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Home My WebLink About166-038By 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 y,\\11/y�_s� THE STATE Alaska Oil and Gas 4 ofConservation Commission ALesK ��.�,#��-- 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 oFALAS�P Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Manager SCANNED JUL 2 6 2017, Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Nicolai Creek Field, S. Beluga and Undefined Upper Tyonek Gas Pool,Nicolai Creek 2 Permit to Drill Number: 166-038 Sundry Number: 317-277 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, sLGX Hollis S. French Chair DATED this day of July, 2017. RBDMS L JUL 1 1 2017 II • RECEIVED STATE OF ALASKA JUN 1 6 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ,A0GOG 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Repair Wen D Operations shutdown El Suspend D Perforate 111 Other Stimulate D Pull TubMg 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing D Other.Temporary Plug 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number Aurora Gas,LLC Exploratory Li Development E 166-038 3.Address: 1400 W.Benson Blvd.Suite 410 111 0 6.API Number Stratigraphic Service Anchorage,AK 99503 50-283-10021-00 - 7.If perforating: 8.Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? AJA- Nicolai Creek#2 Will planned perforations require a spacing exception? Yes [] No [f flii, 9.Property Designation(Lease Number): 10.Field/Pool(s): I), ryco6K ADL 17585 3 cwi 7) 9/16 Nicolai Creek South Beluga and Undefinedeas 11. ) PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Eft MD: Effective Depth ND: MPSP(psi): Plugs(MD): Junk(MD): 5011' 4102' 945e q 2992' 380 psi 3185 None Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 30"LP 80' 80' N/A N/A Surface 286' 20"94*H40 286' 286' 1530 psi 520 psi Intermediate 1934' 13 3/8"54.5* U55 1934' 1762' 2730 psi 1130 psi Production 3545' 7"26"N80 3545' 2992' 7240 psi 5410 psi Liner Perforation Depth MD(ft): 'Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 2198'-3336' •• 2003'-2816' 2 7/8" 6.5*J-55 3277' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ftt Hydraulic and Arrowset packers Hydraulic ci? 2176',2336'&2776'and Arrowset t 3185' 12.Attachments: Proposal Summary n Wellbore schematic ri 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch D Exploratory 0 Stratigraphic 0 Development D ' Service 0 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: OIL D WINJ D WDSPL D Suspended El 16.Verbal Approval: Date: GAS Ej .1 WAG 0 GSTOR 0 SPLUG 0 Commission Representative: GINJ 0 Op Shutdown Ei Abandoned n 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. George Pollock George Pollock Authorized Name: Contact Name: Authorized Title: Manager-:of:0.1t"ng Contact Email: g pot lock( .au rorapowe r.corn Contact Phone: 907-277-1003 Authorized Signature: -- - Date: 16-Jun-17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number 3 1 7-27 1" Plug Integrity III BOP Test Eil Mechanical Integrity Test D Location Clearance D Other: t C1-4-PDV1/417-N-1. FLAxto tt,`'-%---7‘ V")VI- MeE-C izzu.,A%rce-me-t4u 047-"ez. 4%x; DR- Post Initial Injection MIT Req'd? Yes 0 No ED RBDMS (4.1 1 1 2017 Spacing Exception Required? Yes 0 No l'ii Subsequent Form Required: \k) .....4 04_ L APPROVED BY Approved by: ( COMMISSIONER THE COMMISSION Date: -* I t.1 z? A 9,K 71s-li?-,e ((itic I m AL ,,,,-.., --1(-, i,-, Al Subrnit Form and Form 10-403 Revised 4/2017 op imi is valid for 12 months from the date of approval. Attachments in Duplicate Al • Aurora Gas, LLC June 16, 2017 Ms. Cathy Foerster, Chair RECEIVED Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 JUN 16 2011 Anchorage, AK 99501 AOGOC Re: Application for Sundry Approval—Set Temporary Plug Nicolai Creek#2 Well PTD#: 166-038 API #: 50-283-10021-00 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 and Undefined Gas Fields 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 and upper Tyonek sands and is mechanically sound. Aurora Gas is currently in Chapter 11 bankruptcy protection while attempting to reorganize and emerge with new owners/investors. This application is being submitted as part of our Reorganization Plan filed with the bankruptcy court if liquidation actions are ordered. Aurora Gas, LLC will provide all potential new investors/owners 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 1,448' above all open perforated intervals to mechanically isolate the reservoir. After the plug is set, tubing pressure will be monitored for 30 minutes to ensure isolation. The master valve will be closed providing double isolation and the wellhead secured. A follow up pressure reading will be obtained after 24 hours to ensure the integrity of the plug. Please find the attached information as required by 20 AAC 25.110 for your review: • Form 10-403 Sundry Application • Current wellbore diagram illustrating the current well configuration. • Slickline Temporary Plug Set—Generalized Procedure If you have any questions or require any further information,please contact me at(907) 277-1003. Sincerel George Pollock Manager—Production Operations & Engineering 4645 Sweetwater Boulevard, Suite 200 * Sugarland,TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 * Anchorage, AK 99503 * (907) 277-1003 • Aurora Gas, LLC 30"Conductor set at 80'in , , 4* l, 5' ."' V" ,,'' 36"hole,cemented w/300 sx NICOLAI CREEK , •. ' UNIT#2 PTD#: 168-038 ' " .. b 20"94#Surface Casing set at API#:50-283-10021-00-00 *' '' Y ' 286'in 26"hole,cemented w/ DF 23.7 ft - __ 650 sx (As Run October 2013) I u' 1991 * � Sqz Perfs at 298'-sgzd w/ Jan 2015 PWL status �' 200 sx in 1991 and 218 sx in * .- . 2013 4-1/2"12.6#L-80 Liner run -- •-' *p'M 1991 Sqz Perfs at 677'—sqzd between 2 Permanent Isolation v . w/215 sx in 1991 Packers set at 267'and 726'w/ ;' , t . 13-3/8"54.5#Surface Casing tie back sleeve at 262'and seal set at 1934'.Cement w/1600 sx bore on btm pkr& 10'Seal * Assembly at 726-736'. • 2 7/8 6.5#8rd EUE J-55 Tubing '- 2313 XA Sliding sleeve at 1448' Beluga ;,y ' 2198-2212' -- Hydraulic Packer at 2176'w/ On-off Tool w/ 2312" 2244-2260' ` ,'' X profile at 2176' Carya 2-1.0 :1'4 , I. 2.313X0 Sliding sleeve at 2312-2322' , 2258'(Shrouded)(Open) .* ".*114.10.1111g', AAA Hydraulic Set Packer @ 2336' Carya 2-1.1 2426-2476' IIII 'I, 2313 XO Sliding Sleeve at 2573' Carya 2-1.2 .. (Open) EXISTING PERFS --�°'4 4 2700-2716' y Hydraulic Packer set at 2776' Carya 2-2.1 k►t. New 2870-76' pp 2313 XO Sliding Sleeve at 2917'(Open) 2893-2916' +r ' N4 2.313 X Nipple at 3178' Arrowset IX Packer at 3185' F *`- PX Plug set in profile Original Perfs:Carya 2-23 .' * 3270-3315' Cemented over with 87 sx Bal Plug New perfs: Carya 2-2.3 3268-3288' 34/2"Sand Control Screens at 3230-60' -"�""'� 474-1:i*:: ;� 2313"X profile at 3267' 3324-3336' Bull Plug/EOT @ 3277' PBTD @3450'MD 7"26#J-55 Casing to 3545'MD cemented wI 1500 sx Drill 9-7/8"Hole to 5011' A iii: MD/4102'TVD • 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. 41e Saua9e(6/11/2017) Auraora Gas,LLC �" www.aurorapower.com Z-3 6 Z-7 DATA LOGGED / 2-1/2013 M K BENDER RECEIVED November 19, 2013 NOV 2 0 2013 Makana Bender �®G�� Natural Resource Technician Alaska Oil and Gas Conservation Commission 333 W. 7h Ave., Suite 100 Anchorage, Alaska 99501 RE: Well Data Submittal, Nicolai Creek No. 2 Aurora Gas, LLC has included in this package the following documents and electronic files for Alaska Oil and Gas Conservation Commission for the Aurora Gas LLC Nicolai Creek #2 Well, API# 50-283-10021-00-00. Please keep this information contained here -in "CONFIDENTIAL" for 2 -years. ■ AOGCC Form 10-404 Report of Sundry Well Operations w/ Daily Operations Report and As -Run Well -bore Diagram ■ Paper Logs (Confidential 2 -years) 1) Schlumberger Ultrasonic Imaging Tool Gamma Ray Casing Collar Locator 2) Perforating Record 3.5" Power Jet Omega 3) Packer Setting Record Junk Basket / 6.05" Gauge Ring ■ Electronic Documentation (Confidential 2 -years) 4) Schlumberger Digital Wireline Logs If you have any questions or require additional information, please contact me at (281) 495- 9957. Sincerely, AURORA GAS, LLC Edward Jones President enclosures HFp OCT 03 2014 1400 West Benson Blvd., Suite 410 . Anchorage, AK 99503 • (907) 277-1003 • Fax: (907) 277-1006 6051 North Course Drive, Suite 200 . Houston, TX 77072 . (713) 977-5799 • Fax: (713) 977-1347 ` STATE OF ALASKA ALA_ .OIL AND GAS CONSERVATION COMM.--ION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Repair Well H Plug Perforations U Perforate U Other H Cement Squeeze Performed: Alter Casing ❑ Pull Tubing El Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Flow Test Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator Aurora Gas,LLC 4.Well Class Before Work: 5.Permit to Drill Number: Name: Development El Exploratory ❑ 166-038 • 3.Address: 1400 W.Benson Blvd.,Suite 410 Anchorage, Stratigraphic❑ Service ❑ 6.API Number: RECEIVED AK 99503 50-283-10021-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: NOV 2 0 2013 ADL-17585,-391471 ' Nicolai Creek#2 ' 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): AOGC Schlumberger USIT Corrosion,USIT Cement,and Perforating Record Nicolai Creek Unit/South Undefined Gas ¢-��,J�f 11.Present Well Condition Summary: Total Depth measured 5011 feet Plugs measured 3450 feet true vertical 4102 feet Junk measured none feet Effective Depth measured 3450 feet Packer measured see attached feet true vertical 2918 feet true vertical see attached feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 30" 80' 80' Surface 286' 20" 286' 286' 520 psi 1530 psi Intermediate 1934' 13-3/8" 1934' 1762' 1130 psi 2730 psi Production 3545' 7" 3545 2992 5410 psi 7240 psi Liner 449' 4-1/2" 272-721' 272-712' 8430 psi 7500 psi Perforation depth Measured depth see attached feet True Vertical depth see attached feet MC� FA. w1 S Tubing(size,grade,measured and true vertical depth) 2 7/8" J-55 3277' 2930' Packers and SSSV(type,measured and true vertical depth) see attached packer info (no SSSV) 12.Stimulation or cement squeeze summary: Intervals treated(measured): Cement squeezed old perfs at 298'3X. Treatment descriptions including volumes used and final pressure: Cemented w/22.5 bbl(109 sx)Class G cement 2X and with 6.5 bbl 1 (31 sx)for total of 249 sx. Final pressure of last squeeze was 2000 psi. 