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210-127
By Samantha Carlisle at 1:16 pm, Sep 30, 2020 AMAROQ RESOURCES, LLC 9/30/2020PRODUCTION WELL MECHANICAL INTEGRITY TESTSWELL NAME PTD WELL COMPLETION MIT‐T MIT‐T MIT‐T MIT‐IA MIT‐IA MIT‐IA TIFL TIFL# TYPE DATE DATE PRESSURE PASS? DATE PRESSURE PASS? DATE PASS?(psi) (psi)Nicolai Creek Unit #2 166‐038 Gas Prod 10/11/13 10/9/2013 2000 Y 10/9/2013 2000 Y NA NANicolai Creek Unit #3 167‐007 Gas Prod 07/25/04 7/24/2004 1550 Y NA NANicolai Creek #9 202‐208 Gas Prod 09/27/06 9/23/2006 2000 Y NA NANicolai Creek Unit #10 210‐127 Gas Prod 05/25/13 5/21/2013 1500 Y 5/21/2013 1500 Y NA NANicolai Creek Unit #11 209‐067 Gas Prod 09/23/09 9/22/2009 3000 Y 9/22/2009 2000 Y NA NA oF �w1"\\\I%' THE STAG Alaska Oil and Gas � — o ��; �� f Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 ® ALAS*P Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Operations Consultant % JUN 1.8 2fl Amoraq Resources, LLC P.O Box 90225 Anchorage, AK 99509-0225 Re: Nicolai Creek Field,North Undefined Tyonek Gas Pool,Nicolai Creek 10 Permit to Drill Number: 210-127 Sundry Number: 318-227 Dear Mr. Pollock: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this l2- day of June, 2018. RBDMSd JUN 13.2018 III II STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS oN.TitAl 3 162:11k1:6 ((e 20 AAC 25.280 P 6 (_ C k_ A(,,_4 7 ' 1.Type of Request: Abandon 0 Plug Perforations El Fracture Stimulate 0 Repair Well D Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate D Pull Tubing Cli Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing 0 CT Cleanout w/N2 D • 2.Operator Name: 4.Current Well Class: .5 Permit to Drill Number: Amaroq Resources,LIG Exploratory 0 Development D. 210-127 • 3.Address: PO Box 90225 Stratigraphic Ci Service D ,6.API Number: Anchorage,AK 99509-0225 50-283-20145-00-00 • 7.If perforating: 8.Well Name arid Number. What Regulation or Conservation Order governs well spacing in this pool? NA Nicolth Creek#10 Will planned perforations require a spacing exception? Yes 0 No 0 9.Property Designation(Lease Number): 10.Field/Pool(s): /1( e-Thewele.... ADL 63279 * Nicolai Creek Field-Undefinedtas ,44,, z.,--:51'I , 11. PRESENT WELL com1 mom SUMMARY A A Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD: 'Effective Depth TVD: MPSP(psi):455AO rst' Plugs(MD): Junk(MD): 6 „3460*W5b>60c--ot , .9. 3396' 3396 None None Casing Length Size MD 1VD Burst Collapse Structural Conductor 94' 13 3/8"68*K55 94' 94' 3450 psi 1950 psi Surface 654' 9518"40*J55 654' 654' 5750 psi 2370 psi Intermediate Production 4805' 7"23*N80 4805' 4409' 6340 psi 3830 psi , Liner Perforation Depth MD(ft): 'Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(It): 2149'-3866' 1944'-3570' 2 7/8" 6.5ft J55 3838' Packers and SSSV Type: Packers and SSSV__,MD(ft)and TVD(14 Mechanical i 376T(3472'), ---- , Hydraulic and mechanical Hydraulic @ 989'(1822'),2505'(2340').3177'(2931')&3384'(3138) 12.Attachments: Proposal Summary Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch D Exploratory 0 Stratigraphic Li Development El ' Service CI 14.Estimated Date for 15-Jun-18 15.Well Status after proposed work: Commencing Operations: OIL D WINJ El WDSPL Li Suspended D 16.Verbal Approval: Date: GAS • WAG 0 GSTOR 0 SPLUG ri Commission Representative: GINJ D Op Shutdown D Abandoned 0 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. George Pollock George Pollock Authorized Name: Contact Name: Authorized Title: Operations C sul Contact Email: opollockaauroracower.com Contact Phone: 907.351.8286 Authorized Signature: - Date: 31-May-18 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number 5q z2+ Plug Integrity 0 BOP Test 1 ' Mechanical Integrity Test D Location Clearance Li _ e Other: . Post initial Injection MIT Req'd? Yes 0 No El 1 Spacing Exception Required? Yes 0 No {Z( Subsequent Form Required: APPROVED BY Approved by:kcc:X,EC1------- COMMISSIONER THE COMMISSION Date: ::, i Like) RBDMS. JUN 1 3 2018 /Yid-, (97-1r/ovreeeiii /0 1V/',1 .,..&=. .4- • -Submft Form and OP( NIAForm t0-403 Revised 4/2017 Approved appll . :- il(9inNhAoLthe date of approval. Attachments in Duplicate floj • • ANIAROQ RESOURCES,LC NICOLAI CREEK 10 CTU CLEANOUT Bela eduled June 2018 (5/22/18) psP CURRENT=DONDFTONS: STATUS OF WELL: Live well flowing 125 MCFD at 120 psi(200 STP)with fill tagged at+/- 22 ' 'CASING:7"23#K-55 (to 2560')& 26#L-80 set at 4805'1\4D/440W TVD: TUBING: 4' 3-1/2"pup at Surface with 3-1/2"tree ; crosses over to 2-7/8", 6.5# J-55 8 rd EUE with Sliding Sleeves at: WXO at 1992' (packer fluid-closed); WXO at 2191' (Open); WXO at 2739' (Open); WXO at 3279' (Closed); WXO at 3486' (Open) PX Plug set at 3400', and On-Off Tool w/2.313"X landing nipple at 3767' (with PX plug in place). :Packer-s at-2027',-2503',-31"77', 3384' all hydraulic and Arrowset mechanical at 3767' 2-7/8"expansion joint at 2513' EOT—3838' CAPACITIES: 2-7/8" 6.5# Tubing: 0.00579 bbl/ft; Tubing-Casing Annulus: 0.0233/0.0222 BPF; 7"23#-& 26#_Casing: 0.0393/.0382:bbl/ft. Tubing volume-to On-Off T +o1=21.8 bbl. PERFS:'Carya 2-1 at 2149-2156' behindsleeve at 2191' Carya 2-3 at 2688-98'&2825-30' behind Sleeve at 2739' (400 psi SIP?) ,Carya 2-4.1 at 3326-3331' behind Sleeve at 3279' (as high as 1200 psi) Carya 2-4.2 at 3512-3532' behind Sleeve at 3486' 1375 4 Carya 2-5.2 at 3856-3866' below PX plug in On-Off Tool at 3767' (480 psi) NOTES: 1)-Well is=moderately-deviated 26 deg average. 2) Well has been making sand. SUMMARY OF PLAN: RU Pollard and close sleeves at 2191'. Cleanout with Coiled Tubing to PX plug at 3400',pull PX plug, confirm sleeve at 3486' is open, and cleanout with Coiled Tubing to PX plug at 3767'. Work thru sleeve at 3486' until no sand in returns. RD CTU. Set plug at 3279', open sleeves at 2739' and 2191', and put on production until sand control chemical can:be-panid. Then close all sleeves,abbve_plug,_1 31_ping,pu mp sand treatment into sleeve at 3486',and test. • PROCEDURE: 1) Pick and move wellhouse.. 2) RU Pollard. RU lubricator—test to,well pressure_ RIH w/2.25 bailer and tag fill (last found at 2236'). RIFT w/shifting tool and close sleeves at 219T'. RD Pollard--but have them standby(on west side—do other work). 3) MI and RU coiled Tubing Unit w/ 1-1/2" coil, crane, RFR diffuser tanks pit for flowback, and spot N2 unit. MU AG -choke skid and flaw back -iron to SSV on wellhead or flowback tee on BOP skid and flowback tank.. For CT cleanout, use clean (no oily) PW from NC11, Aspen, or M 4 in Tiger Tank on location (approx. 75-150 bbls). 4) Make up coil connector and pull test to 10,000 lbf. Pressure test connector to 200 PSI & 4,500 PSI for 10 and 10 minutes respectively. -5-) Make up BHA: Dimpleon-connector,=dual'flapper=check,-Hyd=disconnect, straight bar, and 1.T5" Wash Nozzle and measure/record actual OD's, ID's,& lengths. • Note: Ensure company rep verifies and is in agreement with BHA to be run. Compare maximum 01) of tools with minimum IDS of the well completion (2.313") 6) Nipple up BOP stack to wellhead –3-1/8" 5000# RTJ Flange (XO available from GE). Notify state 24-48 hrs prior to testing GOP's. 7) Pressure test BOP stack, lubricator,.and flow back manifold against crown valve to 200 PSI&4,500 PSI for 10 and 10 minutes respectively. 8) If running a check valve, bleed pressure through flow back manifold to 1,000 psi and inflow-double-flapper check valve by:bleeding off moiled tubing pressure via the-reel manifold. • Note: take care that excessive stripper pressure is not applied that can cause pipe collapse scenarios. 9) On completion of all tests re-pressure up via coiled tubing to equalize to crown valve and open up tree valves. 10) Fill coiled tubing reel noting volumes on Barrel counter/displacement tanks. Compare with theoretical coiled tubing reel volume. 11)Run 1.50"coiled tubing andclean out sand (last tagged at 2236')to PX plug at 3400' KB with produced water. Monitor losses—sleeve at 2739' is open. a. Begin RIH @ 100 fpm and 10 fpm at restrictions b. While running in=hole,=circulate fluid-at=minimum=rate to prevent nozzle plugging. Generally 0.25bb1/min. c. Run in hole to a depth of 2000 ft and perform pull tests(or more often if the company representative/ supervisor feels it necessary.) Increase fluid to 0.75 • • :bbl/min.=Compare results with modeling predictions. Slow down to=10:tt/min until fill is tagged(expected at 2236'). d. Reduce the penetration rate to 5 fpm while washing formation sand/debris. e. The coiled tubing operator should perform pull tests as required and back jetting passes when washing through the fill to establish that the coiled tubing is free from obstructions. f. Monitor the returns at surface to establish the fill removal efficiency. g. When PX prong at+1-3400' KB is tagged, circulate until clean. POOH. 12)RD coiled tubing lubricator and RU Pollard lubricator. Test to 2000 psi. RIS§and pull PX prong and plug at 3400'. POOH. Confirm that sliding sleeve at 3486' is open. RD Pollard. 13)RU CT=lubricator=and=test=to 2000 psi. Rill w/ CT and cleanout to 3600'. =Circulate clean, pull up andcirculate down through open sleeve several times.Clean out to PX plug again if necessary. Monitor losses—no serious losses expected; however,if severe, nitrify)cleanout fluid. When returns are-clean,pull up to+/-3000' and a. Start time flow of N2 and unload the fluid from the weld, POOH while pumping N2. b. When at surface close in at the wellhead leave at least 400 psi (pressure could be close to SITP of 1200-1400 psi) on the tree when finished & bleed surface equipment down,rig off well head. • Note: Wellhead pressure during a cleanout should be kept above 150 psi to reduce erosion. • Note:If too much till is attempted to be removed too quickly it can cause loss of circulation ofthe lu'nit of-the-well hurt.This could all vthe Mita-fall hack in the ,annulus,sticking the coiled tubing in the well. If this occurs pull above the perforations or further until circulation is restored. Once Circulation is restored circulate a complete wellbore volume at the specified depth and once it is clear of sand proceed into the well. Also iflost circulation is encountered call the engineer immediately. If_bridges-of_till=are encountered,_be-aware=of-the=possibility=of-pressure_being=trapped below the bridge.Maintain sufficient back pressure to protect the coiled tubing from a possible kick.If bottom hole pressures are not known there is a possibility of no pressure below the plug and,once the coiled tubing breaks through,all the circulating fluid with fill falling back down the hole trapping the coviled.tubing.In thiscase,lifting small amounts of fill and circulating it out of the well may be advisable prior to proceeding too deeply into the fill. 14)RD Coiled Tubing Unit. 15)RU Pollard lubricator. Test to 2000 psi. Open sleeve at-3486'. RD Pollard • 1 6)Treat pertbrations from 3512' to 3532' with Sand Aid(or similar chemical sand control) can be pumped into sleeve at-3486'—Procedure for treatment follows. Ed Jones(10/7/15,updated by George Pollock May 2018), • • .--- -Aurora Gas, LLC fkiEtTIE ''' :,. i !:ii ( Tablogrientp p 11 ICIOLAI CREEK27 f5131#rilEE"Ei-551s1ti}t ♦ w . PT'DM 210-1127 .. , «., Cuadsr rt drivel"as 94'CC �, API*54-283-261 ".P ' Y ' , i, `E RKB 14.711 2(118) ®9--5JiW"��1&3 Surface Casiag 54 (As of April r Geta .ppg Type DrE 124/4*Hale to 678" " w ...vs . w 2-7/8" a 7"=Was displaced with 9-3:ppg 3%KO- CR , •-*?` , . packer fluid k' HES S1 Skeet#1992' *' "Aka,.„,* °t.' .. ,�. 2313 X Profile( _ set Packer at 2827' : e_1,,- Carla 2-`1 :.:.*,---1,74k. SlitthigSleeve at 2191'(open) 2149-2156" MIK (Ttet! ate"-81161 Perfs at 2080-82'&2350-52' Mkt S 5 Vel 4.11 pa skalt-as .,•-:,..". � BH Squeezed 75 and 50 sx tl ;. ' i :421,I1Ilyaraufic Set tacker#245' ' i: � 2513 i' 2648-2698'' ' �. ;� tC ' (.x5223-31"TVD) *"--- Srairmg Sleeve..,313(ti a 2'T ' O, P t ,{'S �} VS.)x Ici was*:0 212125.21131r , .. )4 6 4,,,4 11y ras$r Parker#3177' r OMNI24-1 .. gat rl1''a"''"1 Shaw Mcrae* o' 3321-3332' , 2312 X Profile(dosed) X ' {6111 ' .,; ),e - (east3313.43' Squeezed 3319-3331'50 sx �; „1. 12 psi shulria= :1�dr��r Parker#3384' X- ' ? Perforated 3467-3472'squeezed I lir* Perforated with 10661 of 15.8ppg cement r i y rr4' �S It .I SlidagSkeewr a - / ' Z lt, t3 -3 • I r ,' A" a 2-d2 "mss.. �. 13,5 __1-ira �A2�. ' .y (323149"')f Squeezed 3510-3530 75 sx' `- ��. 1 4ls4+l�piesfskirl2313aC-proTrte 1,0 i_e 1"A i`'. mel 1X Park r*3767 Clays ; Pl1TD#3954'11 (364'TVD) (3<g6t ' f31)) *, ,? " "?"'234 X-55&NO L-86 Casing to 4805'MD, Drill 8-1,,T Merle tae mar l "/ND 4438'TVD avg deviation 26deg,KO?900' • • in this:procedure-it-is assumed that the wellbore will-be_cleaned_free=of-ail debrisandthe complete interval is exposed.The treatment will be-pumped down tubing using filtered 2%-KCI base-brine-with 0..3% KleenRinse K252. The treatment must be pumped;at a matrix rate below frac pressure.. 1. Hold safety meeting-with all personnel on location and discuss in detail of all job procedures and responsibilities. 2. Perform QA/QC on the brine fluid to ensure it meets desired specifications. a. KCI should be filtered to a minimum 2 micron absolute (Beta 1000 min). The turbidity of filtered fluid should be<30 N-TU. b, 0,3% (3 gal/1000 gal) KleenRinse K252 is to be added into the KCl (M117) brine and mixed in a..battch'mixer or!frac tank w1'h heavy dircUlation until i `is homogenous. 3_ Rig up all high.pressu.re-pumping equipment and chemical injection system(LAS). a. The expected maximum rate of this treatment is 10bpm b. The maximum allowable pressure is 4,000psi 4. Pressure test treating lines as per ConocoPhillips and Schlumberger requirements to 5,000psi -5. -Pertorm.a step rate test(up to 9Q of frac pressure).-Hoick each rate until,pressure is stabilized(minimum 1 min each)and record pressure in Table 1. Table 1: Rate " Pressure ', Delta " Calculated Delta Friction, Net Diversion (bpm) (psi) Pressure Friction Pressure Pressure Pressure (psi) (psi) (psi) (psi) 1 2 3 4 5 6 8 10 • The Delta pressureisthe difference-between the pressure at rate 1 versus rate 2 and then rate 2 versus rate 3 and soon. • Note that the intent of the step rate test is to verify that sufficient diversion pressure can be established. Net diversion pressure is the difference between delta pressure and delta friction, pressure. • Under normal conditions, the delta pressures should be higher than the delta friction pressures. If not, Consult with the SMS Product Champion to determine if additional bull head is needed to further enhance injection and to finalize the treatment rate. 6_ Model the.injectivitystep rate test in TubeFlo.w PIC and analyze the pressures to determine if adequate diversion can be achieved. 7. Perform SanclAid treatment as detailed-n Tables 2.Sand/WI+K250 and'Sand4ld Dispersant K251 should be pumped only in recommended stages(Main treatment)as per given concentration. Table 3 shows the chemical requirements. Table 2: -Base -Base Cum. Step Nr, Step Fluid Vol. SandAid Slurry Vol. Vol (bbl) (gal) (bbl) (bbl) 1 lnitiat`Displaeement 2%KO° 38.7 38.7 38.7 2 Step Rate Test 2%KCI ` 50.0 50.0 4 88.7 • • , Model the injectivit-r-step rate-test inTikretow fC-to wrifirm-treatrrre rtdesign rate. 3 Preflush 2%KCI 29.8' 29:8 118.5 ' ( Main treatment—791 K25;0, 2%KCa 55,4 2751.2 59„.6, 1781 5Preflush , 2%KCI 29.8 29.8 207.8 6 Main treatment—7%K250 2%KCI 55.4 175.2 59.6 267.4 7 Preflush 2%KCI 29.8 29.8 297.2 8 Main treatment--7%K250 2%KCt 55A 175:2 59.6 356.8 ,Overflush 2%'KO 134.1 1.34.1 490.9 6 Oispimement 2%1(-01 38.7 38.7 t 529.6 Note:Ali yids Except-Fine 1 DisplaaementmustcontMnKtemAinse K252 at 3 rglpt. -The main treatment stages contain SandAid Dispersant at 3 gpt. Code Description Concentration Required K250 SandAid Additive 70 gpt 525.5 gal K251 • Sand'AidDispersant 3 gpt 223 gal K252 Kleen-Rinse Surfactant 3 gpt 50.7 gab 8. Displace treatment down the work-string at recommended rate below estimated fracture rate and fracture pressure. 9. Stop pumps, let pressure bleed off into the formation and monitor tubing pressure. 10. Monitor well for 15 minutes. 11.-secure well. 12.-Rig down pumping equipment. 13. Leave well shut in for minimum 6 hours.Make sure'that`the r-eservoir,fluids near the.we l bore remain;un-idisturbed. • • • ,DAIAD WEIL MOC+L;11. - NI'fROOEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Qperator of upcoming Nitrogen operations. 3.) Perform-Pre-Job Safety Meting. Review Nitrogen vendor standard operating procedures and appmpriate Safety Data Sheets(formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. knclude review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. t -SpotiPtuiqping;Unitand Transport.,_ContirmliquidN2-volumew:initransport. 6.) Rig up lines from the Nitrogen Ptunping unit to,the well and returns tank. Secure lines with whip checks. 7.) Place-signs and placards waning of high pressure and firitoager operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.)Wellsite Manager shall walk deem valve alit4 -a"lltS and ensure valve position is oorrect. 11.)Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated ,cletector -welithataneasures:02 devels. 12.)Pressure test lines upstream of well to approved sundry pressure or MPS? iMaxisatun Potentiel Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank)to 1,500 psi. Perform visual inspection for any leaks. 13.)Bleed off test pressure and prepare for pumping nitrogen. 14.)Punip nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). Alt nitrogen returns are-to be routed to thezeturnstank. 15.)When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well-and Nitrogen Pumping Unit. 16.)Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.0irralize job ;log and T,discuss :epekations -with AVellsite Manager. _Ii)oeument:auy ilessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.)RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport* r 41/ , • Client: Amaraq R ur Sci1I coiled Tubing Services Date: kn�y318`,20i Drawn. Chad Barrett Pressure Category 1 'SOP`Configuration Revision: 0 (0-3,500 psi) Well Category: CAT I �1 I Io e k1 � ..A,�-�:. :rr.• . Pia v 5 • 7 L I Q, a ice., I ! baa .1q . liv&F � .: ir III l III I • 11!;, P. x s • 4f"x"S ga � ., s '17;1,1,411.'101'1: a ' ewe .;..'11...1', . .� e # , ares ,11c:M g A .,. ... igLiNirfi IM PStto 2"1502 x 2-1/1610K Flanged Man Valve O �' x 4�'I," {-A ?a he 2-31?6lflitx2 /i6 _ l 9fREkan !Polus aoru S+ a 0.440; kF§ bbhly, 1q @J K d2IV;LAy fg I -411 �-- „.� ,°�, Wellhead `11 i S OF Tit, THE STATE y \\\I/W Alaska Oil and Gas tv 4 of\LASKA Conservation Commission lS = 333 West Seventh Avenue *4111T., GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 1-\ Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock i 1 2 c Manager 0 Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Nicolai Creek Field, Undefined Upper Tyonek Gas Pool,Nicolai Creek 10 Permit to Drill Number: 210-127 Sundry Number: 317-280 Dear Mr. Pollock: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. The Alaska Oil and Gas Conservation Commission(AOGCC)approves the setting of a temporary plug in this well to provide isolation from the reservoir as a short-term barrier. This work does not meet AOGCC's regulatory requirements for suspension or plugging and abandonment of this well. Prior to relinquishing the lease back to the landowner, the operator is required by law to properly plug and abandon this well. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, d121.3a - Hollis S. French Chair DATED this day of July, 2017. RBDMS L, JUL 1 1 2017 • . • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION jUN 1 6 2017 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AOGCC 1.Type of Request: Abandon ID Plug Perforations 0 Fracture Stimulate 0 Repair Weil 0 Operations shutdown Ej , Suspend El Perforate [] Other Stimulate 0 Pull Tubing Ell Change Approved Program 0 Plug for Redrill El Perforate New Pool 0 Re-enter Susp Well El Alter Casing [I] Other Temporary Plug 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number Aurora Gas,LLC Exploratory 0 Development E. . 210-127 - 3.Address: 1400 W.Benson Blvd.Suite 410 6.API Number Stratigraphic 0 Service Anchorage,AK 99503 50-283-20145-00 , 7.If perforating: 8.Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? NA- Nicolai Creek#10 Will planned perforations require a spacing exception? Yes 0 No co' 42, 9.Property Designation(Lease Number): 10.Field/Pool(s): IA,. ilont.k. ADL-63279 ' Nicolai Creek North Undefinedas 13/4 11. PRESENT WELL CONDITION SUMMARY Total 4e it MD(ft): Total De h ri.(ft): Effective Depth MD: Effective Depth'ND: MPSP(psi): Plugs(MD): Junk(MD): . , •, .d. #45 3396' 3396' 950 psi None None Casing Length Size MD TVD Burst Collapse Structural Conductor 94° 13 3/8"68#K55 94' 94' 3450 psi 1950 psi Surface 654' 95/8"40#L80 654' 654' 5750 psi 2370 psi Intermediate Production 4805' 7"23#N80 4805' 4409' 6340 psi 3830 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 2149'-3866' • 1944'-3570' 27/8" 6.5#J55 3838'" Packers and SSSV Type: Packers and SSSV MD(ft)and ND(It)e . Mechanical @ 3767'(3477) Hydraulic set and mechanical set packers Hydraulic® 2027'(18221 2505'(2340').3177'(2931')and 3384'(3138') 12.Attachments: Proposal Summary 0 Wellbore schematic Ej 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch D Exploratory 10 Stratigraphic 0 Development 0 % Service 0 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: OIL 0 WINJ 0 WDSPL 0 Suspended El 16.Verbal Approval: Date: GAS 0 ,. WAG LI GSTOR Li SPLUG CI Commission Representative: GINJ El Op Shutdown El Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. George Pollock George Pollock Authorized Name: Contact Name: Authorized Title: Manager-.10.4 0 , Contact Email:_gp011ock itaurorapower.corn ...-.•— Contact Phone: 907-277-1003 ________..--,- Authorized Signature: ''' _ Date: 16-Jun-17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number Plug Integrity 0 BOP Test 0 Mechanical Integrity Test D Location Clearance EI Other: .4( %et,,,pc,s_pozNi Pu.k&r PC CI-S ta C."17 ' Cc ak---;:CILAreCIALFW Vc f'0.2.- d',Q4t;MOS.%SO 0 C-. f" .4,. ,t6c Post Initial Injection MIT Req'd? Yes 0 No 0 .. REIDNIS L JULL- 1 1 2017 Spacing Exception Required? Yes 0 No 12( Subsequent Form Required: to —40 4 _ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: .1*1 1 ... ./(>( Ann 7)1141 71511-7- to, 10403 Re4L/2017 0 Rpt,G IIIAL.M:Stx-.) 111 111 a i n lid for 12 months from the date of approval. Submit Form and Attachments in Duplicate 7(6((1 • • Aurora Gas, LLC June 16, 2017 RECEIVED Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission JUN .1 6 2017 333 West 7th Avenue, Suite 100 �a ► Anchorage, AK 99501 Re: Application for Sundry Approval—Set Temporary Plug Nicolai Creek#10 Well PTD #: 210-127 API#: 50-283-20145-00 Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to set a temporary plug to secure this onshore development well in the Nicolai Creek North Undefined Gas Field on the west side of Cook Inlet, southwest of the Village of Tyonek. This well is currently producing gas from multiple zones in the upper Tyonek sands and is mechanically sound. Aurora Gas is currently in Chapter 11 bankruptcy protection while attempting to reorganize and emerge with new owners/investors. This application is being submitted as part of our Reorganization Plan filed with the bankruptcy court if liquidation actions are ordered. Aurora Gas, LLC will provide all potential new owners/investors notice of the impending action before on-site activity begins. The proposed work involves setting a plug via wireline in the profile at a depth of 1,992' above all open perforated intervals to mechanically isolate the reservoir. After the plug is set,tubing pressure will be monitored for 30 minutes to ensure isolation. The master valve will be closed providing double isolation and the wellhead secured. A follow up pressure reading will be obtained after 24 hours to ensure the integrity of the plug. Please find the attached information as required by 20 AAC 25.110 for your review: • Form 10-403 Sundry Application • Current wellbore diagram illustrating the current well configuration. • Slickline Temporary Plug Set—Generalized Procedure If you have any questions or require any further information, please contact me at(907) 277-1003. Sincerel George Pollock Manager—Production Operations&Engineering 4645 Sweetwater Boulevard, Suite 200 * Sugarland,TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 * Anchorage,AK 99503 * (907) 277-1003 • • Aurora Gas, LLC r r +a r 3-1/2"(9.3#)8rd EUE L-80 . 4 ' 4. "; /,', 4r`: Tubing,Oft pup NICOLAI CREEK "' ' "� �`•' ., 2 7/8 6S#8rd EUE J-55 Tubing UNIT#10 .' -° r.° . . 13-3/s"68#Structural PTD# 210-127 4 », ° ." '" Conductor driven to 94'GL API#: 50-283-20145-00-00 > ' RKB 14.7ft " `" 9-5/8"40&36#Surface Casing (As of August 9,2016) setat654' Cement w/12.ppg Type I " r* t .. ,1, ,„, Accelerated Drill 12-1/4"Hole to 678' „h , ...I'', 2-7/8" x 7"annulus displaced ,:' " ,;.i' with 9.3 ppg 3%KCI-NaCI ,. *_ .,, , packer fluid . , .` , HES Sliding Sleeve @ 1992' r s WXO, , 2313 X Profile(closed) Hydraulic set Packer at 2027' ' Carya 2-1 --- Sliding Sleeve at 2191'(open) 2149-2156" , (Tag fill @ 2236'-8/16) (1944-2001'TVD) .::.. Perfs at 2080-82'&2350-52' BH Squeezed 75 and 50 sx '"" 2235-2242' `' ` _ Hydraulic Set Packer @ 2505' (2080-2087'TVD) ms's., Expansion joint*2513' Carya 2-3 .' 2688-2698' _.■,,_ (2523-31'TVD) I Sliding Sleeve(0,2739'WXO, 2312 X Profile (open) 2825-2830' �� ■w•!� (2643-47'TVD) ,„ , , ? p,: _ ,,, Hydraulic Packer(,3177' Carya 2-4.1 .' _ Sliding Sleeve*3279'WXO, 3326-3332' 2312 X Profile (closed) (3080-3091'TVD) qqpp Blast joint 3313-43' Squeezed ,I>_,,I ;�i,. VN Perforated 3467-3472'squeezed ''''' t4Hydraulic Packer @ 3384' with lObbi of 15.8ppg cement .. ' Sliding Sleeve*3,486' "` " . . 2 Blast joints 3489-3549' Carya 2-4.2 3512-3532' A ' _',"', (3251-69'TVD) S:" ' Y Squeezed 3510-3530 75 sx - `.7101111.101101 '' On-Off Seal Nipple w/skirt 2313 X-profile w/PX plug •°, .' Arrowset 1X Mechanical Packer @ 3767 PBTD @ 3950'MD Carya 2-6 .-- 3856-3866' —..4. 1 �! EOT*3838' (3645'TVD (3561-70'TVD) ,a 7"23#K-55&26#U-80 Casing to 4805'MD/ Drill 8-1/2"Hole to 4830'MD, iihk 4409'TVD 4438'TVD avg deviation 26deg,KOP 900' 0 • AURORA GAS, LLC Slickline Temporary Plug Set - Generalized Procedure June 2017 SUMMARY: This procedure describes the steps taken to set a temporary plug in wells operated by Aurora Gas, LLC to secure the well for a short term shut in. RIH with drift for the appropriate sized tool for the tubing, in most cases 2 7/8"tubing with 2.312"or 3 1/2"tubing with 2.812"X landing nipple profile. Set PXX plug in uppermost landing profile. If a profile is not available, RIH with tubing stop pack-off plug and set above uppermost packer. After plug is set, a negative pressure test will be performed to ensure the plug has isolated the productive intervals from the surface. Upon passing the negative pressure test, the wellhead will be secured. PROCEDURE: 1) AG Operators to shut-in well and monitor pressure while rigging up. 2) RU Pollard Wire Line and lubricator on tree after removal of tree cap. Open well to pressure test lubricator—have pressure gauge on lubricator. 3) RIH with appropriate drift for X profile and sliding sleeves in upper profile. Pass through sleeve approximately 10' to insure safe operation of setting tool. POOH. 4) RIH with PXX Plug body on X-Line running tool. Set Plug body in upper most Sliding sleeve X profile above upper most production packer in well. 5) RIH with RB retrieval tool as running tool with prong. Set Prong in Plug body and POOH. 6) Record pressure and Bleed well bore to zero PSI, Monitor for 30 minutes recording pressure readings at 15 minute intervals. 7) Test successful if no pressure increase observed. If test fails, RIH and reset plug. 8) RDMO Pollard Wire Line. 9) Secure the wellhead. 10)Move to next well. 11)After 24 hours, a pressure reading will be obtained to ensure the integrity of the plug. „dyee ,Savage(6/11/2017) DATA SUBMITTAL COMPLIANCE REPORT 3/31/2017 Permit to Drill 2101270 Well Name/No. NICOLAI CK UNIT 10 MD 4830 TVD 4438 Completion Date 9/22/2011 REQUIRED INFORMATION Mud Log Yes DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name Log Perforation ED C Las Log ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C Operator AURORA GAS LLC API No. 50-283-20145-00-00 Completion Status 1 -GAS Current Status 1 -GAS UIC No Samples No�`�`0 Directional Survey Yes ✓ mud log, PEX, GR, SP, ML, FMI, XPT, SWC 21433 Cement Evaluation 21433 Cement Evaluation 21433 Digital Data 21433 Digital Data 21433 Digital Data 21445 Digital Data 21445 Digital Data 21445 Digital Data 21445 Digital Data 21445 Digital Data 21445 Digital Data 21445 Digital Data 21445 Digital Data 21445 Digital Data 21445 Digital Data 21445 Digital Data (data taken from Logs Portion of Master Well Data Maint) Log Log Run Interval OH/ Scale Media No Start Stop CH Received Comments 2 2688 3866 Open 3/20/2012 MD Perforation Record 3.5" Powerjet Omega 3506 654 4808 Case 4/17/2012 USIT CCL GR Plus PDS Graphics 5 Col 654 4808 Case 4/17/2012 USIT CCL GR Plus PDS Graphics 3933 186 4/17/2012 Electronic Data Set, Filename: T21433 MAIN USI 123PUP.las 3911 2254 4/17/2012 Electronic Data Set, Filename: T21433 REPEAT USI 130PUP.las 4/17/2012 Electronic File: T21433 USI_51N.pds 80 4833 7/10/2013 Electronic Data Set, Filename: T21445 1 ft Logging & Gas DataData.las 81 4441 7/10/2013 Electronic Data Set, Filename: T21445 1 ft TVD Logging Data.las 700 6000 7/10/2013 Electronic Data Set, Filename: T21445 Lithology.las 7/10/2013 Electronic File: T21445 2 TVD FEL.emf 7/10/2013 Electronic File: T21445 2MD DEL.emf 7/10/2013 Electronic File: T21445 21VID DEL.pdf 7/10/2013 Electronic File: T21445 2MD FEL.emf 7/10/2013 Electronic File: T21445 2MD FEL.pdf 7/10/2013 Electronic File: T21445 2TVD FEL.pdf 7/10/2013 Electronic File: T21445 5MD FEL.emf 7/10/2013 Electronic File: T21445 5MD FEL.pdf AOGCC Pagel of 4 Friday, March 31, 2017 DATA SUBMITTAL COMPLIANCE REPORT 3/31/2017 Permit to Drill 2101270 Well Name/No. NICOLAI CK UNIT 10 Operator AURORA GAS LLC API No. 50-283-20145-00-00 MD 4830 TVD 4438 Completion Date 9/22/2011 Completion Status 1 -GAS Current Status 1 -GAS UIC No ED C 21445 Digital Data 7/10/2013 Electronic File: T21445 Back Up.adi ED C 21445 Digital Data 7/10/2013 Electronic File: T21445 SDL End of Well Rpt.pdf ED C Las 21445 Report: Final Well RE 0 4833 Open EOW Rpt PDF plusFm Eval Logs EMF PDF Graphics Log 21445 See Notes 2 Col 80 4830 Open 3/20/2012 Surface Data Logging 2" MD Formation Evaluation Log Log 21445 See Notes 2 Col 80 4830 Open 3/20/2012 Surface Data Logging 2" MD Drilling Evaluation Log Log 21445 See Notes 5 Col 80 4830 Open 3/20/2012 Surface Data Logging 5" MD Formation Evaluation Log Log 21445 See Notes 2 Col 80 4438 Open 3/20/2012 Surface Data Logging 2"TVD Formation Evaluation Log Rpt 21445 Report: Final Well RE 0 0 Open 3/20/2012 Surface Data Logging End of Well Report ED C 23013 Digital Data 3354 3672 7/10/2013 Electronic Data Set, Filename: AURORA_NCU#10_PERF_09MAY13 RUN1.LA S ED C 23013 Digital Data 3201 3456 7/10/2013 Electronic Data Set, Filename: AURORA_NCU#10_PERF_09MAY13 RUN2.LA S ED C 23013 Digital Data 2074 2416 7/10/2013 Electronic Data Set, Filename: AURORA_NCU#10_PERF_09MAY13 RUN3.LA S ED C 23013 Digital Data 2000 2259 7/10/2013 Electronic Data Set, Filename: AURORA _NCU#10_PERF_09MAY13 RUN4.LA S ED C 23013 Digital Data 7/10/2013 Electronic File: AURORA_NCU#10_PERF_09MAY13_img.tiff Log 23013 Log Header Scans 0 0 2101270 NICOLAI CK UNIT 10 LOG HEADERS Rpt 28041 Directional Survey 25 4830 Open 3/20/2012 Definitive Survey Report Rpt 28041 Directional Survey 25 4830 Open 3/20/2012 Definitive Survey Report Log 28041 Formation Micro Imac 2 Col 654 4808 Open 3/20/2012 Formation Micro -Imager Dipmeter-Gamma Ray Log 28041 Neutron 2 Col 654 4808 Open 3/20/2012 Platform Express Compensated Neutron/Triple LithoDensity Array Induction Log 28041 Pressure 2 Col 977 3870 Open 3/20/2012 Express Pressure Tool Gamma -Ray Log 28041 Pressure 2 Col 977 3870 Open 3/20/2012 Express Pressure Tool Gamma -Ray AOGCC Page 2 of4 Friday, March 31, 2017 DATA SUBMITTAL COMPLIANCE REPORT 3/31/2017 Permit to Drill 2101270 Well Name/No. NICOLAI CK UNIT 10 MD 4830 TVD 4438 ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data ED C 28041 Digital Data Well Cores/Samples Information: Name Cuttings INFORMATION RECEIVED Operator AURORA GAS LLC API No. 50-283-20145-00-00 Completion Date 9/22/2011 Completion Status 1 -GAS Current Status 1 -GAS UIC No 9 4821 3/9/2017 Electronic Data Set, Filename: AURORA_NICOLAI_CREEK_NO10_PEX_MAIN_ 025PUP.LAS 646 4820 3/9/2017 Electronic Data Set, Filename: SLB_ NICOLAI_CREEK_NO10_FMI_MAIN 046P UP.LAS 3/9/2017 Electronic File: AURORA_NICOLAI_CREEK_NO10_FMI 51N.PD S 3/9/2017 Electronic File: final —AURORA _ NICOLAI_CREEK_N010 PEX 2 & 51N.PDS 3/9/2017 Electronic File: SLB_NICOLAI_CREEK_NO10_XPT LONG.PDS 3/9/2017 Electronic File: Sperry NCU #10 Rig Surveys.txt 3/9/2017 Electronic File: Sperry NCU 10 Definitive Survey Grid.pdf 3/9/2017 Electronic File: Sperry NCU 10 Definitive Survey True.pdf 3/9/2017 Electronic File: WF Core Analysis_Nicolai Creek Unit #10.pdf 3/9/2017 Electronic File: WF LGSA Stats at 1493.pdf 3/9/2017 Electronic File: WF LPSA Stats.pdf 3/9/2017 Electronic File: WF LPSA_Nicolai Creek Unit No 10 Stats and Summary.xlsx 3/30/2017 Electronic File: Au rora_N icola i_Cr_10_Perf_20Sept2011. pds Interval SampleSet Start Stop Sent Received Number Comments 684 4833 3/20/2012 1303 AOGCC' Page 3 of 4 Friday, March 31, 2017 DATA SUBMITTAL COMPLIANCE REPORT 3/31/2017 Permit to Drill 2101270 Well Name/No. NICOLAI CK UNIT 10 MD 4830 TVD 4438 Completion Report 0 Production Test Informatioril /JNA Geologic Markers/Tops ) COMPLIANCE HISTORY Completion Date: 9/22/2011 Release Date: 10/22/2013 Description Comments: Compliance Operator AURORA GAS LLC API No. 50-283-20145-00-00 Completion Date 9/22/2011 Completion Status 1 -GAS Current Status 1 -GAS UIC No Directional / Inclination Data O Mud Logs, Image Files, Digital Date Yy NA Core Chips Y NA Mechanical Integrity Test Information Y /CA Composite Logs, Image, Data Filesa Core Photographs Y Daily Operations Summary ) Cuttings Samples Y / A Laboratory Analyse$( l/ A Date Comments Date: AOGCC Page 4 of 4 Friday, March 31, 2017 Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Friday, March 31, 2017 9:00 AM To: George Pollock Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: RE: Nicolai Creek Unit 10, PTD 210-127, Data Required George, Thank you. That completes the data required for Nicolai Creek #10 well. Regards, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl(c@alaska.gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235 or meredith.guhlPalaska.gov. From: George Pollock (mailto:gpollock@aurorapower.com] Sent: Thursday, March 30, 2017 12:58 PM To: Guhl, Meredith D (DOA) <meredith.guhl@alaska.gov> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: Nicolai Creek Unit 10, PTD 210-127, Data Required Meredith, Attached is the perforation record for the Nicolai Creek #10 well dated September 20, 2011. George Pollock Manager, Production Operations & Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 Main (907) 351-8286 Cell From: Guhl, Meredith D (DOA) [mailto:meredith guhl(abalaska gov] Sent: Wednesday, March 29, 2017 2:03 PM To: George Pollock Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: RE: Nicolai Creek Unit 10, PTD 210-127, Data Required Hello George, Just following up on my request for the digital data for the Schlumberger Perforation record completed 20 Sept 2011. Could you please provide this digital data by April 5? Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235 or meredith.guhl(cDalaska.gov. From: Guhl, Meredith D (DOA) Sent: Friday, March 10, 2017 8:49 AM To: 'George Pollock' <gpollock(cDaurorapower com> Cc: Bettis, Patricia K (DOA) <patricia.bettis alaska.gov>; Schwartz, Guy L (DOA) <guv.schwartz@alaska.gov> Subject: RE: Nicolai Creek Unit 10, PTD 210-127, Data Required Hello again George, The AOGCC has digital and paper versions of the Halliburton Perforating record completed on 9 May 2013. But there is also a paper copy of a log for a Schlumberger Perforation record completed on 20 Sept 2011 that there is no digital data for in our database. Just found this log with the stack of other misfiled logs. Could you please send the digital data for the Schlumberger perforation log? Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhI@alaska.gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235 or meredith.guhl alaska eov. From: Guhl, Meredith D (DOA) Sent: Friday, March 10, 2017 8:35 AM To: George Pollock <gpollock@aurorapower.com> Cc: Bettis, Patricia K (DOA) <patricia.bettis(a@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz(a@alaska.gov> Subject: RE: Nicolai Creek Unit 10, PTD 210-127, Data Required Hi George, Thank you for the digital data. After reviewing our database records, I took another look in our library and found the paper logs I had requested. Someone had misfiled them. I located paper copies of: mudlogs, mudlog EOW report, perforation record, FMI, PEX, and XPT. Which means another copy of the paper logs do not need to be supplied. My apologies for not looking in all the locations they could've been filed. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl alaska.gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235 or meredith.guhl(@alaska.gov. From: George Pollock [mailto:gpollock aurorapower com] Sent: Thursday, March 09, 2017 2:21 PM To: Guhl, Meredith D (DOA) <meredith.guhl@alaska gov> Cc: Bettis, Patricia K (DOA) <patricia.bettis alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: RE: Nicolai Creek Unit 10, PTD 210-127, Data Required Meredith, Attached are the requested items in aigital format. I have requested paper formals which will be provided at a later date. Let me know if you have any questions. Cheers, George Pollock Manager, Production Operations & Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 Main (907) 351-8286 Cell From: Guhl, Meredith D (DOA) [mailto:meredith quhl(abalaska gov] Sent: Thursday, March 02, 2017 9:11 AM To: George Pollock Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: Nicolai Creek Unit 10, PTD 210-127, Data Required Importance: High Hello George, I've discovered that Nicolai Creek Unit 10, PTD 210-127, completed 9/22/2011, has not yet had compliance completed on it. In reviewing the well file, I discovered that there is quite a lot of outstanding data that Aurora is required to submit. Please supply the following items, in both paper and digital format, by April 2, 2017. The log list comes from the 10-407 form. 1. PEX (Array Ind + Comp Ntrn + Litho Den w/GR, SP, ML) logs and digital data 2. FMI dipmeter logs and digital data 3. XPT logs, reports, digital data 4. Additional sidewall core analyses as noted on the 10-407 form Please supply paper copies of the mudlogs and the end of well report completed on this well. Digital data was supplied, but mudlogs have not yet been provided. Please supply a digital directional survey. Please also supply a digital version of the already submitted sidewall core analyses by Weatherford completed 9/12/2011. As noted above, this data is required by April 2, 2017. Please submit the data to my attention. If you have any questions, please contact me. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. Oro - /z.T Guhl, Meredith D (DOA) From: George Pollock <gpollock@aurorapower.com> Sent: Thursday, March 09, 2017 2:21 PM To: Guhl, Meredith D (DOA) Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: RE: Nicolai Creek Unit 10, PTD 210-127, Data Required Attachments: final_AURORA_NICOLAI_CREEK_NO10_PEX_2 & 51N.PDS; AU RORA_NICOLAI_CREEK_NO10_PEX_MAIN_025 PUP. LAS; AURORA_NICOLAI_CREEK_NO10_FMI_51N.PDS; SLB_NICOLAI_CREEK_NO10_FMI_MAIN_ 046PUP.LAS; SLB_NICOLAI_CREEK_NO10_XPT_LONG.PDS; Sperry 1 ft Nicolai Creek #10 Logging & Gas DataData MD.LAS; Sperry NCU 10 Definitive Survey Grid.pdf, Sperry NCU 10 Definitive Survey True.pdf; Sperry NCU #10 Rig Surveys.txt; WF LPSA_Nicolai Creek Unit No 10 Stats and Summary.xlsx; WF Core Analysis_Nicolai Creek Unit #10.pdf; WF LGSA Stats at 1493.pdf; WF LPSA Stats.pdf Meredith, Attached are the requested items in digital format. I have requested paper formats which will be provided at a later date. Let me know if you have any questions. Cheers, George Pollock Manager, Production Operations & Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 Main (907) 351-8286 Cell From: Guhl, Meredith D (DOA) [mailto:meredith.guhl@alaska.gov] Sent: Thursday, March 02, 2017 9:11 AM To: George Pollock Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: Nicolai Creek Unit 10, PTD 210-127, Data Required Importance: High Hello George, I've discovered that Nicolai Creek Unit 10, PTD 210-127, completed 9/22/2011, has not yet had compliance completed on it. In reviewing the well file, I discovered that there is quite a lot of outstanding data that Aurora is required to submit. Please supply the following items, in both paper and digital format, by April 2, 2017. The log list comes from the 10-407 form. I. PEX (Array Ind + Comp Ntrn + Litho Den w/GR, SP, ML) logs and digital data 2. FMI dipmeter logs and digital data 3. XPT logs, reports, digital data 4. Additional sidewall core analyses as noted on the 10-407 form Please supply paper copies of the mudlogs and the end of well report completed on this well. Digital data was supplied, but mudlogs have not yet been provided. Please supply a digital directional survey. Please also supply a digital version of the already submitted sidewall core analyses by Weatherford completed 9/12/2011. As noted above, this data is required by April 2, 2017. Please submit the data to my attention. If you have any questions, please contact me. