissioner TION AND Daniel T. eamount, Jr. Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application For reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL, and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC snails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was riled. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, mid it may be appealed to superior court. That appeal mus'r be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[tllte questions reviewed on appeal are limited to the questions presented to Use AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period rums until 5.00 p.m. oil the next day that does not fall on a weekend or state holiday. THE STATE Alaska Oil and Gas °fALASKA Conservation Commission GOVERNOR SEAN PARNELL Edward Teng Vice President -.Engineering Armstrong Cook Inlet, LLC 1421 Blake Street Denver, CO 80202 Re: North Fork Field, North Fork Oil Pool, North Fork #33-35 Armstrong Cook Inlet, LLC Permit No: 212-135 Surface Location: 588' FSL, 1513' FEL, SEC. 26, 4S, 14W, SM Bottomhole Location: 1530' FSL, 2165' FEL, SEC. 35, 4S, 14W, SM Dear Mr. Teng: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Enclosed is the approved application for permit to drill the above referenced development well. At a minimum, per 20 AAC 25.071(a), a gamma -ray log must be acquired across the interval from the base of conductor pipe to the surface casing shoe. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce is contingent upon issuance of a conservation order approving a spacing exception. Armstrong Cook Inlet, LLC assumes the liability of any protest to the spacing exception that may occur. 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. Sincerely, Cathy P/Foerster Chair DATED this day of September, 2012. cc: Department of Fish & Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) STATE OF ALASKA .SKA OIL AND GAS CONSERVATION COM1, 31ON RECEIVED PERMIT TO DRILL 2n AAC: 25 nns SEP 0 7 2012 1a. Type of Work: Drill F�] - Redrill ❑ Re-entry ❑ 1 b. Proposed Well Class: Development -Oil Service - Winj Lj Single Zone ❑ Stratigraphic Test ❑ Development - Gas 0 • Service - Supply ❑ Multiple Zone ❑✓ Exploratory (Gas) ❑ Service - WAG Service - Disp ❑ 1 c. Specify if w i Coalbed Gas ❑ Gas Hydrates ❑ Shale Gas El 2. Operator Name: Armstrong Cook Inlet, LLC 5. Bond: Blanket ❑� Single Well ❑ Bond No. 559 . 11. Well Name and Number: North Fork #33-35 3. Address: 1421 Blake St., Denver, CO 80202 6. Proposed Depth: MD: 11,210 TVD: 9,778 12. Field/Pool(s): North Fork () 4a. Location of Well (Governmental Section): Surface: 588' FSL & 1513' FEL 26 4S 14W SM Top of Productive Horizon: 1530' FSL & 2165' FEL 35 4S 14W SM Total Depth: 1530' FSL & 2165' FEL 35 4S 14W SM 7. Property Designation (Lease Number): ADL-391210yy/ Ll 8. Land Use Permit: / `l /( /L 13. Approximate Spud Date: 1-Se -12 9. Acres in Property: 1920.00 14. Distance to Nearest Property: 588 FSL 1513 FEL 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 199,898 y 2,121,130 Zone- 4 10. KB Elev above MSL: 679 feet GL Elev above MSL: 658 feet 15. Distance to Nearest Well Open to Same Pool: 1996' to NFU 32-35 16. Deviated wells: Kickoff depth: 700 feet Maximum Hole Angle: 38.65 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 4576 - Surface: 3598 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 0 16 0.5 x56 Welded R3 0 0 120 120 Driven 13 112 10 3/4 45.50 N/L 80 BTC R3 0 0 3,020 2,736 720sx Lead @ 12ppg + 250sx Tail @ 14.8ppg 8 3/4 7 26.00 N/L 80 BTC-M R3 0 0 11,210 9,778 600sx Lead @ 12.7ppg + 230sx Tail @ 13.8ppg 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 Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft) Perforation Depth TVD (ft): 20. Attachments: Property Plat 0 BOP Sketch ❑✓ Drilling Program 0 Time v. Depth Plot Q Shallow Hazard Analysis❑ Diverter Sketch ❑� Seabed Report Frilling Fluid Program ❑� 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 9/1/12 22. 1 hereby certify that the foregoing is true and correct. Contact Stephen Hennigan 337 849 5345 Printed Name Edward Teng Title Vice President -Engineering Sign Phone (303) 623-1821 Date 9/4/2012 Commission Use Only Permit to Drill r Number:' f��5 API Number: ? 50- nI ` 1(..,C�� Permit Approval \ Date: �/ See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained i ales: Other: * Yod �• �/�,O Samples req'd: Yes ❑ No Mud log req© Yes❑ No SHzS measures: Yes ❑ No[5 Directional svy req❑✓❑ YesNo APPROVED BY THE COMMISSION DATE: C� ��l r' 7i ✓ COMMISSIONER ORIGINAL Form 10-401 (Revised 7/2009) This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) Submit in Duplicate y ARMSTRONG RECEIVED Cook hiler. LLC S E P 0 7 2012 ,- A®GGt September 04, 2012 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 RE: Application for Permit to Drill — Armstrong Cook Inlet, LLC — NF#33-35 Dear Ms. Foerster, Armstrong Cook Inlet, LLC hereby applies for a Permit to Drill an onshore gas well near Anchor Point on the Kenai Peninsula. Armstrong plans to spud the well in October, 2012. Armstrong plans on using the Nabors Rig 99 for the drilling of this well. If the well test results are sufficiently encouraging, the well will be placed on long-term production. 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) Plats showing the surface location of the well 3) Aerial map 4) Proposed Wellbore Diagram 5) Plan Plot 6) Drilling Time vs. Depth Plot 7) Program Details with calculations 8) Cementing Program Summary 9) Directional Plans 10) Wellhead diagram 11) Diagrams and Descriptions of the BOP Equipment to be used 12) Proposed Solids handling 13) Rig Layout 1421 Blake Street, Denver, CO 80202 (303)-623-1821 Ph (303)-623-3019 Fax Page 2 Following are Armstrong's designated contacts for reporting responsibilities to the Commission: 1) Completion Report (20 AAC 25.070) - Stephen Hennigan, (337)-849-5345 2) Geologic Data and Logs (20 AAC 25.071) - Colby VanDenburg, (303)-623-1821 If you have any questions or require additional information, please contact one of the following: Stephen Hennigan 337-849-5345 Edward Teng 303-623-1821 Colby Vandenburg 303-623-1821 Thank you. Sincerely, Edward Teng Vice President -Engineering Armstrong Cook Inlet, LLC Enclosures Cc: Colby Vandenburg — G&G Stephen Hennigan — Petroleum Engineers for Armstrong Cook Inlet, LLC _ — �--- — - N 2121143.9950 E 1340068,0700 CP-1 ELEV 666,07' N 2121137.2190 ' E 1339704.6100 _-___- - �_ ELEV 656;691 660 OHE------- L— h EC. METER � PANEL POST --"— -� _ POST C'q_ L -PIPE �� ---_ — m X — X CONEX v W � Tract18 �s� 'GATE X m 41 ©O m --U - 34.26 WELL 32-35 WELL 14-25 WELL m I'i I' I DRILLING PAD x NFU 33-35 WELL j N:2120885.180 E:1339923.440 LATITUDE: 59°47'44.159" N �'' LONGITUDE:-151'37'53.855" W "' NAD83 ASP ZONE 4 �!.! ELEV. 657.8' NAVD88 J X co � �; Tract 19 u') North Fork Acres Subd. No. 12 8'CHAINLINKFENCE I�' ; -- -r�n ; 665--- I -- TOP F BERM Section 26, T04S, R14W, S.M., AK. NORTH SCALE 0 100 200 FEET H irow, He NN lot ..'4 TH •S�� II *..' 49 _*.•* �i ..... C .. c . 