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 14 0 70 79 Subsequent to operation: 169 0 '60 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run attached Exploratory❑ Development p Service ❑ Stratigraphic ❑ Daily Report of Well Operations attached 16.Well Status after work: Oil ❑ Gas ID • WDSPL❑ Well bore diagran attached GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 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: 313-475 Contact Ed Jones Email lejones( aurorapower corn Printed Name J.Edward J. -s Title President Signature , x — Phone 281-491-9957 Date 11/7/2013 Form 1 4 Revised 10/2012 j/ Z g it/ Submit Original Only . RB!Ms NOV 2 000 Aurora Gas, LLC Nicolai Creek#2 Recompletion Workover 2013 AOGCCC 10-404 Sundry Report (313-475) Perforations (new): U. Tyonek Carya 2-2.3: 3268-88', 3324-36' MD (2780-2831' TVD) U. Tyonek Carya 2-2.1: 2870-76' MD (2475-80' TVD) U. Tyonek Carya 2-1.0 2312-2311' MD (2043-50' TVD) L. Beluga Tsuga 2-8: 2198-2212', 2244-60' MD(1962-2004' TVD) Perforations (prior left intact): U. Tyonek Carya 2-2.1: 2893-2916' MD (2493-2511' TVD) U. Tyonek Carya 2-1.2: 2700-16' MD (2342-2356' TVD) U. Tyonek Carya 2-1.1: 2426 -2476' MD (2141-2177' TVD) Packers: Arrowset 1-X Mechanical Packer at 3185' MD (2714' TVD) FH Hydraulic Packer at 2776' MD (2391' TVD) FH Hydraulic Packer at 2336' MD (2061' TVD) FH Hydraulic Packer at 2176' MD (1943' TVD) 7"X 4"Permanent Isolation Packer 721' MD (711' TVD) 7"X 4"Permanent Isolation Packer 267' MD (267' TVD) AURORA GAS, LLC NICOLAI CREEK NO. 2 AOGCC SUNDRY No. 313-475 (API No. 50-283-10021-00) RECOMPLETION WORKOVER OPERATIONS SUMMARY 9/11/13—Level pad. Set rig containment liner and rig mats on liner. 9/12/13—MI and RU AWS #1 rig. 9/13/13—Continue MI and RU AWS #1. Raise derrick. 9/14/13—Continue RU AWS #1. Berm containment around rig. Mix brine. 9/15/13—Finish RU, including gas detectors—test. Pump 20 bbl 8.4 ppg KC1 water down tubing. Set BPV. ND tree.NU BOP's. 9/16/13—Fin NU BOP's. Test BOP's. Pull BPV. Release tubing hanger and pull seal assembly from seal bore packer. Circ out 9.6 ppg brine packer fluid—losing 20 BPH. Monitor well—l5- 20 BPH losses. 9/17/13—Run dump bailer on slick line and dump 20 gal cement from 2400-2370'. POH with 35 stds+ 1 jt 2-7/8"tubing. LD seal assembly. Change rams to 4"and test. PU Packer Plucker and circ sub. RIH on 4"DP,picking up DP. 9/18/13—RIH picking up 4"DP. Build volume of KC1 water. Latch onto seal-bore packer and work free. Drop ball, open circ sub. POH with packer,mill-out extension,tubing spacer, and screens. LD packer, extension, spacers and screens. Daily losses: 30 bbl/total losses: 220 bbl. 9/19/13—Set wear ring. RIH with bit on 6–4-3/4"DC's on 4"DP to 2426'. Bit plugged. POH,unplug bit. RIM, cleaning cement from DP pump 20 bbl brine,pressure to 500 psi, broke back to 35 psi, with returns after 18 bbl. POH, LD DP and DC's. Pick up different joints of DP, RIH, checking for cement and plugging(from plugging and abandonment of NCU 13). Daily losses: 42 bbl/Total losses: 262 bbl. 9/20/13—RIH, cleaning DP to 2949'. Pump 20 bbl Baraplug(graded salt LCM)pill. Pull 10 stds and allow to soak. POH. PU 6-1/4"bit, 6 DC's, and RIM on DP. Tag at 2998'. Wash to 3095'—hard cement. Drill cement 3095-3233'—bit plugged—work w/o success. POH. 0 losses. 9/21/13—Fin POH w/plugged bit. Unplug bit. RIH to 3233',washing last jt to bottom. Drill cement 3233 to 3450'. Circ hole clean. Clean pits. Pump Baraplug pill. Build 9.3 ppg brine and displace hole with same. Filter brine. 0 losses. 9/22/13—Filter brine to 10 microns. P011, LD DP and DC's. ND flow nipple and install shooting flange and Schlumberger lubricator. PU GR/CCL tool and RIH to 3450'. Run correlation log to 2750'—correlate to old electric log-2' correction. PU perf gun#1, RIH and perforate 3321-31' w/6 SPF. 3.3 bbl to fill hole. POH,run gun#2 and perforate 3265-85'. 1.2 bbl loss. PU gun#3. Daily losses: 5 bbl/Total 267 bbl. 9/23/13 RIH w/gun#3, correlate, and perforate 2870-76'. POH--2.2 bbl to fill hole. PU and run gun#4,perforate 2310-20',no losses. Run gun#5 and perforate 2244-60', 2.1 bbl to fill hole. Run gun#6 and perforate 2198-2216', 0.6 bbl to fill. RD Schlumberger. RD shooting flange and RU flow nipple. Change rams, and prep for BOP test. Well started flowing. SI well—SIP built to 350 psi. Build 9.5 ppg brine and monitor well. Build 20 bbl Baraplug LCM pill and 90 bbl brine. Bullhead in—final pump-in pressure-500 psi. Mix 25 bbl Baraplug pill with Baracarb(CaCO)and bullhead in with 60 bbl 9.4 ppg brine—pressure to 650 then to 330 psi. Bled pressure to 200 psi. Pump 20 bbl brine,bled back 20 bbl w/some gas. Pump 10 bbl brine, bled 10 bbl back. SIP-490 psi. 9/24/13—SI and monitor well. Discover water flow/vent near rig (30'). SI NCU#11 flowline to i check for leak—no leak. Move in test unit and flare stack—rig up,pressure testing to 1000 psi. RD flow nipple. Monitor well and surface flow/vent,pick up and haul flowing water to disposal well. Check salinity and LEL hourly—fresh water with 16-100 ppm gas. Load SLB 7" lubricator on planes on North Slope and fly to Anchorage. 9/25/13—Monitor well and surface flows/vents(several additional ones discovered farther from rig)—water is fresh. SIP-405 psi. Move office and break room way from surface vents to avoid water and potential gas. Planes arrived—offload 7"lubricator, shooting flange, and WL BOP. RU Schlumberger 7"lubricator. Pressure test lubricator—change out 0 ring. RIH w/ 6.05"gauge ring and junk basket—hit obstruction at 2893' (top of bottom set of old perfs)-3 tries—no go. POOH. 9/26/13—POH w/GR&JB. SIP--400 psi. MU 1st WL-set packer(AS1-X w/pump-out sub), RIH, correlate, and set at 2400,'. SIP dropped to 360 psi. POOH. Redress setting tool and firing head. PU 2nd AS1-X packer with dual glass disc sub, and RIH on WL, correlate, and set at 2150'. POOH. SIP dropped to 150 psi. Pump 22.75 bbl 9.4 ppg brine—SIP-0 psi. RD Schlumberger. FL dropped 14'. PU LokSet RBP, RIH, and set at 184'. Test casing to 500 psi—bled to 200 psi. Pulled up to 153', set and test—leaked off. (Water flow stopped). POH and inspect RBP- looked OK. RIH and set it at 31'. Test casing to 500 psi, leaked to 400 psi. POH, LD LokSet- and PU AS1-X. RIH to 183' and set—test casing to 630 psi—held. POH, PU RBP, set at 83'— casing test failed—RBP leaking. POH. Install circ sub on AS1-X. RIH and set at 83'—casing tested. Test BOP's. 9/27/13—Finish testing BOP's. RIH,retrieve AS1-X, POH, LD packer. PU CS1 packer, RIH to 2003' w/2 DC's and 2-7/8"tubing. Displace brine w/88 bbl fresh water. Work up hole testing down tubing and casing for leak w/packer at: 2007', 1679', 1356', 1032', 709', 644', and 315'-all good below packer, all leaking above packer. Set packer at 282'-casing tested, tubing failed(thus, casing leak is most likely old sqz perfs at 298'). Pump in at 1.5 BPM at 470 psi. SIP bled to 180 psi. POH and LD CS1 packer. 9/28/13-RU Schlumberger. RIH w/USIT tool and log from 2140' to surface(for cement bond and casing corrosion). Re-log bottom 500' due to brine-induced error. (USIT bond log showed little cement between 150-400' and between 500-1850'). POOH. RD SLB. Reconfigure LokSet RBP, RIH and set it at 388'. Dump 300# sand(14')of sand onto RBP, allow to settle for 30 min. POH. 9/29/13-WO cementers to arrive on barge and drive to location for 17 hrs. RU Baker Hughes P1• cementers w/batch mixer. RIH w/mule shoe on 2-7/8"tubing to 250'. PJSM. Test lines to 1500 psi. Pump into leak at 1.0 and 1.6 BPM at 500 psi max. Bled off. Batch mix 22.5 bbl cement slurry(109 sx Class G w/FL-62 fluid loss agent,CD-32 dispersant,J.5%A_7 CaCI retarder, &FP-6L defoamer w/ 1.16 cf/sk yield, 15.8 ppg, 2:30 pump time, 533 psi in 8 hrs, 943 psi in 12 hrs). Pump 20 bbl at 0.9-1.3 BPM, SD 5 min,bled to 88 psi. Continue hesitation sqz until 22.5 bbl cement+ 1.4 bbl water displaced. FPP-154 psi. Bled to 116 psi. Pull 1 std, rev out. Pump wiper ball. POH. WOC 1 hr. 9/30/13-WOC 9 more hrs. PU bit and DC's, RIH to 250'. Circ and rotate to 320'-no cement. e# Pressure to 400 psi-bled to 100 psi. Pre-pressure to 325 psi,bled to 175 psi. POH, LD bit. PU mule shoe, RIH to 250'. Circ btms up. RU cementers. Test lines to 1500 psi. Pump in at 1.0 . BPM at 380 psi, 1.5 BPM at 500 psi. Batch mix 22.5 bbl cement(109 sx Class G, as before), pump 19 bbl,hesitate sqz 5-10 min 5X,pumping 2 bbl in 35 min at 130-275 psi. Bled back to 75-90 psi each time. Displace w/ 1.4 bbl water,pull 1 std,pump wiper ball, POH. WOC 4 hrs- hole staying full. 10/1/13-WOC another 6.5 hrs. PU bit and DC's. RIH to 192', rotate and circ to 224'-tag cement. Drill cement to 322'. CBU. Test to 500 psi-held. WOC another 12 hrs (24 hr comp strength-2016 psi). Test sqz to 1000 psi-broke down,bled to 150 psi. POH. LD bit,PU mule shoe. RIH to 250'. RU cementers,testing lines to 3000 psi. Pump in 0.25 BPM at 1000 psi for 3 min, bled to 180 psi. Pump in at 0.3 BPM for 2 min at 1500 psi, bled to 156 psi, Pump .3 bbl to 1500 psi, bled to 220 psi in 10 min. 10/2/13-Batch 6.5 bbl(31 sx) same Class G mix. RIH w/mule shoe to 320'. Pump 6 bbl cement for balanced plug from 320-164'. Drop wiper ball,pump around. POH. Close blind rams and pressure to 1500 psi for 1.5 hrs. Increase pressure to 2000 psi for 7 hrs,taking some fluid. WOC 2.5 more hrs. PU bit and DC's and RIH. Tag at 169'. Drill cement to 322', CBU. POH. LD bit. PU pkr retrieving tool, RIH, retrieve RBP. POH&LD RBP. PU packer retrieving tool and RIH to 2136'. 