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhIPalaska gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235 or meredith.guhl(@alaska.gov. RECEIVED STATE OF ALASKA 1 O Z O 13 ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Li Repair Well Li Plug Perforations77 Perforate LzOther Cement Squeeze Performed: Alter Casing ❑ Pull Tubing Q Stimulate - Frac ❑ WaiverE] Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re-enter Suspended Well ❑ 2. Operator Aurora Gas, LLC4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑ Exploratory ❑ 210-127 3. Address: 1400 W. Benson Blvd., Suite 410 Anchorage, Stratigraphic ❑ Service ❑ 6. API Number: AK 99503 50-283-20145-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL -63279 Nicolai Creek #10 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): Halliburton Perforating Record Nicolai Creek Unit/North Undefined Gas 11. Present Well Condition Summary: Total Depth measured 4,830' feet Plu s d Perforation depth Measured depth see attached feet True Vertical depth see attached feet Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) s 12. Stimulation or cement squeeze summary: Intervals treated (measured): see attached T t td J-55 ma men escnptions including volumes used and final pressure: see attached 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 500 12 80 Subsequent to operation: 2,000 0 500 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run attached Exploratory ❑ Development Service ❑ Stratigraphic ❑ Daily Report of Well Operations attached 16. Well Status after work: Oil LJ Gas 1,1 , WDSPL ❑ IGSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ .3USP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. e Exmpt: ��- 3 13 -1-59 4, Contact George Pollock Email ggollockpauroraoower.com Printed Name Title Manager - Production Operations & Engineering Signature - �, Phone 907-277-1003 Date 7/10/2013 RB®MS JUL 11 201 Form 10-404 Revised 10/2012 7--3o-,/3 Submit Original Only ,•C Tam �� g measure none feet true vertical 4,438' feet Junk measured none feet Effective Depth measured 3,950' feet Packer measured see attached feet true vertical 3,645' feet true vertical see attached feet Casing Length Size MD TVD Burst Collapse Structural Conductor 94' 13 3/8" 94' 94' 1,530 psi 520 psi Surface 654' 9 5/8" 654' 654' 3,520 psi 2,020 psi Intermediate Production 4,805' 7" 4,805' 4,409' 4,270 psi 3,120 psi Liner Perforation depth Measured depth see attached feet True Vertical depth see attached feet Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) s 12. Stimulation or cement squeeze summary: Intervals treated (measured): see attached T t td J-55 ma men escnptions including volumes used and final pressure: see attached 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 500 12 80 Subsequent to operation: 2,000 0 500 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run attached Exploratory ❑ Development Service ❑ Stratigraphic ❑ Daily Report of Well Operations attached 16. Well Status after work: Oil LJ Gas 1,1 , WDSPL ❑ IGSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ .3USP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. e Exmpt: ��- 3 13 -1-59 4, Contact George Pollock Email ggollockpauroraoower.com Printed Name Title Manager - Production Operations & Engineering Signature - �, Phone 907-277-1003 Date 7/10/2013 RB®MS JUL 11 201 Form 10-404 Revised 10/2012 7--3o-,/3 Submit Original Only ,•C Tam �� Aurora Gas, LLC NICOLAI CREEK UNIT #10 PTD#: 210-127 API#: 50-283-20145-00-00 RKB 14.7ft (As of May 31, 2013) Drill 12-1/4" Hole to 678' 2-7/8" x 7" annulus displaced with 93 ppg 3% KCI- NaCl packer fluid III Carya 2-1 2149-2156" (1944-2001' TVD) Perfs at 2080-82' & 2350-52' BH Squeezed 75 and 50 sx 2235-2242' (2080-2087' TVD) Carya 2-3 2688-2698' (2523-31' TVD) 2825-2830' (2643-47' TVD) n Carya 24.1 3326-3332' (3080-3091' TVD) _ Squeezed 3319-3331' 50 sx Perforated 3467-3472' squeezed with 10bbl of 15.8ppg cement 3-1/2" (93#) 8rd EUE L-80 Tubing, 4ft pup 2 7/8 6.5# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 94' GL 9-5/8" 40 & 36# Surface Casing set at 654' Cement w/12. ppg'Type I Accelerated y HES Sliding Sleeve @ 1992' WXO, 2313 X Profile (closed) Hydraulic set Packer at 2027' ' Sliding Sleeve at 2191' (open) Hydraulic Set Packer @ 2505' Expansion joint @ 2513' Sliding Sleeve @ 2739' WXO, 2.312 X Profile (Closed) Hydraulic Packer A 3177' Sliding Sleeve @ 3279' WXO, 2.312 X Profile (closed) Blast joint 331343' Hydraulic Packer @ 3384' Sliding Sleeve @ 3,486' with PX plug above it. 2 Blast joints 3489-3549' On -Off Seal Nipple w/ skirt 2313 X -profile W/ PX plug Arrowset 1X Mechanical Packer @ 3767 EOT A 3838' 7" 23# K-55 & 26# Lr80 Casing to 4805' MD/ 4409' TVD Carya 24.2 wftW 3512-3532' (3251-69' TVD) Squeezed 3510-3530 75 sz' PBTD @ 3950' MD Carya 3856-386666'' (3645' TVD) (3561-70' TVD) Drill 8-1/2" Hole to 4830' MD, 4438' TVD avg deviation 26deg, KOP 900' 3-1/2" (93#) 8rd EUE L-80 Tubing, 4ft pup 2 7/8 6.5# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 94' GL 9-5/8" 40 & 36# Surface Casing set at 654' Cement w/12. ppg'Type I Accelerated y HES Sliding Sleeve @ 1992' WXO, 2313 X Profile (closed) Hydraulic set Packer at 2027' ' Sliding Sleeve at 2191' (open) Hydraulic Set Packer @ 2505' Expansion joint @ 2513' Sliding Sleeve @ 2739' WXO, 2.312 X Profile (Closed) Hydraulic Packer A 3177' Sliding Sleeve @ 3279' WXO, 2.312 X Profile (closed) Blast joint 331343' Hydraulic Packer @ 3384' Sliding Sleeve @ 3,486' with PX plug above it. 2 Blast joints 3489-3549' On -Off Seal Nipple w/ skirt 2313 X -profile W/ PX plug Arrowset 1X Mechanical Packer @ 3767 EOT A 3838' 7" 23# K-55 & 26# Lr80 Casing to 4805' MD/ 4409' TVD Aurora Gas, LLC Nicolai Creek #10 RCWO 2013 AOGCCC Sundry Report Perforations (new): Zone 1: 3,512' - 3,532' MD (3,251' - 3,269' TVD) Zone 2: 3,326' - 3,332' MD (3,080' - 3,091' TVD) Zone 5: 2,235' - 2,242' MD (2,080' - 2,087' TVD) Zone 6: 2,149' - 2,156' MD (1,944' - 2,001' TVD) Perforations (prior left intact): Zone 3: 2,825' - 2,830' MD (2,643' - 2,647' TVD) Zone 4: 2,688' - 2,698' MD (2,523' - 2,531' TVD) Packers: Arrowset 1X Mechanical Packer at 3,767' MD (3,487' TVD) HES PHL Packer at 3,384' MD (3,134' TVD) HES PHL Packer at 3,177' MD (2,972' TVD) HES PHL Packer at 2,505' MD (2,331' TVD) HES PHL Packer at 2,027' MD (1,843' TVD) Cement Squeeze Summary: Squeeze 1: existing perforations at 3,510' - 3,530' MD squeezed with 15 barrels (bbls) cement (75 sacks (sx) 15.8 pound per gallon (ppg) Class G with accelelator and gas control); cement slurry pumped with 2 bbls water and 3 bbls KCL water, and was displaced with 12 bbls KCL water at 400 psi. Squeeze 2: existing perforations at 3,319' - 3,331' MD squeezed with 8 bbls 15.8 ppg cement slurry; pump slurry with final rate at 1/3 barrel per minute (BPM) at 1500 psi. Squeeze 3: new perforations at 2,350'- 2,352' MD squeezed with 15 bbls cement slurry pressure built up to 1,100 psi. Squeeze 4: New perforations at 2,080'- 2,082' MD squeezed with 8 bbls cement slurry pressure built up to 1,300 psi. Synopsis Aurora Gas, LLC Nicholai Creek Unit #10 Remedial & Recompletion Workover 2013 AOGCC Sundry Approval 313-138 9 April 13 Move in 1.25" coil tubing unit, pump and nitrogen unit. Rig up and test BOP's. AOGCC witness waived by Jim Regg. Started to fill coil with fluid, pressured up to 6200 psi. Coil appears to be frozen. Cover with tarps and install heater ducts. Apply heat. 10 April 13 Continue to thaw coil. Attempt to pump into coil every hour without success. 11 April 13 Continue thawing operation without success. 12 April 13 Continue thawing operation until noon without success. Rig down all equipment and send coil unit to BHI Kenai yard. Suspend all operations and release crews. 13 April 13 Receive repaired coil unit from barge. Move all equipment to NC 10 location. 14 April 13 Rig up 1.25" coil, pump, and nitrogen unit. Rig up BOP's, choke skid, flowback tank and piping. Run in hole with wash nozzle and wash fill to 3457'. Coil depth counter not counting properly. Flew replacement counter over and installed. Pull out of hole and rig up Pollard to pull plug. Attempt to pull plug. Had to dump bail fill on top of equalizing prong. 15 April 13 Pressure tubing to 1200 psi and pull prong. Make 2 more runs to retrieve plug. Make up coil to wellhead and run and wash sand to 3778'. Circulate well clean and pull out and stand back coil. 16 April 13 Rig up Pollard and close sleeve at 3354. Top of fluid estimated at 1780'. Run in and set PX plug at 3364'. Rig down all equipment and move off location so rig crew can grade pad for rig installation. 17 April 13 Cut off production line and cap. Remove cellar grating and sills. Lay felt and rig liner. Spot pony sub, boat and carrier. Set mats for sub, pits, pump and backyard. 18 April 13 Set mats for parts house, oil shed and fuel tank. Set water tank and install doghouse. Set stairs for doghouse and install mat for office trailer. 19 April 13 Rig up floor and wind walls. Rig up pits and standpipe manifold. Set blocks and guide wires. Continue working on hoses, electric lines and sundry items. 20 April 13 Finish containment. Continue cleaning and organizing yard. Bleed off well and set back pressure valve. Nipple down tree and install DSA and BOP's. Continue rigging up and install CanRig PVT Instrumentation. Notify AOGCC of pending BOP/Rig inspection. 21 April 13 Rig up to test BOP's. Install alarms and test. Test BOP's prior to witness by AOGCC. Fill pits with water. Pull pack pressure valve. 22 April 13 Mix brine. Make up landing joint and screw into tubing hanger. Rig up Pollard and open sleeve at 2547. Reverse 20 bbls from annulus. Pull equalization probe at 3354'. Had to dump bail to get latched on. Fill tubing with fluid. Close sleeve at 2547'. Rig down Pollard. Attempt to open annulus valve. Stem broken. Order replacement valve. Install 2" 15K valve on broken valve for control. 23 April 13 Drug screen all personnel on Aurora property. Release lock down screws and attempt to pull packers free. 3 packers released but having trouble releasing from "On -Off" assembly. Well flowing. Build 9.3 brine and circulate. Worked loose from "on-off" assembly. Pull 20' and circulate to balance fluid. Shut down and monitor. Losing 8-10 bbls/hr at static conditions. 24 April 13 Pump 20 bbl 9.6 ppg LCM pill (Baraplug graded salt in saturated brine) and spot at 2688'. Monitor. Pump 18 bbls 9.6 ppg LCM pill. Fill hole and balance fluid. Well static. Pull tubing hanger and pup and lay down. Pull 70K to pull packers free. Start laying down tubing and %" stainless steel injection line. Recovered 2547' of tubing and % of sliding sleeve. Wait on orders. Clean rig. Rig up drill pipe tongs and change to 4" pipe rams. 25 April 13 Load 4" drill pipe on rack and strap. Test 4" rams. Install wear bushing and pickup fishing tools, drill collars, and pipe. Engage fish at 2493'. Jar up 100k. Circulate and work on power swivel. 26 April 13 Trouble shoot and repair power swivel brake system. Circulate hole and build 9.1 ppg 3% KCI/NaCl brine. Jar fish until loose. Pull out and lay down. Retrieved 2 packers and expansion joint. 27 April 13 Service rig while waiting on replacement overshot. Make up new overshot and run in to 3238'. Engage fish. Jar 120k -140k to work fish to 3207'. 28 April 13 No progress with retrieving fish. Rig up Halliburton E -line, BOP's, and pump in sub. Run in hole with cutter and CCL. Restricted at 3255'. Run in with LIB which showed 1.75 ID circle impression. Rig down HES and continue jarring. 29 April 13 Repair drill line at dead man and change out weight indicator. Wait on Pollard. Run in with LIB and dump bailer. No change. Rig down Pollard. Work 12 rounds of torque down pipe. Work pipe. Work 6 rounds torque down. Fish free. Pull out and lay down pipe. Retrieved 1 joint of cork- screwed tubing and % of sliding sleeve. Fish is now at 3270'. Install test plug and test BOP's. 30 April 13 Continue testing BOP's. Pull test plug and reinstall wear bushing. Change elevators and slips. Make up fishing BHA and run in hole to fish at 3271'. Engage and jar on fish. Tried to run cutter on E -line, but couldn't get below 3224'. Continue working fish. 1 May 13 Continue jarring on fish. Pulled free at 3069'. Pull out of hole with drill pipe, change to 2 7/8 equipment and lay down fish. Left bottom packer and lower part of "on-off" assembly. Clean up rig floor. Make up tapered mill, junk basket, bumper sub, jars and drill collars. Run in to On -Off tool at 3770'. Circulate hole clean and spot 2 sacks of sand on "on-off' assembly. 2 May 13 Run in and set HES Fast Drill cement retainer at 3450' with E -line. Change pipe rams to 2 7/8. Test rams. Make up stinger on drill pipe and run in hole to retainer. Circulate, stab in and get injection rate. 1 BPM at 180 psi, 2 BPM at 400 psi, 3 BPM at 800 psi. Shut down, pressure bled to 200 psi. Batch mix 15 bbls cement (75 sx 15.8 ppg Class G w/ accelerator and gas control, 1.15 cf/sk). Pump 2 bbls water, 15 bbls slurry, 3 bbls KCL water. Sting in and displace slurry with 12 bbls KCL water at 400 psi. Unsting and pump wiper ball. Reverse 2 volumes. Pull out of hole. 3 Mav 13 Run in and set HES Fast Drill retainer at 3265' on E -line. Mix 20 bbls 3% KCL fluid and spot in tubing. Sting into retainer and perform breakdown. .5 BPM at 1000 psi. Batch up 8 bbls 15.8 ppg cement slurry. Unsting and spot slurry. Sting into retainer and squeeze at 1- .33 BPM. Unsting and pump wiper ball. Reverse 2 volumes. Pull out of hole. Rig up HES perforating guns. Test lubricator to 500 psi. Run in and perforate from 2350 — 2352'. Run in with second set of guns and perforate from208O — 2082'. Run in and set HES Fast Drill retainer at 2375'. 4May13 Run in with HES retainer. Couldn't get past 2080'. Pull out and lay down retainer and rig down E -line. Change rams to 4" and test. Run in with mill and scraper to 2380'. Circulate hole clean. Rig up E -line and set retainer at 2258'. Make up stinger and run in to top or retainer. Spot 20 bbls KCL fluid in drill pipe, sting into retainer. Pump .25 BPM at 1300 psi into bottom perfs, unsting and pump .25 BPM at 1000 psi into top perfs. Pull out of hole. 5 May 13 Lay down BHA, Service rig. Run in with bit to 2258' and drill out retainer, circulate bottoms up. Pull out of hole. Run in hole with DP. Batch 15.4 bbls 15.8 ppg cement slurry, test lines to 2000 psi. Pump 5 bbls water, 15.4 slurry, 12 bbls KCI fluid. Pull 6 stands slow, drop wiper ball, displace. Pull 2 stands and reverse out 2 volumes. Close bag, pressure up to 1000 psi, pump away 2 bbls. Bled to 800 psi. Pull out of hole, close bag and pressure to 800 psi. Bled to 530 psi. Run in to 2137'. Circulate bottoms up; no cement. 6May 13 Wash down to 2200'. Tag cement, held 4k. Mix 9.9 brine ppg pill. Spot at 2197'. Pressure casing to 1000 psi. Bled to 750 psi. Rig down Schlumberger. Pull out of hole. Set test plug and perform BOP test. Run in and set HES retainer at 2100'. Rig up Schlumberger and perform breakdown. 1 BPM at 1000 psi. Mix and pump 10 bbls 15.8 ppg cement slurry. Displace below retainer. Pull 7 stands, pump wiper ball, and reverse 2 volumes. Sting in and squeeze 5 bbls at 1300 psi. Hold; bled to 780 psi. Pull out of hole. 7May13 Run in with 6.12" bit to 1920'. Wash to 2010'. Drill retainer and cement to 2108'. Circulate and service rig. Run in and drill cement from 2171— 2264' and 2264 — 2375'. Drill retainer at 2375. 8 Mav 13 Run in and drill retainer at 3265'. Run in and drill cement 3301— 3455. Drill retainer at 3455'. Drill cement 3518- 3750'. Reverse circulate with clean 9.3 ppg brine. Start filtering well fluid with 50 micron filters. Then to 25 micron. 9 May 13 Continue filtering to 10 micron. Pull out of hole and lay down BHA. Prepare to perforate. Perforate 3512 — 3532', 6 shot per foot, 60 degree phasing. Perforate 3326 — 3332', 2235 — 2242', 2149 — 2156'. Rig down HOWCO. Pick up clean out BHA; mill, scraper, junk basket. Run in hole. 10 May 13 Run in and tag "on — off tool" at 3770'. Circulate hole at 6.5 BPM, 920 psi. Pull out and lay down drill pipe. Set test plug, change rams to 2 7/8", test. Safety meeting and start picking up completion string. 11 May 13 Finish picking up completion string. Tag "on/off" tool. Circulate, space out and land tubing hanger. Pressure up and set packers. Hold 1966 psi for 10 minutes. Attempt to test annulus to 1500 psi. Communications with tubing. Run in with Pollard and confirm all sleeves closed and set PX plug in lowest sleeve. Can't get test on tubing or annulus. Open sleeve at 2033' and pump through it. Close sleeve. Still can't get test. Run in with DD hole finder on Pollard. Attempt to test at 2092'. "O" ring leaking on lubricator. Shear off, pull out and repair. 12 May 13 Set plug at 2235, bled off, set at 2175, held 2500 psi. Test all sliding sleeves. Only top one held 2500 psi. Pull PX plug at 3489'. Pull hanger, circulate, release packers and pull out of hole. 2nd sliding sleeve backed off in middle. Attempted to run in and screw into bottom half. No luck. Pull out and pick up grapple. Run in and engage fish. Pick up and saw 2 positive packer releases. Try to work % CCW turn to "on/off tool" to release it. Unable to release. 13 Mav 13 Wait on tools. Clean pits. Wireline truck from Beluga hit soft area in road and broke engine oil pan. Remove, clean and patch. Wait on patch to cure. Continue cleaning pits. Install engine oil pan. 14 Mav 13 Run in and shoot holes in tubing from 3737 — 3741' to relieve pressure wave of radial cutter. Cut tubing at 3745'. Circulate. Pull out with all packers and sleeves. Send packers, sleeves and expansion joint to Weatherford for redressing. Install test plug and test BOP's. Make up overshot and run in to 3735' Circulate 2 bottoms up. 15 May 13 Latch unto fish at 3745 and attempt to release "on/off tool". Run in with dump baler and LIB. Recovered small amount of sand. No obstructions noted on LIB. Pull out of hole. Change pipe rams from 2 7/8" to 4". Test. Pick up and run in open ended with 4" drill pipe to 3450'. 16 May 13 Circulate. Pull out of hole and wait for wash pipe. Clean rig and work on maintenance list. 17 May 13 Road from Tyonek locations shut down due to breakup. Make up BHA with wash pipe, drill collars, junk baskets, magnets, jars and bumper subs. Run in and wash over fish while circulating. Pump hi viscosity pills. Shut down and wait for any debris to settle into junk baskets. 18 May 13 Pull out with wash pipe. Run in with overshot and engage fish at 3745. Work loose and pull out wet. All of fish recovered. Bottom plugged with mud/sand and equalizing probe. Run in with scraper and circulate at 3753'. 19 May 13 Circulate and reverse circulate. Wait for vac trucks and crew to haul off contaminated brine from pits. Haul to production tanks and haul in fresh water. Filter coming off trucks and mix with KCI/Salt to 9.3 ppg. 20 May 13 Continue mixing clean brine. Displace well with clean brine. Pull out and lay down drill pipe. Change rams to 2 7/8". Test. Pick up and run completion string. 21 May 13 Continue running completion string. Circulate at 3765'. Attempt to latch "on/off tool". Run in with LIB. Showed clean "on/off" profile. Continue trying to latch and engage seals. Land tubing without engaging seals. Test hanger to 5000 psi. Set equalizing probe in PX plug at 3767'. Set plug at 3491', check all sleeves for closed. Test tubing to 1500 psi. Set packers with 2800 psi. Hold for 10 minutes. Test annulus to 1500 for 30 minutes. Pull landing joint and set back pressure valve. Remove BOP stack. 22 Mav 13 Nipple up tree and test to 5000 psi for 15 minutes. Pull back pressure valve. Rig up test equipment and test. Retrieve PX plug at 3491'. Lost 3 seal rings; fished out. Test tubing; taking fluid at 400 psi. Start to swab. 8 bbls recovered; well burped; sent to test equipment. Changed plate to 1.75" and 14/64" choke. 900psi well head, 440 psi test unit. Shut in and change washed out 90. 1100 psi well head. Flowing at 4.9 MMcf/day at 870 psi. Shut in and monitor every 30 minutes. 1330, 1375, 1375, 1375 psi. 23 Mav 13 Monitor well. Run in and close sleeve at 3486'. Master tree valve leaking. Pump 20 bbls brine to kill well. Grease tree valves. Run in and set PX plug at 3486'. Test plug to 1500 psi. Open sleeve at 3278'. Swab well. 16 bbls recovered. No gas. Close sleeve at 3278' and open sleeve at 2739'. Swab well to 1900'. 1.2 bbls fluid recovered. No gas. Close sleeve at 2739'. 24 May 13 Open sleeve at 2192'. Monitor well, pressure built to 200 spi. Open to test unit. Test—final flow rate was 2005 mcfpd at 247 psi. Shut in pressure 735 psi. Close sleeve at 2192 and open sleeve at 3278'. Pressure built to 65 psi. Open to flare and bled to "0". Swab. 15 bbls recovered. No gas. Confirm sleeves at 2739 and 2191 closed. Top of fluid at 2670'. Swab. 25 May 13 Swab 6.25 bbls. Close sleeve at 3278 and open sleeve at 2739'. Fluid level at 3100', no flow. Mix 14 bbls 40#/bbl KCI (+/-11%) water and pump 10 bbls into formation at 2739'. Shut in 30 minutes. Swab 13 bbls. Well flowing to test unit. Well head pressure 400 psi. Open and tested at a final rate of 1053 mcf/day at 195 psi. Shut in pressure 740 psi. Close sleeve at 2739'. Confirm all sleeves closed. Release rig at 24:00. Crews working on cleaning, rigging down test equipment and equipment storage. 26 May 13 Continue rigging down and maintenance. 27 May 13 Preparing rig for move. Move 500 bbls tank to location for fluid storage. 28 May 13 Clean pits and cutting tank. Build containment for super sacks of solids. 29 May 13 Continue rig down and maintenance. Install back pressure valve and install flow line from tree to production system. Turn well over to production. 1110 C ,DNS ttGIZ-7ri Regg, James B (DOA) From: George Pollock <gpollock@aurorapower.com> Sent: Tuesday, September 09, 2014 12:05 PM ( kik' To: Regg,James B (DOA) � `' (�� t Cc: Hill, Johnnie W (DOA) Subject: RE: Coil Tubing BOPE Test - NCU #10 Attachments: Baker Coil Treatment Daily Rpts.pdf; NIC. #10, 2014 08 28, P-878.xls; NIC.#10, 2014 08 29, P-879.xls; NIC. #10, 2014 08 30, P-880.xls; NC 10 CTCO 2014 Ops Summary.doc; J195 BOP 8-28-14.xlsx; BOP chart for NC-10 08-28-14.pdf Jim, Attached is the requested information for the NC10 coil tubing clean out where the inspector was not provided the opportunity to witness the BOP Test after the initial notification. Let me know if you require any further information. Regards, George Pollock Manager, Production Operations & Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 Main (907) 351-8286 Cell SCANNED From: George Pollock Sent: Wednesday, September 03, 2014 11:42 AM To: 'Regg, James B (DOA)' Cc: Hill, Johnnie W (DOA) Subject: RE: Coil Tubing BOPE Test - NCU #10 Jim, • Aurora Gas performed the BOP test on the NC#10 well on Thursday August 28. I failed to contact the inspector as instructed to provide the opportunity to witness the BOP Test at that time. I will provide the information requested below. Let me know if you require any further action on this matter. George Pollock Manager, Production Operations & Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 Main • • (907) 351-8286 Cell From: Regg, James B (DOA) [mailto:jim.reclq©alaska.gov] Sent: Wednesday, September 03, 2014 10:11 AM To: George Pollock Cc: Hill, Johnnie W (DOA) Subject: Coil Tubing BOPE Test - NCU #10 Inspector arrived at Nicolai Creek#10 for witness of a coil tubing unit BOPE test last week—notice provided to AOGCC on 8/25 was for test to occur at 3pm on 8/26. Coil Tubing Unit(CTU)was not ready for the BOPE test upon Inspector's arrival. After spending time visually inspecting Aurora wells in the vicinity while waiting for the CTU to get ready, our Inspector was told the CTU would not be ready for BOPE test until the next day. Aurora's representative on the NCU#10 job was instructed to contact the Inspector for witness opportunity when BOPE was ready—no contact was made. Please provide the following for the above-noted coil tubing work on NCU#10: 1) Well Service Reports; 2) Daily Reports; 3) BOPE Test Report and test charts Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information. The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Jim Regg at 907- 793-1236 or jim.regg@alaska.gov. 2 STATE OF ALASKAP OIL AND GAS CONSERVATION COMMISSION �eiIlot 14 BOPE Test Report Submit to: jim.reqqalaska.qov AOGCC.InspectorsCa)alaska.gov phoebe.brooks@alaska.qov Contractor: BJ Coiltech Rig No.: J195 - DATE: 8/28/14 ' Rig Rep.: Marty Martin Rig Phone: Operator: Aurora Gas Op. Phone: 907-632-0583 Rep.: Jon West E-Mail jbwest@q.com Well Name: NC#10 PTD# 2101270 Sundry# N/A Operation: Drilling: Workover: X • Explor.: Test: Initial: X ' Weekly: Bi-Weekly: Test Pressure(psi): Rams: 250/4500 Annular: N/A Valves: 250/4500 - MASP: 4500 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen. P . Well Sign P Upper Kelly 0 NA Housekeeping P • Rig NA Lower Kelly 0 NA PTD On Location P Hazard Sec. NA Ball Type 0 NA Standing Order Posted P Misc. NA Inside BOP 0 NA FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 1 1.50 P - Trip Tank NA NA Annular Preventer 0 NA Pit Level Indicators NA NA #1 Rams 1 Blinds P Flow Indicator NA NA #2 Rams 1 3 1/16 Cutter NA Meth Gas Detector NA NA #3 Rams 1 3 1/16 Slips NA H2S Gas Detector NA NA #4 Rams 1 3 1/16 T Rams P MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln.Valves 2 2" P Inside Reel valves 2 - P ' HCR Valves 0 NA Kill Line Valves 2 2" P Check Valve 1 1.5" P - ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure(psi) 2700 • P - CHOKE MANIFOLD: Pressure After Closure(psi) 2700 P Quantity Test Result 200 psi Attained(sec) 3 . P , No.Valves 5 P Full Pressure Attained(sec) 17 - P . Manual Chokes 1 P Blind Switch Covers: All stations Yes Hydraulic Chokes 0 NA Nitgn. Bottles Avg. (#and psi): 2 @ 1300 P • CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 0 Test Time: 1.5 Hours Repair or replacement of equipment will be made within days. Notify the AOGCC of repairs with written confirmation to:AOGCC.Inspectors@alaska.gov Remarks: Test was delayed from original notice and AOGCC inspector was not notified AOGCC Inspection 24 hr Notice Yes Date/Time Waived By Test Start Date/Time: 8/28/2014 9:09 (date) (time) Witness Test Finish Date/Time: 8/28/2014 10:21 Form 10-424(Revised 06/2014) J195 BOP 8-28-14(2).xlsx 0 • - 0 cm (33 cv .... to_ ---"' = an .:C 0 CD o . . z .a 1- 0 . ..._ _ C\I - I 0 • . 0 (I) 1 0 < i 0 , • • . . •r•- c,) Jo . . 0 v..... 1 * ' (/) (.) CD ,0111•14 > Z al I tit > 0 i L% a) MIMI le, CU 0 o E ...., c‘i •MY Cr; co a * • C z CI) 11X 0 VI I'''' LI M • • (I) ••••• C/) < 0 0 — CC .1--------- > CO E C‘i Ea. cz CO --I 0) z ti,tto 2 cf) ) o 0 0. . a... ...:1 I I.D. ..1 ..v Z . . ..1.j_ CO _cs4 ca i... 1 1 0 2 :3: 0 (-1 CO 1 0. • ) i .... .0 ir- Iti to , L 0 tt ... ..... 4) IX cn 2 = .• L.„ 0 mEakE t o o E it 1 0 -... 1 o .1 a .,c) t4 Tu• 1 I 45: CO 0 Z s. 0 1 0 • • IA , 0 si 0 0 Luegi 1 o a WED o o" ...4ease o o 0 ..c en= i 41 M (isd) SS31:id HM (Isd) SS31:Id di/Virld t JC (13 gel CO • • Nicolai Creek #10 Coil Tubing Clean Out Operations Summary August 27, 2014 Move coil unit, crane,tiger tanks and man lift to NC 10 Nipple up BOP's&rig up circulating iron August 28, 2014 06:00—09:00 Continue rig up Haul water to clean water tank Prime pump truck Function test BOP's 09:00— 10:30 Test BOP's&circulating equipment Good test 10:30— 11:30 Set stripper on well—fill coil—test well head connection 11:30-15:00 RIH pumping 0.75bpm—Check drag where necessary—Work past SS at 2,191 down to 2,500 Good returns 15:00—16:00 Pull up to 1,875 and move pipe up 25' every 10 min. 16:00— 17:30 Wash down and tag PX plug—Sweep tubing&retag—Circ. Hole clean 17:30— 18:30 POH—rig down stripper, secure equipment and make room for Pollard 18:30-22:30 Rig up Pollard slick line unit RIH and pull prong @2,739' RIH—latch on to plug and make several attempts to pull POH—Cut off some slick line&make up heavier tools RIH—make several attempts to pull plug—No luck POH and rig down equipment. August 29, 2014 06:30—08:30 Start equipment—Safety Meeting Rig up to injector—Tool up coil—Set injector on Well Shell test low/HI on tree 8:30— 11:30 Fill coil Wash down to plug@ 2,724' while waiting on Pollard hammer unit • I 11:30— 17:00 Rig up Pollard's hammer Tighten up flow cross on top of tree RIH latch onto plug @ 2,739' Pull plug RIH with LIB tagged 200' early Switch to slick line unit 17:00—24:00 RIH with brush,went to 3,466' RIH with LIB—2.25"tagged—RIH with 2"—unable to get by Expansion Jt. @2,513' RIH and latch on to screen assembly—unable to pull screen-Continue trying August 30, 2014 00:01 —05:00 Able to pull free POH fish or tools—hung up at SS @ 3,279, able to pull trough Hung up in SS @ 2,739' after several attempts to pull free noticed lubricator head was froze Working on thawing head out, Shut wire rams and pump methanol in above rams—open rams Work through SS as well as at 2,191' & 1,992' POH with packer Rig down Pollard Hammer Unit and secure well. 06:20—07:30 Safety meeting—start equipment Lift injector and tool up coil Set injector on well head and shell test Open well—Well head pressure 1150 psi 07:30— 10:30 RIH with pump on line 0.25 bpm At 2,400' raise pump rate up to 0.75 bpm Wash down top of screens—Circ. Hole clean and POH 10:30— 11:00 Rig down and secure well for Pollard WH pressure 10 psi 11:30— 14:30 Rig up Pollard slick line unit-RIH&bait screens,rig up 6 sections of lubricator in case screens came out after 3 tries we were able to latch up to screens-could not pull screens—had a hard time getting screens but was finally able to do so—rig down and secure well August 31,2014 06:00-8:00 Start equipment—Safety Meeting Rig up to injector—Make up extra risers for fishing tools—Tool up coil Set injector on Well Shell test connections Open Well— 1100 psi 8:00— 10:30 RIH—wash down to top of fish—POH&shut in • • 10:30-11:00 Pull injector off—change BHA over to fishing tools Pressure test tools Set injector on well head 11:00— 15:00 RIH tag fish—work string—retag POH—take off injector—No Fish—MU injector-RIH Tag fish—PU 25' run back in—tagged up 4' higher—set down on fish POH—no fish—just bait sub Swing injector out of the way for Pollard 15:00— 19:00 RU Pollard slick line to RIH to set bait sub—POH—Bait sub covered w/sand RIH to close SS above fish @ 3,486'—POH—SS did not close RIH for 2nd attempt—Hit Bridge @ 3,460' and got blown up hole 100'+- POH—lost wt @ 1,000'—POH—lost tool and 24' wire MU fishing tools—RIH—retrieve 2' wadded up wire- 2nd run retrieve wire and tool—Tool showed some hit marks RIH to tag screen to make sure it did not come up with us PUSH SCREEN TO 3,514' September 1, 2014 06:00— 10:00 Start equipment—Safety Meeting Rig up to injector—Tool up coil w/circulating nozzle—Set injector Shell test low/HI on tree Fill coil wash down to top of screen 3,425' Circ.hole clean—work pipe while circulating POH with CT-shut in well-Set back injector-Well head pressure 1150+- Stand by for Pollard wire line work 10:00— 17:30 Rig up Pollard slick line RIH w/bait sub—POH—no indication on tool face of being on fish-still showing a lot of sand PU Bailer RIH came out full of sand PU larger bailer but would not pass through bad spot at 114' RIH to close sliding sleeve—running tool did not shear,indicated sleeve was shut—pressure would not bleed down RIH w/bailer—Cut 2"POH, end of bailer was dinged up from hitting top of fish RIH w/smaller OD bailer and made some more hole RU spear w/grappler—RIH and tag up on fish—pull on fish several times before it started moving uphole POH w/fish Close bottom valve on well head and break down fish Top screen had 3/4"washed clear through both sides 18"from the top of screen Blast joint had been washed on and through right in the middle of the joint—bottom screen look new RD Pollard 17:30—23:00 RU BJ coil for clean out run.—Shell test connections—RIH—pumping 0.75 bpm. N2 on line at 2,850'—wash down to 3,758'—sweep pipe-CBU x3 POH off bottom slowly to make sure hole is clean. POH up to 2,950'—shut down water and raise N2 to clear well and tubing— Pull up into well head and shut in well—blow surface lines—set back injector Rig down cables and hoses—clean up location. • September 2,2014 06:00— 12:00 ND BOP's RD coil and prepare to demob RU Pollard slick line RIH w/brush while BJ pump injecting water-POH RIH set first stage of plug RIH set plug at 3,400' 12:00— 17:00 BJ pump pressure up on well as Pollard RIH and opened SS at 3,279' POH and rig down—well head 450 psi RD Pollard AURORA IA/I'LL SERVICE REPO PT Date: 8/28/2014 Well Number: NICOLAI CREEK#10 Wireline Company: Pollard Wireline Inc. Location: WEST SIDE Work Being Done: PULL PX PLUG AFE# I Charge Code: CHUCK MIKE F. CODY W. Present Operations: ON GOING Wireline Crew: JASON Supervisor: JOHN WEST Total Wireline Miles: 3 Wireline Unit Number: BELUGA Max Depth (KB): 2736' Zero Wireline at: Tubing Hanger Well KB: 14' Minimum Tubing ID: 2.31 Max Tool OD: 2.25 Time Operation Details Inspect Unit M/T 6:00 STANDBY FOR COIL 18:00 RIG UP SL 19:20 RIH W/2" JDC TO 2735' WLM W/TOOL POOH W/ PRONG 20:00 RIH W/2.5" GS TO 2736' WLM W/TOOL SEVERAL JAR LICKS WOULD NOT PULL FREE SHEAR OFF POOH CUT WIRE RE HEAD 22:40 RIH W/ SAME W/ EXCELLERATOR JARS 2736' WLM W/TOOL SEVERAL JAR LICKS WOULD PULL FREE SHEAR OFF POOH DISCUSS W/JOHN 23:59 RIG DOWN SL UNIT CLEAN AREA SECURE WELL FOR NIGHT Tool Cost: 2" JDC $94.00 3 MAN CREW $3240.00 2.5" GS $187.00 6 ADD HRS. $1410.00 EXCELL JARS $450.00 Work String Detail: 1.75" RS EXCELL J STEM OJ LSSJ 6" 4' 10' 3' 7' Description of any NONE tools or debris left in the hole: Brief Summary of PULL PRONG ATEMPT TO PULL PLUG @ 2736' WLM Total Work Completed: I Total Hours Worked 18 Total Tool Cost $731.00 Total Hour Cost $4,650.00 Ticket# : P-878 Day# : Daily Cost: $5,381.00 Cumulative Cost: Well Downtime Hr. H2S PPM Wire Test Approved by: Code: AURORA W LL SERVICE REPO PT Date: 8/29/2014 Well Number: NICOLAI CREEK#10 Wireline Company: Pollard Wireline Inc. Location: _ WEST SIDE Work Being Done: PULL PX PLUG AFE# / Charge Code: Present Operations: ON GOING Wireline Crew: CHUCK MIKEF. CODY W.JASON Supervisor: JOHN WEST Total Wireline Miles: Wireline Unit Number: HAMMER Max Depth (KB): 2736' Zero Wireline at: Tubing Hanger Well KB: 14' _ Minimum Tubing ID: 2.31 Max Tool OD: 2.26" Time Operation Details Inspect Unit M/T 7:00 STAND BY FOR HAMMER UNIT AND COIL 12:00 RIG U THE HAMMER 14:00 RIH W/2.5" PR TO 2736' WLM LATCH W/TOOL 5 JAR LICKS CAME FREE POOH W/ PLUG 15:30 RIH W/2.26" LIB TO 2520 WLM SIT DOWN W/TOOL WOULD NOT FALL POOH 16:00 RIG DOWN HAMMER RIG UP SL 17:30 RIH W/ BRAIDED LINE BRUSH TO 3466'WLM TAG POOH 18:10 RIH W/2.26" LIB TO 2515' WLM W/TOOL WOULD NOT FALL POOH 18:40 RIH W/2" LIB TO 2515' WLM W/TOOL WOULD NOT FALL POOH 19:10 LAY DOWN SL RIG UP HAMMER 20:30 RIH W/2.5" PR W/2 7/8" PARAGON PULLING TOOL TO 3472' WLM LATCH PACKER W/TOOL 2 JAR LICKS SLIPPED OFF WOULD NOT LATCH POOH HUNG UP @ 2192' WLM W/TOOL SWAB HEAD ICED UP HOLD BIND STAND BY FOR METHYNOL 23:59 CONTINUE NEXT DAY Tool Cost: 2.5" PR $188.00 3 MAN CREW$4935.00 2.26" LIB $94.00 5 ADD HRS. $1375.00 2" LIB $94.00 BRAIDED LINE BRUSH $68.00 EXCELL JARS $450.00 Work String Detail: 1.75" RS EXCELL J STEM KJ OJ LSSJ KJ 6" 4' 10' 8" 4' 7' 8" Description of any NONE tools or debris left in the hole: Brief Summary of PULL PLUG @ 2736'WLM Total Work ATTEMPT TO PULL PACKER ASSEMBLY Completed: I Total Hours Worked 17 Total Tool Cost $894.00 Total Hour Cost $6,310.00 Ticket# : P-879 Day# : Daily Cost: $7,204.00 Cumulative Cost: Well Downtime Hr. H2S PPM Wire Test Approved by: Code: AURORA W LLSERVICE REPO Date: 8/30/2014 Well Number: NICOLAI CREEK#10 Wireline Company: Pollard Wireline Inc. Location: WEST SIDE Work Being Done: PULL PACKER AFE# I Charge Code: CHUCK MIKE1-. CODY W. Present Operations: ON GOIN Wireline Crew: JASON Supervisor: JOHN WEST Total Wireline Miles: 2 Wireline Unit Number: HAMMER Max Depth (KB): 3488' Zero Wireline at: Tubing Hanger Well KB: _ 14' Minimum Tubing ID: 2.31 Max Tool OD: 2.7" Time Operation Details Inspect Unit M/T 0:01 STAND BY FOR METHYNOL FOR ICED UP SWAB HEAD 3:30 W/TOOLS FREE POOH HUNG UP © SLIDING SLEEVE @ 1992' W/TOOLS THROGH POOH W/ PARAGON PACKER DISCUSS W/JOHN 6:00 LAY DOWN LUB SECURE WELL FOR COIL 6:30 ARRIVE CAMP STAND BY FOR COIL 11:00 RIG UP SL 12:00 RIH W/2.5 PR W/ PACKER PULLING TOOL TO 3488'WLM W/TOOL SET SEVERAL JAR LICKS WOULD NOT COME FREE SHEAR OFF POOH DISCUSS W/JOHN 14:00 LAY DOWN SL CLEAN AREA SECURE WELL FOR COIL 15:00 PUT WELL HOUSE BACK ON NICOLAI CREEK#11 16:00 ARRIVE @ CAMP Tool Cost: 2.5 PR $188.00 3 MAN CREW 12HR. MIN $4935.00 EXCELL JARS $450.00 4 ADD HRS. $1100.00 Work String Detail: 1.75" RS EXCELL J STEM KJ OJ LSSJ KJ 6" 4' 10' 8" 4' 7' 8" Description of any NONE tools or debris left in the hole: Brief Summary of PULL PARAGON PACKER © 3488'WLM Total Work Completed: I Total Hours Worked 16 Total Tool Cost $638.00 Total Hour Cost $6,035.00 Ticket# : P-880 Day# : Daily Cost: $6,673.00 Cumulative Cost: Well Downtime Hr. H2S PPM Wire Test Approved by: Code: . _. _. .. 0 0 • .,7 1 4 I • 111%, :‘, ... 1 .... 1 ,a4t....\, '1 • '•1 .,-- t-A i v • ' y-4 11 a.) a) 0--• a %1 1 k " 1 CC 4.- 0 N, lit t * • I hp,: ,'.4 .,.. u..... M / * * 1 ILI V A N 1 1-- N . Z Lr , t.-c-1.--- 1 i , ILI 0 I 3,9,V al i II M,.'"' LL 0-,-, Ii F.- 32.9 = 12 < CC 2 9 • 4. LLI = 2 0- '1-1.)"1 - i ailapi_ _ ,,,,,0_,,,, ,,,„ ,,, ore i 1,4 ors_ -'. Lot • , 1 , / Cr -I tr.— I— 1 1 („D Po cf) fr , I- 1.-- Z I t LU (2 M. 2 - „ — i IN 93 CV, = VI. n 0 ul n 1-- , , 0 r ..... H ILI , ,.., z 1 < 0 - , 1 0 11. 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Q 4, 42, 8 Ei a CL 0 L 1-05 saws. , asm c-.,....r ,.—.-.--..._ ` - c.)mw. �III ` ill 3i y Cf u9 ti i... X0.. 0 t r ' „ .C'y S`s s J x 1 r ..., . . . 411• . -i , At . Q 0..11. Al f� w hi, 'igm tt <,..) Ta.,1-,p,.ill a 41 11 %Ili 4,4' 1.„` *4, ..., A .j�� . 5 t ui A • 4..� 0 '.4,'. �" " `+ Iii — - a > 0 M .►C1 ,1 Aurora Gas LLC www.aurorapower.com DATA LOGGED 7 /\9 /2013 M K BENDER July 5, 2013 Makana Bender Natural Resource Technician Alaska Oil and Gas Con. servµtio Cnru mission 333 W. 7 h Ave., Suite 100 Anchorage, Alaska 99501 RE: Well Data Submittal, Nicolai Creek No. 10 RECEIVED JUL 10 2013 Aurora Gas, LLC has included in this package the following documents and electronic files for Alaska Oil and Gas Conservation Commission for the Aurora Gas LLC Nicolai Creek #10 Well, API# 50-283-20145-00. Please keep this information contained here -in "C Di?+ HIMEN 11AL" for 2 -years. Paper Logs (Confidential 2 -years) 1) Hallibm-ton Perforatin- Record s Electronic Documentation (Confidential 2 -years) 2) Halliburton Perforating Record, LAS Data If you have any questions or require additional information, please contact me or Ed Janes at (907) 277-1003. Sincerely, AURORA GAS, LL George Pollock Manager — Production Operations & Engineering enclosures 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 THE STATE Alaska Oil and G&s OIALASKA CGaservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 George Pollock Manager — Production Operations & Engineering Aurora Gas, LLC 1400 W Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Nicolai Creek Field, North Undefined Gas Pool, Nicolai Creek #10 Sundry Number: 313-138 Dear Mr. Pollock: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P oerster Chair DATED this &) day of March, 2013. Encl. �- STATE OF ALASKA ��`. jolk O�` 3 "T"I I I ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Time Extension (� Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Aurora Gas, LLC Exploratory ❑ Development Ell 210-127 3. Address: Stratigraphic ❑ Service ❑ 6. API Number: 1400 W Benson Blvd, Suite 410, Anchorage, AK 99503 CA moo 'V%4 AG nn A^ . ^rr•-�� �rr••��••�•• •� .au •�• .c nwnuu irvm me uaie or appy var. Atta n yD plicate �w 1� 3.2 C � [3 .� p/�3 v�`� 7. If perforating: 11 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 635A.000 - Nicolai Creek #10' Will planned perforations require a spacing exception? Yes ❑ No El 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL -63279 Nicolai Creek Unit/North Undefined Gas, 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): • 4,830' 4,438' , 3,950' 3,645' none none Casing Length Size MD TVD Burst Collapse Structural Conductor 94' 13-3/8" 94' 94' 1,530 psi 520 psi Surface 654' 9-5/8" 654' 654' 3,520 psi 2,020 psi Intermediate Production 4,805' T' 4,805' 4,409' 4,270 psi 3,120 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 2,688-2,698'; 2,825-2,830; 2,523'-2,531; 2,643-2647'; 2-7/8" J-55 3,838' 3,319-3,331'; 3,510-3,530'; 3,080-3,091'; 3,251-3,269'; 3,856-3,866' 3,561-3,570' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 3 X HES PHL Packers & Arrowset 1X Mechanical HES PHL @ 2,582'(2,420'), 3,240'(3,001') & 3,389'(3,130'); Arrowset @ 3,767'(3,472') 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work: Detailed Operations Program ❑✓ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑✓ • Service ❑ 14. Estimated Date for 25 -Mar -13 15. Well Status after proposed work: Commencing Operations: Oil R Gas Q WDSPL ❑ Suspended ❑ WINJ 0 GINJ F1 WAG ❑ Abandoned [�] 16. Verbal Approval: Date: Commission Representative: GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact George Pollock Email goollockCcDaurorapower.corn Printed Name George Pollock Title Manager - Production Operations & Engineering Signature Phone (907) 277-1003 Date 15 -Mar -13 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: —, Svc) p "OLAS MAR 21 2013 Spacing Exception Required? Yes ❑ No Subsequent Form Required: /0 —,qCaq APPROVED BY Approved by: Qom' COMMISSIONER THE COMMISSION Date: J� —j _ ^rr•-�� �rr••��••�•• •� .au •�• .c nwnuu irvm me uaie or appy var. Atta n yD plicate �w 1� 3.2 C � [3 .