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202-208
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 Tit �w \V//7/ THE Silk Alaska Oil and Gas � -s= , of Conservation Commission tts& _ - 333 West Seventh Avenue teePt" -17 GOVERNOR BILL WALKER Anchorage, Alaska 99501 3572 iitynT Main: 907.279.1433 ALAS* Fax 907.276.7542 www.aogcc.alaska.gov George Pollock SCAN# JUN 1 8 .zt) Operations Consultant Amaroq Resources, LLC PO Box 90225 Anchorage, AK 99509-0225 Re: Nicolai Creek Field, Beluga Undefined Gas Pool,Nicolai Creek 9 Permit to Drill Number: 202-208 Sundry Number: 318-228 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 �L Chair J DATED this z day of June, 2018. RBQMSr JUL , 3 2018 , . III 4,-.4 itv-,ivr-k q---,..7; .0' III h:7'qi„.0 i;.:,'S V STATE OF ALASKA MAY 31 2.04i8 ALASKA OIL AND GAS CONSERVATION COMMISSION I*S CO 24 APPLICATION FOR SUNDRY APPROVALS AOGGICH 20 AAC 25280- 1.Type of Request: Abandon El Plug Perforations 0 Fracture Stimulate n Repair Well CI Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate 0 Pull Tubmg 0 Change Approved Program.0 Plug for Redrili 0 Perforate Nov Pool 0 Re-enter Susp Well 0 Alter Casing 0 CT Cleanout wlN2 E - 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Amaroq Resources,MC ' Exploratory CI Development El- 202-208 . 3.Address. PO Box 90225 Stratigraphic 0 Service D 6-API P2r2r1r5 — Anchorage,AK 99509-0225 50-283020102-00 s.si_/A 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? NA Nicolai Creek#9• Will planned perforations require a spacing exception? Yes Li No 0 9.Property Designation(Lease Number): '10.Field/Pool(s): ti-3,04,42,) ADL 391471 ' Nicolai Creek Field-Beluga Gas .4., ,. 11. PRESENT WELL CONDITION SUMMARY A- P-S-'3("1ff Total Depth MD(ft): Total Depth TVD(It): Effective Depth MD: Effective Depth 111D: MPSP(psi): Plugs(MD): Junk(MD): 1 2102' * 2102' ' 2054' - 2054' , 350 None None Casing Length Size MD TVD Blast Collapse Structural Conductor 100' 13 3/6`54*K55 100' 100' 2730 psi 1130 pai Surface 620' 9 518"36*J55 620' 620' 3920 psi 2020 psi Intermediate - Production 2098' 7"23*..155 2098' 2098' 4360 psi 3270 pi ' Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 'Tithing Size: Tubing Grade: Tubing MD(I1)- 1148'-1904' 1148'-1904' 27/8" 65#J55 1904' Packers and SSSV Type: Packers and SSSV MD(it)and TVD(1tf. Hydraulic Hydratlic©10:ii',1283',14.95'and 1806' 12.Attachments: Proposal Summary ID Wellbore schematic Ei 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory [3 Stratigraphic 0 Development Iji - Service El 14.Estimated Date for 15-Jun-18 15.Well Status after proposed work: Commencing Operations: OIL E mu 0 WDSPL 0 Suspended 0 16.Verbal Approval: Date: GAS 2. WAG 0 GSTOR 0 SPLUG ' E Commission Representative: GINJ Li Op Shutdown 0 Abandoned El [3 17. 17. I hereby certify that the foregoing is true and the procedure approved'herein will not i be deviated from without prior written approval. George Pollock NGeorge Pollock : C Authorized Name- Name Authorized Title: Operations ultant Contact Email: 00ollockaauroraioower.corn Contact Phone: 907.351.8286 Authorized Signature: .0°T- -4-- Date: 31-May-18 1_____ COMMISSION USE ONLY 'Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 51,.8 2,22 .. .....-- ( Plug Integrity D BO' Test [V Mechanical integrity Test D Location Clearance D —r--1.e3,---.-- Other: ,s Post Initial Injection MIT Req'd? Yes 0 No .1V:( Spacing Exception Required? Yes 0 No Subsequent Form Required: if b --i../b(--t APPROVED BY Approved by: Lf2C2f -1----- COMMISSIONER TTHE COMMISSION Date: I'2- I e.) 00 RBDAis 1-r\ tR 441-zisi-ir0 R 1 'kJ A ,„te57/4- 54,,,_ Form and 'Af .,11/ k Form 10-403 Revised 412017 JuN 104Nu application Is vat 1 ,,, . , .,, the date of approval. Atadimeds in Dupimate ko • 4 1F�4i? OQ RESOURCES, W NICOLAI CREEK 9 CTU CLEANOUT Scheduled Spring 2018 (4/5/18) STATUS-OF WELL: Live wellflowing200 MCF/D-at-6Qpsi-(180psi SI-TP),with sand/mud fill at+/-=1,846' CASING: 7-inch 234,J-55 LTC-ming set at 2098' (Capacity=00394 bblift), PERFORATIONS: 1148-1170',1190-1200', 1219-1223', 1248-1264' 1320-1330', 1343-1393',1407-1447' 1552-1562, 1624-1630', 1641-1662', 1748-1758', 1768-1778' 1827-1837', 1894-1904' TACKER&_1089'_,12983',1495' 1806' TUBING: 2-7/8" 6.5# J-55 EUE (Capacity-4).00579 bblift).. EOT=1904' w/ Sliding Sleeves with X-Profiles(2.313") at: 5-✓ 1047' (casing fluid--closed), �,� 1130' (closed), t'^ 1270' (closed), l0,0 1482' (open), & �'�� 2 1796' (open). .00 ' S ; 4-1/2"Strata-Pack Screens (HP)at 1827'and 1894' w/butl plug,@ 1904' SUMMARY OF PLAN: Close open sleeves at 1482'& 1796',RU CTU and clean out • fill in tubing. Run to end of tubing and cleanout to bull plug at 1904'. Test well to determine which zone(s)to open. PROCEDURE: 1) RU Pollard. Shut-in well, run 2"bailer to tag and sample fill. Fill expected at /846'. POH. If necessary,bail to expose lower sleeve. 2) Run shifting tool and close sliding sleeves at 1482' & 1796'. 3) POH and remove wellhouse and set off the side of the location. 4) RD Pollard—but have them standby (on west side—do other work). -5) Grease Wellhead Valves really well. ` 6) MI and RU Coiled Tubing Unit w/ 14/2" coil, crane,and spat N2 unit. MU AG A-4 C,�_( choke skid and flow back iron;'tro SSV on wellhead or4lowback tee on BOP skid and flowback tank. For CT cleanout, use clean(no oily)PW from NCI 1,in Tiger Tank on location(approx. 75-150 bbls). a) Fill coiled tubing reel noting volumes on Barrel counter/ displacement tanks. Compare with theoretical coiled tubing reel volume. la) :Make:upxoil_connector and pull test to 10,000 lbf.-Pressure_test connector.to 00;PSI-& 4;500PSI fox an minutes respectively. 211 ltioa s r /14e tex4 o A e c) Make up BHA: DDi�rajc,Rleon connector, duat flipper cheek, Hyd disconnect, straight bar, and 1.75"Wash Nozzle and measure/record.actual OD's,ID's,& lengths. . . • • Note::Ensure ompany-rel}_v_erifie$-and is_inagreement-with -to_he_run.-Comp rre maximum-OD of tools with minimum ID of the well completion(2.313") d) Nipple up BOP stack to wellhead — 2-9/16" 5000# RTI Flange (XO available from Vetco). No*state 24-41t lass prior to testing BOP's e) Pressure test via CST pum�p� stack, flow back manifold against crown valve to 200 PSI & 4,500 PSI fore1,6 and kf1 minutes respectively. 5f :f) if running a check valve,bleed pressure Arough flow back manifold to 1,000 psi and inflow double flapper chock valve.by Needing off coiled tubing pressure via the reel manifold. • Note: take care that excessive stripper pressure is not applied that can cause pipe collapse scenarios. --On completion-ofalftests rpressure:up-via_exiled tdbingto_equulize:to_crown-valve and open up tree valves • It) Displace the cailedtubing to°the ftnittrequired.for the job 7) RIH and clean out sand to EOT. a. Begin RIH @ 100 fpm and 10 fpm at restrictions b. While_runnhag-in-hole,circulate-fuid_at:minimum rate:.to_pmvent=nozzie_plugging. Generally 0.25bbl/min. c. -Run in hole to a depth of sl 5130 eft and z perform 131141 s i(owr more often if the company representative Live/supea r feels xit nec ry.) increase;Aurid to 0.75 bbl/min. Compare results with Modeling predictions. Slow down to 10 ft/min until fill is tagged. =d. Reduce-the_penetrationlateto 5,tpm 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 front obstructions. f. Monitor the returns at surface to establish the fill removal efficiency. 13:.., ..- 'Z g. Continue with t Teleanout R1H w/CT. :When the tubing-has-reached-the desired 5-t) ,depth(2904'),c cul:ate for 30 ntin.w/clean PW and ensure that fluid coming back is sandfreep 6I2Itofr'l , A. Pull up to sleeve at 4432' and circulate clean,runback to bottom and circ clean. l !" r° i. Start the flow of N2 and unload the fluid from the well, POH while pumping N2. I. �� _j. When at-surfnoe close in-at-the wellhead:leave about:(200_psi-:on the-tree -when finished)& bleed surface equipment down,rig off well head. • • Note: =t llbead:pressure--cl.uring-axleanout- hnuld_be:kept_abov_el5li=psi=to_reduce eau. Note:If too,much fiff is attempted to beremoved too quickly it can cause lossof circulation of the fill oat of the well bore. This couldallow the fill to fall back 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 wedintotthe_well. :Also if_lost ei culation iseneo teredeall the_engineer immediately. If bridges Aof,fill are eacosatered,qbe aware of the(possibi` '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 tailing back down the hole trapping the coiled_tubing,.in_this-case,:lifting small amounts offill and circulatingit out of the well may-be advisable prior to. proceeding too deeply into the fill. 8) RD Coiled Tubing Unit. 9) RU Pollard. RIH with 2.25" LIB and tag water level. 14)With eAG-o, eratars,:try_toLow.well,_monitorgas:and water flow_ratescatt_me-to =discuss. 11)Determine if sleeves 1482' and/or 1796'should be re-opened. If not,release Pollard and flow well to production.on. George Pollock 4/5/18 • • • 2 7/8 6.5#8rd EUE J-55 -Aura Gas, LLC { t Nicolai Creek#9 4 Current Completion 2013(as of April 13-3/8" 54.5#K-55 Conductor January driven to 100' 2018) RKB— 12.68ft ' PTD#202-208 I 8-1/2"Pilot Hole to 620',Hole opened to 12-1/4"w/hole .. opener 9-5/8"36#J-55 Surface Casing set at 620' Shoe Joint is 47#with Butt Thread Beluga Tops Tsuga.2.5 ' Tsuga 2.6 , s Tsuga 2.7 WXA Sliding Sleeve*1,047' Tsuga 2.8 `.* '110* Hydro 1 Packer{I,0 9' Perfs 1148-1170' IN SAO Sliding Sleeve @ 1,130'(closed) 1190-1200' 1219-1223' Blast joints across perforations 1248-1264' ., VXO Sliding Sleeve®1,270'(closed ,_Zt, _ Locator Seal Assembly w/ , '�'" Appowpak Seal bore packer 1a83' Original Perls - VXO Sliding Sleeve*1,48 (Open) 1320-1330' 1343-1393' Irl - 1407-1447 *. Hydro I Hydraulic Set Packer @ Perfs —- 1.495' 1552-1562' 1624-1630' 1641-1662' -++_ 1748-1758' 1768-1778' WXO Sliding Sleeve @ 1,7% (Open) Epii*41.4 Hydro 1,hydraulic set packer @ 1,806 w/XN Nipple and 2.205"NoGo @ 1,815' 1 ' O. ru€ O Perls .. ,tl 1827-1837' w +• Cleaned out to 1846'(Aug 2015) 5C 2-7/8"x 3-1/2"x 4-1/2"XO and 10' Stratapak screens @ 1827'and 1894' and bull plug in bottom @ 1904' 1894-1904' 7"23#J-55 LTC Casing to 2,098'MD 41111 k. (TVD) PBTD @ 2,054' Drill 8-1/2"Hole to 2,102' • • Client: Amaroq Resouroes ' '1 111 I honer . Coiled Tubing Services Date: Drawn: May 31st,2018 Chad Barrett Pressure Category I BOP Configuration Revision: 0 ' (0-3,500 psi) Well Category: CAT I k -. la .0.74=47=immiaa r "—11.m);,4 yr I .k.-7.41LiegA 1 FilifilMii-ZIJAA V,-- :-.-...VVt,,,,,.,o9,.,,,,,:,4k.:' lilitron i ,,. •I ,m,,.il..4,1.,,., llitigLi. 4., 111&16...Mt. ArcaofFIRIpacm, Mi .4 11110 I ...'-- -- ,-1---,-, *ait3:4,,,,ikWZ*C062 Lu 40 ,4 wt-gx;Va!tar,,f,v, Igli.Port psi., 010 ...• T 1502 x 2-1/16 10K or■ Flanged Valve 1,_•••• .4"01 --= , -2- 61 1'1 0K x 2-1/t6 0 1-1-ir 411 .7•1•Xi111:4507.1777~0• 41,474W-4 ICK Flanged Valve ,(Manu-al) .71., t.:11111K: I,...7.71 ' ... • P v.,,t5A6A-. 44,.--st-w.,.-4'.-', rr,,,:ke-'5144NWid',Vit€'-sc: 0101114 , s• , P*11114"%! 7,..7, ...-„,,, ,'Arl'.'ila4.46.*.,4 . au, ,.. , 10**444. ' ''PPAPP'447,,,AFF,X,-. ..= ,.,* . ,. ,..- ,..1 7-.se_--,..!•-4-4m sm1,44401,4F''s A=., '410. A:4101-44:4,, ,,,,4,40a4IT'2,::ipuOATA*W .,021,f,*V47'IN iirCiiil[014 110/00100 1 1 ,:A-o-eztiAv.,-*A-giaife5;.--- ,,,,'• 26..i-afdraata,,,,i,o,...a 1 I ,,,-1,-' '.:.'--,`-';',,,,,tt7V2Vt",, ,_. s ",•"..T7V?:.:'''Aq'Tt,:--,4E. , ..-,.--- -4. -&,,,,v,i,:-- - ,-,..... . .-., ..,,„. . _.,,,,,...-,...„,-.,-,.„-,,,,,--.;-,;-,:-..z:-.,i,. '#-r,P,I!,' '''''''' r '''-''''-'-''''':,''-'''V'W.',SKV-P,'S':Zalkle6ili, 'aA'A'',;,,,''' alivi , to, 'al,D. ,-4- -' , , 4 ...,ft,,,--• - , drth. VW. "... , 1 • S , :.'PROCEDURE NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2._) Notify Pad Operator of upcoming_Nitrpgen operations. 3.) 'Perform' re=ob qty Meeting. -Review-Nitrogen vendor standard operating prooedures and VpriaPiatte Safety Data Sheets(formerly MSDS). 4.) Document hazards and mitigation -meastius :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. - 'pot-Pumping=Unit=and=1ranspart.=Confirm-liquid-N2=volumes=in-transport. 6) Rig up lines from the Nitrogen Pumping unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards waning of press and nitrogen operationsat areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure 9.) Place.pressure gauges upstream and downstream of any Check.valves. 10.)Wellsite Manager shall walk down valve all via and pure valve position is ootrect. 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 detector:as-welt that:measures-.02_levels. 12.)Pressure test lines upstream of well to approved shy paessure or MPSP 4Maxigratna Potential Surface Pressure), whichever is higher. Test lines downstream.of well (from well to returns tank)t 1, psi. Perform visual inspection for any leaks. 13.)Bleed off test pressure and prepare for pumping nitrogen. 14.)Pump nitrogen at desired rate, morJtoring rate.(SCF11.M) and pressure (PSI). Alt nitro en ratans are to-be routed-to the re nts- 1r nk. 15.)When final nitrogen volume has been achieved, isolate well from:Nitrol Pumping Unit and bleed down lines between well.and Nitrogen Pumping g 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. :174.Pinallze job =log and=discuss operations :with--Wellsite -Manager. iDocument any _le&sans learned and confirm final rates/pressure/volumes of the job and remainingnitrogenin the transport. 18.)RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport* SOF T,tS %y�s,, THE STATE Alaska Oil and Gas ti oConservation Commission fLAS <:A A wet 333 West Seventh Avenue wGOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OF Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Manager Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 SCANNED JUL 2 5 20I!. Anchorage, AK 99503 Re: Nicolai Creek Field, Beluga Undefined Gas Pool,Nicolai Creek 9 Permit to Drill Number: 202-208 Sundry Number: 317-279 Dear Mr. Pollock: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. The Alaska Oil and Gas Conservation Commission(AOGCC)approves the setting of a temporary plug in this well to provide isolation from the reservoir as a short-term barrier. This work does not meet AOGCC's regulatory requirements for suspension or plugging and abandonment of this well. Prior to relinquishing the lease back to the landowner, the operator is required by law to properly plug and abandon this well. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, • Hollis S. French Chair DATED this day of July, 2017. RBDMS ,L- JUL 1 1 2017 • S RECEIVED STATE OF ALASKA JUN 1 6 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS , AOG CC 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Repair Well 0 Operations shutdown ri Suspend El Perforate 0 Other Stimulate 0 Pull Tubing 111 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing 0 Other Temporary Plug n 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number Aurora Gas,LLC Exploratory 0 Development Ill• 202-208 • 3.Address: 1400 W.Benson Blvd.Suite 410 Stratigraphic 0 Service D 6.API Number. Anchorage,AK 99503 50-283-20102-00 , 7.If perforating: 8.Weil Name and Number What Regulation or Conservation Order governs well spacing in this pool? Alk Modal Creek#9,‘ Will planned perforations require a spacing exception? Yes 0 No re Ail 9.Property Designation(Lease Number): 10.Field/Pool(s): 9/46 ADL 17.585- ....3j417./ Nicolai Creek Sauth Beluga UnALij7laA,ct 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(1t): Total Dep Typ(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): ,071'0 7•\ 0 ski 2996' 2 ' ?At, 2054' • 2054' • 350 psi None None Casing Length Size MD TVD Burst Collapse Structural Conductor 100' 13 3/8"54* K55 100' 100' 2730 psi 1130 psi Surface 620' 9 5/8"3S#J55 286' 286° 3520 psi 2020 psi Intermediate Production 2098' 7"23*J55 2098' 2098' 4360 psi 3270 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 1148'-1904' 1148'-1904' 27/8" 6.5#J-55 1904' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(14 Hydraulic Hydraulic©1089',1283',1495'&1806' 12.Attachments: Proposal Summary 0 Wellbore schematic El 13.Well Class after proposed work: Detailed Operations Program El BOP Sketch 0 Exploratory D Stratigraphic 0 Development 0 • Service 0 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: OIL D WINJ II] WDSPL 0 Suspended El 16.Verbal Approval: Date: GAS 0 - WAG 0 GSTOR 0 SPLUG 0 Commission Representative: GINJ 0 Op Shutdown D Abandoned Li 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: George Pollock Contact Name: George Pollock Authorized Title: Manager- .017,'&Eng Contact Email: a pollock aaurorapower.com ,••••°- Contact Phone: 907-277-1003 Authorized Signature: .•••-• d---- Date: 16-Jun-17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number 2-7 Plug Integrity 0 BOP Test 0 Mechanical Integrity Test D Location Clearance D Other: 1.. *1-1.• 1 e-takecAzAg4 c.)-,...,,,k, t„,.2, t...)cr, MCC-c" clJOGOAAlit.0 Me141-1. F0i2- Post Initial Injection MIT Req'd? Yes D No 0 RBDMS (A_. JUL 1 1 2017 Spacing Exception Required? Yes 0 No Z/ Subsequent Form Required: \Q-4 04 COMMISSIONER thWcC--\-- APPROVED BY Approved by: THE COMMISSION Date: 4 #1. 1 „110-644,04paamlia -ill (1.1 Submit Form and i A Form 10-403 Revised 4/2017 id for 12 months from the date of approval. Attachments in Duplicate 11 I I Aurora Gas �... LLC June 16, 2017 ECEIV. Ms. Cathy Foerster, Chair ED Alaska Oil and Gas Conservation Commission 'It* 1 6 al? 333 West 7th Avenue, Suite 100 AOGOC Anchorage, AK 99501 Re: Application for Sundry Approval—Set Temporary Plug Nicolai Creek#9 Well PTD#: 202-208 API #: 50-283-10102-00 Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to set a temporary plug to secure this onshore development well in the Nicolai Creek South Beluga 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 Beluga sands and is mechanically sound. Aurora Gas is currently in Chapter 11 bankruptcy protection while attempting to reorganize and emerge with new owners/investors. This application is being submitted as part of our Reorganization Plan filed with the bankruptcy court if liquidation actions are ordered. Aurora Gas, LLC will provide all potential new owners/investors notice of the impending action before on-site activity begins. The proposed work involves setting a plug via wireline in the profile at a depth of 1,047' 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. Sincerely, George Pollock Manager—Production Operations& Engineering 4645 Sweetwater Boulevard,Suite 200* Sugarland,TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 * Anchorage, AK 99503 * (907) 277-1003 i 111 2 7/8 6.5#8rd ELIE J-55 _Aurora Gas, LLC Nicolai Creek#9 Current Completion , n .Y « ,; it. s °. . 13-3/8" 543#K-55 Conductor January 2013(as of May ,. driven to 100' 2015) RKB—12.68ft PTD#202-208 8-1/2"Pilot Hole to 620',Hole _ # * M� opened to 12-1/4"wt Hole v.,j { , o ever , 9-5/8"36#J-55 Surface Casing set at 620' p ', >,+Mh, Shoe Joint is 47#with Butt Thread n 3 Beluga Tops Tsuga 2.5 Tsuga 2.6 Tsuga 2.7 I. WXA Sliding Sleeve*1,047' Tsuga 2.8 Hydro 1 Packer i 1,089' Perfs , 4 1148-1170' VXO Sliding Sleeve ret 1,130'(closed) _ 1190-1200' 1219-1223' ` +N , Blast joints across perforations 1248-1264' 1,°"' VXO Sliding Sleeve*1.270'(closed) X s; d� _____ ' Locator Seal Assembly w/ Appowpak Seal bore packer 1.283' Original Perfs � VXO Sliding Sleeve it 1,482'(Open) 1320-1330' 1343-1393' 1407-1447' . , Hydro I Hydraulic Set Packer.