10/3/13-Build 9.4 ppg brine. Displace fresh water with brine to 2150'. POH. PU RBP, RIH, set it at 258'. Test to 500 psi. POH w/tubing. Start BOP test. 10/4/13—Finish BOP test. PU retrieving tool and RIH to 258'. Retrieve RBP. POH, LD RBP. Close blinds and test sqz perfs(both at 298' and 677')to 1500 psi for 30 min—good. PU retrieving tool and RIH to 2150'. Wash out 4' of fill. Engage packer. Drop dart to break glass disc—did not break. RU Pollard,testing lubricator to 2000 psi. RIH w/overshot and retrieve dart. Run bailer—little recovery. RIH w/spear and spang down on disc—broke 3rd try. WHP- 600 psi. Mix and pump 22 bbl 9.4 ppg brine—pressure built to 625 psi. Bled back 3 bbl, pressure increased to 650 psi. Mix and pump 27 bbl 9.8 ppg brine at 875 psi—bled pressure to 0. 10/5/13—Mix 100 bbl 9.8 ppg brine. Unseat packer at 2150'. Pump 74 bbl at 150 psi. Mix 80 bbl 9.8 ppg brine. Ore to balance fluid at 9.8 ppg—lost 8.5 bbl. Pump 25 bbl 10.5 ppg Baraplug pill. POH w/packer,pumping out and circulating. LD packer&tools. PU retrieving tool. RIH to 2398'. Circ. Mix 30 bbl Baraplug pill. Engage packer at 2400'. Pump up to 875 psi—bled to 325 psi &plug released. Unseat packer, POH, LD packer and tool. Start PU bit, string mill, jars, and DC's. 10/6/13—RIH w/bit,mill,jars, DC's on 2-7/8"tubing w/SLM. Rotate and circ thru tight spot at 2893' (found by SLB GR run)—no indication of restriction. RIH to 3310'—tag fill. Wash to 3450'. CBU and pump high-vis sweep. POH, LD BHA. PU test packer w/bypass, RIH, set at 3296'. RU to swab and test. Swab 24 bbl w/no fluid last run(20 bbl to bottom pert) dry to packer w/no gas. RD swab lubricator. Fill tubing. Unseat packer,pull up 1 std and reset at 3232'. RU to swab. Losing 1 BPH, lost 24 bbl today,total lossed-306 bbl. 10/7/13—Standby 9 hrs for daylight to swab. Swab, rec 10 bbl and well kicked off, flowing 4 more bbl to test separator,then dry gas: 600 mcpfd at 160 psi FTP. SITP-760 psi. Open bypass,kill well. Release packer. C & C brine to 9.7 ppg. Slowly POH to avoid swabbing. LD packer and tools. Begin PU completion assembly#1. 10/8/13—PU and RIH w/completion assembly#1: 30' screen w/bull plug&X profile below, AS 1-X mechanical packer w/ X nipple above, 3 hydraulic packers w/3 sliding sleeves between packers. Space out to land w/EOT at 3277'. RU Pollard,testing lubricator to 2000 psi. RIH to set PX plug in X nipple at 3177'—would not set. POH, RD Pollard. Pull completion assembly #1—found XN profile instead of X profile. Changed out and reran completion assembly as before. Set AS1-X mechanical packer at 3185'. RU Pollard,ran PX plug, and set in X nipple at 3177'. RD Pollard. Pressure tubing to 1900 psi and set hydraulic packers, pressure up to 3500 psi for 5 min to test tubing—good. Test casing to 500 psi for 5 min—good. Bled off pressure. Release from T-2 on-off tool at 2176, POH with tubing and T-1 overshot. PU and starting running completion assembly#2. 10/9/13—RIH w/completion assembly#2: T-2 overshot,expansion joint,22 jts tubing, sliding sleeve, 22 jts tubing, sealbore extension, lower 7"X 4"permanent isolation packer, 14 jts 4-1/2" 12.6#, L-80 IBT tubing(for liner between isolation packers), & upper 7"X 4"permanent isolation packer, and tie-back sleeve w/setting tool on 2-7/8"tubing. Engage T-1 overshot, pressure to 2800 psi to set isolation packers at 726' and 267',then test to 3500 psi. Release setting tool and POH. PU 10' seal assembly, RIH, stab into sealbore to 736'. Test casing to 2000 psi for 30 min—good. Space out, install tubing hanger, and land tubing. ND BOP's. NU tree. Test tree and hanger to 5000 psi. RU Pollard, RIH, open sleeve at 1448'. POH. Test casing 2176-721' to 2000 psi for 30 min—good. RIH, close sleeve. POH. RU to swab. 10/10/13—RIH and pull PX plug at 3177'. Swab 19 runs—rec 66 bbl 9.6 ppg brine. Well kicked off—flow test perfs at 3268-3336': 470 mcfpd at 32 psi. SI 1/z hr—SIP 845 psi. RIH and set PX plug at 3177'. Open sleeve at 2916' w/900 psi left on tubing—no change. POH. Open well to test unit—bled to almost 0 w/some gas flaring. Flow for 20 min. Swab—rec 6.2 bbl. Open to flare. 10/11/13—Start rig down AWS #1, Swab 1 run w/no recovery. RIH, close sleeve at 2916', open sleeve at 2573'-225 psi. Swab 15 runs—rec 15-1/2 bbl w/no significant gas. Close sleeve at 2573', open sleeve at 2258—flow. Swabbed and rec 2 bbl. Flow until stable. SI,built to 815 psi. Open and flow at 1381 mcfpd at 120 psi. SI—built to 790 psi. RIH and close sleeve at 2258'. POH. RD Pollard and test equipment. Release rig at midnight. 10/12-14/13—Rig down and move AWS #1 to Lone Creek#3. Ed Jones(11/7/13) I. Aurora Gas, LLri , , A ""Conductor set at 80'in NICOLAI CREEK 6"hole,cemented w/300 sx UNIT #2 , PTD#: 168-038 , "94#Surface Casing set at API#: 50-283-10021-00-00 , 286'in 26"hole,cemented w/ DF 23.7 ft . 650 sx ,> Ins Ociohtr 7iPi31 1`19991 Sqz Perfs at298'—sgzdw/ 7J`t 200 sx in 1991 and 218 sx in 4-1/2" 12.6#L-80IBT 2013 Liner run between 2 — 1991 Sqz Perfs at 677'—sqzd Permanent Isolation , ■ w/215 sx in 1991 Packers set at 267'and 726'w/tie-back sleeve at 13-38"54.5#Surface Casing 262'and seal bore on set at 1934'.Cement w/1600 sx btm pkr& 10'Seal III Assembly at 726-736'. I 2 7/8 6.5#8rd EUE J-55 Tubing XA Sliding Sleeve at 1448' . 2 , Beluga - Ili 2198-2212' Hydraulic Packer at 2176'w/ On-off Tool w/X profile at 2244-2260' ( ..� 2176'ands'Exp Jt at 2163' (1962-2004'TVD) � r Ell Shrouded Sliding Sleeve at Carya 2-1.0 I 2258' 2312-2322' ' ' (2043-2050'TVD) Hydraulic Set Packer @ 2336' Carya 2-1.1 2426-2476' (2141-2177'TVD) 1111 i■ Sliding Sleeve at 2573' Carya 2-1.2 EXISTING PERFS 2700-2716' (2342-2356'TVD) ;>* — --= ,13�a Hydraulic Packer set at 2776' Carya 2-2.1 2870-76' 2893-2916' MM..- 11 1 Sliding Sleeve at 2917' (2475-2511'TVD1 4. I. ti,`- 0 X Nipple at 3178' °r c, — , Arrowset 1X Packer at 3185' Original Perfs:Carya 2-2.3 �°"+ 3270-3315' ^. Cemented over with 87 sx Bal , i Plug .-- . New perfs: Carya 2-2.3 -^ 3268-3288' 3-1/2"Sand Control Screens at 3230-60'w/ 3324-3336' ''�1 III X profile at 3267'and bull plug -..) EOT @ 3277' (2780-2831'TVD) '' - I; PBTD @ 3450'MD )%'s 7"26#J-55 Casing to 3545'MD cemented w/ 1500 sx Drill 9-7/8"Hole to 5011' MD/4102'TVD r �PV OF Ty THE STATE • Oil and Gas \ i//77,v A Alaska fA"d ASK A Conservation n Coln ission GOVERNOR SEAN PARNELL 333 West Seventh Avenue OA, .0.- Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 J. Edward Jones swim NOV 1 3 2013 President /'1 ( Q 3CC Aurora Gas, LLC {d/V 1400 West Benson, #410 Anchorage, AK 99503 Re: Nicolai Creek Field, South/Beluga Undefined Gas Pool, Nicolai Creek Unit#2 Sundry Number: 313-528 Dear Mr. Jones: 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. This approval is subject to full compliance with 20 AAC 25.055. Approval to test and produce sands within the Beluga undefined gas pool is contingent upon issuance of a conservation order approving a spacing exception. Aurora Gas, LLC. as operator, assumes the liability of any protect to the spacing exception that may occur. This approval does not authorize commingling of production from the Beluga and Tyonek undefined gas pools. See 20 AAC 25.215(b) 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, 1:).4(4,00/1"L, Cathy . Foerster Chair, Commissioner DATED this /0 day of October, 2013. Encl. /Q�(b Cnee v- -'' --p Regg,'James B (DOA) p 0 From: Company Man [wellsitesuper@aurorapower.com] Sent: Friday, October 04, 2013 9:45 AM To: DOA AOGCC Prudhoe Bay; Regg, James B (DOA) (a� 4'(i 3 Cc: Ed Jones; George Pollock �C Subject: AWS BOP 10-4-13 Attachments: AWS BOP 10-4-2013.xls SCANNED OCT 0 3 204 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: jim.regg(c�alaska.gov AOGCC.Insoectors(a)alaska.gov Phoebe. brooksCa�alaska. qov Contractor: Aurora Rig No.: 1 DATE: 10-4-2013 Rig Rep.: J. West / D. Williams Rig Phone: 907-632-0583 Rig Fax: N/A Operator: Aurora Well Service Op. Phone: 907-4441-6585 Op. Fax: N/A Rep.: G. Georlich E -Mail wellsitesuper@aurorapower.com Well Name: Nicolai Creek Unit 2 PTD # 1660380 Operation: Drlg: Test: Initial: Test Pressure: Rams: 250/3000 MISC. INSPECTIONS: Test Result Location Gen.: I' Well Sign Housekeeping: I' Drl. Rig PTD On Location I' Hazard Sec, Standing Order Posted P Misc BOP STACK: Quantity Stripper 0 Annular Preventer I #1 Rams I #2 Rams I #3 Rams 0 #4 Rams 0 #5 Rams 0 #6 Rams 0 Choke Ln. Valves I HCR Valves 2 Kill Line Valves 2 Check Valve 0 BOP Misc 0 Workover: X Explor.: 11" Weekly: X Bi -Weekly P Annular: 250/1500 Valves: 250/3000 None TEST DATA FLOOR SAFETY VALVES: Test Result Quantity Test Result P Upper Kelly I P P Lower Kelly I P P Ball Type I P NA Inside BOP I P FSV Misc 0 NA Size/Type Test Result 3 1/16 NA 11" P 2 7/8" P Blinds P None NA None NA None NA None NA 3 1/16 P 3 1/16 P 3 1/16 FP None NA None NA CHOKE MANIFOLD: Quantity Test Result No. Valves 13 1'P ✓ Manual Chokes 1 P Hydraulic Chokes 1 P CH Misc 0 NA Test Results MUD SYSTEM: Visual Alarm Trip Tank P P Pit Level Indicators P P Flow Indicator P P Meth Gas Detector P P H2S Gas Detector P P MS Misc 0 NA Quantity Test Result Inside Reel valves 0 NA ACCUMULATOR SYSTEM: Time/Pressure Test Result System Pressure 3150 P Pressure After Closure 1800 P 200 psi Attained 15 P Full Pressure Attained 80 P Blind Switch Covers: All stations Yes Nitgn. Bottles (avg): 4 @ 1900 ACC Misc 0 NA Number of Failures: 2 Test Time: 10.0 Hours Repair or replacement of equipment will be made within same days. Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Remarks: Manual Kill valve would not test we replaced with new valve and retested and passed. Number two choke v� alve_�vould not test on high pressure we greased and worked valve and retested and it passed 24 HOUR NOTICE GIVEN YES X NO Waived By Jim Regg Date 10-3-2013 Time 0:30 am Witness Test start 6:00om Finish 4:00am Form 10-424 (Revised 03/2013) AWS BOP 10-4-2013.xls \4kp 3 NicD(; Cree,K -11z P7b /6603e0 Regg, James B (DOA) From: Company Man [wellsitesuper@aurorapower.com] Sent: Friday, October 04, 2013 9:05 AM To: Regg, James B (DOA) ! 0 I4 (l 3 Subject: Aurora Unit #2 BOP test 10/4/2013 Attachments: BOP test 10-4-13.pdf Please see the attached file. Thank you, Gary Goerlich t�lcolsc7 Cree�IL � � 9 P rID l 66 a-' 10 166036o L f / o" /V NOON -4500 ___---4000 l� 3500 3000 -2000 O D 0 V . l cl v' --� �- z \/•e, 0 00- 000 0 0. Dost-' - 00pa PI Lia 1HOINQIW �'cjla; Ofrcr--4z piij J>o6o 3�o Q/'"•�� 6 AN a5°0 2 X500 as°o 0 2�00 o. 13°p ' ! \ ,\O0 � CHA -r 0 0 NO• MO NP 0 ER S0pO 1 -1 N .__N- 4 LrI puPT a,, c,. ,-OCAIIOV OFF r it �! `� frOy^� �� n.a . � 000 00 Nd 9 �3 S f " co k r' cry e(L ' z Regg, James B (DOA) P -1-b 16Co3g0 From: jbwest@q.com Sent: Friday, October 04, 2013 7:05 AM To: Regg, James B (DOA) Cc: Ed Jones; Company Man; George Pollock; Dave Boelens Subject: Test on pert squeeze NC 2 Attachments: Casing squeeze test 10-4 001.tif SCANNED 0 C T 0 3 2014 cli-aphis controls I I c ti CHART NO. MC MP -5000 METER--W_,--.--- CHART PUT ON TAKEN OFF -M /V C N 7 LOCA TIO REMARKS F_ IE Cv Wd 9 F_ IE Cv STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill❑ Perforate New Pool❑ Repair Well 0 Change Approved Program El Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing❑ Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate❑ Alter Casing❑ Other:Recomplete,test 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Development 166-038' Aurora Gas, LLC Exploratory ❑ � � 6.API Number: 3.Address: Stratigraphic ❑ Service ❑ 1400 West Benson, Suite 410,Anchorage,AK 99503 50-283-10021-00• 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order govems well spacing in Wool? CO No.478A Nicolai Creek Unit #2 Will planned perforations require a spacing exception? F Yes V No 9.Property Designation(Lease Number): q4 � ■�∎ 10.Field/Pool(s): ADL-17585 , 39 d'i.7 I I Nicolai Creek South Undefined Gas 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): •5011 • 4102 '3450 2918 3450-3537 NA Casing Length Size MD ND Burst Collapse Structural Conductor 80' 30"LP 80' 80' Surface 286' 20",94#, H-40 286' 286' - 520 1530 Intermediate 1934' 13-3/8"54.5#U-55 1934' 1762' 1130 2730 Production 3545' 7",26#, N-80 3545' 2992' 5410 7240 Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 2198-2212,2244-60,2312:22, 1962-2831 2-7/8",6.5# J-55 2150 Packers and SSSV Type: No SSSV. Packers and SSSV MD(ft)and ND(ft): No SSSV AS1-X w/plugs Pkrs-2400'MD/2108'ND,2150 MD/1927'1 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: Detailed Operations Program 151 BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development El- Service ❑ 14.Estimated Date for 3-Oct-13 15.Well Status after proposed work: Commencing Operations: Oil ❑ Gas IO • WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: io •3—/s WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: 6 ..---f,.- GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is tfue and correct to the best of my knowledge. Contact Ed Jones Email lejo esqauro a lowei..corn Printed Name J.Edward Jones Title President Adak Signature Phone 907-277-1003 Date 10/3/2013 �.L�l! �" COMMISSION USE ONLY Conditio approval: Notify Corn' ion so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test [j Mechanical Integrity Test ❑ Location Clearance ❑ Other: -2 57-9° r Si � (p 1/-e--r Tn ( & +€51- tAi p� - p 'r . E xce- r t i r.oar it) ks�1' Ai. 1,4, t-1ko .I a.s ? i p&f s.(;L l�fg-0A, e2y K- 2r�. i Spacing Exception Required? Yes No ❑ Subsequent Form Required: /b- Li L II APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: /0 .�10.--/3 41.147 /D./p /3 elf ` , � Submit Form and Form 1003(Reevvi 0/2012)1 Approved of E31d p 1a�lthe fro daft' provalAttachments in Duplicate O11 ` ' v L`.' II c^// • • AURORA GAS, LLC RIG RECOMPLETION WORKOVER PROCEDURE NICOLAI CREEK UNIT#2 Supplement of October 3, 2013 Version 3.0 (10/3/13) CURRENT CONDITONS: CURRENT STATUS : Perforated—cementing casing leak at 298'.KB=23.7 feet CASING: 7", 26#N-80 set at 3545'MD/2991' TVD. Cement Plug 3450'- 3527'. CURRENT PBTD: 3450'✓ TUBING: 2-7/8", 6.5#J-55 8 rd EUE MOD, PACKERS (temporary): ASX-1 at 2400' w/closed circ valve and at 2150' w/glass disc. RBP at 350'. CAPACITIES: 2-7/8" 6.5# Tubing: 0.00579 bbl/ft; Tubing-Casing Annulus: 0.0222 BPF; 7" 26#Casing: 0.0382 bbl/ft. PERFS: Lower Belgua at 2198-2212' and 2244-2260'(new) 2 Carya 2-1.0 at 2312-22' (new) Carya 2-1.1 at 2426-2487'(mostly depleted) Carya 2-1.2 at 2700-2716'(mostly depleted) Carya 2-2.1a at 2870-76' (new) Carya 2-2.1 at 2893-2916'(mostly depleted) Carya 2-2.3 at 3270-3315' (plugged back) at 3268-88' and 3324-36' (new) NOTES: 1) Well deviated,maximum of 44 deg at 2525' MD. SUMMARY OF PLAN: Cement squeeze leaking old sqz perfs at 298', drill out, and test. Retrieve RBP and temporary packers. Run test packer and test bottom 2 intervals. If no water problems there, pick up and run completion with 5 packers, screens, sliding sleeves to isolate open perforated intervals from new deeper perfs, and new shallower perfs, and to give 2 barriers between production and repaired casing. Set packers, swab in, and test each completion. DETAILED ROCEDURE (starting after Step 11 of original Procedure of 9/18/13): 1) After cement squeeze of old squeeze perfs at 298', PU 6-1/8"bit and RIH with 4-3/4"DC, and 4" DP. Drill out cement to sand above RBP. Pressure test squeeze to 500 psi. If it holds, after 24 hr total WOC time,pressure test casing to 1500 psi. If it does not hold,resqueeze—Procedure will again be supplemented at that time. • • 2) When casing tests to 1500 psi, POH and LD DC's and DP. RIH with tubing and packer stinger, circ any remaining sand off RBP and retrieve it. POH. RIH with ASX-1 stinger, circ down to and tag packer at 2150', circ clean, and displace fresh water with 9.4 ppg 3% KC1-NaC1 brine. 3) Sting into the top packer, break the glass disc, and kill the gas producing perfs at 2198-2322', if - necessary. 4) When well is stable, release the top packer, circulate until well is dead and stable, POH with tubing and packer. 5) RIH with tubing with packer stinger, tag second packer, circulate out any gas. 6) Sting into second packer and monitor losses. If losses are more than 1-2 BPH,mix viscous LCM pill, and spot toward bottom of tubing and pump viscous LCM pill into old perfs, displacing with 9.4 ppg brine. Monitor losses, repeat pill treatment if needed. 7) When well is stable and losses are controlled, release packer and circulate out. Pull tubing and packer. 8) PU casing scraper and bit on 2-7/8"tubing and run thru new perfs, to tag bottom at 3450', and circulate wellbore clean. POH and LD bit. ( 9) If well is stable, PU test service packer(with unloader valve—must be able to kill well without ( releasing packer), RIH to +/-3300', set packer, and swab well in to test perfs at 3321-3331'.'Flow 'Z(R' test until stable (See Testing Procedures)—get good water production rates (recover all load to perfs I - –about 20 bbl, then get a rate of formation water, if any). l r w•° i 10)Kill well, move packer up to 3240' (1 stand) and reset. Test as in 9) above: recover load water then / get a water rate (if any) and gas rates—compare two results—call in results. May set CIBP above lower perfs if making significant water. POOH and LD test packer. °11) PU following completion BHA and RIH in 3 runs (RIH on 2-7/8" Mod tubing, visually inspecting and replacing rubber seal rings and questionable collars), as follows: A. FIRST RUN—PU and RIH w/ a) 10' 2-7/8"pup joint w/bull plug b) X profile nipple w/2.31" ID c) 6' or 8' 2-7/8"pup joint d) Cross-over 2-7/8"pin X 3-1/2"NU box e) 30' 3-1/2" Stratapack Screen (new—on hand at Moquawkie yard) w/bull plug on end; f) Cross-over: 3-1/2"NU pin X 2-7/8"box, g) 1 jt 2-7/8" tubing, h) 7" Arrowset mechanical packer with On-Off tool (w/2.31" X profile)to be set at about 3185', i) 8 jts 2-7/8"tubing j) 2-7/8" Sliding Sleeve to be set at+/-2922', k) 4 jts 2-7/8"tubing, 1) Hydraulic-set packer to be set about 2785' m) 7 jts 2-7/8"tubing, n) 2-7/8" sliding sleeve at about 2556', o) 7 jts 2-7/8"tubing, p) Hydraulic Packer at about 2351' q) 3 jts 2-7/8"tubing, r) Shrouded Sliding Sleeve at 2250', s) 2 jts 2-7/8"tubing, t) draulic-set Packer to 21.80' with T-2 On-Off tool, • • RU Pollard and run PX plug, set in X profile in On-Off Tool above Arrowset packet at 3184'. Pressure to 3000 psi to test tubing, then to +/-3500 psi to set hydraulic packers. Retest casing to 1500 psi. RD Pollard, but don't release. lam. SECOND RUN—PU and RIH w/ a) T-2 On-Off Tool skirt b) 1 jt tubing c) Sliding Sleeve at about 2145' d) 44 jts 2-7/8"tubing, e) Cross-over f) 4"x 10' Seal Bore Extension g) 7"X 4" Permanent Isolation Packer to set at about 710' h) Cross-over to 4-1/2" IBT-M i) 14 jts 4-1/2" 12.6# L-80 IBT-M Tubing (for Liner) (3.958" ID/3.833" drift) j) Cross-over k) 7" X 4"Permanent Isolation Packer to set about 267' 1) RIH on 2-7/8"tubing w/ setting tool. Latch onto On-Off tool at 2179'. Pressure up to test tubing and then to set 2 Isolation Packers. Release from top Isolation packer and POH with 2-7/8"tubing. C. THIRD RUN—PU and RIH w/ a) 10' X 3.250" Seal Assembly b) 27 jts of 2-7/8"tubing to surface. c) Sting into seal bore in top Isolation Packer. Pressure test tubing to 3000 psi. 12)a) Space out, land tubing, and lock down. 1,P 7'r"1) b) Pressure test casing to 2000 psi for 30 minutes (chart—required by AOGCC). J' 0 c) Install BPV. ND BOP. NU and test tree. Pull BPV. (Be rigging up AG test choke manifold, separator, and flare stack, connected with hardline during this time). -� 13) RU Pollard slickline unit and lubricator. Open sleeve at 2145' and pressure test packers to 2000 psi. RIH w/retrieving tool and retrieve prong and plug at 3184'. Run shifting tool and confirm all 21 go' sliding sleeves are closed. POOH. RD Pollard(but do not release). 