� p/�3 v�`� :-� Aurora Gas, LLC March 15, 2013 Cathy Foerster, Chair State of Alaska Oil and Gas Conservation Commssion 333 W. 7h Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Sundry Approval Nicolai Creek #10 Well Cement Squeeze / Perforate / Production Dear Ms. Foerster: RECEIVED MAR 15 2033 AOGGC Aurora Gas, LLC (Aurora) hereby requests approval to allow the proposed cement squeeze, perforations and subsequent production from certain stratigraphic intervals for the Nicolai Creek #10 well and the Nicolai Creek Unit North Undefined Gas field on the west side of Cook Inlet. Attached is the Application for Sundry Approvals. Specifically, Aurora seeks permission to cement squeeze perforations at 3,510' — 3,530' and 3,319' — 3,331'; reperforate at 3,512' — 3,532' (and potentially 3,326' — 3,332' based on test results); and perforate at 2,235' — 2,245' and 2,149' — 2,156'. These actions will allow production from the Carya 2-4.2 (3,512') and Carya 2-4.1 (3,326') sands and add new production from the Carya 2-1 (2,235' & 2,149') sands. Accompanying the Sundry Application is supporting well and engineering data, which include the well completion diagram and the proposed perforation and testing procedure. Should questions arise in connection with this request, please contact either myself in the Anchorage office at (907) 277-1003 or Mr. Ed Jones in the Houston office at (281) 495- 5799. RespectfUlly Submitted, eor;Pollock Manager — Production Operations & Engineering Attachments 6051 North Course Drive, Suite 200 * Houston, TX 77072 * (281) 495-5799 * (281) 495-1473 1400 W Benson Blvd, Suite 410 * Anchorage, AK 99503 * (907) 277-1003 * (907) 277-1006 AURORA GAS, LLC RIG CLEANOUT/SQUEEZE/REPERF WORKOVER PROCEDURE NICOLAI CREEK UNIT #10 April 2013 Version 1.1 CURRENT CONDITONS: k^.h5� Max SITP-1240 psi or less, below Pack -off at 3441'). KB=14.7 feet CASING: 7" 23# K-55 (to 2560') & 26# L-80 set at 4805'MD/4409' TVD. TUBING: 4' 3-1/2" pup at Surface with 3-1/2" tree; crosses over to 2-7/8", 6.5# J-55 8 rd EUE, with chemical injection sub at 2512' (w/ external 1/" SS tubing to surface) and with Sliding Sleeves at: WXA at 2547' (packer fluid -closed); WXO at 2741' (Open): WXO at 3354' (Open): Slip Stop at 3440' (WLM); Pack -off Plug at 3441' (WL); and AD -2 Stop at 3443' (WL); WXO at 3549' (Open & washed out and On -Off Tool w/ 2.313" X landing nipple at 3767' (with PX plug in place). Packers at 2582', 3240, 3389', 3767' (see attached well bore and completion diagrams) 2-7/8" expansion joint at 3,260'. EOT – 3838' CAPACITIES: 2-7/8" 6.5# Tubing: 0.00579 bbl/ft; Tubing -Casing Annulus: 0.0233/.0222 BPF; 7" 23# & 26# Casing: 0.0393/.0382 bbl/ft. Tubing volume to On -Off Tool=21.8 bbl, Annular Volume to top Packer= 59.8 bbl; to On -Off Tool= 86.3 bbl (bottoms up); Casing Volume to Arrowset Packer at 3767'= 146 bbl. PERFS: Carya 2-3 at 2688-98' & 2825-30' behind Sleeve at 2741' (400 psi SIP?) Carya 2-4.1 at 3319-3323' & 3326-3331' behind Sleeve at 3354' (as high as 1200 psi) Carya 2-4.2 at 3510-3530' behind Sleeve at 3549' (1100-1300 psi) Carya 2-5.2 at 3856-3866' below PX plug in On -Off Tool at 3767' (480 psi) NOTES: 1) Well is moderately deviated 26 deg average. 2) Well has been making sand. SUMMARY OF PLAN: Clean out with Coiled Tubing to Pack -Off, pull Pack -Off, cleanout with Coiled Tubing to On -Off Tool, release hydraulic packers, circulate out sand, release from On -Off tool, pull tubing with fishing as necessary, squeeze perfs at 3510-3530' and at 3319-3331', block squeeze/ circulate cement for shallower recompletion, drill out, reperf , add shallower perfs, re -run completion, swab in and test. PROCEDURE: 1) Pick and move wellhouse, be sure to disconnect methanol line before lifting wellhouse. 2) RU Pollard. SI well, RU lubricator—test to well pressure. RIH w/ 2.25 GR and tag fill (last found at 3169'). RIH w/ shifting tool and close sleeve at 2741'. RD Pollard. 3) MI and RU coiled tubing unit on Nicolai Creek Unit #10 with N2 unit, AG well test choke skid and AWS pit for flowback (or AG mud pit). RU with 3-1/2" EUE internal thread connection on tree cap to lubricator. Test lubricator to 2000 psi. 4) Run 1.50" or 1.25" coiled tubing and clean out sand (last tagged at 3189') to Slip Stop at 3440' WL (+/-3450' KB) with nitrified produced water. Monitor losses—none expected with sleeve at 2741' closed. 5) Unload well with N2 until it flows (from sliding sleeve at 3354')—flow test (to facility) to get 1 hour of stable flow on 12/64 to 18/64" choke—monitor gas rate and get good measurement of water (gauge tanks before and after flow). SI and allow to build-up for 1 hour or until pressure stabilizes to within 5 psi in 15 minutes. Call in results (mcfpd, FTP, BW, and SITP). 6) RIH w/ coiled tubing and tag bottom—clean out to Slip Stop again, if necessary. Report feet of fill. 7) RD coiled tubing lubricator and RU Pollard lubricator. Test to 2000 psi. RIH and pull Slip Stop at 3440' and Pack -Off plug and AD -2 Stop just below. RD Pollard... PL. SG p h4 --,f- 3i I i 8) RU CT lubricator and test to 2000 psi. RIH w/ CT and cleanout to PX plug in On -Off tool at 3767' with nitrified produced water. Circulate clean. Monitor losses—no serious losses expected; however, if severe, mix and circulate 20 bbl "Baraplug" LC pill (see Notes below). Leave wellbore dead with clean produced water, if possible. POOH with CT and RD CTU. Monitor well pressure. 9) If tubing pressure builds, RU Pollard, RIH and set PX plug in profile in profile just above sliding sleeve at 3354'. RD Pollard. Bleed off pressure to test plug. 10) Move in, rig up AWS #1 rig w/ single workover pit for mud system (not AG mud system) and support equipment only as needed for workover (one gen set, 1 mud pump, etc.). Also, move in and spot Aurora Gas choke skid, test unit, and flare and spooling unit for %" SS tubing (chemical injection line). 11) Starting with clean mud pit, mix 150 bbl (usable volume) 9.0 ppg 3% KCl -NaCl brine (3% KCl- 11#/bbl+ weight up with oilfield salt, 34#/bbl), using clean produced water from tanks on AG locations. 12) Set GE 2 -way check in hanger. ND tree, NU 3000 -psi BOPE. Test to 2500 psi (or as required by AOGCC Sundry approval). Pull 2 -way check—release GE. If PX plug was set in Step 9, RU Pollard and pull plug before next Step. 13) Screw into tubing hanger, and release hold downs. Then pull tubing and completion as follows (be prepared to cut tubing, as with sand production, 2-3 cuts will likely be required): a. Pull to release two hydraulic packers (approx 43,000# overpull) above expansion joint. Reverse circulate out any gas seen in casing. Monitor loses (depleted perfs at 2688-2830' now open). Mix and circulate 20 bbl "Baraplug" LC pill if needed (see Notes below) b. Pull (30,000" overpull) to release hydraulic packer at 3389'—may have sand on it. (If it won't release, will cut off tubing and wash over—Supplemental Procedure provided at that time Have wash pipe, shoes, and free point equipment on the West Side and on standby). Reverse Circulate out any gas. c. Release from On -Off tool at 3767'. (If it won't release, RU Pollard, close sleeve at 3354' and reverse circulate thru sleeve at 3549' to attempt to free it. May have to cut off tubing and wash over—Supplemental Procedure provided at that time). d. When packers and On -Off Tool are all released, reverse circ bottoms up (60 bbl) then until gas free, then POH, standing back tubing, spooling '/" SS tubing, and laying down packers and sliding sleeves. (If tubing is stuck or has drag, may want to have Pollard close sliding sleeves at 3354' [if not already closed] and 3549' and circulate thru On -Off tool O/S skirt). Strap out of hole and keep good records. Monitor hole and keep full. Expect some losses (and gas if hole not kept nearly full). e. Send packers and sliding sleeves in for expedited rebuilding. 14) PU drillable composite cement retainer and RIH on 2-7/8" tubing to just above 3460' (nearest joint of tubing at workable height above floor). Dump/circulate 2 sx (i.e., 2 cu. ft, 9'+) clean fine sand down tubing—allow to settle. Set retainer. Install head pin and valve and pump -in sub and valve. 15) RU cementers. Perform injectivity test into perfs at 3510-3530' w/ clean 3% KCl water. Pump 1 BPM for 2 minutes, 2 BPM for 2 minutes, and 3 BPM for 2 minutes (12 bbl), but keep pressure below 1000 psi (slow rate as necessary; if pressure reaches 1000 psi maintain rate for 2 minutes, unless less than 1 bpm—if less than 1 BPM, achieve rate and record pressure). Record ISIP. (Open surface and production casing valves and monitor during all pumping.) 16) Unsting from retainer. Cement as follows: A) Batch mix 10-12 bbl Class G cement (+/-50 sx at 15.8 ppg, 1.15 cf/sk) w/ defoamer, 0.7% BA -56 gas control, and accelerator (BHT estimated at 90-95 deg F). B) Pump w/ 2 bbl fresh water spacer ahead and behind and displace with 3% KCl water. Spot cement to near retainer (tubing volume to 3460' = 20.0 bbl, casing volume is almost 4 bbl/100'), sting into retainer. (Confirm w/ serviceman this plan to set, unsting, spot and sting into, rather than set retainer—either would work). C) Pump as much as to 9 bbl of cement into perfs, starting at 2-3 BPM with pressure below breakdown, as indicated by injectivity test (or less than 750 psi initially, increasing to 800 psi max after pumping 8 bbl displacement). Slow rate to 1/3 to % BPM as maximum pressure or 7 bbl is approached. LEAVE AT LEAST 2 BBL (50') OF CEMENT IN CASING BELOW RETAINER. D) Stop pumping when 800 psi is achieved. Hesitate for 5 minutes and repressure, 2-3 times. When pressure holds, pull out of retainer, pull one stand, and reverse out any remaining cement + 2 tubing volumes (20 bbl X 2 = 40 bbl). DO NOT RELY ON STRCTLY ON RIG PUMP STROKE COUNTER FOR DISPLACEMENT—USE CEMENTER TUBS OR TANK GAUGES TO CONFIRM. (Pressure increase during job should be about 200-300 psi due to negative hydrostatic differential of cement and displacement KCl water). , 17) POH w/ tubing and stinger. PU second composite cement retainer. RIH to +/-3265'. Repeat Steps �?' 12 and 13 above to squeeze perfs at 3319-3331'. 18) If perfs at 2688-2830' are taking significant fluid, squeeze each zone with 30 sx, setting retainers at �" 2750' and 2650' (second one after the first squeeze) and squeezing as per Steps 15-16 above. 19) POH w/ tubing and stinger. LD stinger. RU perforators and perforate to squeeze/circulate at 2350- fl� 52' and 2080-82' w/ 6 SPF (big holes, not deep penetration). 20) PU (3rd or 5`h) composite cement retainer. RIH and set at +/-2280'. a) Mix 110sx Class G cement with defoamer, gas control, and accelerator (BHT is 75 deg F); b) Pump 2 bbl fresh water spacer, 10 bbl mud -cleaner preflush, 1 bbl fresh water, 22.5 bbl cement, 1 bbl fresh water, and displace with 3% KCl brine. c) Monitor casing returns, and establish circulation between sets of perfs (into casing -tubing annulus). Circulate cement between perfs at 2350-52' and 2080-82'. Pump at high rate, 5- 10 BPM if pressures allow—displace cement with total of 14 bbl, leaving about 50' in casing below retainer. Pull above 2000', rev out 2 tubing volumes (23 bbl total), catching and isolating the 10 bbl of mud preflush (and all returns until clean). Pull 1 additional stand. Close annular and pressure casing to 500 psi and hold for 6 hours. 21) PU 6-1/8" bit, bit sub, X -O, and 4 4-3/4" DC', and X -O, RIH with 2-7/8" tubing to tag cement, expected at 2075'. Rev Circ bottoms up (12 bbl). After WOC minimum of 12 hours, drill out cement and retainers to sand above On -Off tool at +/-3757'—if cement is "green" wait another 4 hours, try again, repeat as necessary until cement is hard, then drill out thru all perfs and retainers to bottom. Pump Barazan high -vis sweep if not cleaning. Tag sand above of On -Off tool, pull one stand (i.e., leave sand in place until Step 23), and circulate hole w/ filtered 9.0 ppg 3% KCl/NaCl brine (and filter with sock filters, 25 then 10 micron filters while circulating). Monitor losses (if depleted perfs at 2688-2698' are still open). POH w/ tubing. Strap tubing on TOH to validate tally. LD bit and DC's. 22) RU perforators w/ lubricator. Run GR/CCL correlation log and correlate to Platform Express log of 9/8/11 and previous GR/CCL log of Sept. 2011. a) PU 20' 3-1/2" PowerJet Omega perforating guns, test lubricator to 1500 psi, and RIH to perforate 3512-32' w/ 6 SPF w/ 60 -deg phasing. Watch for gas, pressures, and fluid P level in casing while shooting. b) NOTE: if test of perfs behind sleeve at 3354' (Carya 2-4.1 sand with perfs at 3319- 3331') shows good gas rates and pressure and low water, we may reperf 3326-32' also with a second run. c) Perforate 2235'- 2242' d) Perforate 2149-561. e) POOH, LD perf guns, RD wireline. 23) PU casing scraper and bit and run thru new perfs, to tag sand at +/-3757'. Circulate sand off On - Off tool and circulate wellbore clean. 24) PU following completion BHA and RIH on 2-7/8" tubing, visually inspecting and replacing questionable collars or whole joints, as follows: a) On -Off tool OS/skirt, b) 2-7/8" pin X 3-1/2" box Cross-over c) 9 jts 3-1/2" tubing, d) 3-1/2" pin X 2-7/8" box Cross-over IV e) 2-7/8" Selecta-Flow shrouded Sliding Sleeve (Sand Control Screen with internal sliding sleeve) SpA to be set at +/-3485' f) 2-7/8" pin X 3-1/2" box Cross-over, g) 3 jts 3-1/2" tubing, h) 3-1/2" pin X 2-7/8" box Cross-over, i) Hydraulic -set packer to be set about 3385', J ) 2 Jts 2-7/8" tubing, k) If 3326-32' was reperforated, run 2-7/8" Shrouded sliding sleeve at about 3315', 1) 2-7/8" tubing, m) If intervals at 2688-2830' were not squeezed and if 3326-32' was reperforated, set Hydraulic Packer at about 3200' with expansion joint or shear -out safety connection a joint below; n) 2-7/8" tubing, o) If intervals at 2688-2830' are open, run Sliding Sleeve to 2750', p) 2-7/8" tubing, q) Hydraulic -set Packer to 2500' with shear -out safety connection 1 joint below, r) 2-7/8" tubing, s) Sliding Sleeve at 2200', t) 2-7/8" tubing, u) Hydraulic -set Packer at about 2100', v) 1 jt 2-7/8" tubing, w) XA sliding sleeve, x) 1 jt 2-7/8" tubing, y) Chemical injection sub w/ V SS tubing back to surface, and z) 2-7/8" tubing to surface (with X -O and 4' 3-1/2" pup on tubing hanger). JA 25) Latch onto On -Off tool. Space out, land tubing, and lock down.. Pressure test tubin to 2500 psi, then pressure up to set hydraulic packers (against existing plug in profile in on-off tool). rbleed off pressure. Install BPV. ND BOP. NU and test tree. Pull BPV. (Be rigging up AG test choke manifold, separator, and flare stack, connected with hardline during this time). 26) RU Pollard slickline unit and lubricator, test lubricator to 1500 psi. RIH w/ shifting tool and open sliding sleeve at 3485'. POOH. RD Pollard (but do not release to go to town, will have other work in field for them to do). 27) RU to swab and swab in Carya 2-4.2 perfs at 3512-32' and test thru test separator. Allow to cleanup. SI for 1 hr buildup. Open to flow and allow to stabilize at about 80% (or more) of SIM SI, and watch buildup for 1 hr. 28) RU Pollard. Test lubricator to tubing pressure. RIH and Set PX plug in highest X profile (in XA sleeve at +/-1970'. RD Pollard. Release rig and move to NCU 14 drilling location. 29) When rig is moved, RU Pollard. RIH and pull PX prong and plug. RIH and open sleeve to test next shallower completed interval (3326-32', 2688-2830', or 2150-2242') as in Step 27 above. Tubing s/b essentially dry so no swabbing should be needed, unless perfs are making water. 30) Repeat until all completed intervals are tested. RD Pollard. RD AG test equipment. Turn well to operators to reconnect flowline and put to sales thru 3-10 production facility. 31) If rates are lower than expected, will plan to acidize perfs (w/o rig) to clean-up cement damage. Ed Jones (3/14/13) Rev 3/15/13 NOTES: Mix 20 bbl saturated brine in very clean water, then use this to make 12 bbl pill of Baraplug (see notes at end of Procedure) and balance for spacer. Spot Baraplug pill across perfs at 2600-471, precede w/ 5 bbl saturated brine spacer and followed by 3 bbl saturated -brine spacer. (Displace Baraplug to 3100' w/ 3 bbl saturated brine + 15 bbl 6% KCl -NaCl brine.) BARAPLUG Perf Pill (Note: Barazan can be substituted for N -Vis, but it is dirtier). Product Concentration Saturated NaCl Brine 0.83 bbl BARADEFOAM HP 0.1 ppb or as needed Citric Acid 0.5 ppb N -VIS 2 ppb or as needed for 35 YP DEXTRID 4 ppb KOH As needed pH 9.0 BARAPLUG 50 50 ppb NaCl (Salt) 10 ppb ALDACIDE G 0.25 ppb 3% KCI Saturated NaCl brine: 0.888 bbls Water+11 ppb KCI+98 ppb NaCl Saturation will be a 9.9+ ppg MW NICOLAI CREEK Y '= UNIT #10 yr= Hydraulic Packer (a, 3240' PTD#:210-127 API#: 50-283-20145-00-00 .z . RKB 14.7ft AD -2 Stop at 3440' WL w/ Pack -off 7 :" (Jan. 2013).'. Plug and Slip Stop below ` Sliding Sleeve @ 3354' WXO, Drill 12-1/4" Hole to 678' 2.312 X Profile (Open) Hydraulic Packer @ 3389' 3yy 1 " ° 2-7/8" x 7" annulus displaced _ with 9.3ppg inhibited packer fluid g. Carya 2-3 2688-2698' (2523-31' TVD) 2825-2830' (2643-47' TVD) Carya 24.1 3319-3323' 3326-3331' (3080-3091' TVD) Perforated 3467-3472' squeezed with 10bb1 of 15.8ppg cement Carya 2-4.2 S�� t 3510-3530' (3251-69' TVD) PBTD @ 3950' MD (3645' TVD) Drill 8-112" Hole to 4830' MD, 4438' TVD avg deviation 26deg, KOP 900' Carya 2-6 3856-3866' (3561-70' TVD) 3-1/2" (9.3#) 8rd EUE L-80 �� Tubing, Oft pap ' 1171 2 7/8 6.5# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 94' GL ia..,., 9-5/8" 40 & 36# Surface Casing set at 654' Cement w/12. ppg Type I Accelerated a� Chemical Injection Sub, 2-7/8" 8rd EUE, '/4" apt connection, 1/4" S.S. tubing, @ 2512' w/2way check Sliding Sleeve @ 2547' WXA, 2.313 X Profile tclosedl Hydraulic Set Packer @ 2582' Sliding Sleeve @ 2741' WXO, 2.312 X Profile (Open) Fill left at 3169' WL 01/2013 yr= Hydraulic Packer (a, 3240' Expansion joint @ 3260' AD -2 Stop at 3440' WL w/ Pack -off Plug and Slip Stop below ` Sliding Sleeve @ 3354' WXO, 2.312 X Profile (Open) Hydraulic Packer @ 3389' 3yy 1 " _ Sliding Sleeve @ 3,549' WXO, 2.313 X Profile (Open, washed nnt) X ? E On -Off Seal Nipple w/ skirt 2.313 X -profile w/ PX plug ' Arrowset 1X Mechanical Packer @ 3767 Et7T n 3838' 7" 23# K-55 & 26# L-80 Casing to 4805' MD/ 4409' TVD Aurora Gas, LLC 3-1/2" (9.3#) 8rd EUE L-80 Tubing, 4ft pup NICOLAI CREEK 2 7/8 6.5# 8rd EUE J-55 Tubing UNIT #10 , 13-3/8" 68# Structural PTD#• 210-127 Conductor driven to 94' GL API#:50-283-20145-00-00 RKB 14.7ft Drill 12-1/4" Hole to 678' 9-5/8" 40 & 36# Surface Casing set at 654' 2-7/8" x 7" annulus displaced Cement w/12, ppg Type I Accelerated with 9.3ppg inhibited packer fluid r .P Chemical Injection Sub, 2-7/8" 8rd EUE, V4" opt connection, 1/4" S.S. tubing, @, 2512' w/2way check Sliding Sleeve @ 2547' WXA, 2.313 X Profile (closed) Hydraulic Set Packer @ 2582' Carya 2-3 2688-2698' (2523-31' TVD) r Sliding Sleeve @ 2741' WXO, 2.312 X Profile (Open) 2825-2830' (2643-47' TVD) Fill left at 3169' WL 01/2013 Hydraulic Packer @ 3240' Carya 24.1 Expansion joint @ 3260' 3319-3323' AD -2 Stop at 3440' WL w/ Pack -off 3326-3332' Plug and Slip Stop below (3080-3091' TVD) Sliding Sleeve @ 3354' WXO, 2.312 X Profile (Open) Perforated 3467-3472' squeezed Hydraulic Packer @ 3389' with 10661 of 15.8ppg cement (2011) Carya 2-4.2 Sliding Sleeve @ 3,549' WXO, 3510-3530' 2.313 X Profile (Open, washed (3251-69' TVD) outl On -Off Seal Nipple w/ skirt 2.313 X -profile W/ PX plug Carya 2-6 Arrowset 1X Mechanical Packer @ 3767 ' PBTD 3950' MD @ 3856-38661 (3645' TVD) (3561-70' TVD) EOT @ 3838' 7" 23# K-55 & 26# L-80 Casing to 4805' MD/ Drill 8-1/2" Hole to 4830' MD, 4409' TVD 4438' TVD avg deviation 26deg, KOP 900' Aurora Gas, LLC NICOLAI CREEK UNIT #10 PTD4. 210-127 API#: 50-283-20145-00-00 RKB 14.7ft Drill 12-1/4" Hole to 678' 2-7/8" x 7" annulus displaced with 93ppg inhibited packer fluid Carya 2-1 2149-2156" _ (1944-2001' TVD) 2235-2242' (2080-2087' TVD) I Carya 2-3 2688-2698' (2523-31' TVD) 2825-2830' (2643-47' TVD) Carya 24.1 3326-3332' (3080-3091' TVD) squeezed 3319-3331 Perforated 3467-3472' squeezed with I Obbl of I 5.8ppg cement 0 Carya 2-4.2 3512-3532' (3251-69' TVD) squc, PBTD A 3950' MD (3645' TVD) Drill 8-1/2" Hole to 4830' MD, 4438' TVD avg deviation 26deg, KOP 900' Carya 3856-386666' (3561-70' TVD) 3-1/2" (93#) 8rd EUE L-80 Tubing, 4ft pup 2 7/8 6.5# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 94' GL 9-5/8" 40 & 36# Surface Casing set at 654' Cement w/12. ppg Type I Accelerated + Chemical I ti nJec on Sub, 2-7/8 8rd EUE,'/," opt connection, 1/4" S.S. tubing, A 1980' w/2way check i Sliding Sleeve A 2100' WXA, 2313 X Profile (closedl Sliding Sleeve A 2200' WXA, 2.313 X Profile telosedl Hydraulic Set Packer A 2500' Sliding Sleeve A 2750' WXO, 2.312 X Profile (Open) Hydraulic Packer (0 3200' Expansion joint A 3260' AD -2 Stop at 3440' WL w/ Pack -off Plug and Slip Stop below + Sliding Sleeve A 3315' WXO, 2.312 X Profile (Open) Hydraulic Packer A 3385' 't Selecta-Flow shrouded Sliding Sleeve A 3,485' (Open) On -Off Seal Nipple w/ skirt 2.313 X -profile W/ PX plug Arrowset 1X Mechanical Packer A 3767 EOT A 3838' 7" 23# K-55 & 26# L-80 Casing to 4805' MD/ 4409' TVD . Aurora Gas, LLC NICOLAI CREEK UNIT #10 PTD#: 210-127 AP1#:50-283-20145-00-00 RKB 14.7ft Drill 12-1/4" Hole to 678' 2-7/8" x 7" annulus displaced with 9.Oppg inhibited packer fluid Carya 2-1 2149-2156" (1944-2001' TVD) Perfs at 2080-82' & 2350-52 for circ 110 sa Cement 2235-2242' (2080-2087' TVD) Carya 2-3 2688-2698' (2523-31' TVD) 2825-2830' (2643-47' TVD) Carya 24.1 3326-3332' (3080-3091' TVD) �queczcd 3319-3331 Perforated 3467-3472' squeezed with I0bbl of 15.8ppg cement Carya 2-4.2 3512-3532' (3251-69' TVD) squ, PBTD @ 3950' MD Carya 2-6 (3645' TVD) 3856-3866' (3561-70' TVD) Drill 8-1/2" Hole to 4830' MD, 4438' TVD avg deviation 26deg, KOP 900' 3-1/2" (93#) 8rd EUE L-80 Tubing, 4ft pup 2 7/8 6.5# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 94' GL 9-5/8" 40 & 36# Surface Casing set at 654' Cement w/12. ppg Type I Accelerated Chemical Injection Sub, 2-7/8" 8rd EUE, '/49' npt connection, 1/4" S.S. tubing, @ 2030' w/2way check Sliding Sleeve @ 2065' WXA, M' 2.313 X Profile (closed) Hydraulic set Packer at 2100' Sliding Sleeve at 2200' Hydraulic Set Packer @ 2500' ` Sliding Sleeve @ 2750' WXO, 2.312 X Profile (Closed) s Hydraulic Packer @ 3200' Expansion joint @ 3260' X -profile Shrouded Sliding Sleeve @ 3315' WXO, 2.312 X Profile Hydraulic Packer @ 3385' Selecta-Flow shrouded Sliding Sleeve @ 3,485' (Open) On -Off Seal Nipple w/ skirt 2.313 W/ PX plug Arrowset 1X Mechanical Packer @ 3767 EOT @ 3838' 7" 23# K-55 & 26# L-80 Casing to 4805' MD/ 4409' TVD Aurora Well S, mice Rig No. l: Proposed 3M BOi- configuration A/'/ COL,41 C,ecck. (jA1/T Fill Up Line 1 1'3M l Mud Crass j j i 3" SM Manual Valve (Kill Line) L—��LfL 3" SM Hydrauiac: Valve (Kill Line) Fluid flow direr;tion�' while reverse circulating 18.75" w (30.00") H 2-7/8" OD Aurora Weil Service BOUI Bell Nipple with flow line to pits Pipe Rams sized 1 to work string. Blind Rams 3M Schaffer Annular Presenter 11" 3M Double Gate w/ 3/12" pipe rams installed - –' _3" 5M Manual Valve (Choke Line) �// 3" 5M Hydraulic Valve (Choke Line) 11 5,000 SSS 1 13-3/8" OD CSG ' 9 OD CSG T OD CSG Dravring Not to Scate Aurora Well Service JZig No. I Proposed Choke / Kill Manifold Configuration All -vahjes are 3" rated at 5000 psi. Inlet from Output to Pits Power Swivel (Reverse Circulation Mode) I" 2" 5M Rated Valves Hydraulic Remote Activated choke I [ ri! X -R t -M L/._ Inlet frr)rn BOP T Choice line 3" W Rated Valves *3 Bleed f=lare Line to 3" 5M Rated Open Flare Pit 3" 5M Rated Valves Valves .J f Manual Choke Aurora We -h Seance Choke Manifold 2" SM Rated Valves To Gas Buster "Atmospheric Degasser" Schwartz, Guy L (DOA) From: George Pollock <gpollock@aurorapower.com> Sent: Tuesday, March 19, 2013 2:46 PM To: Schwartz, Guy L (DOA) Cc: Ed Jones Subject: RE: Nicolai Crk #10 (ptd 210-127) Attachments: NC10 Proposed Completion _rev_March2013.doc; NCU #10 BOP.pdf Guy, Thank you for providing the "go by" you like to see for RWO sundries. This format will be followed in the future. Answers to your specific questions are below: 1) Need Before and after wellbore schematics (just have before now) see attached. 2) BOP sketch, choke, kill lines for AWS #1 see attached. 3) What is pack off plug at 3441' ? Assume it is a slip stop type SL set plug. Yes, slip -stop at 3,440' (WLM); Pack -off 4) Are you leaving the bottom Arrowset Packer in place and releasing from on-off tool? Then stinging back in...? Yes, the bottom Arrowset packer will stay in place we will release from the On -Off tool and u e stir 5 back onto it when the well in recompleted. 5) What are you using for a workstring? We are using the 2-7/8" 8 rd EUE J-55 tubing that is in the well for a workstring —we will visually inspect and replace any damaged collars orjoints (and any that want torque up when being made up) when running the new completion. Let me know if you have any further questions. Regards, George Pollock Manager, Production Operations & Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 Main (907) 351-8286 Cell From: Schwartz, Guy L (DOA) [ma ilto:guy. schwa rtz(aalaska gov) Sent: Tuesday, March 19, 2013 10:38 AM To Subject: Nicolai Crk #10 (ptd 210-127) George, Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, March 19, 2013 10:37 AM To: 'gpollock@aurorapower.com' Subject: Nicolai Crk #10 (ptd 210-127) Attachments: RWO Sundry Format & go-by.pdf George, Can you please review the attached "go by " for RWO sundries and fill in some missing info .... this is the format I have most of the operators use. You have a very good detailed procedure but there are some items missing if you can please supply. 1) Need Before and after wellbore schematics (just have before now) 2) BOP sketch , choke, kill lines for AWS #1 3) What is pack off plug at 3441' ? Assume it is a slip stop type SL set plug. 4) Are you leaving the bottom Arrowset Packer in place and releasing from on-off tool? Then stinging back in...? 5) What are you using for a workstring? Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office -- Auro►ra Gas ---`., LLC www.aurorapower.com ' April 16, 2012 Makana Bender Natural Resource Technician Alaska Oil and Gas Conservation Commission 333 W. 7h Ave., Suite 100 Anchorage, Alaska 99501 RE: Well Data Submittal, Nicolai Creek No. 10 Aurora Gas, LLC has included in this package the following documents and electronic files for Alaska Oil and Gas Conservation Commission for the Aurora Gas LLC Nicolai Creek #10 Well, API# 50-283-20145-00. Please keep this information contained here -in "CONFIDENTIAL" for 2 -years. Paper Logs (Confidential 2 -years) 1) Schlumberger Ultrasonic Imaging Tool — Casing Collar Locator — Gamma Ray Electronic Documentation 2) Schlumberger (Confidential 2 -years) a. USIT (PDS Format) b. USIT (LAS Format) If you have any questions or require additional information, please contact me or Ed Jones at (907) 277-1003. Sincerely, AURORA GAS, LLC Chad Helgeson Manager — Production Operations & Engineering enclosures 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 3LV� - i X-? 2-1) - i Z7 Aurora Gas, LLC www.aurorapower.com March 20, 2012 Makana Bender Natural Resource Technician Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Suite 100 Anchorage, Alaska 99501�i -40 RE: Well Data Submittal, Nicolai Creek No. 10 Aurora Gas, LLC has included in this package the following documents and ele�t7'rc & files for Alaska Oil and Gas Conservation Commission for the Aurora Gas LLC Nicolai Creek #10 Well, API# 50-283-20145-00. Please keep this information contained here -in "CONFIDENTIAL" for 2 -years. Paper Logs (Confidential 2 -years) 1) Schlumberger Perforating Record 2) Schlumberger Formation Micro -Imager, Dipmeter — Gamma Ray 3) Schlumberger Platform Express 4) Schlumberger Express Pressure Tool (2 logs) 5) Halliburton 2" TVD Formation Evaluation Log 6) Halliburton 2" MD Formation Evaluation Log 7) Halliburton 2" MD Drilling Evaluation Log 8) Halliburton 5" MD Formation Evaluation Log Electronic Documentation (Confidential 2 -years) 9) Schlumberger a. Perf, FMI, XPT Long, XPT Short (PDS Format) b. X-PEX, FMI (LAS Format) 10) Halliburton a. End of Well Report b. Final Log Files c. ASCII LAS Files d. ADI Database e. Log Viewers 6051 North Course Drive, Suite 200 • Houston, Texas 77072 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 0 Fax (907) 277-1006 March 20th, 2012 Page 2 Paper Documentation (CONFIDENTIAL -2 years) 11) Halliburton Surface Data Logging End of Well Report (CD Enclosed) If you have any questions or require additional information, please contact me or Ed Jones at (907) 277-1003. Sincerely, AURORA GAS, LLC Chad Helgeson Manager — Production Operations & Engineering enclosures STATE OF ALASKA ALA_..A OIL AND GAS CONSERVATION COM. -SIGN GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: L✓j Initial Lj Annual Special 1b. Type Test: Lj Stabilized Lj Non Stabilized d Multipoint ❑ Constant Time ❑ Isochronal ❑ Other: 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Aurora Gas, LLC 21 -Oct -11 210-127 3. Address: 6. Date TD Reached: 12. API Number: 1400 West Benson Blvd., Suite 410, Anchorage AK 99503 September 6, 2011 50- 283-201145-00-00 4a. Location of Well (Governmental Section): 7. KB Elevation above MSL (feet): 13. Well Name and Number: Surface: 1779' FNL, 1486' FWL, Sec. 20, T11N R12 W SM 255.3 Nicolai Creek #10 Top of Productive Horizon: 8. Plug Back Depth(MD+TVD): 14. Field/Pool(s): 935' FNL, 756' FWL, Sec. 20, T. 11 N., R. 12 W., S.M. 3,950' MD & 3645' TVD Nicolai Creek Unit Total Depth: North Undefined Gas Field 9. Total Depth (MD + TVD): 517' FNL, 355' FWL, Sec. 20, T. 11 N., R. 12 W., S.M. 4830' MD & 4438'TVD 4b. Location of Well (State Base Plane Coordinates NAD 27): 10. Land Use Permit: 15. Property Designation: Surface: x- 242,963 y- 2,571,972 Zone- 4 CIRI ADL -063279 TPI: x- 242,233 y- 2,572,816 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 241,860 y- 2,573,259 Zone- 4 Multi -packer Selective w/ Sliding sleeves (4 -separate zones) 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 7" 23# & 26# 6.366" & 6.276" 4,805' 3510-32' (tested --also: 2688-98', 2825-30' 3319-23', 3326-31', 3856-66': isolated) 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 2-7/8" 6.5# 2.44" 3,838' 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocarbons: 23. Specific Gravity Flowing Fluid (G): 2582', 3240', 3389', 3767' N/A N/A 0.569 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): Tubing ❑ Casing 90 F° 1537 psia @ Datum 3001' TVDSS 14.65 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO2: % N2: % H2S: Prover: Meter Run: Taps: 3,549 3,288 0.569 0.356 2.6 0 Daniel Sr. 4.026 Flange 26. FLOW DATA TUBING DATA CASING DATA Prover No. Line xOrifice Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow Size in. Size (in.) psig Hw F° psig F° psig F° Hr. 1• 4 X 1.5 791.8 14.44 47.61 1350 50 t3 1 hr 2• 4 X 1.5 830.35 28.09 47.61 1320 55 C(j 1 hr 3• 4 X 1.5 843.4 43.56 46.92 1300 60 „ Uffft$jr, 1 hr 4• 4 X 1.5 896.6 82.81 46.92 1270 65 P 1 hr 5. X Basic Coefficient I- Flow Temp. Super Comp. No. 24 -Hour hw m ( ) y P Pressure Gravity Factor Rate of Flow Factor Factor Fb or Fp Pm Ft F9 O� Mcfd Fpv 1. 11.23 107.91 806.45 0.981 1.326 1.073 1,691 2. 11.23 154.06 845 0.990 1.326 1.077 2,447 3. 11.23 193.32 1 858.05 1 1.000 1 1.326 1.079 3,106 4. 11.23 274.69 1 911.25 1 1.010 1 1.326 1.083 4,472 5. Form 10-421 Rev."613IMS+ MAR 0 5 701NW30MD ON REVERSE SIDE Submit in Duplicate Temperature for Separator for Flowing No. Pr T Tr z Gas Fluid Gg G 1 0.9981 0.569 0.569 2 • 0.9981 0.569 0.569 3. 0.9981 Critical Pressure 0.569 0.569 4• 0.9981 Critical Temperature 0.569 0.569 5. Form 10-421 Rev."613IMS+ MAR 0 5 701NW30MD ON REVERSE SIDE Submit in Duplicate Pc 1420 poz 2016400 1539 Pe 2368521 AOF (Mcfd) 28,622 Remarks: AOF & n: Calculated using Ryder- Scott Reservoir Solutions Software, see attached. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed��� Title Mgr. Production Ops & Eng DEFINITIONS OF SYMBOLS n 1 Date 12/6/2011 AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= -1 —1/Z dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas -oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back -pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 7/2009 Side 2 rt PV Pc` -Pt` PW pW2 Pc2-PW2 Ps Ps Pf -Psz 1• 1365 1863225 153175 114 12996 2003404 1479 2187441 181.08 2. 1335 1782225 234175 113 12769 2003631 1448 2096704 271.817- 3. 1315 1729225 287175 114 12996 2003404 1429 2042041 326.48 4• 1295 1677025 339375 122 14884 2001516 1417 2007889 360.632 5. 7G AOF (Mcfd) 28,622 Remarks: AOF & n: Calculated using Ryder- Scott Reservoir Solutions Software, see attached. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed��� Title Mgr. Production Ops & Eng DEFINITIONS OF SYMBOLS n 1 Date 12/6/2011 AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= -1 —1/Z dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas -oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back -pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 7/2009 Side 2 v Ryder Scott WELL NAME: NICOLAI CREEK #10 Reservoir FIELD: NICOLAI CREEK GAS FIELD - - - - olutions LOCATION: West Side Cook Inlet, Kenai Bor., Alaska =- (Public) RESERVOIR: Carya 2-4.2 (3510-30' MD) J(Protected) Q, Mcf/d BCPD Test Data BWPD FTP, Psia I i BOTTOMHOLE TEMP, °F: 93 SOUR GAS MOLE % GAS GRAVITY: 0.569 N2 2.60 H2O GRAVITY, yW: 1.010 CO2 0.00 GOND. GRAV., *API:—__ 0 HZS 0.00 - -- --- TVD, FT: - 3,256 1,479 _MEAS. DEPTH, FT: __3,5 49 Options Cond. Correl. (Y/N): N Check, Corrected* Tc, OR: 342.50 If Injection Well Corrected* Pc, Psia: 668.99 El Smooth Pipe Roughness Pressure Base, Psia: 14.650 TUBING ID, IN.: 2.441 Wichert-Aziz correction for contaminants, if any 0 0 1,295 RESULTS 1,417 AOF, Mcf/d: 28,622 C:_ 0.0120_91 n: 1.000000 1000 6 OL 7.000 MOM -`_-. 100:000 FIOw Rate, Mefld POINT NO. (Automatic) Q, Mcf/d BCPD Test Data BWPD FTP, Psia I i 7.000 MOM -`_-. 100:000 FIOw Rate, Mefld POINT NO. (Automatic) Q, Mcf/d BCPD Test Data BWPD FTP, Psia I WHT, OF FLOWING BMP, Psia COMMENT SHUT-IN 0 0 0 1,420 1,539 SIBHP 1 1,704 0 0 1,365 J�:�50 1,479 2 2,415 0 0 1,335 55 1,448 3 3,038 0 0 1,315 60 1,429 4 4,356 0 0 1,295 65 1,417 These results were prepared using Reservoir Solutions Software. This is not Ryder Scott work product. STATE OF ALASKA ALASK,, JIL AND GAS CONSERVATION C(�MMIS1(�N WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas Q � SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ ❑ WAG ❑ WDSPL ❑ No. of Completions: _ 4 . 1b. Well Class: Development _ Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Aurora Gas, LLc 5. Date Comp., Susp., or Aband.: 9/22/2011 12. Permit to Drill Number: 210-127 ' 3. Address: 1400 West Benson, Suite 410, Anchorage, AK 99503 6. Date Spudded: 8/11/2011 13. API Number: 50-283-20145-00-00 4a. Location of Well (Governmental Section): Surface: 1779' FNL, 1486' FWL, Sec. 20, T1 1N R12 W SM Top of Productive Horizon: 975' FNL, 682' FWL, Sec. 20, T11N R1 2W SM Total Depth: 517' FNL, 355' FWL, Sec. 20, T11 N R12W SM 7. Date TD Reached: 9/6/2011 �,� : 14. Well lNam� and Number: �Nicdial Creek Unit #10 8. KB (ft above MSL): ,ssY77" GL (ft above MSL): 240.6' 15. Field/Pool(s): Nicolia Creek Unit North Undefined Gas 9. Plug Back Depth(MD+TVD): 3950' MD - 3645' TVD 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 242,963 y- 2,571,972 - Zone- 4 TPI: x- 242,178 y- 2,572,876 Zone- 4 Total Depth: x- 241,860 y- 2,573,259 Zone- 4 10. Total Depth (MD + TVD): . 4830' MD - 4438' TVD - 16. Property Designation: ADL -063279 - 11. SSSV Depth (MD + TVD): -4575' MD - -4103' TVD 17. Land Use Permit: CIRI 18. Directional Survey: Yes ✓ No (Submit electronic and printed information per 20 AAC 25.050) 19. Water Depth, if Offshore: NA (ft MSL) 20. Thickness of Permafrost MD/TVD: NA 21. Logs Obtained (List all logs here and submit electronic and printed information per 20AAC25.071): Mud Log, PEX (Array Ind + Comp Ntrn+ Litho Den w/ GR, SP, ML), FMI--dipmeter, XPT (pressures), SWC's 22.Re-drill/Lateral Top Window MD/TVD: NA 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM PULLED 13-3/8" 68 K-55 Surf 94' Surf 94' Driven Driven 0 9-5/8" 36 & 40 K & L Surf 660' Surf 660' 12-1/4" 241 sx 12.0 ppg Type 1 0 7" 23 & 26 K & L Surf 4805' Surf 4409' 8-1/2" 221 sx Lite + 893 sx Type 1 0 24. Open to production or injection? Yes ❑ No❑ If Yes, list each interval open (MD+TVD of Top & Bottom; Perforation Size and Number): Perfs at 3856-66' MD / 3561-3570' TVD - 6 SPF w/ 3-1/2" csg gun (0.44") (Also perforated 3510-30' MD / 3251- 3269' TVD w/ same guns, isolated w/ packer & sldg slv; 3319- 23'& 26-31' MD /3080-91' TVD w/ same guns & isolated w/ packer & sldg slv; and 2825-30' & 2688-98' MD / 2643-47' & 2523-31' TVD w/ same guns & isolated with packer and sldg slv) 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 2-7/8" 3838' 3767' MD/3392' TVD & 3389', 3240', 2582' MD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 3467-72' Sqzd w/ 58 sx Class G cmt (est 38 sx behind casing) 27. PRODUCTION TEST Date First Production: 10/19/2011 Method of Operation (Flowing, gas lift, etc.): Flowin Date of Test: 10/20/2011 Hours Tested: 23 Production for Test Period Oil -Bbl: 0 Gas -MCF: 1618 ' Water -Bbl: 1 Choke Size: variable Gas -Oil Ratio: INA Flow Tubing Press. 1400 Casing Press: 0 Calculated 24 -Hour Rate -.► Oil -Bbl: 10 Gas -MCF: 1689 Water -Bbl: 1 Oil Gravity - API (torr): NA 28. CORE DATA Conventional Core(s) Acquired? Yes ❑ No Sidewall Cores Acquired? Yes No ❑ If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. See attached core analysis-- additional analyses submitted separately. 30 side-wall cores taken at: 988', 1008', 1206', 1426', 1449', 1493', 1510', 2032', 2040', 2348', 2356', 2362', 2530', 2650', 2690', 2696', 2825', 2830', 2834', 3325', 3330', 3335', 3516', 3522', 3532', 3540', 3856', 3860', 3866', and 3872' MD (987' to 3575' TVD). r RECEIVE ` V 2 2 2x11 RBDMS NOV 2 a 2011 NQ Form 10-407 Revised 12/2009 CONTINUED ON REVERSE A1ska Oil & ( bf0,ie%rWW"n >'iI� MARKERS (List all formations and markers encountered): Permafrost - Top Permafrost - Base Glacier Wash Beluga Tyonek Carya 2-1 Carya 2-2 Carya 2-3 Carya 2-4 Carya 2-4.1 Carya 2-4.2 Carya 2-5 Carya 2-6 Carya 2-7 Formation at total depth: Tyonek Carya 2-7 T NA NA Surface 794 1684 1918 2198 2664 3046 3258 3420 3588 3820 4512 �B� Surface 794 1626 1835 2056 2501 2863 3026 3170 3321 3260 4141 3�. FORMATION TESTS Well tested? Yes 21 No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if needed, and submit detailed test information per 20 AAC 25.071. Carya 2-3 perfs at 2688-98' and 2825-30': 1019 mcfpd at 570 psi w/ no water. SITP --1050 psig. Carya 2-4.1 perfs at 3319-23' and 3326-31': 2041 mcfpd at 900 psi. SITP--1270 psig. Carya 2- 4.2 perfs at 3510-30': 4360 mcfpd at 1278 psig w/ no water. SITP--1405 psig. Carya 2-6 perfs at 3856-66': 2963 mcfpd at 1300 psig w/ no water. SITP--1480 psig. 31. List of Attachments: Daily Operations Summary, Well Schematic Diagram , Core Analysis, and Directional 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name: J. FIWard J Signature: Title: President Phone: 281-495-9957 INSTRUCTIONS submitted separately) Contact: Ed Jones Date: 11/17/2011 General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1b: Classification of Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 12/2009 Aurora Gas, LLC NICOLAI CREEK UNIT #10 PTD#: 210-127 API#:50-283-20145-00-00 RKB 14.7ft Drill 12-1/4" Hole to 678' 2-7/8" x 7" annulus displaced with 9.3ppg inhibited packer fluid Carya 2-3 2688-2698' (2523-31' TVD) 2825-2830' (2643-47' TVD) i mss. Carya 24.1 3319-3323' 3326-3331' (3080-3091' TVD) Carya 2-4.2 3510-3530' (3251-69' TVD) PBTD @ 3950' MD Carya 2-6 (3645' TVD) 3856-3866' (3561-70' TVD) Drill 8-1/2" Hole to 4830' MD, _ 4438' TVD avg deviation 26deg, KOP 900' Sliding Sleeve @ 3,549' WXO, 2.313 X Profile On -Off Seal Nipple w/ skirt 2.313 X -profile Arrowset 1X Mechanical Packer @ 3767 EOT @ 3838' 7" 23# K-55 & 26# L-80 Casing to 4805' MD/ 4409' TVD 3-1/2" (9.3#) 8rd EUE L-80 Tubing, 4ft pup 2 7/8 6.5# 8rd EUE J-55 Tubing 4.. 13-3/8" 68# Structural •4 Conductor driven to 94' GL i' N.ry x s 9-5/8" 40 & 36# Surface Casing set at 654' t. is Cement w/12. ppg Type I Accelerated Chemical Injection Sub, 2-7/8" 8rd EUE, �'/," npt connection, 1/4" S.S. tubing, @ 2512' w/2way check Sliding Sleeve @ 2547' WXA, 2.313 X Profile Hydraulic Set Packer @ 2582' Sliding Sleeve @ 2741' WXO, 2.312 X Profile i., ' Hydraulic Packer @ 3240' Expansion joint @ 3260' v " •- Sliding Sleeve @ 3354' WXO, 2312 X Profile Hydraulic Packer @ 3389' Sliding Sleeve @ 3,549' WXO, 2.313 X Profile On -Off Seal Nipple w/ skirt 2.313 X -profile Arrowset 1X Mechanical Packer @ 3767 EOT @ 3838' 7" 23# K-55 & 26# L-80 Casing to 4805' MD/ 4409' TVD Aurora Gas, LLC Nicolai Creek Unit #10 Nicolai Creek Field Kenai Peninsula Borough, Alaska Weatherford' LABORATORIES PERCUSSION SIDEWALL CORE ANALYSIS FILE NO.: HH -53579 ANALYST: Monti DATE: 9-12-11 CORES: Schlumberger In. Rec. Sample Depth Feet Permeability mD Porosity % Pore Volume Prob Prod Bulk Volume Crit. Water % QA Factor Core Lithology Saturation Saturation Oil % I Water % Oil % Cas % 1.7 988.0 8.3 19.8 0.0 86.0 (6) 0.0 1.8 1008.0 175.0 22.5 0.0 87.2 Wtr 0.0 1.8 1206.0 5.1 19.7 0.0 87.6 (6) 0.0 1.7 1426.0 3.2 19.2 0.5 86.3 (6) 0.1 2.0 1449.0 1 s Sd mg sslty sshy no flu 8.7 34 1 s Sd mg sslty sshy scarb no flu 1.7 1493.0 0.8 16.3 5.1 81.7 (6) 0.8 1.6 1510.0 610.0 25.3 2.4 67.4 Gas 0.6 1.6 2032.0 405.0 25.1 0.0 69.3 Gas 0.0 1.7 2040.0 675.0 23.9 0.0 68.0 Gas 0.0 1.6 2348.0 385.0 21.7 0.0 60.0 Gas 0.0 1.6 2356.0 485.0 26.0 0.0 64.8 Gas 0.0 1.5 2362.0 400.0 23.6 0.0 64.3 Gas 0.0 1.7 2530.0 560.0 24.7 0.0 69.4 Gas 0.0 2.8 68 1 s Sd vfg slty shy w/thn Garb lams no flu 2.9 43 1 s Sd f -mg sslty sshy scarb no flu 2.4 71 1 s Sd vfg vslty shy no flu 2.5 71 1 s Sd vfg vslty vshy lams ft stk flu Shale dk brn sslty vorg no flu 2.1 70 1 s Silt vshy lams ft yl stkd flu 460 api 7.7 34 1 s Sd fg sslty sshy vft flu 7.7 38 1 s Sd f -mg sslty sshy no flu 7.7 32 1 s Sd mg sslty sshy no flu 8.7 34 1 s Sd mg sslty sshy scarb no flu 9.1 37 1 s Sd fg slty sshy no flu 8.4 37 1 s Sd c -mg sslty sshy scarb no flu 7.6 34 1 s Sd f -mg sslty sshy no flu 5200 N. Sam Houston Pkwy. West, Suite 500 * Houston, Texas 77086* Fax (281) 583-8959* Phone (832) 375-6800 Page 1 of 3 Aurora Gas, LLC Nicolai Creek Unit #10 Nicolai Creek Field Kenai Peninsula Borough, Alaska Weatherford LA 8 0 R A T 0 R I E S PERCUSSION SIDEWALL CORE ANALYSIS FILE NO.: HH -53579 ANALYST: Monti DATE: 9-12-11 CORES: Schlumberger In. Rec. Sample Depth Feet Permeability ml) Porosity % Pore Volume Prob Prod Bulk Volume Crit. Water % QA Factor Core Lithology Saturation Saturation Oil % Water % Oil % Gas %a 1.5 2650.0 Lignite 1.5 2690.0 250.0 23.8 0.0 68.7 Gas 0.0 7.4 41 1 s Sd f-vfg slty sshy no flu 1.5 2696.0 225.0 25.4 0.0 68.9 Gas 0.0 7.9 42 1 s Sd f-vfg slty sshy no flu 1.3 2825.0 7.3 21.6 0.0 78.3 (6) 0.0 4.7 72 1s Sd vfg vslty w/thn sh & Garb lams no flu 1.6 2830.0 300.0 26.2 0.0 78.0 Wtr 0.0 5.7 41 1 s Sd f-vfg sslty sshy no flu 1.9 2834.0 0.1 17.5 0.7 86.6 (6) 0.1 2.2 76 1 Sd vfg slty w/95% sh lam org no flu 1.7 3325.0 440.0 27.8 0.0 68.0 Gas 0.0 8.9 40 1 s Sd fg slty sshy no flu 1.4 3330.0 650.0 25.9 0.0 57.5 Gas 0.0 11.0 34 1 s Sd f -mg ssity sshy scarb no flu 1.4 3335.0 625.0 25.7 0.0 55.1 Gas 0.0 11.5 35 1 s Sd f -mg ssity sshy no flu 1.4 3516.0 550.0 25.3 0.0 57.8 Gas 0.0 10.7 34 1 s Sd f -mg ssity sshy no flu 1.4 3522.0 500.0 26.5 0.0 52.0 Gas 0.0 12.7 38 1 s Sd f -mg sslty sshy scarb lams no flu 1.1 3532.0 325.0 22.8 0.0 49.8 Gas 0.0 11.4 37 1 s Sd c -mg w/peb sslty sshy scarb no flu 1.3 3540.0 310.0 21.2 0.0 68.3 Gas 0.0 6.7 36 1 s Sd c -mg w/peb ssity sshy scarb no flu 1.4 3856.0 375.0 25.9 0.0 61.0 Gas 0.0 10.1 39 1 s Sd fg sity sshy no flu 1.5 3860.0 600.0 25.3 0.0 60.0 Gas 0.0 10.1 34 1 s Sd f -mg sslty sshy no flu 0.8 3866.0 33.0 21.9 0.0 66.2 Gas 0.0 7.4 58 3sf Sd m-vfg ssity sshy vcalc no flu 5200 N. Sam Houston Pkwy. West, Suite 500 * Houston, Texas 77086* Fax (281) 583-8959* Phone (832) 375-6800 Page 2 of 3 Aurora Gas, LLC Nicolai Creek Unit #10 Nicolai Creek Field Kenai Peninsula Borough, Alaska Weatherford LABORATORIES PERCUSSION SIDEWALL CORE ANALYSIS Pore Volume In. Sample Permeability Porosity Saturation Prob Rec. Depth Oil I Water Prod Feet mD % % % 1.4 3872.0 575.0 27.9 0.0 64.0 Gas FILE NO.: HH -53579 ANALYST: Monti DATE: 9-12-11 CORES: Schlumberger Bulk Volume Saturation Crit. I QA Core Lithology Oil Gas Water Factor 0.0 10.0 37 1 s Sd f -mg sslty sshy no flu 5200 N. Sam Houston Pkwy. West, Suite 500 * Houston, Texas 77086* Fax (281) 583-8959* Phone (832) 375-6800 Page 3 of 3 AURORA GAS, LLC NICOLAI CREEK NO. 10 (AOGCC PERMIT No. 210-127) (API No. 50-283-20145-00) DRILLING, COMPLETION, AND TESTING OPERATIONS SUMMARY 8/1/11—Pre-spud meeting in Anchorage. Mobilize crews to West Side of Inlet (Shirleyville Camp). 