* Perfs 1A95' 1552-1562' 1624-1630' 1641-1662' 1748-1758' 1768-1778' PIWXO Sliding Sleeve 1,796'(Open) --"" Hydro I,hydraulic set packer 1,806 w/XN Nipple and 2.205"NoGo(at)1,815' (open) Perfs glii 1827-1837' 2-7/8"x 3-1/2"x 4-1/2"XO and 10' .r Stratapak screens(a?1827'and 1894' _' ..; and bull plug in bottom(a?.1904' 1894-1904' _...,� In A 7"23#J-55 LTC Casing to 2,098'MD (TVD) PBTD*2,054' Drill 8-1/2"Hole to 2,102' • • AURORA GAS, LLC Slickline Temporary Plug Set - Generalized Procedure June 2017 SUMMARY: This procedure describes the steps taken to set a temporary plug in wells operated by Aurora Gas, LLC to secure the well for a short term shut in. RIH with drift for the appropriate sized tool for the tubing, in most cases 2 7/8"tubing with 2.312" or 3 %2"tubing with 2.812"X landing nipple profile. Set PXX plug in uppermost landing profile. If a profile is not available, RIH with tubing stop pack-off plug and set above uppermost packer. After plug is set, a negative pressure test will be performed to ensure the plug has isolated the productive intervals from the surface. Upon passing the negative pressure test, the wellhead will be secured. PROCEDURE: 1) AG Operators to shut-in well and monitor pressure while rigging up. 2) RU Pollard Wire Line and lubricator on tree after removal of tree cap. Open well to pressure test lubricator—have pressure gauge on lubricator. 3) RIH with appropriate drift for X profile and sliding sleeves in upper profile. Pass through sleeve approximately 10' to insure safe operation of setting tool. POOH. 4) RIH with PXX Plug body on X-Line running tool. Set Plug body in upper most Sliding sleeve X profile above upper most production packer in well. 5) RIH with RB retrieval tool as running tool with prong. Set Prong in Plug body and POOH. 6) Record pressure and Bleed well bore to zero PSI, Monitor for 30 minutes recording pressure readings at 15 minute intervals. 7) Test successful if no pressure increase observed. If test fails, RIH and reset plug. 8) RDMO Pollard Wire Line. 9) Secure the wellhead. 10)Move to next well. 11)After 24 hours, a pressure reading will be obtained to ensure the integrity of the plug. Zyie $a,ua9e(6/11/2017) rage 1 of 1 • Maunder, Thomas E (DOA) From: Ed Jones [jejones@aurorapower.com] Sent: Tuesday, August 26, 2003 6:21 PM To: Tom Maunder Cc: 'Duane Vaagen'; 'Andy Clifford'; Randy Jones; Scott Pfoff Subject: Production of the Nicolai Creek No. 1 B, 2, and 9 s • ~~ ~'c~~ Tom, Duane Vaagen forwarded your note to me regarding this matter. Aurora is working toward expanding the Nicolai Creek Unit and has been in ongoing discussions with the DNR, Mental Health Trust, and BLM, all surface and mineral owners, for some time. I believe that Bob Crandall is in the loop or soon will be (Andy Clifford-- geology/geophysics-- and Randy Jones--land/contracts-- from our Houston office are very involved in this, incorporating the recent 3-D seismic data into the geological interpretation there}. We are aware of the prohibition to produce until all have approved and are working toward obtaining all necessary approvals. Nonetheless, we appreciate the reminder. Regarding the schedule for facilities, we plan to start the pipeline about the first of September and the compressor-dehy facility about the middle of September, expecting 4-6 weeks to finish the work. Please let me know if you need any additional information. I am in Anchorage for the next several weeks and am available at 277-1003, in person, or by email. .Regards, Ed J. Ed Jones Vice President Engineering & Operations Aurora Gas, LLC c~~o~o~c~\~~ ~~s~ a~ S~ tt ~r~d~J"~ ~ ~~~- y is ~~}~; ~ O ~a7`'l~rc ~~~ ~~ ~i' l ~Iti ~O 2/14/2008 Page 1 of 1 • Maunder, Thomas E (DOA) From: Tom Maunder [tom maunder@admin.state.ak.us] Sent: Tuesday, August 26, 2003 3:58 PM To: Ed Jones Cc: Steve Davies; John D Hartz Subject: Re: Production of the Nicolai Creek No. 1 B, 2, and 9 Attachments: tom maunder.vcf U Thanks Ed, In looking for some information for Duane I read the conservation order and noted the requirement. My intent is sending the note to Duane was to "make sure it was out there". It would be unfortunate to have everything ready to produce and not have this "i" dotted. Aurora has multiple concerns to satisfy around Nicolai Creek. Good luck. Your geological questions for the West Side should be directed to Steve Davies at 793-1224 and reservoir questions to Jack Hartz at 793-1232. Within the Commission, Steve, Jack and myself have the responsibility for Cook Inlet offshore and the West Side. Please do not hesitate to contact any of us with regard to activities over there. With regard to your facilities, it would be appreciated if you could send a copy of the "meter specs" similar to what you sent for Lone Creek #1. Tom Maunder, PE AOGCC Ed Jones wrote: Tom, Duane Vaagen forwarded your note to me regarding this matter. Aurora is working toward expanding the Nicolai Creek Unit and has been in ongoing discussions with the DNR, Mental Health Trust, and BLM, all surface and mineral owners, for some time. I believe that Bob Crandall is in the loop or soon will be (Andy Clifford--geology/geophysics--and Randy Jones--land/contracts-- from our Houston office are very involved in this, incorporating the recent 3-D seismic data into the geological interpretation there). We are aware of the prohibition to produce until all have approved and are working toward obtaining all necessary approvals. Nonetheless, we appreciate the reminder. Regarding the schedule for facilities, we plan to start the pipeline about the first of September and the compressor-dehy facility about the middle of September, expecting 4-6 weeks to finish the work. Please let me know if you need any additional information. I am in Anchorage for the next several weeks and am available at 277-1003, in person, or by email. Regards, Ed J.Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 2/14/2008 • Maunder, Thomas E (DOA) From: Tom Maunder [tom maunder@admin.state.ak.us] Sent: Friday, June 06, 2003 12:47 PM To: Bill Penrose Cc: Steve Davies Subject: Re: FW: Aurora Attachments: tom maunder.vcf t ~.-_ , tom_maunder.vcf (681 B) Bill, Thanks for the information. This really helps. One thing I noticed is the reference to Nicolai 1-2-9. I know this refers to the wells at the end of the airstrip and the point I have to make may not be for you specifically. In the regulatory scheme of things, the wells at the end of the airstrip are 1B, 2 and 9. For the AOGCC purposes, NCU 1 and lA are/have been plugged and abandoned. I am aware of a few other items that Steve Davies is concerned with mostly with regard to spacing exceptions. He has been in contact with the land person at Aurora (not sure who) and has sent an email noting what he requires. He has yet to have his needs addressed. According to our status tracking board, the wells are Long Lake #1 and W Moquawkie #l. Please call if you have any questions. Tom Maunder, PE AOGCC Bill Penrose wrote: > -----Original Message----- > From: Ray Eastlack > Sent: Friday, June 06, 2003 11:26 AM > To: 'Glenn Gray@dnr.state.ak.us' > Cc: Bill Penrose; 'jejonesCaurorapower.com'; 'gspfoffC~aurorapower.com' > Subject: RE: Aurora > Glenn, > You're about to get some paperwork. Since the pre-app meeting, the > NCU > 1-2-9 facilities and pipeline have been moved way up in priority by > Aurora gas so we've been concentrating on that. We've surveyed in the > pipeline route and had a biologist delineate wetlands along it. The > wetlands report will be ready for submittal to the Corps and to your > office (along with the CPQ for this phase of the project) next week. > We have also been in contact with ADEC and EPA concerning storm water > runoff and hydro test water discharge and will be submitting the > appropriate paperwork to them with copies to your office. > We have requested ADEC to issue a C-Plan exemption and they in turn > have requested the AOGCC to provide verification of our justification for it. > Steve Davies at AOGCC indicated agreement verbally and will notify > ADEC in writing soon. We will ensure your office receives a copy of > the C-Plan exemption when/if it arrives. > Once all this is in motion next week for NCU 1-2-9, we will be sending > the surveyors and biologist back out to tackle the Long Lake 1, Lone > Creek 3, NCU #7, and possibly Kaloa 2 routes and locations. This is > scheduled for late next week. Once the wetlands report for these > locations is prepared, we will submit it to the Corps for their > determination of Corps permitting needs. Any projects that they 1 > determine will need a permit ~m them will receive a permit ~l.ication from us and you will receive a CPQ. > We don't expect to need any permits other than AOGCC well work permits > for the Moquawkie wells as they're on a well-established road and pad system. > Regards, > Ray Eastlack 2 • • ..„, ~~~-"_ ,.r-= MICROFILMED 03/01/2008 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE. F:\LaserFiche\CvrPgs_InsertsiMicrofilm Maxi~er.doc · . ~AuTOra Gas, '-~C www.aurorapower.com RECEIVED OCT 1 9 2006 October 19, 2006 Alaska Oil & Gas Cons. Commissía!\ Anchorage Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage,AJ( 99501 Attn: Mr. John Norman RE: Nicolai Creek Unit No.9 Dear Mr. Norman: This letter in duplicate originals transmits the data to you identified below, pursuant to Aurora Gas, LLC's obligation to you. This data is relative to operations at the Nicolai Creek Field, Cook Inlet, Alaska. Enclosed herewith: SCHLUMBERGER PERFORATING DEPTH CORRELATION Nicolai Creek #9 1- GRlCCL Correlation Pass (TCP guns) Please signify that you have received and accepted this data by signing in the space below and returning this letter to me at the Houston address below or by fax to me at 713-977-1347. If you have questions, please contact Andy Clifford or me at the Houston number below. Sincerely, -Z- ¿Jeo/S Bruce D. Webb Manager, Land and Regulatory Affairs ('r b.\\.'iò.l'~l~ ðwn:'t~~t;..· ?, f BY: TITLE: ÐO(J-riò-x- 10333 Richmond Avenue, Suite 710· Hóust'ifn, Texas 77042· (713) 977-5799· Fax (713) 977-1347 1400 West Benson Blvd., Suite 410· Anchorage, Alaska 99503· (907) 277-1003· Fax (907) 277-1006 . . \ Aurora Gas, LLC www.aurorapower.com Bruce D. Webb Manager - Land and Regulatory Affairs 1400 W. Benson Blvd. Suite 410 Anchorage, AK 99503 (907) 277-1003 Fax (907)277-1006 Cell (907) 229-8398 bwebb@aurorapower.com . . .urora Gas, LLC October 9, 2006 RE: Report of Sundry Well Operations Aurora Gas, LLC: Nicolai Creek #9 (PTD 202-208) R~C~/I/, OCl . t:D 41ask, 1 0 ') II 011 ~ G <006' as C. A Q/1s C I1cl. . ,'1h,. 'IOtah ~'f7m¡,,· . ue <Ii$lfJn Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Dear Commissioner Norman, Aurora Gas, LLC hereby submits its Report of Sundry Well Operations for the work performed in working over its Nicolai Creek #9 gas production well in the Nicolai Creek Gas Field on the west side of Cook Inlet. Please find enclosed the following information for your files: 1) Form 10-404 Report of Sundry Well Operations 2) Workover Operations Summary 3) Wellbore Diagram as completed 4) Well Flow Test Summary ç' C' ( If you have any questions or require additional information, please contact me at (713) 977-5799 or Ron Stadem at Fairweather at 343-0389. Sincerely, AU.RORA ~/. LC ~{í - ,for ....J,=-:r J. Edward Jones Vice President, Engineering and Operations enclosures cc: Mr. Ron Stadem - Fairweather . STATE OF ALASKA . ALASKA~AND GAS CONSERVATION COMMIS REPORT OF SUNDRY WELL OPERATIONS RECEIVED ocr 1 0 2006 ..... 1 . Operations Abandon U Repair Well U Plug Perforations U Stimulate U ~'''~, L::.J 1 & Gas COQi. Com ~i Performed: Alter Casing 0 Pull Tubing Iï?' Perforate New Pool 0 WaiverD Time Extension 0 Anthorage Change Approved Program 0 Opera!. Shutdown 0 Perforate 0 Re-enter Suspended Well 0 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Aurora Gas, LLC Development 0 Exploratory 0 202-208 . 3. Address: 1400 W. Benson Blvd, Ste 410 Stratigraphic 0 Service 0 6. API Number: Anchorage, Alaska 99503 50-283-20102-00 7. KB Elevation (ft): 9. Well Name and Number: 48' AMSL . NCU #9 8. Property Designation: 10. Field/Poo/(s): AA-8426 . Nicolai Creek Gas Field - 11. Present Well Condition Summary: Total Depth measured 2,102 , feet Plugs (measured) None true vertical 2,102 feet Junk (measured) None Effective Depth measured 2,054 . feet true vertical 2,054 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 82' 13-3/8" 100' 100' N/A N/A Surface 602' 9-5/8" 620' 620' 3,520 psi 2,020 psi Intermediate 2,080' 7" 2,098 2,098' 4,360 psi 3,270 psi Production Liner Perforation depth: Measured depth: 1,148' - 1,904' True Vertical depth: 1,148' - 1,904' Tubing: (size, grade, and measured depth) 2-7/8" J-55 1 ,444' Packers and SSSV (type and measured depth) Hydro 1 @ 1,090' RSBP @ 1,284' Hydro 1 @ 1,496' Hydro 1 @ 1,807' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: RBDMS 8Ft 0 (1 :i 1 2006 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bb/ Casing Pressure Tubing Pressure Prior to well operation: 400 . 130 psi Subsequent to operation: 1967 680 psi 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run None Exploratory 0 Development 0 . Service 0 Daily Report of Well Operations Attached 16. Well Status after work: Oil 0 Gas 0 " WAG 0 GINJ 0 W/NJ 0 WDSPL 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. ¡SUndry Number or N/A if C.O. Exempt: 306-297 Contact Ron Stadem 907-343-0389 P'""d N,m, J. Ed.."" J,"~ Title Vice President, Engineering & Operations /D~O/ob ~ / ~ Phone 719-977-5799 Date Signature/ /;j~. ,'- ~"":/SJ- . ~.. ."P.~~.~ Ission Form 10-404 Revised 04/2006 ~15\. ;í~J~ . . OPERATIONS SUMMARY Aurora Gas, LLC Nicolai Creek Unit #9 September 11, 2006 Move A WS # 1 Rig onto location. Begin rigging up. September 12,2006 Continue rigging up. September 13, 2006 Continue rigging up. Fill pits wi 9.3ppg, 6% KCL brine mix. Rig accepted @ 1500 hrs. RU Pollard wire line, open SSV @ 1,210' and reverse circulate. Set BPV, ND tree, Set test dart, NU BOPE. September 14,2006 Test BOPE. Replace faulty HCR. Test new HCR valve. RD test equipment. Pull BPV. RU to reverse circulate. September 15,2006 Reverse circulate. POH wi existing tubing. RIH wi packer retrieving tool to 1,242' and pull packer free wi 32,000 Ibs. Circ 1-1/2 bottoms up Monitor well for 15 min., then POH wi packer. Changed pipe rams to 3.5" and tested. RIH wi scraper and bit to 2,012'. Circ and filter brine, then POH. ND flow nipple and NU shooting flange. September 16,2006 RU Schlumberger lubricator and test to 1000 psi. RIH w GR-CCL and tie into open hole logs. MU shooting flange and lubricator and test to 1000 psi. RIH with Schulmberger 4.5" HSD guns and perf the intervals as follows: Run #1 1,894' - 1,904' ~ Run #2 1,827' - 1,837' Run #3 1,768' - 1,778' Run #4 1,748' - 1,758' Run #5 1,689' - 1,694' Run #6 Miss- fire Run #7 1,652' - 1,662' Run #8 1,641' - 1,646' Run #9 1,624' - 1,629' Run #10 1,552' - 1,562' Mostly static during perf op wI slight losses immediately after perf. RD Schlumberger, ND shooting flange and NU flow nipple. Install wear bushing. RIH wi scraper and bit to 2,000'. Circ well clean and filter brine. . . September 17, 2006 POH and LD scraper and bit. TIH and set packer @ 1,800'. RU to swab perfs below packer. RU test separator and flare stack. Swab well wI one pull @ 1,000'. Unload well to pits (13.5 bbl) and flow test well. 2.6 MMCF @ 480 psi wI 36/64 choke - 18 bbls total fluid recovered. Shut in well for build~up - 610 psi in 5 min. - 615 psi in 30 min. U-tube well dead - circ out reverse and long way. Reset packer @ 1,637' and swab perfs below packer recovering 9.1 bbl. Flow test well at 350 psi thru 36/64 choke - showing communication wI perfs above packer. SI well and monitor pressure. Final SIP 610 psi and 31 bbl total fluid recovery. Backside pressure @ 240 psi. Lubricate and bleed to zero. SI well and monitor. September 18, 2006 Lubricate and bleed gas bubble off annulus. Monitor annulus and tubing - tubing stable @ 640 psi - annulus built to 150 psi. Lubicate and bleed. Confirm annulus is dead and open rams. U-tube well dead and reverse eirc. Unseat packer and set @ 1,515'. Swab well from 1,000' recovering 7 bbl and flowing 3 bbl. - well unloading water - backside taking 22 bbl/hr. SI well, u-tube dead and reverse circ. Unseat packer and reset @ 1,292' - wouldn't test. Change out packer and reset @ 1,292', testing backside to 400 psi. Unseat packer and reset at 1,637'. Swab well fl 1000' recovering 4 bbl. Repeat swab recovering 2 bbl . September 19,2006 Flow well from perfs below packer trying various choke sizes. Drop soap sticks and allow pressure to build for 30 min and then flow test - flowing @ 2.11 mmcf @ 225 tubing pressure. SI well and monitor for 1 hour - pres stabilized at 540 psi. U-tube and reverse circ well dead. Unseat packer and reset @ 1,515'. Swabbed two pulls at 1,000' and 1,100' recovering 11 bbl and unloading 7 bbl to pits. Flow test to separator @ 2.21 mmcf @ 285 psi tubing pressure. September 20, 2006 SI well and monitor build-up - built from 280 psi to 580 psi. Kill well. Release packer and reset at 1,793'. Swab well four times from various depths. Well came on. Flowed well thru 20/64 choke at 160 psi. SI well for one hour - pres built from 280 psi to 610 psi. Changed flow meter to 1.5 choke - getting 672 mcf. SI well for 1 hour - built to 600 psi. Reverse kill thru unloader and circ long way. POH wI packer and test BOPE. September 21, 2006 Continue BOPE test. RIH wI notch collar to 2,008' checking for sand. POH, PU production BHA, SLM and drift and RIH. Drop ball and set packer @ 1,284'. POH, PU seal bore plugand set plug in PBR - test to 1000 psi. Lay in two sacks sand on top of plug. Displace well wI 10.2 ppg NaCL, KCL and NaBr brine. POH and RU TCP perf guns. September 22, 2006 Continue RU of guns, packer, and hydraulic jars. RIH wI perf assembly. RU wire line and set on depth. RD wire line and set packer @ 1,099', pressuring up on backside to 2,500 psi. Open PTV. Have JSA wI on-site personnel before dropping bar fire guns and perforating over the following intervals: 1,148' -1,170', 1,190' -1,200', 1,218' -1,224', /" . . 1,258' - 1,264', 1,248' - 1,254'. Flow test intervals thru 20/64 choke. SITP 560 psi. Change orifice in meter to 2" and flow again thru 40/64 choke - holds stable at FTP 440 psi and 1622.8 mcf. SI and allow to build up to 550 psi. Reverse circ and kill well. POH. September 23. 