7/0 14)RU to swab and swab in Carya 2-2.3 perfs at 3268-3336' and test thru test separator. SEE SUPPLEMENTAL TEST PROCEDURE. Allow to cleanup. SI for 1 hr buildup. Open to flow and allow to stabilize at about 80% (or more) of SITP. SI, and watch buildup for 1 hr. Do not kill well. 15)RU Pollard. Test lubricator to tubing pressure. RIH and reset PX plug and prong in On-Off toll profile at 3186'. Open sleeve at 2932' and test new 2-2.1 perfs at 2870-76' (lower pressure is Z— expected since it is commingled with open partially depleted perfs). RD Pollard. Test these perfs as in Step 15 above. Tubing s/b essentially dry so no swabbing should be needed, unless perfs are making water. 16)RU Pollard. RIH and close sleeve at 2932', bleed pressure down below 400 psi, and open sleeve at 2585' to blow down and get water off partially-depleted 2426-2716'. Do not test except to flow back any water and get SI pressure buildup. 17)RU Pollard. RIH and close sleeve at 2585' and open sleeve at 2270' to test new perf interval 2198- 2322' as in Step 15 above. NOTE: AWS rig can be released when 2 zones are successfully tested at rates above 1 MMcfpd each w/o significant drawdown (FTP>75% SIP). 18)Based on test results, determine initial configuration of well for production (probably deepest, driest interval) and RIH w/Pollard to pull plug and/or open sleeves to facilitate configuration. RD • • Pollard. RD AG test equipment. Turn well to operators to reconnect flowline and put to sales thru 3-10 production facility. Ed Jones (Rev 10/3/13) . . ID • Aurora Gas, LLC 30"Conductor set at 80'in NICOLAI C EK :++ ''a.` t '";, 36"hole,cemented w1300 sx UNIT#2 PTD#: 168-038 "i . . 20"94#Surface Casing set at API#: 50-283-10021-00-00 .. . 286'in 26"hole,cemented w/ DF23.7ft 4 -- — 650sx (To be run October 2013) , 1991 Sqz Perfs at 298'-sqzd w/ ?` 200 sx in 1991 and 218 sx in 4-1/2"12.6#L-80 Liner �I �" 2013 run between 2 Permanent —=` �. 4 1991 Sqz Perfs at 677'—sqzd Isolation Packers set at w/215 sx in 1991 266'and 710'w/seal bore on btm nkr. 13-3/8"54.5#Surface Casing set at 1934'.Cement w/1600 sx ER 2 7/8 6.5#8rd EUE J-55 Tubing I ■ 11 Sliding sleeve at 2145' Carya 2-1.0 --.4 .._,,;, Hydraulic Packer at 2180'w/ 2198-2212' On-off Tool 2244-2260' ' =••• Shrouded Sliding Sleeve at t+: CI 2251' 2312-2322' ,,' . ..:. z �. . -.... All New ....._ —/ — Hydraulic Set Packer 2350' Carya 2-1.1 w/Expansion joint bel@ ow it 2426-2476' IIII /l/ II Sliding Sleeve at 2556' Carya 2-1.2 EXISTING PERFS 2700-2716' Hydraulic Packer set at 2785' Carya 2-2.1 New 2870-76' 03 —° Sliding Sleeve at 2921' 2893-2916' , t% ' Arrowset 1X Packer at 3185' �—�I With On-Off Tool Original Perfs:Carya 2-2.3 . ,,3270-3315' t' I. Cemented over with 87 sx Bal Plug __ New perfs: Carya 2-2.3 -. 3268-3288' c ° a 3-1/2"Sand Control Screens at 3220-50'w/ =. X profile and bull plug 3324-3336' ,'' � ; .,F " EOT @ 3251' PBTD @ 3450'MD t.° .. 7"26#J-55 Casing to 3545'MD cemented w/ "'t "? 1500 sx Drill 9-7/8"Hole to 5011' MD/4102'TVD . • • Nicolai Creek No.2 Proposed Nicolai Creek Field Alaska 1 X Current Production 2 7/8"Production Tubing 36"Hole ,41$, I 11 � II 1,J'w Mi 30"@80' i l . CMTD to surface ia �ja : w/300 SX _ .' - 0 ;< Attachment xS 26"Hole /;� ;, t t i 41,i , '_ : fit; t 20"94#@ 286' '' '�f 5 SPF @ 298'Squeezed w/200 sx in 1991 CMTD to surface 3 3.i ski W/650 SX " 4:E . p i' a ;. yr i I 1 17 1/2"Hole �P. t�; � „It, 5 SPF @ 677'Squeezed w1215 sx in 1991 , � � ' ;Ri TOC @-1900'MD ' A in 133/8"X7"annulus 13 3/8"54.5#@ 1934' ',Al CMTD W/1600 SX 1 y`"i 2.313"ID X-Nipple at 2288.8' *';' ' + Permanent Packer at 2327' ■ 4•, 5"Meshrite Screen r`'t Perforate @ 5 SPF 2426'- 2476' tti / Perforate @ 5 SPF 2700'-2716' I; 9 7/8"Hole ;+ `, f , Vi; ,r T, Perforate @ 5 SPF 2893'to 2916' Original production perforations 4 1/2 SPF *' from 3270'to 3315'cemented over ' a 87 Sk Class"G"Cement Plug 3102'-3537' during 1991 Suspension Procedure " 7,71_.*e 'i; Plug(Baffle Plate) 7"26#@ 3585'MD 44,5 :.� @ 3543'MD CMTD W/1400 SX CRAWIN3 NOT TOSCALE NICOLAI CREEK No.2 TD @ 5011'MD 4086'TVD FAIRWEATHER E&P Rev 01!DHV 05Sept-02 SERVICES INC. T - p o i r rat a__ L..c COMPANY DATE TEMP GUN SIZE SPF PHASING AURORA GAS LLC 3-Oct 27 LEASE: WELL FLUID WEIGHT /TYPE SPECIALIST NICOLAI CREEK UNIT#2 ANDY MILAZZO OFFSHORE BLOCK PARISH STATE COMPLETION INTERVIAL I '6 KENAI PENINSULA _ ALASKA _ ITEM DESCRIPTION OD ID LENGTH DEPTH 0.00 11 11 25 _ 0.00 ADDITIONAL INFORMATION ON WORKSHEET 2 _ 0.00 0.00 r4 0.00 A 0.00 0.00 I ,/I 23 0.00 �.M 22 0.00 0.00 1r 21 27 2-7/8"TUBING TO SURFACE 713.00 0.00 '_ A 10' SEAL ASSEMBLY 10.00 713.00 - -•,0 723.00 IMMINICI nom 19 i - ! 18 26 7" X 4" ID ISOLATION PACKER 3.00 266.60 L=_== 25 4-1/2" CASING (14 JOINTS) 440.50 269.60 17 24 7" X 4" ID ISOLATION PACKER 3.00 710.10 6 23 4" SEAL BORE EXTENSION 10.00 713.10 22 2-7/8"TUBING (45 JOINTS) 1,455.00 723.10 -•_ 21 2-7/8"T-2 ON-OFF TOOL 1.50 2,178.10 15 20 7" FH HYDRAULIC SET PACKER 6.50 2,179.60 II 14 19 2-7/8"TUBING (2 JOINTS) 64.60 2,186.10 13 18 2-7/8"SHROUDED SLIDING SLEEVE 3.00 2,250.70 12 17 2-7/8"TUBING (3 JOINTS) _ 97.00 2,253.70 - -• 1 16 7" FH HYDRAULIC SET PACKER 6.50 2,350.70 ,� 15 2-7/8" EXPANSION JOINT 5.00 2,357.20 -= 14 2-7/8"TUBING (6 JOINTS) 193.80 2,362.20 •MIN1• 10 13 2-7/8"SLIDING SLEEVE 3.20 2,556.00 III 12 2-7/8"TUBING (7 JOINTS) 226.10 2,559.20 9 11 7" FH HYDRAULIC SET PACKER 6.50 2,785.30 l 8 UMW •10 2-7/8"TUBING (4 JOINTS) _ _ 130.00 2,791.80 98" SLIDING SLEEVE 3.20 2,921.80 t, 7 8 2-7/8"TUBING (8 JOINTS) 258.50 2,925.00 E-� 7 27778"T-2 ON-OFF TOOL 1.50 3,183.50 6 7"AS1-X PACKER 7.00 3,185.00 6 5 2-7/8"TUBING (1 JOINT) 31.00 3,192.50 = 4 :3-1/2"STRATAPACK SCREEN 30.00 3,223.50 5 3 2-7/8" X 8' PUP JOINT _ 8.00 3,253.50 -'-- 2 2.313" 'X' PROFILE NIPPLE 1.20 3,261.50 h EEl 4 2-7/8" X 8' PUP JOINt 8.00 3,262.70 - __ 11 2-7/8" BULL PLUG 0.501 3,27(176 „ „ 1I 3 1 1 2 I "FM 11 i Regg, James B (DOA) A�ak 6reei-- #"z- prJj /6(o03eo From: Brooks, Phoebe L (DOA) Sent: Tuesday, October 01, 2013 1:04 PM To: Company Man Cc: Regg, James B (DOA) Subject: RE: Aurora AWS BOP test Attachments: Aurora 1 09-27-13 Revised.xls Attached is a revised report for Aurora 109-27-13 changing the Choke Ln. valves to "FP" and the Upper Kelly to "P" per Jim Regg. Please update your copy or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Statistical Technician II�� Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 From: Company Man[maiIto: weIIsitesuper@aurorapower.com] Sent: Saturday, September 28, 2013 5:46 AM To: Regg, James B (DOA); Brooks, Phoebe L (DOA); DOA AOGCC Prudhoe Bay Cc: Ed Jones; George Pollock Subject: Aurora AWS BOP test BOP test form and charts. Thanks David 1 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: lim.regq(a�alaska.gov AOGCC.Inspectors(a.alaska.gov Phoebe. brooks(d.alaska.gov Contractor: Aurora Rig No.: 1 DATE: 9/27/13 Rig Rep.: J. West / D. Williams Rig Phone: 907-632-0583 Rig Fax: N/A Operator: Aurora Well Service Op. Phone: 907-4441-6585 Op. Fax: N/A Rep.: G. Georlich E -Mail wellsitesuper@aurorapower.com Well Name: Nicolai Creek Unit 2 PTD # 1660380 Operation: Drlg: NA Workover: X Explor.: 1 Test: Initial: #1 Rams Weekly: X Bi -Weekly P Test Pressure: Rams: 250/3000 Annular: 250/1500 Valves: 250/3000 0 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: 0 Test Result NA Test Result Quantity Test Result'. Location Gen.: P Well Sign P Upper Kelly 1 P Housekeeping: P Drl. Rig P Lower Kelly 1 P PTD On Location P Hazard Sec. P Ball Type 1 P Standing Order Posted P Misc NA Inside BOP 1 P BOP STACK: Quantity Size/Type Test Result Stripper 0 NA NA Annular Preventer 1 11" P #1 Rams 1 2 7/8" P #2 Rams 1 Blinds FP #3 Rams 0 None NA #4 Rams 0 None NA #5 Rams 0 None NA #6 Rams 0 None NA Choke Ln. Valves 1 3 1/16 FI' HCR Valves 2 3 1/16 P Kill Line Valves 2 3 1/16 P Check Valve 0 None NA BOP Misc 0 None NA CHOKE MANIFOLD: Quantity Test Result No. Valves 13 P Manual Chokes 1 P Hydraulic Chokes 1 P CH Misc 0 NA FSV Misc 0 NA Test Result MUD SYSTEM: Visual Alarm Trip Tank P P Pit Level Indicators P P Flow Indicator P P Meth Gas Detector P P H2S Gas Detector P P MS Misc 0 NA Quantity Test Result Inside Reel valves 0 NA ACCUMULATOR SYSTEM: Time/Pressure Test Result System Pressure 3050 P Pressure After Closure 2000 1' 200 psi Attained 16 P Full Pressure Attained 78 I' Blind Switch Covers: All stations Yes Nitgn. Bottles (avg): 4 @ 1900 ACC Misc o NA Test Results Number of Failures: 2 Test Time: 7.5 Hours Repair or replacement of equipment will be made within days. Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Remarks: Blind rams failed first test , functioned rams and washed them then retested and passed. Choke Line valve failed - passed retest. 24 HOUR NOTICE GIVEN YES NO X Waived By Jim Regg Date 9/26/13 Time 16:17 Witness Test start 23:00 Finish 06:30 Form 10-424 (Revised 03/2013) Aurora 1 09-27-13 Revised.xls N; co L j` C>eeV- st z P -IL i66,7350 Regg, James B (DOA) From: Company Man [wellsitesuper@aurorapower.com] Sent: Monday, September 30, 2013 10:42 PM To: Regg, James B (DOA)q Subject: RE: Aurora AWS BOP test We were looking for a leak. Found it on the test pump. 1" Valve was allowing fluid to leak back through pump. Changed and everything tested good. David From: Regg, James B (DOA) [mailto:iim.regg@alaska.gov] Sent: Monday, September 30, 2013 11:24 AM To: Company Man Subject: RE: Aurora AWS BOP test What are the pressure cycles after testing super choke and prior to testing lower kelly valve? Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: Company Man[ma iIto: wellsitesuperCcbaurorapower. com] Sent: Saturday, September 28, 2013 5:46 AM To: Regg, James B (DOA); Brooks, Phoebe L (DOA); DOA AOGCC Prudhoe Bay Cc: Ed Jones; George Pollock Subject: Aurora AWS BOP test BOP test form and charts. Thanks David AWS#1 BOPE Test — Nicolai Creek Unit #2 (PTD 1660380) 9/27/2013 2013-0927—BOP—AWS INCU-2 Page 1 of 4 IV_C 0 Yc WCII 2013-0927 B0PA W S I —N C U-2 Page 2 of 4 m 2013-0927—BOP—AWS INCU-2 Page 3 of 4 e n oK�� ro s Cry c 4'j %d �cn caps r/ C c C � r \tet it Cco !G- UHART No. j"1C typ 500 J ph p7 7 At�7 r .. -Z �' ZO _ 5x oV)k L_� SCYv c,ll C�j� 0 tea, vZ 2013-0927—BOP—AWS I NCU-2 Page 4 of 4 • • rTp AURORA GAS, LLC /14C, 6 8 NICOLAI CREEK UNIT #2 CASING LEAK REMEDIATION II—CEMENT SQUEEZE PROCEDURE September 27, 2013 CAPACITIES: 2-7/8" 6.5#Tubing:0.00579 bbl/ft;Tubing-Casing Annulus:0.0222 BPF; 7"26#Casing:0.0382 bbI/ft. 1) After running Schlumberger USIT casing inspection log,review results. If no area of casing appears to need repair other than old squeeze perfs at 298',PU RBP (mechanical packer so configured), RIH on 2-7/8"tubing(with 4-3/4"DC's if needed for weight)and set at+1-360'. Release from RBP,POH, stand back DC's, LD running tool. 2) PU mule-shoe for tubing and RIH with tubing,tag RBP, PU one joint,and dump 2 sx(200#) sand onto RBP (+1-10'). Pull up to+/-250'. 3) RU Baker Hughes cementers,with batch mixer,including plan to inject foam tubing wiper balls into tubing. Close pipe rams. Perform injectivity test into leaking old perfs at 298' w/ clean fresh water. Pump 1 BPM for 3 minutes and 2 BPM for 3 minutes(9 bbl),but keep pressure below 500 psi(slow rate as necessary; if pressure reaches 500 psi maintain rate for 2 minutes,unless less than 1 bpm—if less than 1 BPM, achieve rate and record pressure). Record ISIP. (Open surface casing valves and monitor during all pumping.) 4) Cement as follows: A)Batch mix 22-23 bbl Class G cement(109 sx at 15.8 ppg, 1.16 cf/sk)w/defoamer, 0.3%CD-32 dispersant,0.7%FL-63 fluid loss additive, and 1.5%CaC12 accelerator (BHT estimated at 60-70 deg F). B)Pump w/fresh water spacer ahead and with foam wiper plug behind and displace with fresh water. (Tubing volume to 250' = 1.4 bbl, casing volume to 298' is 1.9 bbl, so total volume to perf is only 3.35 bbl). C)Pump as much as to 19 bbl of cement into perfs, starting at 1-2 BPM with pressure below breakdown, as indicated by injectivity test(or less than 500 psi). Slow rate to 1/3 to Ilz BPM as maximum pressure or 18 bbl is approached. LEAVE AT LEAST 2 BBL (50') OF CEMENT IN CASING. D) Stop pumping when 500 psi is achieved or when 4 bbl remain in casing. Hesitate for 5 minutes and repressure,2-3 times—LEAVE AT LEAST 2 BBL CEMENT IN CASING . When pressure holds or 2 bbl remain in casing, pull one stand,and reverse out any remaining cement+ 10 bbl. DO NOT RELY ON STRCTLY ON RIG PUMP STROKE COUNTER FOR DISPLACEMENT—USE CEMENTER TUBS OR TANK GAUGES TO CONFIRM. (Pressure increase during job should be about 100 psi due to negative hydrostatic differential of cement and displacement fresh water). Pump (circulate)a second foam wiper plug down tubing+one additional tubing volume. . • 5) POH w/tubing(could pull one stand and SI if pressure is low and not concerned about cement flowing back—in that case,close pipe rams), close blind rams and pressure to final squeeze pressure if possible,but pumping no more than %2 volume of cement left in casing. 6) WOC at least 12 hours. 7) PU 6-1/8"bit and RIH with 4-3/4"DC,and 4"DP. Drill out cement to sand above RBP. Pressure test squeeze to 500 psi. If it holds, after 24 hr total WOC time,pressure test casing to 1500 psi. If it does not hold,resqueeze—Procedure will again be supplemented at that time. 8) When casing tests to 1500 psi,LD DC's and DP. RIH with tubing and packer stinger, displace fresh water with 9.4 ppg 3%KC1-NaC1 brine. 9) Sting into the top packer,break the glass disk, and kill the gas producing perfs at 2198-2322', if necessary. 10)When well is stable,release the top packer, circulate good until well is dead and stable, POH with tubing and packer. 11)RIH with tubing with packer stinger,tag second packer,circulate out any gas. 12)Sting into second packer and monitor losses. If losses are more than 1-2 BPH,mix viscous LCM pill,and spot toward bottom of tubing and pump viscous LCM pill into old perfs, displacing with 9.4 ppg brine. Monitor losses,repeat pill treatment if needed. 13)When well is stable and losses are controlled,release packer and circulate out. 14)Pull tubing and packer and run immediately run planned completion with multiple packers. Ed Jones 9/28/13 �' CO k G-eC7IL �nif Z Regg, James B (DOA) From: Company Man [wellsitesuper@aurorapower.com] Sent: Tuesday, September 24, 2013 6:15 AM To: DOA AOGCC Prudhoe Bay 2�'1� �� Subject: BOP shut in 9-23-13 Attachments: Aurora Gas LLC BOP Use.docx Shane McGeehan 701-651-3344 yCWED OCT 03 2094 P-J-J� I6603�O Aurora Gas LLC BOP Use Date / Time: September 23, 2012. 10:00 AM Well / Location / PTD Number: Nicolai Creek #2. Nicolai Creek South. 166-038 Rig Name: Aurora Well Service #1 , Operators Name: Aurora Gas LLC Operators Contact: Ed Jones, Aurora Gas LLC. 281-495-9957 Office; 713-899-8103 Cell Operations Summary: We finished perforation well early this AM. Before we could run a casing scraper, we had a BOP test scheduled. As we were getting ready to start the test, we started getting an influx of -gas, and our casing pressure built to 400 psi. We did not have tubing in the hole. Well was only slightly overbalanced when perforating due to the open depleted perfs. Rr)PF IlcPrl- Blind rams, kill line and choke. Reason for BOPE Use: Gas kick during normal operation of getting ready for BOP test. Actions Taken / To Be Taken (include date used BOPE was tested: Bullheaded LCM pill and 9.3 ppg brine. Attempt to bleed gas. Monitor well. Looking at other options including packers, bridge plugs and coiled tubing. EINEM • • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Thursday, October 03, 2013 4:48 PM To: 'Ed Jones' Cc: 'Company Man';"George Pollock";'Regg,James B(DOA) (jim.regg @alaska.gov)' Subject RE: Nicolia Creek#2 Remedial 4-1/2" Liner Proposal 10-403 (PTD 166-038) Ed, Procedure looks good.. changes are noted and approved. You have verbal approval to proceed per the latest version of the completion procedure (Oct 3 2013). This procedure and new sundry request supersedes the original sundry 313- 475. Get me a signed copy of the sundry as soon as you can if you have not already mailed one. Make sure the rig has a copy of the latest version and has this email to verify approval if an AOGCC inspector is on site. BOP test pressures are same as before... 2500 psi. I won't need a testing string diagram ..your description is adequate. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: Ed Jones [mailto:jejones @aurorapower.com] Sent:Thursday, October 03, 2013 4:20 PM To: Schwartz, Guy L(DOA) Cc: 'Company Man'; "George Pollock" Subject: RE: Nicolia Creek#2 Remedial 4-1/2" Liner Proposal 10-403 Guy, I have changed the Procedure (see attached): 1)to test to test the squeeze perfs to 1500 psi,to test the top production packer to 1500 psi (see last line of Step 11.A, after setting the packers on the First Run, 2) to add a sliding sleeve between the top (hydraulic packer) and the bottom isolation packer so we can test it, and 3) have added that test to the Procedure (in Step 13). I don't believe that temperature fluctuations will be an issue, due to the low temperatures at that depth and the expected modest flow rates—however, we want to bleed off the pressure after the test. Regarding your question about#2 below,we will run a Tripoint JS-2A retrievable packer, which has an internal by-pass valve that will allow us to circulate brine to kill the well after testing without bullheading, before releasing the packer(the bypass opens and closes by pickup and set down of the tubing). This packer will be run on the 2-7/8"tubing without any other accessories in the string. The tubing will be set in the slips with the BOP on the well,the annular closed, and the casing pressure monitored with a gauge. The AWS 3000-psi "swab tee" will be used as a test tree with a flow tee connected to a TIW valve on the top joint of tubing, a 5000-psi plug valve on the wing of the tee, and a 3000-psi ball valve on top of the tee, which will be capped after the well is swabbed in and the swab lubricator removed. Please let me know if you need more info. (I can draw up a test string diagram, but I have given you all the details above—let me know if you still want one). Thanks, Ed J. Edward Jones 1 • • President ✓ Aurora Gas, LLC 6051 North Course Dr.,Ste 200 Houston,TX 77072 281-495-9957(0) 713-899-8103 (C) From: Schwartz, Guy L(DOA) [mailt o:guy.schwartz @alaska.gov] Sent:Thursday, October 03, 2013 3:30 PM To: Ed Jones Cc: 'Company Man'; "George Pollock" Subject: RE: Nicolia Creek#2 Remedial 4-1/2" Liner Proposal 10-403 Responses below: Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: Ed J ones [rnailtojeiones aaurorapower.com] Sent:Thursday, October 03, 2013 12:01 PM To: Schwartz, Guy L(DOA) Cc: 'Company Man'; "George Pollock" Subject: RE: Nicolia Creek#2 Remedial 4-1/2" Liner Proposal 10-403 Guy, In response to your questions: 1) We do plan to pressure test again. Because the cement was green when we drilled out, I wanted to give it more time to cure. However, our maximum expected BH pressure is only 1303 psi,from our perfs at 3324-3339' MD/2831'TVD (2831 X 8.85 ppg X.052)—could we test both sets of old squeeze perfs to only 1500 psi? (I missed that revision in the Procedure). After we cover the perfs with the liner, we will test to 2000 psi—would this be acceptable? (We needed to move the RBP to test the lower old sqz perfs). We can do this today—we are essentially at a place to do that. A pressure test to 1500 psi is acceptable. The sqz perfs need to test to that before they can be exposed to potential reservoir pressure or MASP. 2) The short term flow test is a "nice to have" but not critical if you are concerned about it. It will take some time—we are concerned about the possibility of water production, and this point would be the best time to resolve it—although it could be done later with wireline if it is the bottom set. As long as upper sqz perfs are holding a short term flow test is OK to determine fluid properties. Make sure well is killed (bullhead) before pulling packer. What type of unloader valve are you considering? Could you send test string diagram? Using a test tree or nipple up production tree? 3) Testing the upper production packer at that point was in the original procedure, and overlooked in this version- -we could certainly do it at that point, but once again, would prefer to keep pressure to 1500 psi until we get liner in well. Agree, 1500 psi test at this point. 