00 STAN A. MCLANE 4637—S ,II PFo'•.3/30/12. �h 513' ------ -a► FEL I w U 0 2 al J W I N 2120261.15 E 1341421.67 S26 S25 S35 S36 1. BASIS OF HORIZONTAL COORDINATES ARE ALASKA STATE PLANE NAD 83 ZONE 4 EPOCH 2O03 DETERMINED BY AN NGS OPUS SOLUTION FROM CORS BASE STATIONS "KEN5" , "TSEA" AND "KOD5•' OBSERVED DEC. 13, 2007ON NF1 3 112" ALUM. CAP SET N: 2121137.137 E 1339704.533 ELEV.656.69 2) BASIS OF ELEVATION IS NGS BENCHMARK N86 TT0195 ELEV. 180.84 FT, NAVD88 DATUM. 3) SOUTHEAST CORNER SEC. 26 COORDINATES DETERMINED FROM DIRECT SURVEY TIE TO THE TO EXISTING BLM SECTION CORNER TIE PER HM91-57 AND NOT THE PROTRACTED SECTION CORNER VALUES. PROJECT REVISION: ARMSTRONG COOK INLET, LLC NORTH FORK 33-35 WELL DATE. 3/30112 BGB AE DENVER,GO8020214� AS -STAKED SURFACE LOCATION DIAGRAM NAD83 SCALLE: 1- SC=100' 4' PROJECT NO 12023 E NGINEER ING l MAPPING / SURVEYING I TESTING COn5ul.bnfj Ina P.0 BOX 460 SOLDOTNA, AK 99%9 M Q VOICE (907)2e3A216 FAX 19071283-3265 EMAIL SAMCLANE@MCLANECGCOM BOOK NO. LOCATION SW 1/4 SE 1/4 S26 T4S R14W SEWARD MERIDIAN, ALASKA SLIEST °F 1 CP-2 N 2121143\.99- 50 E 1340068.0700 CP-1 ELEV666.0T N2121137.2190 E 1339704.6100 ELEV656,69' i a4 0HE ^70HE OHE LEC..MEI PANELPOSfi66O-----__�___ POST—�� - un-----� rn /! X X / 7 CONEX D a �,I.j it 65 Tract 18 1% GATE! ID I,i il+ O _ 34-26 WELL 32-35 WELL 14-25 WELL I� x DRILLING PAD x NFU 33-35 WELL N:2121130.02 E:199898.02 LATITUDE: 59°47'46.3626" N LONGITUDE:-151'37'46.0848" W NAD27 ASP ZONE 4 ELEV. 657.8 NAVD88 x Tract 19 L&,CHAfNLWK FENCE Fork Acres Subd. No. FENCE --- E611 - b(O Section 26, T04S, R14W, S.M., AK. LL. TOP F BERM SCALE 0 100 200 FEET PROJECT ARMMONG COOK INLET, LLC 70017TH STREET111400 DENVER, CO80202 ENGINEERING 11AAPPING / SURVEYING I TESTING Consulting Inc P O. 13OX 468 SOLDOT__0 A AA 996G9 M VOICE (907)283A218 FAX 1007)2833265 EMAIL 5AMCLANEeMCLANECGCO!A o M Wco i [ 0' V[ _. --- X tJ I' Of • U CL IIW � %%X111,111 I 49 TH ................................. 00 / 00 -�z.. ; '" STAN A. McLANE 01 c� np, .• 4637—S _ �,` IIi FP�o.'.3/30/12,. °ROFESS I p ' LA *1111, IEEE_-- — - --- W V 0 1„ 2 Z J 0 Imo` Lu N 2120261.15 E 1341421.67 S26 S25 S35 S36 1. BASIS OF HORIZONTAL COORDINATES ARE ALASKA STATE PLANE NAD 83 ZONE 4 EPOCH 2O03 DETERMINED BY AN NGS OPUS SOLUTION FROM CORS BASE STATIONS "KEN5" , " TSEA" AND "KOD5" OBSERVED DEC. 13, 2007 ON NF1 3 1/2"ALUM. CAP SET N: 2121137,137 E: 1339704.533 ELEV.656.69 2) BASIS OF ELEVATION IS NGS BENCHMARK N86 TT0195 ELEV. 180.84 FT. NAVD88 DATUM. 3) SOUTHEAST CORNER SEC. 26 COORDINATES DETERMINED FROM DIRECT SURVEY TIE TO THE TO EXISTING BLM SECTION CORNERTIE PER HM91-57 AND NOT THE PROTRACTED SECTION CORNER VALUES. NORTH FORK 33-35 WELL AS -STAKED SURFACE LOCATION DIAGRAM NAD27 FOR INFORMATIONAL PURPOSES ONLY LOCATION SW 1/4 SE 1/4 S26 T4S R14W SEWARD MERIDIAN, ALASKA REVISION. DATE. 3/30/1? DRAVW BY: BGB SCALE. 1 "=100' PROJECT NO 12023 BOOK NO. SHEET 1OF 1 Exception Plats (Previously applied for exception) O �— M w U U •Ca JS p 'i �U yn I N O Z) p ry U 3n�az'`a i 00 Q) 9 C.) J 04 N Q M N M M ti a QU) LL ry Q P ¢ LL LL M CA ~ Z p to M �; 4 N N M i B7A' y, i r r J (0 p iy O -M N N �0 .J W Q 0i 9 L' •- J M 2 M '. L� 0� M 0) 9 M N �a J (n 0 LL Z Q r 4 N _N O) J U] -1 Ul W Q Q N L M MM ❑ c) -- ----J M —O o p ♦ ' r'M U. t— r a) _ rJU) p r Q Z r r �O { M C i i COS cn `' ('� M i { Z) U- (D O z O J LA N N Q r M CD co � 0 ♦ ♦ �cya/ I.b LL r ` 0 r ` ' • Z` M ' U 0' LL F I f6 O of Y O LL s L O z Ln co In M UD Ln L!1 Ol Q1 Y Ln Q c O 0- 0 s U C ARMSTRONG ( bnk In/r!. LL ( ' Armstrong Cook Inlet, LLC () Exploration North Fork Unit # 33-35 NF Unit Block/Sec 26 4S 14W North Fork () Kenai Peninsula Bor. () Alaska Ser #.: 212 ??? USDW: ' ZIz_135 Pro Prepared By: Armstrong Cook Inlet, LLC () and Petroleum Engineers, Inc (337) 984-2603 and All American Oilfield Associates Armstrong Cook Inlet, LLC 0 North Fork Unit # 33-35 Block/Sec 26 4S 14W North Fork 0 Kenai Peninsula Bor. 0 Alaska Ser #.: 212 ??? S.3 8.6 9.8 100'pen* ......... T20-11 I I 5llx56 Welded ROP/Gas log Cond/l)rive to TD. 8.3 8,8 14.0 Mud Logging 30210 .:45.5# NIT 80 RTC 2 736' Casing I Upper Target Tgt TD Mud Logging: Manned: 2 sx every 10',0'to TD Est TOC Wtr. Dpth Drive Sz >> 16 " 13 1/2" 10 3/4, 9.0 10.0 16.5 Quad LWD 11111;ktq� L26# NIL 80 BTC-M 8 3/4" 9778' Bicenter/UIR ? 7 n 111 Al Ez Q Y L 0 LL 0 Z E. 0 0 0 0 0 0 0 0 0 O o O o 0 0 0 ,o 0 0 0 0 0 0 N M " OAD CO 0) CD 00 O — Y) �— O O O O N O 0 0 O O O 0 0 0 O LO 0 Armstrong Cook Inlet, LLC Q North Fork Unit # 33-35 Block/Sec 26 4S 14W North Fork 0 Kenai Peninsula Bor, 0 Alaska Ser #,: 212 ??? 0 Time vs Depth Casing Size & Depth Days vs MD TVD vs Days fI, k Prod Csg/Inr 1,000 2,000 r 3,000 I{ 4,000 j: I' 5,000 I 6,000 7,000 i i 8,000 I{ I y 9,000 j 10,000 I� C 11,000 P' 12,000 5 10 15 20 25 30 35 76, 7 0 0 -s 1 Emergency response Information 1.1 Directions to Location Method Directions Air Latitude: 59.47'46.3626"N longitude: 151.37'46.0848"W NAD 27 Directions from Kenai • Start outgoing north on Main St toward Highland Ave. travel 0.1 mi • Take the 2nd right onto Kenai Spur Hwy. Kenai Spur Hwy is just past Frontage Rd travel 0.7 mi • Turn right onto Bridge Access Rd. Bridge Access Rd is 0.1 miles past Spur View or travel 3.3 Ground • Turn right onto Kalifornsky Beach Rd. travel 16.2 mi • Turn right onto Sterling Hwy/AK-1/1-A1.Sterling Hwy is 0.2 miles past Heine Berger Ln travel 4S.7 mi • Turn left onto N Fork Rd.N Fork Rd is just past Williams Way travel 8.4 mi • Turn Right on Epic rd. travel 120' • Pad on right hand side of road 3S315 North Fork Road Anchor Point, Alaska 99556 1.2 Rig Contact Numbers (Tentative depending on rig and communications available at time of MIRU)) Rig Phone List Cell #'s Co.Man: See below Tool Pusher: Mud Engr: Directional: Expediter: Rig Fax: CM Backup: See below TP Backup: 1.3 Emergency Response Contact Numbers Company Contact Numbers Position Office Cell Larry Driskill Co Man (907) 598-1650 Larry MacAlester Co Man (907) 240-6244 Pete Berga Response Service Ambulance Fire Hospital Police Tool Pusher: Superintendent Location Homer, AK Anchor Point, AK Homer, AK Homer, AK Homer, AK Anchor Point, AK Spill & Contamination Alaska National Response Center Coast Guard AOGCC Main Single Point 1.4 Company Emergency Response Name Ed Teng Steve Hannigan Pete Dickinson Pete Berga Position Vice Pres.- Engineering Drilling Engineer Operation Manager Superintendent Drilling Supervisor Drilling Supervisor (573)201-3861 Contact Phone Front desk (907)235-8121 Station (907) 235-6700 (907) 399-1482 (907)235-3155 South Peninsula (907) 235-8101 Front desk (907) 283-7879 (907)235-3150 Alaska State (907) 235-8239 Alaska State Spill Reporting Refer to Facility chart Oil/Toxic Spills, etc (800) 424-8802 (800)479-5555 (907) 793-1226 (907) 279-1433 (866)942-6564 Office Mobile (303)981-9957 (337)849-5345 (907)230-6541 (573)201-3861 Prepared by Stephen F. Henniganq 9/5/2012 Page 6 2 Regulatory Agency Contacts by phone or email Agency Office M-F (8AM- 5PM) Contact 24 hr AOGCC (907) 793-1236 Inspection Supervisor (Jim Regg) See Industry Guidance 10-01 oom.aopcc, r hoe,haLLai iska.gov 3 Regulatory Compliance Regulation New Requirement 20 AAC 25 BOP testing every 7 days 24hr notice required 4 Drilling Program Summary 4.1 General Well data Name North Fork Unit k 33-35 Surface Lcn 588' FSL 8 1453' FEL 26 4S 14W Sit/Pad Exstg pad Field North Fork () KB (above MSL) 679 County/Prov Kenai GL (above MSL) 658 State AK Perm Datum KB Total MD 10,639 WD na Total TVD 9,700 USDW <+-2700' 4.2 Working Interest Owners Working Company Interest Address Armstrong 1421 Blake St., Denver, CO 80202 Operator Cook Inlet, LLC Lease/Lic ADL-391210 Was Code Spud Date(est) 09101112 API No. Permit No. Well Class Exploration Drlg Contractor Nabors Alaska Rig Name Rig 99 Primary Phone Fax (303)623-1821 Prepared by Stephen F. Henniganq 9/5/2012 Page 7 4.3 Geologic Program Summary NAD 27 Ii,T tT . 