2006 LD packer, jars and remainder of perf guns. MU bit and scraper and RIH to 1267'. POH. RIH wi 6" magnet. POH (skirt full of gun debris). Repeat. PU seal bore retrieval tool tagging sand @ 1,278'. Release plug at 1,284' and POR. Change rams to 2-7/8" and test to 1000 psi. RIH wi completion assembly space out hanger and seals, land and energizing hanger, set packers against blanking plug to 2000 psi. September 24.2006 Set BPV, ND BOPE, NU tree, pull BPV and test upper annulus to 600 psi. RU slick line and swab equipment and have PJSM. RIH, open sleeve @ 1027' and pump packer fluid. Close sleeve verifying closure wi 300 psi. Open sleeve at 1270'. Flow well thru 27/64. Shut in - pressure built from 420 psi - 535 psi. RIH wi slick line to close sleeve @ 1270' and open sleeve at 1482'. POH. Try swabbing - having problems. RIH wi gauge ring - no problems. RIH wi brush to find restrictions between 1177' and 1187'. September 25. 2006 RIH wi gauge ring. Swab well from 1484' recovering 3 bbl. Flow well @ 92 mcf fl 1284' - 1497' interval. SI well - 82 psi build-up. RIH wi slick line to close SSV @ 1483' and open SSv @ 1796'. Lubricate in 5 bbl into tubing. Swab sleeve at 1796'. Tag fluid at 200' recovering 7.5 bbl. Well flowing thru 24/64 choke. Unload 7 bbl of 9.4 brine thru 30/64 choke at 150 mcf. Shut in for build up to final SITP of 640 psi. RIH and close SSV @ 1796'. Attempt prong retrieval @ 1814'. RIH wi bailer. Retrieve prong @ 2 runs after plug. September 26. 2006 Made four runs attempting to retrieve plug wi no luck - sand in plug latch. MU bailer and RIH. Latch in and receive plug. Flow lower zone (1827' - 1904' thru 30/64 choke wi 2" disc. Showing 1500 mcfd. SI and allow to build to 630 psi. September 27.2006 Finish wi build up - 63 psi. RIH wi Pollard to open sleeve at 1796' and flow test zones from 1496' - 1806' thru 37/64 choke wi 2" orifice, stabilizing at 188 mcfd. SI well and release rig. RD rig. . . NCU9 ACTUAL WELLBORE CONFIGURATION After Recompletion of Sept. 2006 Upper Completion New Perfs @ 1148-1170' 1190-1200' 1218-1224' 1248-1254' 1258-1264' Middle Completion Existing Perfs 1320-1330' 1343-1393' 1407-1447' Lower Completion New Perfs @ 1552-1562' 1624-1629' 1641-1646' 1652-1662' 1689-1694' 1748-1758' 1768-1778' 1827-1837' 1894-1904' J EJ 1 0/2/06 2-7/8" 6.5# EUE Tubing Sliding Sleeve (Pkr Fluid) @ 1047' Hydro I Hydraullic Set Packer @ 1090" Production Sliding Sleeve at 1130' Blast Joints Across Perfs, at 1149-1170', 1188-1228', & 1246-1267' Production Sliding Sleeve at 1271' Seal Bore Packer @ 1284' (Retrievable) Production Sliding Sleeve 1483' w/2.31" X Hydro I Packer @ 1496' Prod Sliding Sleeve @1796' Hydro I Packer at 1807' XN Nipple @ 1815' wI 2.312" bore Screens at 1828-38' & 1894-1904' PBTD - 2102' ./ AURORA GAS, LLC NICOLAI CREEK UNIT #9 TEST RESULTS SUMMARY 2006 WORKOVER DATE DATUM TEST MCFPD FTP I SITP dl WTR COMMENTS STATUS of TOP BASE NET (mid perf) NO. (Calc BHP) 10/1/2006 TEST MDITVD MDITVD PERFS TVDss psig psig BPH TSUGA 2-6 NEW PERFS ADDED IN 9/2006 9/22/2006 1148 1170 22 5 788 480 0.00 9/22/2006 1190 1200 10 6 1622 455 550 9/25/2006 1218 1224 6 -1158 7 530_ 460 535 thru sleeve at 1271' CLOSED 1248 1254 6 (565 psia) (sleeves at 1130' and 1258 1264 6 1271' closed) 44 TSUGA 2-7 9/25/2006 ORIGINAL PERFS 8 90 50 82 0.00 thru sleeve at 1482' 1320 1330 10 1343 1393 50 -612 CLOSED 1407 1447 40 (sleeve at 1483' closed 100 NEW PERFS ADDED IN 9/2006 9/18/2006 1552 1562 10 3 2210 285 590 0.60 1552-1904' 1624 1629 5 1641 1646 5 9/18/2005 1652 1662 10 -1617 2 2111 255 540 1641-1904' OPEN 1689 1694 5 (sleeve at 1796' open) 9/25/2006 1748 1758 10 9 1522 320 640 0.33 1552-1778' 1768 1778 10 (681 psia) thru sleeve at 1796' 9/27/2006 55 11 1967 340 1552-1904' commingled TSUGA 2-8 9/17/2006 NEW PERFS ADDED IN 9/2006 1 2574 420 615 1827-1904' 9/20/2006 1827 1837 10 4 672 320 610 1827-1904' OPEN 9/26/2006 1894 1904 10 -1817.5 10 1579 285 630 1827 -1904' (no plug in packer) 20 (672 psia) . . Ed Jones 10/5/2006 AURORA GAS, LLC WELL TEST REPORT Flow test Peñs f/1894' to 1904' & 1827' to 1837' Peñormed by: Jack 1 Johann Well unloaded 18 bbl prior to being placed on Chart Recorder-Well made no additional NCU #9 brine 17 -Sep-06 Test #1 ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Delta Total TIME PERFS SPYDR, TEMP - 164' PRESS STATIC DIFF TEMP FACTOR MCFID VOL VOL PSIA deg F psi blue red green H2O H2O Shut In Flow Test 1:15 440 36 340.00 4.60 4.60 5.60 130 2750.80 1:30 430 36 340.00 4.60 4.60 5.65 130 2750.80 1:45 425 36 320.00 4.55 4.50 5.70 130 2661.75 2:00 420 36 320.00 4.50 4.40 5.70 130 2574.00 1:15 420 36 320.00 4.50 4.40 5.70 130 2574.00 . . . . Flow Test #1 Buildup Min Pressure 14:13 420 psi 1 540 psi 2 570 psi 3 590 psi 4 590 psi 5 600 psi 6 610 psi 7 610 psi 8 610 psi 9 610 psi 10 610 psi 11 610 psi 12 610 psi 13 610 psi 14 610 psi 15 610 psi 16 610 psi 17 610 psi 18 610 psi 19 610 psi 20 610 psi 21 610 psi 22 610 psi 23 610 ~si 24 610 psi 25 610 psi 26 610 psi 27 610 psi 28 610 psi 29 610 psi 30 615 psi 40 615 psi 50 615 psi 60 615 psi 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 I 220 I . . AURORA GAS, LLC WELL TEST REPORT Flow Test Peñs f/1,641' to 1904' Peñormed by: Jack McDade Flowed well fl 00:00 to 10:00 through various choke settings in attempt to increase flow NCU #9 1 Recovered 35 bbl 9.3 brine prior to swapping to seperator 1 Well made no fluid during 18-Sep-06 TEST #2 test ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Delta Total TIME PERFS SPYDR, TEMP - 164' PRESS STATIC DIFF TEMP FACTOR MCFID VOL VOL PSIA deg F psi blue red green H2O H2O Shut In Flow Test 10:00 280 40 180 3.00 6.20 5.50 130 2418.00 10:15 275 40 180 3.00 6.20 5.50 2418.00 10:30 260 40 180 2.80 6.00 5.60 2184.00 10:45 260 40 180 2.80 5.90 5.60 2147.60 11:00 260 40 180 2.80 5.85 5.60 2129.40 11:15 260 40 180 2.80 5.85 5.60 2129.40 11:30 260 40 180 2.80 5.85 5.60 2129.40 11:45 255 40 180 2.80 5.85 5.60 2129.40 12:00 255 40 180 2.80 5.80 5.60 2111.20 1 hr buildup 540 . . . . . Flow Test #2 Buildup Min Pressure 12:19 255 psi 1 375 psi 2 440 psi 3 480 psi 4 500 psi 5 510 psi 6 515 psi 7 520 psi 8 520 psi 9 520 psi 10 525 psi 11 530 psi 12 530 psi 13 530 psi 14 530 psi 15 530 psi 16 530 psi 17 530 psi 18 530 psi 19 530 psi 20 530 psi 21 530 psi 22 530 psi 23 530 psi 24 530 psi 25 530 psi 26 535 psi 27 535 psi 28 535 psi 29 535 psi 30 535 psi 40 540 psi 50 540 psi 60 540 psi 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 I 220 I . . AURORA GAS, LLC WELL TEST REPORT Flow Test Perfs f/1,552' to 1,904' Performed by: Jack NCU #9 18-Sep-06 TEST #3 ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Tank Total TIME PERFS SPYDR, TEMP - 164' PRESS STATIC DIFF TEMP FACTOR MCF/D Air VOL PSIA deg F psi blue red green Gap H2O Shut In Flow Test 19:30 220 40 180 3.00 3.40 5.90 130 1326.00 79" 28.28 19:45 225 40 180 3.10 3.70 5.70 130 1491.10 - - 20:00 230 40 180 3.10 3.90 5.80 130 1571.70 - - 20:15 235 40 180 3.20 4.00 5.80 130 1664.00 - - 20:30 240 40 180 3.20 4.20 5.80 130 1747.20 78" 29.4 20:45 245 40 185 3.20 4.20 5.70 130 1747.20 - - 21:00 250 40 190 3.30 4.30 5.70 130 1844.70 - - 21:15 255 40 190 3.40 4.40 5.70 130 1944.80 - - 21:30 260 40 190 3.40 4.50 5.70 130 1989.00 76" 31.64 21:45 260 40 190 3.40 4.60 5.70 130 2033.20 - - 22:00 265 40 190 3.40 4.60 5.70 130 2033.20 - - 22:15 270 40 195 3.40 4.70 5.70 130 2077.40 - - 22:30 270 40 195 3.40 4.80 5.70 130 2121.60 76" 31.64 22:45 275 40 195 3.40 4.80 5.70 130 2121.60 - - 23:00 275 40 195 3.40 4.80 5.70 130 2121.60 - - 23:15 275 40 195 3.40 4.90 5.70 130 2165.80 - - 23:30 280 40 195 3.40 5.00 5.70 130 2210.00 75.5" 32.24 23:45 280 40 195 3.40 5 5.70 130 2210.00 - - 0:00 285 40 200 3.40 5 5.70 130 2210.00 - - 2 hr buildup 590 . . . . Flow Test #3-Buildup Min Pressure 0:00 280 psi 1 360 psi 2 450 psi 3 490 psi 4 510 Dsi 5 530 psi 6 535 Dsi 7 540 psi 8 545 psi 9 545 psi 10 545 psi 11 545 psi 12 545 Dsi 13 550 psi 14 550 psi 15 550 psi 16 550 psi 17 550 psi 18 550 psi 19 550 psi 20 550 psi 21 550 Dsi 22 550 psi 23 550 psi 24 550 psi 25 550 psi 26 550 psi 27 555 psi 28 555 Dsi 29 555 psi 30 555 Dsi 40 560 psi 50 560 psi 60 570 psi 70 570 psi 80 570 psi 90 570 psi 100 570 psi 110 570 psi 120 575 psi 130 575 psi 140 575 Dsi 150 575 psi 160 575 psi 170 575 psi 180 580 Dsi 240 590 Dsi 300 590 psi AURORA GAS, LLC WELL TEST REPORT Flow test Peñs f/1894' to 1904' & 1827' to 1837' Peñormed by: Jack 1 Jack NCU #9 20-Sep-06 TEST #4 ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Delta Total TIME PERFS SPYDR, TEMP 22 164" PRESS STATIC DIFF TEMP FACTOR MCF/D VOL VOL PSIA deg F psi blue red green H2O H2O Shut In 610 psi 15:35 Flow Test 610 22 240 16:00 320 24 180.00 3.20 3.20 6.10 70 7.16 16:15 330 24 180.00 3.20 3.00 6.10 70 672.00 16:30 330 24 140.00 3.20 3.00 6.10 70 672.00 16:45 320 24 180.00 3.20 3.00 6.10 70 672.00 17:00 320 24 180.00 3.20 3.00 6.10 70 672.00 17:15 320 24 180 3.20 3.00 6.20 70 672.00 1 hr buildup 610 . . FI T t #4 B 'Id ow es - UI UJ 1 Min Pressure 1 200 psi 2 300 psi 3 350 psi 4 400 psi 5 450 psi 6 500 psi 7 525 psi 8 530 psi 9 540 psi 10 545 psi 11 550 psi 12 555 psi 13 560 psi 14 565 psi 15 570 psi 16 575 psi 17 575 psi 18 575 psi 19 575 psi 20 580 psi 21 585 psi 22 590 psi 23 595 psi 24 595 psi 25 600 psi 26 600 psi 27 600 psi 28 605 psi 29 605 psi 30 606 psi 40 607 psi 50 609 psi 60 610 psi 70 80 90 100 110 120 130 140 150 160 170 180 190 200 220 #2 . . 380 430 470 490 500 510 525 530 540 545 550 550 560 560 565 570 575 575 580 580 585 590 590 595 595 595 595 595 600 600 600 600 600 AURORA GAS, LLC WELL TEST REPORT Flow test Perfs f/1148' to 1264' Performed by: Jack IZane NCU #9 22-Sep-06 TEST #5 ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Delta Total TIME PERFS SPYDR, TEMP 27 164" PRESS STATIC DIFF TEMP FACTOR MCF/D VOL VOL PSIA deg F psi blue red green H2O H2O 9:00 Flow Test 490 200 2.60 2.50 5.30 70 611.80 1 bbl 9:15 490 140.00 2.30 3.80 5.20 70 611.80 0 9:30 490 140.00 2.30 3.80 5.20 70 611.80 0 9:45 495 140.00 2.30 3.80 5.20 70 611.80 0 10:00 495 140.00 2.30 3.80 5.20 70 611.80 0 10:15 495 140.00 2.30 3.80 5.20 70 595.70 0 10:30 495 140 2.30 3.70 5.20 70 787.50 0 10:45 490 140 2.50 4.50 5.20 70 770.00 0 11:00 480 140 2.50 4.40 5.20 70 770.00 0 11:15 480 140 2.50 4.40 5.20 70 770.00 0 11:30 480 140 2.50 4.40 5.20 70 770.00 0 11:45 ice in choke 485 140 2.50 4.30 5.20 70 752.50 0 12:00 485 140 2.70 4.80 5.20 70 907.20 0 12:15 move choke fl ice 480 140 2.70 4.80 5.20 70 907.20 0 12:30 ice inchoke,shut in 480 140 2.70 4.80 5.20 70 787.50 0 . . . . Flow Test #5-Buildup 9/22/2006 1148/1254 Min Pressure 0:00 480 psi 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 240 300 AURORA GAS, LLC WELL TEST REPORT Flow test Perfs f/1148' to 1264' Performed by: Jack IZane/Johann NCU #9 22-Sep-06 TEST #6 ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Delta Total TIME PERFS SPYDR, TEMP 27 164" PRESS STATIC DIFF TEMP FACTOR MCF/D VOL VOL PSIA deg F psi blue red green H2O H2O 14:30 460 32 160 2.70 3.60 5.40 130 1263.00 14:45 460 32 160 2.60 3.60 5.30 , 1216.00 15:00 465 32 140 2.60 3.60 5.30 , 1216.80 15:15 445 42 180.00 3.20 4.00 5.40 , 1664.00 15:30 450 42 180.00 3.20 3.80 5.40 , 1580.00 15:45 455 42 180.00 3.20 3.80 5.40 , 1580.00 16:00 455 42 180.00 3.20 3.90 5.35 , 1622.40 16:15 455 42 180.00 3.20 3.90 5.40 II 1622.40 16:30 455 42 180 3.20 3.90 5.50 , 1622.40 1-1/2 hr buildup 550 . . . . Flow Test #5-Buildup 9/22/2006 1148/1254 Min Pressure 0:00 480 psi 1 520 psi 2 530 psi 3 535 psi 4 525 psi 5 530 psi 6 540 psi 7 545 psi 8 545 psi 9 545 psi 10 545 psi 11 545 psi 12 545 psi 13 545 psi 14 545 psi 15 545 psi 16 545 psi 17 545 psi 18 545 psi 19 545 psi 20 545 psi 21 545 psi 22 545 psi 23 545 psi 24 545 psi 25 , 26 . 27 , 28 29 , 30 , 40 550 psi 50 550 psi 60 550 psi 70 550 psi 80 550 psi 90 550 psi 100 110 120 130 140 150 160 170 180 240 300 AURORA GAS, LLC WELL TEST REPORT Flow test Perfs f/1148-1264' test thru tree SSV open @1271' Performed by: Jack IZanel NCU #9 25-Sep-06 #7 test ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Delta Total TIME PERFS SPYDR, TEMP 23/64" PRESS STATIC DIFF TEMP FACTOR MCF/D VOL VOL PSIA deg F psi blue red green H2O H2O 18:00 2"disc 400 100 1.50 4.00 130 780.00 18:15 420 100 1.70 3.50 130 774.00 18:30 410 100 2.00 4.10 130 1 066.00 18:45 460 1 00.00 1.70 2.40 130 530.00 19:00 19:15 19:30 19:45 20:00 buildup 535 in 2 min--stable . . Flow Test 7-Buildup 9-23 Min Pressure 0:00 480 psi 1 530 psi 2 535 psi 3 535 psi 4 535 psi 5 535 psi 6 535 psi 7 535 psi 8 535 psi 9 535 psi 10 535 psi 11 535 psi 12 535 psi 13 535 psi 14 535 psi 15 535 psi 16 535 psi 17 535 psi 18 535 psi 19 535 psi 20 535 psi 21 22 23 24 25 26 27 28 29 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 240 300 . . NCU#9 1148-1264 perfs AURORA GAS, LLC WELL TEST REPORT Perfs 1320-1447' (old perfs) SSV@ 1482' Performed by: Jack IZanel NCU #9 25-Sep-06 TEST #8 ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Delta Total TIME PERFS SPYDR, TEMP 23/64" PRESS STATIC DIFF TEMP FACTOR MCF/D VOL VOL PSIA deg F psi blue red green H2O H2O tesr#8 1" disc 70 60 1.00 4.00 30 120.00 0 10:45 65 60 1.00 3.80 30 114.00 0 11:00 65 60 1.00 3.50 30 105.00 0 11:15 60 60.00 1.00 3.40 30 102.00 0 11:30 50 60.00 1.00 3.20 30 96.00 0 12:00 50 50.00 1.00 3.00 30 90.00 0 12:15 50 50.00 1.00 3.00 30 90.00 0 . . . AURORA GAS, LLC WELL TEST REPORT 1552-1778' zone Peñormed by: Jack IZanel NCU #9 25-Sep-06 TEST #9 ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Delta Total TIME PERFS SPYDR, TEMP 23/64" PRESS STATIC DIFF TEMP FACTOR MCF/D VOL VOL PSIA deg F psi blue red green H2O H2O test #9 24/64 swab 7 bbls 16:00 clean up 335 30 200 3.50 5.10 5.90 70 1249.00 7.3 7.3 16:15 clean up 320 30 200 3.60 5.30 5.90 1335.00 16:30 320 30 200.00 3.60 5.30 5.90 1335.00 16:45 320 30 200.00 3.60 5.40 5.90 1360.00 17;00 320 30 200.00 3.60 5.40 5.90 1360.00 17:15 320 30 200.00 3.60 7.50 5.70 1522.00 0.5 0.5 17:30 320 30 180.00 2.90 7.50 5.70 1522.00 9.4mw 14.8 160 min Buildup 640 . . Min Pressure 0:00 320 psi 1 450 psi 2 520 psi 3 540 psi 4 570 psi 5 575 psi 6 580 psi 7 585 psi 8 590 psi 9 590 psi 10 595 psi 11 595 psi 12 595 psi 13 598 psi 14 600 psi 15 600 psi 16 600 psi 17 600 psi 18 600 psi 19 600 psi 20 605 psi 21 605 psi 22 605 psi 23 608 psi 24 609 psi 25 609 psi 26 609 psi 27 610 psi 28 611 psi 29 612 psi 30 613 psi 40 615 psi 50 618 psi 60 620 psi 70 623 psi 80 625 psi 90 628 psi 100 630 psi 110 635 psi 120 638 psi 130 638 psi 140 640 psi 150 640 psi 160 640 psi 170 180 240 300 . . NCU#9 1496--179€ perfs 9/25/2006 #9 . . Flow Test 8-Buildup 9-25-06 NCU#9 1320-1447' perfs Min Pressure 0:00 50 psi 1 60 psi 2 65 psi 3 70 psi 4 75 psi 5 80 psi 6 80 psi 7 80 psi 8 80 psi 9 80 psi 10 80 psi 11 80 psi 12 80 psi 13 80 psi 14 80 psi 15 80 psi 16 82 psi 17 82 psi 18 82 psi 19 82 psi 20 82 psi 21 82 psi 22 82 psi 23 82 psi 24 82 psi 25 82 psi 26 82 psi 27 28 29 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 240 300 · . NCU#9 1806-1904 perfs Min Pressure 0:00 325 psi 1 420 psi 2 500 psi 3 545 psi 4 565 psi 5 575 psi 6 585 psi 7 590 psi 8 595 psi 9 597 psi 10 599 psi 11 599 psi 12 600 psi 13 600 psi 14 601 psi 15 602 psi 16 603 psi 17 604 psi 18 604 'psi 19 605 psi 20 606 psi 21 606 psi 22 607 psi 23 608 psi 24 609 psi 25 609 psi 26 610 psi 27 610 psi 28 610 psi 29 610 psi 30 610 psi 40 613 psi 50 617 psi 60 620 psi 70 623 psi 80 625 psi 90 630 psi 100 630 psi 110 630 psi 120 630 psi 130 630 psi 140 630 psi 150 630 psi 160 630 psi 170 180 240 300 AURORA GAS, LLC WELL TEST REPORT 1827 ---1904 zone Performed by: Jack IZanel NCU #9 26-Sep-06 TEST 10 ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Delta Total TIME PERFS SPYDR, TEMP 164" PRESS STATIC DIFF TEMP FACTOR MCF/D VOL VOL PSIA deg F psi blue red green H2O H2O test #10 16:45 1.5"orifice 400 24 200 3.00 8.00 5.50 70 1120.00 2bbls 17:00 2" orifice 325 37 160 2.70 4.30 I 130 1509.00 17:15 300 37 160.00 2.70 4.30 I , 1509.00 17:30 285 37 160.00 2.70 4.30 I I 1509.00 17:45 285 37 160.00 2.70 4.50 " , 1579.00 18:00 280 37 160.00 2.70 4.60 I I 1614.00 18:15 280 37 160.00 2.70 4.60 I I 1614.00 18:30 285 37 160 2.70 4.50 I I 1579.00 18:45 285 37 160 2.70 4.50 I I 1579.00 19:00 285 37 160 2.70 4.50 " I 1579.00 19:15 285 37 160 2.70 4.50 I I 1579.00 19:30 285 37 160 2.70 4.50 , I 1579.00 19:45 285 37 160 2.70 4.50 , I 1579.00 20:00 285 37 160 2.70 4.50 I , 1579.00 90 min Buildup 630 . . AURORA GAS, LLC WELL TEST REPORT Peñs at 1552-1904'--- SSV open @1796 testing both zones Peñormed by: Jack NCU #9 27 -Sep-06 TEST 11 ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE Delta Total TIME PERFS gauge TEMP 164" PRESS STATIC DIFF TEMP FACTOR MCFID VOL VOL PSIG deg F psi blue red green H2O H2O test #11 0 2" orifice 37 200 3.90 3.90 5.50 130 1977.00 2:00 340 " " 3.40 4.20 , 1856.00 2:15 340 " " 3.40 4.45 , , 1967.00 2:30 340 II " 3.40 4.45 , , 1967.00 2:45 340 " " 3.40 4.45 II , 1967.00 3:00 340 " " 3.40 4.45 , , 1967.00 , , , , , , " , , , , , , , , , . . . . DATA TRANSMITTAL Please reply to: AURORA GAS, LLC 10333 RICHMOND, STE. 710 HOUSTON, TX 77042 ATTN: ANDY CLIFFORD State of Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 9950 I ATTENTION: Howard Okland Enclosed From Area 1 CD Aurora Gas, LLC NCU-9 well. Cook Inlet. Alaska Date: 7 September, 2006 1. One CD containing complete digital log data (LAS, DLIS, FMA, FNL & PDS formats) from the NCU-9 well. SCANNED SEP 1 3 2006 PLEASE ACKNOWLEDGE RECEIPT OF DATA BY SIGNING BELOW AND SENDING A COPY BACK TO AURORA GAS FOR OUR FILES. Received by: DJk-. Date: SEP 11 2006 AURORA GAS, LLC, 10333 RICHMOND, S'PIIU0JI1I~/II1.NiQI17042 TEL: 713-977-5799, FAX: 713-977-13,ff1chorage Q00-8015 1t 1i.{1é)f;, RE: Aurora Gas NCD #9 Workover e e Super! Thanks, Tom, and have a good weekend. Regards, JDd--dO~ Bill Penrose Vice President / Drilling Manager Fairweather E&P Services, Inc. 2000 E. 88th Avenue, Suite 200 Anchorage, Alaska 99507 907-258-3446 '''''CA· NN!::n ~FP 1 3 ZOOS \:) ....:-> ,- -. - -----Original Message----- From: Thoma s Ma unde r [~9.__~1:~'?_:,:t., on:_~?:!::1:!?:.?~~~~9~_~~_=_~!:=_?:!__~_:_?:~:_~~] Sent: Friday, September 08, 2006 2:57 PM To: Bill Penrose Subject: Re: Aurora Gas NCU #9 Workover Bill, Commissioner Norman has signed the sundry. The approval is similar to NCU lB. I will fax you the sundry and letter. Tom Maunder, PE AOGCC Bill Penrose wrote, On 9/8/2006 1:51 PM: Tom, Aurora Gas submitted a Sundry Application for working over Nicolai Creek Unit #9 on August 29. While our recent discussion indicates that it's in the final stages of approval, we would like to request that the Commission issue verbal approval to commence the work before Aurora receives the written approval as the rig may be moving onto the well during this coming weekend. Thanks and regards, Bill Penrose Vice President I Drilling Manager Fairweather E&P Services, Inc. 2000 E. 88th Avenue, Suite 200 Anchorage, Alaska 99507 907-258-3446 1 of 1 9/12/20068:03 AM . . August 29, 2006 RECEIVED AUG 2 9 2006 Alaska Oil & Gas Cons Comm¡' A . '1lon ., nChorage E & P SERVICES, INC, Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 West ih Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Sundry Approval: Workover ofNCU #9 (PTD No. 202-208) s,., ANNcf), ('CD 1 Iè) 'ìnU' nr:; '..;:\f~ ...,,(,..