8/2-7/11— Move in rig and related equipment and start rig up. 8/8/11—Continue rig up. Mix 200 bbl 10.0 ppg spud mud. PU BHA. 8/9/11—Strap and drift 9-5/8" casing. Test diverter, floor and dart valves, and gas detection—witnessed by Chuck Scheve. MU power swivel. MW -10.0 ppg 8/10/11—Rack and tally 4-3/4" DC's and 4" DP. Work on accumulators. Run BHA into conductor. MW -10.0 ppg. 8/11/11—Spud at 00:01. Drill to 217'. MW -10.0 ppg. 8/12/11—Drilled to 226'—bit stopped. POH and change bit. RIH and drill to 336'. MW -1,K.3 ppg. 8/13/11— Dri11336' to 618'w/ survey at 451'-0.75 deg. MW -10.0 ppg. Mud loss - 20 bbl. 8/14/11—Drill to 678'. Circ clean. Svy-0.75 deg. POOH, stand back DC's and DP. Lay down BHA. RU GBR casing crew. MU shoe and collar on lst joint of 9-5/8". MW -10.0 ppg. 8/15/11—. Run 16 jts 9-5/8" 36# K-55 LTC (6 jts, 240') & 40# L-80 BTC casing to 660'. Circ and condition mud. RD GBR. RU BJ. Test lines to 2000 psi. Pump 25 bbl spacer 9.5 ppg SealBond spacer, 91 bbl 12.0 ppg Type I gas -resistant light cement (2.14 cf/sk), 5 bbl fresh water spacer, then displace w/ 47.9 bbl mud—did not bump plug, so pumped another 1.4 bbl --did not bump. Good returns throughout job, but no cement to surface Floats held. WOC. RD diverter. Clean mud pits. Slack off casing. RD cement head. Cutoff casing. MW -10.0 ppg. 8/16/11—Run 1" pipe down conductor X surface casing annulus—tag at 20'. Pump 1 bbl cement, left 9 bbl cement in cellar. Final cut of 9-5/8" casing. Weld on head. Test -- OK. NU BOP and install choke lines and hydraulic choke. 8/17/11—Test BOP's to 300/3000 psi—witnessed by John Crisp, AOGCC. Mix 180 bbl new EZ mu -c a11U(p g " 8/18/11—Fin BOP test. Set wear ring. Test casing to 1500 psi for 15 minutes. Make up 8-1/2" BHA. RIH to tag at 597'. Circ and condition mud. Drill out cement and shoe track to 660'. Displace spud mud w/ EZ mud. Drill 20' new hole 678' to 698'. MW - 10.0 ppg. 8/19/11—FIT to 16.0 ppg EM_W. POH w/ cleanout BHA PU 8-12" BHA w/ PDC bit, motor, and MWD. RIH, picking up BHA—test MWD shallow. Continue RIH, PU BHA. Circulate and condition mud. Drill 8-1/2" hole to 766'. Attempt to slide and kick off. MW -10.0 ppg. Mud loss -12 bbl. 8/20/11—Orient and slide to 855'. POH to change angle on motor housing. Drain motor, inspect bit, adjust bent housing on motor to 1.76 deg. Lower flow parameters on MWD. Change out bit to 2nd PDC. MW -10.2 ppg. Mud loss -6 bbl. 8/21/11—RIH to 824', wash to bottom at 855'—no fill. Orient and drill to 1201', MW -9.9 ppg. Mud loss -13 bbl. 8/22/11—Drill to 1484'. CBU. Short trip to 855—tight at 1290'. Drill to 1672'. MW - 9.8 ppg. Mud loss -19 bbl. 8/23/11—Drill to 1986'. CBU 3X. Short trip—differential sticking. Stuck pipe w/ bit at 1860'. Work stuck pipe. MW -9.6 ppg. Mud loss -24 bbl. 8/24/11—Work stuck pipe. Pump soap pill & high vis sweep. Pull 120 K and torque to 7,000 ft-lb—no movement. RU surface jars and jar 5X before jar failure—unable to cock._ Work stuckpipe while mixing Black Magic pill. Pump 27 bbl Black Magic pill (7.4 ppg w/ 35 sec. vis). Spot pill w/ 15 bbl 9.6 ppg mud. Work stuck pipe (80K and & 7000 ft -lb) while pumping 1 bbl Black Magic pill every 15 minutes until all out of drill string, then %2 bbl every 15 min. MW -9.6 ppg. Mud loss -7 bbl. 8/25/11—.Continue to work stuck i e to 80K pull w/ 7000 torque. RU GBR 10-3/4" tongs, torque pipe—unable to rotate. Pull 14K, work with tongs. Displace pill w/ 27 bbl mud. _RU Schlumberger w/ WL side entry for free -point run MW -9.6 ppg. 8/26/11— RU SLB w/ APRS tools for free -point run. Problems w/ interface between tools and SLB. LD side -entry assembly to WO tools. RU and work stuck pipe. RU SLB % APRS to free point. RIH w/ FP indicator—found pipe free at 1407'. POOH w/ WL, MU string shot, and RIH on WL. Fire at 1407'. Back -off pipe. POH, RD SLB & APRS. Pull 1 stand—tight. Double line break-out tongs and snub back stands. POH w/ dreill 2 string. Inspect and LD DC where backed off. PU screw-in sub and fishing BHA w/ bumper sub, jars, pump -out sub, and accelerator jars. MW -9.6 ppg. 8/27/11-RIH to shoe. Cut & slip drilling line. RIH and tag fish at 1412'. Circ and condition -5 BPM at 200 psi. Screw into fish, torque to 7000 ft -1b.-5 BPM at 450 psi. Jar 170K pull fish free. Circ and condition at 5 BPM, 450 psi. Back ream out 10 jts, then POH, LD fishing BHA, 5 4-3/4" DC's and 4 6" DC's. POH w/ directional BHA. LD MWD. Adjust bent housing to 1.5 deg. MW -9.6 ppg. Mud loss -12 bbl. 8/28/11-PU clean-out BHA w/ RR MT bit, RIH, tag at 1224'. Ream 1209-1310' and 1586' to 1986'. Drill to 2026'. CBU. POH, change out motor and bit. MW -9.5 ppg. Mud loss -7 bbl. 8/29/11 -Load MWD tools, RIH w/ bit #6 (MT) and directional BHA. Drill to 2520'. MW -9.5 ppg. Mud loss -10 bbl. 8/30/11 -Drill to 2541'. Circ clean. POH for short trip -back ream 2541-2378' and 2316-2001'. Ream back to bottom. Drilled to 2819'. MW -9.4 ppg. Mud losses -10 bbl. 8/31/11 -Drill to 3014'. Circ clean. Back ream to 2764'. Circ clean. Back ream to 2390'. POH to 1056' -stuck. Work pipe free with torque and down weight. Back ream 1056-870'. POH. MW -9.3 ppg. Mud loss -10 bbl. (Total mud losses to date -150 bbl). 9/l/11 -LD MWD and bit. Test BOP's to 300/3000 psi (AOGCC witness waived). Change pump liners to 5-1/2". PU bit #7 (HTC MXL-S 1 V). RIH. MW -9.3 ppg. 9/2/11-PU Omni sting ("ghost") reamer at 560' from bit. RIH to 725', ream to 947'. TIH to 1320' (reamer at 760') --tight. PU to 1293', ream to 1481'. CBU. Ream to 2277'. TIH to 2928'. Circ and condition mud. Wash to 3014'. Drill to 3242'. MW - 9.3 ppg. 9/3/11 -Drill to 3525' w/ svy each connection. Circ clean & pump sweep. Make 500' short trip. Ream last 3 jts to bottom. Circ and condition. Drill to 3619'. MW -9.4 ppg. 9/4/11 -Drill to 3996' w/ svy and flow check each connection. Mix and pump high vis sweep --cuttings increased 20%. Short trip, pump out 4 jts then TOH to 3400'. Smooth TIH to 3965'. Ream to bottom. Drill to 3998' w/ high torque. MW -9.5 ppg. 9/5/11 -Drill and work pipe to clean hole. Drilled to 4014', unable to rotate -slid to 4022'. Rotary drill to 4581'. MW -9.7 ppg. 9/6/11 -Drill to 4830' (hard streak 4720-35'). Circ clean and pump high vis sweep H for wiper trip to condition for logs. Tight 2676-2582'. MW -9.55 ppg. 3 9/7/11—POH to shoe for wiper trip. RIH to 2361'—tight. Wash & ream through -4576 units gas. Wash to 2424'. RIH to 3206'. CBU-5282 units of gas. RIH to TD, 4830'. CBU-5470 units of gas. Condition mud and increase weight to 9.7 ppg. Monitor hole. Mix and pump 15 bbl 10.7 ppg pill. POH s ow y to 273'. MW__—___� 7 ppg. 9/8/11—Fin POH, lay down string reamer and `smart' BHA including motor. RU Schlumberger (SLB). RU and test lubricator. PU and run SLB PEX tool (array induction, neutron and density porosity, GR, SP. Microlog, and caliper). Log 4830-650' FOOH WO tool. 13U FMI rmation micro imager) tool, RIH, and log 4808-660'. MW -9.7 ppg. 9/9/11—POOH and LD FMI tool. PU XPT tool, RIH, and take 15 formation pressures between 3870' and 977'. POOH and LD tool. PU side-wall core gun, RIH, shoot and recover 30 cores between 3872' and 988'. POOH, LD gun, RD SLB. PU bit #7 RR for conditioning trip, start TIH. MW -9.7 ppg. 9/10/11—Finish TIH w/ clean-out BHA to TD. CBU, pump high vis sweep and `dry job' pill. POH, LD DP and BHA. Pull wear ring. MW -9.7 ppg. 9/11/11—Change pipe rams to 7" and test to 250/3000125i. RU GBR to run casing. PU up shoe track and test. Run 109 jts (4784') 7 inch 26# L-80 LTC (47 jts, 2208') and 23# K-55 LTC (62 jts, 2575') to 4803' KB w/ 44 centralizers and 11 turbolators. 9/12/11—Circ and condition mud. RU BJ to cement. Test BJ lines to 3000 psi. Drop bottom plug, pump 40 bbl 11.5 ppg SealBond spacer, 84 bbl (221 sx) Type I light -weight gas-tight cement at 12.0 ppg (2.14 cf/sk), 214.7 bbl (893 sx) Type I gas-tight cement at 14.8 ppg 5 c s , top plug, 5 bbl_ fresh water, 178.8 bbl 3% KCl water (by pump strokes} -did not bump plug but got 95 bbl o cemrnt to surface. Check floats—held. RD cementers. Install and test casing hanger packof£ Change rams to 2-7/8" and test to 250/3000 psi. Lay out and strap 2-7/8" 6.5# J-55 8 -rd EUE tubing. Install wear ring, RU to run tubing. 9/13/11—Finish cleaning pits and RU to run tubing. PU 6-1/8" bit and casing scraper and RIH on 2-7/8" tubing. Tag at 3404'. PU power swivel and clean out cement to 3414'. Drill plug to 3415'. Drilled cement to 3574', pumped high vis sweep in 3% KCl water. MW -8.5 ppg (KCL water). 9/14/11—Drilled cement to 3600'. Circ and condition. Drilled cement to 3950'. Circ hole clean. Start to clean pits. 9/15/11—Clean pits and displace with water. Pump 30 bbl 100 -vis sweep at 10 BPM at 1600 psi. Test casing to 2000 psi. Build 9.3 ppg 3% KCl -NaCl brine. Displace hole and filter brine to 10 microns. Start BOP test --test choke manifold. MW -9.3 ppg. 9/16/11—Circ and filter brine to 5 microns. POH from 3950', strapping tubing. LD bit and scraper. Test BOP'S. RU Schlumberger (SLB). RIH w/ GR/CCL/ USIT CBL tool to 3940'—short in wireline. POOH and make 2nd run—short in different wire in wireline. POOH. Rehead wireline. RIH for 3`d attempt w/ GR/CCL/ CBL and log from 3950' to surface—much questionable bond. LD logging tools. RU shooting flange and lubricator and test to 1600 psi. Re -run CBL from 3950-2500' w/ 1500 psi on casing— little improvement in bond. 9/17/11—POOH w/ CBL tools, and LD. RU to run gun to perf for cement squeeze. RIH rJ w/ 5' 3-1/2" Poweet Omega gun and perf 3467-72' w/ 6 SPF. POOh. ND shooting flange and lubricator and RU flow nipple. PU HES FastDtill composite BP and RIH on 2-7/8" tubing, set at 3500'. POH w/ setting tool. PU FastDrill cement retainer—wrong stinger to run on tubing. 9/18/11—WO replacement stinger. Build 30 bbl 9.3 ppg KCl -NaCl brine. MU and start RU of BJ. Run composite cement retainer on 2-7/8" tubing and set at 3395'. Fin RU BJ—test lines to 2000 psi. Perform injectivity test w/ brine: 1/2 BPM at 1500 psi, 3/4 BPM at 1600 psi, and 1 BPM at 1650 psi. Unsting from retainer. Batch mix 12 bbl (58 sx) Class G cement. Pump 2 bbl fresh water, 12 bbl cement, 2 bbl fresh water, and sting into retainer. Displace w/ 17 bbl brine. Pump cement below retainer, with final pressure of 1100 psi. Pull out of retainer. Rev out 2 tubing volumes (38 bbl). RD BJ. POH w/ tubing and LD setting tool. PU bit, scraper,and 2 4-3/4" DC's. RIH on 2-7/8" tubing to 1055'. 9/19/11—RIH to 3352', Wash to 3395'. Drill retainer t, 3397'., Drill BP to 3502'. RIH to 3950'. Circ clean at 8 BPM at 1200 psi, filtering brine to 10 microns. Build 30 bbl 9.3 ppg 3% KCl -NaCl brine. Circ and filter. 9/20/11—Circ and filter to 5 micron. POH, LD DC's. RD flow nipple and NU shooting flange. RU SLB, PU perf gun #1, test lubricator to 500 psi. RIH and perf 3856-66' (2-6 sand) w/ 6 SPF w/ 3-1/2" PowerJet Omega charges. Perf 3510-30' (2-4.2 sand) w/ gun #2, 3319-23' & 3326-31'(2-4.1 sand) w/ gun #3—hole took 1.5 bbl, 2825-30' (2-3 sand) w; gun #4, and 2688-98' (2-3 sand) w/ gun #5. RD SLB and shooting flange. RU flow nipple. PU bit and scraper and RIH to 2550'. 9/21/11—Cont RIH to 3925'. Circ and filter brine to 10 micron -380 units gas max. POH, LD 6 jts tubing, scraper, and bit. PU completion and RIH as follows on 2-7/8" 6.5# J-55 EUE tubing: --WL entry guide and pump out sub, --2 jts 2-7/8" tubing, --Weatherford Arrowset mechanical set packer w/ On -Off tool w/ X profile (set at --XO sliding sleeve (set at 3549') --Hydraulic-set packer (set at 3389 J --XO slidings sleeve (set at 3354') --Expansion Joint (set at 3255') --Hydraulic packer (set at 3240') --XO sliding sleeve (set at 2740') 5 --Hydraulic packgr set at 2583' --XA sliding sleeve (set at 2548') --injection sub (at 2512' w/ 3/8" stainless steel tubing banded to outside of tubing) Set mechanical packer at 3767'. Release from packer. Mix and pump 80 bbl brine w/ 40 gal Baracor corrosion inhibitor down backside at 2 BPM. Latch into on-off tool. Land hanger and lock down. Drop ball and set hydraulic packers. Test tubing to 2400 psi. Increase pressure to 3200 psi and pump out ball and pump -out plug. Test casing to 2000 psi. Attempt to set BPV—wrong size, 4" instead of 3". 9/22/11—WO BPV. Clean floor and ND flow nipple. Receive 3" BPV and set. ND BOP. Run control line (3/8" SS) thru tubing head. NU tree. Pull BPV and set 2 -way check. Test tree to 3500 psi. Pull 2 -way check and set BPV. 9/23/11—Rig down and start moving rig to Three Mile Creek #3. Leave well SI pending spacing Conservation Order. 10/3/11—Vetco service man pulled BPV 10/13-10/18/11—Weld, bury, hydrotest, and backfilled 300' flowline from well head to NCU 3 production facility, and install temporary piping to facilitate testing through choke and test unit to sales thru NC#3 compressor and dehy. 10/19/11—RU Pollard. Run 2.25" GR to 3955' WL and tag. RU to swab. Make 5 runs to 240'—well started weak flow, died (deepest completion, Upper Tyonek Carva 2-6 perfs at 3856-66' open). Well flowing weakly after run #6 –found FL at 120', pulled from 220'. Swabbed run #7—FL at 20', pulled from 124'—well kicked off. Well unloaded to test tank. Built to 800 psi while flowing. SI to rig down Pollard and put water and gas thru test separator—built to 1100 psi in 13 minutes. Open well to test separator and test. Tested zone, but had difficulty getting stable rate and pressure due to the choke freezing off. Tested well to sales thru compressor. 10/20/11—Continue to test 2-6 sand completion. Install methanol pump. Test at various rates: 1724 mcfpd at 1400 psi and 2963 mcfpd at 1300 psi, flowing well to sales thru compressor. Total water recovered since opening well -20.9 bbl (tubing volume -22.2 bbl). 1 -hr SITP-1480 psig. 10/21/11—RU Pollard. Run 2.25" GR to 3956' WL. Ran2.313" PX plug and set in X profile in On -Off tool at 3766'. Ran and set prong in plug. Open sleeve for Carya 2-4.2 completion at 3549' erfs at 3510-30' RD Pollard. SITP-1405 psig. Open well to test 2-4.2 perfs. Flow well and get 4 -point test: 1704 mcfpd at 1350 psi, 24,14 mcfpd at 320 psi, 3029 mcfpd at 1300 psi, and 4360 mcfpd at 1278 psig w/ no water. (Flowing well to sales thru compressor). - 10/22/11—RU Pollard. Closed sleeve at 3549'. Open, sleeve at 3354. SITP-1270 psig. Flow Carya 2-4 l perfs at 3319-23' and 3326-31' for 1:20 hr. Rate and pressure stabilized at 2041 mcfpd at 900 psi w/ 0.3 bbl water (9.2 per). SI. Built up to 1270 psi n in 10 minutes and stabilized. RU Pollard. Closed sleeve at 3354' and opened sliding sleeve at 2741' to test Carva 2-3 perfs at 2688-98' and 2825-30'. SITP-1060 psi. Open well and flow for 45 minutes—stabilized-at 1019 mc$d at 570 nsia w/ no water. SI well for 1 hr—SITP-1050 psi and building slowly. RU Pollard and closed sleeve at 2741'. Pulled PX prong and plug at 3766'. SITP-1495 psi RD Pollard Open well to sales from Carya 2-6 perfs at 3856-66'. Ed Jones 11/11/11 Aurora Gas, LLC Cook Inlet Nicola! Creek Unit NCU#10 Sperry Drilling Services Definitive Survey Report 14 September, 2011 HALLIBURTON Sperry Drilling Services Halliburton Company Definitive Survey Report Company: Aurora Gas, LLC Local Co-ordinate Reference: Well NCU#10 Project: Cook Inlet TVD Reference: NCU #10 @ 266.00ft (250 + 16) Site: Nicolai Creek Unit MD Reference: NCU #10 @ 266.00ft (250 + 16) Well: NCU#10 North Reference: True Wellbore: NCU#10 Survey Calculation Method: Minimum Curvature Design: NCU #10 Database: Sperry EDM .16 PRD Project Cook Inlet, COOK INLET BASIN Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well NCU#10 Well Position +N/ -S 0.00 ft +E/ -W 0.00 ft Position Uncertainty 0.00 ft Wellbore NCU#10 Northing: 2,571,972.10 ft Latitude: Easting: 242,963.07 ft Longitude: Wellhead Elevation: 0.00 it Ground Level: Magnetics Model Name Sample Date Declination Dip Angle C) V) - BGGM2011 8/15/2006 19.50 73.78 - Design NCU #10 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: Vertical Section: Depth From (TVD) +N/ -S +E/ -W (ft) (ft) (ft) 25.40 0.00 0.00 Survey Program Date 9/14/2011 From To (ft) (ft) Survey (Wellbore) Tool Name Description 100.00 660.00 NCU #10 (BLIND) (NCU#10) BLIND Blind drilling 704.06 4,772.76 NCU 410 (MWD) (NCU410) MWD MWD - Standard Survey -- MD Inc Azi TVD TVDSS +N/ -S (ft) V) (I (ft) (ft) (ft) 25.40 0.00 0.00 25.40 -240.60 0.00 100.00 0.00 358.73 100.00 -166.00 0.00 200.00 0.00 358.73 200.00 -66.00 0.00 300.00 0.00 358.73 300.00 34.00 0.00 400.00 0.00 358.73 400.00 134.00 0.00 500.00 0.00 358.73 500.00 234.00 0.00 660.00 0.00 358.73 660.00 394.00 0.00 704.06 0.41 86.58 704.06 438.06 0.01 735.52 0.28 147.24 735.52 469.52 -0.05 766.98 0.18 27.19 766.98 500.98 -0.07 798.38 0.85 320.53 798.38 532.38 0.15 829.83 2.38 314.28 829.81 563.81 0.79 861.26 4.11 314.69 861.19 595.19 2.04 9/14/2011 9:54.00AM 25.40 Direction C) 319.70 61' 1'55.015 N 151 ° 26' 58.48 W 250.00 ft , Field Strength (nT) 55,588 Survey Start Date 08/22/2011 09/13/2011 Map Map Vertical +E1 -W Northing Easting DLS Section (ft) (ft) (ft) (°1100') (ft) Survey Tool Name 0.00 2,571,972.10 242,963.07 0.00 0.00 UNDEFINED 0.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 0.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 0.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 0.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 0.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 0.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 0.16 2,571,972.11 242,963.22 0.93 -0.09 MWD (2) 0.31 2,571,972.05 242,963.38 1.16 -0.24 MWD (2) 0.38 2,571,972.02 242,963.44 1.28 -0.30 MWD (2) 0.25 2,571,972.25 242,963.32 2.54 -0.04 MWD (2) -0.37 2,571,972.90 242,962.72 4.89 0.84 MWD (2) -1.63 2,571,974.18 242,961.48 5.50 2.61 MWD (2) Page 2 COMPASS 2003.16 Build 71 Halliburton Company Definitive Survey Report Company: Aurora Gas, LLC Local Co-ordinate Reference: Well NCU#10 Project: Cook Inlet TVD Reference: NCU #10 @ 266.00ft (250 + 16) Site: Nicolai Creek Unit MD Reference: NCU #10 @ 266.00ft (250 + 16) Well: NCU#10 North Reference: True Wellbore: NCU#10 Survey Calculation Method: Minimum Curvature Design: NCU #10 Database: Sperry EDM .16 PRD Survey MD Inc Azi TVD TVDSS +++E/-W+E/- Map Northing Map Eastin 9 DLS 1 Vertical Section (ft) V) 0 O (ft) (ft) (ft) (ft) (ft) (ft) (°/100') (ft) Survey Tool Name 892.71 6.93 321.91 892.49 626.49 4.32 -3.61 2,571,976.51 242,959.56 9.22 5.63 MWD (2) 924.11 8.57 321.50 923.61 657.61 7.65 -6.23 2,571,979.88 242,957.01 5.23 9.86 MWD (2) 955.50 8.88 322.88 954.63 688.63 11.41 -9.15 2,571,983.71 242,954.17 1.19 14.62 MWD (2) 986.92 10.22 324.79 985.62 719.62 15.62 -12.22 2,571,987.99 242,951.20 4.38 19.82 MWD (2) 1,018.37 10.74 322.23 1,016.54 750.54 20.22 -15.62 2,571,992.66 242,947.90 2.22 25.52 MWD (2) 1,049.89 11.11 319.54 1,047.49 781.49 24.85 -19.39 2,571,997.37 242,944.23 2.00 31.49 MWD (2) 1,081.34 12.89 319.45 1,078.25 812.25 29.82 -23.64 2,572,002.44 242,940.09 5.66 38.03 MWD (2) 1,112.90 15.14 320.99 1,108.87 842.87 35.70 -28.52 2,572,008.42 242,935.34 723 45.67 MWD (2) 1,144.29 17.79 321.41 1,138.97 872.97 42.63 -34.09 2,572,015.48 242,929.93 8.45 54.57 MWD (2) 1,175.69 19.91 320.94 1,168.69 902.69 50.54 -40.46 2,572,023.52 242,923.74 6.77 64.71 MWD (2) 1,207.11 21.33 319.42 1,198.09 932.09 59.03 -47.54 2,572,032.17 242,916.84 4.83 75.77 MWD (2) 1,238.59 21.76 317.58 1,227.37 961.37 67.69 -55.21 2,572,040.99 242,909.37 2.54 87.33 MWD (2) 1,269.97 22.85 315.79 1,256.41 990.41 76.35 -63.38 2,572,049.83 242,901.40 4.09 99.22 MWD (2) 1,301.38 25.04 317.56 1,285.11 1,019.11 85.63 -72.12 2,572,059.30 242,892.87 7.34 111.95 MWD (2) 1,332.84 26.57 317.73 1,313.43 1,047.43 95.75 -81.34 2,572,069.62 242,883.87 4.87 125.63 MWD (2) 1,364.18 26.65 316.70 1,341.45 1,075.45 106.05 -90.88 2,572,080.13 242,874.56 1.49 139.66 MWD (2) 1,395.64 26.68 317.16 1,369.57 1,103.57 116.36 -100.52 2,572,090.66 242,865.15 0.66 153.76 MWD (2) 1,427.03 27.27 317.00 1,397.54 1,131.54 126.79 -110.21 2,572,101.30 242,855.69 1.89 167.98 MWD (2) 1,458.51 27.45 316.51 1,425.50 1,159.50 137.33 -120.13 2,572,112.05 242,846.01 0.92 182.43 MWD (2) 1,489.51 27.53 316.82 1,453.00 1,187.00 147.74 -129.94 2,572,122.68 242,836.43 0.53 196.72 MWD (2) 1,521.31 27.09 316.82 1,481.26 1,215.26 158.38 -139.93 2,572,133.53 242,826.68 1.38 211.29 MWD (2) 1,552.66 27.44 316.69 1,509.12 1,243.12 168.84 -149.77 2,572,144.21 242,817.08 1.13 225.64 MWD (2) 1,584.07 27.44 317.09 1,537.00 1,271.00 179.41 -159.66 2,572,154.99 242,807.42 0.59 240.09 MWD (2) 1,615.43 27.11 316.77 1,564.87 1,298.87 189.90 -169.47 2,572,165.71 242,797.84 1.15 254.45 MWD (2) 1,646.85 27.57 315.92 1,592.78 1,326.78 200.34 -179.43 2,572,176.36 242,788.12 1.92 268.85 MWD (2) 1,678.30 27.49 316.07 1,620.67 1,354.67 210.80 -189.53 2,572,187.04 242,778.25 0.34 283.36 MWD (2) 1,709.72 27.29 316.03 1,648.57 1,382.57 221.21 -199.56 2,572,197-67 242,768.45 0.64 297.78 MWD (2) 1,741.20 27.07 315.43 1,676.57 1,410.57 231.50 -209.60 2,572,208.18 242,758.65 1.12 312.13 MWD (2) 1,772.61 26.82 315.74 1,704.57 1,438.57 241.67 -219.56 2,572,218.57 242,748.91 0.91 326.33 MWD (2) 1,835.49 26.12 315.77 1,760.86 1,494.86 261.75 -239.12 2,572,239.07 242,729.81 1.11 354.29 MWD (2) 1,866.95 26.04 315.70 1,789.12 1,523.12 271.65 -248.77 2,572,249.19 242,720.38 0.27 368.08 MWD (2) 1,898.41 26.03 314.94 1,817.39 1,551.39 281.47 -258.48 2,572,259.22 242,710.89 1.06 381.85 MWD (2) 1,976.32 25.93 316.56 1,887.42 1,621.42 305.92 -282.29 2,572,284.18 242,687.62 0.92 415.90 MWD (2) 2,007-90 25.48 316.25 1,915.88 1,649.88 315.84 -291.74 2,572,294.31 242,678.40 1.49 429.57 MWD (2) 2,039.36 25.94 317.59 1,944.22 1,678.22 325.81 -301.06 2,572,304.48 242,669.30 2.36 443.20 MWD (2) 2,070.86 26.84 317.99 1,972.44 1,706.44 336.18 -310.46 2,572,315.06 242,660.13 2.91 457.20 MWD (2) 2,102.27 26.91 319.26 2,000.46 1,734.46 346.83 -319.85 2,572,325.92 242,650.98 1.84 471.39 MWD (2) 2,165.07 27.28 319.72 2,056.37 1,790.37 368.58 -338.42 2,572,348.07 242,632.89 0.68 499.99 MWD (2) 2,196.47 26.87 319.91 2,084.33 1,818.33 379.50 -347.65 2,572,359.19 242,623.91 1.33 514.29 MWD (2) 2,227.94 26.68 318.61 2,112.42 1,846.42 390.24 -356.90 2,572,370.14 242,614.90 1.96 528.46 MWD (2) 9/142011 9:54:OOAM Page 3 COMPASS 2003.16 Build 71 Halliburton Company Definitive Survey Report Company: Aurora Gas, LLC Local Co-ordinate Reference: Well NCU#10 Project: Cook Inlet Site: Nicolai Creek Unit TVD Reference: NCU #10 @ 266.00ft (250 + 16) Well: NCU#10 MD Reference: NCU #10 @ 266.00ft (250 + 16) Wellbore: NCU#10 North Reference: True Design: NCU #10 Survey Calculation Method: Minimum Curvature Database: .Sperry EDM .16 PRD Survey M MD Incn Azi TVD TVDSS +N/_g +E/ -w Map Northing Map Easting DLS Vertical Section (,) (ft) (ft) (ft) ft () (ft) (ft) (°/100') (ft) Survey Tool Name 2,259.42 26.75 318.99 2,140.54 1,874.54 400.89 -366.22 2,572,380.99 242,605.82 0.59 542.61 MWD (2) 2,290.84 26.10 317.89 2,168.68 1,902.68 411.35 -375.49 2,572,391.65 242,596.78 2.59 556.59 MWD (2) 2,322.36 25.69 318.15 2,197.03 1,931.03 421.59 -384.70 2,572,402.09 242,587.80 1.35 570.35 MWD (2) 2,353.78 25.69 318.42 2,225.35 1,959.35 431.75 -393.76 2,572,412.45 242,578.97 0.37 583.97 MWD (2) 2,385.26 26.70 318.09 2,253.59 1,987.59 442.12 -403.02 2,572,423.02 242,569.95 3.24 597.86 MWD (2) 2,416.77 26.63 318.36 2,281.75 2,015.75 452.67 -412.44 2,572,433.78 242,560.76 0.44 611.99 MWD (2) 2,448.20 26.51 318.57 2,309.86 2,043.86 463.19 -421.76 2,572,444.50 242,551.68 0.48 626.05 MWD (2) 2,479.65 26.20 317.87 2,338.04 2,072.04 473.60 -431.06 2,572,455.12 242,542.61 1.40 640.01 MWD (2) 2,511.15 26.82 318.74 2,366.23 2,100.23 484.10 -440.41 2,572,465.82 242,533.49 2.32 654.06 MWD (2) 2,574.07 27.67 318.22 2,422.17 2,156.17 505.67 459.50 2,572,487.80 242,514.88 1.40 682.86 MWD (2) 2,605.59 28.13 318.53 2,450.03 2,184.03 516.69 -469.30 2,572,499.04 242,505.33 1.53 697.60 MWD (2) 2,637.04 28.21 318.70 2,477.75 2,211.75 527.83 -479.12 2,572,510.40 242,495.76 0.36 712.45 MWD (2) 2,668.35 28.20 317.99 2,505.34 2,239.34 538.89 -488.95 2,572,521.67 242,486.18 1.07 727.24 MWD (2) 2,699.76 28.09 317.70 2,533.04 2,267.04 549.87 -498.89 2,572,532.87 242,476.48 0.56 742.05 MWD (2) 2,731.27 28.24 316.77 2,560.82 2,294.82 560.79 -508.99 2,572,544.01 242,466.62 1.47 756.91 MWD (2) 2,762.73 28.57 317.40 2,588.49 2,322.49 571.75 -519.18 2,572,555.19 242,456.68 1.42 771.86 MWD (2) 2,794.31 28.31 316.68 2,616.26 2,350.26 582.76 -529.43 2,572,566.42 242,446.68 1.36 786.88 MWD (2) 2,825.77 28.05 316.86 2,643.99 2,377.99 593.58 -539.61 2,572,577.47 242,436.74 0.87 801.72 MWD (2) 2,857.23 28.40 317.96 2,671.71 2,405.71 604.54 -549.67 2,572,588.64 242,426.92 1.99 816.59 MWD (2) 2,888.67 28.52 317.47 2,699.35 2,433.35 615.62 -559.75 2,572,599.95 242,417.09 0.84 831.56 MWD (2) 2,920.12 28.50 317.72 2,726.99 2,460.99 626.71 -569.88 2,572,611.25 242 407.22 0.38 846.56 MWD (2) 2,965.92 28.47 316.85 2,767.24 2,501.24 642.76 -584.69 2,572,627.63 242,392.76 0.91 868.38 MWD (2) 2,997.36 28.19 316.21 2,794.92 2,528.92 653.58 -594.96 2,572,638.68 242,382.74 1.31 883.28 MWD (2) 3,028.79 28.19 317.34 2,822.62 2,556.62 664.40 -605.12 2,572,649.72 242,372.81 1.70 898.11 MWD (2) 3,060.21 27.78 318.55 2,850.37 2,584.37 675.35 -615.00 2,572,660.88 242,363.18 2.23 912.85 MWD (2) 3,091.53 27.90 317.53 2,878.06 2,612.06 686.23 -624.78 2,572,671.97 242,353.64 1.57 927.47 MWD (2) 3,122.90 27.75 318.62 2,905.81 2,639.81 697.12 -634.56 2,572,683.08 242,344.11 1.69 942.10 MWD 2 3,154.33 28.06 317.90 2,933.58 2,667.58 708.10 -644.36 2,572,694.27 242,334.56 1.46 956.81 MWD (2) 3,185.77 27.21 318.14 2,961.43 2,695.43 718.94 -654.11 2,572,705.32 242,325.05 2.73 971.38 MWD (2) 3,217.21 27.48 318.31 2,989.36 2,723.36 729.71 -663.73 2,572,716.30 242,315.67 0.89 985.82 MWD (2) 3,248.69 26.94 319.24 3,017.36 2,751.36 740.53 -673.22 2,572,727.34 242,306.42 2.18 1,000.21 MWD (2) 3,280.14 27.12 319.65 3,045.37 2,779.37 751.39 -682.51 2,572,738.40 242,297.37 0.82 1,014.50 MWD (2) 3,311.57 26.98 317.71 3,073.36 2,807.36 762.13 -691.94 2,572,749.34 242,288.18 2.84 1,028.79 MWD (2) 3,343.03 27.13 318.29 3,101.38 2,835.38 772.76 -701.52 2,572,760.18 242,278.84 0.96 1,043.10 MWD (2) 3,374.48 26.30 317.61 3,129.47 2,863.47 783.26 -710.99 2,572,770.89 242,269.61 2.81 1,057.23 MWD (2) 3,405.97 26.40 317.92 3,157.69 2,891.69 793.61 -720.38 2,572,781.44 242,260.45 0.54 1,071.20 MWD (2) 3,437.36 26.21 317.17 3,185.83 2,919.83 803.87 -729.77 2,572,791.91 2,791.91 242,251.29 1.22 1,085.10 MWD (2) 3,468.86 26.94 317.62 3,214.00 2,948.00 814.25 -739.31 2,572,802.49 242,241.98 2.40 1,099.18 MWD (2) 3,500.48 26.56 318.86 3,242.24 2,976.24 824.86 -748.79 2,572,813.31 242,232.74 2.14 1,113.40 MWD (2) 3,531.82 25.95 318.16 3,270.35 3,004.35 835.25 -757.97 2,572,823.90 242,223.79 2.18 1,127.27 MWD (2) 9/1412011 9:54:O0AM Page 4 COMPASS 2003.16 Build 71 Halliburton Company Definitive Survey Report Company: Aurora Gas, LLC Local Co-ordinate Reference: Well NCU#10 Project: Cook Inlet ND Reference: NCU #10 c(_@ 266.00ft (250 + 16) Site: Nicolai Creek Unit MD Reference: NCU #10 Q 266.00ft (250 + 16) Well: NCU#10 North Reference: True Wellbore: NCU#10 Survey Calculation Method: Minimum Curvature Design: NCU #10 Database: Sperry EDM .16 PRD Survey MD Incn Azi ND NDSS +N/-S+E/-WMap Northing Map Easting DLS Vertical Section (ft) (°) (ft) (ft) (ft) (ft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,563.19 25.69 317.87 3,298.58 3,032.58 845.40 -767.11 2,572,834.26 242,214.88 0.92 1,140.92 MWD (2) 3,594.54 26.33 318.44 3,326.76 3,060.76 855.64 -776.28 2,572,844.70 242,205.93 2.19 1,154.67 MWD (2) 3,625.78 26.35 317.25 3,354.76 3,088.76 865.92 -785.58 2,572,855.18 242,196.86 1.69 1,168.52 MWD (2) 3,657.21 26.50 318.29 3,382.90 3,116.90 876.28 -794.98 2,572,865.74 242,187.69 1.55 1,182.50 MWD (2) 3,688.62 26.43 318.36 3,411.02 3,145.02 886.73 -804.29 2,572,876.40 242,178.62 0.24 1,196.49 MWD 2 3,720.05 26.53 318.03 3,439.15 3,173.15 897.18 -813.63 2,572,887.05 242,169.51 0.57 1,210.50 MWD (2) 3,751.45 25.92 317.44 3,467.32 3,201.32 907.45 -822.96 2,572,897.52 242,160.41 2.11 1,224.37 MWD (2) 3,782.91 26.60 316.55 3,495.53 3,229.53 917.63 -832.46 2,572,907.91 242,151.15 2.50 1,238.27 MWD (2) 3,814.33 26.18 317.61 3,523.68 3,257.68 927.85 -841.97 2,572,918.34 242,141.86 2.01 1,252.22 MWD (2) 3,845.74 26.57 316.14 3,551.82 3,285.82 938.04 -851.51 2,572,928.73 242,132.55 2.42 1,266.16 MWD (2) 3,877.20 26.13 317.37 3,580.01 3,314.01 948.21 -861.07 2,572,939.11 242,123.21 2.23 1,280.10 MWD (2) 3,908.67 26.11 316.67 3,608.27 3,342.27 958.34 -870.52 2,572,949.45 242,114.00 0.98 1,293.94 MWD (2) 3,940.18 26.37 317.45 3,636.53 3,370.53 968.54 -880.01 2,572,959.86 242,104.73 1.37 1,307.86 MWD (2) 3,971.70 26.56 319.85 3,664.75 3,398.75 979.09 -889.28 2,572,970.61 242,095.69 3.45 1,321.90 MWD (2) 4,003.20 26.65 319.12 3,692.91 3,426.91 989.81 -898.45 2,572,981.53 242,086.77 1.08 1,336.01 MWD (2) 4,034.76 26.76 320.22 3,721.11 3,455.11 1,000.62 -907.63 2,572,992.54 242,077.83 1.60 1,350.19 MWD (2) 4,066.21 26.09 320.51 3,749.27 3,483.27 1,011.40 -916.55 2,573,003.52 242,069.15 2.17 1,364.18 MWD (2) 4,097.70 26.06 320.24 3,777.56 3,511.56 1,022.06 -925.38 2,573,014.37 242,060.56 0.39 1,378.02 MWD (2) 4,129.17 26.09 319.61 3,805.82 3,539.82 1,032.65 -934.29 2,573,025.15 242,051.89 0.89 1,391.86 MWD (2) 4,160.66 26.30 318.85 3,834.08 3,568.08 1,043.17 -943.36 2,573,035.88 242,043.05 1.26 1,405.76 MWD (2) 4,192.12 25.88 320.19 3,862.33 3,596.33 1,053.70 -952.35 2,573,046.59 242,034.30 2.30 1,419.59 MWD (2) 4,223.56 25.86 319.89 3,890.62 3,624.62 1,064.21 -961.16 2,573,057.30 242,025.73 0.42 1,433.31 MWD (2) 4,255.02 26.04 319.00 3,918.91 3,652.91 1,074.67 -970.11 2,573,067.96 242,017.01 1.36 1,447.07 MWD (2) 4,286.55 26.02 319.18 3,947.24 3,681.24 1,085.13 -979.17 2,573,078.61 242,008.18 0.26 1,460.91 MWD (2) 4,317.95 26.15 319.76 3,975.44 3,709.44 1,095.62 -988.14 2,573,089.30 241,999.45 0.91 1,474.72 MWD (2) 4,349.34 25.48 320.28 4,003.70 3,737.70 1,106.10 -996.92 2,573,099.97 241,990.90 2.25 1,488.39 MWD (2) 4,380.84 25.82 319.66 4,032.10 3,766.10 1,116.54 -1,005.69 2,573,110.60 241,982.36 1.38 1,502.02 MWD (2) 4,412.34 25.94 320.30 4,060.44 3,794.44 1,127.07 -1,014.53 2,573,121.32 241,973.75 0.97 1,515.77 MWD (2) 4,443.61 25.74 321.51 4,088.58 3,822.58 1,137.64 -1,023.13 2,573,132.08 241,965.40 1.80 1,529.40 MWD (2) 4,475.15 25.05 320.57 4,117.07 3,851.07 1,148.16 -1,031.63 2,573,142.79 241,957.13 2.53 1,542.92 MWD (2) 4,506.69 25.53 319.46 4,145.59 3,879.59 1,158.49 -1,040.29 2,573,153.30 241,948.70 2.14 1,556.39 MWD (2) 4,537.96 25.56 319.50 4,173.81 3,90281 1,168.74 -1,049.05 2,573,163.74 241,940.17 0.11 1,569.87 MWD (2) 4,569.56 25.60 320.07 4,202.31 3,936.31 1,179.16 -1,057.86 2,573,174.35 241,931.59 0.79 1,583.52 MWD (2) 4,600.89 25.24 319.47 4,230.60 3,964.60 1,189.42 -1,066.54 2,573,184.81 241,923.14 1.41 1,596.97 MWD (2) 4,631.17 25.05 318.72 4,258.02 3,992.02 1,199.15 -1,074.97 2,573,194.72 241,914.93 1.23 1,609.83 MWD (2) 4,663.67 24.52 319.21 4,287.52 4,021.52 1,209.42 -1,083.91 2,573,205.19 241,906.22 1.75 1,623.45 MWD (2) 4,695.04 24.99 318.90 4,316.01 4,050.01 1,219.35 -1,092.52 2,573,215.30 241,897.83 1.55 1,636.59 MWD (2) 4,726.31 25.47 318.55 4,344.30 4,078.30 1,229.36 -1,101.31 2,573,225.51 241,889.26 1.61 1,649.92 MWD (2) 4,757.76 25.10 317.54 4,372.73 4,106.73 1,239.35 -1,110.29 2,573,235.70 241,880.51 1.81 1,663.34 MWD (2) 4,772.76 25.30 318.11 4,386.31 4,120.31 1,244.09 -1,114.58 2,573,240.52 241,876.32 2.10 1,669.73 MWD 2 9/1412011 9.54.00AM Page 5 COMPASS 2003.16 Build 71 Halliburton Company Definitive Survey Report Company: Aurora Gas, LLC Local Co-ordinate Reference: Well NCU#10 Project: Site: Cook Inlet Nicolai Creek Unit TVD Reference: NCU #10 @ 266.00ft (250 + 16) Well: NCU#10 MD Reference: NCU #10 @ 266.00ft (250 + 16) Wellbore: NCU#10 North Reference: True (°1100') (ft) Survey Tool Name Survey Calculation Method: Minimum Curvature Design: NCU #10 Database: Sperry EDM .16 PRD Survey 0.00 - _ - -- — MD Inc Azi TVD TVDSS +N/ -S +E1_W Map Northing Map Easting DLS Vertical Section (ft) (ft) (ft) (ft) (ft) (ft) (°1100') (ft) Survey Tool Name 4,830.00 25.30 318.11 4,438.06 4,172.06 1,262.30 -1,130.91 2,573,259.09 241,860.40 0.00 1,694.18 PROJECTED to TO 911412011 9.54:00AM Page 6 COMPASS 2003.16 Build 71 STATE OF ALASKA ALASKA �. L AND GAS CONSERVATION COMMISSr.,N REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Li Repair Well Plug PerforationsOther Stimulate Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver❑ Time Extension❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re-enter Suspended Well ❑ 2. Operator AURORA GAS, LLC 4. Well Class Before Work: Name: 5. Permit to Drill Number: Development Exploratory❑ 204-183 3. Address: 1400 WEST BENSON, STE. 410, Stratigraphic❑ Service 6. API Number: ANCHORAGE, AK 99503 7. KB Elevation (ft): 50-283-20108-00 333 9. Well Name and Number: THREE MILE CREEK #1 8. Property Designation: 10. Field/Pool(s): ADL -388233 11. Present Well Condition Summary: Three Mile Creek Gas Field --Beluga Undefined Gas Pool otal Depth measured 8016 feet true vertical 8180 feet Effective Depth measured 5410 feet true vertical 5304 feet Casing Length Size MD Structural Conductor 110' 110' Surface 2438' 9-5/8" 2438' Intermediate Production 8133' 7" 8113' Liner Plugs (measured) Junk (measured) TVD Burst Collapse 110' 1530 psi 520 psi 2438' 3520 psi 2020 psi 7944' 4270 psi 3120 psi Perforation depth: Measured depth: 2570' - 4972' True Vertical depth: 2453' 4785' Tubing: (size, grade, and measured depth) L-80 3498, Packers and SSSV (type and measured depth) 2502'& 3455' 12. Stimulation or cement squeeze summary: Intervals treated (measured): None. Treatment descriptions including volumes used and final pressure: Added perforations at 4962-72', 4874-68', 4884-94', 4786-96', 3812-22', and 3728-38' MD (4805-3568' TVD). No other treatment. 13. Representative Daily Average Production or Injection Data Prior to well opOil-Bbl 130 Gas-Mcf 0.2 Water -Bbl 0 Casing Pressure Tubing Pressure operation: 0 80 Subsequent to operation: 0 295 2 0 130 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory❑ Development Service ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ❑ as WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: Contact Ed Jones 1311-209 Printed Name J. Edward Jones Title President Signature Phone 281-495-9957 Date 11/17/2011 Form 10-404 Revised 04/2006 Submit Original Only 4urewa Gas, LLC November 17, 2011 Mr. Daniel T. Seamount, Jr., Chair C Alaska Oil and Gas Conservation Commission N CiFlY6 333 West 7th Avenue, Suite 100 OV 22 2011 Anchorage, AK 99501-3539 AINke oil & Gas ,C017s. C�'rr��►ess�o� ed yr RE: Nicolai Creek Field, North Undefined Gas Pool, Nicolai Creek Unit #10 Permit Number: 210-127 (revised), API No. 50-283-20145-00-00 Form 10-407 Report of Sundry Well Operations Dear Commissioner Seamount: Enclosed is the Form 10-407, Well Completion Report and Log, for the subject well, Nicolai Creek Unit #10, with Daily Operations Summary, Well Schematic Diagram, Side-wall Core Analysis, and Directional Survey attached. Well logs and additional core analyses will be submitted under separate cover. Please let me know if you need additional information. Sincerely, YJ. Edward Jones President Cc: Temple Davidson, Petroleum Land Manager, Department of Natural Resources Attachments (4) 6051 North Course Drive, Suite 200 - Houston, Texas 77072 - (281) 495-9957 - Fax (281) 495-1473 1400 West Benson Blvd., Suite 410 - Anchorage, Alaska 99503 - (907) 277-1003 - Fax (907) 277-1006 Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket # CO -11-34. The application of Aurora Gas, LLC for an exception to the spacing requirements of 20 AAC 25.055, for the drilling, completion and regular production of a development gas well within 3000 feet of wells that are, or may be capable of, producing from the same pool, Aurora Gas, LLC, by a letter received August 24, 2011, requests the Alaska Oil and Gas Conservation Commission (Commission) issue all order for an exception to the spacing requirements of 20 AAC 25.055 to drill the Nicolai Creek Unit No. 10 development gas well in the Nicolai Creek Unit within 3000 feet of wells are, or may be capable of, producing from the same pool. The proposed surface and bottom -hole locations of the well are as follows: Nicolai Creek Unit No. 10 Surface Location: 1799' from the north line and 1504' from the west line of Section 20, Ti IN, R.12W, Seward Meridian (S.M.). Bottom -hole Location: 593' from the north line and 434' from the west line of Section 20, TI IN, R I 2W, S.M. The Commission has tentatively scheduled a public hearing on this application for October 6, 2011 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7"' Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the Commission no later than 4:30 p.m. on September 19, 2011. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the hearing, call 793-1221 after September 26, 2011. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7" Avenue, Suite 100, Anchorage, Alaska 99501, Comments must be received no later than 4:30 p.m. on October 4, 2011, except that, if a hearing is held, comments must be received no later than the conclusion of the October 6, 2011 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the Commission's Special Assistant Jody Colombie, at 793-1221, no later r� than September 20, 2011. Daniel T. &5amount, Jr. Chair, Commissioner ems` ('7 FL, I A 21�., ZL! SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COM U SSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 September 9, 2011 Mr. J. Edward Jones Executive Vice President Aurora Gas, LLC 1400 West Benson Boulevard, Suite 410 Anchorage, AK 99503 Re: Nicolai Creek Unit No. 10 Request Dear Mr. Jones: By this correspondence, the Alaska Oil and Gas Conservation Commission (AOGCC) clarifies the cover letter attached to the approved application for the Permit to Drill for the Nicolai Creek Unit No. 10 well (Permit No. 210-127 revised). To ensure a consistent policy concerning changing well completion practices, the AOGCC modifies its approval as follows: 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. Aurora Gas, LLC assumes the liability of any protest to the spacing exception that may occur. All other conditions associated with approval of this Permit to Drill remain unchanged. Sincerely, `7 Cathy P Foerstteer"" Commissioner AA Aurora Gas, LLC www. aurorapower. com September 7, 2011 Mr. Daniel T. Seamount, Jr. Chair, Commissioner Alaska Oil and Gas Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501-3539 RE: Nicolai Creek Field, Undefined Gas Pool, Nicolai Creek Unit #10 Aurora Gas, LLC Permit No: 210-127 (Revised) Dear Commissioner Seamount: RECD EU SEP 0 7 2011 > � tit an Can. E ssion Anchmas Re: Docket # CO -11-34. The application of Aurora Gas, LLC for an exception to the spacing requirements of 20 AAC 25.055, for the drilling, completion and regular production of a development gas well within 3000 feet of wells that are, or may be capable of, producing from the same pool. Aurora Gas, LLC (Aurora) is finalizing the drilling of the subject well and hereby respectfully requests an exception to one condition of the August 4th approval by the AOGCC of the APD, which states "Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception." While Aurora will not be in full compliance with regulation 20 AAC 25.055 until the spacing exception Conservation Order is approved, it is requested that Aurora be allowed to perforate prospective pay in the well prior to the hearing and approval of the subject spacing exception Conservation Order. This request is to perforate only (i.e., not test or produce) prior to approval of the Order and is based on economics: the plan is to complete the well with multiple selective completions, and to do so safely, requires a rig on the well. To release and demobilize the rig following drilling and to bring it back and rig up for the perforating and completion will cost an estimated additional $400,000- 500,000 compared to perforating and running the completion now before the rig is released following drilling. If this exception is granted, the plan would be to perforate using casing guns with overbalanced brine in the well, run the multiple packers on tubing, install the tree, and release the rig. The well would be swabbed in and tested following the approval of the spacing exception Conservation Order. The additional cost is to mobilize the rig back from the Three Mile Creek #3 well, rig it up, and demobilize a second time; all of this taking an additional 8-12 days and costing $30,000-40,000 per day plus trucking. Aurora's request to allow perforating is also based on the following: 1) Aurora holds all the oil and gas leases within the 3000' radius of the bottom -hole location; 2) the spacing order was required due to the proximity of the well to the Nicolai Creek Unit #3 well, also operated by Aurora, not by distance from lease lines (i.e., the bottom -hole location is more than 1500' from all lease lines); and 3) the Mental Health Trust, the Lessor within the 3000' radius who was not originally given notice, does not object to the perforating prior to receiving the spacing exception (Aurora is the Lessee of the subject lease, MHT 6051 North Course Drive, Suite 200 • Houston, Texas 77072 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 9300066)—see attached copy of email from Mike Franger. Nonetheless, Aurora assumes all the liability of any protest to the spacing exception. This timing issue is a matter of an oversight on the part of Aurora— when the bottom -hole location was changed, we failed to realize that the notification of mineral owners within 3000' was required by 20 AAC 25.055(d)(1) and had not been done in the case of the Mental Health Trust. For the reasons given above, Aurora hereby respectfully requests the Commission's approval to perforate the subject well, but not test or produce, prior to the approval of the spacing exception Conservation Order. Please let me know of your decision as soon as practical, if possible by Friday, September 9th, as the rig will be preparing to move by early next week, if Aurora is not allowed to perforate before approval of the Order. Thank you for your consideration. Sincerely, L"64 6."'Edward (Ed) Jones Executive Vice President Aurora Gas, LLC Copies: Greg Jones & Mike Franger, Mental Health Trust AOGCC (4) Ed Jones From: Franger, James M (DNR) [mike.franger@alaska.gov] Sent: Wednesday, September 07, 2011 1:26 PM To: jejones@aurorapower.com Subject: NCU 10 Well Ed, Thanks for the information describing the bottom hole location of the NCU No. 10 well. The TLO does not object to Aurora perforating the well in advance of receiving the spacing exception for this well, with the understanding that no testing or production will occur until the spacing exception issue is settled. Mike Franger Senior Resource Manager Trust Land Office 2600 Cordova Street, Suite 100 Anchorage, Alaska 99503 isl No virus found in this message. Checked by AVG - xvv"v.avg.com Version: 10.0. 