959"+17'46—N t.OeayITJCE-1,?�'3'?'3 L �a!"4"d NAM 7 Ate' ZZ FE 4 NAD 83 N> li :-25 WELL tt; .112.3554_7BC E 1.53 ?I -A11TJDtE: -OW5117LIM, 6d ZW ADP .-L"C'AE A r- 1pv. &'9'.B., sv5' oft NAD 27; Alaska Zone 4 X Co-ord. Y Co-ord. Surface Location Co-ordinates 199,958 2,121,128 Bottom Hole Location coordinates 200,686 2,117,904 Pore Pressure Targets M.D. (ft) T.V.D. (ft) X Co-ord. Y Co-ord. (ppg) est Upper Target 3020.55 2736.27 199,729 2,120,159 8.3 Tgt 7159.20 5968.35 199,286 2,117,612 8.4 TD 7823.00 6486.74 199,215 2,117,204 9 4 4 Formation Evaluation Summary �vZ -74` CZ,-;LJf.l GL LWD OH WL LOGGING OH TESTING/CORE MUD LOGGING FULL MUDLOGGING NONE NONE NONE CREW SURFACE TO TO v ` e -4'z' C —y / �i c i�- IZ GR, RES SURFACE CP TO 5700' MD INONE NONE GR, RES, DEN, NEUT, SONIC (P&S) Posslble NMR 5700' MD TO TO NONE NONE Prepared by Stephen F. Henniganq 9/5/2012 Page 8 4.5 Summary of Potential Drilling Hazards Hazard Event Depth Discussion /interval Balling Surface Maintain high gpm/rpm to keep bit/BHA clean Perform aditional circulating times Boulders/rocks/sand Surface Control penetration, add Icm, high vis sweeps Possible depleted zones Intm Wells off of same pad had no issues. High drill gas Intm Wells off of same pad had no issues. Precautions Monitor for loss of rtns Monitor for loss of rtns and differential sticking. Discontinuity of formations minimizes potential Monitor for connections in hole. Circulate hole clean to clear wellbore of gas before proceeding. Be sure degassing eqpmt is operating properly prior to spud. Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake, driller or relief driller is responsible for shutting the well in BOPE or diverter as applicable as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No H2S is anticipated. Gas sands MAY be encountered from ±30007VD to total depth of the well. These sands will run from slightly depleted to normal pressure. The drilling mud system will be properly weighted to control control the pressure of all sands and lost circulation materials will be available on location if required. Prepared by Stephen F. Henniganq 9/5/2012 Page 9 4.6 Drilling Program Summary 4.6 General Summary Well Name North Fork Unit # 33-35 Permit to Drill No. Location Surface: 588' FSL & 1453' FEL 26 4S 14W Top of Productive Horizon: 2593' FNL & 651' FWL 35 4S 14W Bottom Hole: 2593' FNL & 651' FWL 35 4S 14W Planned TD MD: ` 10,639 TVD: 9,700 Directional Plan As per program Well Summary A 16" conductor will be driven/drilled to ±120' and a cellar will be constructed and installed. Using water -based mud, approximately 1000' MD of 13-%" hole will be drilled as a straight hole prior to kicking off and drilling directionally to the first casing point at ±2750' TVD where 10-%" surface casing will be set and cemented to surface. Then a 8 314" hole will be directionally drilled to a planned TD of 1112079778' MD/TVD. If electric logs indicate zones that are encouraging, 7" production casing will be set and cemented. Then the well will be tested, completed, and then suspended for production hook-up. The entire production hole will be drilled in the Beluga and Tyonek Formations, which contain coal beds of varying thickness. The well will be drilled using PDC bits. These bits exhibit a reverse drilling break upon encountering coals, allowing time for these bits to work the coals as they distress and swell. Based upon the near offsets, gas cut mud may occur. Therefore there will be close monitoring and more circulation of mud to insure proper conditions for progressing. Based on offsetting well information, there are no shallow gas or H2S risks anticipated for this well. KEY DEPTHS Start Depth Seat Depth Interval Hole Size MD TVD MD TVD Drive/ Structural Driven 0 0 120 120 NO Conductor Surface 131/2" 0 0 3020 2736 IntmlProd 8 3/4" 0 0 11210 9778 Pore Pressure/ Mud Program The well will be drilled to TD using water -base mud with a weight of 9.3 to 9.9 ppg in the production hole section and adjusted as necessary while drilling to TD. Mud Logging Gas monitoring will be provided in the surface hole. Basic mud logging services will be provided from the surface casing depth to TD. Services will consist of cuttings description and construction of a lithology log. The mud loggers will tie their well monitoring system into a PVT system to help monitor fluid levels and system aains/losses. Logging Program Electric logging (either LWD or/and open hole) will be performed at each casing depth. If hydrocarbons are indicated to be potentially economic, then the testing phase will begin after casing is run at TD. BOP Testing BOP testing will be conducted at least every seven days. AOGCC Field Inspectors will be notified 24 hours in advance of spud and all diverted BOP Tests. It will be noted on drilling report and on IADC sheet whether the test was witnessed by the AOGCC inspector or waived. Waste Disposal All solid waste, including drill cuttings, will be disposed of in a nearby permitted facility. Excess mud and fluids will be disposed of as permitted. CompletionlWell Testing After the production casing/liner is run, it will be cleaned out and tested. A completion/test string and packer will be run. Each potential zone will be perfect, tested, and then isolated. Following the tests, zones to be produced will be identified and then put to completion. Prepared by Stephen F. Henniganq 9/5/2012 Page 10 4.7 Casing program Summary Start Depth Seat Depth Seat Depth Casing Interval Hole Size MD TVD MD TVD Size Wt(lb/ft) Grade Conn Burst Collapse Tension Drivel Driven 0 0 120 120 16 0.5 x56 Welded N/A N/A N/A structural NO Conductor Surface 13 1/2" 0 0 3020 2736 10.75 45.5 N/L 80 BTC 4230 2470 845 Intm/Prod 8 3/4" 0 0 11210 9778 7 26 N/L 80 BTC-M 7240 5410 604 Buck on float equipment @ yard MU casing to optimum torque 4.8 Calculation of Maximum Anticipate Pressures (MASP and MADP) Note: In this program, MASP for each hole section is defined as the pore pressure (in psi) at the next casing point (or TD) less a gas column to surface. The MADP is defined as the maximum pp WITHOUT a gas gradient. Gas gradient is assumed to be 0.1 psi/ft. 13 1/2" Hole Section — estimated pore pressure of 8.3 ppg emw This hole section will be drilled to depth with a diverter only (no BOP's) and t 8.7-9.1 ppg mw. While MASP will equal the formation pore pressure at the next shoe, less a gas gradient to surface, it cannot be shut in, only diverted. Calculations: MASP(pp) = ((PP ppge) x .052 x TVD) - (gg x TVD) MASPt,3 ,n*) = 2736' TVD x ((8.3 ppge`.052) - 0.1 psi/ft) 907 psi MADP = ((PP ppg) x .052 x TVD) MADP = 2736' TVD x (8.8 ppg' 0.052) 1252 psi 8 3/4" Hole Section — estimated MAXIMUM pore Pressure of ) 9 ppg emw This hole section will be drilled