~-." ,,) L...] _ ç) ¡.. . v),) Dear Mr. Norman, Fairweather E&P Services, Inc., on behalf of Aurora Gas, LLC, hereby applies for approval of Aurora's plan to work over the NCU #9 gas well in the Nicolai Creek Gas Field on the west side of Cook Inlet. The workover is expected to commence approximately September 6. " This workover will involve adding perforations to those presently existing in the well, extensive flow testing of all old and new perforated intervals and the running of a multi- packer completion to allow selective production ofthe old ahd new intervals. " Enclosed please find a Form 10-403, Application for Sundry Approval, for this work. Also enclosed are a detailed work plan and a current NCU #9 wellbore diagram. The BOP system to be used for this workover is the same as that previously used on the A WS # 1 rig and is on file with the Commission. If you have any questions or require additional information, please contact me at 258- 3446 or Aurora Gas' Ed Jones at (713) 899-8103. Sincerely, F~P SERVICES, INC. Bill Penrose Vice President / Drilling Manager enclosures cc: Ed Jones - Aurora Gas 740 2000 East 88th Avenue· Anchorage, Alaska 99507 . (907) 258-3446 . FAX (907) 279-5 650 North Sam Houston Parkway East, Suite 505· Houston, Texas 77060· (281) 445-5711 . FAX (281) 445-3388 I Ð~ ,/~ /,01,£1 Jil- RECEIVED STATE OF ALASKA L,(r- /4i <t.~ ALAS OIL AND GAS CONSERVATION COMMI Is AUG 2 9 2006 APPLICATION FOR SUNDRY APPROVALS . . 20 MC 25,280 ATa~;ka Oil & Gas Cons. CommtSSlon 1. Type of Request: AbandonD Suspend D Operational shutdownD Perforate0 Wai rage OtherD Alter casingD Repair well D/þ" p(". Plug PerforationsD StimulateD Time Extension D Change approved prograrO Pull TubingØ ~}~ Perforate New PoolO Re-enter Suspended Well D 2, Operator Name: w 4, Current Well Class: 5. Permit to Drill Number: ~ /!¿.¿ÎQ,I'tJt..... (f¡a-j L L C- Development 0' Exploratory D 202-208 3, Address: Stratigraphic D Service 0 6, API Number: 1400 W. Benson Blvd, Suite 410, Anchorage, AK99503 50-283-20102-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line where ownership or landownership changes: Spacing Exception Required? Yes D 9, Property Designation: 8. Well Name and Number: AA-8426 No 0 10. KB Elevation (ft): 11. Field/Pool(s): 48' AMSL PRESENT WELL CONDITION SUMMARY Effective Depth MD (ft): Effective Depth TVD (ft): 2,054' 2,054' NCU #9 Nicolai Creek Gas Field 12. Total Depth MD (ft): 2,102' Casing Structural Conductor Surface Intermediate Production Liner Total Depth TVD (ft): 2,102' Length Plugs (measured): None Junk (measured): None Collapse 82' Size MD TVD 13-38" 100' 100' 9-5/8" 620' 620' 7" 2,098' 2,098' Burst 602' N/A 3,520 psi 4,360 psi N/A 2,020 psi 3,270 psi 2,080' Perforation Depth MD (ft): 1,320' - 1,447' Packers and SSSV Type: Perforation Depth TVD (ft): 1,320' - 1,447' Tubing Size: 2·7/8" Tubing Grade: J·55 Tubing MD (ft): 1,444' 7" Arrow·Pak Seal Bore Retrievable pkr Packers and SSSV MD (ft): 1,243' 13. Attachments: Description Summary of Proposal 0 Detailed Operations Program 0 BOP Sketch 0 15. Estimated Date for Commencing Operations: 9/6/2006 14, Well Class after proposed work: Exploratory 0 Development 16. Well Status after proposed work: Oil 0 Gas 0. WAG D GINJ 0 o Service D 17. Verbal Approval: Commission Representative: 18, I hereby certify that the foregoing is true and correct to the best of my knowledge, Printed Name Title Date: Plugged WINJ o o Abandoned WDSPL D o Contact Bill Penrose 258-3446 Signature Vice President, Engineering and Operations Date 713-977-5799 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: .30(p'" ¿e¡-¡ Plug Integrity 0 BOP Test ~ Mechanical Integrity Test 0 Other: r0-r\/""'. \£. F\h . \. \ C'\ ð~~\ DV~ "\t:<jT ù'> ~ ~~,~ J Location Clearance 0 Form 10-403 Revised 06/2006 Subsequent Form Required: ~O l-\ Approved by: . STATE OF ALASKA _ ALASKA Oil AND GAS CONSERVATION COMMI~N APPLICATION FOR SUNDRY APPROVALS RECEIVED AUG 2 9 2006 20 MC 25.280 AI~.. ,^ n:, <> n 1, Type of Request: AbandonD Suspend 0 Operational shutdownD Perforate 0 waìVli~ll(""uns. r.;ommiNiíã! Alter casingD Repair well 0 Plug PerforationsO Stimulate 0 Time Extensi Orage Change approved prograr{] Pull Tubing~ Perforate New PoolO Re-enter Suspended Well 0 2, Operator Name: 4, Current Well Class: 5, Permit to Drill Number: Forest Oil Corporation Development 0 Exploratory 0 ./ 202-20S 3, Address: Stratigraphic 0 Service 0 67mber: 1400 W. Benson Blvd, Suite 410, Anchorage, AK99503 50-2S3-20102-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name M7" property line where ownership or landownership changes: 0 0 NCU #9 Spacing Exception Required? Yes No 9. Property Designation: 10, KB Elevation (ft): 11. Field/P7: AA-8426 4S' AMSL Nicolai Creek Gas Field 12. PRESENT WELL CONDITION SUMMAJlÝ Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective ~~~ (ft): Plugs (measured): Junk (measured): 2,102' 2,102' 2,054' tX.' ,0 ' None None Casing Length Size MD A :V / TVD Burst Collapse Structural \ "V/. Conductor S2' 13-3S" 100' ^/ 100' N/A N/A Surface 602' 9-5/S" 6i~7 620' 3,520 psi 2,020 psi Intermediate 2,OSO' 7" ~J [AlS' 2,09S' 4,360 psi 3,270 psi Production J/f Liner n...v Perforation Depth MD (ft): Perforation Depth TVD (ft): TU~ize: Tubing Grade: Tubing MD (ft): 1,320' - 1,447' 1,320' -1,447' t 'r>.~ 2-7/S" J-55 1,444' Packers and SSSV Type: 7" Arrow-Pak Seal Bore Rejable pkr Packers and SSSV MD (ft): 1,243' 13. Attachments: Description Summary of proposjb 0 14. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch Exploratory 0 Development 0 Service 0 15, Estimated Date for 9/6t6 16. Well Status after proposed work: Commencing Operations: Oil 0 Gas 0 Plugged 0 Abandoned 0 17. Verbal Approval: Date; WAG 0 GINJ 0 WINJ 0 WDSPL 0 Commission Representative: 18, I hereby certify that the foregoing is true zorrect to the best of my knowledge. Contact Bill Penrose 25S-3446 Printed Name Ádwar Jones Title Vice President, Engineering and Operations Signature .h"" . /R, Phone Date 8/:1 )/o~ ,/'/' /VUI/-' , J V"I" J'\E... T' 713-977-5799 / COMMISSION USE ONLY Conditions of approval: Nol'Y co'¡~;o, ~ Ihat a '''''"",,1'''' may w;lne~ Sundry Number: 8~ .. aq'} . Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: ,.4 'íŠ' 'Jc> Ð{." Form 10-403 Revised 06/208 RIG I N A L Submit in Duplicate . . Aurora Gas, LLC NICOLAI CREEK UNIT #9 2006 RIG WORKOVER / RECOMPLETION PROCEDURE (VERSION 1.0) CAPACITIES: Currently 2-7/8" 6.5# J-55 EUE Tubing: 0.00579 bbl/ft. Work String: 3-1/2" Tubing: 0.0087 bbllft 7" 23# Casing: 0.0393 bbllft Casing Drift ID is 6.241" PBTD=2102' Straight Hole (TVD=MD) Tubing Volume to Packer is 7.2 bbl. Casing vol. below pkr to deepest perf: 8.1 bbl KB= 15' (all depths from KB) PACKER: Weatherford Arrow-Pak Seal Bore Retrievable Production Packer at 1242.9' RESTRICTIONS IN TUBING: Tubing ID=2.441", WXA Sliding Sleeve at 1210'- 2.31", X Nipple wi 2.312" ID below seal-bore extension below packer at 1253'. BACKGROUND: NCU 9 is a shallow straight hole drilled in 2003 to recover reserves behind 2 strings of pipe in NCU 1 and 2. The well had an initial AOF of 48.8 MMCFPD and tested at rates in excess of 5 MMcpfd. The well has produced 1.04 BCF, but production and pressures have fallen to about 400 mcfpd at 130 psi, so the proposed workover will add 125' of new perfs above and v below the 100' of Tsuga 2-7 (Beluga) sands in which the well was completed in 2003. Additional packers will be added as well to isolate the current perfs from those above and below. Thus, the well will be recompleted as a triple selective with 3 packers and sliding sleeves, leaving the current, perfs to come back to when the pressures of the other zones have depleted to same level. 1) Prior to moving in rig, shut in well (all tree valves including SSV). Disconnect flow line downstream of SSV. Disconnect electrical and put in safe place-use care to avoid damaging. (Need Work Permit from Operators to do so). Remove well houses from #9 well and set aside out of the way. 2) Move in, rig up A WS #1 rig wi single workover pit for mud system (not AG mud system) and support equipment only as needed. 3) Starting with clean mud tank, mix 150 bbl (usable volume) 9.3 ppg KCI-NaCI brine (min. 6% KCI) in left-over MM 1 workover or clean produced water. Expected volume to fill well is 15-16 bbl. 4) RU to pump down annulus thru casing valve on tree. Expect to have some pressure «200 psi)-b1eed off. RU to take returns from flowline (2-9/16" 5000# API flanged connection)-have operators open and lock SSV open wi screw-on cap. Disconnect SSV controls and put aside in safe place. 5) RU Pollard with lubricator on 2-7/8" tree cap. Run in hole with slick line and open WXA sliding sleeve at 1210'. Reverse circulate volume (20-40 bbl) to kill well with 9.3 ppg brine. Monitor well--circulate/reverse circulate as needed- expected kill weight brine weight is only 5.0 ppg. May lose volume as perfs at 1320-1447' are significantly depleted (expected BHP is 300-340 psi). Monitor . . losses-may need to use non-damaging LCM (salt or ground calcium carbonate) material to control. 6) When well is dead, set BPV in tubing hanger, ND tree, NU 3000-psi BOPE. Test to 2000 psi (or as required by AOGCC Sundry approval)-maximum BHP expected is less than 1000 psi, based on MDT data. 7) Latch onto tubing hanger and unsting from seal-bore packer. Reverse circulate tubing volume as needed to get any gas out of tubing. Watch well to be sure it is dead. POH wi tubing and seal assembly, standing back 2-7/8" tubing. ./ 8) With packer service man on location, pick up and run packer retrieving tool and 3-112" tubing work string, retrieve Weatherford seal-bore packer at 1243' (packer has 200' of length including seal bore, 3-112" tubing spacer, and 4-112" Stratapack screens beneath it). 9) Run 6" bit and 7" 23# casing scraper on 3-112" tubing and clean out to 2000', noting depths any fill is encountered. Catch samples of fill. Circulate hole clean. Circulate and filter brine until it is 9.3 ppg and clean (thru 5 micron sock filters). POOH with tubing. LD bit and scraper. 10) Move in Schlumberger electric-line unit, lubricator, grease injection skid, and grease injector lubricator. Pressure test. Run GR/CCL to 2000' and tie in to open-hole logs. PU and RIH wi Schlumberger 4.5" HSD guns with Powerjet Omega charges (5 SPF wi 60 deg phasing) and perforate as follows: v a) 1894-1904' b) 1827-1837' c) 1768-1778' d) 1748-1758' (or run 30' gun with middle 10' blanked for c and d). e) 1689-1694' t) 1652-1662' g) 1641-1646' (or 20' gun with above zone, f & g, 1641-61' wi 5' blanked) h) 1624-1629' i) 1552-1562' Total of75' of perfs, 6-10' and 3-5' guns (or 1- 20' and 1- 30' gun to replace 3- 10' and 1-5"). While perforating check pressure immediately after firing, pull out of hole slowly, checking for flow after each run, circulating "across the top", and keep hole full-monitor gas and pit volumes. 11) RD perforators. Insure well is dead, lubricate in 9.3 ppg brine to kill well if needed, using minimal amount of brine. PU casing scraper on 3-1/2" tubing and run to 2000'. Rev CBU-filter brine until clean using 5 or 10 micron sock filters. POH and LD csg scraper. 12) RU Aurora Gas Test Unit as follows: a) set test choke manifold close to rig choke skid and connect wi 1502 hard line from; install 24164" positive choke in manifold (left side)-- use 2" 1502 target tees upstream of choke skid; c) run AG 2" 1502 hard line from choke manifold to test separator; d) set flare stack 100' or more from the rig and production facilities and raise stack; and e) lay AG 3" 1502 hard line from separator skid to flare stack, and connect propane bottle to flare stack. . . 13) PU Treat/Test Packer (w/ unloader/circulating valve) and TIH to 1800' +/- and set pkr. Prepare to swab test deepest 2 sets of new perfs, 1826-1904'. 14) Prepare for test: a) Take and record initial measurements of brine levels in all tanks to which swabbed/flowed back brine will go-know exact volume of brine is in all tanks; b) Record test separator water meter reading; c) install new chart on Barton recorder; d) install fresh nitrogen bottle onto skid for instrumentation; e) install new 1000 psi pressure gauge near test head, isolated with needle valve (upstream from valve that will shut in well for buildup-will want it to record and show SI pressures), and f) confirm electric clock on chart recorder is on and set to 12 hrs and chart is appropriate for clock time. 15) Swab in perfs and flow test until clean and stable, as follows: a) swab in, unloading fluid to shaker/possum belly until well is gassing and/or kicks off to flow; b) when significant gas is at surface (whether swabbing or flowing) or the well is flowing, divert flow to test separator: i) shut down momentarily to light flare stack, then bring back on, adjusting choke size until well is flowing strongly to cleanup, but holding some back pressure on it (probably start at 14/64's and adjust accordingly, target flow at 400- 500 psi. ii) Flow until rate and pressure have stabilized for 15 minutes, increasing slightly is OK, but dropping is not-wait until fluctuations tend to be up, not down) and water has dried up (all of tubing volume + casing volume to bottom of top set of perfs has been recovered) or rate has stabilized. Flow for a minimum of 1 hour. Probably more (2-3 hours), depending upon water production and cleanup. Watch for sand production in water. If producing any sand or much water, shut in and call. iii) Start w/ 1-112" orifice in test meter. Flow rate in mcf/day= static reading (blue) X differential reading (red) X 70, If red chart reading is below 3, change to 1.0" orifice; if it is above 8 change to 2.0" orifice. Meter factors change to 31 or 130, respectively. Orifices may be changed by experienced operator while flowing wI the Daniel Sr. orifice fitting. iv) Catch water samples thru out (downstream oftest separator)-have tested by mud engineer for chlorides and weight-record both and time of sample. Produced water should have chlorides of less than 20,000 ppm and and weight is less than 8.4 ppg-if water is trending in that direction, continue to flow until these properties have stabilized. Keep last sample of produced water to send to lab in Anchorage-label thoroughly. v) Shut in well for buildup twice as long as flow period (should build up to about 800 psi, on first test-lower on all subsequent tests). Report test results to me (Ed)-including email report of flow and buildup tests. . . 16) Open unloader and reverse out gas to kill well thru choke. When well is dead, release packer, CBU, pull up and reset pkr at 1630' and repeat Step 15 to test perfs at 1641-1904' 17) Repeat Step 16, except to reset pkr at 1500' (+1-) to test all new lower- completion perfs at 1552-1904', repeating Step 15. Report results. 18) Open unloader and reverse out to kill well thru choke. When well is dead, release prk, CBU, and TOH wI pkr. At this point, if any of the perfs appear to be making water, we may attempt to shut off the water-procedure will be provided at that time, depending upon test info. If not significant water, proceed as follows: 19) Run completion equipment for these zones as follows, on 3-1/2" work string, wI cross-overs as needed: a) 4-112" Stratapack screens across the perfs with 3-112" tubing spacers between screens-use existing inventory (ideally: 10' screen, 57' spacer, 10' screen, 49' spacer, 30' screen, 86' spacer, 20' screen, 20' screen, 62' spacer, 10' screen, tubing spacer). b) 2.25" (or larger) XN nipple (if BHP from well tests seems to be less than .45 psilft, consider running plug in this profile-would prefer not to). c) Hydraulic set packer set at about 1500' d) Production sliding sleeve (open downward) wI 2.31" X profile at about 1490' (closed) e) 2-7/8" tubing spacer t) Retrievable seal-bore packer wI seal bore extension set at about 1300' 20) Set packers: seal bore packer, then hydraulic packer. TOH wI work string 21) LD setting tool and PU seal-bore plug. TIH wI work string and set plug in seal-bore packer. Pressure test to 1000 psi. Circ 2 sx of clean sand onto plug (confirm this practice with packer service man). Displace brine in well with 10.2 ppg NaBr-NaCI-KCI brine- pull 1 joint and circ and filter brine wI 5 micron filter. TOH with work string. 22) PU 4-1/2" PI Omega TCP perf guns (5 SPF, 60-deg phasing) to perforate: a) 1258-64' b) 1248-54' c) 1218-24' d) 1190-1200' e) 1148-70' 50' of perfs over 120' of gross gun length. Run with test packer on 3- 1/2" work string. Correlate and set packer. (More specific procedure will be provided by perforating service company). 23) Swab well down 350-400' from surface (100-200 psi pressure differential into wellbore, depending upon depths of perfs and original pressure). RD swab equipment. Prep to flow back well as in Step 14 above. . . 24) Prep to perforate. Drop bar to fire guns. Flow back well thru test separator to flow rates, and shut in for pressure buildup as in Step 15 above. (Swab in if necessary, but don't expect it to be needed). If well produced significant water during test, procedure will be supplemented at this point to isolate and deal with it. If not, proceed to Step 25. 25) Kill well with 10.2 ppg brine thru circulating valve in test/treat packer. CBU until all gas is out and well is dead. TOH with work string, laying down packer, and spent guns. 26) PU and run casing scraper on work string to sand at +1-1290'. Reverse circ sand off plug. Pull up and circ and filter brine w/ 5 micron filter. TOH, laying down scraper. 27) PU plug-prong retrieving tool, TIH. Pull prong to equalize pressure. CBU. TOH wI prong and tool. 28) PU plug retrieving tool and TIH. Latch onto plug and pull. TOH, lay down tool and plug. Monitor well for fluid loss (bottom zone is open-it is believed to have .45-.48 psi/ft pressure gradient-determine from well tests-this will not be an issue if plug was run in Step 19.b). 29) Pick up completion string and run in hole wI crossovers as needed: a) Seal assembly wI seal units, extension (if needed), and locator sub b) 10-15' pup joint of 2-7/8" tubing c) Production sliding sleeve wI 2.31" profile (open downward) d) Blast joints across perfs (4 - 20' w/ 2-7/8" tubing and cross-overs between) e) Production sliding sleeve wI 2.31" profile (open downward) at +/1130' (1 joint below packer) f) Hydraulic-set packer set at ±1,100'. g) Sliding sleeve 1 joint above packer (for packer fluid placement and well kill) h) 2-7/8" tubing to surface. 30) Sting into seal bore packer. Space out. Set hydraulic packer, and land tubing. Set BPV. ND BOPE, NU and test tree. 31) Circ packer fluid wI biocide and corrosion inhibitor- do not use diesel to freeze protect. (After setting packers, place by opening sleeve just above packer at 1100' and reverse circulate). 32) (If plug was placed in XN nipple, RU Pollard and pull it) With all sliding sleeves shut, swab in and test lower zones thru test unit-long enough only to get stable rate and shutin pressure. 33) RU Pollard and set plug in XN nipple below deepest packer (at about 1510'). 