1392 /Virus Database: 1520/3881 -Release Date: 09/06/11 1 FF ZUT11 O AIA29-1 SEAN PARNELL, GOVERNOR AVIASKA OIL ArID 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 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Nicolai Creek Field, Undefined Gas Oil Pool, Nicolai Creek Unit # 10 Aurora Gas, LLC Permit No: 210-127 (revised) Surface Location: 1799' FNL, 1504' FWL, Bottomhole Location: 593' FNL, 434' FWL Dear Mr. Webb: SEC. 20, T11N, R12W, SM , SEC. 20, T1 IN, R12W, SM Enclosed is the approved application for permit to drill the above referenced development well. 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. 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, Daniel T. Seamount, Jr. I _ Chair DATED this q day of August, 2011. cc: Department of Fish 8s Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) STATE OF ALASKA AL ..A OIL AND GAS CONSERVATION COW. _ON PERMIT TO DRILL 20 AAC 25.005 /0 WOA- !11[' 1 2 1011 1a. Type of Work: Drill Q Redrill ❑ Re-entry ❑ 1b. Proposed Well Class: Development -Oil ❑ Service - Winj ❑ Single Zone ❑ > Stratigraphic Test ❑ Development - Gas ❑., Service - Supply ❑ Multiple Zone ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ .1c. Specify if well is pro061fid illilll$ Coalbed Gas ❑ . Gas Hydrates ❑ Shale Gas ❑ 2. Operator Name: Aurora Gas LLC 5. Bond: Blanket Q Single Well ❑ Bond No. NZS 429815 11. Well Name and Number: Nicolai Creek Unit #10 3. Address: 1400 W. Benson Blvd Suite 410 Anchorage AK 99503 6. Proposed Depth: MD: 4,470' TVD: 4,200' 12. Field/Pool(s): Nicolai Creek Unit North Undefined Gas 4a. Location of Well (Governmental Section): Surface: T. 11 N., R. 12 W., S.M., Section 20 1,799' FNL and 1,504' FWL Top of Productive Horizon: 1,355' FNL and 1,114' FWL, Sec. 20 Total Depth: 593' FNL and 434' FWL, Sec. 20 l( �I) VS W/ S%'( o l 7. Property Designation: ADL -63279 8. Land Use Permit: CIRI 13. Approximate Spud Date: 8/1/2011 9. Acres in Property: 320 14. Dist. to Nearest Property: 434' west to ADL 391472 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 242963 y- 2571970 Zone- 4 10. KB Elevation above MSL: 265 feet GL Elevation above MSL: 249 feet 15. Distance to Nearest Well„Open to Same Pool: SE'207' +/- 16. Deviated wells: Kickoff depth: 650' +/- feet Maximum Hole Angle: 42 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 2,142 psi Surface: 1,722 psi 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) driven 13-3/8” 68# Structural n/a 80' 0 0 80' 80' n/a 12-1/4" 9-5/8" 40 136# K-55 BTC / LTC 650' 0 0 650' 650' 12 ppg Type 1, 176 sx. 8-1/2" 7" 23/26# K-55 / L-80 LTC 4,470' 0 0 4,470' 4,200' 12.5 ppg Type G, 93 sx. lead 15.8 ppg Type 1, 422 sx. tail - 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): 0 Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD &TVD (ft): Approximately 850' MD/TVD to 4,320' MD / 4,060' TVD. Actual pert s will be determined from log analysis. 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Program ❑✓ Time v. Depth Plot Q Shallow Hazard Analysis Q Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements❑✓ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct. Contact Printed Name Bruce D. Webb Title Manager, Land and Regulatory Affairs Signature Phone (907) 277-1003 Date July 11, 2011 Commission Use Only Permit to Drill Number: 210-127 API Number: 50 - 283 - 20145 - 00 - 00 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 in shales: [] Other:—t e St- f j D PE `O 3 0 0 0 - Samples req'd: Yes ❑ No Q Mud log req'd: Yes Q No ❑ PK✓ 1uft4 LO ZO AA Zs, 03$ (k� (L) v��p�, HZS measures: Yes �] No0 Directional sv req'd: Yes Q No E]vcK.�E Ceh.e %s �prove,�. _ APPROVED BY THE COMMISSION le DA . 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 Purl Aurora Gas, LLC NCU #10 Drilling Program NICOLAI CREEK UNIT #10 Nicolai Creek Unit #10 is a 4450' grass-roots well targeting Beluga and Tyonek Gas Production. It is located in the Nicolai Creek Gas Field, directionally drilled from the #3 well and facility pad to a BHL +/-1580' northwest of the surface location, which is about 208' northwest of the #3 well. It will target Beluga and Upper Tyonek Carya 2-1 thru 2-5 sands that have produced more than 4 BCF from the Nicolai Creek Field. Pre Rig work 1. The site was surveyed in 2006 for the Nicolai Creek #10—pad GL elevation is about 249'. The conductor was driven to 80' from GL at that time. 2. Add gravel as necessary to the old pad area configured for AWS #1 with drilling support. Build sufficient emergency cuttings containment for planned drilling program, and build containment for diverter line. 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. 80' of 13-3/8" conductor has been pre-installed. Install 13-5/8" VG LOK head. 3. Rig up diverter & mud loggers. Test & calibrate all PVT / gas sensor equipment. Provide 48 -hr notice to AOGCC inspectors for chance to witness diverter test. 4. Notify AOGCC & pertinent agencies when ready to start drilling operations. 5. Prepare spud mud system / weight up to 10.0 ppg. Load, strap & drift 700'+/- of 9-5/8" 40# BTC and 36# LTC surface casing. Locate cross-over (20' short joint with LTC box X BTC pin ). (Drift all casing and X -O with 8-1/2" drift on rack before running - 53.5# casing will not drift, and we have 4-5 joints in the Moquawkie yard). 6. PU 12-1/4" mill tooth bit & drill to –650', using 8" stabilized BHA. 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. 7. Make wiper trip to conductor to condition hole for running 9-5/8" surface casing, Run ESS. POOH, LD 12-1/4" BHA. 8. Run & cement new 9-5/8" 40# K-55 BTC & 36# K-55 LTC casing @ 650-700', installing 1 centralizer / joint centered on the 1st 4 joints above shoe, & 1 centralizer every 2nd joint across the collars there after. Shoe joint connection at float shoe and float collar must be Baker -Locked. Cementing will be single stage using 12.0 ppg accelerated light -weight Type I cement at 100% excess volume. Overdisplace by 1 bbl if plug Prepared by Ed Jones Page 1 of 12 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program doesn't bump. Be prepared to treat cement returns with retarder. Leave 6" to 18" of cement in cellar to seal bottom. 9. RD cementers, nipple down diverter, cut casing and install I V 3M wellhead. W.O.C. 10. RU and test 11" 3M BOP stack and 5M choke manifold. Test stack and surface equipment to 000- psi. Pressure test 9-5/8" casing to 1,500 psi for 15 minutes or as required on ap&6 ed Permit to Drill. Mud weight to drill out should be at least 10 ppg at this point, do not cut back if higher, up to 10.5 ppg. RU directional drillers. 11. PU 8-1/2" Mill Tooth Bit & RIH w/ 6-%" collars. Drill out shoetrack. Swap out mud system from spud mud to 10.0 ppg EZ (KCl -polymer) mud --system, drill 20' new formation. Pull back into shoe & perform FIT / LOT up to (16.0. ppg EMW maximum with low volume test pump. Record results. POH & LD 6-1/4" collars. 12. PU 4-3/" directional drilling assembly w/ 8-1/2" bit, motor & DIR MWD assembly, non - mag DC's, jars & HWDP as specified by DD proposal. 13. RIH and directionally drill 8-1/2" hole. 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, prepare to short trip if needed. Anticipated mud weights required are 9.5 ppg – 10.0 ppg. If no significant mud logs shows are seen by 1600', gradually cut back mud weight to 9.5 ppg to drill thru partially depleted sands to 1900-2400' (TVD). Be ready to add LCM to mud. Do not exceed fracture gradient determined in step 11. Finish drilling to 4450' MD (4200' TVD) TD per DD directional plan, or other depth as directed by Aurora Gas geologist (may as shallower depending upon top of Carya 2-5). If possible, adjust TD to put cement head on floor. While drilling, load, tally & drift 7" casing (83 jts of 23# K-55 and balance 26# L-80—all LTC) on racks. 14. Condition hole, short trip and prepare for running wireline logs. 15. POOH, rack back drillstring and RU wireline BOP'S and lubricator and logging tools. Log 9-5/8" cased hole section w/gamma ray sensor, Log OH section with logging suite including resistivity and porosity logs as directed by Aurora Gas. RD wireline. 16. RIH w/ 8-1/2" drilling assembly to TD & condition hole for running 7" casing. Ensure cementing head has proper connections or proper cross-over and is available for quick rig UP. 17. POOH while laying down drillpipe & BHA, RU to run casing. Verify cementer's equipment is ready. 18. Install 7" pipe rams. 19. Run +/-1050' of 7" 26# L-80 LTC casing, then 3400' of 7" 23# K-55 LTC casing, installing 1 centralizer per joint centered on 1St 4 joints above shoe, 1 centralizer every 2nd joint in open hole & every 3rd joint inside surface casing (use Turbolator centralizers below/thru each pay sand and where directional inclination is greater than 10 deg). Shoe joint connection at float shoe, float collar & stage tool landing collar must be Baker -Locked (80' shoetrack). While running casing, fill every 3rd joint. Be prepared to wash to bottom. Prepared by Ed Jones Page 2 of 12 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program 20. RU cementers, cement per attached cementing program from TD to surface. A sufficient amount of accelerated 12.5 ppg light weight Class G lead cement will be pumped to cover from 1450' up thru the annulus from the 9-5/8" shoe to surface.` This will be followed by sufficient amount of 15.8 ppg Type I tail blend cement to cover from TD back to 1450'. Excess will be calculated using caliper log data—top of tail slurry will be determined following evaluation of the logs. Plug will be bumped with clean 3% KCl brine. If possible reciprocate pipe while displacing cement. Land casing & WOC. 21. RD cementers, nipple down stack, land casing in slips & cut casing. 22. 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. 23. Install 2-7/8" pipe rams. 24. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Displace well w/ filtered KCl/NaCl 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 25. 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 7" 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 guns, RD wireline. 26. 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. 27. 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 3 (or 4) hydraulic packers w/ sliding sleeves between packers and an expansion joint between 2nd and 3rd hydraulic 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 3'600 psi (or as required) to test and to set packers. Install BPV. ND BOP. NU and test tree. 28. Pull BPV. 29. 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 and set in X nipple in on/off tool below deepest sliding sleeve. Prepared by Ed Jones Page 3 of 12 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program 30. Add needed KCl water cushion to tubing (1000' above sliding sleeve or as determined by engineer). Open deepest sliding sleeve. Test well as per Step 29. DO NOT KILL, but close sliding sleeve. 31. Repeat Step 30 for remaining shallower intervals (2 or 3). 32. Open zones for initial production (depending upon pressures and test results—likely the 2-4.2 and deeper)—flow to clean up. Shut in. Set BPV in tree or x -plug above sliding sleeves in well. Release rig, RD, and move rig. 33. Pull BPV or plug. Run 4 -point test of initial production zone as per Procedure provided at that time. RD test unit. 34. Clear & clean location. Hand well over to production. 35. File completion reports with proper agencies. Site Access Nicolai Creek Unit #10 will be accessible via existing gravel roads currently in use to support production operations at the Nicolai Creek Unit #3 well and production facility (right off Shirleyville-to-Tyonek gravel road). Rig Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the Nicolai Creek Unit #10 well. The Alaska Oil & Gas Conservation Commission has information on this rig and equipment as it has been in use for the last 9 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 will be drilled vertically and the survey program will consist of multi - shot survey and supplemented with 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). The 8-1/2" production hole will be drilled directionally. For all directional work, directional MWD will be utilized with supplemental wellbore surveys taken at maximum of 100 ft intervals as needed, per AAC 25.050 (a)(1). Logging Program Mud loggers will be on site for the duration of drilling activities. Schlumberger will provide wireline logging services as proposed below: Prepared by Ed Jones Page 4 of 12 Rev. 1.0 Aurora Gas, LLC Nicolai Creek Unit #10 Proposed Logging Program NCU #10 Drilling Program Well Section De the t) OH CH Log Type 12-1/4" Surface 0'— 650' v N/A: No open -hole logs planned for surface at this time. GR only in cased hole. 8-1/2"' Production 650'-4450' v Platform Express: Array Induction, Compensated Neutron, Hole Litho -Density, SP, GR, and possibly DSI and/or FMI/DM.. Also MDT or XPT and, possibly, Sidewall cores. 7" Csg surface --4450' v GR/CBL/CCL Surface — TD Open 96'— 4450' v Mud Logging Services Hole BOP Equipment Aurora Gas, LLC will use the same BOP system they have been using for the last (6) years 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 & 12" diverter line will be used: an exception to 20 AAC 25.035 (c)(1)(A), requiring that the diverter line outlet size be at least 16" diameter or (B) at least as large as the hole size being drilled, will be requested. 8-1/2" Production Hole An 1 I" 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' Glacial Wash and Beluga Formation Base Fluid Fresh or produced water Density 10-11 ppg PV 10-30 YP 30-40 API Filtrate not controlled Prepared by Ed Jones Page 5 of 12 Rev. 1.0 Aurora Gas, LLC Total Solids 15-25% Bentonite Gel (Aquagen mud system Drilling Fluid Properties While Drilling 8-1/2" interval to 4450' Beluga and Tvonek Formations Base Fluid 6% KCI , Density 9.5 —11,0 ppg PV 22 — 30 YP 20-30 API Filtrate < 5 Total Solids 10-15% Polymer (EZ Mud) mud system Drilling Fluid Handling System Shale Shaker, Mud Cleaner, Centrifuge, PVT monitors Drilling Waste Disposal NCU #10 Drilling Program The cuttings will be mixed with saw dust, 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 or injected into the Aspen 1 Disposal well. 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 The conductor for Nicola Creek Unit #10 has been installed by drilling/driving the 13-3/8" pipe to 80' from GL/96' 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 & 40# & K-55 BTC Surface Casing Analysis and Cementing Program The 9-5/8" surface casing will be cemented from the proposed setting depth of 650' to surface with an accelerated 12.0 ppg accelerated light -weight Type I cement w/ poz powder, glass spheres, and gas control. Capacities: Prepared by Ed Jones Page 6 of 12 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program 9-5/8" 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: 47' x .0773 bbl/ft = 3.6-bbls Total Surface Cement Volume#72.0 bbl __111 Actual volumes to be re -calculated at time of running casing due to potential variation in actual depth from planned. Cement S stem Weight (PDO bbl cf sx Accelerated Light Type I 12.0 72.0 404 176 Yield 2.30 cf/sx Please see attached 9-5/8" surface casing analysis and specifications. 7" 23# K-55 LTC & 26# L-80 LTC Production Casing Cementing Program The 7" production casing will be cemented in fully from the proposed set depth of 4450' to surface. A 12.5 ppg accelerated lead light -weight "G" cement (2.47 cf/sk yield) followed with a 15.8 ppg Type I tail cement (1.17 cf/sk yield) 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 pay). This program is designed to insure the intended perforating / production intervals are isolated with tail blend (except possible shallow Beluga, so Lead cement will also have sufficient strength for perforating). Capacities: 7" 23## csg capacity = 0.0393 bbl/ft 7" 26# csg capacity= 0.0382 bbl/ft 7" csg X 8-1/2" OH capacity =.0226 bbl/ft 7# csg X 9-5/8" 40# annular capacity =.0282 bbl/ft Lead System: 9-5/8" x 7" Csg: 650'+ (1450-650') 8-1/2" open hole 650'x.0282 bbls/ft x 1 (0% excess) = 18.33 bbls Lead Cement Volume = 18.3 bbl+800' X .0226 X 1.25 (25% excess) = 40.9 bbl Tail System: 8-1/2" OH x 7" Csg: 4450-1450 = 3000' 3000'x .0226 bbl/ft x 1.25 (25% excess) =84.75 bbls Shoe Joint: 85' x .0382 bbl/ft = 3.3 bbls Total Tail Cement Volume = 88.1 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 NCU #10 Drilling Program Cement System Type Cement Weight (ppg) bbl cf sx Lead @ 2.47 cf/sx G 12.5 40.9 229.5 93 ' Tail @ 1.17 cf/sx Type I 15.8 88.1 494 422 Please see attached 7" production casing analysis and specifications. Pressure Calculations Maximum Anticipated Surface Pressure From offset wells in the immediate area and actual pressure data from the nearby offset well Nicolai Creek Unit #10, maximum anticipated bottom -hole pressures should not exceed �2142:/'psi at 4200 ft. (TVD). Pressures measured at the Nicolai Creek Unit #11 well indicated a maximum gradient of —.0.51 psi/ft with a bottom -hole pressure of 1196 psi recorded at 2,344' (maximum observed from XPT). Maximum anticipated surface pressures "MASP" can be calculated by subtracting the gas gradient of .1 psi/ft from pore pressure gradient of .51 psi / ft and multiplying by the total TVD depth. Maximum Anticipated Surface Pressure = (.51 - .1) * 4200' = 1722 psi A leak -off test to 15.4 ppg EMW @ 650' was conducted while drilling Nicolai Creek #11. Assuming casing shoe strength of 16.0 ppg EMW (or 0.83 psi/ft), our estimated Maximum Allowable Surface Pressure during the 8-142" interval is expected to be Maximum Allowable Surface Pressure = (.83-.1)*650'=475 psi Drilling Hazards Shallow gas Shallow gas is a known hazard which exists throughout the area. The northwest side of Cook E: 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 H2Sn 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, Prepared by Ed Jones Page 8 of 12 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program allowing the coal to stabilize. Re-enter, drill some more, and pull back out again. Continue in this fashion until successfully through the coal bed. The key word in successfully drilling the coal beds is patience. It should be remembered that coals behave plastically, and will flow under the weight of the overburden. The deeper the coal, the more pronounced this tendency becomes. For this reason it is critical to maintain the proper weight and viscosity of the drilling fluid to properly remove the coal cuttings, and to hold flowing coals in place. Again, heed the recommended drilling fluid program and advice offered by the on-site Mud Engineer. Well Proximity Risk There are 2 existing wellbores within a mile of this location: the Nicolai Creek Unit #3, 208' southeast of this surface location and the P&A'd Nicolai Creek #5, about 3200' west of this location. The #5 was a straight hole, and the BHL of the #10 is expected to stay more than 2500' northeast of it. The #3 was straight hole to with no more than 2 degrees deviation down to 4000' (it was later sidetracked at about 6900' to the southwest), but due to the close proximity to the proposed #10, a gyro survey was run in 2006 to below 2000', and this data is incorporated into the directional plan by the directional services company. 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 NICOLAI CREEK UNIT #10 PossiBLE *, Configuration (exact`' determined by logs and tests) tr.* Drill 12-1/4" Hole to 650' sy 4� w ' 2-7/8" x 7" annulus to be t- �. displaced over to inhibited packer fluid through sleeve (ii),1445' " f rospective Pay Tops eluga — 500-1300' TVD arya 2-1.1 — 1660' MD / 1560' TVD arya 2-2.1 — 2060' MD/1930' TVD V arya 2-2.3 — 2440' MD/ 2290' TVD* arya 24.2— 2560' MD / 2410' TVD arya 2-5.1 — 3120' MD/2935' TVD arya 2-6 — 3670' MD/ 3150' TVD �';` ..: Upper Beluga rforation Intervals to be ermined by open -hole logging. *�� L. Beluga H Carya 2-1 �� ' "*� <r a Carya 2-2 , rill 8-1/2" Hole to 4450' MD Estimated PBTD @ 4360' �' D P B C C C C C C Pe det NCU #10 Drilling Program 2 7/8 6.5# 8rd EUE J-55 Tubing 13-3/8" 68# Structural Conductor driven to 94' GL 9-5/8" 40 & 36# Surface Casing set at 650' Cement w/12. ppg Type I Accelerated Hydraulic Set Packer @ 800' Sliding Sleeve @ 1200' Hydraulic Set Packer @ 1400' Carya 2-4.2 & 2-5.1 Sliding Sleeve @ —I500' ydraulic Packer @ 1600' Sl H Sl iding Sleeves @ 1800' ydraulic Packer @ 2000' iding Sleeve @ 2400' 27/8 Tool" 6.5# EUE 8rd Tubing w/ On -Off on Mechanical Packe r@ 2500'MD w/ 2.31 profile X nipple 7" 23# K-55 & 26# L-80 Casing to 4450' MD/ 4200' (TVD) Prepared by Ed Janes Page 10 of 12 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program 0 -500 -1000 -1500 -2000 -t00 a W -3000 -3500 -4000 -4500 -5000 NICOLAI CREEK 10 DRILLING TIME DAY Days 1-3: Drill 12-1/4" Hole Days 3-6: Run and cement 9-5/8" casing Day 6: Test casing, drill out w/ 8-1.-/2" bit and run FIT, kick off directional 8-1/2" hole. Days 6-15: drill directional 8-1/2" hole to 4450' MD / 4200' TVD Days 15-16: Log Days 17-18: Run 7" casing and cement. Days: 19---: Complete and test well. r — * Flan __........._n ed.... Prepared by Ed Jones Page 11 of 12 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program NICOLAI CREEK UNIT #10 Summary of Drilling Hazards POST THIS NOTICE IN DOGHOUSE v There is potential for abnormal pressured shallow gas. There is potential for stuck pipe in coals encountered while drilling from surface to TD. Short trips as dictated by drilling trends. v There is no H2S risk anticipated for this well. v Due to potential for shallow gas kick, very little response time will be afforded to respond. PVT and gas detection systems must be fully operational and functioning at all times, visual flow checks and pit level monitoring are critical. CONSULT THE NICOLAI CREEK UNIT #10 WELL PLAN FOR ADDITIONAL INFORMATION Prepared by Ed Jones Page 12 of 12 Rev. 1.0 NCU 10 Casing Properties Design Verification Casing Performance Properties: Aurora Gas Nicolai Creek Unit #10 Tensile Strength Section Internal Collapse Size Weight Yield Resistance TVD MD MW MASP Inches lb/ft Grade Cnxn (Psi s ij Joint Body Length ft RKB ft RKB tppgj BF si 9-5/8" 40 K-55 BTC 3950 2570 843000 630000 650 650 650 10.5 0.84 475 9-5/8" 36 K-55 LTC 3520 2020 489000 56000 650 650 650 10.5 0.84 455 7" 23 K-55 LTC 4360 3270 341000 3�00 4470 4200 4470 11 0.83 1722 7" 26 L-80 LTC 7240 5410 -119000 604000 4470 4200 4470 11 0.83 1722 Design Safety Factor* Size Tensile Burst Collapse 9-5/8,40 38.6 8.3 8.9 9-5/8,36 24.9 7.7 7.0 7,23 4.0 2.5 1.6 7,26 5.4 ' 4.2 2.7 * 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 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 114�7, p 4fZoo provide shoe strength in the event of a kick. 7" ^ U' MD /..5< TVD Production casing to stabilize and isolate producing interval for production operations. --InlGl� Ed Jones 7/14/2010 Rev 6/23/11 Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Plan NCU#10 NCU#10 Plan: wp04 Standard Proposal Report 27 July, 2011 HALLIBURTON Sperry Drilling Services Aurora Gas, LLC Project: Cook Inlet Site: Nicolai Creek Unit Well: Plan NCU#10 Wellbore: NCU#10 Plan: wp04 (Plan NCU#10/NCU#10) Beluga SECTION DETAILS Sec MD Inc Azi TVD +N/ -S +E/ -W DLeg TFace VSec Target 1 244.1 0.00 0.00 244.1 0.0 0.0 0.00 0.00 0.0 2 650.0 0.00 0.00 650.0 0.0 0.0 0.00 0.00 0.0 3 670.0 0.00 0.00 670.0 0.0 0.0 0.00 0.00 0.0 4 1327.6 26.30 319.78 1304.7 113.2 -95.8 4.00 319.78 148.3 5 4557.3 26.30 319.78 4200.0 1206.0 -1020.0 0.00 0.00 1579.5 TD WELLBORE TARGET DETAILS (MAP CO-ORDINATES) Name TVD +N/ -S +E/ -W Northing Easting Shape TD 4200.0 1206.0 -1020.0 2573175.94 241942.69 Point WELL DETAILS: Plan NCU#10 Ground Level: 250.0 +N/ -S +E/ -W Northing Easting Latittude Longitude Slot 0.0 0. 571969.97 242962.66 61° 1'54.994 #61' 26'58.486 W a - - - - Start 20.0 hold at 650.0 MD 9 5/8" ` 900 Start DLS 4.00 TFO 319.78 Tsuga 2-7 1200 Start 3229.7 hold at 1327.6 MD Carya 2.1 1500 1800 c _�E; 21 0 0 0 L Q24 N 0 U 27 N F - 3900 REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan NCU#10, Grid North Vertical (ND) Reference: 072711 @ 266.0ft (250+16) Measured Depth Reference: 072711 @ 266.0ft (250+16) Calculation Method: Minimum Curvature SURVEY PROGRAM 2011-07-27T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 244.1 644.0 wp04 (NCU#10) BLIND 644.0 4557.3 wp04 (NCU#10) MWD Carya 2-1.1- - - - COMPANY DETAILS: Aurora Gas, LLC CASING DETAILS Drilling Carya 2-1-2- - - TVD MD Name Size Calculation Method: Minimum Curvature 4199.8 45557.0 7" 7 50.0 9 5/8" 9-5/8 Error System: ISCWSA 4199.Scan Method: Tray. Cylinder North Carya 2-2 1- - Error Surface: Elliptical Conic Warning Method: Rules Based Carya 2-2.2 Carya 2.-2.3 Carya 2-4.2 Carya 2-5.1 Carya /2-6 FORMATION TOP DETAILS TVDPal1MDPath Formation 490.0 490.0 Beluga 1031.0 1034.9 Tsuga 2-7 1239.0 1255.1 Carya 2.1 1563.0 1615.7 Carya 2-1.1 1753.0 1827.6 Carya 2-1.2 1932.0 2027.3 Carya 2-2.1 2078.0 2190.2 Carya 2-2.2 2288.0 2424.4 Carya 2.-2.3 2407.0 2557.2 Carya 2-4.2 2933.0 3143.9 Carya 2-5.1 3151.0 3387.1 Carya 2-6 4067.0 4408.9 Min TD 4200.0 4557.3 Max TD Plan NCU#10/wp04 Min TO 7" Max TD- _ TO at 4557.3 HALLIBURTON Sperry Drilling Services -600 -300 0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 Vertical Section at 319.78° (600 ft/in) I SECTION DtTAILS Sec MD Inc Azi TVD +N/ -S +E/ -W DLeg TFace VSec Targ ,Aurora Gas, LLC 1 244.1 0.00 0.00 244.1 0.0 0.0 0.00 0.00 0.0 2 650.0 0.00 0.00 650.0 0.0 0.0 0.00 0.00 0.0 3 670.0 0.00 0.00 670.0 0.0 0.0 0.00 0.00 0.0 4 1327.6 26.30 319.78 1304.7 113.2 -95.8 4.00 319.78 148.3 Project: Cook Inlet 5 4557.3 26.30 319.78 4200.0 1206.0 -1020.0 0.00 0.00 1579.5 TD Site: Nicolai Creek Unit Well: Plan NCU#10 Wellbore: NCU#10 Plan: wp04 (Plan NCU#10/NCU#10) WELL DETAILS: Plan NCU#10 Ground Level: 250.0 SURVEY PROGRAM +N/ -S +E/ -W Northing Easting Latittude Longitude Slot 0.0 0.0 2571969.97 242962.66 61° V54.994 1161° 26'58.486 W 2011-07-27700:00:00 Validated: Yes Version: WELLBORE TARGET DETAILS (MAP CO-ORDINATES) Depth From Depth To Survey/Plan Tool Name TVD +N/ -S +E/ -W Northing Easting Shape 244.1 644.0 vvp04 (NCU#10) 644.0 4557.3 vvp04 (NCU#10) BLIND MWD TO 4200.0 1206.0 -1020.0 2573175.94 241942.69 Point COMPANY DETAILS: Aurora Gas, LLC Drilling Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Tray. Cylinder North Error Surface: Elliptical Conic Warning Method: Rules Based CASING DETAILS ND MD Name Size 650.0 650.0 95/8" 9-518 4199.8 4557.0 7" 7 REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Plan NCU#10, Grid North Vertical (ND) Reference: 072711 @ 266.Oft (250+16) Measured Depth Reference: 072711 @ 266.Oft(250+16) Calculation Method: Minimum Curvature West( -)/East(+) (300 11/in) 1350 -1200 -1050 -900 -750 -600 -450 -300 -150 0 1200 Plan NCU#10/wp04 - - - 1050 TD at 4557.3 c 0 750 0 c 600 s C/o) 450 150] HALLIBURTON Sperry Drilling Services 0 150 1350 1200 1050 cr 750 C 0 600 + C 450 300 150 9 5/8" 0 Start DLS 4.00 TFO 319.78 , Start 20.0 hold at 650.0 MD -150 -1800 -1650 -1500 -1350 -1200 -1050 -900 -750 -600 -450 -300 -150 0 150 West( -)/East(+) (300 Win) HALLIBURT ON Database: ..Sperry EDM Prod .161 Company: Aurora Gas, LLC Project: Cook Inlet Site: Nicolai Creek Unit Well: Plan NCU#10 Wellbore: NCU#10 Design: wp04 Local Co-ordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Company Standard Proposal Report Well Plan NCU#10 072711 @ 266.Oft (250+16) 072711 @ 266.0ft (250+16) Grid Minimum Curvature Project Cook Inlet, COOK INLET BASIN Map System: Geo Datum: US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) System Datum: Mean Sea Level Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Sample Date Declination Dip Angle Field Strength F Nicolai Creek Unit (°) Position: Northing: From: Map Easting: Position Uncertainty: 0.0 ft Slot Radius: 2,565,258.00ft Latitude: 241,507.00ft Longitude: 0" Grid Convergence: 61° 0' 48.597 N 151° 27' 24.998 W -1 27 ° (nT) BGGM2005 5/15/2006 Well Plan NCU#10 73.77 Well Position +N/ -S 0.0 ft Northing: 2,571,969.97 ft Latitude: 61° 1'54.994 N +E/ -W 0.0 ft Easting: 242,962.66 ft Longitude: 151° 26'58.486 W Position Uncertainty 0.0 ft Wellhead Elevation: 266.0 ft Ground Level: 250.Oft Wellbore NCU#10 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2005 5/15/2006 19.65 73.77 55,548 - - -� Design wp04 Audit Notes: Version: Phase: PLAN Tie On Depth: 244.1 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (ft) (ft) (ft) (I 244.1 0.0 0.0 319.78 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (ft) (°) (°) (ft) ft (ft) (ft) (°/100ft) (°/100ft) (°/100ft) 244.1 0.00 0.00 244.1 -219 0.0 0.0 0.00 0.00 0.00 0.00 650.0 0.00 0.00 650.0 384.0 0.0 0.0 0.00 0.00 0.00 0.00 670.0 0.00 0.00 670.0 404.0 0.0 0.0 0.00 0.00 0.00 0.00 1,327.6 26.30 319.78 1,304.7 1,038.7 113.2 -95.8 4.00 4.00 -6.12 319.78 4,557.3 26.30 319.78 4,200.0 3,934.0 1,206.0 -1,020.0 0.00 0.00 0.00 0.00 7/27/2011 3:19:56PM Page 2 COMPASS 2003.16 Build 71 Database: ..Sperry EDM Prod .161 Map Company: Aurora Gas, LLC +N/ -S +E/ -W Project: Cook Inlet DLS (ft) (ft) Site: Nicolai Creek Unit -21.90 0.0 Well: Plan NCU#10 242,962.66 0.00 0.0 Wellbore: NCU#10 242,962.66 0.00 0.0 Design: wp04 242,962.66 0.00 0.0 Planned Survey 2,571,969.97 242,962.66 0.00 0.0 Measured 2,571,969.97 242,962.66 Vertical 0.0 Depth Inclination Azimuth Depth TVDss (ft) (°) (°) (ft) ft 244.1 0.00 0.00 244.1 -21.9 300.0 0.00 0.00 300.0 34.0 400.0 0.00 0.00 400.0 134.0 490.0 0.00 0.00 490.0 224.0 Beluga -24.4 2,571,998.86 242,938.22 4.00 500.0 0.00 0.00 500.0 234.0 600.0 0.00 0.00 600.0 334.0 650.0 0.00 0.00 650.0 384.0 Start 20.0 hold at 650.0 MD - 9 5/8" -76.1 670.0 0.00 0.00 670.0 404.0 Start DLS 4.00 TFO 319.78 242,874.63 4.00 700.0 1.20 319.78 700.0 434.0 800.0 5.20 319.78 799.8 533.8 900.0 9.20 319.78 899.0 633.0 1,000.0 13.20 319.78 997.1 731.1 1,034.9 14.60 319.78 1,031.0 765.0 Tsuga 2-7 -202.3 2,572,209.21 242,760.32 0.00 1,100.0 17.20 319.78 1,093.6 827.6 1,200.0 21.20 319.78 1,188.0 922.0 1,255.1 23.41 319.78 1,239.0 973.0 Carya 2.1 -288.2 2,572,310.71 242,674.47 0.00 1,300.0 25.20 319.78 1,279.9 1,013.9 1,327.6 26.30 319.78 1,304.7 1,038.7 Start 3229.7 hold at 1327.6 MD -342.6 2,572,375.05 1,400.0 26.30 319.78 1,369.6 1,103.6 1,500.0 26.30 319.78 1,459.3 1,193.3 1,600.0 26.30 319.78 1,548.9 1,282.9 1,615.7 26.30 319.78 1,563.0 1,297.0 Carya 2-1.1 0.00 1,700.0 26.30 319.78 1,638.6 1,372.6 1,800.0 26.30 319.78 1,728.2 1,462.2 1,827.6 26.30 319.78 1,753.0 1,487.0 Carya 2-1.2 1,900.0 26.30 319.78 1,817.9 1,551.9 2,000.0 26.30 319.78 1,907.5 1,641.5 2,027.3 26.30 319.78 1,932.0 1,666.0 Carya 2-2.1 2,100.0 26.30 319.78 1,997.2 1,731.2 2,190.2 26.30 319.78 2,078.0 1,812.0 Carya 2-2.2 2,200.0 26.30 319.78 2,086.8 1,820.8 2,300.0 26.30 319.78 2,176.5 1,910.5 2,400.0 26.30 319.78 2,266.1 2,000.1 2,424.4 26.30 319.78 2,288.0 2,022.0 Carya 2.-2.3 Halliburton Company Standard Proposal Report Local Co-ordinate Reference: Well Plan NCU#10 TVD Reference: 072711 @ 266.Oft (250+16) MD Reference: 072711 @ 266.Oft (250+16) North Reference: Grid Survey Calculation Method: Minimum Curvature Vert Section 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.31 5.90 18.43 37.85 46.24 64.06 96.94 117.86 136.33 148.32 180.40 224.71 269.03 275.98 313.34 357.65 369.90 401.97 446.28 458.38 490.60 530.55 534.91 579.22 623.54 634.36 7127/2011 3:19.56PM Page 3 COMPASS 2003.16 Build 71 Map Map +N/ -S +E/ -W Northing Easting DLS (ft) (ft) (ft) (ft) -21.90 0.0 0.0 2,571,969.97 242,962.66 0.00 0.0 0.0 2,571,969.97 242,962.66 0.00 0.0 0.0 2,571,969.97 242,962.66 0.00 0.0 0.0 2,571,969.97 242,962.66 0.00 0.0 0.0 2,571,969.97 242,962.66 0.00 0.0 0.0 2,571,969.97 242,962.66 0.00 0.0 0.0 2,571,969.97 242,962.66 0.00 0.0 0.0 2,571,969.97 242,962.66 0.00 0.2 -0.2 2,571,970.21 242,962.46 4.00 4.5 -3.8 2,571,974.47 242,958.85 4.00 14.1 -11.9 2,571,984.03 242.950.76 4.00 28.9 -24.4 2,571,998.86 242,938.22 4.00 35.3 -29.9 2,572,005.27 242,932.80 4.00 48.9 -41.4 2,572,018.88 242,921.29 4.00 74.0 -62.6 2,572,043.98 242,900.06 4.00 90.0 -76.1 2,572,059.96 242,886.55 4.00 104.1 -88.0 2,572,074.05 242,874.63 4.00 113.2 -95.8 2,572,083.21 242,866.88 4.00 137.7 -116.5 2,572,107.70 242,846.17 0.00 171.6 -145.1 2,572,141.54 242,817.55 0.00 205.4 -173.7 2,572,175.37 242,788.94 0.00 210.7 -178.2 2,572,180.68 242,784.45 0.00 239.2 -202.3 2,572,209.21 242,760.32 0.00 273.1 -231.0 2,572,243.04 242,731.70 0.00 282.4 -238.9 2,572,252.39 242,723.80 0.00 306.9 -259.6 2,572,276.87 242,703.09 0.00 340.7 -288.2 2,572,310.71 242,674.47 0.00 350.0 -296.0 2,572,319.95 242,666.66 0.00 374.6 -316.8 2,572,344.54 242,645.86 0.00 405.1 -342.6 2,572,375.05 242,620.05 0.00 408.4 -345.4 2,572,378.38 242,617.24 0.00 442.3 -374.0 2,572,412.21 242,588.62 0.00 476.1 -402.7 2,572,446.04 242,560.01 0.00 484.4 -409.7 2,572,454.31 242,553.02 0.00 Vert Section 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.31 5.90 18.43 37.85 46.24 64.06 96.94 117.86 136.33 148.32 180.40 224.71 269.03 275.98 313.34 357.65 369.90 401.97 446.28 458.38 490.60 530.55 534.91 579.22 623.54 634.36 7127/2011 3:19.56PM Page 3 COMPASS 2003.16 Build 71 Database: ..Sperry EDM Prod .161 TVD Reference: Company: Aurora Gas, LLC North Reference: Grid Project: Cook Inlet DLS Vert Section (ft) Site: Nicolai Creek Unit (ft) 2,089.75 Well: Plan NCU#10 -431.3 2,572,479.88 Wellbore: NCU#10 667.85 529.3 -447.6 Design: wp04 0.00 693.19 543.8 Planned Survey 2,572,513.71 242,502.78 0.00 712.16 Measured -488.5 2,572,547.55 Vertical 0.00 Depth Inclination 611.4 Azimuth Depth TVDss (ft) (°) (°) (ft) ft 2,500.0 26.30 319.78 2,355.7 2,089.7 2,557.2 26.30 319.78 2,407.0 2,141.0 Carya 2-4.2 2,572,682.88 242,359.70 0.00 933.73 2,600.0 26.30 319.78 2,445.4 2,179.4 2,700.0 26.30 319.78 2,535.0 2,269.0 2,800.0 26.30 319.78 2,624.7 2,358.7 2,900.0 26.30 319.78 2,714.3 2,448.3 3,000.0 26.30 319.78 2,804.0 2,538.0 3,100.0 26.30 319.78 2,893.6 2,627.6 3,143.9 26.30 319.78 2,933.0 2,667.0 Carya 2-5.1 882.1 -746.1 2,572,852.05 242,216.62 3,200.0 26.30 319.78 2,983.3 2,717.3 3,300.0 26.30 319.78 3,072.9 2,806.9 3,387.1 26.30 319.78 3,151.0 2,885.0 Carya 2-6 2,572,953.55 242,130.77 0.00 1,288.24 3,400.0 26.30 319.78 3,162.6 2,896.6 3,500.0 26.30 319.78 3,252.2 2,986.2 3,600.0 26.30 319.78 3,341.8 3,075.8 3,700.0 26.30 319.78 3,431.5 3,165.5 3,800.0 26.30 319.78 3,521.1 3,255.1 3,900.0 26.30 319.78 3,610.8 3,344.8 4,000.0 26.30 319.78 3,700.4 3,434.4 4,100.0 26.30 319.78 3,790.1 3,524.1 4,200.0 26.30 319.78 3,879.7 3,613.7 4,300.0 26.30 319.78 3,969.4 3,703.4 4,400.0 26.30 319.78 4,059.0 3,793.0 4,408.9 26.30 319.78 4,067.0 3,801.0 Min TD 4,500.0 26.30 319.78 4,148.7 3,882.7 4,557.0 26.30 319.78 4,199.8 3,933.8 7" 4,557.3 26.30 319.78 4,200.0 3,934.0 TD at 4557.3 - Max TD -TD Halliburton Company Standard Proposal Report Local Co-ordinate Reference: Well Plan NCU#10 TVD Reference: 072711 @ 266.Oft (250+16) MD Reference: 072711 @ 266.Oft (250+16) North Reference: Grid Survey Calculation Method: Minimum Curvature Targets Target Name - hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (ft) (ft) (ft) (ft) (ft) TD - plan hits target center 0.00 360.00 4,200.0 1,206.0 -1,020.0 2,573,175.94 241,942.69 - Point 7/27/2011 3:19.56PM Page 4 COMPASS 2003.16 Build 71 Map Map +N/ -S +E/ -W Northing Easting DLS Vert Section (ft) (ft) (ft) (ft) 2,089.75 509.9 -431.3 2,572,479.88 242,531.39 0.00 667.85 529.3 -447.6 2,572,499.22 242,515.03 0.00 693.19 543.8 -459.9 2,572,513.71 242,502.78 0.00 712.16 577.6 -488.5 2,572,547.55 242,474.16 0.00 756.48 611.4 -517.1 2,572,581.38 242,445.55 0.00 800.79 645.3 -545.7 2,572,615.21 242,416.93 0.00 845.10 679.1 -574.4 2,572,649.05 242,388.31 0.00 889.42 712.9 -603.0 2,572,682.88 242,359.70 0.00 933.73 727.8 -615.5 2,572,697.74 242,347.13 0.00 953.20 746.8 -631.6 2,572,716.71 242,331.08 0.00 978.05 780.6 -660.2 2,572,750.55 242,302.47 0.00 1,022.36 810.1 -685.1 2,572,780.02 242,277.54 0.00 1,060.96 814.4 -688.8 2,572,784.38 242,273.85 0.00 1,066.67 848.3 -717.4 2,572,818.22 242,245.23 0.00 1,110.99 882.1 -746.1 2,572,852.05 242,216.62 0.00 1,155.30 915.9 -774.7 2,572,885.88 242,188.00 0.00 1,199.61 949.8 -803.3 2,572,919.72 242,159.39 0.00 1,243.93 983.6 -831.9 2,572,953.55 242,130.77 0.00 1,288.24 1,017.4 -860.5 2,572,987.39 242,102.16 0.00 1,332.55 1,051.3 -889.1 2,573,021.22 242,073.54 0.00 1,376.87 1,085.1 -917.8 2,573,055.05 242,044.92 0.00 1,421.18 1,119.0 -946.4 2,573,088.89 242,016.31 0.00 1,465.50 1,152.8 -975.0 2,573,122.72 241,987.69 0.00 1,509.81 1,155.8 -977.5 2,573,125.74 241,985.14 0.00 1,513.76 1,186.6 -1,003.6 2,573,156.56 241,959.08 0.00 1,554.12 1,205.9 -1,019.9 2,573,175.84 241,942.77 0.00 1,579.38 1,206.0 -1,020.0 2,573,175.94 241,942.69 0.00 1,579.50 Targets Target Name - hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (ft) (ft) (ft) (ft) (ft) TD - plan hits target center 0.00 360.00 4,200.0 1,206.0 -1,020.0 2,573,175.94 241,942.69 - Point 7/27/2011 3:19.56PM Page 4 COMPASS 2003.16 Build 71 HALLIBURTON Database: ..Sperry EDM Prod .161 Company: Aurora Gas, LLC Project: Cook Inlet Site: Nicolai Creek Unit Well: Plan NCU#10 Wellbore: NCU#10 Design: wp04 Casing Points Halliburton Company Standard Proposal Report Local Co-ordinate Reference: Well Plan NCU#10 TVD Reference: 072711 @ 266.Oft (250+16) MD Reference: 072711 @ 266.Oft (250+16) North Reference: Grid Survey Calculation Method: Minimum Curvature Measured Vertical Casing Hole Depth Depth Vertical Diameter Diameter (ft) (ft) Name +N/ -S +E/ -W 4,557.0 4,199.8 7" (ft) 7 8-1/2 Comment 650.0 650.0 9 5/8" 650.0 9-5/8 12-1/4 Start 20.0 hold at 650.0 MD 670.0 670.0 0.0 0.0 Start DLS 4.00 TFO 319.78 Formations 1,304.7 113.2 -95.8 Start 3229.7 hold at 1327.6 MD Measured Vertical Vertical 4,200.0 1,206.0 -1,020.0 i Dip Depth Depth Depth SS Dip Direction (ft) (ft) ft Name Lithology 2,424.4 2,288.0 Carya 2.