to TD with BOP's and related equipment installed and tested and with a 9.3-9.9 ppg mud weight. Based on available offset information the most likely maximum pore pressure is anticipated to be <8.6 ppg EMW. Calculations: MASP(pp) = ((PP ppg) x .052 x TVD) - (gg x TVD) MASP = 9778' TVD x (( 9 ppge'.052) - 0.1 psilft) 3598 psi ✓ MADP = ((PP ppge) x .052 x TVD) MADP = 9778' TVD x ( 9 ppg` 0.052) 4576 psi Prepared by Stephen F. Henniganq 9/5/2012 Page 11 4.9 Casing Design and Calculations Note: In this program, MASP for each hole section is defined as the pore pressure (in psi) at the next casing point (or TD) less a gas column to surface. Gas gradient is assumed to be 0.1 psi/ft. MADP is defined as the maximum pore pressure in the hole section. Start Depth Seat Depth Casing Interval Hole Size MD TVD MD TVD Size Wt(Ibtft) Grade Conn Burst Collapse Tension Drivel Driven 0 0 120 120 16 0.5 x56 Welded NIA NIA NIA structural NO Conductor surface 13.5 0 0 3020 2736 10.75 45.5 NIL 80 BTC 4230 2470 845 IntmlProd 8.75 0 0 11210 9778 7 26 NIL 80 BTC-M 7240 5410 604 = minimum of body and connection strengths RECOMMENDED Casing Design Factors BURST (from internal pressure) 1.1 COLLAPSE (from external pressure) 1 TENSILE (joint body and connection) strength 1.6 Prepared by Stephen F. Henniganq 9/5/2012 Page 12 BURST REQUIREMENTS 10 3/4" Surface 8 3/4" Hole Section — estimated pore pressure of 9 ppg emw This hole section will be drilled to 9778'TVD with BOP's and related equipment installed and tested and with a 9.3-9.9 ppg mud weight. Based on available offset information the most likely maximum pore pressure is anticipated to be 8.6 ppg EMW Estimated fracture gradient (FG) at the 10 W shoe is 14 ppg emw and safety factor (SF) of .5 ppg emw. from above MASP = 9778' TVD x (( 9 ppge'.052) - 0.1 psi/ft) 3598 psi MADP = 9778' TVD x ( 9 ppg" 0.052) 4576 psi MASP(fg) _ ((FG + SF ppg) x .052 x TVD) - (gg x TVD) MASP Csg Design = 2736' TVD x (( 14ppge+ .5 ppge) - 0.1 psi/ft) 1789 psi Burst Stress = MASP Csg Design is used since in case of a kick in excess of 1789 psi, shoe would break down. Design Factor Burst Strength/ Burst Stress = 4230 / 1789,344 2.36 SF 7 " Intm/Prod Since this is a production design, MASP of 3598 psi is used for highest pp. Design Factor Burst Strength/ Burst Stress = 7240 / 3598.304 2.01 SF s Prepared by Stephen F. Henniganq 9/5/2012 Page 13 COLLAPSE REQUIREMENTS Use an external pressure that the casing could possibly be put under. One design methodology uses pore pressure at the casing shoe with a gas gradient internally. 10 3/4" Surface External Pore Pressure less gas gradient MASP(pp) _ ((PP ppge) x .052 x TVD) - (gg x TVD) MASP(13 1/2") = 2736' TVD x ((8.3 ppge'.052) - 0.1 psi/ft) 907 psi Design Factor Collapse Rating /Collapse stress = 2470 / 907.2576 2.72 SF 7 " Intm/Prod External Pore Pressure less gas gradient MASP(pp) _ ((PP ppg) x .052 x TVD) - (gg x TVD) MASP = 9778' TVD x (( 9 ppge'.052) - 0.1 psi/ft) 3598 psis Design Factor Collapse Rating /Collapse stress = 5410 / 3598.304 1.50 SF TENSILE REQUIREMENTS Tension is usually defined as the body or connection tensile strength (whichever is least) compared to the buoyed weight of casing in mud when run. Buoyed weight is defined as weight in air minus the weight of displaced fluid that it is run in. Buoyed weight formula = MD ' Csg Wt (lb/ft) . (1- mw / 65.45) where 65.5 is the avg wt per cu ft of iron in air. 10 3/4" Surface Buoyed weight = 3020' MD x 45.5 ppf' (1- 8.8ppg / 65.45) 118935 pounds Design Factor = tensile strength / buoyed wt = 845000 / 118935 7.10 SF 7 Intm/Prod Buoyed weight = 11210' MD x 26 ppf' (1- 10ppg / 65.45) 246929 pounds Design Factor = tensile strength / buoyed wt = 604000 / 246929 2.45 SF /' Prepared by Stephen F. Henniganq 9/5/2012 Page 14 4.10 Casing Test Pressure Calculations Casing test pressures are based on the maximum of MASP or 50% of the BOP ram rating In this well, formation pressure is assumed to be the backup. See Casing design and MAW P calculations. BOP PROGRAM Test Pressures and Casing Test Pressures MASP = Maximum Anticiapted Surface Pressure (psi) MADP = Maximum Anticipated Downhole Pressure (psi) @ TD Casing Size Casing Equipment Test Pressure 16 " Structural Casing @ 120 ' 21-1/4" 2000 Diverter Function Test 70% of Burst N/A Test Pressure Function Test NO Conductor j Ij 70% of Burst: Test Pressure` 10.75 " Surface Casing @ 3020 ' (1) 13-5/8" 5000 Annular 250/ 2500 70% of Burst 2961 Min. (2) 13-5/8" 5000 Pipe Rams 250/ 4000 Test Pressure 3000 (1) 13-5/8" 5000 Blind Rams 250/ 4000 MASP 3598 MADP 4576 MASP Casing Design 1789 7 " Production @ 11210' (1) Will not drill out Annular 250/ 2500 70% of Burst 5068 Min. (2) Will not drill out Pipe Rams 250/ 4000 Recommended Test Pressure 3000 (1) Will not drill out Blind Rams 250/1 4000 Test PressureF 4000 MASP 3598 MAD P 4576 MASP Casing Design 3598 7" BOP Test Pressures for Completion Production (1) 70% of Burst 5068 Min. (2) Test Pressure 4000 (1) Annular 250/ 2500 Pipe Rams 250/ 4000 Blind Rams 250/ 4000 Prepared by Stephen F. Henniganq 9/5/2012 Page 15 4.11 Blowout prevention Equipment Details, Testing and General Procedures SEE ATTACHED DRAWINGS Testing: Onsite supervisor will verify all pressure tests. All tests are to be recorded on the IADC and DDR reports. ALL are to be charted. AOGCC to verify BOP tests (24 hr notice) Casing Test BOPs Test Casing Casing Size( MADP (psi) MASP (psi) Pressure Test Fluid 250 psi Pressure Density Size & Rating Low/high (psi) (lb/gal) (psi) Surface 10 3/4" 4,576 3,598 3000 8.8 (1) 13 5/8" 5M annular 2500 (1) 13 -5/8" 5M pipe ram 4000 (1) 13 -5/8" 5M blind ram (1) 13 -5/8" 5M drilling spool w/ 3 — 1/8" 5M outlets (1) 13 -5/8" 5M pipe ram Intm/Prod 7 4,576 3,598 4000 10 (1) 13 5/8" 5M annular 2500 (1) 13 -5/8" 5M pipe ram 4000 (1) 13-5/8" 5M blind ram (1) 13-5/8" 5M drilling spool w/ 3 —1 /8" 5M outlets For (1) 13 -5/8" 5M pipe ram COMPLETION 7 4,576 3,598 4,000 8.6 (1) 13 5/8" 5M annular 2500 (1) 13 -518" 5M pipe ram 4000 (1) 13 -518" 5M blind ram (1) 13 -5/8" 5M drilling spool w/ 3 — 1/8" 5M outlets (1) 13 -5/8" 5M pipe ram 4.11a The choke manifold will be rated 3 1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also on the location is a poor -boy gas buster and a vacuum type degasser. Flow sensors will be installed in the flowline and the mud pits will have a PVT system. All data will be available to the driller, company men and key individuals. 4.11 b Function Testing: Function on each tour. Report test on daily drilling report (DDR). Prepared by Stephen F. Henniganq 9/5/2012 Page 16 4.12 Wellhead Equipment Summary Component Description B.ASEPLATE KIT,2� OD X 1u ID X 1.50 THK, VV16 NUMBER 1 GUSSETS.W.M0 2-IJ2 GROUT SLOTS,F/13-518 CS,GHD Casing Head HSG.WG.SH12-BAR,1_ SM X 10-3/4 cXW''M'OR1NG,W12 2-1i 1ir 5M FPC, 5.A-F'U-AA-1-2 CSGHGR.X o-Ci SH2,1i X T 23_j Casing Hanger -26•1' LC iiGX BTM X 7.375.4 ACNE LA' PIN TOPMINBORE TBGHGR G.T-11140-CCL1:X 2-718,ELI STM AND Tubing Hgr TORINj2-IJ2 HBPV THD AND TWO DHCV PORT;', 413C; b+J1C, nA- LU-OO-"+9L-u-2 Tree 5k - TBD USE SPACER SPOOL AS NECESSARY SEE ATTACHED DRAWING Prepared by Stephen F. Henniganq 9/5/2012 Page 17 4.13 Directional Program Summary Well is to be drilled as a directional hole. Surveys will be taken per AOGCC regulations or more frequently as needed. 