34) Bleed pressure to 300 psi, and open sleeve in middle completion at +1-1490'. Open well and flow to clean up-swab if necessary. Test thru test unit long enough to get stable rate and SIP-expect 500 mcfpd at 150 psi, and SIP of about 300 psi. 35) Close sleeve at 1490' -maintain SIP as high as possible. (Lubricate in a small amount of brine if a cushion is needed when opening sliding sleeves). . . Open 2 sleeves between top and middle packers (at 1290' and 1130'). POH wi slick line. Open well and flow to clean up thru test unit-get stable rate and SIP. 36) RIH wi slickline and close sliding sleeves at 1130' and 1290'. Pull plug in XN nipple at 1510'. (All sleeves are closed). RD and release Pollard. If water cushion was used in well to open sleeves, it may remain in tubing below sleeve at 1290', so flow well thru test separator to unload. Shut in. 37) Set BPV in tree. Release rig, rig down and move. Pull BPV from tree after rig has moved. Put well on production thru existing facility NOTE: None of the zones open in this well after this work are producing in either of the other two Nicolai Creek Unit wells on the pad-the No. 1B nor the No.2. These are all Beluga Sands in the Beluga P A. Ed Jones (8/25/06) Proposed Final Condition 133/8" 54.5# Conductor Driven 1 00' 8 1/2" Pilot Hole to 620 ' Hole Opened to 12 1/4" with Hole Opener 9 5/8" 36#J-55 620' MD (TVD) Shoe Joint is 47# With Buttress Thread. ai Creek No.9 Gas Prod. Nicolai Creek Field Packer Fluid: 02 Inhibited KCl Fluid above Pkr. 8 1/2" Hole Production Perfs 1320' -1330' @ 5 SPF Production Perfs 1343' -1393' @ 5 SPF Production Perfs 1407' - 1441' @ 5 SPF 1" 23# LTC @ 209.8' MD (TVD) Cemented to Surface 6.5# J·55 8rd Production Tubing Please see attachedcomponant tally for moredetait Weatherford WXAsliding X-Nipple profile. Lo.cated 1 Jt above packer 7" Arrow-Pak Seal Bore RetrievableProcluctiofl Packer @ 1242.90' 3.25" BPR Extension below Packer Crossover 2.312 ID X Nipple Crossover 2 Joints and 1 pup of 3 1/2" 9.2# l-l30 8 rei tubing Crossover 4 1/2" Weatherford Stratapac 11 base pipe, 5.12" Nom OD Screen @ 16.9 ppf) Crossover (1)31/2" 9.2# l·80 Brei Pup Joint Crossover 4 1/2" Weatherford base pipe, 2" Crossover (2) 3 112" 9.2# l~80 8rd PI.IP Joints Crossover 4 1/2" WeatherfordStratapac Screen (4 base pipe, 5.1 aD Screen @1ß.9 ppf) 4 112" Bull Plug @ 1444' 81/2" Hole toTD 2102' MD (TVD) PBTD at 2054' Nicolai Creek Unit No.9 Rev. 02 DHV 03-Nov-2003 Drawing Not to Scale Fairweather E&PServices, Inc. . . FRANK H. MURKOWSKI, GOVERNOR ALASKA. OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Edward Jones Vice President, Engineering and Operations Aurora Gas, LLC 1400 W. Benson Blvd, Ste 410 Anchorage, AK 99503 Re: Nicolai Creek Unit #9, Nicolai Creek Gas Field, NCU #9 Sundry Number: 306-297 ~' ~Ocg ~O Dear Mr. Jones, Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Approval to proceed with pulling of tubing and perforation of additional intervals in Nicolai Creek Unit No. 9 ("NCU 9") is granted. Aurora is granted 20 consecutive days to perforate and test each of the intervals listed in Item No. 10 of the attached 2006 Rig Workover / Recompletion Procedure, shut the interval in, and then to commence testing of another interval or to complete all testing operations. For combined intervals, Aurora is granted 20 consecutive days to test, shut the interval in, and then commence testing of another interval or to complete all testing operations. All test results must be reported to the Commission within 30 days of the last test conducted within the well. Because the additional intervals that will be perforated lie beneath the Beluga Participating Area as defined by the Department of Natural Resources in the Findings and Decision of the Director of the Division of Oil and Gas dated March 10, 2005, the following conditions must be met before the Commission will consider an administrative amendment to CO 478A allowing regular production from NCU 9: 1. All affected owners and landowners must provide written notice to the Commission stating that they are aware that the perforated intervals in NCD 9 lie both outside of the Beluga Participating Area and that they consent to regular production from NCU 9; and 2. Aurora must comply with all requirements of CO 478A that are within Aurora's ability to control. Nicolai Creek #9 . Sundry Number: 306-297 . As soon as these conditions are satisfied, Aurora may apply to the Commission for an administrative amendment to CO 478A to allow regular production to commence from well NCU 9. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). 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 rehearing. A request for rehearing 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. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Please call Steve Davies at (907) 793-1224 if you have any questions. cc: Bill Penrose, Fairweather Steve Davies, AOGCC . . r···· ., .- ,;'\. - " ";'. . ../i··· MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs _ Inserts\Microfilm _ Marker.doc 1 f\j~\J ';{~~b DATA SUBMITTAL COMPLIANCE REPORT 11/8/2005 Permit to Drill 2022080 Well Name/No. NICOLAI CREEK 9 Operator AURORA GAS LLC 5p4 ,¿q ~ Jl~J API No. 50-283-20102-00-00 MD 2102 --- TVD 2102 '/comPletion Date 10/3/2003 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log Yes Samples No Directional Survey ~ S~ J ~~~~ DATA INFORMATION Types Electric or Other Logs Run: GRlCC/ Correlation 7/29/02 Note: used single shot mechaincal "Inc 0 Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name (data taken from Logs Portion of Master Well Data Maint Log Log Run Scale Media No Interval OH / Start Stop CH . Received Comments / Log ¡Log \ Log ðr Mud Log 15 Blu 80 2102 c;aee 11/6/2003 Induction/Resistivity 25 Blu 618 2102 Open 11/6/2003 Array Induction Log/MCFL Compensated Neutron/Density - Platform Express Neutron 25 Blu 618 2102 Open 11/6/2003 Array Induction Log/MCFL Compensated NeutronlDensity - Platform Express Density 25 Blu 618 2102 Open 11/6/2003 Array Induction Log/MCFL Compensated Neutron/Density - Platform I Express . ~iPer log 5 Blu 618 2102 Open 11/6/2003 Caliper Log - Platform Express Pressure Blu 770 1830 Open 11/6/2003 Modular Dynamic Tester Temperature Blu 770 1830 Open 11/6/2003 Modular Dynamic Tester Magnetic Resonance 5 Blu 618 2102 Open 11/6/2003 Combinable Magnetic Resonance Tool Gamma Ray 5 Blu 770 1830 Case 11/6/2003 Cased Hole Gamma Ray (Surface Casing) Cement Evaluation 5 Blu 100 2010 Case 11/6/2003 Ultrasonic Cement and Casing Imager Casing collar locator 5 Blu 100 2010 Case 11/6/2003 Ultrasonic Cement and Casing Imager ( Log ~ /' Log Log /Log ~g ~L09 f/ ~ Log I DATA SUBMITTAL COMPLIANCE REPORT 11/8/2005 Permit to Drill 2022080 y102 i I Well Name/No. NICOLAI CREEK 9 Operator AURORA GAS LLC API No. 50-283-20102-00-00 TVD 2102 Completion Date 10/3/2003 Completion 1-GAS Current Status 1-GAS UIC N Completion Status 5 Blu 1320 --- 1447 Case 11/6/2003 41/2" HSD Power Jet 4505, HMX, 5 SPF - Completion Record Well Cores/Samples Information: Name Interval Start Stop Sample Set Number Comments Sent Received . ADDITIONAL INFOR~C. ION Well Cored? Yl!Y Daily History Received? G/N ~N Chips Received? '( ¡ r~- Analysis Received? Formation Tops ~ Comments: ~-"~-.~-~ ~..- G J+ ~)1',l\ ~,\},·i-s ~á ..t.JWv.;l ~l J\.M." cJ ~~ t \\ II" ~ ~ 'f~~Å\M..'-- ~l'l)-. o..-,(,I;U.o"'~ e- '""..aÞ"o. Y'''W-W. t.c,)~ ~~ ~ ~r- µ~ - ,,~ Compliance Reviewed By: Date: ~ Þ-u-- ~ ¡-- . RE ( STATE OF ALASKA .... CEIVED ALASKA OIL AND GAS CONSERVATION COMk....SION DEC 3+ 2003 ~~~ W~n~~O OP~ ~L1~~~OT~~lltL T~on~!iøR~~ .-mmilsion Constant Time 0 Isochronal 0 Other _ Anchor:Jgo 5. Date Completed: 11. Permit to Drill Number: 10/3/2003 202-208 1 a. Test: 2. Operator Name: Aurora Gas, LLC 3. Address: 6. Date TD Reached: 10333 Richmond, Ste 710, Houston, TX 77042 9/22/2003 12. API Number: 50- 283-201 02-00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): Surface: 2010' FSL, 261' FWL, SEC 29 T11N R12W, SM 48' 8. Plug Back Depth (MD + ~~~~~rodudive TVD): 2054' (MD &TVD) sam e 9. Total Depth (MD + TVD): 2102' (MD & TVD) 10. Land Use Permit: Total Depth: 4b. Location of Well (State Base Plane Coordinates): Surface: x- 241,605.305 y- 2,565,249.981 TPI: x- y- y- Weight per foot, lb. 23 Weight per foot, lb. 6.5 21. GOR cf/bbl: NA TotalDepth: x- 17. Casing Size 7" 18. Tubing Size 2-7/8" 20. Packer set at ft: 1243 24a. Producing through: 24b. Reservoir Temp: Tubing m Casing 0 66 p 25. Length of Flow Channel (L): Vertical Depth (H): 1384' 1384' 26. FLOW DATA Prover Choke Pressure Diff. Line X Orifice No. Size (in.) Size (in.) psig hw 1. 5.761 X 2.0 506 2. 5,761 X 2.0 499 3. 5.761 X 2.0 528 4. 5.761 X 1.0 488 5. 13. Well Name and Number. NICOLAI CREEK UNIT #9 14. FieldlPool(s): NICOLAI CREEK GAS FIELD Zone- 15. Property Designation: AA-8426 Zone- 16. Type of Completion (Describe): Cased and perforated, wI sand control screens Set at ft. 19. Perforations: From To 2098 Zone- I.D. in inches 6.366 I.D. in inches 2.441 Set at ft. 1243 1320-1330'; 1343-1393'; 1407-1447' 22. API Liquid Hydrocarbons: NONE 23. Specific Gravity Flowing Fluid (G): 0.56 24c. Reservoir Pressure: 688 psia @ Datum 1384' Gg: % CO2: % N2: 0.562 0.35 0.89 24d. Barometric Pressure (Pa): 15 psia Taps: Flange TVDSS %H2S: o Prover: Meter Run: 5.761" TUBING DATA CASING DATA Temp. Pressure Temp. Pressure Temp. Duration of Flow OF psig of psig of Hr. 41 580 280 1.25 49 614 280 1.0 38 633 280 1.0 36 641 280 1.0 Basic Coefficient ..,¡ hwPm Pressure Flow Temp. Gravity Factor Super Compo Rate of Flow (24-Hour) Pm Factor Factor a, Mcfd No. Fb or Fp Ft Fg Fpv 1. 5390 ? NOT AVAlLABLE- CALCULATED ELECTRONICALLY BY ASRC WELL TeST UNIT 3590 3, 1980 4. 930 5_ Temperature for Separator for Flowing Pr T Tr z Gas Fluid No. Gg G 1. 0.56 2. NOT CALCULATED --USED RYDER SCOTT SPREADSHEET 3. SEE ATTACHED Critical Pressure 672.14 4. Critical Temperature 343.45 5. Form 10-421 Revised 2/2003 CONTINUED ON REVERSE SIDE Submit in Duplicate OR'G'NJ~l._ ) Pc 667 P& 444,889 No. pt PF Pc2-PF Pw 1. 595 354,025 90,864 2. 629 395,641 49,248 3. 648 419,904 24,895 4. 656 430,336 14,553 5. 25. AOF (Mcfd) 49,146 Remarks: Pf ..?~~_ ) PF ~73,344 Pw2 PC2_PW2 Ps 650 664 673 768 PS2 422,500 440,896 452,929 459,684 PF_PS2 50,844 32,448 20,415 13,660 n ~.:.o.Q-º___ Signed e and correct to the best of my knowledge. Title Vice Preside.!!~ ---- Date 12/29/~3 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/-v'hwPm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= ~dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psi a 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 2/2003 Side 2 ) fí:1 ID'~ -- "::'"::\1".,..".,,, " \ . \( ... .b\... J ~ Ryder Scott Reservoir Solutions (Public) (Protected) WELL NAME: FIELD: LocATION: RESERVOIR: BOTTOMHOI E TEMP, of: GJ S GRAVITY: 66 0.562 1.005 SOUR GAS· N2 CO2 H2S. RESULTS AOF, Mcf/d: C· . ' POINT NO. ;Automatic) Q, Mcf/d SHUT~N 0 1 5,390 ..v--".,_."..~-~--_._"'_._--"--_._-- ____.~_____._.___~,5~____ ..._~._ 1,980 4 930 BCPD "_."--~-- ) NICOLAI CREEK UNIT NO.9 NICOJ..AI CREEK T11N,R12WSM, Kenai Boromgh, West Side Cook Inlet, ALASKA Beluga 1320-1447' MOLE % 0.89 0.35 0.00 Options 2.441 n: 49,146 0.10~704 1'.000000 1,000 '7 ~ >< "\0 .¡;; 0- C;¿ ~ 100 100 FTP, Psla 667 595 629 648 656 WHT, of 40 40 40 38 36 1,000 Flow Rate. Mcf/d 10,000 FLOWING BHP, Psia 688 650 664 673 678 100,000 COMMENT SIBHP 42/64 chk 32/64 chk 24/64 chk 16/64 chk These results were prepared using Reservoir Solutions Software. This is not Ryder Scott work product. o o o o o Test Data BWPD o o o o o H20 I iRAVITY, Yw: CONDo 'RAV., GAPI: TVD, FT: 1,384 MEAS DEPTH, FT: 1,384 Cond...';orrel. (Y/N): N 0 Check, If Injection Well Corn ;tOO* Tc, oR: 343.45 Correc.1 ~d* Pc, Psia: 672.14 0 Smooth Pipe Roughness· Pressua: , Base, PSÎa: 14.730 T1:'BING ID, IN~: .,. Wlchert-Azlz Ci ,'rectlon tor contaminants, If any /Oó'/1,OOO r ("t') b T'""" x N co "en a.. N C/) a.. N c:- /0 / 100 100 1,000 - - !\í///) í \¡ ! ( U/ A i (;2 /~ / ~ IV 0 Q LI ¡;;//r í~t;T" 1//;]/03 - - T- - _.-. ~- ¡]f i ___T tl~_-=-~=_!-----r---I------T!-r--i 1-- :j¡ .Ii / ¡ il i¿ , ,/' I: .- if - -). - i ¡i I 11 ¡ .1 i I !;* z ! y I l ¡I;,! I .7 j 3 I Kf II X .II 7 I /i Ii _ í I lï i I .~' :1 . 'J -- Flow Rate, Mcf/d 10,000 100,000 IJOF Job Log I::ntry ·1 in'¡ 11/19/03 1< 55 11/20/03 7. )0 11/20/03 7 )2 ll/20/037 ;0 11/20/03 7 ;0 11/20/03 8 I 0 11/20/03 9 )0 11/20/03 9 ~O 11/20/03 9 ;5 11/20/03 1 ( 00 11/20/03 H II 1l/20/03 ] ( 51 1l/20/03 1 ¡ 15 11120/03 ] 2 00 11120/03 1 ¿ 02 11120/03 1: 00 11/20/03 I:: 12 1l/20/03 L 45 11/20/03 1:' 50 ] 1/20/03 ], 17 11120/03 1, 30 11120/03 I, 42 11/20/03 1 ~ 00 ] 1/20/03 I.' 2Ð 11/20/03 1: 30 11/20/03 ] ( 00 11/20/03 1 ( 30 11/20/03 ]' 00 11/20/03 l' 18 11/20103 l' 30 11/20/03 1 j no 11/20/03 ( 15 11/20/03 I, 30 11/20/03 I' 00 11/21/03 () )0 ) ') Job Log Comment Pressure Test Complete Open Safety System. Open Wing Monitor SII Pressure Open To Separator 1" Orifice Plate Change To High Range Gas Turbine Meter Building Back Pressure in separator to 500 psi Stabilizing Back Pressure and Rate Installed a 20/64 positive Choke in Manifold. Diverted to 16/64 Adjustable choke Incrfeased choke to 20/64 Divert to Daniel Meter for Gas Measurement Decreased choke to 16/64 Increased Adjustable Choke to 20/64, Dropped Separator Pressure To 100 psig. Start Injecting MEOH Changing Orifice Plate To 1.25" Increased Choke To 24/64. Open Choke To 28/64. Change Orifice Plate To 1.5" Increased Choke To 32/64. Changed Orifice Plate To 2" Increased Choke To 36/64. Increased Choke To 40/64. Increased Choke To 42/64. Start Test With 42/64 Choke, Reset Totalizers Drop Back In 2" Orifice Plate Start Test Through Orifice Plate Reset Totalizers End 42/64 Choke Test, Decreased choke to 32/64 Start 32/64 Choke Test, Reset Totalizers End 32/64 Choke Test. Decreased choke to 24/64 Orifice Changed and Stabilizing for 24/64Choke Test. Start 24/64Choke Test. End 24/64 Choke Test. Decreased choke to 16/64 Stabilize For 16/64 Choke Test. Start 16/64 Choke Test. End 16/64 Choke Test. SII @ Choke Manifold Monitor S/I Pressure. SI @ Master, SSV, and Wing move inlet to NC-02 Page 1 Location NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 N C-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 NC-09 ) 15 Min Reads ) Well Head Skid BS&W Vessel Gas VVCUI:ft vI III"'" IIA O/A Choke Cut Solids Carbolite Gas Liquid Size Rate Increment Total Reading Time Locath (PsIg) (Pslg) (Pslg) (DegF) Setting % % % (Pslg) (DegF) (DegF) (In) (mmscfld) (mscfld) (mscfld) 11/20103 7:15 NC-( 0 0 652 0 16 0.00% 0.00% 0.00% 0 53 61 1 .p.02 0.00 0.00 11/20/03 7:30 NC-U ) 0 0 648 0 16 0.00% 0.00% 0.00% 9 50 56 I 0.00 0.00 0.00 11/20/03 7:45 NC-O' 0 0 644 0 16 0.00% 0.00% 0.00% 221 53 56 I 0.32 0.00 0.00 11/20103 8:00 NC-(, 0 0 648 0 16 0.00% 0.00% 0.00% 153 40 42 0 1.09 0.24 0.24 11/20/03 8: 15 NC-( , 0 0 648 0 16 0.00% 0.00% 0.00% 468 56 57 0 0.00 0.00 3.84 ] 1/20/03 8:30 NC-( 0 0 648 0 16 0.00% 0.00% 0.00% 504 53 56 0 0.01 0.08 6.85 11/20/03 8:45 NC-( I 0 0 656 0 16 0.00% 0.00% 0.00% 529 50 55 0 0.00 0.00 7.51 11/20/03 9:00 NC-() ,I 0 0 656 0 16 0.00% 0.00% 0.00% 509 49 54 0 0.00 0.00 7.65 11/20/03 9: 15 NC-O) 0 0 652 0 16 0.00% 0.00% 0.00% 497 49 54 0 0.00 0.00 7.68 11/20/03 9:30 NC-O ) 0 0 652 0 16 0.00% 0.00% 0.00% 489 48 54 0 0.01 0.00 7.72 11/20/03 9:45 NC-( 0 0 644 0 16 0.00% 0.00% 0.00% 537 49 55 0 0.01 0.00 8.00 ] 1/20/03 10:00 NC-C1 0 0 652 0 16 0.00% 0.00% 0.00% 229 33 35 0 0.00 0.00 8.90 11/20/03 10:15 NC-O I 0 0 648 0 20 0.00% 0.00% 0.00% 504 43 48 1 0.60 0.38 2.13 11/20/03 10:30 NC-O' 0 0 648 0 20 0.00% 0.00% 0.00% 502 41 47 1 0.37 0.24 6.70 11/20/03 10:45 NC-O I 0 0 652 0 20 0.00% 0.00% 0.00% 508 41 48 1 0.04 0.03 8.79 11/20/03 11 :00 NC-O 1 0 0 644 0 20 0.00% 0.00% 0.00% 510 40 47 1 1.01 0.59 13.65 11 /20/03 11: 15 NC-O) 0 0 641 0 20 0.00% 0.00% 0.00% 445 37 44 I 0.03 0.05 20.98 11/20/03 11:30 NC-O' 0 0 648 0 20 0.00% 0.00% 0.00% 100 27 31 1 0.35 0.24 22.88 lI/20/03 11:45 NC-O I 0 0 648 0 20 0.00% 0.00% 0.00% 101 30 35 1 0.37 0.25 26,57 11/20/03 12:00 NC-O) 0 0 648 0 20 0.00% 0.00% 0.00% 101 30 36 I 0.41 0.28 30.18 11/20/03 12:15 NC-O) 0 0 644 0 24 0.00% 0.00% 0.00% 108 26 31 1 0.02 0.01 33.48 11/20/03 12:30 NC-O) 0 0 644 0 24 0.00% 0.00% 0.00% 110 25 30 1 0.00 0.00 34.13 II/20/03 12:45 NC-O I 0 0 648 0 24 0.00% 0.00% 0.00% 105 24 30 0 0.00 0.00 19.37 lI/20/03 13:00 NC-O I 0 0 644 0 24 0.00% 0.00% 0.00% 106 24 29 1 0.70 0.17 37.16 11 /20/03 13: 15 NC-O 0 0 636 0 28 0.00% 0.00% 0.00% 115 19 27 2 1.80 1.27 43.23 11/20/03 13:30 NC-O 0 0 641 0 28 0.00% 0.00% 0.00% 112 17 25 2 1.70 1.09 60.85 11/20/03 13:45 NC-O ,I 0 0 633 0 28 0.00% 0.00% 0.00% 113 15 25 0 1.99 -47.70 30.81 11/20/03 14:00 NC-O 1 0 0 625 0 32 0.00% 0.00% 0.00% 121 15 25 2 3.02 2.02 93.28 11/20/03 14:15 NC-Oi 0 0 625 0 32 0.00% 0.00% 0.00% 122 15 25 2 2.81 1.94 122.67 11/20/03 14:30 NC-O 1 0 0 584 0 40 0.00% 0.00% 0.00% 136 16 27 0 3.67 2.57 80.45 11/20/03 14:45 NC-O) 0 0 569 0 42 0.00% 0.00% 0,00% 140 18 28 0 3.76 2.61 118.66 1I/20/03 15:00 NC-O ) 0 0 569 0 42 0.00% 0.00% 0.00% 140 20 29 0 3.73 0.00 0.00 Il120/03 15: 15 NC-O I 0 0 580 0 42 0.00% 0.00% 0.00% 511 35 43 0 4.71 3.59 48.39 Start 1/2 Houl· 42/64 t IS Choke Test lI/20/03 15:30 NC-O' 0 0 580 0 42 0.00% 0,00% 0.00% 509 39 46 2 5.39 0.00 0.00 1I/20/03 15 :45 NC-O 0 0 580 0 42 0.00% 0.00% 0.00% 507 40 48 2 5.39 3.74 55.82 1I/20/03 16:00 NC-O 1 0 0 580 0 42 0.00% 0.00% 0.00% 506 41 49 2 5.39 3.75 112,05 End 1/2 Hour 42/64 tt ) Choke Test lI/20/0316:15 NC-o ¡ 0 0 614 0 32 0.00% 0,00% 0.00% 502 40 47 2 3.58 2.49 150.47 St8l11/2 Hour 32/64 I IS Choke Test 11/20/03 16:30 NC-O 0 0 614 0 32 0.00% 0.00% 0.00% 500 40 48 2 3.59 0.00 0.00 11/20/03 16:45 NC-O ¡ 0 0 614 0 32 0.00% 0.00% 0.00% 499 40 48 2 3.59 2.50 37.34 11/20/03 17:00 NC-O 1 0 0 614 0 32 0.00% 0.00% 0,00% 499 40 49 2 3.59 2.50 74.79 End 1/2 Hour 32/64 tI ; Choke Test 11/20/03 17: 15 NC-O! 0 0 629 0 24 0.00% 0.00% 0.00% 432 37 44 2 0.00 0.00 85.70 Start 1/2 Hour 24/64 t IS Choke Test 11/20/03 17:30 NC-()) 0 0 633 0 24 0.00% 0.00% 0.00% 527 39 48 2 1.99 0.00 0.00 lI/20/03 17:45 NC-(J! 0 0 633 0 24 0.00% 0.00% 0.00% 528 38 48 2 1.98 1.38 20.64 lI/20/03 18:00 NC-O I 0 0 633 0 24 0.00% 0.00% 0.00% 528 38 47 2 1.98 1.38 41.27 End 1/2 Hour 24/64 tl ,Choke Test Page 1 15 Min Reads ) 11/20/03 18: 15 NC-O' ¡ 0 0 644 0 16 0.00% 0.00% 0.00% 517 38 45 0.74 0.00 0.00 Start 1/2 Hour 16/64 t is Choke Test 11/20/03 18:30 NC-()' ¡ () 0 641 0 16 0.00% 0.00% 0.00% 483 36 45 0.94 0.00 0.00 11/20/03 18:45 NC-O I 0 0 641 0 16 0.00% 0.00% 0.00% 485 36 45 0.94 0.65 9.74 11/20/03 19:00 NC-O) 0 0 641 0 16 0.00% 0.00% 0.00% 488 36 45 0.93 0.65 19.46 End 1/2 Hour 16/64 tll ) Choke Test 11/20/03 19: 15 NC-O' I 0 0 652 0 16 0,00% 0,00% 0.00% .0 20 23 I 0.00 0.00 20.01 11/20/03 19:30 NC-O) 0 0 648 0 16 0.00% 0.00% 0.00% 1 27 30 1 0.00 0.00 0.00 11/20/03 19:45 NC-O' 0 0 648 0 16 0.00% 0.00% 0.00% 1 30 33 1 0.00 0.00 0.00 11/20/03 20:00 NC-OI 0 0 652 0 16 0.00% 0.00% 0.00% 0 32 35 1 0.00 0.00 0.00 11/20/0320:15 NC-O) 0 0 652 0 16 0.00% 0.00% 0.00% 0 33 36 1 0.00 0.00 0.00 11/20/03 20:30 NC-O) 0 0 648 0 16 0.00% 0.00% 0.00% 0 34 38 1 0.00 0.00 0.00 11/20/03 20:45 NC-O) 0 0 648 0 16 0.00% 0.00% 0.00% 0 34 39 1 0.00 0.00 0,00 11/20/0321 :00 NC-O) 0 0 652 0 16 0.00% 0.00% 0.00% 0 35 40 1 0.00 0.00 0.00 11/20/03 21: 15 NC-O) 0 0 652 0 16 0.00% 0.00% 0.00% 0 35 40 1 0.00 0.00 0.00 11/20/03 21 :30 NC-O) 0 0 648 0 16 0.00% 0.00% 0.00% 0 36 41 1 0.00 0.00 0.00 11/20/03 21:45 NC-O) 0 0 648 0 16 0.00% 0.00% 0.00% 0 36 42 I 0.00 0.00 0.00 11/20/03 22:00 NC-O) 0 0 652 0 16 0.00% 0.00% 0.00% 0 36 42 1 0.00 0.00 0.00 11/20/0322:15 NC-C) 0 0 652 0 16 0.00% 0.00% 0.00% 0 37 43 1 0.00 0.00 0.00 11/20/03 22:30 NC-(;) 0 0 652 0 16 0.00% 0.00% 0.00% 0 37 43 1 0.00 0.00 0.00 11/20/03 22:45 NC-O) 0 0 652 0 16 0.00% 0.00% 0.00% 0 38 44 1 0,00 0.00 0.00 11/20/03 23:00 NC-O) 0 0 652 0 16 0.00% 0.00% 0.00% 0 38 44 1 0.00 0.00 0.00 11/20/03 23:15 NC-(\ ) 0 0 648 0 16 0.00% 0.00% 0.00% 0 38 45 1 0.00 0.00 0.00 11/20/0323:30 NC-( ) 0 0 652 0 16 0.00% 0.00% 0.00% 0 38 45 1 0.00 0.00 0.00 11/20/03 23:45 NC-( ) 0 0 656 0 16 0.00% 0.00% 0.00% 0 39 46 1 0.00 0.00 0.00 11/21/030:00 NC-O) 0 0 652 0 16 0,00% 0.00% 0.00% 0 39 46 1 0.00 0.00 0.00 Page 2 ,DEÇ-22-03 09:25 AM IND TRIAL INSTRUMENT EG&G Chandler Engineering Model 292 BTU Analyzer Test time: Dec.12 03 09:58 Test #:1 Methane Ethane Moisture Nitrogen ( C02 ) ___ Standard/Dry Analysis___ Mole' BTU* R.Den.