-2.3 0.00 1,255.1 1,239.0 Carya 2.1 0.00 1,827.6 1,753.0 Carya 2-1.2 0.00 2,190.2 2,078.0 Carya 2-2.2 0.00 4,408.9 4,067.0 Min TD 0.00 3,387.1 3,151.0 Carya 2-6 0.00 3,143.9 2,933.0 Carya 2-5.1 0.00 2,557.2 2,407.0 Carya 2-4.2 0.00 1,034.9 1,031.0 Tsuga 2-7 0.00 490.0 490.0 Beluga 0.00 4,557.3 4,200.0 Max TD 0.00 1,615.7 1,563.0 Carya 2-1.1 0.00 2,027.3 1,932.0 Carya 2-2.1 0.00 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (ft) (ft) (ft) (ft) Comment 650.0 650.0 0.0 0.0 Start 20.0 hold at 650.0 MD 670.0 670.0 0.0 0.0 Start DLS 4.00 TFO 319.78 1,327.6 1,304.7 113.2 -95.8 Start 3229.7 hold at 1327.6 MD 4,557.3 4,200.0 1,206.0 -1,020.0 TD at 4557.3 7/27/2011 3:19.56PM Page 5 COMPASS 2003.16 Build 71 Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Plan NCU#10 NCU#10 wp04 Anticollision Report 27 July, 2011 SURVEY PROGRAM Date: 2,11-07-27100:00:00 Validated: Yes Version: Aurora Gas, LLC Depth From Depth To Survey/Plan 244.1 644.0 wp04 (NCITHIO) 644.0 4557.3 wp04 (NCIT#10) HALLIBURTON Sperry Drilling 270 0 180 Travelling Cylinder Azimuth (TFO+AZn j°) vs Centre to Centre Separation 1100 NAD 27 ASP Zone 4: WELL DETAILS: Plan NCU#10 Ground Level: 250.0 +N/ -S +E/ -W Northing Easting Latittude Longitude Slot 0.0 0.0 2571969.97 242962.66 61' T54.994 N 151° 26' 58.486 W 90 ANTI -COLLISION SETTINGS 7 Interpolation Method: MD, interval: 100.0 Tool Depth Range From: 244.1 To 4557.3 BLIND Results Limited By: Centre Distance: 631.3 MNVD Reference: Plan: wp04 (Plan NCU#10/NCU#10) Scan Method: Tray. Cylinder North From Color To MD 0 - 244 2.a - 4% 494 - ]44 744 - 9% 994 1244 1244 - 14% 1494 - 17M 1744 19% 19% 2244 2244 m94 0 180 90 Travelling Cylinder Azimuth (TFO+AZI) I°I vs Centre to Centre Separation 120 Win] Aurora Gas, LLC Drilling Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Tray. Cylinder North Error Surface: Elliptical Conic Warning Method: Rules Based REFERENCE INFORMATION Co-ordinate (WE) Reference: Well Plan NCU#10, Grid North Vertical (TVD) Reference: 072711 @266.Oft (250+16) Section (VS) Reference: Slot - (O.ON, O.OE) Measured Depth Reference: 072711 @ 266.Oft (250+16) Calculation Method: Minimum Curvature SECTION DETAILS Sec MD Inc Azi TVD +N/ -S +E/ -W DLeg TFace VSec Target 1 244.1 0.00 0.00 244.1 0.0 0.0 0.00 0.00 0.0 2 650.0 0.00 0.00 650.0 0.0 0.0 0.00 0.00 0.0 3 670.0 0.00 0.00 670.0 0.0 0.0 0.00 0.00 0.0 4 1327.6 26.30 319.78 1304.7 113.2 -95.8 4.00 319.78 148.3 5 4557.3 26.30 319.78 4200.0 1206.0 -1020.0 0.00 0.00 1579.5 TD Aurora Gas, LLC Drilling Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Tray. Cylinder North Error Surface: Elliptical Conic Warning Method: Rules Based REFERENCE INFORMATION Co-ordinate (WE) Reference: Well Plan NCU#10, Grid North Vertical (TVD) Reference: 072711 @266.Oft (250+16) Section (VS) Reference: Slot - (O.ON, O.OE) Measured Depth Reference: 072711 @ 266.Oft (250+16) Calculation Method: Minimum Curvature Company: Aurora Gas, LLC Project: Cook Inlet Reference Site: Nicolai Creek Unit Site Error: 0. Oft Reference Well: Plan NCU#10 Well Error: 0. Oft Reference Wellbore NCU#10 Reference Design: wp04 Halliburton Company Anticollision Report Local Co-ordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well Plan NCU#10 072711 @ 266.Oft (250+16) 072711 @ 266.Oft (250+16) G rid Minimum Curvature 2.00 sigma ..Sperry EDM Prod .161 Offset Datum Reference wp04 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of referen nterpolation Method: MD Interval 100.Oft Error Model: ISCWSA depth Range: Unlimited Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 631.3ft Error Surface: Elliptical Conic Survey Tool Program Date 7/27/2011 From To (ft) (ft) Survey (Wellbore) Tool Name Description 244.1 644.0 wp04 (NCU#10) BLIND Blind drilling 644.0 4,557.3 wp04 (NCU#10) MWD MWD - Standard Summary Nicolai Creek Unit - NCU#3 - NCU#3 - NCU#3 Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (ft) from Plan Offset Well - Wellbore - Design (ft) (ft) (ft) Measured (ft) Nicolai Creek Unit Vertical Reference Offset Toolface + Offset Wellbore Centre Casing - NCU#3 - NCU#3 - NCU#3 700.0 700.0 209.8 26.00 183.8 Pass - Major Risk Offset Design Nicolai Creek Unit - NCU#3 - NCU#3 - NCU#3 Survey Program: 100-GYD-GC-MS, 2104 -CB -MAG -MS Rule Assigned: Major Risk Offset site Error: 0.0 ft Offset Well Error: 0.0 ft Reference Offset Semi Major Axis Measured Vertical Measured Vertical Reference Offset Toolface + Offset Wellbore Centre Casing - Centre to No Go Allowable Warning Depth Depth Depth Depth Azimuth +N/ -S +E/ -W Hole Size Centre Distance Deviation (ft) (ft) (ft) (ft) (ft) (ft) (1) (ft) (ft) (ft) (ft) (ft) (ft) 304.0 304.0 300.0 300.0 0.4 0.4 139.93 -160.4 135.0 0.9 209.6 2.61 207.0 Pass - Major Risk 404.0 404.0 400.0 400.0 2.8 0.6 140.00 -160.8 134.9 0.9 209.9 6.82 203.1 Pass - Major Risk 504.0 504.0 500.0 500.0 7.2 0.7 140.11 -160.9 134.5 0.9 209.7 13.72 196.0 Pass - Major Risk 604.0 604.0 600.0 600.0 13.6 0.7 140.23 -161.1 134.0 0.9 209.5 23.01 186.5 Pass - Major Risk, CC 700.0 700.0 700.0 700.0 15.4 0.7 140.27 -161.1 133.9 0.6 209.8 26.00 183.8 Pass - Major Risk, ES, SF 786.6 786.5 800.0 800.0 15.4 0.9 140.31 -161.1 133.6 0.6 214.8 27.01 187.8 Pass - Major Risk 872.8 872.1 900.0 900.0 15.4 1.0 140.37 -161.2 133.3 0.6 225.7 28.08 197.8 Pass - Major Risk 957.5 955.6 1,000.0 1,000.0 15.4 1.2 140.38 -161.3 133.0 0.6 242.7 29.19 213.9 Pass - Major Risk 1,040.3 1,036.1 1,100.0 1,100.0 15.4 1.4 140.37 -161.4 132.8 0.6 265.4 30.34 235.8 Pass - Major Risk 1,120.6 1.113.2 1,200.0 1,200.0 15.5 1.6 140.36 -161.4 132.6 0.6 293.6 31.48 263.2 Pass - Major Risk 1,200.0 1,188.0 1,300.0 1,300.0 15.6 1.7 140.32 -161.4 132.4 0.6 327.0 32.65 296.0 Pass - Major Risk 1,272.4 1,254.8 1,400.0 1.400.0 15.7 1.9 140.30 -161.5 132.2 0.6 365.3 33.81 333.8 Pass - Major Risk 1,348.1 1,323.1 1,500.0 1,500.0 15.8 2.1 140.29 -161.6 131.9 0.6 408.2 35.07 375.9 Pass - Major Risk 1,437.8 1,403.5 1,600.0 1,600.0 16.1 2.3 140.27 -161.6 131.6 0.6 452.4 36.62 419.0 Pass - Major Risk 1,527.4 1,483.9 1,700.0 1,700.0 16.4 2.5 140.25 -161.8 131.4 0.6 496.7 38.24 462.1 Pass - Major Risk 1,616.9 1,564.0 1,800.0 1,800.0 16.7 2.5 140.19 -162.0 131.9 0.6 541.5 39.69 505.8 Pass - Major Risk 1,706.1 1,644.1 1,900.0 1,900.0 17.1 2.7 140.11 -162.4 132.8 0.6 586.6 41.41 549.7 Pass - Major Risk 7/27/2011 3:27:55PM Page 2 of 3 COMPASS 2003.16 Build 71 Company: Project: Reference Site: Site Error: Reference Well: Well Error: Reference Wellbore Reference Design: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit 0. Oft Plan NCU#10 0. Oft NCU#10 wp04 Halliburton Company Anticollision Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset TVD Reference: Well Plan NCU#10 072711 @ 266.Oft (250+16) 072711 @ 266.Oft (250+16) G rid Minimum Curvature 2.00 sigma ..Sperry EDM Prod .161 Offset Datum Reference Depths are relative to 072711 @ 266.Oft (250+16) Coordinates are relative to: Plan NCU#10 Offset Depths are relative to Offset Datum Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04 Central Meridian is 150° 0'0.000 W ° Grid Convergence at Surface is: -1.27° 7/27/2011 3:27:55PM Page 3 of 3 COMPASS 2003.16 Build 71 Ladder 600 I I I 1 I 1 I I I I I I I 1 I I I fC I 1 1 1 I I 1 I I I I I I I 1 I 1 _ I I I I i I I I I I I I I I I I I I _ - , _ - I i I - �- 450— C) tt7 C O _ _ _ _ tD d_ U) 300 m C d C1 O d C v 150 0 300 600 900 12010 1500 1800 N1 easured Depth (300 ft., in) LEGEND -{}- NCU*3, NCUR3, NCUR3U-0 -B- wp34 7/27/2011 3:27:55PM Page 3 of 3 COMPASS 2003.16 Build 71 I I I 1 I 1 I I I I I I I 1 I I I 1 I I I � I I 1 I I 1 1 1 I I 1 I I I I I I I 1 I 1 _ I I I I i I I I I I I I I I I I I I _ - , _ - I i I - 7/27/2011 3:27:55PM Page 3 of 3 COMPASS 2003.16 Build 71 TRANSMITTAL LETTER CHECKLIST WELL NAME / l %rn ia_'Or �C PTD# Development Service Exploratory Stratigraphic Test Non -Conventional Well FIELD• POOL: R y d! l 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 roduce / in'ect is contingent upon issuance of conservati or approving a spacing exception. L__L&assumes the liability of any p otest to the spacing excen that may occur. �ti 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 Well Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for (name of we 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 NICOLAI CREEK, NORTH UND GAS - 560500 Well Name: NICOLAI CK UNIT 10 _Program DEV Well bore seg ❑ PTD#:2101270 Company AURORA GAS LLC _ _ Initial Class/Type DEV/1-GAS GeoArea 820 Unit 51430 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven. gas conforms to AS31.05.0300,1.A),02A-D) - _ - NA_ - - - _ _ - - - - - - - - - - .. _ - _ _ Geologic Engineering Public SPACING EXCEPTION Required due to being >3000' from a well capable of producing from same pool and because NCU 10 Date: Date Date Commissioner: Commissioner: Commissioner could potentially be the second well capable of production in section 20. Initial spacing exception in CO 635 will be amended as DTS �`�L6�/ `'_ / JKN all affected acreage is owned and operated by Aurora and the State is landowner. SFD 8/2/2011 ����:FF`' 1 Permit fee attached NA 2 Lease number appropriate. - - - - - No_ As revised, the entire wellbore will now lie within_ ADL_ 63279. 3 Unique well -name and number --- Yes Previous -permit applications for NCU 10 have expired - - - I4 Well located in -a -defined pool No. Nicolai Creek Unit North Undefined Gas Pool 5 Well located proper distance from- drilling unit -boundary- Yes _ - _ - - . . . . 6 Well located proper distance_ from- other wells No SPACING EXCEPTION REQURIED: less than 3000' from NCU 3. 7 Sufficient acreage available in -drilling unit No_ . - - SPACING EXCEPTION REQURIED: Potentially second -gas producer in Section 20, but reservoirs -are discontinuo 8 -if-deviated, is wellbore plat_included - - - - - - Yes Received via email -from -B. Webb to_S. Davies on- 8/2/2011 9 Operator only affected party. Yes _ 10 Operator has -appropriate bond in force Yes -- - Appr Date 11 Permit -can be issued without conservation order_ NA 12 Permit. can be issued without administrativ_e_approval _ _ _ _ _ _ _ .... Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - SFD 8/2/2011 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 - - - - - - - 13-3/8" driven to 80'. Engineering 19 Surface casing_ protects all known- USDWs - - - - Yes - - - - - - - - - 20 _C_MT.vol_adequate.to circulate on conductor _& su_rf_csg Yes Adequate excess. 21 MIT vol- adequate - to tie-in long string to surf csg_ _ _ _ _ Yes _ - - - - - - - - - - - - _ - 122 C_MT-will cover all known -productive horizons Yes - - - - - - . 23 Casing designs adequate for C,_T, B &_permafr_ost_ Yes Adequate safety factors._ 124 Adequate tankage or reserve pit . Yes AWS #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_diverter required, does it meet regulations_ - - - - - - - - - - - - NO. Vent line variance required. Appr Date 28 Drilling fluid -program schematic & equip list adequate - - - - - - Yes - -Max MW_11.0_ppg._ WGA 8/4!2011 29 BOPEs,_do they meet regulation - Yes 30 BOPE_press rating appropriate; test - -(put psig in comments) Yes MASP 1722 -psi; test to 3000 psi._ 31 Choke -manifold complies w/API RP -53 (May 84)_ Yes 32 Work will occur without operation shutdown_ - - - _ Yes _ _ _ _ _ _ _ _ _ _ _ _ _ I33 Is presence. of H2S gas probable No_ Not an H2S area._ I34 Mechanical_ condition of wells within AQR verified (For service well only) _ _ _ NA_ 35 Permit can be issued _w/o hydrogen sulfide measures Yes None expected based on offset drilling, but _H2S-detectors will_ be_utilized------- - _ - _ Geology 36 Data_presented on potential overpressure zones. Yes _ _ _ _ _ Expected pressure gradient_is 0.51 psi/ft (9.8 ppg_EMW); will be drilled using_9.5-11.0 ppg mud. Appr Date 37 Seismic analysis_ of shallow gas -zones_ - - No_ - - _ - _ _ Shallow gas is always a danger in this area. A warning along, with_ mitigation measures, is presented in the SFD 8/2/2011 38 Seabed condition survey (if off_ -shore) ------------- NA_ Drilling Hazards_ section of the application along with mitigation measures. 39 -Contact name/phone for weekly -progress reports_ [exploratory only] - - - - - - - - - Yes Ed Jones _2.81-495-9957._ - . _ - - - - - - . - - - - - - - - - - - Geologic Engineering Public SPACING EXCEPTION Required due to being >3000' from a well capable of producing from same pool and because NCU 10 Date: Date Date Commissioner: Commissioner: Commissioner could potentially be the second well capable of production in section 20. Initial spacing exception in CO 635 will be amended as DTS �`�L6�/ `'_ / JKN all affected acreage is owned and operated by Aurora and the State is landowner. SFD 8/2/2011 ����:FF`' `. SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COPOUSSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 Bruce D. Webb FAX (907) 276-7542 Manager, Land and Regulatory Affairs Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Nicolai Creek Field, Undefined Gas Oil Pool, Nicolai Creek Unit #10 Aurora Gas, LLC Permit No: 210-127 Surface Location: 1799' FNL, 1504' FWL, SEC. 20, TI IN, R12W, SM Bottomhole Location: 2140' FNL, 300' FEL, SEC.�T1IN, R12W, SM 19 am Dear Mr. Webb: I.1l.10 Enclosed is the approved application for permit to drill the above referenced development well. 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. 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, Daniel T. Seamount, Jr. l� Chair DATED this! day of September, 2010. cc: Department of Fish & Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) .Aurora Gas, LLC www.aurorapower.com September 7, 2010 Dan Seamount, Chairman State of Alaska Oil and Gas Conservation Commission 333 W. 7t' Avenue, Suite 100 Anchorage, AK 99501 Re: Nicolai Creek Unit #10, Development Well Reapplication for Permit to Drill Dear Mr. Seamount: .F,c E V 7 2010 i a Gas OFtt3 lvft'�Ission Aurora Gas, LLC (Aurora) hereby requests approval of the Permit to Drill for Nicolai Creek Unit #10. This well has been previously approved and the Permit to Drill has expired. The expired AOGCC permit to drill number is 206-080-0. The procedures in the previously approved plan have been modified. The previously approved plan and the new Permit to Drill Application (AOGCC form 10-401) are attached for your review and consideration. I understand that we may retain the well designation as Nicolai Creek Unit #10, but it will have a new Permit to Drill number upon re - issuance. Should questions arise in connection with this request, please contact Mr. Ed Jones in the Houston office at (281) 495-9957. Respectfully Submitted By, -;Rf rlcL t-'J"e6 Bruce D. Webb Manager, Land and Regulatory Affairs attachments D;V veKT \Iarjgj(L-e j000 FOIE-- trot. 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 STATE OF ALASKA ALA_ _.A OIL AND GAS CONSERVATION COMMI_ _,ON PERMIT TO DRILL 20 AAC 25.005 FCFIVFD w6k 0 9 114120 10 SEP 0 7 2010 1 a. Type of Work: 1 b. Proposed Well Class: Development - Oil ❑ Service - Winj ❑ Single Zone ❑ 1 c. Specify if well is prpposed for: Drill ❑✓ Redrill ❑ Stratigraphic Test ❑ Development - Gas ❑� Service - Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates ❑ Re-entry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket FZ] Single Well ❑ 11. Well Name and Number: Aurora Gas LLC Bond No. NZS 429815 Nicolai Creek Unit #10 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 1400 W. Benson Blvd Suite 410 Anchorage AK 99503 MD: 4,000' TVD: 3,550' Nicolai Creek Unit North Undefined Gas 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: T. 11 N., R. 12 W., S.M., Section 20 ADL -63279 8. Land Use Permit: 13. Approximate Spud Date: 1,799' FNL and 1,504' FWL Top of Productive Horizon: 1,977' FNL and 1,131' FWL, Sec. 20 CIRI ; 10/15/2010 Total Depth: 2,140' FNL and 300' FEL, Sec. 19 6154,) x-10 9. Acres in Property: 14. Dist. to Nearest Property: 111V n Z o 320 1,504' west to ADL 391472 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 265 feet 15. Distance to Nearest Well Open Surface: x 242963 Y 2571970 ' Zone- 4 GL Elevation above MSL: 249 feet to Same Pool: SE 207' +/- 16. Deviated wells: Kickoff depth: 820' +/- feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 2.035) / 4 2 � WGA - Maximum Hole Angle: 42 degrees , Downhole: 1,976 psi Surface: 1,4Wpsi , 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD I TVD (including stage data) driven 13-3/8" 68# Structural n/a 96' 0 0 96' 96' n/a 12-1/4" 9-5/8" 40 153.5# K-55 / L-80 BTC 650' 0 0 650' 650' 13 ppg Type 1, 221 sx. 8-1/2" 7" 23 / 26# K-55 / L-80 LTC 4,000' 0 0 4,000' 3,550' 12 ppg Type G, 101 sx. lead 14.8 ppg Type 1, 319 sx. tail 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): 0 Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD & TVD (ft): Approximately 900' MD/TVD to 3,400'MD / 2,990"TVD. Actual pert s will be determined from log analysis. 20. Attachments: Property Plat BOP Sketch ❑ Drilling Program 0 Time v. Depth Plot ❑� Shallow Hazard Analysis ❑✓ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program 0 20 AAC 25.050 requirements El 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct. Contact Printed Name Bruce D. Webb Title Manager, Land and Regulatory Affairs Signature 1� Phone (907) 277-1003 Date September 7, 2010 Commission Use Only Permit to Drill - Z L- API Number:.. _ 2 �L% ' C�-' ` Permit A pr vat See cover letter for other Number: I f 7 50- Z ate: 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 in shales: 0 Other. g Mud log req'd: Yes 2 No E]r F0 PF f o 3000 ,p S ( Samples req'd: Ye, fo 5-� HzS measures: Yep L, Directional svy req'd: Yes 0 No ❑ Pursuo►..st �o Z-0 AAC ZS.03� C``�(Z�l dttlerife-r el f (ir.,C vara G� �`S 0g9'r oiled. C APPROVED BY THE COMMISSION / DATE,"COMMISSIONER i UKIVIIVAL 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 Aurora Gas, LLC NCU #10 Drilling Program NICOLAI CREEK UNIT #10 Nicolai Creek Unit #10 is a grass-roots well targeting Beluga and Tyonek Gas Production. It is located in the Nicolai Creek Gas Field, directionally drilled from the #3 well and facility pad to a BHL +/-1970' west and slightly south of the surface location, which is about 200' northwest of the #3 well. It will target Beluga and Upper Tyonek Carya 2-1 thru 2-5 sands that have produced more than 4 BCF from the Nicolai Creek Field. Pre Rig work The site was surveyed in 2006 for the Nicolai Creek #10—pad GL elevation is about 249' The conductor was driven to 96' from GL at that time. 2. Add gravel as necessary to the old pad area configured for AWS #1 with drilling support. Build sufficient emergency cuttings containment for planned drilling program, and build containment for diverter line. 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. 96' of 13-3/8" conductor has been pre-installed. 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 & pertinent agencies when ready to start drilling operations. 5. Prepare spud mud system / weight up to 10.0 ppg. Load, strap & drift 650' of 9-5/8" 53# BTC and 40# LTC surface casing. Locate cross-over (short joint with BTC pin?). 6. PU 12-1/4" mill tooth bit & drill to –650', using 8" stabilized BHA. 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. 7. Make wiper trip to conductor to condition hole for running 9-5/8" surface casing, Run ESS. POOH, LD 12-1/4" BHA. 8. Run & cement new 9-5/8" 40#, K-55 LTC & 53# L-80 BTC casing @ 650-700', installing 1 centralizer / joint centered on the 1St 4 joints above shoe, & 1 centralizer every 2nd joint across the collars there after. 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. Be prepared to treat cement returns with retarder. Leave 6" to 18" of cement in cellar to seal bottom. Prepared by Ed Jones Page 1 of 11 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program 9. RD cementers, nipple down diverter, cut casing and install 11" 3M wellhead. 10. RU and test 1r0q1r00`psi. 3M BOP stack and 5M choke manifold. Test stack and surface s equipment to Pressure test 9-5/8" casing to 1,500 psi for 15 minutes or as required on ap`proved Permit to Drill. Mud weight to drill out should be at least 10 ppg at this point, do not cut back if higher, up to 10.5 ppg. However, if no significant mud logs show are seen by 1600', gradually cut back mud weight to 9.5 ppg to drill thru partially depleted sands to 1900-2400' (TVD). Be ready to add LCM to mud. 11. PU 8-1/2" Mill Tooth Bit & RIH w/ 6-1/4"colr20' :"Drill out shoetrack. Condition / treat mud as needed for cement contamination, dril ew formation. Pull back into shoe & perform FIT / LOT up to 16.0 ppg EMW maximum with low volume test pump. Record results. POH & LD 6-1/4" collars. 12. PU 4-1/4" directional drilling assembly w/ 8-1/2" bit, motor & DIR MWD assembly, non - mag DC's, jars & HWDP as specified by Sperry proposal. 13. RIH and directionally drill 8-1/2" hole to 4000' MD (3540' TVD) TD per Sperry directional plan, or other depth as directed by Aurora Gas geologist (may as shallower ' depending upon top of Carya 2-5). 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, prepare to short trip if needed. Anticipated mud weights required are 9.5 10.0 Do not exceed fracture J P g q ppg – ppg• gradient determined in step 11. If possible, adjust TD to put cement head on floor. While drilling, load, tally & drift 7" casing (83 jts of 23# K-55 and balance 26# L-80—all LTC) on racks. 14. Condition hole, short trip and prepare for running wireline logs. 15. POOH, rack back drillstring and RU wireline BOP's and lubricator and logging tools. Log 9-5/8" cased hole section w/gamma ray sensor, Log OH section with logging suite including resistivity and porosity logs as directed by Aurora Gas. RD wireline. 16. RIH w/ 8-1/2" drilling assembly to TD & condition hole for running 7" casing. Ensure cementing head has proper connections or proper cross-over and is available for quick rig UP. 17. POOH while laying down drillpipe & BHA, RU to run casing. Verify cementer's equipment is ready. 18. Install 7" pipe rams. 19. Run 600' of 7" 26# L-80 LTC casing, then 3400' of 7" 23# K-55 LTC casing, installing 1 centralizer per joint centered on 1" 4 joints above shoe, 1 centralizer every 2nd joint in open hole & every 3rd joint inside surface casing (use Turbolator centralizers below/thru each pay sand and where directional inclination is greater than 10 deg). Shoe joint connection at float shoe, float collar & stage tool landing collar must be Baker - Locked (80' shoetrack). While running casing, fill every 3rd joint. Be prepared to wash to bottom. 20. RU cementers, cement per attached cementing program from TD to surface. A sufficient amount of accelerated 12.0 ppg light weight Class G lead cement will be pumped to Prepared by Ed Jones Page 2 of l l Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program cover from 1400' up thru the annulus from the 9-5/8" shoe to surface. This will be followed by sufficient amount of 14.8 ppg Type I tail blend cement to cover from TD back to 1400'. Excess will be calculated using caliper log data—top of tail slurry will be determined following evaluation of the logs. Plug will be bumped with clean brine. If possible reciprocate pipe while displacing cement. Land casing & WOC. 21. RD cementers, nipple down stack, land casing in slips & cut casing. 22. 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. 23. Install 2-7/8" pipe rams. 24. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Displace well w/ filtered KCI NaCI 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 25. 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 7" 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 guns, RD wireline. 26. 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. 27. 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 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. Spar 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. Install BPV. ND BOP. NU and test tree. 28. Pull BPV and RIH w/ slick line and pull blanking plug. 29. 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 and set in XN nipple below deepest packer. 30. Add needed KCl water cushion to tubing (1000' above sliding sleeve). Open deepest sliding sleeve. Test well as per Step 29. DO NOT KILL, but close sliding sleeve. 31. Repeat Step 30 for remaining shallower intervals (I or 2). Prepared by Ed Jones Page 3 of l 1 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program 32. Open zones for initial production (depending upon pressures and test results—likely the 2-4.2 and deeper)—flaw to clean up. Shut in. Set BPV in tree. Release rig, RD, and move rig. 33. Pull BPV. Run 4 -point test of initial production zone as per Procedure provided at that time. RD test unit. 34. Clear & clean location. Hand well over to production. 35. File completion reports with proper agencies. Site Access Nicolai Creek Unit #10 will be accessible via existing gravel roads currently in use to support production operations at the Nicolai Creek Unit #3 well and production facility (right off Shirleyville-to-Tyonek gravel road). Rig Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the Nicolai Creek Unit #10 well The Alaska Oil & Gas Conservation Commission has information on this rig and equipment as it has been in use for the last (8) 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 will be drilled vertically and the survey program will consist of Sperry multi -shot survey and supplemented with 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). The 8-1/2" production hole will be drilled directionally. For all directional work, directional MWD will be utilized with supplemental wellbore surveys taken at maximum of 100 ft intervals as needed, per AAC 25.050 (a)(1). Logging Program Mud loggers will be on site for the duration of drilling activities. ` Schlumberger will provide wireline logging services as proposed below: Nicolai Creek Unit #10 Proposed Logging Program Well Section Depths t OH CH Log Type 12-1/4" Surface 0'— 650' N/A: No open -hole logs planned for surface at this time. GR only in cased hole. 8-1/2"' Production Hole 650'-4000' Platform Express: Array Induction, Compensated Neutron, Litho -Density, SP, GR, and possibly DSI and/or FMI/DM.. Also MDT or XPT and, possibly, Sidewall cores. 5-1/2" Int. Csg surface —3900' GR/CBL/CCL Surface — TD 96'— 4000' Mud Logging Services Prepared by Ed Jones Page 4 of II Rev. 1.0 Aurora Gas, LLC BOP Equipment NCU #10 Drilling Program Aurora Gas, LLC will use the same BOP system they have been using for the last (6) years 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 &12"- diverter line will be used: an exception to 20 AAC 25.035 (c)(1)(A), requiring that the diverter line outlet size be at least 16" diameter or (B) at least as large as the hole size being drilled, will be requested. 8-1/2" Production Hole An 11" 3000 PSI WP Schafco (Shaffer Equivalent) BOP system will be used which is configured with an I V 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 o -blind rams and (1) 11" 3000 PSI WP rated drilling spool. BOP tests will be performed to 000 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' Glacial Wash and Beluga Formation Base Fluid Fresh or produced water Density 10-11 ppg PV 10-30 YP 30-40 API Filtrate not controlled Total Solids 15-25% Bentonite Gel (Aquagen mud system Drilling Fluid Properties While Drilling 8-1/2" interval to 4000' Beluaa and Tvonek Formations Base Fluid 6% KCL - Density 10.0 — � 1 0" ppg PV 22-30-- YP 20-30 API Filtrate < 5 Total Solids 10-15% Polymer (EZ Mud) mud system Prepared by Ed ,Jones Page 5 of 11 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program 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 or injected into the Aspen 1 Disposal well. 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 The conductor for Nicola Creek Unit #10 has been installed by drilling/driving the 13-3/8" pipe to 80' from GL/96' RKB. Joints are welded together and a drilling shoe was welded to the bottom joint. No cementing is required. 9-5/8" 40# K-55 LTC & 53.5# L-80 BTC Surface Casing Analysis and Cementing Program 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. Capacities: 9-5/8" 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: 47' x .0773 bbl/ft = 3,6rbbls Total Surface Cement Volume ,72,0 bbl -` Actual volumes to be re -calculated at time of running casing due to potential variation in actual depth from planned. Cement System Accelerated Class G Yield 1.83 cf/sx Prepared by Ed Jones Rev. 1.0 Weight (ppg) bbl cf sx 13.0 72.0 404 221 Page 6 of I 1 Aurora Gas, LLC NCU #10 Drilling Program Please see attached 9-5/8" surface casing analysis and specifications. 7" 23# K-55 BTC & 26# L-80 LTC Production Casing Cementing Program The 7" production casing will be cemented in fully from the proposed set depth of 4000' to surface. A 12.0 ppg accelerated lead light -weight "G" cement (2.2 cf/sk yield) followed with a 14.8 ppg Type I tail cement (1.35 cf/sk yield) 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 pay). This program is designed to insure the intended perforating / production intervals are isolated with tail "G" blend. Capacities: 7" 23## csg capacity = 0.0393 bbl/ft 7" 26# csg capacity= 0.0382 bbl/ft 7" csg X 8-1/2" OH capacity =.0226 bbl/ft 7# csg X 9-5/8" 40# annular capacity = .0282 bbl/ft Lead System: 9-5/8" x 7" Csg: 650'+ (1400-650') 8-1/2" open hole 650' x .0282 bbls/ft x 1 (0% excess) = 18.33 bbls i Lead Cement Volume = 18.3 bbl+750' X.0226 X 1.25 (25% excess) --�39.'bbl Tail System: 8-1/2" OH x 7" Csg: 4000-1400 = 2600' 2,600' x .0226 bbl/ft x 1.25 (25% excess) =73.5 bbls Shoe Joint: 85' x .0382 bbl/ft =,-3.3 bbls Total Tail Cement Volume ="76.8 bbls Actual volumes will be calculated at time of running casing due to potential variation in depth from planned. Cement System Type Cement Weight (ppg) bb] cf sx Lead @ 2.2 cf/sx G 12.0 39.5 221.6 101 Tail @ 1.35 cf/sx Type I 14.8 76.8 430.9 319 Please see attached 7" production casing analysis and specifications. Pressure Calculations Maximum Anticipated Surface Pressure From offset wells in the immediate area and actual pressure data from the nearby offset well Nicolai Creek Unit #10, maximum anticipated bottom -hole pressures should not exceed 1976 psi at 4000 ft. Pressures measured at the Nicolai Creek Unit # 11 well indicated a maximum gradient of —.0.51 psi/ft with a bottom -hole pressure of 1196 psi recorded at 2,344' (maximum observed from XPT). Maximum anticipated surface pressures "MASP" can be calculated by subtracting the gas gradient of. 1 psi/ft from pore pressure gradient of .51 psi / ft and multiplying by the total TVD depth. Prepared by Ed Jones Page 7 of l l Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program •C&I(®ZI Maximum Anticipated Surface Pressure = ( - .1) * 3550' _ �psi A leak -off test to 15.4 ppg EMW @ 650' was conducted while drilling Nicolai Creek #11. Assuming casing shoe strength of 15.4 ppg EMW (or 0.80 psi/ft) our estimated Maximum Allowable Surface Pressure during the 8-142" interval is expected to be Maximum Allowable Surface Pressure = (.80-.I)*650'=455 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 1-12S in the region, however; a gas detection system capable of detecting H2S as well as methane will be i 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 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 are 2 existing wellbores with a mile of this location: the Nicolai Creek Unit #3, 207' southeast of this surface location and the P&A'd Nicolia Creek #5, about 3200' west of this location. The #5 was a straight hole, and the BHL of the #10 is expected to stay more than 1000' east of it. The #3 was straight hole to with no more than 2 degrees deviation down to 4000' (it was later sidetracked at about 6900' to the southwest), but due to the close proximity to the proposed #10, a gyro survey was run in 2006 to below 2000', and this data is incorporated into the directional plan by the directional services company. 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 8 of 11 Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program 2 7/8 6.5# 8rd EUE J-55 Tubing :� Aurora Gas, LLC NICOLAI CREEK UNIT #IO 13-3/8" 68# Structural POSSIBLE Conductor driven to 96' GL Configuration (exact determined by logs and tests) 9-5/8" 40 & 53.5# Surface Casing set at 650' Cement w/13.0 ppg Type 1 Drill 12-1/4" Hole to 650' 2-7/8" x 7" annulus to be LA displaced over to inhibited packer fluid through sleeve (d1445' Prospective Pay Tops Beluga — 900-1750' TVD Carya 2-1.1 — 2030' MD / 1920' TVD Hydraulic Set Packer @ 1950' Carya 2-2.1 — 2460' MD/2210' TVD Carya 2-2.3 — 2655' MD/ 2325' TVD Carya 2-3.1— 2810' MD / 2480' TVD Carya 2-4.2 — 2910' MD/2585' TVD Sliding Sleeve @ 2100' Carya 2-5.1 — 3400' MD/ 2990' TVD Carya 2-1 Perforation Intervals to be Hydraulic Set Packer @ 2150' determined by open -hole logging. Carya 2-2 LT Sliding Sleeves @ —2600' MD & 2800' Carya 2-3 2 7/8" 6.5# EUE 8rd Tubing w/ On - Off Tool on Mechanical Packer @ q 2850 'MD w/ 2.31 profile X nipple Carya 24.2 Carya 2-5.1 U Drill 8-1/2" Hole to 4000' MD r ' w 7" 23# K-55 & 26# L-80 Casing to 4000' MD/ 3550' (TVD) Estimated PBTD @ 3915' TVD Prepared by Ed Jones Page 9 of i I Rev. 1.0 Aurora Gas, LLC NCU #10 Drilling Program NICOLAI CREEK 10 DRILLING TIME 0 1 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 -500 -1000 - -1500 -2000 2 -9600 -3000 -3500 -4000 -4500 DAY Days 1-3: Drill 12-1/4" Hole Days 3-6: Run and cement 9-5/8" casing Day 6: Test casing, drill out w/ 8-1.42" bit and run FIT, kick off directional 8-1/2" hole. Days 6-14: drill directional 8-1/2" hole to 4000' MD / 3550' TVD Days 15-16: Log Days 17-18: Run 7" casing and cement. Days: 19---: Complete and test well. Prepared by Ed Jones Page 10 of 11 Rev. 1.0 — �- Plan Heel Aurora Gas, LLC NCU #10 Drilling Program NICOLAI CREEK UNIT #10 Summary of Drilling Hazards POST THIS NOTICE IN DOGHOUSE f � There is potential for abnormal pressured shallow gas. There is potential for stuck pipe in coals encountered while drilling from surface to TD. Short trips as dictated by drilling trends. � There is no H2S risk anticipated for this well. Due to potential for shallow gas kick, very little response time will be afforded to respond. PVT and gas detection systems must be fully operational and functioning at all times, visual flow checks and pit level monitoring are critical. CONSULT THE NICOLAI CREEK UNIT #10 WELL PLAN FOR ADDITIONAL INFORMATION Prepared by Ed Jones Page 11 of 11 Rev. 1.0 SECTION 20 T11N R12W SM NICOLAI CREEK 10 A -SLAKED NORTH NOTES 1) BASIS OF COORDINATES IS ALASKA STATE PLANE NAD 27 ZONE 4 FROM A DIRECT TIE TO ADL NO. 31270. 2) BASIS OF ELEVATION IS FROM TIDAL OBSERVATION ON 9-22-93. DATUM IS MLLW. ALL ELEVATIONS SHOWN HEREON WERE TAKEN ON GROUND. 3) SECTION LINES SHOWN HEREON ARE BASED ON PROTRACTED VALUES. LEGEND 0 —ND MON- 0 FDIRroFROPERIYCORNER �� ROWER PdE 4 -DE -E ® RANB DR Cl PIpNE—EBTAL CU1 SLOPE DAYl1GM FILL 9EOPf DAY- -a••— DVERNEADELE—C uoe —R--EIE — —�— UNUERDRDUN CAB —.c. UNDERDROVND RIONE —•�— BILT FENCE (INBrALL A68FpW11I REE LRE DETAIL NICOLAI CREEK PAD P 1g B �pG`SR AD[7Mi)5 267.8' i EXISTING EXIS77NG ROAD 469.3' NICOLAI CREEK NO. 10 WELL / AS PAD ELEV. 249.0' GRID N:2571969.966 y LINER GRID E:242962.661 LATITUDE: 61 '12'X17 Z BDG. ePIPEUNE LONGITUDE: 151°26'58.486'W W a TANK TANK m $ NICOLAI CREEK PAD NICOLAI CREEK NO.3 WELL LINER LINER, SCALE GRID N:2571810.830 O WITH 1978 PHOTO GRID E:243095.873 1 Inch = 40000. 0 100 600 800 LATITUDE: 61°01'53.457N O WELL (ABANDONED) (see detail) LONGITUDE: 151°26'55.711'W 8' DIAM. CMP FLUSH p SCALE 7g�e 7OLSp 1 inch = 100 ft 0 100 Iso zoo [�,y7rs V �NEERING-TEBTIN BO%b9 � solnorru. uc. meas ImnTm.z,e Frx:Im>t:uvee )RAWN BY: MSM D EMED RY: SAM 1CRZ. SCALE: 1'-100' &RT. SCALE: NA SHEET: 4 Casing Performance Properties: Aurora Gas Nicolai Creek Unit#10 Nicolai Creek Unit #10 Casing Properties and Design Verification Tensile Strength Section * 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 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. 7" 4000' MD / 3550' TVD Production casing to stabilize and isolate producing interval for production operations. Ed Jones 7/14/2010 Internal Collapse Size Weight Yield Resistance TVD MD MW MASP Inches lb/ft Grade Cnxn(psi sij Joint Body Length (ft RKB) (ft RKB) i BFsi 9-5/8" 53.5 L-80 BTC 7930 6620 132901244000 650 650 650 10.5 0.84 455 9-5/8" 40 K-55 BTC 3950 2570 843"000 630000 650 650 650 10.5 0.84 455 7" 23 K-55 LTC 4360 3270 341000 366000 4000 3550 4000 11 0.83 1455.5 7" 26 L-80 LTC 7240 5410 519000 604000 4000 3550 4000 11 0.83 1455.5 Design Safety Factor* Size Tensile Burst Collapse 9-5/8" 45.5 17.4 22.8 9-5/8,40 38.6 8.7 8.9 - 7,23 4.5 3.0 2.0 7,26 6.0 5.0 3.2 - * 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 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. 7" 4000' MD / 3550' TVD Production casing to stabilize and isolate producing interval for production operations. Ed Jones 7/14/2010 NCU 10 Proposed Location Ed Jones Executive Vice -President Aurora Gas LLC July 16, 2010 NCU 10 Well Location NCU 10 Surface Location Well List Search;— �,iier Reset • N TBU SPR -07 TS -7: <Undefinec.J feet • N TBU SPR -08: <Undefined>: 51 • N TBU SPR -09: <Undefined> : 51 -�-N TYONEK ST 1 : NTS#1 5028: -NAPTOWNE 24.08 <Undefined. ' NC: 11: 5028320135: AURORA NCFW 1 : NFIV-1 0000000000: 14CI A-01 : <Undefined> : 5088321 NCI A-02 : <Undefined> :5088321 NCI A-03: <Undefined> : 5088321 NCI A-04: <Undefined> : 5088321 NCI A-05: <Undefined> : 5088321 NCI A-06: <Undefined>: 5088321, NCI A-07: <Undefined> : 5088321 NCI A-08: <Undefined> : 5088321 NCI A-09: <Undefined> : 5088321 NCI A-10: <Undefined>: 5088321 NCI A-11 : <Undefined>: 5088321 NCI A-12 : <Undefined> : 5088321 NCI B-01 : <Undefined>: 5088321 NCI B -01A - <Undefined>: 50883 NCI B-03: <Undefined> : 5088321 NCI ST 1 <Undefined> : 508831 NCIU A-13: <Undefined>: 50883 NCU : #1 502831002000: TEXE . NW: uJu 22 ,2222 .�,urur, Well Name: NCU Well Number: #10 Etevation: 216.00000 feet Elevation Reference:. •� K8 (Kelly Bushing) - Location Unit r X/Y r Inline/Crossline r Decimal Deg r Deg/Min/Sec Surface Location X; 243099:33335 feet Y: 12571966.91367 feet Surface. feet Elevation. Total Depth: 4000.00000 feet Borehole Comments; (Max. 255 characters) - Borehole D Borehole Name: Imain .71 UWI: 22323222 Symbol; p Location Only . Edit... Operator Name: AURORAGASS Edit... Lease Name; 1—j Edit... Bottom Hole Location: Deviated _ I I I c _ I j.:~ feet Edit... Y- `- feet OK Cancel IApply Help 0 feet 4000 feet —� Edit... --� Edit... -- Edit.. NCU 10 Topld ormation Tops File owl Well list: Search;�=�iier Reset jNCFW 1 NFW-1 : 0000000000: AURC.±i )NCIA-01 : <Undefined> 50883200160( 'INCI A-02: <Undefined> : 50883200180( NCI A-03 : <Undefined> :50883200200( NCI A-04: <Undefined> : 50883200230( NCI A-05: <Undefined> 50883200250( x NCI A-06: <Undefined> .50883200260( NCI A-07: <Undefined> 50883200270( NCI A-08: <Undefined> 50883200280( a NCI A-09: <Undefined> 50883200290( ;NCI A-10 : <Undefined> 50883200300(--t NCI A-11 : <Undefined> 50883200310( NCI A-12 : <Undefined> 50883200320( NCI B-01 : <Undefined> 50883200930( +r`NCI B -01A <Undefined> : 50883200931 j�NCI B-03: <Undefined> 50883200950( NCI ST 1 : <Undefined> 508831001801 NCIU A-13 : <Undefined> 5088320087 NCU : #1 :502831002000: TEXACO MIMI wrl l - till - gmR�lnn-?nm - 1lwnrw -1 41 21 Author cliff Well Name: INCU Well Number: 1#10 Borehole Name: I main -71 Depth Type (Feet) Elevation: 216.00'(f) C MD r TVD (Eley. Ref.) r TVD (Seismic r `Subsea I Seismic Datum; 0.0 (f) Total MD; 4000.00 (f) Add Delete Management.:. I T -D Curve, Calculated, Defin Deviated Well Depth(feet) Time I Abbrev. I formation Top I Quarity 1618.55 2029.47 2656.61-- _I- 2808.91 2907.91 3395.280.90363 0.39550 0.51598 0.71057 )TOP TYO `► 1TOP TYONEK (cliff)_+l C2-1 1 ► CARY1� 2 1.1 cliff + fir_ _ _ .( __il IC2-23 .2,CARYA2-2.3(cliff,_- C2-4.2 �CARYA 2 4 2 SAN �► CARYA 2 3.1 C2-5.1 CARYA 2 5.1 SAN ► _ '� -- --� 10.76474 0.79220 — -- - j - .-.-_ __- 4000.00 1.03933 - -- --- - ITD (cliff) `► I - - --- - V - �- OIC Cancel Apply Help Add/Delete Quality... I J �I J NCU 10 Survey Deviation SurveysFile Well List: Search: �- (=iitc t Reset ♦ N TBU SPR -07 TS -7: <Undefin A + N TBU SPR -08: <Undefined> N TBU SPR -09: <Undefined> -�-N TYONEKST 1 : NTS#1 :50 y}-NAPTOWNE 24-08: <Undefinec NC: 11 : 5028320135: AURORr NCFW 1 : NR%1.1 : 0000000000 NCI A-01 : <Undefined> : 50883, NCI A-02: <Undefined> : 50883, NCI A-03: <Undefined> : 50883', NCI A-04: <Undefined> : 50883'', NCI A-05: <Undefined> : 50883, NCI A-06: <Undefined> : 50883, NCI A-07: <Undefined> : 50883,1—j NCI A-08: <Undefined> : 50883, NCI A-09: <Undefined> : 50883', NCI A-10 : <Undefined> : 50883, NCI A-11 : <Undefined> : 50883', NCI A-12: <Undefined> : 50883 NCI B-01 : <Undefined> : 50883, p'NCI B -01A: <Undefined> : 5088: NCI B-03: <Undefined>: 50883, NCI ST 1 : <Undefined>: 50883' NCIU A-13 : <Undefined> : 5088 NCU : #1 : 502831002000: TESD 199111111111111I NCU : ' 1A 502831002001 :;P Well Name NCU Reference Elevation: 216.00 (f) . Well Number. r:1 is Daka Seismic Datum:- 0.0 (f) Total MD: 400U0 (f) Borehole: - r T•D Curve: Calculated, Defined Deviated Well Deviation Survey Management- Last Modified Rename...Delete... Author 1:10 Active Deviation Survey Name: Untitled Date: Ifl-I North Reference i— Insert Kick Off Point — Depth Calculati6h Priority... Magnetic North Kick Off MD: �— DIA<•>DXY Computation Method: r True North Tan ential 7 {' Grid tJorlh .Kick -Off Azimuth:—" 9 I Calculate inclinationAzimuth Unlock Source Add Row Delete Row Calculate Ge:p::a Note: Click "Unlock Source" to edit source data. Delete a source cell's contents to convert it to non -source. XIY are in Grid North. DXIDYIA2imuth are with respect to Grid North. OK Cancel,::,.; Help Ei Test for geometric viability TRANSMITTAL LETTER CHECKLIST WELL NAMEa1 f� PTD# i/ Development Service Exploratory Stratigraphic Test Non -Conventional Well FIELD: POOL: Circle Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (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 approved subject to fu mpliance with 20 AAC EXCEPTION 25.055. Approval to perforate a `p 6duic6vl inject is contingent upon issuance f a conservati er approving a spacing exception. �,.,y,- =-` e4,i4, l-Z_6L assumes the liability of any protest to 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 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 NICOLAI CREEK, NORTH UND GAS - 560500 Well Name: NICOLAI CK UNIT 10 _-____ _ --Program DEV Well bore seg PTD# 2101270 Com an AURORA GAS LLC Initial Class/Type DEV/PEND GeoArea 820 Unit 51430 On/Off Shore On Annular Disposal ❑ 35 Permit can be issued w/o hydrogen sulfide measures Yes Administration 1 Permit. fee attached. NA_ - - - - - -- Appr Date 37 2 Lease number appropriate No Addition t0_107401: Surface location and top prod_ interval in ADL 63279; TD in ADL 391472. Seabed condition survey (if off. -shore) - - 3 Unique well name and number Yes Previous_permit_applications for NCU 10 have expired -Contact-name/phone for weekly progress reports [exploratory only] . - 4 Well located in_a_defined pool _ - No_ - - - - Nicolai Creek Unit North -Undefined Gas Pool 5 Well located proper distance. from drilling unit -boundary - - - Yes I6 Well located proper distance from_ other wells_ No SPACING EXCEPTION R_EQURIED: Less than 3000' from NCU 3. 17 Sufficient acreage available in drilling unit _ No SPACING EXCEPTION REQURIED: Potentially second -gas producer_ in Section 20. 8 If deviated, is -wellbore plat -included Yes 9 Operator only affected party Yes . 10 Operator has appropriate_ bond in force Yes 11 -Permit can be issued without conservation order --- ------------------ _NA Appr Date 12 Permit can be issued without administrative- approval Yes 13 Can permit be approved before 15 -day wait_ Yes SFD 9/7/2010 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. - - - - - - - - - - - - . - I16 Pre -produced injector: duration of pre production less_ than 3 months_ (For service well only) NA - I17 Nonconven. gas conforms to AS31.05.0306.1..A),0,2_.A-D) NA 18 Conductor string provided Yes 13-3/8" driven to 96'. Engineering 19 Surface casing -protects all -known- USDWs - Yes 20 CMT_vo1_adequ_ate_to circulate -on conductor_& surf-csg - - - - - - - - Yes Adequate excess. - - - 21 CMT vol_ adequate. to tie-in long string to surf csg. Yes - 22 CMT_will coverall known -productive horizons_ Yes - - 23 Casing designs adequate for C, -T, B & permafrost Yes Adequate safety factors._ 24 Adequate tankage or reserve pit Yes _ AWS #1._ 25 If a_re-drill, has -a- 1.0-403 for abandonment been approved - - - - - - NA_ New well. _ - - - - - 26 Adequate wellbore separation proposed No_ Spacing exception required. 