0.00 0.00 188.47 0.00 199898.UZ Z1Z11.iu.uZ U.Uu u.uu U.UU u.uu Est. RTE: 21' 20.55 0.00 188.47 20.55 199898.02 2121130.02 0.00 0.00 0.00 0.00 KOP 700.00 0.00 188.47 199898.02 2121130.02 0.00 0.00 0.00 0.00 End of Build 2246.10 38.65 188.47 2131.47 199811.94 2120635.43 2.50 2.50 0.00 502.03 Surface Casing 3020.55 38.65 188.47 2736.27 199729.00 2120158.87 0.00 0.00 0.00 985.75 Rvsd Target #2 Hora 7159.20 38.65 188.47 5968.35 199285.77 2117612.17 0.00 0.00 0.00 3570.73 Begin Angle Drop 7823.00 38.65 188.47 6486.74 199214.68 2117203.71 0.00 0.00 0.00 3985.33 EOD, Tgt 1 9110.03 0.00 188.47 7678.35 199143.03 2116791.99 3.00 -3.00 0.00 4403.24 Rvsd TD Horizon 11210.03 0.00 188.47 9778.35 199143.03 2116791.99 0.00 0.00 0.00 4403.24 Plots ARMSTRONG Well Armstrong Cook Inlet, LLC INSiS IMAXIIM Lorauon" Cook lrxaf Alaska (Kenai FerxnsWa) Sb1' Henn Fork fi3s3', help. Norm Forty Well. NFU#3335 NUONES Factl NOM F=UMt NADP W'911bIXe' NFUA33-35 Plot NFU #3335 Version #4 True vertical de the are ra(arencsd fo Nabors 99 (RTE) Gnd S temNAD27 r TM Alaska SR Zone 4 (5004). US feet Measured dalxfw era referenced to Nabors 99 RTE North Reference: True north Nabors 139 RTE to Mean Sea Leval: 678.35 /eet Scale: Tnte d.W- Mean Sea Level W Mud kne (At Sbt: North Fork *3335): O feet De hs era m feet C dmatas are In feet referenced to SWt Geated b nethah on 2SJW-12 Easltng (n) Sao a 900 North FWk #33-35 Est RTE' 21 KDP} O ✓FrJ�1 ''�� v 6+n CTondIK.IIX KC'iP Entl o1 Bu1ht 2.50'ltllOn 10 ]5,n Casln9 Sudarx= f Entl of Buf W Cactna S...- NFU33-35 Tar9at #2 (NAD2]I Rvsp: 9-3u1-t2 Msd Tar9at fit IaonZon BeOln AnOle Drop ao•rrocm NFU33-35 Taro t #2 (NAD2; Rvstl: 9Ju1-12 NFU:i3-35 T119et Al (NAD21) Rvsp 9-Jul-l2 Rvstl Ta 1 At Hp Target R kbrtzm Begin wt91e Drop U33RU THemet NF35TD (NAp2])Rvsd: 4JW-12 �� Tln Casing Prpductron NFu fi33-3s � RVSe Taryat fil Hon2on »�N-3- FU3335 Taryet*11-2])Rvsp9 lOD '.rt 3aa0 .9•!60 �600 6260 WOa TD HZ2-T)VBraCfll SACifOn (1i) 335 TD (NAD2])Rvsd SJUF12 A:ilttuUr t88 46• whit rererenca O 00 N. 0.00E -- Prepared by Stephen F. Henniganq 9/5/2012 Page 18 See 6-1. icy — — 1--11 Spider F <)sung (ff) Prepared by Stephen F. Henniganq 9/5/2012 Page 19 4.14 Directional Surveying Summary Downhole realtime surveying tool. Interval MD (ft) MWD/LWD Magnetic Multi Gyro Multi EEIog Other Remarks Drive/ Structural 0 120 NO Conductor 120 Surface 3020 x Intm/Prod 3020 11210 x 4.15- Drilling Fluids Program Summary and Specifications 4.16 Depth Mud Wt. Funnel Pv Yield Point Gels pH API FL HTHP FL Chloride SLDS (MD) vm 10 sec/10 min 250°F ppg sec/qt cp Ibf/100 R2 Ibf/100 ft2 cc mg/I %/Vol. 0' - 3,020'± 8.8-9.5 60-100 15-24 30+ 20/35 8.0-9.0 <18 N/A 5 5000 < 7 1 Pre -hydrate all Bentonite additions. Mix & pump prehydrated gel slurry in case of pea -gravel & massive sands, add Gelex to sweeps for added viscosity. 2 Run all available solids control equipment for maximum solids control. 3 Reduce fluid loss with additions of PolyPac Supreme UL prior to reaching 2000' 4 pH should be controlled with Caustic and / or Soda Ash 5 Add 2-5ppb MIX II to mud system if seapage losses become a problem. 6 Maintain low gravity solid at < 8% with dilution and solids control. Depth Mud Wt. Funnel Pv Yield Point Gels pH API FL HTHP FL Chloride SLDS Visc 10 seG10 min 250T "wo.. ppg s /pt cp Ibf1100 ft2 Ibf1100 ft2 cc cc mg/1 %NOL 3,020 - 11210'± 8.8 - 9.9 40 - 50 ic— 12-18 10 - 14 9-9.5 7.00 N/A 28k-32k <6 r 1 Drill out 10.76" casing shoe with previous mud and displace to new KlaShield while drilling shoe before FIT The WBM should be maintained with KCI, Flowzan and PolyPac with sweeps as needed for additional hole cleaning. Maintain 2 concentrations of KlaStop for inhibition. 3 Prior to drilling cement, pretreat the mud system with .25 ppb Sodium Bicarbonate to minimize effects of cement contamination. 4 Begin adding Asphasol and Resinex as coal are drilled, coal stringers will be drilled thru this section. 5 Add MIX II and sized SafeCarb (20, 40, 250) to the mud for seepage (<15 bph). 6 Run solids control equipment continuously to maintain low gravity solids below 6%. 7 Lower yield point/gel strengths prior to logging, running casing, and cementing. Note: Production casing plug will be bumped with water. Prepared by Stephen F- Henniganq 9/S/2012 Page 20 4.17 Solids Control Equipment Interval Shaker Desander Desilter Mud Cleaner Centrifuge Cuttings Dryer Cuttings Injection Zero Discharge Comments Closed Loop System, Full Containment, 0-Total Depth x x x run shakers with finest screens possible Item Equipment Specifications (typical but may not be exact depending on rig) (quality, design type, brand, model, flow capacity, etc.) Shaker 2-Brandt King Cobra Degasser Demco style Vacuum Desander N/A Desilter N/A Mud Cleaner N/A Centrifuge Rig Cuttings Dryer N/A Cuttings Injection N/A Zero Discharge N/A Best Practices: Have vacuum trucks pull fluids from trough above the cuttings tank to more efficiently pull fluids for disposal. This minimizes water added to the solids to suspend for pick up by the trucks, thus minimizing total volume to be disposed of. Cuttings will be pulled from J Prepared by Stephen F. Henniganq 9/5/2012 Page 21 4.18 Cement Program Summary (Brief vendor prog is attached) Cementing Summary #VALUE Surface Size: 10.75 Setting Depth: 3020 ft. Annular Volume (No Washout): 1122.51 cu. ft. Lead Slurry Density: 12 ppg Yield: 2.62 cu.ft./sx No. Sxs: 720 Specifications: Type I Desired Top of Cement: 0 ft. Tall Slurry Density: 14.8 ppg Yield: 1.34 cu.ft./sx No. Sxs:-F 250 Specifications: i 8 Hour Compressive Strength of Tail Slurry: 1000+ psi Total Volume: 2221.4 1 cu. ft. Desired Top of Cement: 2660 ft. 970 Intm. Prod. Casing Size: 7 Setting Depth: 11210 ft. Annular Volume (No Washout): 1236.15 cu. ft. Lead Slurry Density: 12.7 ppg Yield: 2.18 cu.ft./sx No. Sxs: r 600 Specifications: G Desired Top of Cement: 3000 ft. Tail Slurry Density: 13.8 ppg Yield: 1.85 cu.ft./sx No. Sxs: F 230 Specifications: G Desired Top of Cement: 9200 ft. Total Volume: 1733.5 cu. ft. 8 Hour Compressive Strength of Tail Slurry: 1000+ psi 830 0 bee cement prognosis Tor details afia spacer spec determined by eiog caliper and other parameters. #VALUE Prepared by Stephen F. Henniganq 9/5/2012 Page 22 4.19 Bit Summary NO. Size Model Type Surface Hole 1 131/2" GTX-C1 or similar tooth Intm/Prod 2 8 3/4" HCD504ZX or similar PDC Prepared by Stephen F. Henniganq 9/5/2012 Page 23 4.20 Casing Test, FIT, Lot procedure Perform Casing Test (CIT) - the pressure to which the casing should be tested should be 300-400 psi above the expected surface pressure needed for the leak off test. It is NOT necessary to retest to the APD casing test pressure. 1. GIH and clean out to the top of the float collar for casing test. 2. Circulate and condition mud until shaker is free of cuttings and mud weight in is within +/- 0.1 ppg of weight out for several consecutive measurements. 3. Rig up, pressure test and check for leaks. Make sure air is purged from the system. 4. Pumping down the drillpipe, break circulation with cementing unit (or low vol/high press pump). 