* GPM** 98.689 999.09 0.5467 0.074 1.31 0.0008 0.0197 0.000 0.00 0.0000 0.889 0.00 0.0086 0.348 0.00 0.0053 907 283 7766 P.02 ) Calibration #:Default Location No. :9 Saturated/Wet Analysis . MOle' BTU. R. Den. ... 96.972 981.71 0.5371 0.072 1.29 0.0008 1.740 0.88 0.0108 0.874 0.00 0.0085 0.342 0.00 0.0052 Total 100.00 1000.4 0.5613 0.0197 100.00 * : Uncorrected for compressibility' at 60.0F & 14.730PSIA. **: Liquid Volume reported at 60.0F. Standard/Dry Analysis Molar Mass - 16.257 Relative Density = 0.5622 Compressibility Factor ~ 0.9980 Heating Value = 23298. Btu/lb Heating Value ~ 1002.4 Btu/CF Absolute Gas Density = 43 .0240 Ibm/100'DCF Wobbe Index a 1314.9' Unnormalized Total: 118.352- .. '. e_ .. , 983.9 0.5624 Saturated/Wet Analysis 16.288 0.5633 0.9979 22870. Btu/lb 985.9 Btu/CF 43.1094 lbm/1000CF , ~b+ Last upaace: GPA 2261-90. C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.Wt. 92.00. AURORA GAS NCU #9 Sample Date: 11-23-03 Run Date: 12-12-03 Press: 652# RUN 1 12/8/2003 10:12 AM lof2 The results of the above mentioned flow testing is being processed and reviewed and will be forwarded to the AOGCC within the next couple of weeks. Please call with any questions or concerns. Aurora Gas, LLC would like to inform the Alaska Oil and Gas Conservation Commission that they are in the final stages of testing and commissioning their Nicolai Creek Unit production facilities and will likely begin production within the next couple of days. Sales will be through the custody transfer meter originally set up for gas sales from the NCU #3 well. It should be noted that each of the (3) wells, NCU IB, NCU 2, and NCU 9 have individual flow meters for production allocation and that there is a site master meter as well. Per our phone conversation this morning, this email is being submitted on behalf of Aurora Gas, LLC. We just recently wrapp'ed up testing of the NCU IB, NCU 2, NCD 9, and Mobil Moquawkie No. 1 (late November, the results of which were just received from the testing contractor). Aurora has installed the production facility and gathering lines to begin production from the (3) Nicolai Creek wells located in a cluster on the beach near Shirleyville. d-,Dd - \ CO~ l (0(.0.- OS <6 ~·a ð'- d-a 'ìÇ' \ \ Torn: ~ ~ "\ duane vaagen wrote: ,,~ ~ \..) \ '::' Thanks much Duane. information. Tom Maunder, PE AOGCC We will look forward to receiving the testing Subject: Re: Nicolai Creek Production From: Thomas Maunder <tom _ maunder@admin.state.ak.us> Date: Mon, 08 Dec 2003 10: 12:22 -0900 ¡To: duane vaagen <duane@fairweather.com> iCC: John D Hartz <jack _hartz@admin.state.ak..us>, Steve Davies <steve_davies@admin.state.ak.us>, Steve McMains ~steve _IDcmains@admin. state .ak. us> BCC: Daniel T Seamount JR <dan_seamount@admin.state.ak.us> ) ) Re: Nicolai Creek Production ) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION CL.JMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL: GAS: X 2. Name of Operator Aurora Gas, LLC 3. Address 1029 W. Third Ave., Suite 220 Anchorage AK 99501 4. Location of well at suñace 2010' FSL, 261' FWL, S29, T11N, R12W SM (ASPX 241585.4, ASPY=2565248.12) At Top Producing Interval At 1320' MD Same At Total Depth Same 5. Elevation in feet (indicate KB, OF, etc.) 48'KB 12. D~~ Spudded 13. Date T.D. Reached 8¡2tJ12003 $9 9/22/2003 . 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) 2102' MD & TVD 2054' MD & TVD 22. Type Electric or Other Logs Run GRlCCL Correlation 7/29/2002 23. SUSPENDED: ABANDONED: SERVICE: At PBTD 2054' MD & TVD 7. Permit Number 202-208 8. API Number 50· 283-20102-00 9. Unit or Lease Name Nicolai Creek Unit 10. Well Number NCU #9 11. Field and Pool 6. Lease Designation and Serial No. AA-8426 14. Date Comp., Susp. or Aband. / 10/3/2003 Completed 19. Directional Survey Yes: x No: Nicolai Creek Gas Field 15. Water Depth, if offshore 16. No. of Completions NA feet MSL 1 20. Depth where SSSV set 21. Thickness of Permafrost NA feet MD NA 7" WT. PER FT. 54.5# 36 &47# 23# GRADE K-55 K-55 J-55 Note: Used single shot mechanical "Inc Only" type survey instrument. CASING, LINER AND CEMENTING RECO~D SETTING DEPTH MD TOP BOTTOM o 100' o 620' o 2098' HOLE SIZE CASING SIZE 13 3/8" 95/8" Driven CEMENTING RECORD N/A 270 sx Type I 289 sx "G" AMOUNT PULLED o o o o 12 1/4" 81/2" SIZE 27/8" TUBING RECORD DEPTH SET (MD) 1243' PACKER SET (MD) 1243' 24. Peñorations open to Production (MD+ TVD of Top and Bottom and interval, size and number) 25. 1320' -1330" MD (1320' -1330' TVD) 5 SPF 41/2 HSD 1343' -1393' MD (1343' -1393' TVD) 5 SPF 41/2 HSD 1407' - 1447' MD (1407' - 1447' TVD) 5 SPF 4 1/2 HSD 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 27. Date First Production PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.) Flowing Gas through Choke and Seperator PRODUCTION FOR OIL-BBL GA5-MCF TEST PERIOD => 0 Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCF Press. 0 24-HOUR RATE => 0 0 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. Date of Test Hours Tested WATER-BBL o WATER-BBL o CHOKE SIZE GAS-OIL RATIO NA OIL GRAVITY-API (corr) NA None , I' c,-, \... ""~.ILIL1,., ¡:,'c;J........ " .Ll),._~' _o.~._ , _..~Å!} -.- ,- -. : NOV 0 5 '~"':' " , RfDIS 8Ft. tIW 1 2 ?Ot! Form 10-407 Rev. 7-1-80 CONT'Nð ~~\t;~K~ L Submit in duplicate l,F ) 29. 30. ) FORMATION TESTS GEOLOGIC MARKERS NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Base Glacial Wash 512' 512' TSUGA 2-5 "Beluga" 733' 733' TSUGA 2-6 "Beluga" 1030' 1030' TSUGA 2-7 "Beluga" Perfs @ 1320' - 1330' 1343' - 1393' 1407' - 1447' Same Flow 1 hr on 20/64" choke. Unload well then steady flow 1.5 mmcfd at 570 psi FTP. Flow 20 min on 26/64" choke: Steady flow 2.4 mmcfd at 570 psi FTP. Flow 15 min on 32/64" choke: Steady flow 3.5 mmcfd at 535 psi FTP. Flow 10 min on 20/64" choke: Steady flow 1.5 mmcfd at 615 psi FTP. SI after 1hr 45 min flow: 1-min SITP 648 psi, 10 min SITP 650 psi, 15 min SITP 650 psi. Recovered total of 9 bbls load water with 172,000 ppm CI (completion fluid) TSUGA 2-8 "Beluga" 1822' 1822' CARYA 2-1 "Tyonek" 2074' 2074' <í\ \:" I.~~~OV 1\ f) Ï!J ,t~l 31. LIST OF ATTACHMENTS Wellbore schematic, Completion tally, Summary of Rig Workover Operations 32. I hereby certify that the foregoing is true and ct to the best of my knowledge sçtt~~-/ Title _Exec. Vice President, Operations and Engineering_ Date / I ~ ~ 3 INSTRUCTIONS 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. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other space on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the productin intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (OF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump. Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 ORIGINAL "J WELL DRILLING AND COMPLETION REPORT NICOLAI CREEK UNIT NO.9 Shirleyville, Alaska ~}Aurora Gas, I.I.C 3-N ovember-2003 Aurora Gas, LLC Page 1 of8 ) Background Information: The Nicolai Creek Unit No.9 well was pennitted to be drilled as a natural gas production well by Aurora Gas, LLC. The location to be an existing well site which already contained NCU #2 and NCU #lB. Aurora submitted and received approvals from the State of Alaska AOGCC on November 15,2002 and the US Bureau of Land Management on January 24, 2003. The conductor for the Nicolai Creek Unit No.9 was installed on September 24,2002 when the rig, Aurora Well Service Rig No. 1 was moved over the well site and a 13 3/8" 54.5#/ft conductor was driven to refusal at 100'. The rig was then moved off site and operations suspended until the following year. On August 22, 2003 the location was prepared by laying do\vn a geo-textile felt and herculite to create an impenneable barrier between the rig and ground. The rig, Aurora Well Service No.1, along with tanks, pumps and ancillary equipment was then moved into place and the perimeter was blocked with sills to provide a benn of sufficient size to contain a possible spill. The following well work summary details the drilling and completion work chronology. Attachment I is schematic of the well as completed and Attachment II is a tally and diagram of the actual completion equipment in the well at this time. Also attached is a diagram of the Cameron production tree installed on the well. Work Summary and Daily Activities: 22-Aug-2003 23-Aug-2003 24-Aug-2003 25-Aug-2003 26-Aug-2003 27-Aug-2003 28-Aug-2003 Aurora Gas, LLC Mobilize rig to NCU #9 well site from NCU #3. Secondary containment placed (felt and herculite) on ground and rig mats placed. Move in rig and RU. Continue RU. Continue RU Continue RU Continue RU. Rig floor, install Diverter and spools wi flow nipple. Work on installation of mud cleaning equipment and de- gasser. Continue RU. Fabricating flow lines for mud cleaning equipment. RU and test gas sensors. Pre-Spud meeting at Shirleyville wi Vendors. Lou Grimaldi wi AOGCC on site to inspect diverter. Noted deficiencies in rig-up and noted one gas detector failure. Correct deficiencies and order out replacement part for gas detector. Spud delayed when unable to mix mud. Work on rebuild of mud mixing system. Page 2 of8 ) 29-Aug-2003 Mix and condition spud mud, rig accepted to drill and well spudded at 1530 hrs. Tag fill at 35' inside drive pipe with 8 1/2" bit, attempt drill out of material, shaker loading with material, found shaker to be wired incorrectly. Repair and proceed to drill out of conductor to 234' wi 8 ~" BHA. 30-Aug-2003 Drill to 390', stop drilling when primary pump engine "OPI 750" developed problem. Appeared to be diesel leak internally which filled crankcase. Shut down drilling and rotate off bottom while diagnosing problem. 31-Aug-2003 Decide to POOH while mechanic working on pump engine. Drop single shot survey and POOH. Encounter tight spot and had to rotate back up into shoe of conductor. Retrieve survey tool, shows 2 degree of inclination at 330'. RIH to 110' and standby while waiting on pump engine and shaker motor repairs. o I-Sept-2003 Standby while repairing wiring on shakers and waiting on replacement fuel pump for diesel engine on mud pump. Diverter function tested at 48 seconds to cycle valves. 02-Sept-2003 Wait on fuel injector pump, work on rebuild of mud mixing system. POOH and PU 12 Y4" bit to clean out conductor. Appears to be rocks or gravel inside yet that won't clean up. 03-Sept-2003 Replace defective breakers on mud cleaning equipment. Wait on inj ector pump for mud pump engine. Work on rig mods while waiting on mechanic. 04-Sept-2003 Mechanic on site with rebuilt injector pump. Load test pump engine while washing and reaming fill material out of conductor with 12 Y4" bit. Found obstruction at 115', drill on it and appeared to clean out in 1 foot. POOH with 12 Y4" bit assembly and pick up 8 ~" BHA to continue drilling pilot hole. Pump engine appears to still have problem with diesel in crankcase. 05-Sept-2003 Pull head on pump engine and found badly scored cylinder, decide to change out liners on (2) "GD" pumps to 4 ~" and attempt to continue drilling out 8 ~" pilot hole. W ash back in hole with 8 ~" bit to 200'. Decision made to bring in different pump until repair issues resolved. 06-Sept-2003 Wash in hole to 419', begin drilling. Drill to 450', stop to repair sand line (used for torque arm). Drill to TD at 620', CBU and Aurora Gas, LLC Page 3 of 8 il ... ) ) drop single shot survey. POOH to pick up 12 ~"hole opener assembly. Survey at 610' at 1 deg. 07 -Sept-2003 POOH with 8 12" BHA and bit. LD stabilizer and bit, PU 12 ~" hole opener and stabilizer with XO's. RIH and open to 12 ~" while load testing pump engine repair. Open hole to 189' and unable to proceed further. Appears rock may of bridged hole off and bull nose cannot re-enter hole. Make several attempts to work past obstruction. 08-Sept-2003 Continue to attempt hole opener entry. Decide to POOH and LD 12 ~"hole opener and pick up 12 ~"bit. POOH. Function test diverter, OK. Pump engine still appears to be dumping diesel into crankcase. RrH to just below conductor and work on diagnosing pump engine problem. Change oil and RIH and continue hole opener operations to 352'. 09-Sept-2003 Continue with 12 ~"hole opener operations to 620' with occasional stops made to work on diagnosing opr pump engine problems. Using GD pumps to circulate while working on other. Short trip to 246' and RIH, CBU, hole does not appear to be taking correct fluid. Again short trip to 246' and RIH, CBU, hole taking correct fluid amounts. Condition hole for running 9 5/8" surface casing. POOH and LD 12 ~" BHA components. 10-Sept-2003 RU for running 9 5/8" surface casing. Pick up shoe joint of 47# casing with buttress thread and shoe joint and float collar installed. Install stop collar and centralizer. RIH, Baker Lock next joint and install remainder of9 5/8" 36# LT&C surface casing with centralizers on first 4 joints of casing. While running casing, discovered tight spots while running joints 4, 5, 7, 8 at depth of 347'. RIH to 600', RU BJ Services and wash to bottom at 620'. Circulate and reciprocate casing. Condition mud and prepare to cement casing in place. II-Sept-2003 Circulate and reciprocate casing while RU cementers. Test lines to 2500 psi. Mix and displace 270 sks Type I "Gas Tite" cement slurry. Total volume pumped was 71.3 bbls at 100% excess. Cement was displaced into place with 41.8 bbls mud. Did not feel plug "bump" so overdisplaced 12 of shoe joint volume or 3 bbls. Observed trace of cement and cement contaminated mud returns at surface at completion of job. Drain diverter, and rinse out cement. Close annular to center casing in wellbore and WOC 12 hours. Slack off, on casing and ND diverter. Rough cut 9 5/8" casing, remove diverter and landing joint remnant. Prepare to perform top job. Aurora Gas, LLC Page 4 of 8 ) ') 12-Sept-2003 Rig up and RIH with 90' of 1" pipe to locate top of cement~ Firm cement tagged at 67'. RU cementers, flush 9 5/8" x 13 3/8" annulus with fresh water to remove mud. Batch and mix 14.7 "G" cement. Pump into place and observe pure cement at surface. Center 9 5/8" casing and evacuate cellar with vac truck. WOC. Cut and remove 13 5/8 starter head, and prep 9 5/8" casing for installation of casing head per Cameron procedure. Orient head, weld and test. OK. 13-Sept-2003 Inspect rig, mast and drill line. Service rig. Pick up 11" 3M double gate BOP. Install along with mud cross, spacer spool and 11" 3M annular. Initiate rig modifications for cold weather work by installing blow down lines. Break out remaining 12 'i4" BHA components and LD. Move gas detector to dog house. Continue with BOPE rig up and rig modifications. 14-Sept-2003 Prepare (1) GD pump for stack-out and installation ofPZ-7 replacement. Notify agencies of impending BOPE test. Finalize installation ofBOPE and choke and kill lines. Modify flowline riser, rig up test plug and prepare to test BOPE. 15-Sept-2003 RU and connect gas buster. PU and verify test plug and associated hardware is ready. Await arrival of BLM inspector. Initiate BOPE test sequence. State representation waived. BLM representative Tim Lawlor on site as witness. Problems discovered with both manual and hydraulic "Swaco Super Choke". Rig on standby while waiting on repairs. 16-Sept-2003 Rig down total 24 hours waiting parts to repair choke(s). Manual choke repaired. OK'd to pick up 8 12" BHA and RIH to 514'. Level rig and perform rig repairs while waiting on parts for Super Choke. 17-Sept-2003 Treating mud in preparation for drill out of cement at shoe. Parts to repair Super Choke arrived. All BOPE now operable. RIH and tag TOC at 556.5'. Pressure test casing above float to 1500 psi, OK. Received approval from BLM witness Tim Lawlor to proceed. Drilled cement and out of shoe to 638'. Get slow pump rates and prepare for FIT. Attempt to weight up mud system to 12.5 ppg. Hopper set-up is not working correctly at elevated mud weights. Shut down while modifying flow lines. Perform FIT to 14.5 ppg MWE at 620'. 18-Sept-2003 Operations suspended when again unable to mix mud to density required in program. Complete re-configuration and re-routing of Aurora Gas, LLC Page 5 of 8 ') suction and flow lines. Weight up and condition mud to 12.5 ppg. Proceed to commence drilling. Drill to 101 7' . 19-5ept-2003 Drill to 1138' and decide to short trip. Drop survey. RIH with slickline and retrieve SS survey tool. Survey depth 1134', Inc. .75 deg. POOH to shoe. Hole tight, rig up swivel and back ream from 1106' - 604'. Pull up to 513' and add drill co lIar. Circulate and condition mud. Wash and ream to bottom at 1138'. Drill to 1180'. 20-Sept-2003 Drill to 1381'. Hole appears to be sticky due to overbalance, drop mud weight to 12.0 ppg. Short trip to 1035'. Rill and continue drilling to 1631'. Circulate and condition hole while RU to run wireline retrievable single shot survey. 21-Sept-2003 Run survey, 1 deg inclination at survey depth of 1624'. POOH with survey instrument and continue drilling to 1755'. Circulate while performing rig service and ready for short trip. Backream out of hole to 1250'. Driller attempted to pull 3 stands without circulating and swabbed in well. Shut in well with 2.5 bbl kick. Casing pressure at 217 psi. Based on well kill calculations, weight up to 13.8 ppg to kill well. Pump 1800 strokes, open bag and monitor for flow. No flow. 22-Sept-2003 Well kill complete, RIH to 1755' breaking circulation every six joints. Circulate and condition mud, blow down choke manifold and kill lines to clean and assure ready for use. Drill to TD 2102' . ¡./ Condition mud and pump sweeps to aid in clean up of clays. Drop single shot survey. Survey at 2098', 1.0 deg. Pull survey tool and begin trip out of hole, backreaming on way out. 23-Sept-2003 Back ream out of hole to 9 5/8" shoe at 620'. Proceed to trip out remainder. Swabbed in well at 294', close in well and initiate kill sequence. Kill well with 12.3 ppg mud, shut in and monitor well. Still flowing, build mud weight to 12.5 and continue to circulate out gas. Till to 638' and pump 12.5 ppg mud around to kill well while circulating through choke. 