127 If_diverter required, does it meet regulations_ No Vent line variance required. Appr Date28 Drilling fluidequip list adequate Yes - 11.0schematic_& - - Max MW_11,0_ppg._ WGA 9/14/2010 29 BOPEs,_do they meet regulation - - Yes 30 BOPE_press rating appropriate; test to _(put psig in comments)_ Yes MASP 1621 psi; test to 3000 psi._ 31 Choke manifold complies w/API RP -53 (May 84) Yes 32 Work will occur without operation shutdown_ . . - - Yes . -- - - - _ - - - - 33 Is presence. of 1-12S gas_ probable - - - - No. - Not an H2S area._ 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 expected based on offset drilling, but _H2S_detectors_will _be -utilized._ Geology 36 Data- presented on potential overpressure zones. Yes Expected pressur_egradient_is 0.51 psi/ft (9_.8 ppg_E_MW); will be drilled using_110.0-11.0_ppg mud. Appr Date 37 Seismic analysis- of shallow gas -zones- No - - - Shallow gas is always a danger in this area. A warning along, with mitigation_ measures, is presented in the SFD 9/7/2010 38 Seabed condition survey (if off. -shore) - - NA_ - - - Drilling Hazards_ section of the application along with mitigation measures. I39 -Contact-name/phone for weekly progress reports [exploratory only] . - Yes - - _ - - Ed Jones _281-495-9957._ _ - - - Geologic Engineering Pu Lc SPACING EXCEPTION NEEDED due to being >3000' from a well capable of producing from same pool and because NCU 10 Commissioner: Date: Cone : Date Co er Date could potentially be the second well capable of production in section 20. Spacing hearing vacated August 27th. Order in I/5/v m s- .3'_/J__4rogress. SFD 9/7/2010 Technical Report Title Date Client: Aurora Gas, LLC Field: Nicolai Creek Unit/Gas Field Rig: AWS #1 Date: September 22, 2011 Surface Data Logging End of Well Report Nicolai Creek #10 TABLE OF CONTENTS 1. General Information 2. Daily Summary 3. Morning Reports 4. Bit Record 5. Mud Record 6. Formation Tops 7. Survey Report 8. Days vs. Depth Digital Data to include: Final Logs Log Viewers End of Well Report in PDF format ASCII/LAS Files ADI Backup GENERAL WELL INFORMATION Company: Aurora Gas, LLC Rig: AWS-1 Well: Nicolai Creek #10 Field: Nicolai Creek Gas Field Borough: Anchorage State: Alaska Country: United States API Number: 50-283-20145-00 Sperry Job Number: AK-AM-8348053 Job Start Date: 26 July 2011 Spud Date: 05-Aug-2011 Total Depth: 4833’ North Reference: True Declination: 17.8804 Dip Angle: 73.842 Total Field Strength: 55613 Date Of Magnetic Data: 17 Aug 2011 Wellhead Coordinates N: 61° 1’ 55.01” N Wellhead Coordinates W: 151° 26’ 58.48” W Drill Floor Elevation 16’ Ground Elevation: 240.6’ Permanent Datum: Mean Sea Level SDL Engineers: Mark Lindloff Roderick Porche Company Representatives: Gary Goerlich, Shane Mogeehan SSDS Unit Number: 117 DAILY SUMMARY 8/5/2011 Mudloggers arrived on location. Performed rig site assessment and inspected mudlogging unit. Met with Company Man and Tool Pusher to discuss logistics and rig timelines. Met with Electrician to discuss getting power to the unit. Mudloggers ran preliminary sensor cables. 8/6/2011 Continued to run sensor cables while waiting for mudlogging unit power. Began rigging up rig sensors that weren’t affecting rig operations. Load computers and gas gear into racks and plumb up for operation. 8/7/2011 Hooked up to rig power. Continued rigging up cables and rig sensors. Discovered that the mudlogger barrier box does not operate correctly. Continued to rig up sensors while trouble shooting barrier box. 8/8/2011 Continued to rig up sensors and trouble shoot barrier box. Decision was made to abandon the current barrier box for a temporary setup. Parts on order from Anchorage. 8/9/2011 Worked on piecing together a barrier box with parts from town. Drove to another Sperry SDL job to calibrate pit sensors. Rig floor monitor is rigged up and running. Temporary fix to barrier box is found and worked on with plans to replace with a good working box after TD of Surface Section. 8/10/2011 Add final touches to new barrier box and ready to spud. Company Man’s Insite machine operating. With the cooperation of the rig, mudloggers were preparing to calibrate sensors (hookload, block height, stand pipe pressure, flow out paddle) when it was noted that the stroke sensors were not reacting normally. It was determined that the Insite Software on the Iris computer was miscounting pump strokes. The Iris machine was changed over to a different machine in which the problem was resolved. 20’ to 30’ of data was not collected. Real time pit monitoring was able to be continued during this time. 8/11/2011 Drilled from 100’ MD to 150’ MD. Spudded Surface Section at 80’ MD, drilled to 100’ MD and serviced rig. Tool Pusher’s Insite machine and Data Exchange to town operating. Began drilling ahead. 8/12/2011 Drilled ahead from 150’ MD to 316’ MD. Pulled out of hole to inspect bit due to slow ROP’s. Decided to wait on motors. Picked up and ran in the hole with new bit while waiting on motors. Drilling ahead at midnight. 8/13/2011 Drilled from 320’ MD to 590’ MD. Noted no losses; gas maxed out at 2 units with slight peaks of Methane indicating Coal seams. Iris Machine failed and machines were readjusted. Drilling ahead at midnight. 8/14/2011 Drilled from 590’ MD to a TD of 678’ MD. Well took 25 bbls at 610’ MD; pump rate was slowed and MW was cut to 10.0ppg. Suspected that well began losing immediately preceding the connection and continued after connection once pumps were brought online. Circulated hole clean and prepped for short trip. Short tripped with no significant losses. Ran back in the hole with no losses and circulated. Prepped and pumped a 30 bbls Hi-Vis Walnut sweep. Circulated until hole was clean. Added 3.5 ppb background LCM (Barofibre) into Active mud system. Pulled out of the hole. Rig up to run 9 5/8” casing. 8/15/2011 Run 9 5/8 casing to 660'MD. Circulated well while cutting mud back. Rig pumped 12 ppg cement with no cement returned to surface. Rig up and currently pumping Top job. 8/16/2011 Complete cement top job. Nipple down converter and currently nipple up BOP’s at report time. 8/17/2011 Finished nipple up. Currently testing BOP. 8/18/2011 Finished testing BOP’s, the stack and surface equipment. Tripped in the hole and drilled out cement. Swapped over to EZ- MUD system. Drilled to 698’ (20) feet and prepped to perform leak off test. 8/19/2011 Finish Leak Off Test. LOT = 16.0ppg 200 PSI. Pull out of hole and lay down 6 1/4" drill collars. Pick up mud motor and MWD assembly and run in the hole. Begin drilling from 698’ to 769’ MD. Gas increased at 711’ MD. Average gas was 8 units with a max gas of 24 units. Average ROP for the day was 26 ft/hr with a max ROP of149 ft/hr at 734’ MD. Samples started being sandy but by 750’ were predominately claystone. . 8/20/2011 Continue to pull out of the hole.. Change out collars and pick up MWD. Run in the hole. Drilled from 698’ to 769’. Directional Driller not able to kick off, Pull out of hole to adjust bend on mud motor. Currently running in the hole. Started seeing gas increase at 711’ MD. Average ROP for the day was 26 ft/hr with a max ROP of Max Rop was 736 at 856' MD. Samples predominately claystone. 8/21/2011 Continue to Slide/drill from 769’ to 1204’. Gas averaged 24 units with a Max Gas of 256 units. Average ROP for the day was 35 ft/hr with a max ROP of 357 ft/hr at 880' MD. Samples 100% claystone with occasional intervals of coal. 8/22/2011 Continued to slide/drill. From 1204’ to 1670’ md. Short trip and monitored losses and returns. Returns show hole was clean. Lost power to the unit for about 0.5 hours. Was able to run on UPS battery and no data was lost. Lost power again while being switched over to another generator. Generator was not working right and shut our power down. Therefore we were switched back to the old generator. Tried to start computers and would lose power. Upon investigating found the breaker had tripped and unit was up and running. Run in the hole and continued drilling. Gas averaged 100 units for the day with a max gas of 694 units. Average ROP for the day 68 ft/hr with a max ROP of 319 ft/hr at 1458' MD. Samples 100% Claystone, with intervals of coal. 8/23/2011 Continued to slide drill from 1670’ to 1992'md. Begin short trip to clean the hole. At 1820’ became differentially stuck in an area of coal. Average gas for the day 99 units with a max gas of 416 units. The average ROP for the day 26 ft/hr with a max ROP of 241 fph at 1967' MD. Samples 100% Claystone, with intervals of coal. 8/24/2011 Stuck pipe. Attempted to get unstuck with Jars. Attempted to get unstuck with downjars. Pumped high vis-sweep. Pumped Black Magic (slick'em) pill. 8/25/2011 Continue to work pipe while letting Black Magic soak in. Tried to rotate pipe using tongs. Rigging up wireline to locate stuck point. 8/26/2011 Ran wireline logs till freepoint was found. Spun off BHA Established circulation and pulled out of hole. Rig up and currently running in the hole with down jars and bumper sub. 8/27/2011 Run in hole with downhole jars. Work, jar pipe using downhole jars to free fish. Got fish and circulated until hole was clean with lot of returns over shakers. Pull out of hole. Rig up cleanout assembly. Run in the hole with cleanout assembly. 8/28/2011 Run in hole with cleanout assembly. Drill to 2026' MD. Circulated till returns were clean. Average gas for the day 164 units. Max gas was 211 units.. Average ROP for the day 35 ft/hr with a max ROP of 100 ft/hr at 2018' MD. .Pull out of hole to pick up New BHA. Samples 100% Claystone 8/29/2011 Finish making up BHA. Run in the hole and drill ahead. Drill from 2026 to 2522’ md. Average gas for the day 172 units, Max gas was 466 units at 2248. Average ROP for the day was 140 ft/hr with a max ROP of 192 FPH at 2073'. Samples predominately siltstone but by the end of the day samples increased in sandstone with scattered layers of coal. 8/30/2011 Drilled from 2520 Ft to 2541 Ft. Circulated and cleaned hole. Backreamed from 2541 Ft to 2378 Ft. Tight spots at 2316. Drilled from 2536 Ft to 2813 Ft. Average gas for the day 81 units, Max gas was 628 units. Average ROP for the day was 85 with a max ROP of 205 ft/hr at 2548' MD. Samples predominately loose, unconsolidated sandstone, 8/31/2011 Drilled ahead from 2820' MD' to 3014 MD' and pull out of hole While pulling out hole got stuck at 1028' MD, pulled free and continued to pull out of the hole. Rig up to test BOPS. Average gas for the day 130 units with a max gas of 899 units at 2838'. Average ROP for the day 29 ft/hr with a max ROP of 152 FPH at 2836' MD. Samples predominately loose, unconsolidated sandstone. 9/1/2011 Continue to rig up and test BOPS. Change out liner on pump #2 to 5.5 in. Rig down test equipment. Work on Pump #1. Pick up BHA and run in the hole, test MWD tools and continued to run in hole. 9/2/2011 Finish picking up BHA. Ream 1298' MD to 1575’ MD then circulated down to 2082' MD, sticky at 2082' MD continuing to ream to 2304' MD. Circulate down to 2928' MD. Circulate and condition mud. Drill from 3014’ to 3207' MD. Trip gas was 204 units. Average gas for the drilling period was 98 units max gas was 302 units at 3041'.Average ROP for the day 21ft/hr with a max ROP was 325 ft/hr at 3169' MD. Samples began as unconsolidated sandstone with coal coming in at 3,030’ md then continuing on with sandstone. 9/3/2011 Drilled from 3214' MD to 3500' MD. Increase of 15 BBL observed at 3182'. Pump 20 bbl Hi - vis sweep no increase in cutting at shaker. Pull out of hole 18 singles for short trip. Run in the hole and drill to 3627' MD. Average gas for the day 135 units with a max gas of 939 units at 3526'. Max ROP was 246 FPH at 3468' MD. Samples ranged from sandstone to claystone with intermittent coal layers. By 3500’ samples turned back to unconsolidated to loose sandstone. 9/4/2011 Drilled ahead from 3619' MD to 3996' MD. Pump 25 bbl High - Viscosity sweep 20% increase in cuttings return observed at shaker. Pull out of hole to 3400' MD for short trip. Run in hole and drill ahead 4005' MD. Average gas for the drilling period was 238 units with a max gas of 2,515 units at 3875'. Average ROP was 41 ft/hr with a max ROP of 251 FPH at 3971'. Samples predominately unconsolidated to loose sandstone with intermittent layers of coal. 9/5/2011 Drilled from 4005' MD to 4585' MD with no problems. Decided to drill another 300 ft past planned 4450’ TD. Average gas was 112 units with a max gas of 423 units at 4469'. Average ROP for the day was 49 ft/hr with a max ROP of 199 ft/hr at 4301' MD. Samples predominately unconsolidated to loose sandstone until 4450’ At 4450’md drilled into coal. 9/6/2011 Drilled ahead from 4585' MD to TD 4830'MD. Pump Hi- Vis sweep no increase in cuttings at shakers. Average gas was 90 units with a max gas of 254 units at 4611'. Average ROP was 40 ft/hr with a max ROP of 237 ft/hr at 4592' MD. Start short trip to shoe to clean hole. Samples continued siltstone with intermittent layers of coal then at 4785’md samples became predominately sandstone. 9/7/2011 Finish Pulling out of hole for short trip. Run in hole to +/- 2500' where high levels of gas were encountered (4400 units). Circulate gas out max gas was 5,282 units. Continue to running in the hole to 3200'. Circulate to check for gas (5300 units). Circulate out gas and RIH to bottom. Circulate bottom up without gas. Pump 20 bbl Dry job and start pulling out of the hole. Lay down bottom hole assembly and rig up to run wireline. 9/8/2011 Running wireline. Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs md Drill ahead from 320' to 615', 0.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)1 1 Depth Avg Diam 281 Drilling Goerlich/S. McGeeh 4 Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 773 2.7900 $0.00 466 192 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke % 9.3 mg/l AvgMin Max Max Min Avg pH Chlorides GvlCoal Ambient Air Pit Room 83 Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 1 8/14/2011 615 Tyonek Daily Charges Avg 12.25 0.210 25.4 90.0 Gas (units) ml/30min Max: AGS-1 $0.00 AK-AM-0008348053 12.25 0.210 (ppb Eq)cP PV Size MBT Siltst ClystCht 36.51 23.0 Mill Tooth 573'3310.30 10.30 Sd Depth 8.0 Lst 80' 100 200 Mill Tooth 220' 140' Sh 3' H2S Data Sample Line Avg: Sst Chromatograph (ppm) Silt Mark Lindloff/Ryan Massey Ann Corr Cor Solids (lb/100ft2) 780 24 hr Max YP API Filt 8.0034 Tuff Gas Breakdown Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 83 Siltst Depth H2S Data Sample Line md Circulated until hole was clean. POOH out of hole and rig up to run casing. Running casing at report time. Drill ahead from 615' to 684', TD section.Circulated BU, POOH for short trip. Run back to bottom and pump a sweep. 0 0 Total Charges: Flow In (spm) SPP (psi)0.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)1 1 641' Depth Avg Diam AvgMin Max Max 69 Running Casaing Goerlich/S. McGeeh 4 656' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 0 2.7900 $33,870.00 pH Chlorides GvlCoal Ambient Air Pit Room Clyst 9.0 % 8.3 mg/l Min Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 2 8/15/2011 684 Tyonek Daily Charges Avg 12.25 0.210 22.0 140.0 Gas (units) ml/30min Max: AGS-1 $3,520.00 AK-AM-0008348053 12.25 0.210 (ppb Eq)cP PV Size MBT Ann Corr Cor Solids (lb/100ft2) 800 24 hr Max YP API Filt 8.50 Avg Gallons/stroke Lst 80' 100 200 Mill Tooth 202' 140' Sh 3 3' 23.0 Mill Tooth 684' 202' 684' 3210.30 10.30 Sd Roderick Porche/Ryan Massey Avg: 38 Tuff Gas Breakdown Avg: Chromatograph (ppm) SiltSst Cht 12.90 464' 36.51 Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 36.51 Roderick Porche/Ryan Massey Avg: 9.90 9.90 Sd 17 Tuff Gas Breakdown Avg: Daily Charges Avg 12.25 0.210 Gas (units) ml/30min Max: $2,320.00 12.25 0.210 (ppb Eq)cP PV Size MBT SiltSst Cht 12.90 464' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 3 8/16/2011 684 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 600 24 hr Max Min Lst 80' 100 200 Mill Tooth 202' 140' Sh 3 3' 23.0 Mill Tooth 684' 202' 684' Clyst Max Max YP API Filt 8.00 Avg Chromatograph (ppm) 0 Rig and pump Top job Goerlich/S. McGeeh $35,865.00Total Charges: Min 2.0 % 7.8 mg/l 31 GvlCoal Ambient Air Pit Room Gallons/stroke Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 0 2.7900 pH Chlorides 0 0 Flow In (spm) SPP (psi) Avg 0.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)1 1 Depth Avg Diam md pumped 12 ppg cement with no cement returned to surface. Rig up and pump Top job at report time g g g g p p j p ppg cement with no cement returned to surface. Rig up and pump top job at report time. Max: Hole Condition On Bot Hrs 61 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 61 Siltst Depth H2S Data Sample Line md Finished cement top job. Nipple and nipple down. Nippleup at report time. 0.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)1 1 Depth Avg Diam Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 0 2.7900 pH Chlorides 0 0 Flow In (spm) SPP (psi) Avg 0 Rig up BOP Goerlich/S. McGeeh $36,515.00Total Charges: Min 8.0 % 7.8 mg/l 31 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max YP API Filt 8.00 Avg Chromatograph (ppm) Min Lst 80' 100 200 Mill Tooth 202' 140' Sh 3 3' 23.0 Mill Tooth 684' 202' 684' SiltSst Cht 12.90 464' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 4 8/17/2011 684 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 600 24 hr Max Daily Charges Avg 12.25 0.210 Gas (units) ml/30min Max: $2,320.00 12.25 0.210 (ppb Eq)cP PV Size MBT 9.90 9.90 Sd 17 Tuff Gas Breakdown Avg: 36.51 Roderick Porche/Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 36.51 Roderick Porche/Mark Lindlof Avg: 10.00 10.00 Sd 8 Tuff Gas Breakdown Avg: Daily Charges Avg 12.25 0.210 Gas (units) ml/30min Max: $2,320.00 12.25 0.210 (ppb Eq)cP PV Size MBT SiltSst Cht 12.90 464' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 5 8/18/2011 684 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 600 24 hr Max Min Lst 80' 100 200 Mill Tooth 202' 140' Sh 3 3' 23.0 Mill Tooth 684' 202' 684' Clyst Max Max YP API Filt 8.00 Avg Chromatograph (ppm) 0 Testing Goerlich/S. McGeeh $36,890.00Total Charges: Min 8.0 % 7.8 mg/l 7 GvlCoal Ambient Air Pit Room Gallons/stroke Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 0 2.7900 pH Chlorides 0 0 Flow In (spm) SPP (psi) Avg 0.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)1 1 Depth Avg Diam md Finished nipple up. Tested BOP. Test stack and surface. Testing at report time. Max: Hole Condition On Bot Hrs 44 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 42 Siltst Depth H2S Data Sample Line md EZ- MUD system. Drilled 20' feet and did a shoe test. LOT = 16.0ppg 200 PSI. POOH at report time. Finished testing BOP. Finished testing stack and surface equipment. TIH and Drilled out cement. Swapped over to 0.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)1 1 Depth Avg Diam Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 0 2.7900 pH Chlorides 0 0 Flow In (spm) SPP (psi) Avg 0 POOH Goerlich/S. McGeeh $39,640.00Total Charges: Min 20.0 % 6.8 mg/l 16 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max YP API Filt 9.00 Avg Chromatograph (ppm) Min Lst 202' 200 300 PDC 684' 464' Sh 5 3 0.0 Mill Tooth 684' 684' 698' SiltSst Cht 12.90 14' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 6 8/19/2011 684 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 15,000 24 hr Max Daily Charges Avg 8.5 0.752 Gas (units) ml/30min Max: $3,070.00 12.25 0.210 (ppb Eq)cP PV Size MBT 10.00 10.00 Sd 32 Tuff Gas Breakdown Avg: 12.90 Roderick Porche/Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 12.90 Roderick Porche/Mark Lindlof Avg: 10.00 10.00 Sd 13 Tuff Gas Breakdown Avg: Daily Charges Avg 8.5 0.752 26.0 149.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.752 (ppb Eq)cP PV Size MBT Silt 90 Sst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 7 8/20/2011 769.05 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 17,000 24 hr Max Min Lst 684' 300 400 PDC 698' 14' Sh 5 7.5 PDC 768' 698' Clyst Max Max CLY YP API Filt 9.00 Avg Chromatograph (ppm) 10 71 Drilling Goerlich/S. McGeeh $40,515.00Total Charges: Min 8.0 % 6.6 mg/l 13 GvlCoal Ambient Air Pit Room Gallons/stroke24729' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 1685 2.7900 pH Chlorides 515 195 Flow In (spm) SPP (psi) Avg 13.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)1 8 734' Depth Avg Diam md gas was 24 units @ 729'. Drilling ahead at report time. g y @ g 24 units @729' MD. Max: Hole Condition On Bot Hrs 36 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 6.80 Roderick Porche/Mark Lindlof Avg: 10.00 10.00 Sd 18 Tuff Gas Breakdown Avg: Daily Charges Avg 8.5 0.902 26.0 736.0 Gas (units) ml/30min Max: $2,320.00 8.5 0.752 (ppb Eq)cP PV Size MBT SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 8 8/21/2011 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 15,000 24 hr Max Min Lst 698'400 500 PDC 862'164' Sh 6 7.5 PDC 768' 698' Clyst Max Max CLY YP API Filt 7.50 Avg Chromatograph (ppm) 93 TIH Goerlich/S. McGeeh $45,065.00Total Charges: Min 6.0 100 % 2.0 mg/l 12 GvlCoal Ambient Air Pit Room Gallons/stroke23848' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ NA 2.7900 pH Chlorides NA NA Flow In (spm) SPP (psi) Avg NA Max @ ft Current R.O.P. (ft/hr) Gas (units)NA 7 856' Depth Avg Diam md change out bit and nozzles. TIH at report time. Drilled to 862' MD. Max gas was 23 units at 848' MD. Max Rop was 736 at 856' MD. POOH to dail mud motor up and Max: Hole Condition On Bot Hrs 37 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 36 Siltst Depth H2S Data Sample Line md drilling and sliding at report time. Finish TIH with BHA. Drilled to 1204' MD. Max ROP was 357 fph at 880' MD. Max gas was 259 units at 1106'. Continue 16.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)27 23 880' Depth Avg Diam 259 1106' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 1388 2.7900 pH Chlorides 448 160 Flow In (spm) SPP (psi) Avg 342 Drilling Goerlich/S. McGeeh $48,135.00Total Charges: Min 7.0 100 % 5.2 mg/l 11 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max CLY YP API Filt 7.50 Avg Chromatograph (ppm) Min Lst 698'400 500 PDC 862'164' Sh 6 7.5 PDC 1170' 862' SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 9 8/22/2011 1204 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 22,000 24 hr Max Daily Charges Avg 8.5 0.902 35.0 357.0 Gas (units) ml/30min Max: $2,320.00 8.5 0.752 (ppb Eq)cP PV Size MBT 9.80 9.80 Sd 11 Tuff Gas Breakdown Avg: 6.80 Roderick Porche/Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 1633 Max: Hole Condition On Bot Hrs 240 1453694 1586 37 Siltst Depth H2S Data Sample Line md and return.TIH back to bottom and continued drilling ahead. Max rop was 319 fph at 1458' MD. Max gas was 694 units at 1453. Drilling ahead at report time. Continued to drill down to 1484' MD. Circulated bottoms up and do a short trip at 1484' MD and monitored for losses 24.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)32 70 1458' Depth Avg Diam 694 1453' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 1206 2.7900 pH Chlorides 396 141 Flow In (spm) SPP (psi) Avg 446 Drilling Goerlich/S. McGeeh $51,205.00Total Charges: Min 6.0 100 % 6.5 mg/l 12 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max CLY YP API Filt 8.50 Avg Chromatograph (ppm) 542 147 1416 Min Lst 698'400 500 PDC 862'164' Sh 6 7.5 PDC 1660' 862' 162 1610 1571230 1558 335 293 SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 10 8/23/2011 1670' Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 18,000 24 hr Max 1266 1359 Daily Charges Avg 8.5 0.902 68.0 319.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.752 (ppb Eq)cP PV Size MBT 9.80 9.80 Sd 16 Tuff Gas Breakdown 279 Avg: 6.80 Roderick Porche/Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 6.80 Roderick Porche/Mark Lindlof Avg: 9.60 9.60 Sd 18 Tuff Gas Breakdown 266 Avg: 1674 1695 Daily Charges Avg 8.5 0.902 26.0 241' Gas (units) ml/30min Max: $3,070.00 8.5 0.752 (ppb Eq)cP PV Size MBT SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 11 8/24/2011 1992' Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 16,000 24 hr Max 238 1893 1780310 1767 207 243 325 202 1717 Min Lst 698'400 500 PDC 862'164' Sh 6 7.5 PDC 1992' 862' Clyst Max Max CLY YP API Filt 8.50 Avg Chromatograph (ppm) 322 Drilling Goerlich/S. McGeeh $54,275.00Total Charges: Min 7.0 100 % 4.7 mg/l 11 GvlCoal Ambient Air Pit Room Gallons/stroke4161737' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 1432 2.7900 pH Chlorides 455 162 Flow In (spm) SPP (psi) Avg NA Max @ ft Current R.O.P. (ft/hr) Gas (units)6 70 1967' Depth Avg Diam md time we are doing a short trip. Continued to slide and drill to 1992' MD. Max gas was 416 units at 1737'. Max rop was 241 fph at 1967' MD. At report 1976 Max: Hole Condition On Bot Hrs 353 1737416 1820 38 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 54 Siltst Depth H2S Data Sample Line md Pumped Black Magic (slick'em). Max gas was 15 units. Wating on Black Magic at report time. Stuck pipe at 1992' MD. Attempted to get unstuck with jars. Attempted with downjars. Pumped a high vis sweep. NA Max @ ft Current R.O.P. (ft/hr) Gas (units)NA NA NA Depth Avg Diam 12 NA Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ NA 2.7900 pH Chlorides NA NA Flow In (spm) SPP (psi) Avg NA Waiting on pill Goerlich/S. McGeeh $57,345.00Total Charges: Min 7.0 100 % 6.8 mg/l 20 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max CLY YP API Filt 8.50 Avg Chromatograph (ppm) Min Lst 698'400 500 PDC 862'164' Sh 6 7.5 PDC 1992' 862' SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 12 8/25/2011 1992' Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 15,000 24 hr Max Daily Charges Avg 8.5 0.902 NA NA Gas (units) ml/30min Max: $3,070.00 8.5 0.752 (ppb Eq)cP PV Size MBT 9.60 9.60 Sd 38 Tuff Gas Breakdown Avg: 6.80 Roderick Porche/Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 52 Siltst Depth H2S Data Sample Line md where we are stuck at. Wireline at report time. Stuck pipe Work pipe while letting Black Magic soak in. Tried to rotate pipe using tongs. Rig up wireline to locate NA Max @ ft Current R.O.P. (ft/hr) Gas (units)NA NA NA Depth Avg Diam NA NA Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ NA 2.7900 pH Chlorides NA NA Flow In (spm) SPP (psi) Avg NA Wireline Goerlich/S. McGeeh $60,415.00Total Charges: Min 7.0 100 % 5.7 mg/l 21 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max CLY YP API Filt 8.50 Avg Chromatograph (ppm) Min Lst 698'400 500 PDC 862'164' Sh 6 7.5 PDC 1992' 862' SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 13 8/26/2011 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 15,000 24 hr Max Daily Charges Avg 8.5 0.902 NA NA Gas (units) ml/30min Max: $3,070.00 8.5 0.752 (ppb Eq)cP PV Size MBT 9.60 9.60 Sd 39 Tuff Gas Breakdown Avg: 6.80 Roderick Porche/Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 6.80 Roderick Porche/Mark Lindlof Avg: 9.60 9.60 Sd 31 Tuff Gas Breakdown Avg: Daily Charges Avg 8.5 0.902 NA NA Gas (units) ml/30min Max: $3,070.00 8.5 0.752 (ppb Eq)cP PV Size MBT SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 14 8/27/2011 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 15,000 24 hr Max Min Lst 698'400 500 PDC 862'164' Sh 6 7.5 PDC 1992' 862' Clyst Max Max CLY YP API Filt 8.50 Avg Chromatograph (ppm) NA RIH Goerlich/S. McGeeh $62,735.00Total Charges: Min 7.0 100 % 5.7 mg/l 18 GvlCoal Ambient Air Pit Room Gallons/strokeNANA Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ NA 2.7900 pH Chlorides NA NA Flow In (spm) SPP (psi) Avg NA Max @ ft Current R.O.P. (ft/hr) Gas (units)NA NA NA Depth Avg Diam md downhole jars and bumper sub. TIH at report time. Finish running wireline logs. Found freepoint.Spun off BHA. Estabilished circulation and POOH. Rig up and RIH with Max: Hole Condition On Bot Hrs 54 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 59 Siltst Depth H2S Data Sample Line md lot of returns over shakers. POOH. R/U cleanout assembly. TIH with cleanout assembly at report time. RIH with downhole jars and work and jar pipe using downhole jars got pipe free. Circulated until hole was clean with NA Max @ ft Current R.O.P. (ft/hr) Gas (units)NA NA NA Depth Avg Diam NA NA Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ NA 2.7900 pH Chlorides NA NA Flow In (spm) SPP (psi) Avg NA TIH Goerlich/S. McGeeh $65,055.00Total Charges: Min 5.0 100 % 5.6 mg/l 21 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max CLY YP API Filt 7.50 Avg Chromatograph (ppm) Min Lst 698'400 500 PDC 862'164' Sh 5 7 7.5 PDC 1992' 862' 1992' SiltSst Cht 32.78 1130' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 15 8/28/2011 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 17,000 24 hr Max Daily Charges Avg 8.5 0.902 NA 136.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.752 (ppb Eq)cP PV Size MBT 9.50 9.60 Sd 41 Tuff Gas Breakdown Avg: 6.80 Roderick Porche/Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 2025 Max: Hole Condition On Bot Hrs 182 2009211 2018 69 Siltst Depth H2S Data Sample Line md 100 FPH at 2018' MD. POOH. RU NEW BHA. TIH with BHA at report time. TIH with cleanout assembly. Drill to 2026' MD. Circulated till return was clean. Max gas was 211 units. Max ROP was NA Max @ ft Current R.O.P. (ft/hr) Gas (units)NA NA 2018' Depth Avg Diam 211 2009' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ NA 2.7900 pH Chlorides NA NA Flow In (spm) SPP (psi) Avg 34 TIH With BHA Goerlich/S. McGeeh $67,375.00Total Charges: Min 6.2 100 % 5.6 mg/l 16 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max CLY YP API Filt 8.50 Avg Chromatograph (ppm) 193 195 2007 Min Lst 862' 500 600 TRICONE 1992' 1130' Sh 8 5 7.5 PDC 2026' 1992' 2026' 181 2021 2015162 2011 161 195 SiltSst Cht 0.26 34' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 16 8/29/2011 2026' MD Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 17,000 24 hr Max 1996 1998 Daily Charges Avg 8.5 0.920 35.0 100.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT 9.50 9.50 Sd 37 Tuff Gas Breakdown 141 Avg: 32.78 Roderick Porche/Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 2530 Max: Hole Condition On Bot Hrs 202 2162250 2350 82 Siltst Depth 90 H2S Data Sample Line md MD. Drill to 2541' MD and Circulated bottoms up. Making a short trip at report time. Finish making up BHA. TIH with BHA and drill ahead. Max gas was 466 units at 2248' Max rop was 192 FPH at 2073' 47.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)89 85 2073' Depth Avg Diam 466 2248' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 1174 2.7900 pH Chlorides 285 134 Flow In (spm) SPP (psi) Avg 506 TIH With BHA Goerlich/S. McGeeh $71,690.60Total Charges: Min 6.5 % 5.6 mg/l 22 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max CLY YP API Filt 8.50 Avg Chromatograph (ppm) 163 239 2072 Min Lst 1992' 600 700 Tricone 2026'34' Sh 8 7.5 PDC 2477' 2026' 265 2417 2280392 2248 424 466 SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 17 8/30/2011 2532' MD Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 17,000 24 hr Max 2033 2053 Daily Charges Avg 8.5 0.920 140.0 192.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT 9.50 9.50 Sd 41 Tuff Gas Breakdown 131 Avg: 0.26 Roderick Porche/Mark Lindlof Avg: 10 Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 2780 Max: Hole Condition On Bot Hrs 318 2692349 2742 60 Siltst Depth 25 H2S Data Sample Line md 2316' MD. Change swab and liner and H2 pump. Drilled from 2532' MD to 2820' MD. Max gas was 628 units at 2700'. Max rop was 205 FPH at 2548' MD. Drilling ahead at report time. Drilled from 2520' MD to 2541' MD. Circulated and clean hole. Back reamed from 2541' MD to 2378' MD. Tight spot at 21.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)163 81 2548' Depth Avg Diam 628 2700' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 1351 2.7900 pH Chlorides 380 136 Flow In (spm) SPP (psi) Avg 288 TIH With BHA Goerlich/S. McGeeh $74,728.20Total Charges: Min 7.0 % 6.6 mg/l 14 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max CLY YP API Filt 8.50 Avg Chromatograph (ppm) 15 440 510 2656 Min Lst 1992' 600 700 Tricone 2026'34' Sh 8 10.0 PDC 2813' 2026' 170 2758 2714267 2700 235 628 SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 18 8/31/2011 2820' MD Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 17,000 24 hr Max 2646 2650 Daily Charges Avg 8.5 0.920 85.0 205.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT 9.30 9.30 Sd 28 Tuff Gas Breakdown 317 Avg: 0.26 Roderick Porche/Mark Lindlof Avg: 60 Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 11.71 Roderick Porche/Mark Lindlof Avg: 60 9.40 9.40 Sd 33 Tuff Gas Breakdown 258 Avg: 2829 2833 Daily Charges Avg 29.0 152.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 19 9/01/2011 3014' MD Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 12,000 24 hr Max 178 2987 2894185 2842 159 498 564 804 2836 Min Lst 2026' 700 3014' 988' Sh 10 9.0 Tricone 3014' Clyst Max Max CLY YP API Filt 8.50 Avg Chromatograph (ppm) 15 194 R/U TEST BOP Goerlich/S. McGeeh $77,798.20Total Charges: Min 10.0 % 7.0 mg/l 12 GvlCoal Ambient Air Pit Room Gallons/stroke8992838' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ NA 2.7900 pH Chlorides NA NA Flow In (spm) SPP (psi) Avg NA Max @ ft Current R.O.P. (ft/hr) Gas (units)NA 130 2836' Depth Avg Diam md While pulling out hole got stuck at 1028' MD. Pull free and continued to POOH . Rigging to test BOP at report time. Drilled ahead from 2820' MD' to 3014 MD'. Max gas was 899 units at 2838'. Max rop was 152 FPH at 2836' MD. POOH 3004 Max: Hole Condition On Bot Hrs 156 2838899 2945 55 Siltst Depth 25 H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 11.71 Roderick Porche/Mark Lindlof Avg: 9.30 9.30 Sd 11 Tuff Gas Breakdown Avg: Daily Charges Avg 8.5 0.902 NA NA Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 20 9/02/2011 NA Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 12,000 24 hr Max Min Lst 2026' 700 800 Tricone 3014' 988' Sh 10 5.0 Tricone 3014' 3014' Clyst Max Max YP API Filt 9.00 Avg Chromatograph (ppm) NA TIH With BHA Goerlich/S. McGeeh $80,868.20Total Charges: Min 6.0 % 6.0 mg/l 11 GvlCoal Ambient Air Pit Room Gallons/strokeNANA Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ NA 2.4680 pH Chlorides NA NA Flow In (spm) SPP (psi) Avg NA Max @ ft Current R.O.P. (ft/hr) Gas (units)NA NA NA Depth Avg Diam md and TIH test MWD tools. Continued to TIH with BHA at report time. R/U and test BOP. Change out liner on pump #2 to 5.5 in. Rig down test equipment. Work on Pump #1 Pick up BHA Max: Hole Condition On Bot Hrs 47 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 11.71 Roderick Porche/Mark Lindlof Avg: 5040 9.40 9.40 Sd 20 Tuff Gas Breakdown 206 Avg: 3015 3029 Daily Charges Avg 8.5 0.902 21.0 325.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 21 9/03/2011 3207' Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 18,000 24 hr Max 111 3183 3140133 3112 72 101 102 302 3041 Min Lst 2026' 700 800 Tricone 3014' 988' Sh 10 3.0 Tricone 3214' 3014' Clyst Max Max YP API Filt 8.50 Avg Chromatograph (ppm) 10 193 TIH With BHA Goerlich/S. McGeeh $93,626.40Total Charges: Min 6.0 % 6.6 mg/l 17 GvlCoal Ambient Air Pit Room Gallons/stroke3023041' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 1590 2.4680 pH Chlorides 416 176 Flow In (spm) SPP (psi) Avg 51.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)62 54 3169' Depth Avg Diam md Circulate to 2928' MD. Circulate and condition mud. Drill to 3207' MD. Trip gas was 204 units. Max gas was 302 units at 3041'. Max rop was 325 fph at 3169' MD. Drilling ahead at report time. Finish P/U BHA. Ream 1298' MD to 1575 ft MD. Circulate down to 2082' MD, sticky at 2082' MD. Ream to 2304' MD. 3190 Max: Hole Condition On Bot Hrs 84 3055228 3157 49 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 11.71 Roderick Porche/Mark Lindlof Avg: 40 9.40 9.40 Sd 30 Tuff Gas Breakdown 134 Avg: 3250 3262 Daily Charges Avg 8.5 0.902 39.0 246.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 22 9/04/2011 3627 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 19,000 24 hr Max 81 3574 3526939 3425 607 334 311 531 3338 Min Lst 2026' 700 800 Tricone 3014' 988' Sh 10 2.5 Tricone 3562' 3014' Clyst Max Max YP API Filt 8.50 Avg Chromatograph (ppm) 20 420 TIH With BHA Goerlich/S. McGeeh $96,696.40Total Charges: Min 4.8 40 % 6.5 mg/l 24 GvlCoal Ambient Air Pit Room Gallons/stroke9393526' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 1803 2.4680 pH Chlorides 416 173 Flow In (spm) SPP (psi) Avg 32.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)84 86 3468' Depth Avg Diam md cutting at shaker.POOH 18 single for short trip. RIH and drill to 3627' MD. Max gas was 939 units at 3526'. Max rop was 246 FPH at 3468' MD. Drilling ahead at report time. Drilled from 3214' MD to 3500' MD. Increase of 15 BBL observed at 3182'. Pump 20 bbl Hi - vis sweep no increase in 3589 Max: Hole Condition On Bot Hrs 299 3407239 3532 72 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 11.71 Roderick Porche/Mark Lindlof Avg: 9.50 9.50 Sd 26 Tuff Gas Breakdown 240 Avg: 3649 3652 Daily Charges Avg 8.5 0.902 41.0 251.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 23 9/05/2011 4005 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 18,000 24 hr Max 329 3893 3831479 3726 2515 378 630 347 3656 Min Lst 2026' 700 800 Tricone 3014' 988' Sh 10 2.5 Tricone 4004' 3014' Clyst Max Max YP API Filt 8.50 Avg Chromatograph (ppm) 378 TIH With BHA Goerlich/S. McGeeh $99,766.40Total Charges: Min 5.0 % 6.5 mg/l 22 GvlCoal Ambient Air Pit Room Gallons/stroke2,515 3875' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 1964 2.4680 pH Chlorides 425 183 Flow In (spm) SPP (psi) Avg 44.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)176 238 3971' Depth Avg Diam md POOH to 3400' MD for short trip. RIH and drill ahead 4005' MD. Max gas was 2,515 units at 3875'. Max rop was 251 FPH at 3971' MD. Drilling ahead at report time. Drilled ahead from 3619' MD to 3996' MD. Pump 25 bbl Hi - Vis sweep 20% increase in cutting observed at shaker. 3952 Max: Hole Condition On Bot Hrs 154 3717225 3875 56 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 4537 Max: Hole Condition On Bot Hrs 135 4229121 4469 63 Siltst Depth 60 H2S Data Sample Line md at report time. Drilled from 4005' MD to 4585' MD. Max gas was 423 units at 4469'. Max ROP was 199 FPH at 4301' MD. Drilling ahead 70.0 Max @ ft Current R.O.P. (ft/hr) Gas (units)81 112 4301' Depth Avg Diam 423 4469' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 1919 2.4680 pH Chlorides 413 176 Flow In (spm) SPP (psi) Avg 580 Drilling Ahead Goerlich/S. McGeeh $102,836.40Total Charges: Min 4.5 % 6.5 mg/l 23 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max YP API Filt 8.00 Avg Chromatograph (ppm) 318 191 4040 Min Lst 2026' 700 800 Tricone 3014' 988' Sh 10 2.5 Tricone 4570' 3014' 376 4490 4305223 4283 423 155 SiltSst Cht Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 23 9/06/2011 4585 Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 19,000 24 hr Max 4025 4029 Daily Charges Avg 8.5 0.902 49.0 199.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT 9.50 9.50 Sd 28 Tuff Gas Breakdown 118 Avg: 11.71 Roderick Porche/Mark Lindlof Avg: 40 Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 4817 Max: Hole Condition On Bot Hrs 80 4631158 4748 61 Siltst Depth 15 H2S Data Sample Line md units at 4611'. Max rop was 237 FPH at 4592' MD. POOH to 2160' MD for short trip. POOH at report time. Drilled ahead from 4585' MD to 4830'MD.Pump Hi- Vis sweep no increase in cuttings at shakers. Max gas was 254 Max @ ft Current R.O.P. (ft/hr) Gas (units)90 4592' Depth Avg Diam 254 4611' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 2.4680 pH Chlorides Flow In (spm) SPP (psi) Avg 248 Short Trip Goerlich/S. McGeeh $105,458.20Total Charges: Min 4.5 % 6.5 mg/l 22 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max YP API Filt 9.00 Avg Chromatograph (ppm) 10 222 253 4618 Min Lst 2026' 700 800 Tricone 3014' 988' Sh 12 10 2.5 Tricone 4830' 3014' 4830' 116 4754 469484 4672 142 151 SiltSst Cht 1816' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 25 9/07/2011 4830' Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 18,000 24 hr Max 4590 4609 Daily Charges Avg 8.5 0.902 40.0 237.0 Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT 9.50 9.50 Sd 30 Tuff Gas Breakdown 85 Avg: 11.71 Roderick Porche/Mark Lindlof Avg: 75 Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 70 Siltst Depth H2S Data Sample Line md Wireline. max gas was 5,282 units. Continune RIH to 3200'. Circulate to check for gas ( 5300 ppm). Circulate out gas and RIH to TD. Circulate bottom up with out gas. Pump 20 bbls Dry job and POOH. POOH out of hole at report time. Once out of hole R/U for Finish POOH for short trip. TIH to +/- 2500' where high levels of gas were encontered ( 4400 ppm). Circulate gas out Max @ ft Current R.O.P. (ft/hr) Gas (units) Depth Avg Diam 5,282 2050' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 2.4680 pH Chlorides Flow In (spm) SPP (psi) Avg NA POOH Goerlich/S. McGeeh $108,611.75Total Charges: Min 4.5 % 6.5 mg/l 27 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max YP API Filt 9.00 Avg Chromatograph (ppm) Min Lst 2026' 700 800 Tricone 3014' 988' Sh 12 10 2.5 Tricone 4830' 3014' 4830' SiltSst Cht 1816' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 26 9/08/2011 NA Tyonek AGS-1 AK-AM-0008348053 Ann Corr Cor Solids (lb/100ft2) 18,000 24 hr Max Daily Charges Avg 8.5 0.902 Gas (units) ml/30min Max: $3,070.00 8.5 0.902 (ppb Eq)cP PV Size MBT 9.70 9.70 Sd 27 Tuff Gas Breakdown Avg: 11.71 Roderick Porche/Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 74 Siltst Depth H2S Data Sample Line md Running wireline logs. Max @ ft Current R.O.P. (ft/hr) Gas (units) Depth Avg Diam Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 2.4680 pH Chlorides Flow In (spm) SPP (psi) Avg NA Run Wireline Goerlich/S. McGeeh $109,926.75Total Charges: Min 5.0 % 6.6 mg/l 19 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max 2-3-WT-A-E-NO-TD YP API Filt 8.00 Avg Chromatograph (ppm) Min Lst 2026' 700 800 Tricone 3014' 988' Sh 11 11 2.0 Tricone 4830' 3014' 4830' SiltSst Cht 1816' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 28 9/10/2011 4830 Tyonek AGS-1 AK-AM-0008348053 1-2-WT-A-E-I-CT-HR Ann Corr Cor Solids (lb/100ft2) 17,000 24 hr Max Daily Charges Avg 8.5 0.902 Gas (units) ml/30min Max: $1,315.00 8.5 0.902 (ppb Eq)cP PV Size MBT 9.70 9.70 Sd 96 86 23 Tuff Gas Breakdown Avg: 11.71 Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air 27.51 Mark Lindlof Avg: 9.70 9.70 Sd 96 86 21 Tuff Gas Breakdown Avg: Daily Charges Avg 8.5 0.902 Gas (units) ml/30min Max: $1,315.00 8.5 0.902 (ppb Eq)cP PV Size MBT SiltSst Cht 52.14 1816' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 28 9/10/2011 4830 Tyonek AGS-1 AK-AM-0008348053 1-2-WT-A-E-I-CT-HR Ann Corr Cor Solids (lb/100ft2) 17,000 24 hr Max Min Lst 2026' 700 800 Tricone 3014' 988' Sh 11 11 2.0 Tricone 4830' 3014' 4830' Clyst Max Max 2-3-WT-A-E-NO-TD YP API Filt 8.00 Avg Chromatograph (ppm) NA P/U Cleanout Run Goerlich/S. McGeeh $111,241.75Total Charges: Min 5.0 % 6.6 mg/l 20 GvlCoal Ambient Air Pit Room Gallons/stroke Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 2.4680 pH Chlorides Flow In (spm) SPP (psi) Avg Max @ ft Current R.O.P. (ft/hr) Gas (units) Depth Avg Diam md Running wireline logs. Currently rigging up for clean out run. Max: Hole Condition On Bot Hrs 74 Siltst Depth H2S Data Sample Line Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 84 Siltst Depth H2S Data Sample Line md cuttings at shakers). POOH and LD BHA. Rig up to RIH with casing. 