5. Close annular BOP or pipe rams. 6. Pump down drillpipe at 1/2 bpm. Do not exceed this rate and maintain constant rate as well as possible. Record pressure at each 1/2 bbl increment pumped. NOTE: Larger than 11 314" use .75-1 bpm. 11 314-9 518 use .75-.5 bpm - plot should be tgreater than 45' 7. Continue until the test pressure (as described above) is reached. Do not exceed test pressure. Stop pump and shut in valve. 8. Monitor and record shut in pressure; hold for at least 5 minutes, or as specified. Troubleshoot problems if desired test pressure cannot be obtained. 9. Release pressure and record volume of fluid recovered during flow back. 10. Input recorded pressures and corresponding volumes on the Casing Test section of the "CSG-FIT" worksheet (in the yellow shaded area). This is the minimum volume line for the subsequent leak off test. Enter flow back when pressure is released. Prepared by Stephen F. Henniganq 9/5/2012 Page 24 Perform Formation Test (LOT, FIT, etc) - enter all the header information for the well, rig, casing size, shoe depth, mud weight, date and your name at the top of the form on the "CSG-F/T" worksheet. 1. Drill shoe track and +20' of new formation. POOH into the casing shoe. Circulate and condition mud until shaker is free of cuttings and mud weight in is within +/- 0.1 ppg of weight out for several consecutive measurements. 2. Rig up lines, pressure test and check for leaks. Make sure air is purged from the system. 3. Pumping down the drillpipe, break circulation with cementing unit (or low vol/high press pump). 4. Close annular BOP or pipe rams. 5. SLOWLY pump down drillpipe and maintain constant rate as well as possible. Required rate may vary, but first attempt should be at 1/2 bpm (OR same rate as casing test). Record pressure at each 1/2 bbl increment pumped and plot on the FORM INTEG.TEST (FIT) section of the "CSG-FIT" worksheet (in the blue shaded area). This will require teamwork among at least two, but better with three individuals. If the FORM INTEG. TEST (FIT) plot curves BELOW the Maximum Volume Line, stop and bleed off pressure then re -run the test at a higher pump rate (suggest 1/4 bpm higher). Note - also have someone record casing pressure from the choke manifold at the same -- bbl increments. If these pressures differ from the drillpipe recorded pressures by more than 10%, notify the office. 6. Continue until leak off (fracture initiation) is detected as indicated by a change in the rate of pressure increase. This is determined by the leak off test chart and observation of the pressure behavior. Once leak off indications are noted continue to pump at constant rate to confirm. If the pressure resumes a constant rate of increase, continue pumping and watch for subsequent leak off indications. If the rate of pressure increase continues to decline, continue pumping for 3 more _ bbl increments to insure fracture has occurred (a noticable pressure drop should be evident). If a sudden pressure drop occurs, stop pumping immediately. 7. Record instantaneous shut in pressure (]SIP). Monitor and record shut in pressure every minute for at least 10 minutes. See #11 below 8. Release pressure and record volume of fluid recovered during flow back. 9. If the measured leak off pressure is less than the predicted leak off, then a cement channel may exist. Whenever a cement channel is suspected, the LOT should be repeated for confirmation. If a channel exists there should be little or no improvement seen. LOT or FIT or PIT (in EMW) = pressure (psi) 10521 casing shoe depth (' TVD) + current mud weight (Ppo) 10. If the Leak Off plot falls between the Minimum and Maximum Volume Lines, this is a good leak off plot. Pick the point on the curve where the line begins to break over (the rate of pressure increase has changed from a straight line) . This is the leak off value. On a "jug" test, there is no bend. PPG equivalents are calculated on the right. 11. Input recorded pressures and corresponding volumes on the FORM INTEG.TEST (FIT) section of the "CSG-FIT" worksheet. Values should initially fall between the Maximum volume line and the Csg Test line. 12. Input recorded shut in pressures and corresponding times on the Shut In Pressure (ISIP) section of the "CSG-FIT" worksheet (in the yellow shaded area). This is indicated by ISIP and incremental time @ the bottom of FORM INTEG. TEST (FIT) section. Prepared by Stephen F. Henniganq 9/5/2012 Page 2S ARIVISRONG COOK INLET LLC. North Fork Unit #33-35 Cementing 10-3/4" Surface Casing: 1. Prior to cementing casing: • Check cement lab test for sufficient pumping time, free water and fluid loss. • Discuss job with cementer, check calculations and additives. • Verify cementing lines (chicksans, flexhose, etx.) are made up ready to go. • Confirm Stab -In collar placement is correct and drillpip nipple matches Stab -In collar. • Drift casing prior to running. • Assure extra hoses are available for water and mud. Cement the casing as follows: Immediately prior to shutting the pumps down record and report the pump pressure ON A RATE/TIME/PRESSURE basis ± 5-10 minutes. Hold pressure for 1 minute. Bleed pressure down to 0 psi. and pull out of tool. Load wiper plug into drill pipe and pump with rig with total displacement plus 5 bbls. to clean drill pipe. Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 24 BBL Mud Clean II Lead: 733 sx Type I Cement + Additives 12.0 ppg Excess 100% Over calculated volume Tail: 200 sx ✓ Type I Cement + Additives 14.8 ppg Excess 100% Over calculated volume Displacement Spacer: 5 BBL Use fresh water Displacement Mud: 48 BBL 8.4 ppg WBM — 54 BBL Total Displacement Estimated Top Cement Lead Surface Estimated Top Cement Tail 2,660' PROPERTIES LEAD TAIL Weight 12.0 14.8 Yield 2.62 1.34 Water 15.13 6.34 Pump time 5:35 2:31 Water Loss N/A N/A Free Water N/A N/A Compressive Strength 8 hours 106 500 12 hours 224 743 24 hours 423 1198 48 hours 661 Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. 2. After Cementing, record the following: • Time cement in place • Pressure used to displace. • RATE/TIME/PRESSURE after slowing down in anticipation of bumping plug. • Amount of barrels pumped behind cement. • Amount of barrels bled back to check floats. • When and if returns were lost while cementing. • Amount of cement (in barrels) circulated to surface. Cementing 7" Production Casing: 1. Prior to cementing casing: • Check cement lab test for sufficient pumping time, free water and fluid loss. • Discuss job with cementer, check calculations and additives. • Verify cementing lines (chicksans, flexhose, etc.) are made up ready to go. • Verify that wiper plugs are loaded in cementing plug assembly. • Drift casing prior to running. • Assure extra hoses are available for water and mud. Cement the casing as follows: Bump the plug with 500 psi over circulating pressure. Immediately prior to shutting the pumps down record and report the pump pressure ON A RATE/TIME/PRESSURE basis + 5-10 minutes. Hold pressure for 5 minutes. Release the pressure and confirm the floats are holding. Do not over displace by more than half of the shoe volume. Spacer: 5 BBL Use Fresh Water to pressure test cementing iron Spacer: 40 BBL 10.0 ppg Seal Bond Spacer Drop Bottom Plug Lead: 626 sx "G" Cement + Additives ppg - (12.7 ppg) Excess 50% Over calculated volume or 20% over caliper volume Tail: 300 sx "G" Cement + Additives - (13.5 ppg) Excess 50% Over calculated volume or 20% over caliper volume Drop Top Plug Displacement Spacer: 5 BBL Use fresh water to drop Top Rubber Plug Displacement Mud: 394 BBL 9.0 ppg WBM — 399 BBL Total Displacement Estimated Top Cement Lead 2,800' Estimated Top Cement Tail 8,748" PROPERTIES LEAD TAIL Weight 12.7 13.5 Yield 2.18 1.85 Water 11.74 9.24 Pump time 5:42 4:19 Water Loss 32 cc 10 cc Free Water 0 0 Compressive Strength 8 hours 242 502 12 hours 661 1427 24 hours 1583 2825 48 hours 1830 3203 Note: The final slurry design will be provided after testing cement, additive and mix water samples prior to performing the job. 2. 