4) Yes, adding a sliding sleeve to test the packers would be easy to do. If we tested the packer at 2100' earlier(to 1500 psi), then the 2000 psi test of the 2 packers thru the sleeve would be a definitive test of both packers if good, but probably indicate a problem with the lower Isolation packer if not good. A Sleeve would be good here ... any issues with having a confined volume of fluid trapped between packers? i.e. Temperature fluctuations etc. Let me know if these are acceptable, and I'll revise the Procedure accordingly. 2 . . - • • Thanks, Ed J. Edward Jones President Aurora Gas, LLC 6051 North Course Dr., Ste 200 Houston,TX 77072 281-495-9957(0) 713-899-8103(C) From: Schwartz, Guy L(DOA) [mailto:quy_schwartz(atalaska.gav_] Sent:Thursday, October 03, 2013 1:06 PM To: Ed Jones Subject: RE: Nicolia Creek#2 Remedial 4-1/2" Uner Proposal 10-403 Ed, Have looked at your procedure... it looks good. A couple of questions came up: 1. Are you going to pressure test the sqz perfs to 2000 psi as per step number 1? Your last report indicated that you had tested to 500 psi but then pulled the RBP already. If you plan breaking the isolation barriers on the two packers below the casing must be tested first to 1500-2000 psi at least ... ( I would also test the sqz perfs at 677') before moving forward with that part of your program. 2. I am ok with doing a short term flow test of the lower two zones but as above the casing must pass pressure test first . 3. Are you testing the upper packer at 2180ft after setting the X plug to inflate the hydraulic packers? 4. Is there any way to test the lower 7" X 4" isolation packer at 710ft? . I don't see how you will be able to do that after setting the two 7 "x 4" Isolations packers hydraulically. Could put a sliding sleeve at about 2100'to test both packers (710ft and 2180'packers).. I may be missing part of the picture, just an observation. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: Ed Jones [rnailto_:j_ejonesa?arrorapower_com] Sent:Thursday, October 03, 2013 9:13 AM To: Schwartz, Guy L(DOA) Cc: Regg,James B(DOA); "George Pollock"; 'Company Man'; 'Steve Zenthoefer' Subject: Nicolia Creek #2 Remedial 4-1/2" Uner Proposal 10-403 Guy, As we discussed,here is a form 10-403,a detailed Procedure,a Proposed Wellbore Diagram,and a supporting Tripoint tool completion diagram. Please let me know of your questions,comments,or approval. Thanks, Ed J.Edward Jones President Aurora Gas,LLC 6051 North Course Dr.,Ste 200 Houston,TX 77072 281-495-9957(0) 3 Or Tit, w w��\\I/7; s9 THE STATE Alaska Oil and Gas ' �' ®fl LASJ(A Conservation Commission r GOVERNOR SEAN PARNELL 333 West Seventh Avenue 9',.�„\T'�` P. Anchorage, Alaska 99501-3572 ALASY' Main: 907.279.1 433 CONE® NOV 1 202 Fax: 907.276.7542 George Pollock !� Manage, Engineering and Operations / Q Aurora Gas, LLC I (� 1400 West Benson, Suite 410 Anchorage, AK 99503 Re: Nicolai Creek South Field, Undefined Gas Pool,Nicolai Creek Unit#2 Sundry Number: 313-475 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. This Approval is subject to full compliance with 20 AAC 25.055. Approval to test and produce sands within the Beluga undefined gas pool is contingent upon issuance of a conservation order approving a spacing exception. Aurora Gas, LLC, as operator, assumes the liability of any protest to the spacing exception that may occur. This Approval does not authorize commingling of production from the Beluga and Tyonek undefined gas pools. See 20 AAC 253215(b). 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, I ,'( __ Cathy P. oerster Chair DATED this /" day of September, 2013. Encl. • • Vlit, RELfEIVED STATE OF ALASKA el A41 SEP a42013 ALASKA OIL AND GAS CONSERVATION COMMISSION (y ID. -5 1 11 1 APPLICATION FOR SUNDRY APPROVALS AOGCC 20 MC 25.280 1.Type of Request: Abandon❑ Plug for Redrill❑ Perforate New Pod❑ Repair Well❑ Change Approved Program ❑ Suspend❑ Plug Perforations❑ Perforate El • Pull Tubing Q • Time Extension ❑ , Operations Shutdown❑ Re-enter Susp.Well i i■ Stimulate❑ Alter Casing Other /';'o 17 ❑ ❑ O w 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Aurora Gas, LLC Exploratory ❑ Development ®. 166-038 • 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: 1400 West Benson, Suite 410,Anchorage,AK 99503 50-283-10021-00 7.If perforating: 8.Well Name and Number, What Regulation or Conservation Order governs well spacing in this pool? CO No.478A Nicolai Creek Unit #2• Will planned perforations require a spacing exception? Yes ❑ No 9.Property Designation(Lease Number): ? 10.Field/Pool(s): ADL-17585 l AjL 391,171 ��5�� Nicolai Creek South Undefined Gast 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): •5011 -4102 -3119 •2672 3119-3537' NA Casing Length Size MD ND Burst Collapse Structural Conductor 80' 30" LP 80' 80' Surface 286' 20", 94#, H-40 286' 286' 520 1530 Intermediate 1934' 13-3/8"54.5#U-55 1934' 1762' 1130 2730 Production 3545' 7", 26#, N-80 3545' 2992' 5410 7240 Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 2426-76,2700-16,2893-2916 2177-2511' 2-7/8", 6.5# J-55 2291' Packers and SSSV Type: No SSSV. Packers and SSSV MD(ft)and ND(ft): No SSSV Baker Perm Seal-bore Pkr Packer at 2327'MD/2054'ND 12.Attachments: Description Summary of Proposal 5. 13.Well Class after proposed work: Detailed Operations Program in BOP Sketch ©- Exploratory ❑ Stratigraphic❑ Development 5 - Service ❑ 14.Estimated Date for 13-Sep-13 15.Well Status after proposed work: Commencing Operations: Oil ❑ Gas 5• WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: `C-S-3 WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: SG e�7 Z GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and corn ct to the best of my knowledge. Contact Ed Jones Email leiones(C7auroraPower.com Printed Name Geor ,. 'O.,. Title Manager, Engineering and Operations Signature Phone 907-277-1003 Date 9/4/2013 COMMISSION USE ONLY Conditions of appr.#: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: 1-2 S n) p 5 L Hof s r RECEIVED SEP 0 4 2013 /0- il° it uu�}�� r � � Spacing Exception Required? Yes [ No ❑ Subsequent Form Required: ! i s W � r � k � bb dd.."" u S 1 APPROVED BY Approved bi: l . COMMISSIONER THE COMMISSION Date: q_ —75 7-1-/S Submit Form and )11.b,\,,1 Form 10-403(-evised 10/2012) Appr v RfenisNdA tmonths frRo BD etecof OCT 1 approval. 20 j/ chma plicate �1vv RBDMS l� 1 • Aurora Gas, LLC September 4, 2013 Ms. Cathy Foerster, Chair ilk Alaska Oil and Gas Conservation Commission RECEIVED 333 West 7th Ave., Suite 100 a t.P 0 4 2013 Anchorage, Alaska 99501 AOGCO RE: Application for Sundry Approval Nicolai Creek Unit#2 Well PTD # 166-038 and API# 50-283-10021-00 Perforate New Intervals and Recomplete Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to add new perforated interval to this onshore gas development well in the Nicolai Creek South Field—Undesignated, on the west side of the Cook Inlet, northeast of the village of Tyonek. The well is now completed in Upper Tyonek Sands, the Carya 2-1.1 thru the Carya 2-2.3, and the planned perforations are shallower Upper Tyonek Sands, the Carya 2-1.0, additional perfs in the Carya 2-2.1, partial reperforating and adding additional perfs to the Carya 2-2.3 interval, all to test for gas. The AWS #1 rig will be used to recompleter this well, it is standing by for approvals following the drilling of the Nicolai Creek Unit #13. The rig's well control systems are on file with the Commission. The rig is expected to be ready for the work to start about September 13, 2013. (Due to logistics, the plan and preference is to do this work before the recently approved recompletion of the Lone Creek 3). Please find attached information as required by 20 AAC 25.280 for your review. Pertinent information attached to this application includes the following: 1) Form 10-403 Sundry Application 2) Proposed Summary and Detailed Workover Procedure 3) Schematics of the current and proposed wellbore and completion. 