24-Sept-2003 Continue circulation. RIH to 763' and build mud weight to 12.6 ppg and circulate around. Still evidence of gas influx in mud. Till to 1011' and circulate 12.6 ppg mud around while circulating through choke. Well still showing flow and gas influx. Raise mud weight to 13.0 ppg and circulate around. Shut in pumps and monitor well. Well static. Backream out of hole to surface. Found Spiral stabilizer balled up. Layout and prepare for BOP test. Aurora Gas, LLC Page 60f8 ) ) 25-Sept-2003 Test BOPE. Witness waived by AOGCC and BLM. Pick and prepare to RIH with bit and 8 Yí" string reamer. RIH to 2000', RU power swivel and wash and ream remainder of hole to TD at 2102'. Hole condition is excellent. Circulate and condition hole with 13 ppg mud to run eline logs. TOH, RU Schlumberger eline, calibrate logging tools and begin logging operations. 26-Sept-2003 Running eline logs. Run Platfonn Express suite, CMR log and MDT. POOH and RD Schlumberger. TIH with 8 Yí" bit to 2102'. Circulate and condition mud and prepare to run 7" production casIng. 27-Sept-2003 POOH, LD 8 Yí" BHA. Install test plug in BOP. Change out 3 Yí" pipe rams with 7" for casing. Cavity test BOP, OK. Pull test plug and RU casing crew with equipment. Run 53 joints of 23# J-55 casing to 2098'. Wash down last joint, Reciprocate casing while circulating 2 hole volumes. Initiate cementing procedure by pumping 39 bbls of 14 ppg spacer followed with 32 bbls of 13.5 ppg lead cment and 35.4 bbls of 15.5 tail cement. Dropped plug and displaced with 9.5 ppg mud. Bump plug and hold at 850 psi. Release pressure and check floats, OK, RD cementers. Had good cement returns back to surface with r-.J 25 bbls returned. Wash up BJ lines, drain and rinse out stack, flow line and shakers. WOC and center pipe with Hydril. Begin nipple down ofBOPE. Tim Lawlor with BLM on site to witness cementing. 28-Sept-2003 WOC. Slack off and pick up stack. Pull 60K tension on 7" and set slips. Rough cut 7" and set back stack. Final cut on 7", set on tubing spool, NU and install BOP, pressure test all to 2500 psi. PU 6 ~"bit and scraper. TIH, tag TOC at 2054', CBU. 29-Sept-2003 Wash and drill out cement to top of float at 2054'. CBU, and reverse circulate out mud and replace with clean brine. Clean mud pits, and make up 10 ppg brine completion fluid. POOH, LD 3 Yí" DP and BHA. Change out 3 Yí" pipe rams with 2 7/8" rams for workstring. 30-Sept-2003 Body and function test BOP after ram change-out. RU lubricator flange for top of BOP. Install and RU Schlumberger to begin perforating operations. Lubricator is not functioning properly. Attempt change out of wireline spool and packing elements, no luck. Pack off on wireline failing to hold fluid. Waiting on parts. 01-0ct-2003 Waiting on lubricator parts for Schlumberger. Parts flown in from Nikiski, install and pressure test lubricator to 400 psi. Holds fine. Ann and RIH with perforating gun #1. Shoot 1407' - 1447' in (2) " Aurora Gas, LLC Page 7 of 8 ..... 'I 02-0ct-2003 03-0ct-2003 Aurora Gas, LLC i~ ) ) runs with 4.5" guns, shooting .45" holes at 5 spf. POOH, LD, Shoot from 1343' - 1393' in (3) runs with 4.5" gun, shooting .45" holes at 5 spf. Shoot 1320' - 1330' in (1) run with 4.5" gun, shooting .45" holes at 5 spf. Circulate brine over top of hole while rigging down perforators. RD Schlumberger. PU bit and scraper. RIH to 1490'. Circulate and POOH, laying down BHA. PU completion screens and packer. Rlli and set packer hydraulically. Required 3500 psi to set. Weatherford 7" Arrow-Pak retrievable seal-bore packer set at 1245', with sand exclusion screen hung off below across open perforations. POOH with setting tool and LD. PU seal assembly, spot packer fluid in annulus stab into packer, space out and land tubing in hanger. Test 2 7/8" x 7" annulus to 2000 psi for 1 0 minutes. OK. Attempt to set BPV to rig down stack and discover vendor has wrong size BPV. Will wait until am flight for correct BPV. Will proceed with rig down of non-essential rig modules. Correct BPV on location with morning flight. Install and ND BOPE. RU production tree and pressure test to 2500 psi. Remove non-essential equipment and install swabbing lubricator and pack- off. Install flow test line and choke for flow testing. Proceed to swab in well. Swab 1 run from 200' and well flowed freely, unloading completion brine. Shut in briefly to observe wellhead pressure of 450 psi and shut down all engines and electrical equipment on rig. Open choke and let flow 1 hour at with choke at 20/64". Unloaded 5 bbls brine and perforating debris. Shut well in with flowing pressure at 450 psi. Monitor build up and prepare for quick variable rate flow test. v' Initiate flow test with SITP at 645 psi. Open well on 20/64" choke and flow 1 hour wi light to heavy mist. Stable flow with estimated flow at 1.5 MMCFPD at 570 psi FTP. Open choke to 26/64" and flow for 20 minutes with stable flow estimated at 2.4 MMCFPD with 570 psi FTP. Open choke to 32/64" and flow for 15 minutes with stable flow estimated at 3.5 MMCFPD at 535 psi FTP. Reduce choke to 20/64" and flow for 10 minutes at stable 1.6 MMCFPD and FTP of615 psi. SI well after 1 hr 45 minutes flow. 1 min SITP at 648 psi. 10 min SITP at 650 psi. 15 min SITP at 650 psi and steady. Recovered estimated 4 additional bbls brine during test. Restart generators and release rig to move to next site. Page 80f8 ) ') AURORA GAS LLC NICOLAI CREEK # 9 ..191.. [("1('3)1 EL~ ( ) IUJ,J-~-[UI ~~, "@@ (( .~~ 2-9/16" 5,000 ~~. ]@-ig1¡ Wing 2-9/16" 5,000 .E.=:5"~I~_~~~~ ·"'·· ~~[1~~?5-~~~~¡",-· Tree Ru n Þ --_.~ ~ «}:"fu @j..----- c:...~\ j,~_ t==:-~~=~~5 ,___I~~ '~,ör;·/ '...-1-- '] ~~@fõ~0.~(Ò}~§'J~ L'..I ,l~]Dl - . ~(/'''''''''(i~-~~~~ ~~((O). ~~::::::@ ,-~::.~:tt~~ ~7 A p:n I---'-~ LJJ~::rJ 7-1/16" 3,000 Þ {=~-=c~-=~!~ ~~~ f.L1(.....h.......~:1 ~:Jj ¡c- J :~:' ~r~~~; L: ~~~' ~ .." ~mi~ 1. rJ~-l~[] 2-1116"5,000 '0) _ I 1 \.. ~ì,f'j l.L.J:L=~~-c._'''~'''''_ -1Jh --LCII 11" 3 ,000 I{~-=~_:~__=:_= _oo"~'~~~1 Þ~"'~_""~.." "0' ..-." ~''''-'(}'''''' '.'. [ëúl~====~-== 11111\ .. \ ~ ( .,J= CI JlllJOfID 2-1116" LP ---==:j l~0J ~ 9-5/8" CSG Þ I I ::~:'~TBG ~Llj fØ C A MER 0 N David Shaw Anchorage Ak 04/04/02 x Proposed Final Condition 133/8" 54.5# K-55 Conductor Driven 100' 8 1/2" Pilot Hole to 620 · Hole Opened to 12 1/4" with Hole Opener 9 5/8" 36#J-55 620' MD (TVD) Shoe Joint is 47# With Buttress Thread. Packer Fluid: 02 Inhibited KCL Fluid above Pkr. 8 1/2" Hole Production Perfs 1320' -1330' @ 5 SPF Production Perfs 1343' -1393' @ 5 SPF Production Perfs 1407' - 1447' @ 5 SPF 7" 23# J-55 LTC @ 209S' MD (TVD) Cemented to Surface ) Nicolai Creek No.9 Gas Prod. Nicolai Creek Field '"$".""' I' "".' ! t~ i"n" '. ,.. :1: ¡" ,;·ji\i'í I~ !~,'!:;,} II '~:It' ¡¡I' !'.¡r¡; Nicolai Creek Unit NO.9 Fairweather E&P Services, Inc. ) iiA~jjAurora Gas,LLC 2 7/8" 6.5# J-55 8rd Production Tubing Please see attached componant tally for more detail. Weatherford WXA sliding sleeve @ 1210.27' w/2.31 ID X-Nipple profile. Upshift to open Located 1 Jt above packer 7" Arrow-Pak Seal Bore Retrievable Production Packer @ 1242.90' 3.25" BPR Extension below Packer Crossover 2.312 ID X Nipple Crossover 2 Joints and 1 pup of 3 1/2" 9.2# L-SO Srd tubing Crossover 41/2" Weatherford Strata pac Screen (4 1/2" 11.6# base pipe, 5.12" Nom OD Screen @ 16.9 ppf) Crossover (1) 3 1/2" 9.2# L-SO Srd Pup Joint Crossover 41/2" Weatherford Strata pac Screen (4 1/2" 11.6# base pipe, 5.12" Nom OD Screen @ 16.9 ppf) Crossover (2) 3 1/2" 9.2# L-SO Srd Pup Joints Crossover 41/2" Weatherford Strata pac Screen (4 1/2" 11.6# base pipe, 5.12" Nom OD Screen @ 16.9 ppf) 4 1/2" Bull Plug @ 1444' S 1/2" Hole toTD 2102' MD (TVD) PBTD at 2054' Rev. 02 DHV 03-Nov-2003 Drawing Not to Scale ') . .;,:., "_, ,': :>::'~",', . >:,,:', ~,.: yvøatOør;fQrâ~ßj)mJ>.letiõns'laòttðmcHóìe~As"seíTIbJy~S,*~ead>Slieet . ~; , :;-~~, ':,:~-:~-;7-f:~~ ;~;' ~/ ~'l~t~. ;:r~n' I, ~~1~~~"~:t:~1;~~~:rl;~t~ùfffffi'~êiJi~I[~~Nrt:óta[CtØéki"#9 ~ ~ '~i ~ ~:~i.'~ ¡ '~. TooII>escr!ption I Depth err T. Surf... L T()()I º/D ' Tool IlD L ~en\;t_h 1 e-I Item I PRODUCTION TUBING TO SURFACE 27/8 ..Á) 2.875" rY11 . ~~ j 1210.27' 2 7/8 Sliding Sleeve (2.66' L) With 2.312" "X" Protile o~o 1212.93' __'JJ L~." -_.~ · e= ) Full Joint 2 7/8" Tubing (31.7' L) r' I r="O II ¡'-. 1244.63' ____ LOCATOR SUB (1.45' L) ----. ~ t._] SEAL Extention (5.75' L) -_J) 3,25" PRODUCTION SEAL UNIT (3.05' L) Mule Shoe _/ Total Length of B.H.A.:· Please nole thai all OlD's and IID's are approximate, and are given as a guideline only 2.441" 3,625" 2.312" 2,66 2,875" 2.441" 31.70 4.625" 2.441 1.45 2.875" 2.441" 5.75 3.25" 2.375" 3.06 13,60 (Meters) I (Feet) 44.62 ) Connection Asset No. 27/8 EUE 27/8 EUE 2 7/8 EUE 27/8 EUE box Acme . Weatherford DRILLING & INTERVENTION SERVICES THRU TUBING PACKER INTERVENTION B.H.A Prepared by I Lyle Savage Date :- 1-0ct-03 , ' } ') . . ~ ' ." :"~,:':';:~~~~0~1~;,r1~~~~~~~!~~~t~~~~jN%~~!~f:ë~~,1~f~~~~·:~·~~fll.::··':· "; r CrrTuSur..... I TooIO/D Tool lID Length Depth ,,' Asset No. -. , ",.... . :1', Item Tool Description Connection 1242,9' Locator Sub and Spacer Tube 7" "ARROW-PAK SEAL BORE RETRIEVABLE 5.938" 4.000 4.73 PRODUCTION PACKER 4.00 ID SEAL BORE ~. B- - I ::::i 1247.63' Bottom Sub ~ 5,875" 2.990" 0.58 Acme 1248.21' 3,25 PBR Extension 4.125" 2.992 4.38 1252,59' Bottom Sub / Cross Over 5,625" 0,66 Acme X 2 7/8 EUE bpx 1253.25' E··j i 2 312" X nipple r~ 3.125" 0,80 2 7/8 EUE pin X Pin ,;[:~ . 1254.05' I fj I Cross Over 3,875" 2.750 0.60 27/8 EUE X 3 1/2 EUE 1254.65' 3 1/2 Full Joint E 3.5" 2,992" 3\.16 3 1/2 EUE ¡ 1285.81' 3 1/2 Full Joint 3.500 2,992" 31.20 3 1/2 EVE t \, 1317.01' 3 1/2 Pup Joint 3.500" 2.992" 4.14 3 1/2 EVE Cross Over 4.470" 3.082 0.55 3 1/2 EUE box X 4 1/2 LTC pin 1321.7' SAND SCREEN Media: 316L PMF 20/40 (125 micron) 5.120" 3.958" 3\.11 41/2LTC 4 1/2" LTC CONNECTIONS 16.9# per foot E 1352,81' Cross Over ~ 5,00" 3.082" 0,55 41/2 LTC box X 3 1/2 EVE pin 1353,36' 3 1/2 Pup Joint 3.5" 2.992" 8.14 3 1/2 EUE E ~ 1361.5' Cross Over 4,470" 3.082" 0.55 3 1/2 EUE box X 4 1/2 LTC pin 1362.05' SAND SCREEN 5,120" 3,958" 31.11 41/2 LTC Media: 316L PMF 20/40 (125 micron) 41/2" LTC CONNECTIONS 16.9 # fer foot 1393.16' 5.00" 3,082" 0,55 41/2 LTC box X 31/2 EUE pin Cross Over t I 1393.71' 3 1/2 Pup Joint 3.5" 2,992" 10,01 3 1/2 EVE 1403.72' 3 1/2 Pup Joint 3.5" 2.992" 8.08 3 1/2 EUE 1411.8' Cross Over 4.470" 3,082" 0.55 3 1/2 Eue box X 41/2 LTC pin 1412.35' SAND SCREEN 5,120" 3.958" 30.55 4 1/2 LTC Media: 316L PMF 20/40 (125 micron) 4 1/2" LTC CONNECTIONS 16,9 # per foot r- I b_ j 1442,9' .. 4 II2" BULL PLUG L_..-~ 5,000" \.10 C~ 1444' Weatherford DRILLING & INTERVENTION SERVICES THRU TUBING PACKER INTERVENTION :=JI Total Length of B,H.A. ;- 61.29 jMeters) 201.10 (Feet) B.H.A Prepared by I Date ;- Please note thai all 010'5 and lID's are approximate. and are given as a guideline only r Lyle Savage 1-0cl-03 ) ) Nicolai Creek Unit No.9 Wellbore Survey Summary Aurora Gas, LLC 4-0ct-03 While Drilling Nicolai Creek Unit No.9, surveys were obtained with a mechanical "Inclination Only" single-shot type survey tool. The following results were obtained: Depth (ft) 320 610 620 1134 1624 2101 Inclination 2 deg. 1 deg. 2 deg. .75 deg 1 deg 1 deg ) ') Nicolai Creek Unit No.9 Electric Log Summary Aurora Gas, LLC 4-0ct-03 The following logs were obtained by Schlumberger at the conclusion of drilling Nicolai Creek Unit No.9. 1. Cased hole Gamma- Surface to 800' (620' of which was recorded inside of9 5/8" surface casing). 2. Open Hole (TD - Surface casing) a) Platfonn Express wi Array Induction /MCFL, Compensated Neutron-Density, and Caliper Log b) Modular Dynamic Tester (MDT) c) Combined Magnetic Resonance Tool (CMR) 3. Cased Hole (PBTD into surface casing) a) Ultrasonic Cement and Casing Imager (US IT) wi Gamma Ray I Casing Collar locator (GR I CCL) b) Perforation / Completion Log ) Jc /~~Aurora Gas, L~ www.aurorapower.com November 4, 2003 State of Alaska Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, AK 99501 Attn: Mr. Steve Davies RE: Nicolai Creek Unit No.9, PTD #202-208 Gentlemen: This letter in duplicate originals transmits the data to you identified below, pursuant to Aurora Gas, LLC's obligation to you. This data is relative to operations at the Nicolai Creek Field, Cook Inlet, Alaska. Enclosed herewith: ~CHLUMBERGER OPEN-HOLE WELL LOGS V""f= ~EX- Array InductionlMCFL/Compensated Neutron/Density '0- r.EX- Caliper Log ~Modular Dynamic Tester ~ Combined Magnetic Resonance Tool SCHLUMBERGER CASED-HOLE LOGS 1- Ultrasonic Cement and Casing Imager w/ Gamma Ray and Casing-Collar Locator I - Completion Record JY"' Cased-Hole Gamma Ray (surface casing) SPERRY SUN MUD LOGS ~/;.;t+OO' Scale ),À"- 5"/ I 00' Scale Please signify that you have received and accepted this data by signing in the space below and returning this letter to me at the Houston address below or by fax to me at 713-977-1347. If you have questions, please contact Andy Clifford or me at the Houston number below. Sincÿ~ly , ()/ C/. )( / i ¿~ûtt(/~-::> /. Edward Jones ' /~,. l£:X:ecutive Vice Pres i den¡¡;..ingin eering and Operations RECEIVED AND ACCEPTED ABOVE DATA this (¡; Day of November, 2003. BY~\:.~\."'/~", \.C_~,--->~~~/Y\ TITLE: ,{1> l~ ~~~ '\:\~ ~\-~~ -\~ \ ~ "'-L.::> 10333 Richmond Avenue, Suite 710 · Houston, Texas 77042 · (713) 977-5799 · Fax (713) 977-1347 1029 West 3rd Avenue, Suite 220 · Anchorage, Alaska 99501 · (907) 277-1003 · Fax (907) 277-1006 FW: Aurora Gas, LLC Nicolai Creek Unit #9 \ ) 'L~O ¿ - Co ) f Subject: FW: Aurora Gas, LLC Nicolai Creek Unit #9 Date: Thu, 18 Sep 2003 10:33:27 -0800 From: duane vaagen <duane@fairweather.com> To: "Winton Aubert (winton_aubert@admin.state.ak.us)" <winton_aubert@admin.state.ak.us>, 'Tom Maunder' <tom_maunder@admin.state.ak.us> CC: 'Ed Jones' <jejones@aurorapower.com> Winton: Based on our conversation yesterday morning, the 17th of September, on behalf of Aurora Gas, LLC I would like to notify the Alaska Oil and Gas Conservation Commission of the following: We have modified the lead cement system to be used for cementing the 7" production casing on the NCU #9 well. The original plan was to use a 12.5 ppg lead system. We have decided to change the lead system density to 13.5 ppg and the spacer to 14.0 ppg to give us a margin of safety for shallow gas. We are currently drilling with a 12.5 ppg mud system. We were originally permitted to drill to 2300' MD (TVD) and after logging, set the 7" casing at 2300'. We are now considering drilling to 2500' MD (TVD) for purposes of gathering more geologic information. Ultimately the decision to drill to the full 2500' will depend on observations and samples obtained by our on-site mud loggers. In the event we do drill to 2500', it is our intent to run and set the 7" casing string at this depth as well. This would give us added rat-hole for completion equipment and allow us to land the 7" on bottom. Also, please be advised, we may reach TD by this weekend and may be logging and running casing within the next few days. Please do not hesitate to call with any questions or concerns. Thank You Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane@fairweather.com Office: (907)258-3446 Cell: (907)240-1107 As-Built NCU 9 ) ) Subject: As-Built NCU 9 Date: Thu, 3 Apr 2003 08:34:04 -0900 From: duane vaagen <duane@fairweather.com> To: 'Tom Maunder' <tom_maunder@admin.state.alcus> CC: "Steve Davies (steve_davies@admin.state.ak.us)" <steve_davies@admin.state.ak.us> Tom: As requested, attached is as-built for the NCU 9 site. We had McLane re-shoot all wells on the site last fall as there were some discrepancies in records. Please call if any questions or concerns. Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane@fairweather.com Office: (907)258-3446 Cell: (907)240-1107 ; ~nl'llml :"""\ 'WI IIU o/J I:1 ill. : IIII__II_JI'I__:_"tWfotlIIIIJmUI II:III~"\ - I-II:;I~-ff'V'AI_ .111I11111I111111:;-.111. _n"lIllIIlm1tHnlllll!IIII_ r.¡Y··\ I#'»IoIII ¡IX",~~ :111;1'" "'-I:lm¡-I. _n't'Xt. _1\1Y.1I'11I~_ lmIIIXIIII'#lo)l~I; ¡ ¡ Name: NCU 9 asbuilt.pdf ¡ ~NCU 9 aSbuilt.pdf Type: Acrobat (applicationJpdf)I '''''''''''''''''''''_'''''C'''''''''''''''''''''''''''''''''''''''''''''''''''~''''",.".".J~,!,~,?,~,~~,~,~""~,~,~~,~,~""""""""""""""",,.",,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,",,,1 Re: Well sign information ) Subject: Re: Well sign information Date: Wed, 06 Nov 2002 12:33:26 -0900 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: Jeff Osborne <josborne@fairweather.com> Jeff, The suggestion over here is to send in a copy of the as built for the wells. You can fax it and we will put the information in the files. With regard to the location for the well signs, I would use the best information you have (the new stuff) . Tom Tom Maunder wrote: > Jeff, > I will check on this matter. Things are close. There may be a need to send in > sundry notices regarding the updated surface locations. I will get back to you. > > Tom > > Jeff Osborne wrote: > > > Tom, > > Aurora Gas needs to replace a well sign for Nicolai Creek Unit #2. It has > > come to our attention, that the well data on the sign matches that on the > > approve permit to drill. > > However, when the surveyors were locating and as-builting the NCU #8 and #9 > > locations, they as-built the #1 Band #2 locations. These locations are > > different from the original data that has been used since #1 and #2 were > > originally spudded. » > > For example, > > No. 2 old coordinates are 1999' FSL, 209' FWL and > > No. 2 as-built coordinates are 2018' FSL, 205' FWL. » > > My question: what would the Commission prefer we use for location > > information on the well signs: original location data from original spud > > and permit applications, or as-built data from McLane surveyors completed in > > 2002. » > > Call me at your convenience to discuss in further detail. » > > Regards, » > > Jeff Osborne > > Project Manager > > Fairweather E&P Services, Inc. > > josborne@fairweather.com > > (907) 258-3446 office > > (907) 441-6600 mobile Tom Maunder <tom maunder@admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 of 2 ') dCB-act 11/7/20023:51 PM ..:.......~1\\~rt" ·tfjJ> , >...,-.,. " fi~¡ ¡ I\'Ù :;~;.""'¡, ¡.. 9 iF \~~B\l¿/ > ED ~ LEGEND o FOUNt> 1/2 REBAR W/IICLANE CAP . SET 1/2 REBAR W/ll~E CAP E)'fIEU. ~ ;¡ !~ ~... é~ H ~~ A I FROI.I A DA 1U1oI IS IS NOTES 1) BASIS OF COOROtNAlES IS IUSl<A STATE PLANE HAD 27 ZONE 4, AND DIRECT 'liE TO ADl NO. 3127D. 2) BASIS OF ELEVAl10N IS rROI.I DIRECT TIDAl 08S£RVATION ON 9-22-83, M.lw. AI.L ElLVAl10NS SHOYIN HEREON IlERE TMEN ON CRDUHD. 3) SECllOH LIlIES SHOWN HDlEON ARE BASED ON PRO~ACTED VALUES. 4) BEARINGS SHO'Mf HEREON ARE GRID. \ \ r_------P~LW~-----------\ I I I I I I w z S: ::; = o z!O o IX) ¡::: p U - W 0 (/) (/) ~ r o o ~ c-.