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Cook Inlet, Alaska (Kenai Peninsula) Slot: North Fork #33-35 Field North Fork Well: NFU #33-35 A R M S T R 0 N G Facility North Fork Unit NAD27 Wellbore: NFU #33-35 W., (Gas, lw rrt2 BAKER HUGHES Plot reference wellpath is NFU #33-35 Version #4 True vertical depths are referenced to Nabors 99 (RTE) Grid System: NAD27 / TM Alaska SP, Zone 4 (5004). US feet Measured depths are referenced to Nabors 99 (RTE) North Reference: True north Nabors 99 (RTE) to Mean Sea Level: 678.35 feet Scale: True distance Mean S Level to Mud line (At Slot: North Fork #33-35): 0 feet Depths are in feet Coordinates are in feet referenced to Slot Created by: jonethoh on 25-Jul-12 Traveling Cylinder: Map North ou .+or+tic mro IUloaclirorl npnfhc nn Rpfprpnce Wellnath I dl aFJ a+J 6 930' j�90' lea I2aI / 300' f 60' NFl ��, l Bolt 4oft / I 0iii 2102 l r 40i1 i "+ry fimr 240' 210' 160' 120' 120ft 160/1 150' Scale 1 inch = 60 ft A ARMSTRONG c o"G /n/, I, M DRILLING OPERATIONS SUMMARY North Fork 33-35 Start Depth Seat Depth Casing Interval Hole Size MD TVD MD TVD Size Wt (IWft) Grade Conn Burst Collapse Tension* Drivel Structural Driven 0 0 120 120 16 0.5 X56 Welded N/A N/A N/A NO Conductor Surface 13.5 0 0 3020 2736 10.75 45.5 N/L 80 BTC 4230 2470 845 Intm/Prod 8.75 0 0 11210 9778 7 26 N/L 80 BTC-M 7240 5410 604 * = minimum of body and connection strengths Note: AOGCC MUST be notified 24 hrs prior to each diverter function and BOPe test. Conductor: 1. Drill/Drive 16" conductor to +/- 120ft. RKB. RD conductor rig. 2. MIRU drilling rig. 3. Install starting head 16" SLC x 21 7/4", 2M flange. 4. Nipple up 21 '/4", 2M diverter, 16" diverter valve and 16" diverter line. 5. Function test diverter and diverter valve. (AOGCC 24 hr notice) .--"' 6. Build spud mud. 7. Install mud logging. 8. Inspect bha equipment. Surface: 1. PU 5" drill pipe, bit and DIRECTIONAL BHA per bit/directional proposal. Set up WEEKLY STATUS Report for the Commission. 2. Drill w/ low rpm, gpm until stabilizers have exited drive pipe. Run max gpm, rotary, etc as allowed. 3. Continue to directionally drill a 13 '/" hole to ±3020' MD/ 2736' TVD short tripping and pumping sweeps as considered necessary. At hole section TD, pump a HIGH VIS sweep and circulate the hole clean. 4. Short trip. Circulate hole clean. Repeat. 5. Condition mud to lower YP and gels. Monitor pill lag and mud log lag times to aid in adjusting cement volumes for hole washout. 6. Prep for excess mud, cement, rinse water, etc disposal. 7. Calculate landing equipment to have proper space out with top of landing jt ±4-6' above rotary. Run 10 1/" surface casing as follows Baker -Locking the shoe track: a) Shoe b) Sting -in collar c) Casing With centralizers placed as follows: d) 2 bow -springs with stop collars in center of bottom 2 jts e) Centralizers across the bottom 2 couplings f) 1 centralizer across the coupling of every third jt g) NO CENTRALIZER INSIDE CONDUCTOR AS CASING NEEDS TO BE CENTERED IN ROTARY h) ESTIMATED TOTAL centralizers = ±35 w/ 2 stop collars 8. Perform a running tag. Reciprocate casing. Circulate and condition mud at a rate not to exceed the AV around the collars while drilling. 9. RU cementing head and lines. Test to 500/5000psi. Cement 10 3/" casing PER cementing proposal with an inner string, cut off cementing when cement reaches surface, dump 2-5 bbls on top of sting -in collar. Circulate clean. Cement volumes are presently designed with 100% excess. Adjust as necessary to allow for cement returns to surface. 10. ND Diverter. Cut off 10 %" casing. Prep to install mud loggers per logging program. Instruct same re dry ditch samples for AOGCC. 11. Install 10 3/" slip lock connection X 11" 5M flanged multihowl wPJlhPad. Test to 50% of casing collapse or 1600 psi whichever is greater. 12. NU adapter spool. NU 13 5/8" 5M BOPs. Verify proper rams are installed for drill pipe �D in use. Test BOPs and choke manifold to 300/4000 psi, hydril to 300/2500 psi. (AOGCC 24 hr notice) 1� If AOGCC approves, casing may be tested here while testing BOPe. That is, pull test plug and perform casing test under the blinds. Test casing to 3000 psi. NOTE: If AOGCC does not approve of casing test under blinds then test before drilling out float equipment. NOTE: (BOPe MUST be tested every 7 days during the remainder of the well. AOGCC must be notified at least 24 hours before) NOTE: Maintain good communications with regulatory. Communicate with the inspector every couple of days just to let them know what is going on. 13. Set wear bushing. Run CBL. Production: 1. PU 8 3/4" PDC bit and directional BHA w/ LWD. Drill out float equipment and at least 20' of new formation. Circulate hole clean. 2. Contact AOGCC. Test shoe to LEAK OFF on a chart. Email results. Estimated Leak Off EMW is 14.0 ppg emw. If test is less, discuss with office. A minimum of 13.5 is acceptable. 3. Drill ahead per directional plan. D N gas 4. Continue to directionally drill to ±11210'MD / 9778TVD as per program, short tripping and pumping HIGH VIS sweeps as required. MINIMUM flow rate should be 500gpm. Higher if possible. 5. At hole section TD, pump a HIGH VIS sweep and circulate the hole clean. Make wiper trip. Again pump a sweep and circulate hole clean. Make sure pump is at MAX rate. Hole will require more than just circulating bottoms up. POOH. 6. TIH. Condition hole as before. Condition mud to lower YP and gels. Monitor pill lag and mud log lag times to aid in adjusting cement volumes for hole washout and compare to log value (LWD). 7. TOOH. Pull wear bushing. Install test plug. Close blind rams. 8. Change out pipe ram with 7" casing rams in upper ram. Run test joint and test casing ram to 250/ si. J►4- `f•«•�'— l#poa 9. Calculate space out and prep as per previous. Run casing as follows Baker -Locking the shoe track: a) Shoe b) 2 jts casing c) Collar d) casing With centralizers placed as follows: e) 3 bow -springs with stop collars in the centers of bottom 3 jts f) Centralizers across the bottom 3 couplings g) 1 centralizer across the coupling of every third jt for the next ±3600' casing (±30) but will be adjusted across potentially productive zones h) 1 centralizer across the coupling of every third jt to ±5000' (±15) i) ESTIMATED TOTAL centralizers = 41 w/ 3 stop collars 10. Run and cement 7" casing per cementing procedure while rotating and/or reciprocating. Land hanger. Cement volumes are presently designed for bringing cement to the previous casing shoe with 40% excess. Adjust as necessary to insure top of cement at shoe. 11. Back out landing joint. Install packoff and test to 5000 psi. Change out casing rams with pipe rams. Run test plug and test BOPs to 300/4000 psi, hydril to 300/2500 psi. (AOGCC 24 hr notice) ' If AOGCC approves, casing may be tested here while testing BOPe. 12. Set wear bushing. 