253 units Max gas at report time. y p p ( Circulate and condition mud. Pump 25 Max @ ft Current R.O.P. (ft/hr) Gas (units)12 38 Depth Avg Diam 253 Cir Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 2.4680 pH Chlorides Flow In (spm) SPP (psi) Avg NA Run Casing Goerlich/S. McGeeh $112,556.75Total Charges: Min 5.0 % 6.6 mg/l 25 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max 2-3-WT-A-E-NO-TD YP API Filt 8.00 Avg Chromatograph (ppm) Min Lst 2026' 700 800 Tricone 3014' 988' Sh 11 11 2.0 Tricone 4830' 3014' 4830' SiltSst Cht 52.14 1816' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 29 9/11/2011 4830 Tyonek AGS-1 AK-AM-0008348053 1-2-WT-A-E-I-CT-HR Ann Corr Cor Solids (lb/100ft2) 17,000 24 hr Max Daily Charges Avg 8.5 0.902 Gas (units) ml/30min Max: $1,315.00 8.5 0.902 (ppb Eq)cP PV Size MBT 9.70 9.70 Sd 96 86 29 Tuff Gas Breakdown Avg: 27.51 Mark Lindlof Avg: Customer:Report #: Well:Date: Area:00:00 Depth Location:Progress 24 hrs: Rig:Rig Activity: Job No.:Report For: ROP & Gas: . Mud Data:Density (ppg)Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:*10000 units = 100% Gas In Air Max: Hole Condition On Bot Hrs 84/65 Siltst Depth H2S Data Sample Line md Preparing for Cement Job at time of Report. Continued running casing in hole. Lost approximately 2 bbls to hole while running the casing. Max @ ft Current R.O.P. (ft/hr) Gas (units)28 38 Depth Avg Diam 98 4817' Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ 2.4680 pH Chlorides Flow In (spm) SPP (psi) Avg NA Preparing for Cement Goerlich/S. McGeeh $113,871.75Total Charges: Min 5.0 % 4.3/2.3 mg/l 25/120 GvlCoal Ambient Air Pit Room Gallons/stroke Clyst Max Max 2-3-WT-A-E-NO-TD YP API Filt 8@65 Avg Chromatograph (ppm) Min Lst 2026' 700 800 Tricone 3014' 988' Sh 11 11 2.5 Tricone 4830' 3014' 4830' SiltSst Cht 52.14 1816' Aurora Gas, LLC Nicolai Creek 10 Nicolai Creek 10 30 9/12/2011 4830 Tyonek AGS-1 AK-AM-0008348053 1-2-WT-A-E-I-CT-HR Ann Corr Cor Solids (lb/100ft2) 17,000 24 hr Max Daily Charges Avg 8.5 0.902 Gas (units) ml/30min Max: $1,315.00 8.5 0.902 (ppb Eq)cP PV Size MBT 9.70 9.70 Sd 96 86 30 Tuff Gas Breakdown Avg: 27.51 Steve Gales, Jr. Avg: WELL NAME:Nicolai Creek #10LOCATION:Nicolai Gas FieldOPERATOR:Aurora Gas, LLCAREA:Nicolai Creek FieldMUD CO:BaroidSTATE:AlaskaRIG:Aurora Well Svcs #1SPUD:5-Aug-11SPERRY JOB:AK-AM-8348053TD:5-Sep-11BIT RECORDBHA # Bit # Bit Type Bit SizeDepth InDepth OutFootage Bit HoursTFA AVG ROPWOB (max)RPM (max)SPP(max)FLOW GPM (max)Bit Grade Remarks1 1 Mill Tooth 12.25 80 202 122 36.51 -3.3 70 600 474 - POOH to change Bit2 2 Mill Tooth 12.25 202 678 476 12.90 -36.9 26.80 2385 581 - TD 12 1/4" Section3 3 Tricone 8.50 678 698 20 0.41 0.751748.8 7.80 850 167 2-2-CT-A-E-I-NO-BHAPOOH to Change Out BHA4 4 PDC 8.50 698 862 164 8.04 0.751720.4 25 70 1600 500 4-8-BT-A-X-I-ER-BHAPOOH do to Not building Angle5 5 PDC 8.50 862 1992 1130 42.51 0.902026.6 15 801600 500 4-4-LM-A-X-I-NR-HP Stuck Pipe. Retrieved Fish6 3rr1 Tricone 8.50 1992 2026 34 0.75 Open45.3 10 80900 400 2-2-CT-A-E-I-NO-BHAClean out Run7 7 Tricone 8.50 2026 3014 988 27.51 0.920435.9 15 901420 440 1-2-WT-A-E-I-CT-HRPOOH to Test BOP's8 8 Tricone 8.50 3014 4830 1816 52.14 0.920434.8 20 1002090 435 2-3-WT-A-E-I-NO-TDTD Nicolai #10 WELL NAME:Nicolai Creek #10LOCATION:Nicolai Creek UnitOPERATOR:Aurora Gas LLCAREA:Nicolai CreekMUD CO:BaroidSTATE:AlaskaRIG:Aurora Well Svcs #1SPUD:5-Aug-11SPERRY JOB:AK-AM-8348053TD:6-Sep-11 Water Based Mud RecordDate Depth Wt Vis PV YP Gels FiltR600/R300/R200/R100/R6/R3Cake SolidsOil/WaterSd Pm pH MBT Pf/Mf Chlor Hard Remarksft - MD ppg sec cP lb/100 lb/100ft2 m/30m Rheometer 32nds % % % ppb Eqv mg/l Ca++11-Aug 12010.40 82 32 37 8/21/1938 8.0 101/69/54/39/10/9 3 10.8 0.0/89.0 4 0.2 8.7 23 0.15/0.30 500 40 Drilling12-Aug 32010.00 83 21 34 24/49/56 9.0 76/55/44/31/14/12 3 10.8 0.0/89 4 0.3 8.5 23 0.15/0.35 800 40 Drilling13-Aug 59510.30 83 33 34 10/46/55 8.0 100/67/52/34/9/7 3 9.3 0.0/90.5 2.5 0.25 8 23 0.10/0.30 780 40 Drilling14-Aug 678 10.30 83 32 38 12/47/56 9.0 102/70/54/36/12/10 3.0 8.3 0.0/92.0 1.50 0.30 8.5 23.0 0.20/0.35 800 40 Run Casing15-Aug 678 9.90 61 31 17 4/5/6 2.0 79/48/36/21/4/2 2.0 7.8 0.0/92.0 1.60 0.00 8.0 23.0 0.00/0.10 600 240 Wait on cement16-Aug 678 9.90 61 31 17 4/5/6 8.0 79/48/36/21/4/2 2.0 7.8 0.0/92.0 1.60 0.00 8.0 23.0 0.00/1.00 600 240 nipple up BOP17-Aug 678 10.00 44 7 8 6/15/24 8.0 22/15/10/7/4/3 2.0 7.8 0.0/94.5 1.40 0.00 8.0 23.0 0.00/1.00 600 240 Testing B.O.P.18-Aug 700 10.00 42 16 32 15/19/20 8.0 64/48/44/37/4/3 2.0 6.8 0.0/92.0 0.50 1.20 9.0 0.0 0.50/1.80 15,000 80 Drilling19-Aug 768 10.00 36 13 13 5/11/15 8.0 39/26/22/16/8/7 1.0 6.7 0.0/92.0 1.20 0.70 9.0 7.5 0.40/70 17,000 80 Drilling20-Aug 862 10.00 37 12 18 5/7/8 6.0 42/30/24/17/5/4 2.0 6.8 0.0/92.0 1.20 0.50 8.5 7.5 0.10/0.80 15,000 200 Tripping21-Aug 1170 9.00 36 11 11 4/6/9 7.0 33/22/17/11/3/2 2.0 5.2 0.0/93.0 1.00 0.20 8.5 7.5 0.10/0.60 22,000 400 Drilling22-Aug 1660 9.80 10 12 16 5/14/19 6.0 40/28/22/16/5/4 2.0 6.5 0.0/93.0 1.00 0.20 8.5 7.5 0.00/0.30 18,000 520 Drilling23-Aug 1992 9.60 38 11 18 7/15/19 7.0 40/29/24/18/7/5 2.0 4.7 0.0/94.0 0.60 0.00 8.5 7.5 0.00/0.30 16,000 800 Tripping24-Aug 1992 9.60 54 20 38 14/26/30 7.0 78/58/50/38/16/14 2.0 6.8 0.0/92.0 0.50 0.00 7.5 8.5 0.00/0.30 15,000 920 Waiting on Black Magic Pill25-Aug 1992 9.60 52 21 29 12/18/24 7.0 71/50/41/32/11/9 2.0 5.7 0.0/93.0 0.40 0.10 8.5 7.5 0.00/0.30 15,000 840 Rig up Wireline26-Aug 1992 9.60 54 18 31 11/16/19 7.0 67/49/39/28/10/9 2.0 5.7 0.0/93.0 0.30 0.00 8.5 7.5 0.00/0.30 15,000 920 Wire Line Logs27-Aug 1992 9.50 59 21 41 16/24/29 5.0 83/62/55/43/16/14 2 5.6 0.0/93.0 0.40 0.40 8.5 7.5 0.10/0.60 17,000 920 Rig up28-Aug 2026 9.50 69 16 37 16/27/32 6.2 69/53/48/39/18/16 2 5.6 2.0/91.0 0.30 0.10 8.5 7.5 0.10/0.40 17,000 920 Drilling29-Aug 2477 9.50 82 22 41 18/24/30 6.5 85/63/56/46/23/18 2 5.6 2.0/91.0 1.00 0.00 8.5 7.5 0.00/0.60 17,000 960 Drilling30-Aug 2813 9.40 60 14 28 17/30/0 7.0 56/42/37/30/18/17 2 6.6 2.0/90.0 1.00 0.00 8.5 10.0 0.00/0.60 17,000 600 Drilling31-Aug 3014 9.40 55 12 33 23/43/55 10.0 57/45/38/33/24/21 2 7.0 2.0/90.0 0.25 0.10 8.5 9.0 0.10/0.80 12,000 600 Tripping1-Sep 3014 9.30 47 11 11 5/7/12 6.0 33/22/18/12/4/2 2 6.0 2.0/91.0 0.25 0.10 9.0 5.0 0.10/1.00 12,000 600 Tripping2-Sep 3214 9.40 49 17 20 12/18/24 6.0 54/37/24/16/12/8 2 6.6 2.0/90.0 0.25 0.10 8.5 3.0 0.10/1.10 18,000 600 Drilling3-Sep 3562 9.40 72 24 30 10/25/32 4.8 78/54/47/34/11/9 2 6.5 1.0/91.0 0.25 0.10 8.5 2.5 0.10/1.10 19,000 800 Drilling4-Sep 4004 9.50 56 22 26 7/15/21 5.0 70/48/39/29/10/6 1 6.5 1.0/91.0 0.25 0.10 8.5 2.5 0.10/1.10 18,000 800 Drilling5-Sep 4570 9.50 63 23 28 7/16/21 4.5 74/51/41/27/8/6 1 6.5 0.5/91.5 0.25 0.10 8.0 2.5 0.10/1.00 19,000 800 Drilling6-Sep 4830 9.50 61 22 30 8/16/21 4.5 74/52/43/31/9/8 1 6.5 0.5/91.5 0.25 0.10 9.0 2.5 0.15/1.10 18,000 750 POOH7-Sep4830 9.7 70 27 277/14/204.581/54/44/31/8/616.50.5/91.50.250.1 92.5 0.20/1.10 18000 800 POOH8-Sep4830 9.7 74 19 23 - 5.0 61/42/33/23/6/4 1 6.6 0.5/91.5 0.15 0.1 8 2 0.10/0.80 17000 750Running Wireline9-Sep4830 9.7 74 20 21 - 5.0 61/41/33/23/6/4 1 6.6 0.0/92.0 0.1 0.1 8 2 0.10/0.80 17000 750Taking Dev Surveys10-Sep4830 9.784 25 29 7/15/20 5.0 79/54/43/31/8/6 1 6.6 0.0/92.0 0.10 0.10 8 2.0 0.10/0.80 17000 800 Run Casing11-Sep4830 9.784 25 30 8/14/22 5.0 80/55/45/32/9/7 1 6.6 0.0/92.0 0.10 0.10 8 2.5 0.10/1.0 17000 800 Cir, Condition MudCasing Record16" Conductor @ 15811.75" Intermediate @ 3512'9.625" Intermediate @ 11,6587' 7" Intermediate @ 14,082' Marker MD INC AZ TVD TVDSS Beluga 790.0 0.18 28.46 798.99 -542 Top Tyonek Coal 1684.0 27.49 317.34 1626.00 -1369 Carya 2-1.1 1980.0 25.93 317.83 1891.00 -1634 Carya 2-2 2208.0 26.87 321.18 2095.00 -1838 Carya 2-3 2664.0 28.20 319.26 2501.00 -2244 Carya 2-4 3046.0 28.19 318.61 2838.00 -2581 Carya 2-4.1 3258.0 26.94 320.97 3026.00 -2769 Carya 2-4.2 (aka Tyonek "C")3420.0 26.40 319.19 3170.00 -2913 Carya 2-5 3589.0 26.33 319.71 3295.00 -3038 Carya 2-6 3820.0 26.18 318.88 3529.00 -3272 Carya 2-7 (aka Tyomek "D")4512.0 25.53 320.73 4151.00 -3894 Nicolai Creek #10 Interpolated Tops 14 September, 2011 Cook Inlet Nicolai Creek Unit NCU#10 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: NCU#10 NCU#10 Survey Calculation Method:Minimum Curvature NCU #10 @ 266.00ft (250 + 16) Design:NCU #10 Database:.Sperry EDM .16 PRD MD Reference:NCU #10 @ 266.00ft (250 + 16) North Reference: Well NCU#10 Grid Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Cook Inlet, COOK INLET BASIN Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: ft +E/-W +N/-S Position Uncertainty ft ft ftGround Level: NCU#10 ft ft 0.00 0.00 2,571,972.10 242,963.07 250.00Wellhead Elevation:0.00 ft0.00 61° 1' 55.015 N 151° 26' 58.48 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NCU#10 Model NameMagnetics BGGM2011 8/15/2006 19.50 73.78 55,588 Phase:Version: Audit Notes: Design NCU #10 1.0 ACTUAL Vertical Section: Depth From (TVD) (ft) +N/-S (ft) Direction (°) +E/-W (ft) Tie On Depth:25.40 320.970.000.0016.00 From (ft) Survey Program DescriptionTool NameSurvey (Wellbore) To (ft) Date 9/14/2011 Survey Start Date BLIND Blind drilling100.00 660.00 NCU #10 (BLIND) (NCU#10)08/22/2011 MWD MWD - Standard704.06 4,772.76 NCU #10 (MWD) (NCU#10)09/13/2011 MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 25.40 0.00 0.00 25.40 0.00 0.00-240.60 2,571,972.10 242,963.07 0.00 0.00 UNDEFINED 100.00 0.00 360.00 100.00 0.00 0.00-166.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 200.00 0.00 360.00 200.00 0.00 0.00-66.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 300.00 0.00 360.00 300.00 0.00 0.0034.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 400.00 0.00 360.00 400.00 0.00 0.00134.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 500.00 0.00 360.00 500.00 0.00 0.00234.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 660.00 0.00 360.00 660.00 0.00 0.00394.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 704.06 0.41 87.85 704.06 0.01 0.16438.06 2,571,972.11 242,963.22 0.93 -0.09 MWD (2) 735.52 0.28 148.51 735.52 -0.06 0.31469.52 2,571,972.05 242,963.38 1.16 -0.24 MWD (2) 766.98 0.18 28.46 766.98 -0.08 0.37500.98 2,571,972.02 242,963.44 1.28 -0.30 MWD (2) 798.38 0.85 321.80 798.38 0.15 0.25532.38 2,571,972.25 242,963.32 2.54 -0.04 MWD (2) 829.83 2.38 315.55 829.81 0.80 -0.35563.81 2,571,972.90 242,962.72 4.89 0.84 MWD (2) 861.26 4.11 315.96 861.19 2.07 -1.59595.19 2,571,974.18 242,961.48 5.50 2.61 MWD (2) 9/14/2011 9:50:41AM COMPASS 2003.16 Build 71 Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: NCU#10 NCU#10 Survey Calculation Method:Minimum Curvature NCU #10 @ 266.00ft (250 + 16) Design:NCU #10 Database:.Sperry EDM .16 PRD MD Reference:NCU #10 @ 266.00ft (250 + 16) North Reference: Well NCU#10 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 892.71 6.93 323.18 892.49 4.40 -3.51626.49 2,571,976.51 242,959.56 9.22 5.63 MWD (2) 924.11 8.57 322.77 923.61 7.78 -6.06657.61 2,571,979.88 242,957.01 5.23 9.86 MWD (2) 955.50 8.88 324.15 954.63 11.61 -8.89688.63 2,571,983.71 242,954.17 1.19 14.62 MWD (2) 986.92 10.22 326.06 985.62 15.89 -11.87719.62 2,571,987.99 242,951.20 4.38 19.82 MWD (2) 1,018.37 10.74 323.50 1,016.54 20.56 -15.17750.54 2,571,992.66 242,947.90 2.22 25.52 MWD (2) 1,049.89 11.11 320.81 1,047.49 25.27 -18.84781.49 2,571,997.37 242,944.23 2.00 31.49 MWD (2) 1,081.34 12.89 320.72 1,078.25 30.34 -22.97812.25 2,572,002.44 242,940.09 5.66 38.03 MWD (2) 1,112.90 15.14 322.26 1,108.87 36.32 -27.73842.87 2,572,008.42 242,935.34 7.23 45.67 MWD (2) 1,144.29 17.79 322.68 1,138.97 43.38 -33.14872.97 2,572,015.48 242,929.93 8.45 54.57 MWD (2) 1,175.69 19.91 322.21 1,168.69 51.42 -39.33902.69 2,572,023.52 242,923.74 6.77 64.71 MWD (2) 1,207.11 21.33 320.69 1,198.09 60.07 -46.23932.09 2,572,032.17 242,916.84 4.83 75.77 MWD (2) 1,238.59 21.76 318.85 1,227.37 68.89 -53.69961.37 2,572,040.99 242,909.37 2.54 87.33 MWD (2) 1,269.97 22.85 317.06 1,256.41 77.73 -61.67990.41 2,572,049.83 242,901.40 4.09 99.22 MWD (2) 1,301.38 25.04 318.83 1,285.11 87.20 -70.201,019.11 2,572,059.30 242,892.87 7.34 111.95 MWD (2) 1,332.84 26.57 319.00 1,313.43 97.52 -79.201,047.43 2,572,069.62 242,883.87 4.87 125.63 MWD (2) 1,364.18 26.65 317.97 1,341.45 108.04 -88.511,075.45 2,572,080.13 242,874.56 1.49 139.66 MWD (2) 1,395.64 26.68 318.43 1,369.57 118.56 -97.921,103.57 2,572,090.66 242,865.15 0.66 153.76 MWD (2) 1,427.03 27.27 318.27 1,397.54 129.20 -107.381,131.54 2,572,101.30 242,855.69 1.89 167.98 MWD (2) 1,458.51 27.45 317.78 1,425.50 139.95 -117.061,159.50 2,572,112.05 242,846.01 0.92 182.43 MWD (2) 1,489.51 27.53 318.09 1,453.00 150.58 -126.641,187.00 2,572,122.68 242,836.43 0.53 196.72 MWD (2) 1,521.31 27.09 318.09 1,481.26 161.44 -136.391,215.26 2,572,133.53 242,826.68 1.38 211.29 MWD (2) 1,552.66 27.44 317.96 1,509.12 172.11 -145.991,243.12 2,572,144.21 242,817.08 1.13 225.64 MWD (2) 1,584.07 27.44 318.36 1,537.00 182.90 -155.651,271.00 2,572,154.99 242,807.42 0.59 240.09 MWD (2) 1,615.43 27.11 318.04 1,564.87 193.61 -165.231,298.87 2,572,165.71 242,797.84 1.15 254.45 MWD (2) 1,646.85 27.57 317.19 1,592.78 204.27 -174.961,326.78 2,572,176.36 242,788.12 1.92 268.85 MWD (2) 1,678.30 27.49 317.34 1,620.67 214.94 -184.821,354.67 2,572,187.04 242,778.25 0.34 283.36 MWD (2) 1,709.72 27.29 317.30 1,648.57 225.57 -194.621,382.57 2,572,197.67 242,768.45 0.64 297.78 MWD (2) 1,741.20 27.07 316.70 1,676.57 236.09 -204.431,410.57 2,572,208.18 242,758.65 1.12 312.13 MWD (2) 1,772.61 26.82 317.01 1,704.57 246.47 -214.161,438.57 2,572,218.57 242,748.91 0.91 326.33 MWD (2) 1,835.49 26.12 317.04 1,760.86 266.98 -233.261,494.86 2,572,239.07 242,729.81 1.11 354.29 MWD (2) 1,866.95 26.04 316.97 1,789.12 277.09 -242.701,523.12 2,572,249.19 242,720.38 0.27 368.08 MWD (2) 1,898.41 26.03 316.21 1,817.39 287.12 -252.181,551.39 2,572,259.22 242,710.89 1.06 381.85 MWD (2) 1,976.32 25.93 317.83 1,887.42 312.09 -275.451,621.42 2,572,284.18 242,687.62 0.92 415.90 MWD (2) 2,007.90 25.48 317.52 1,915.88 322.22 -284.671,649.88 2,572,294.31 242,678.40 1.49 429.57 MWD (2) 2,039.36 25.94 318.86 1,944.22 332.39 -293.771,678.22 2,572,304.48 242,669.30 2.36 443.20 MWD (2) 2,070.86 26.84 319.26 1,972.44 342.97 -302.941,706.44 2,572,315.06 242,660.13 2.91 457.20 MWD (2) 2,102.27 26.91 320.53 2,000.46 353.83 -312.091,734.46 2,572,325.92 242,650.98 1.84 471.39 MWD (2) 2,165.07 27.28 320.99 2,056.37 375.98 -330.181,790.37 2,572,348.07 242,632.89 0.68 499.99 MWD (2) 2,196.47 26.87 321.18 2,084.33 387.10 -339.161,818.33 2,572,359.19 242,623.91 1.33 514.29 MWD (2) 2,227.94 26.68 319.88 2,112.42 398.04 -348.171,846.42 2,572,370.14 242,614.90 1.96 528.46 MWD (2) 9/14/2011 9:50:41AM COMPASS 2003.16 Build 71 Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: NCU#10 NCU#10 Survey Calculation Method:Minimum Curvature NCU #10 @ 266.00ft (250 + 16) Design:NCU #10 Database:.Sperry EDM .16 PRD MD Reference:NCU #10 @ 266.00ft (250 + 16) North Reference: Well NCU#10 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 2,259.42 26.75 320.26 2,140.54 408.90 -357.261,874.54 2,572,380.99 242,605.82 0.59 542.61 MWD (2) 2,290.84 26.10 319.16 2,168.68 419.56 -366.301,902.68 2,572,391.65 242,596.78 2.59 556.59 MWD (2) 2,322.36 25.69 319.42 2,197.03 430.00 -375.271,931.03 2,572,402.09 242,587.80 1.35 570.35 MWD (2) 2,353.78 25.69 319.69 2,225.35 440.36 -384.111,959.35 2,572,412.45 242,578.97 0.37 583.97 MWD (2) 2,385.26 26.70 319.36 2,253.59 450.93 -393.131,987.59 2,572,423.02 242,569.95 3.24 597.86 MWD (2) 2,416.77 26.63 319.63 2,281.75 461.68 -402.322,015.75 2,572,433.78 242,560.76 0.44 611.99 MWD (2) 2,448.20 26.51 319.84 2,309.86 472.41 -411.402,043.86 2,572,444.50 242,551.68 0.48 626.05 MWD (2) 2,479.65 26.20 319.14 2,338.04 483.03 -420.472,072.04 2,572,455.12 242,542.61 1.40 640.01 MWD (2) 2,511.15 26.82 320.01 2,366.23 493.73 -429.592,100.23 2,572,465.82 242,533.49 2.32 654.06 MWD (2) 2,574.07 27.67 319.49 2,422.17 515.71 -448.202,156.17 2,572,487.80 242,514.88 1.40 682.86 MWD (2) 2,605.59 28.13 319.80 2,450.03 526.95 -457.752,184.03 2,572,499.04 242,505.33 1.53 697.60 MWD (2) 2,637.04 28.21 319.97 2,477.75 538.31 -467.322,211.75 2,572,510.40 242,495.76 0.36 712.45 MWD (2) 2,668.35 28.20 319.26 2,505.34 549.58 -476.902,239.34 2,572,521.67 242,486.18 1.07 727.24 MWD (2) 2,699.76 28.09 318.97 2,533.04 560.78 -486.602,267.04 2,572,532.87 242,476.48 0.56 742.05 MWD (2) 2,731.27 28.24 318.04 2,560.82 571.92 -496.452,294.82 2,572,544.01 242,466.62 1.47 756.91 MWD (2) 2,762.73 28.57 318.67 2,588.49 583.10 -506.402,322.49 2,572,555.19 242,456.68 1.42 771.86 MWD (2) 2,794.31 28.31 317.95 2,616.26 594.34 -516.402,350.26 2,572,566.42 242,446.68 1.36 786.88 MWD (2) 2,825.77 28.05 318.13 2,643.99 605.38 -526.342,377.99 2,572,577.47 242,436.74 0.87 801.72 MWD (2) 2,857.23 28.40 319.23 2,671.71 616.56 -536.162,405.71 2,572,588.64 242,426.92 1.99 816.59 MWD (2) 2,888.67 28.52 318.74 2,699.35 627.86 -545.992,433.35 2,572,599.95 242,417.09 0.84 831.56 MWD (2) 2,920.12 28.50 318.99 2,726.99 639.17 -555.872,460.99 2,572,611.25 242,407.22 0.38 846.56 MWD (2) 2,965.92 28.47 318.12 2,767.24 655.54 -570.322,501.24 2,572,627.63 242,392.76 0.91 868.38 MWD (2) 2,997.36 28.19 317.48 2,794.92 666.59 -580.342,528.92 2,572,638.68 242,382.74 1.31 883.28 MWD (2) 3,028.79 28.19 318.61 2,822.62 677.63 -590.272,556.62 2,572,649.72 242,372.81 1.70 898.11 MWD (2) 3,060.21 27.78 319.82 2,850.37 688.80 -599.902,584.37 2,572,660.88 242,363.18 2.23 912.85 MWD (2) 3,091.53 27.90 318.80 2,878.06 699.89 -609.442,612.06 2,572,671.97 242,353.64 1.57 927.47 MWD (2) 3,122.90 27.75 319.89 2,905.81 710.99 -618.982,639.81 2,572,683.08 242,344.11 1.69 942.10 MWD (2) 3,154.33 28.06 319.17 2,933.58 722.18 -628.522,667.58 2,572,694.27 242,334.56 1.46 956.81 MWD (2) 3,185.77 27.21 319.41 2,961.43 733.24 -638.042,695.43 2,572,705.32 242,325.05 2.73 971.38 MWD (2) 3,217.21 27.48 319.58 2,989.36 744.22 -647.422,723.36 2,572,716.30 242,315.67 0.89 985.82 MWD (2) 3,248.69 26.94 320.51 3,017.36 755.25 -656.662,751.36 2,572,727.34 242,306.42 2.18 1,000.21 MWD (2) 3,280.14 27.12 320.92 3,045.37 766.31 -665.712,779.37 2,572,738.40 242,297.37 0.82 1,014.50 MWD (2) 3,311.57 26.98 318.98 3,073.36 777.26 -674.912,807.36 2,572,749.34 242,288.18 2.84 1,028.79 MWD (2) 3,343.03 27.13 319.56 3,101.38 788.10 -684.242,835.38 2,572,760.18 242,278.84 0.96 1,043.10 MWD (2) 3,374.48 26.30 318.88 3,129.47 798.81 -693.482,863.47 2,572,770.89 242,269.61 2.81 1,057.23 MWD (2) 3,405.97 26.40 319.19 3,157.69 809.36 -702.642,891.69 2,572,781.44 242,260.45 0.54 1,071.20 MWD (2) 3,437.36 26.21 318.44 3,185.83 819.83 -711.802,919.83 2,572,791.91 242,251.29 1.22 1,085.10 MWD (2) 3,468.86 26.94 318.89 3,214.00 830.41 -721.112,948.00 2,572,802.49 242,241.98 2.40 1,099.18 MWD (2) 3,500.48 26.56 320.13 3,242.24 841.23 -730.352,976.24 2,572,813.31 242,232.74 2.14 1,113.40 MWD (2) 3,531.82 25.95 319.43 3,270.35 851.82 -739.303,004.35 2,572,823.90 242,223.79 2.18 1,127.27 MWD (2) 9/14/2011 9:50:41AM COMPASS 2003.16 Build 71 Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: NCU#10 NCU#10 Survey Calculation Method:Minimum Curvature NCU #10 @ 266.00ft (250 + 16) Design:NCU #10 Database:.Sperry EDM .16 PRD MD Reference:NCU #10 @ 266.00ft (250 + 16) North Reference: Well NCU#10 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 3,563.19 25.69 319.14 3,298.58 862.17 -748.213,032.58 2,572,834.26 242,214.88 0.92 1,140.92 MWD (2) 3,594.54 26.33 319.71 3,326.76 872.62 -757.153,060.76 2,572,844.70 242,205.93 2.19 1,154.67 MWD (2) 3,625.78 26.35 318.52 3,354.76 883.10 -766.223,088.76 2,572,855.18 242,196.86 1.69 1,168.52 MWD (2) 3,657.21 26.50 319.56 3,382.90 893.66 -775.393,116.90 2,572,865.74 242,187.69 1.55 1,182.50 MWD (2) 3,688.62 26.43 319.63 3,411.02 904.32 -784.473,145.02 2,572,876.40 242,178.62 0.24 1,196.49 MWD (2) 3,720.05 26.53 319.30 3,439.15 914.97 -793.573,173.15 2,572,887.05 242,169.51 0.57 1,210.50 MWD (2) 3,751.45 25.92 318.71 3,467.32 925.44 -802.683,201.32 2,572,897.52 242,160.41 2.11 1,224.37 MWD (2) 3,782.91 26.60 317.82 3,495.53 935.83 -811.943,229.53 2,572,907.91 242,151.15 2.50 1,238.27 MWD (2) 3,814.33 26.18 318.88 3,523.68 946.26 -821.223,257.68 2,572,918.34 242,141.86 2.01 1,252.22 MWD (2) 3,845.74 26.57 317.41 3,551.82 956.65 -830.533,285.82 2,572,928.73 242,132.55 2.42 1,266.16 MWD (2) 3,877.20 26.13 318.64 3,580.01 967.03 -839.873,314.01 2,572,939.11 242,123.21 2.23 1,280.10 MWD (2) 3,908.67 26.11 317.94 3,608.27 977.38 -849.093,342.27 2,572,949.45 242,114.00 0.98 1,293.94 MWD (2) 3,940.18 26.37 318.72 3,636.53 987.78 -858.353,370.53 2,572,959.86 242,104.73 1.37 1,307.86 MWD (2) 3,971.70 26.56 321.12 3,664.75 998.53 -867.403,398.75 2,572,970.61 242,095.69 3.45 1,321.90 MWD (2) 4,003.20 26.65 320.39 3,692.91 1,009.45 -876.323,426.91 2,572,981.53 242,086.77 1.08 1,336.01 MWD (2) 4,034.76 26.76 321.49 3,721.11 1,020.47 -885.263,455.11 2,572,992.54 242,077.83 1.60 1,350.19 MWD (2) 4,066.21 26.09 321.78 3,749.27 1,031.44 -893.943,483.27 2,573,003.52 242,069.15 2.17 1,364.18 MWD (2) 4,097.70 26.06 321.51 3,777.56 1,042.29 -902.533,511.56 2,573,014.37 242,060.56 0.39 1,378.02 MWD (2) 4,129.17 26.09 320.88 3,805.82 1,053.07 -911.203,539.82 2,573,025.15 242,051.89 0.89 1,391.86 MWD (2) 4,160.66 26.30 320.12 3,834.08 1,063.80 -920.043,568.08 2,573,035.88 242,043.05 1.26 1,405.76 MWD (2) 4,192.12 25.88 321.46 3,862.33 1,074.52 -928.793,596.33 2,573,046.59 242,034.30 2.30 1,419.59 MWD (2) 4,223.56 25.86 321.16 3,890.62 1,085.23 -937.363,624.62 2,573,057.30 242,025.73 0.42 1,433.31 MWD (2) 4,255.02 26.04 320.27 3,918.91 1,095.88 -946.083,652.91 2,573,067.96 242,017.01 1.36 1,447.07 MWD (2) 4,286.55 26.02 320.45 3,947.24 1,106.54 -954.913,681.24 2,573,078.61 242,008.18 0.26 1,460.91 MWD (2) 4,317.95 26.15 321.03 3,975.44 1,117.23 -963.653,709.44 2,573,089.30 241,999.45 0.91 1,474.72 MWD (2) 4,349.34 25.48 321.55 4,003.70 1,127.89 -972.193,737.70 2,573,099.97 241,990.90 2.25 1,488.39 MWD (2) 4,380.84 25.82 320.93 4,032.10 1,138.52 -980.733,766.10 2,573,110.60 241,982.36 1.38 1,502.02 MWD (2) 4,412.34 25.94 321.57 4,060.44 1,149.25 -989.343,794.44 2,573,121.32 241,973.75 0.97 1,515.77 MWD (2) 4,443.61 25.74 322.78 4,088.58 1,160.01 -997.703,822.58 2,573,132.08 241,965.40 1.80 1,529.40 MWD (2) 4,475.15 25.05 321.84 4,117.07 1,170.72 -1,005.963,851.07 2,573,142.79 241,957.13 2.53 1,542.92 MWD (2) 4,506.69 25.53 320.73 4,145.59 1,181.23 -1,014.393,879.59 2,573,153.30 241,948.70 2.14 1,556.39 MWD (2) 4,537.96 25.56 320.77 4,173.81 1,191.67 -1,022.923,907.81 2,573,163.74 241,940.17 0.11 1,569.87 MWD (2) 4,569.56 25.60 321.34 4,202.31 1,202.28 -1,031.503,936.31 2,573,174.35 241,931.59 0.79 1,583.52 MWD (2) 4,600.89 25.24 320.74 4,230.60 1,212.74 -1,039.963,964.60 2,573,184.81 241,923.14 1.41 1,596.97 MWD (2) 4,631.17 25.05 319.99 4,258.02 1,222.65 -1,048.163,992.02 2,573,194.72 241,914.93 1.23 1,609.83 MWD (2) 4,663.67 24.52 320.48 4,287.52 1,233.12 -1,056.884,021.52 2,573,205.19 241,906.22 1.75 1,623.45 MWD (2) 4,695.04 24.99 320.17 4,316.01 1,243.23 -1,065.264,050.01 2,573,215.30 241,897.83 1.55 1,636.59 MWD (2) 4,726.31 25.47 319.82 4,344.30 1,253.44 -1,073.834,078.30 2,573,225.51 241,889.26 1.61 1,649.92 MWD (2) 4,757.76 25.10 318.81 4,372.73 1,263.63 -1,082.594,106.73 2,573,235.70 241,880.51 1.81 1,663.34 MWD (2) 4,772.76 25.30 319.38 4,386.31 1,268.45 -1,086.774,120.31 2,573,240.52 241,876.32 2.10 1,669.73 MWD (2) 9/14/2011 9:50:41AM COMPASS 2003.16 Build 71 Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: NCU#10 NCU#10 Survey Calculation Method:Minimum Curvature NCU #10 @ 266.00ft (250 + 16) Design:NCU #10 Database:.Sperry EDM .16 PRD MD Reference:NCU #10 @ 266.00ft (250 + 16) North Reference: Well NCU#10 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 4,830.00 25.30 319.38 4,438.06 1,287.02 -1,102.704,172.06 2,573,259.09 241,860.40 0.00 1,694.18 PROJECTED to TD 9/14/2011 9:50:41AM COMPASS 2003.16 Build 71 Page 6 14 September, 2011 Cook Inlet Nicolai Creek Unit NCU#10 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: NCU#10 NCU#10 Survey Calculation Method:Minimum Curvature NCU #10 @ 266.00ft (250 + 16) Design:NCU #10 Database:.Sperry EDM .16 PRD MD Reference:NCU #10 @ 266.00ft (250 + 16) North Reference: Well NCU#10 True Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Cook Inlet, COOK INLET BASIN Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: ft +E/-W +N/-S Position Uncertainty ft ft ftGround Level: NCU#10 ft ft 0.00 0.00 2,571,972.10 242,963.07 250.00Wellhead Elevation:0.00 ft0.00 61° 1' 55.015 N 151° 26' 58.48 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) NCU#10 Model NameMagnetics BGGM2011 8/15/2006 19.50 73.78 55,588 Phase:Version: Audit Notes: Design NCU #10 1.0 ACTUAL Vertical Section: Depth From (TVD) (ft) +N/-S (ft) Direction (°) +E/-W (ft) Tie On Depth:25.40 319.700.000.0025.40 From (ft) Survey Program DescriptionTool NameSurvey (Wellbore) To (ft) Date 9/14/2011 Survey Start Date BLIND Blind drilling100.00 660.00 NCU #10 (BLIND) (NCU#10)08/22/2011 MWD MWD - Standard704.06 4,772.76 NCU #10 (MWD) (NCU#10)09/13/2011 MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 25.40 0.00 0.00 25.40 0.00 0.00-240.60 2,571,972.10 242,963.07 0.00 0.00 UNDEFINED 100.00 0.00 358.73 100.00 0.00 0.00-166.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 200.00 0.00 358.73 200.00 0.00 0.00-66.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 300.00 0.00 358.73 300.00 0.00 0.0034.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 400.00 0.00 358.73 400.00 0.00 0.00134.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 500.00 0.00 358.73 500.00 0.00 0.00234.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 660.00 0.00 358.73 660.00 0.00 0.00394.00 2,571,972.10 242,963.07 0.00 0.00 BLIND (1) 704.06 0.41 86.58 704.06 0.01 0.16438.06 2,571,972.11 242,963.22 0.93 -0.09 MWD (2) 735.52 0.28 147.24 735.52 -0.05 0.31469.52 2,571,972.05 242,963.38 1.16 -0.24 MWD (2) 766.98 0.18 27.19 766.98 -0.07 0.38500.98 2,571,972.02 242,963.44 1.28 -0.30 MWD (2) 798.38 0.85 320.53 798.38 0.15 0.25532.38 2,571,972.25 242,963.32 2.54 -0.04 MWD (2) 829.83 2.38 314.28 829.81 0.79 -0.37563.81 2,571,972.90 242,962.72 4.89 0.84 MWD (2) 861.26 4.11 314.69 861.19 2.04 -1.63595.19 2,571,974.18 242,961.48 5.50 2.61 MWD (2) 9/14/2011 9:54:00AM COMPASS 2003.16 Build 71 Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: NCU#10 NCU#10 Survey Calculation Method:Minimum Curvature NCU #10 @ 266.00ft (250 + 16) Design:NCU #10 Database:.Sperry EDM .16 PRD MD Reference:NCU #10 @ 266.00ft (250 + 16) North Reference: Well NCU#10 True MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 892.71 6.93 321.91 892.49 4.32 -3.61626.49 2,571,976.51 242,959.56 9.22 5.63 MWD (2) 924.11 8.57 321.50 923.61 7.65 -6.23657.61 2,571,979.88 242,957.01 5.23 9.86 MWD (2) 955.50 8.88 322.88 954.63 11.41 -9.15688.63 2,571,983.71 242,954.17 1.19 14.62 MWD (2) 986.92 10.22 324.79 985.62 15.62 -12.22719.62 2,571,987.99 242,951.20 4.38 19.82 MWD (2) 1,018.37 10.74 322.23 1,016.54 20.22 -15.62750.54 2,571,992.66 242,947.90 2.22 25.52 MWD (2) 1,049.89 11.11 319.54 1,047.49 24.85 -19.39781.49 2,571,997.37 242,944.23 2.00 31.49 MWD (2) 1,081.34 12.89 319.45 1,078.25 29.82 -23.64812.25 2,572,002.44 242,940.09 5.66 38.03 MWD (2) 1,112.90 15.14 320.99 1,108.87 35.70 -28.52842.87 2,572,008.42 242,935.34 7.23 45.67 MWD (2) 1,144.29 17.79 321.41 1,138.97 42.63 -34.09872.97 2,572,015.48 242,929.93 8.45 54.57 MWD (2) 1,175.69 19.91 320.94 1,168.69 50.54 -40.46902.69 2,572,023.52 242,923.74 6.77 64.71 MWD (2) 1,207.11 21.33 319.42 1,198.09 59.03 -47.54932.09 2,572,032.17 242,916.84 4.83 75.77 MWD (2) 1,238.59 21.76 317.58 1,227.37 67.69 -55.21961.37 2,572,040.99 242,909.37 2.54 87.33 MWD (2) 1,269.97 22.85 315.79 1,256.41 76.35 -63.38990.41 2,572,049.83 242,901.40 4.09 99.22 MWD (2) 1,301.38 25.04 317.56 1,285.11 85.63 -72.121,019.11 2,572,059.30 242,892.87 7.34 111.95 MWD (2) 1,332.84 26.57 317.73 1,313.43 95.75 -81.341,047.43 2,572,069.62 242,883.87 4.87 125.63 MWD (2) 1,364.18 26.65 316.70 1,341.45 106.05 -90.881,075.45 2,572,080.13 242,874.56 1.49 139.66 MWD (2) 1,395.64 26.68 317.16 1,369.57 116.36 -100.521,103.57 2,572,090.66 242,865.15 0.66 153.76 MWD (2) 1,427.03 27.27 317.00 1,397.54 126.79 -110.211,131.54 2,572,101.30 242,855.69 1.89 167.98 MWD (2) 1,458.51 27.45 316.51 1,425.50 137.33 -120.131,159.50 2,572,112.05 242,846.01 0.92 182.43 MWD (2) 1,489.51 27.53 316.82 1,453.00 147.74 -129.941,187.00 2,572,122.68 242,836.43 0.53 196.72 MWD (2) 1,521.31 27.09 316.82 1,481.26 158.38 -139.931,215.26 2,572,133.53 242,826.68 1.38 211.29 MWD (2) 1,552.66 27.44 316.69 1,509.12 168.84 -149.771,243.12 2,572,144.21 242,817.08 1.13 225.64 MWD (2) 1,584.07 27.44 317.09 1,537.00 179.41 -159.661,271.00 2,572,154.99 242,807.42 0.59 240.09 MWD (2) 1,615.43 27.11 316.77 1,564.87 189.90 -169.471,298.87 2,572,165.71 242,797.84 1.15 254.45 MWD (2) 1,646.85 27.57 315.92 1,592.78 200.34 -179.431,326.78 2,572,176.36 242,788.12 1.92 268.85 MWD (2) 1,678.30 27.49 316.07 1,620.67 210.80 -189.531,354.67 2,572,187.04 242,778.25 0.34 283.36 MWD (2) 1,709.72 27.29 316.03 1,648.57 221.21 -199.561,382.57 2,572,197.67 242,768.45 0.64 297.78 MWD (2) 1,741.20 27.07 315.43 1,676.57 231.50 -209.601,410.57 2,572,208.18 242,758.65 1.12 312.13 MWD (2) 1,772.61 26.82 315.74 1,704.57 241.67 -219.561,438.57 2,572,218.57 242,748.91 0.91 326.33 MWD (2) 1,835.49 26.12 315.77 1,760.86 261.75 -239.121,494.86 2,572,239.07 242,729.81 1.11 354.29 MWD (2) 1,866.95 26.04 315.70 1,789.12 271.65 -248.771,523.12 2,572,249.19 242,720.38 0.27 368.08 MWD (2) 1,898.41 26.03 314.94 1,817.39 281.47 -258.481,551.39 2,572,259.22 242,710.89 1.06 381.85 MWD (2) 1,976.32 25.93 316.56 1,887.42 305.92 -282.291,621.42 2,572,284.18 242,687.62 0.92 415.90 MWD (2) 2,007.90 25.48 316.25 1,915.88 315.84 -291.741,649.88 2,572,294.31 242,678.40 1.49 429.57 MWD (2) 2,039.36 25.94 317.59 1,944.22 325.81 -301.061,678.22 2,572,304.48 242,669.30 2.36 443.20 MWD (2) 2,070.86 26.84 317.99 1,972.44 336.18 -310.461,706.44 2,572,315.06 242,660.13 2.91 457.20 MWD (2) 2,102.27 26.91 319.26 2,000.46 346.83 -319.851,734.46 2,572,325.92 242,650.98 1.84 471.39 MWD (2) 2,165.07 27.28 319.72 2,056.37 368.58 -338.421,790.37 2,572,348.07 242,632.89 0.68 499.99 MWD (2) 2,196.47 26.87 319.91 2,084.33 379.50 -347.651,818.33 2,572,359.19 242,623.91 1.33 514.29 MWD (2) 2,227.94 26.68 318.61 2,112.42 390.24 -356.901,846.42 2,572,370.14 242,614.90 1.96 528.46 MWD (2) 9/14/2011 9:54:00AM COMPASS 2003.16 Build 71 Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: NCU#10 NCU#10 Survey Calculation Method:Minimum Curvature NCU #10 @ 266.00ft (250 + 16) Design:NCU #10 Database:.Sperry EDM .16 PRD MD Reference:NCU #10 @ 266.00ft (250 + 16) North Reference: Well NCU#10 True MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 2,259.42 26.75 318.99 2,140.54 400.89 -366.221,874.54 2,572,380.99 242,605.82 0.59 542.61 MWD (2) 2,290.84 26.10 317.89 2,168.68 411.35 -375.491,902.68 2,572,391.65 242,596.78 2.59 556.59 MWD (2) 2,322.36 25.69 318.15 2,197.03 421.59 -384.701,931.03 2,572,402.09 242,587.80 1.35 570.35 MWD (2) 2,353.78 25.69 318.42 2,225.35 431.75 -393.761,959.35 2,572,412.45 242,578.97 0.37 583.97 MWD (2) 2,385.26 26.70 318.09 2,253.59 442.12 -403.021,987.59 2,572,423.02 242,569.95 3.24 597.86 MWD (2) 2,416.77 26.63 318.36 2,281.75 452.67 -412.442,015.75 2,572,433.78 242,560.76 0.44 611.99 MWD (2) 2,448.20 26.51 318.57 2,309.86 463.19 -421.762,043.86 2,572,444.50 242,551.68 0.48 626.05 MWD (2) 2,479.65 26.20 317.87 2,338.04 473.60 -431.062,072.04 2,572,455.12 242,542.61 1.40 640.01 MWD (2) 2,511.15 26.82 318.74 2,366.23 484.10 -440.412,100.23 2,572,465.82 242,533.49 2.32 654.06 MWD (2) 2,574.07 27.67 318.22 2,422.17 505.67 -459.502,156.17 2,572,487.80 242,514.88 1.40 682.86 MWD (2) 2,605.59 28.13 318.53 2,450.03 516.69 -469.302,184.03 2,572,499.04 242,505.33 1.53 697.60 MWD (2) 2,637.04 28.21 318.70 2,477.75 527.83 -479.122,211.75 2,572,510.40 242,495.76 0.36 712.45 MWD (2) 2,668.35 28.20 317.99 2,505.34 538.89 -488.952,239.34 2,572,521.67 242,486.18 1.07 727.24 MWD (2) 2,699.76 28.09 317.70 2,533.04 549.87 -498.892,267.04 2,572,532.87 242,476.48 0.56 742.05 MWD (2) 2,731.27 28.24 316.77 2,560.82 560.79 -508.992,294.82 2,572,544.01 242,466.62 1.47 756.91 MWD (2) 2,762.73 28.57 317.40 2,588.49 571.75 -519.182,322.49 2,572,555.19 242,456.68 1.42 771.86 MWD (2) 2,794.31 28.31 316.68 2,616.26 582.76 -529.432,350.26 2,572,566.42 242,446.68 1.36 786.88 MWD (2) 2,825.77 28.05 316.86 2,643.99 593.58 -539.612,377.99 2,572,577.47 242,436.74 0.87 801.72 MWD (2) 2,857.23 28.40 317.96 2,671.71 604.54 -549.672,405.71 2,572,588.64 242,426.92 1.99 816.59 MWD (2) 2,888.67 28.52 317.47 2,699.35 615.62 -559.752,433.35 2,572,599.95 242,417.09 0.84 831.56 MWD (2) 2,920.12 28.50 317.72 2,726.99 626.71 -569.882,460.99 2,572,611.25 242,407.22 0.38 846.56 MWD (2) 2,965.92 28.47 316.85 2,767.24 642.76 -584.692,501.24 2,572,627.63 242,392.76 0.91 868.38 MWD (2) 2,997.36 28.19 316.21 2,794.92 653.58 -594.962,528.92 2,572,638.68 242,382.74 1.31 883.28 MWD (2) 3,028.79 28.19 317.34 2,822.62 664.40 -605.122,556.62 2,572,649.72 242,372.81 1.70 898.11 MWD (2) 3,060.21 27.78 318.55 2,850.37 675.35 -615.002,584.37 2,572,660.88 242,363.18 2.23 912.85 MWD (2) 3,091.53 27.90 317.53 2,878.06 686.23 -624.782,612.06 2,572,671.97 242,353.64 1.57 927.47 MWD (2) 3,122.90 27.75 318.62 2,905.81 697.12 -634.562,639.81 2,572,683.08 242,344.11 1.69 942.10 MWD (2) 3,154.33 28.06 317.90 2,933.58 708.10 -644.362,667.58 2,572,694.27 242,334.56 1.46 956.81 MWD (2) 3,185.77 27.21 318.14 2,961.43 718.94 -654.112,695.43 2,572,705.32 242,325.05 2.73 971.38 MWD (2) 3,217.21 27.48 318.31 2,989.36 729.71 -663.732,723.36 2,572,716.30 242,315.67 0.89 985.82 MWD (2) 3,248.69 26.94 319.24 3,017.36 740.53 -673.222,751.36 2,572,727.34 242,306.42 2.18 1,000.21 MWD (2) 3,280.14 27.12 319.65 3,045.37 751.39 -682.512,779.37 2,572,738.40 242,297.37 0.82 1,014.50 MWD (2) 3,311.57 26.98 317.71 3,073.36 762.13 -691.942,807.36 2,572,749.34 242,288.18 2.84 1,028.79 MWD (2) 3,343.03 27.13 318.29 3,101.38 772.76 -701.522,835.38 2,572,760.18 242,278.84 0.96 1,043.10 MWD (2) 3,374.48 26.30 317.61 3,129.47 783.26 -710.992,863.47 2,572,770.89 242,269.61 2.81 1,057.23 MWD (2) 3,405.97 26.40 317.92 3,157.69 793.61 -720.382,891.69 2,572,781.44 242,260.45 0.54 1,071.20 MWD (2) 3,437.36 26.21 317.17 3,185.83 803.87 -729.772,919.83 2,572,791.91 242,251.29 1.22 1,085.10 MWD (2) 3,468.86 26.94 317.62 3,214.00 814.25 -739.312,948.00 2,572,802.49 242,241.98 2.40 1,099.18 MWD (2) 3,500.48 26.56 318.86 3,242.24 824.86 -748.792,976.24 2,572,813.31 242,232.74 2.14 1,113.40 MWD (2) 3,531.82 25.95 318.16 3,270.35 835.25 -757.973,004.35 2,572,823.90 242,223.79 2.18 1,127.27 MWD (2) 9/14/2011 9:54:00AM COMPASS 2003.16 Build 71 Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: NCU#10 NCU#10 Survey Calculation Method:Minimum Curvature NCU #10 @ 266.00ft (250 + 16) Design:NCU #10 Database:.Sperry EDM .16 PRD MD Reference:NCU #10 @ 266.00ft (250 + 16) North Reference: Well NCU#10 True MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 3,563.19 25.69 317.87 3,298.58 845.40 -767.113,032.58 2,572,834.26 242,214.88 0.92 1,140.92 MWD (2) 3,594.54 26.33 318.44 3,326.76 855.64 -776.283,060.76 2,572,844.70 242,205.93 2.19 1,154.67 MWD (2) 3,625.78 26.35 317.25 3,354.76 865.92 -785.583,088.76 2,572,855.18 242,196.86 1.69 1,168.52 MWD (2) 3,657.21 26.50 318.29 3,382.90 876.28 -794.983,116.90 2,572,865.74 242,187.69 1.55 1,182.50 MWD (2) 3,688.62 26.43 318.36 3,411.02 886.73 -804.293,145.02 2,572,876.40 242,178.62 0.24 1,196.49 MWD (2) 3,720.05 26.53 318.03 3,439.15 897.18 -813.633,173.15 2,572,887.05 242,169.51 0.57 1,210.50 MWD (2) 3,751.45 25.92 317.44 3,467.32 907.45 -822.963,201.32 2,572,897.52 242,160.41 2.11 1,224.37 MWD (2) 3,782.91 26.60 316.55 3,495.53 917.63 -832.463,229.53 2,572,907.91 242,151.15 2.50 1,238.27 MWD (2) 3,814.33 26.18 317.61 3,523.68 927.85 -841.973,257.68 2,572,918.34 242,141.86 2.01 1,252.22 MWD (2) 3,845.74 26.57 316.14 3,551.82 938.04 -851.513,285.82 2,572,928.73 242,132.55 2.42 1,266.16 MWD (2) 3,877.20 26.13 317.37 3,580.01 948.21 -861.073,314.01 2,572,939.11 242,123.21 2.23 1,280.10 MWD (2) 3,908.67 26.11 316.67 3,608.27 958.34 -870.523,342.27 2,572,949.45 242,114.00 0.98 1,293.94 MWD (2) 3,940.18 26.37 317.45 3,636.53 968.54 -880.013,370.53 2,572,959.86 242,104.73 1.37 1,307.86 MWD (2) 3,971.70 26.56 319.85 3,664.75 979.09 -889.283,398.75 2,572,970.61 242,095.69 3.45 1,321.90 MWD (2) 4,003.20 26.65 319.12 3,692.91 989.81 -898.453,426.91 2,572,981.53 242,086.77 1.08 1,336.01 MWD (2) 4,034.76 26.76 320.22 3,721.11 1,000.62 -907.633,455.11 2,572,992.54 242,077.83 1.60 1,350.19 MWD (2) 4,066.21 26.09 320.51 3,749.27 1,011.40 -916.553,483.27 2,573,003.52 242,069.15 2.17 1,364.18 MWD (2) 4,097.70 26.06 320.24 3,777.56 1,022.06 -925.383,511.56 2,573,014.37 242,060.56 0.39 1,378.02 MWD (2) 4,129.17 26.09 319.61 3,805.82 1,032.65 -934.293,539.82 2,573,025.15 242,051.89 0.89 1,391.86 MWD (2) 4,160.66 26.30 318.85 3,834.08 1,043.17 -943.363,568.08 2,573,035.88 242,043.05 1.26 1,405.76 MWD (2) 4,192.12 25.88 320.19 3,862.33 1,053.70 -952.353,596.33 2,573,046.59 242,034.30 2.30 1,419.59 MWD (2) 4,223.56 25.86 319.89 3,890.62 1,064.21 -961.163,624.62 2,573,057.30 242,025.73 0.42 1,433.31 MWD (2) 4,255.02 26.04 319.00 3,918.91 1,074.67 -970.113,652.91 2,573,067.96 242,017.01 1.36 1,447.07 MWD (2) 4,286.55 26.02 319.18 3,947.24 1,085.13 -979.173,681.24 2,573,078.61 242,008.18 0.26 1,460.91 MWD (2) 4,317.95 26.15 319.76 3,975.44 1,095.62 -988.143,709.44 2,573,089.30 241,999.45 0.91 1,474.72 MWD (2) 4,349.34 25.48 320.28 4,003.70 1,106.10 -996.923,737.70 2,573,099.97 241,990.90 2.25 1,488.39 MWD (2) 4,380.84 25.82 319.66 4,032.10 1,116.54 -1,005.693,766.10 2,573,110.60 241,982.36 1.38 1,502.02 MWD (2) 4,412.34 25.94 320.30 4,060.44 1,127.07 -1,014.533,794.44 2,573,121.32 241,973.75 0.97 1,515.77 MWD (2) 4,443.61 25.74 321.51 4,088.58 1,137.64 -1,023.133,822.58 2,573,132.08 241,965.40 1.80 1,529.40 MWD (2) 4,475.15 25.05 320.57 4,117.07 1,148.16 -1,031.633,851.07 2,573,142.79 241,957.13 2.53 1,542.92 MWD (2) 4,506.69 25.53 319.46 4,145.59 1,158.49 -1,040.293,879.59 2,573,153.30 241,948.70 2.14 1,556.39 MWD (2) 4,537.96 25.56 319.50 4,173.81 1,168.74 -1,049.053,907.81 2,573,163.74 241,940.17 0.11 1,569.87 MWD (2) 4,569.56 25.60 320.07 4,202.31 1,179.16 -1,057.863,936.31 2,573,174.35 241,931.59 0.79 1,583.52 MWD (2) 4,600.89 25.24 319.47 4,230.60 1,189.42 -1,066.543,964.60 2,573,184.81 241,923.14 1.41 1,596.97 MWD (2) 4,631.17 25.05 318.72 4,258.02 1,199.15 -1,074.973,992.02 2,573,194.72 241,914.93 1.23 1,609.83 MWD (2) 4,663.67 24.52 319.21 4,287.52 1,209.42 -1,083.914,021.52 2,573,205.19 241,906.22 1.75 1,623.45 MWD (2) 4,695.04 24.99 318.90 4,316.01 1,219.35 -1,092.524,050.01 2,573,215.30 241,897.83 1.55 1,636.59 MWD (2) 4,726.31 25.47 318.55 4,344.30 1,229.36 -1,101.314,078.30 2,573,225.51 241,889.26 1.61 1,649.92 MWD (2) 4,757.76 25.10 317.54 4,372.73 1,239.35 -1,110.294,106.73 2,573,235.70 241,880.51 1.81 1,663.34 MWD (2) 4,772.76 25.30 318.11 4,386.31 1,244.09 -1,114.584,120.31 2,573,240.52 241,876.32 2.10 1,669.73 MWD (2) 9/14/2011 9:54:00AM COMPASS 2003.16 Build 71 Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Nicolai Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: NCU#10 NCU#10 Survey Calculation Method:Minimum Curvature NCU #10 @ 266.00ft (250 + 16) Design:NCU #10 Database:.Sperry EDM .16 PRD MD Reference:NCU #10 @ 266.00ft (250 + 16) North Reference: Well NCU#10 True MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 4,830.00 25.30 318.11 4,438.06 1,262.30 -1,130.914,172.06 2,573,259.09 241,860.40 0.00 1,694.18 PROJECTED to TD 9/14/2011 9:54:00AM COMPASS 2003.16 Build 71 Page 6 0 1000 2000 DepthNicolai Creek #10 Days vs. Depth Cleanout Run, Drill 30' of new formation Cut Drill String Retrieved Fish Short Trip to SDL Crew Arrived 8 /05/19/2011 Spud Well Set 9 5/8" Casing 660', 660' TVD TD 12 1/4" Surface Hole 678' MD, 678' TVD Off Bot: 04:42 03-Feb-2011 Short Trip to Shoe Pipe stuck at 1823' MD Begin Drilling 12 1/4" Section Begin 8 1/2" Section On Bot: 22:23 07/06/2011 POOH, P/U Drilling BHA, 700 RIH, Drill ahead. 3000 4000 5000 0 102030405060Measured DRig Days TD Well 4833' MD, 4440.75' TVD On 14:45 , 6-Jul-2011 CBU, Short Trip to shoe Test BOP's, P/U Drilling BHA 800, RIH, Drill adead. Drill to 3014' md, POOH to test BOP's Surface Data Logging After Action Review Employee Name: Mark Lindloff Date: 9/8/2011 Well: Nicolai Creek #10 Hole Section: Production What went as, or better than, planned: Drilled as planned. Difficulties experienced: Phones communication was terrible, and it is going to be more critical that they work on the next well because of the distance to drive to find cell service. Need better interaction with the rig floor and pit watcher so that we know what is happening. Recommendations: Recommend renting satellite phones. Innovations and/or cost savings: None