~ ~~~~ ~~~i ~~~¡ s ê ~ ~ WELL #2 GRID N: 2565238.314 GRID E:241533.129 LAlJTUDE: 61'00'48.409" I LONGITUDE: -151'27'24.459" <......... " ....... ELEV. 33.2 fT. MLL7 \ 295' FWL /) 261' FWL ( 209' FWL r It I 186' F'M... r Ð- ~ ) ~. o If:! J~ I~ _----------------- I~ PAD LIMITS _----------- C~~~~~-~--- --------------------- 1999' FSL \ \ \ \ \ \ \ L_______________________ SECTION 29 TOWNSIHP 11 NORTH RANGE 12 WEST SEWARD MERIDIAN, AK / WELL #6 GRID N: 2565284.791 ,. .1.' GRID E: 241620.232 <i9- LATITUDE: 61"00'48.886" ~ LONGITUDE: -151'27'22.713" ELEV. 33.6 FT. MLLW WEll #9 GRID N: 2565248.120 GRID E: 241585.426 LATITUDE: 61 '00' 48.517" LONGITUDE: -151'27'23.402" ELEV. 32.9 FT. MLlW ~ II ,~ AIRSTRIP " ... ~.. ~ ~i ~1 h., ~.! !t~ ð "åí! ~l;! ~ ¡ã :2 i~ ÐRA'IIN BY lSC DlECI<ED 8Y pÇO HORZ. SCAI.£ 1· . 50" 'ÆRT. SÇA .[ HIA OIIM'- I/O. 02..'1102 SHEET 1 SECTJON LINE 588"44'34"E FSL 1999' FSL 204~ FSL p 2010' WELL #1 GRID N: 2565238.429 GRID E: 241509,651 LATl1UDE: 61'00'48.405" LONGITUDE: -151'27'24.935" ELEV. 32.5 fT, MLLW SECTION 29 SECTION .32 PROTRACTED SECTION CORNER GRID N: 2563243.909 GRID E: 241284.057 LATITUDE: 61"00'28.720' LONGITUDE: -151'27'28.610· ~ SECTION 30 SECTION .31 .~ .''t ~1fÆLæ CJ~ !Æl!Æ~~~ / A.',A.~1iA. OIL AND GAS I CONSERVATION COMMISSION I J. Edward Jones Vice President Aurora Gas, LLC 1029 West 3rd Avenue Ste 220 Anchorage AK 99501 TONY KNOWLES, GOVERNOR 333 W. "fTH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Nicolai Creek No.9 (replaces Nicolai Creek #8) Aurora Gas, LLC Pennit No: 202-208 Surface Location: 2012' FSL, 256' FWL, Sec. 29, T11N, R12W, SM Bottomhole Location: 2012' FSL, 256' FWL, Sec. 29, T11N, R12W, SM Dear Mr. Jones: Enclosed is the approved application for pennit to drill the above referenced development well. This pennit to drill replaces the cancelled pennit to drill for Nicolai Creek #8. Conservation Order No. 478, granted for Nicolai Creek #8, governs Nicolai Creek #9. This pennit to drill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. The pennit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. Aurora Gas, LLC assumes the liability of any protest to the spacing exception that may occur. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the tenns and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). ~ncerely, U,~~~~ C~ýi Oechsli Tay1\,; Chair BY ORDER OF THE COMMISSION DATED this21b day of November, 2002 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. ) J ~Aurora Gas, L.L.C www.aurorapower.com 30-September- 2002 Mr. Tom Maunder P.E. Senior Petroleum Engineer 333 w. ih Ave., Ste. 100 Anchorage, AK 99501 Re: Well name change, Nicolai Creek No.8 to Nicolai Creek No.9. Dear Mr. Maunder: Please find attached a new AOGCC Form 10-401 Permit to Drill application. This form is being submitted as a result of our having to move the surface location of the Nicolai Creek No.8. While driving the conductor for the Nicolai Creek No.8, refusal was reached at,...., 57', which we considered to be too shallow. The conductor was pulled and the rig moved exactly 7 feet due east. Upon inspection, it was revealed the drive shoe had collapsed, probably from a boulder. A new drive shoe was installed and the 13 3/8" conductor was driven to refusal at 99 feet. A phone call to your office indicated that because of the change in our surface location, it would be necessary to file a new PTD application and change the name of the well. Because of the minimal change in surface coordinates (7 feet), Aurora Gas wishes to work under the already approved drilling program and permit issued for the Nicolai Creek No.8, only we will now call the project well, Nicolai Creek No.9. The new surface coordinates are indicated on the attached Form 10-401 being submitted. Please find attached a plat map indicating the relationship of the NC No.9 with respect to the originally proposed NC No.8 and other wells already on the site. Well No.6 is P&A'd. Please do not hesitate to call the undersigned at (713) 977-5799, or Duane Vaagen at 258-3446 with any questions or concerns. Sincerely; J. Edward Jones Executive Vice President Aurora Gas, LLC Attachments: cc: Duane Vaagen (Fairweather E&P Service, Inc.) RECEIVED OCT 0 4 2002 A1aska 00& Gas Cons. comm\sS'on Anchorage 10333 Richmond Avenue, Suite 710 · Houston, Texas 77042· (713) 977-5799 · Fax (713) 977-1347 1029 West 3rd Avenue, Suite 220· Anchoragè,(Ala~(c~r99501 · (907) 277-1003 · Fax (907) 277-1006 , ", ¡ ì" Weight 54.5 36 23# STATE OF ALASKA ..~ ALASKA __1 AND GAS CONSERVATION COMr\/I. ~ .~ION PERMIT TO DRILL 20 MC 25.005 [ ] Redrill11 b. Type of well [ ] Service [X] Development Gas [ ] Single Zone [ ] Deepen [ ] Exploratory [ ] Stratigraphic Test [ ] Development Oil Aurora Gas LLC. 5. Datum Elevation (OF or KB) 10. Field and Pool 36' AMSL (OF) Nicolai Creek Gas Field 6. Property Designation AA-S426 7, Unit or Property Name Nicolai Creek Gas Field 8, Well Number Nicolai Creek No.9 9. Approximate spud date 14-Sep-02 14, Number of acres in property 15. Proposed depth (MD and TVD) 1738 Acres 2500' MD & TVD 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} Maximum sulface 1025 psig , At total depth (TVO) Setting Depth Top Bottom MD TVD MD TVD o 0 -80' -80' o 0 620' 620' o 0 2300' 2300' h\(J/1 1a. Type of work [X] Drill [ ] Re-Entry 2. Name of Operator [ X] Multiple Zone Resolution Plaza Suite 710 Anchorage, Alaska 99501 4. Location of well at surface 2012' FSL, 256' FWL, Sec 29, T11 N, R12W SM ASPX 241580.094, ASPY 2565250.279 At top of productive interval 2012' FSL, 256' FWL, Sec 29, T11 N, R12W SM 3. Address 11. Type Bond (See 20 AAC 25.025) Letter of Credit Number NZS 429815 At total depth 2012' FSL, 256' FWL, Sec 29, T11N, R12W SM Amount $200,000 12. Distance to nearest property line -100' 16. To be completed for deviated wells Kick Off Depth N/A 18. Casing Program Size Casing 13 3/S" 9 5/S" 7" 113. Distance to nearest well -48' Maximum Hole Angle 1100 psig Hole Driven 121/4" 8 1/2" Specifications Grade Coupling K-55 Welded K-55 LTC J-55 LTC Length -80'+ 622' 2302' Quantity of Cement (include stage data) No cement, driven 74 Bbls (415 ft3) 44 Bbls (247 ft3) 19. To be completed for Redrill, Re-entry, and Deepen Operations, Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical feet feet feet feet Plugs (measured) Junk (measured) Casing Length Size Cemented MD TVD Structural Conductor Surface Intermediate Production Liner Perforation depth: measured true vertical RIE:IIVeD OCT 0 4 2002 AlasIàl 01& au Cons. Gommissiorl Anchorage 20. Attachments [ X] Filing Fee [ X] Property Plat [ X] BOP Sketch [ X] Diverter Sketch [ X] Drilling Program [X] Drilling Fluid Program [ ] Time vs Depth Plot [] Refraction Analysis [ ] Seabed Report [ ] 20MC25.050 Req. . Edward Jones (907)277-1003 Prepared By Name/Number: Duane H. Vaagen (907)258-3446 correct to the best of my knowledge Title 0è¿.. f?~.r/~"J- Commission Use Only Date ~30/oz- PermitN 2/.>2-269> IAP~ m~?B.:~-2D/02. - Có 1r.t}o/),rl ~~:~:;e~~~~:ments Conditions of Approval: Samples Required: [ ] Yes K1 No ¿u?l~ Required Þ<J'Yes [ ] No Hydrogen Sulfide Measures: [ ] Yes rx No Directional Survey Req'd ~es [ ] No Required Working Pressure for BOPE: [] 2M, [] 3M, [] 5M, [] 10M, [] 15M Other: ~SCXJ Q~\ ~ ~-\ ~~S ") ~ ~~?JYf OrIginal Signed By by order of Cammy Oechsli Taylor Commissioner the commission Da~fØJ~ Approved By Form 10-401 Rev. 12-01-85 ~.:-....~'\\~., ('~ð ""t. .. ~..:-- '..,<\"~,,,, Ii ~ W LEGEND o FCMIO 1/2 IGAA W¡\ICUNE eN' . ~ 1/211E11AA WþlCl.ME eN' ell!LL ..,. ~ j i '1; 1 I ; ¡ " 19 NOTES I) BASIS OF COORØIH"1ES IS ALASKA STAtE IVJ« MAD 27 ZOM£ 4, NiO IS rIION ~ 1If: to #Ø. Ho. 31210. 2) BASIS OF EIE#I'11OH 1$ FRON DIRECT 110AL OBSERVATION ON t-22-93. OAN" w.w. AU. ELEVATIONS SHO'Mt H!MON wE:M: TAKOC ON ~. 3} S£CtION IJNES SHQWI HEREON m 8ASm ON PROtllAC'ÆD V.a.LUß 4) BEAft 4QS !IIIOWH HERtOM AM QRIO, --------- '-'/~ PAD LÎMITÇ---------' / ' / \ / \ / \ / \ \ \ Lù :g~ ...J 0 Õ~ F,P U .... W 0 V> V> r- ¡ i C\II~ ~- ~~~ ~ Ii ~li1 @ I!I ~ WEll H2 GRID N: 2565238.314 GRID E: 2'¡'15~;;.129 LATITUDE: 61'00'48.409- LONG/WOE: -151"27'24,459- " " " ElEV. 33.2 FT. MLLl \ 295' FWL ) ,Zs:-,'AJl- - / 249' FWl ( 209' FWL - ~ I j \ 186' FWI... · 8- é-- ~. o 1{!2 I~ I~ ---------------- 1;;< PAD LlMlí?._ -- - - - - -- -- - - -- ~- ---- - ------- ..,--- C::-------- -------- '< 1999' FSL \ \ \ \ \ ~----------------------- SEC1l0N 29 TOWNstHP 11 NORTH RANGE 12 VÆ:ST SEWARD MERtÐ~ANt AK AIRSTRIP \ \ / WELL Ií6 GRID N: 2565284.791 , 1-' GRID E: U1620.232 Cð)-- LATITUDE: ß1"OO' 48.886" .. \. LONGITUDE: -151"27'22.713H I \ ELEV. 33.6 FT. MlLW è- ~ --- (Mr." ~ ~ ~\ PROPOSEO WELL ft8 GRID N: 2565250.219 GR1D E: 241573.094 I LATITUDE: 61'00'48.536" , LONGITUDE: -151'27'23.653- £lEV. 32.9 FT. MLI.W I !... . .... " .. . ;< OJ2' F SL ! ~ if "I ~~- ~ ... \ok 2012' 1999' FSL 20-8' FSL " , If . 1 ,. FSL WELL II GRIO N: 2565238."-29 GRID E: 241509,651 LAl1TUDE: 61'00'48.405- LONGITUDE: -151'27'24.935" ELEV. 32.5 FT. MLLW ~ - CIIIIJÞD'" /'CO -. JC.4U" . f1(/ vørr. tcAU: 14/" ~ 1IOo1ItI3I0t IHeeT 1 SECTION LINE S8S'44',34"E SECTION 29 SECTION 32 PROTRACTED SECTION CORNER GRID N: 2563243.909 GRID E: 241284.057 LA TlTUDE: 61 "00'28. 720" LONGITUOE: -151"27'28.610" SECTION 30 SECTION 31 ), ~Aurora Gas, LL.t www.aurorapower.com ~Auro'a Gas, LLC September 4, 2002 Mr. Tom Maunder PE Senior Drilling Engineer Alaska Oil and Gas Conservation Commission 333 W. ih Ave. Ste 100 Anchorage, Alaska 99501 RE: End of well reporting and documentation: Nicolai Creek Unit #9 Dear Mr. Maunder, Aurora Gas, LLC hereby submits the final well report, which covers both the drilling and completion of Nicolai Creek Unit No.9. Operations were completed on October 3rd, 2003. Pertinent information included under cover of this letter includes the following: 1) Form 10-407 "Well Completion Report and Log" - 3 copies. 2) Summary of well operations. 3) Wellbore schematic depicting final well completion configuration. Copies of electrical well logs, mud-logging reports and any future well testing results will be submitted under separate cover. If you have any questions or require additional information, please contact the undersigned at (907) 277-1003, or Duane Vaagen at (907) 258-3446. Sincerely, /.·3/- ~~.~ .. / ¡ {J. Edward. Jones {.r/' Executive Vice President, Engineering & Operations Aurora Gas, LLC Att: cc: Duane Vaagen Andy Clifford 10333 Richmond Avenue, Suite 710 · Houston, Texas 77042 · (713) 977-5799 · Fax (713) 977-1347 1029 West 3rd Avenue, Suite 220 · Anchorage, Alaska 99501 · (907) 277-1003 · Fax (907) 277-1006 f"-~~ ~.. c~.PAYTOTHE¡\ ... . ~...···..OR·DER OF··· ·.·.··.·.··.R..O.·.Qro.···O_(b ¿\J~ ~<Y"\~~ò.~'- ?; -~ 10128 10 ,.2"09. I $/OO!! --------------ObLLARS ~ ~¡, W "'to>. '::o~ , -- MEMO~~\\ t\}\~\@ Q)\9J;.~ t-J(J q ~~,I_~~ III 0 ~ 0 ~ 2 a III _: ~ 2 5 2000 5 ? -: ? :1 2 ~ 5 b 2 5 j Sill .-......-..--.~. ~ -.---- .~- -----.-..-, .-- . -~.- -- ...- --- -.- - - -..-.. ...- ~ - ~ _. -'~-'- -. ~ .~ ') ) ,I TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERlPARAGRAPHS TO BE INCLUDED IN T~MI~TAL LETTER . WELL NAME ,;(;c.o~ C-u.£ ¿,¡-- PTD# 2/'7 ~ó8 CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API num ber last two (2) digits are between 60-69) ¢Fe¡ "CLUE" The permit is for a new wellbore segment of existing well Permit No, API No. Production should continue to be reported as a function' of the original API number, stated above. HOLE In accordance with 20 AAC 25.005(t), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 70/80) from records, data and logs acquired for well (name on permit). paOT (PH) SPACING EXCEPTION v DRY DITCH SAMPLE Rev: 07110/02 C\jody\templates The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issu~nce of a conse~ation ordeyapproving a spacing exception. ?lv-.r~ (Company Name) assumes the liability of any protest t~o the spa9n~~. exc tion ~at ~);, occur. ~c. /Y¿:l1' 'FF?[ t4v L!C;> V~ ~ All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. ~~ ~I ~4~ NCU"1\ (~~ /Í¿~ 7'/' ~ ~ t-V-Úl). ~X- . WEL.LPERMITCHECKLIST COMPANY AURORA FIELD & POOL 560500 - Nicolai Creek, Undefined ADMINISTRATION APPR DATE SFD 10/4/2002 (For Service Well Only) (For Service Well Only) ENGINEERING APPR DATE TEM 10/7/2002 þr~+vJt ,°1 ~ (For Service Well Only) WELL NAME NICOLAI CREEK UNIT #9 Initial ClasslType DEV /1-GAS PROGRAM Exploritory (EXP)_Development (DEV) ~ Redril ~ervice (SER) _Well bore seg _ Annular disposal para req GEOL AREA 820 UNIT No. 51430 ON/OFF SHORE On 1. Permit fee attached.................. ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... .. 2. Lease number appropriate... ... ... ... ... ... ... ... ... ... ... ... ... ... ... '" ... ... ... ... ... ... ... ,.. ... ... ... ... . 3. Unique well name and number .................. ...... ... ... ... ... ...... ......... ...... ... ............ ... .... 4. Well located in a defined pool.................................................................,..,............ 5. Well located proper distance from drilling unit boundary ... ... ... ... ... ... ... ... ... ... ... ... ... ... ..... 6. Well located proper distance from other wells... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... 7. Sufficient acreage available in drilling unit.................................................................. 8. If deviated, is wellbore plat included ......................................................................... 9. Operator only affected party .................................................................................... 10. Operator has appropriate bond in force ... .,. ... ... ... ... ... ... ... ... ... ... ... ... ... ... .,. ... ... ... ... .... 11. Permit can be issued without conservation order......... ... ............... ... ... ... ...... ... ...... .... 12. Permit can be issued without administrative approval....................... ..... .................... 13 Can perm it be approved before 15-day wait ......... ......... ...... ...... ... ...... ... ... ... .. .... ....... 14 Well located within area and strata authorized by Injection Order # 15 All wells witthin 1/4 mile area of review identified ....................................................... 16 ACMP Finding of Consistency has been issued for this project... ...... ............ ...... ...... ... 17 Conductor string provided..................................................................................... 18 Surface casing protects all known USDWs ............................................................... 19 CMT vol adequate to circulate on conductor & surf csg ... ... ... ... ... ... ... ... ... ... ... ... ... ... .... 20 CMT vol adequate to tie-in long string to surf csg ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... .,. ... ... 21 CMT will cover all known productive horizons... ... ... ... ... ... ... ... ... ... ... ... ...... ... ... ...... ... .. 22 Casing designs adequate for C, T, B & permafrost......... ......... ...... ... ... ...... ... ...... ... .... 23 Adequate tankage or reserve pit ... ... ... ... ... ... ... ... ... ... .,. ... ... ... ... ... ... ... ... ... ... ... ... ... .... 24 If a re-drill, has a 10-403 for abandonment been approved .......................................... 25 Adequate wellbore separation proposed ... ... ... ... '" ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... 26 If diverter required" does it meet regulations... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... . 27 Drilling fluid program schematic & equip list adequate...... ...... ... ... ... ... ...... ...... ...... ... ... 28 BOPEs, do they meet regulation ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... ... .... 29 BOPE press rating appropriate; test to ..................... 2500 psig ........................... 30 Choke manifold complies w/API RP-53 (May 84) ...................................................... 31 Work will occur without operation shutdown... ............ ... ...... ......... ...... ...... ...... ...... ... . 32 Is presence of H2S gas probable...... ... ... ... ...... ...... ...... ... ...... ...... ... ...... ... ...... ... ...... 33 Mechanical condition of wells within AOR verified ... ... ...... .................. ... ...... ... ... ... ...... GEOLOGY 34 Permit can be issued w/o hydrogen sulfide measures ................................................ 35 Data presented on potential overpressure zones......... ...... ...... ... ......... ...... ...... ......... . APP~ DATE ~6~eismic analysis of shallow gas zones .................................................................... lb· -Z.O ~ Seabed condition survey (if off-shore) ..................................................................... SF 10/4/2002 38 Contact name/phone for weekly progress reports{exp/oratory only] ........................... COMMISSION: RPC: GEOLOGY: ENGINERING: RES. ENGINERING: TEM: TEM JDH: COT: DTS: /(I! y Ie: 2- ,;M-J..-/& /I? /.Y p;/ p Z-- SFD: SFD WGA: MJW: Yes Yes Yes No No No No Yes Yes No Yes No Yes Yes Yes Yes Yes Yes Yes Yes NA Yes Yes Yes Yes Yes Yes Yes No NA Yes Yes Yes # 10128 FEDERAL LEASE AA-8426 ~~~~~! .well t~!9~ti~9.. ~~ .l!nd~~~~d p~ol_~i~~i~.t~.~. þc:>~~~.;?~~ti~~ _ _ ..;;> __._ _ r . _ . '-r r-' _ _ _ _ '" .. _ _ .. _ __ _ _ _ _ _ _ ._ _ ._._ __ _ \ _ __ Comments). SPACING EXCEPTION REQUIRED «3000' from 2 other gas wells); Spacing exception approved for NCU #8 in CO 478 on 9/5/2002. Third gas well in Sec. 29, T11 N, R12W, SM. Spacing exception approved for NCU #8 in CO 478 on 9/5/2002. Not Applicable: vertical well. Letter of Credit NZS 429815 SPACING EXCEPTION REQUIRED; Spacing exception approved for NCU #8 in CO 478 on 9/5/2002. Not Applicable Not Applicable 8/5/2002: Matt Rader of DNR states Nicolai Creek project is consistent. ~r ~ No recorded domestic water supply wells within 5 mi of the proposed well. Closest known water well is a 120-foot deep utility water well located at NCU #3, about 3,230 feet from NCU #9. Surface and production casing cemented to surface will protect any potential USDWs. Rig pits are small, however the planned hole sections have similar volumes to the #1 B. All waste will be held in tanks and hauled to disposal. No excavated reserve pits are planned. Well spacing is close at surface. Interferance will be assessed and gyros run if necessary. Aurora has requested to drill 12.25" hole with a 10" diverter line. A shallow gas event was experienced drilling the NCU 1. Waiver is NOT recommended. . .J Shallow hazards analysis & drilling program address shallow gas as known hazard throughout area. Mudlog required to mitigate risk. Not Applicable Not Applicable J. Edward Jones, 907-277-1003 Comments/Instructions This well replaces NCU #8, located 7' to the west, which could not get conductor driven to 80' MD (refusal point was -57' MD, likely due to a boulder), NCU #9 will utilize drilling and logging programs approved for NCU #8. Well will be mud logged from conductor to TD (NCU #8 drilling program, item 3). Well will be logged from surface casing shoe to TD with PEX-AITH (induction, SP, GR, CNL, FDC, and GR-Sonic) and FMI. Samples not required due to cutting samples recovered from adjacent wells NCU #1, #2, and #6. Mudlog required due to likely shallow gas associated with shallow coals seams, especially coal seam at -750' MD. Directional Survey required due to close proximity of other wells and a property line. Spacing exception approved for NCU #8 in CO 478 on 9·5·2002. SFD