13. Clean out and test casing to 4000 psi adjusted for mud wt in use at test. POOH. 14. Run CBL. Well Test/ Completion: 1. Detailed Procedure will be provided with a completion/well test sundry. 2. Rig down and move out drilling rig. 0 GE Oil & Gas This drawing is the property of GE Oil & Gas Pressure Control LP and is considered confidential. Unless otherwise approved in writing, neither it nor its contents may be used, copied, transmitted or reproduced except for the sole purpose of GE Oil & Gas Pressure Control LP. BUCCANEER ALASKA ARMSTRONG COOK INLET 10-3/4" x 7-5/8" x 2-7/8" 5M SH2/LRC2 Wellhead AssemblyDRAWN VJK 24MAY12 APPRV KN 24MAY12 With T-M40-CCL Tubing Hanger and M40-CCLAdapter Flange FOR REFERENCE ONLY DRAWING NO. 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Trucks �o 0 b tp PRA C 'TAWS rf-M PC AARv v'TAS It .2610 w-%VVv41' Example Drilling Waste Treatment Facility — EIIXIZAIOIAIZI;� TANG 1 c u�n vn R� �ueu i:ur:t F P•r I sr�mT�' LFNM�+i � • �e r,_• '•alav «f XT �F •P# 11' I f -Y E4 I - D- T-1 .awv.. Y n� _ • tT'I#! • IF 6 ' i allRFACE alTE PLAN Davies, Stephen F (DOA) From: Colby VanDenburg [colby@armstrongoilandgas.com] Sent: Tuesday, July 17, 2012 2:11 PM To: Davies, Stephen F (DOA); Schwartz, Guy L (DOA) Cc: Edward Teng Subject: RE: Armstrong North Fork Unit 23-25 Steve, Sorry for the confusion again. The NFU 22-35 should be classified as a development gas well, not an exploratory well. The 'development gas well' designation should be used for all of our 2012 permit applications at North Fork. Colby VanDenburg Geologist Armstrong Oil and Gas 1421 Blake Street Denver, CO 80202 (303) 623-1821 From: Davies, Stephen F (DOA)[mailto:steve.davies@alaska.gov] Sent: Tuesday, July 17, 2012 2:31 PM To: Colby VanDenburg; Schwartz, Guy L (DOA) Cc: Edward Teng Subject: RE: Armstrong North Fork Unit 23-25 Colby, I'm reviewing Armstrong's Permit to Drill Application for the proposed NFU 22-35 well. Could you please justify why this well should be classified as an exploratory gas well rather than a development gas well? Thanks, Steve Davies AOGCC 907-793-1224 From: Colby VanDenburg[mailto:colby(a)armstrongoilandgas.com] Sent: Tuesday, July 10, 2012 2:14 PM To: Schwartz, Guy L (DOA); Davies, Stephen F (DOA) Cc: Edward Teng Subject: Armstrong North Fork Unit 23-25 Steve, We have discussed the well classification for this year's drilling program at North Fork, and we're comfortable with the designation of 'Development Well' for the NFU 23-25. Please let me know if we need to make changes to the APD or if you can handle it internally. We will make sure to stay consistent with any subsequent APD filings. Sorry for the confusion. Colby VanDenburg Geologist Armstrong Oil and Gas 1421 Blake Street Denver, CO 80202 (303) 623-1821 TRANSMITTAL LETTER CHECKLIST WELL NAME 61 PTD# 2- t 2- rs S Development Service Exploratory Stratigraphic Test Non -Conventional Well FIELD• /VL''7POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WET (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTILATERAL 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 approve ect to full compliance with 20 AAC EXCEPTION 25.055. Approval t roduce inject is contingent upon issuance of �a conservation o approving a spacing exception. /- GLC-assumes ''�( 5¢i - ,,7i(7e the liability of any protest t the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted 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 tar et 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: 9/09/2011 J� 0 7 ( 6�0 4- fi ! L 1iL j L ,GZ-C'� 7 l>�C- Z ` �Cc�✓L112 C1�_ r � 1�j /JZZ�C (.G %!J-� _ a_ C? Ce'�_�� 4' ��l— "T�C.f� WELL PERMIT CHECKLIST Field & Pool NORTH FORK, UNDEFINED GAS - 568500 PTD#:2121350 Company ARMSTRONG COOK INLET, LLC Initial Class/Type Well Name: NORTH FORK UNIT 33-35 Program DEV Well bore seg DEV / PEND GeoArea 820 Unit 51450 On/Off Shore On Annular Disposal Administration 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA 1 Permit fee attached NA 2 Lease number appropriate Yes Surface location in ADL 391211, top prod interval & TD in ADL 391210 3 Unique well name and number Yes 4 Well located in a defined pool No North Fork Undefined Gas Pool 5 Well located proper distance from drilling unit boundary Yes 6 Well located proper distance from other wells No SPACING EXCEPTION REQUIRED: Closer than 3000' to well capable of producing from same pool. 7 Sufficient acreage available in drilling unit No SPACING EXCEPTION REQUIRED: Fourth well in Section 35 8 If deviated, is wellbore plat included Yes Public Hearing tentatively scheduled for Sept 26, 2012 9 Operator only affected party NA 10 Operator has appropriate bond in force Yes Appr Date 11 Permit can be issued without conservation order No SFD 9/11/2012 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15-day wait Yes 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 18 Conductor string provided Yes 16" conductor driven to 120' md. Engineering 19 Surface casing protects all known USDWs Yes Surface casing to 2700 ft TVD. 20 CMT vol adequate to circulate on conductor & surf csg Yes Surface casing will be fully cemented... using an inner string to cement. 21 CMT vol adequate to tie-in long string to surf csg Yes Production casing will be cemented back to surface casing shoe at 3000' md. 22 CMT will cover all known productive horizons Yes 7" casing will be cemented to 3000' md. 23 Casing designs adequate for C, T, B & permafrost Yes BTC calculations meet industry standards. 24 Adequate tankage or reserve pit Yes Rig has steel pits... Wastes to holding pond and then transported to approved disposal well.s 25 If a re -drill, has a 10-403 for abandonment been approved NA Grassroots gas development well. 26 Adequate wellbore separation proposed Yes Proximity analysis performed . No issues. 27 If diverter required, does it meet regulations Yes 16" diverter line.. Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation press= 4576 psi ( 9 ppg EMW ) Will drill with 9.3- 9.9 ppg mud .. GLS 9/17/2012 29 BOPEs, do they meet regulation Yes 5M BOP stack... annular, 2 pipe rams , 1 blind.. 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP = 3598 psi Will test BOP to 4000 psi ( annular to 2500 psi) 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable No H2S not expected... Rig has sensors and alarms. 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures Yes None anticipated based on offset wells. Geology 36 Data presented on potential overpressure zones Yes Expected reservoir pressure is 9.0 ppg EMW; will be drilled using 9.3-9.9 ppg mud. Appr Date 37 Seismic analysis of shallow gas zones NA SFD 9/11/2012 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Geologic Date Engineering P Date Grassroots Gas development well .... Date: Commissioner: Commissioner:]_ _ Co ner