4) BOP Sketch If you have any questions or require additional information, please contact me at (907) 277-1003 or 907-351-8286 (cell) or Ed Jones at 713-899-8103. Sincerely, AURORA AS, L -George Pollock Manager, Engineering and Operations CC: DNR, MHT 6051 North Course Drive, Suite 200•Houston, Texas 77072•(281)495-9957•Fax(281)495-1473 1400 West Benson Blvd., Suite 410•Anchorage,Alaska 99503•(907)277-1003•Fax(907) 277-1006 • • • AURORA GAS, LLC RIG RECOMPLETION WORKOVER PROCEDURE NICOLAI CREEK UNIT#2 September 2013 Version 1.0 (9/4/13) CURRENT CONDITONS: CURRENT STATUS : SITP-400 psi; Flowing less than 100 mcfpd. KB=23.7 feet CASING: 7", 26#N-80 set at 3545'MD/2991' TVD. Cement Plug 3119'- 3527'. CURRENT PBTD: 3119' TUBING: 2-7/8", 6.5#J-55 8 rd EUE MOD, w/ packer fluid in tbg-csg annulus(weight unknown—maybe be as heavy as 10.5 ppg) above top packer and with: 2.313 X nipple at 2289', Locator sub at 2323', and Seal Assembly at 2327' w/5.5' seals PACKER: Baker SC-1 Permanent Packer at 2327' w/Mill-out extension and 3-1/2"tubing and pups, cross-overs, and 5"Meshrite screens to EOT at 2916" (see Baker completion details) CAPACITIES: 2-7/8" 6.5#Tubing: 0.00579 bbl/ft; Tubing-Casing Annulus: 0.0222 BPF; 7"26#Casing: 0.0382 bbl/ft. Tubing volume to Seal Assembly=13.5 bbl,Annular Volume to top Packer= 51.7 bbl; Casing Volume to top of Packer: 88.9 bbl PERFS: Carya 2-1.1 at 2426-2487'(open to screens—mostly depleted) Carya 2-1.2 at 2700-2716'(open to screens—mostly depleted) Carya 2-2.1 at 2893-2916'(open to screens—mostly depleted) Carya 2-2.3 at 3270-3315' (plugged back with 86 sx cement plug) NOTES: 1)Well deviated,maximum of 44 deg at 2525' MD. SUMMARY OF PLAN: Kill well,release packers, circulate out,pull tubing and seal assembly. Burn over and retrieve permanent packer and 589'of 3-1/2"tubing and screens. Drill out cement from 3119' to 3450'. Circulate clean with 9.3 ppg 3%KC1-NaC1 brine. Perforate: 3324-36', 3268-88', 2870-76', 2312-22', 2244-60', and 2198-2212' with 6 SPF with casing guns Pick up and run completion with 4 packers, screens, sliding sleeves to isolate open perforated intervals from new deeper perfs, and new shallower perfs. Set packers, swab in, and test each completion. DETAILED ROCEDURE: 1) Pick and move wellhouse. 2) Move in,rig up AWS #1 rig w/single workover pit for mud system(not AG mud system) and support equipment only as needed for workover(one gen set, 1 mud pump, etc.). Also, move in and spot Aurora Gas choke skid,test unit, and flare. • • 3) Starting with clean mud pit,mix 150 bbl (usable volume) 8.4 ppg 3%KC1 water(3%KC1- 11#/bbl),using clean produced water from tanks on location and add fresh water as needed. Open perfs are depleted and may have to deal with losses into depleted intervals later. 4) Set GE 2-way check in hanger. ND tree,NU 3000-psi BOPE. Test to 2500 psi (or as required by AOGCC Sundry approval). Pull 2-way check—release GE. 5) Screw into tubing hanger, and release hold downs. Unsting from packer—fluid in packer is expected to be heavier that KC1 water and will equalize. Reverse out—check returning fluid weight. If packer fluid brine is greater than 10 ppg, circulate/reverse out and save heavy brine into clean tiger tank(for use at Lone Creek 3). Circulate well with 3%KC1 water. Pull tubing, standing back tubing and laying down locator sub and seal assembly. 6) PU "Packer Plucker" and RIH on 2-7/8"tubing to tag packer at 2327'. Mill/burn over packer and retrieve packer with 589' of 3-1/2 tubing, cross-overs,4 5"Meshrite screens(5"LTC connections). Lay down packer and all below it. 7) PU 6-1/8"bit, 4-3/4"drill collars, and 4"drill pipe—run in hole to tag cement at 3119'. Circulate bottoms up. a. If losses are serious, greater than 5 BPH,pull a stand, and mix and circulate 20 bbl "Baraplug" LC pill if needed (see Notes below). 8) When losses are controlled, drill out cement to 3450', watching for gas when drilling through old perfs at 3270-3315'. Weight up with oilfield salt as needed—no more than 9.0 ppg weight is expected to be required. While drilling,mix and filter 150 bbl of 9.3 ppg 3%KC1-NaC1 brine (11#KC1 per bbl+ 50#NaC1 per bbl). Filter to 10 microns. 9) Circulate clean and replace drilling fluid with filtered 9.3 ppg brine. If losses are excessive,pump Baraplug pills as needed (see Note below). (Pump additional Baraplug before filtering). 10)RU perforators w/grease-injection lubricator. Run GR/CCL correlation log and correlate to correlation logs from 2002. a) PU 4" premium Deep-Penetrating perforating guns, test lubricator to 1500 psi, and RIH to perforate Carya 2-2.3 sand at 3324-3326 (10'—expected max pressure-8.85 ppg) w/ 6 SPF w/ 60-deg phasing. Watch for gas, pressures, and fluid level in casing while shooting. b) Perforate the"2-2.3 Sand" at 3268-3288 (20'—expected max pressure-8.85 ppg) >(� c) Perforate the"2-2,1 Sand" at 2870-2876' (6'—expected max pressure-9.0 ppg) �� d) Perforate the"2-1 .0 Sands" at 2312-2322' (10'—expected max pressure-9.2 ppg) e) And 2244-2260' (16') f) And 2198-2212' (14') g) POOH, LD perf guns, RD wireline. (6 runs, 76' of perforations). 11) PU casing scraper and bit and run thru new perfs, to tag bottom at 3450', and circulate wellbore clean. POH and LD bit. . 12) PU following completion BHA and RIH on 2-7/8"Mod tubing,visually inspecting and replacing rubber seal rings and questionable collars, as follows: a) 30' 3-1/2" Stratapack Screen(new—on hand at Moquawkie yard)w/bull plug on end; b) Cross-over: 3-1/2"NU pin X 2-7/8"box, c) 1 jt 2-7/8"tubing, d) 7"Arrowset mechanical packer with On-Off tool (w/2.31"X profile)to be set at about 3185', e) 8 jts 2-7/8"tubing f) 2-7/8" Sliding Sleeve to be set at+/-2930', • • g) 4 jts 2-7/8"tubing, h) Hydraulic-set packer to be set about 2805' i) 7 jts 2-7/8"tubing, j) 2-7/8" sliding sleeve at about 2585', k) 7 jts 2-7/8"tubing, 1) Expansion Joint or Safety Joint m) Hydraulic Packer at about 2365', n) 3 jts 2-7/8"tubing, o) Shrouded Sliding Sleeve at 2270', p) 2 jts 2-7/8"tubing, q) Hydraulic-set Packer to 2170' r) 1 jt 2-7/8"tubing, s) Sliding sleeve, ` t) 2-7/8"tubing to surface �S 13) Space out,land tubing, and lock'down.. RU Pollard run PX plug and prong and set in profile in On-Off tool at 3186'. RD Pollard. Pressure test tubing to 2500 psi,then pressure up to set hydraulic packers (against existing plug in profile in on-off tool). Bleed off pressure. Install BPV. ND BOP. NU and test tree. Pull BPV. (Be rigging up AG test choke manifold, separator, and flare , stack, connected with hardline during this time). le_S r IA- 4a 2-17 o µ°ll 14) RU Pollard slickline unit and lubricator. RIH w/retrieving tool and retrieve prong and plug at ( �`�`'%°S`'J 3186'. Run shifting tool and confirm all sliding sleeves are closed. POOH. RD Pollard(but do not release). 15)RU to swab and swab in Carya 2-2.3 perfs at 3268-3336' and test thru test separator. SEE 7€/5 SUPPLEMENTAL TEST PROCEDURE,Note II below. Allow to cleanup. SI for 1 hr buildup. Open to flow and allow to stabilize at about 80%(or more) of SITP. SI, and watch buildup for 1 hr. Do not kill well. 16)RU Pollard. Test lubricator to tubing pressure. RIH and reset PX plug and prong in On-Off toll profile at 3186'. Open sleeve at 2932' and test new 2-2.1 perfs at 2870-76' (lower pressure is v expected since it is commingled with open partially depleted perfs). RD Pollard. Test these perfs as in Step 15 above. Tubing s/b essentially dry so no swabbing should be needed,unless perfs are making water. 17)RU Pollard. RIH and close sleeve at 2932',bleed pressure down below 400 psi, and open sleeve at 2585' to blow down and get water off partially-depleted 2426-2716'. Do not test except to flow back any water and get SI pressure buildup. 18)RU Pollard. RIH and close sleeve at 2585' and open sleeve at 2270' to test new perf interval 2198- 2322' as in Step 15 above. NOTE: AWS rig can be released when 2 zones are successfully tested at rates above 1 MMcfpd each w/o significant drawdown (FTP>75% SIP). 19)Based on test results, determine initial configuration of well for production(probably deepest, driest interval) and RIH w/Pollard to pull plug and/or open sleeves to facilitate configuration. RD Pollard. RD AG test equipment. Turn well to operators to reconnect flowline and put to sales thru 3-10 production facility. Ed Jones (9/4/13) • • NOTES: I. BARAPLUG RECIPE System Formulation: Saturated Salt Water- .888 bbl Salt- 109 ppb System Formulation: Sized Salt Bridging Pill Product Concentration Saturated Brine 0.83 bbl Baradefoam HP 0.1 ppb Citric acid 0.5 ppb BARAZAN D+ 2.0 ppb N-DRIL HT+ 4 ppb caustic .1 ppb(to a 9.0 pH) Baraplug 20 30 ppb Baraplug 50 27.5 ppb Baraplug 6/300 10 ppb Aldacide G 0.1 ppb Special Mixing Instructions: • Mix in order as listed • Please note that we will manipulate the pH to speed the additions of polymer • A can of X-Cide 207 must be added to any pills mixed. Adjust the pH of the brine for the pill to a 5.0 or less with citric acid. Then the BARAZAN D+ and N- DRIL HT+ can be added rapidly though the hopper. After all the polymer is added, adjust the pH back up to a 9-9.5 with caustic. The polymer will then yield. Check the YP after adding the caustic. The YP should then be adjusted to the 35-40 range with BARAZAN D+ if needed. The Aldacide G should be mixed in all fluid entering the wellbore. If possible, add it in the suction pit or below the mud line (inline chemical injection pump on the suction?). The Mud Man will make all additions of Aldacide G or supervise closely. Further additions of fluids will require the additions of Aldacide G. When pumping a kill pill, remove suction and DP screens. Pump pill at a fast rate as this will help maintain the integrity of the pill. When the pill gets to the perfs slow the pumps down to 1-1.5 bbl/min. Continue pumping until 200-400 extra psi is observed. Shut the pump down and watch for the pressure to bleed off. Repeat this procedure until it takes 10-15 minutes for the pressure to bleed off. Be careful not to over displace while squeezing and wash the pill away. If no squeeze pressure can be obtained, stop pumping and let the pill soak into the perfs. 3% KCI Saturated NaCI brine: 0.888 bbls Water+11 ppb KCI+98 ppb NaCI Saturation will be a 9.9+ ppg MW 9.3 ppg 3 %KC1 NaCI Brine: 11 ppb KC1 and 55 ppb NaC1 • • II. TEST SUPPLEMENTAL PROCEDURE A. Prepare for test: 1)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; 2) Record test separator water meter reading; 3)install new chart on Barton recorder; 4)install fresh nitrogen bottle onto skid for instrumentation(or use separator pressure); 5) install Pollard SPIDR surface pressure recorder(or new 2000-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 6) confirm electric clock on chart recorder is on and set to 12 hrs. B. RU to swab. Swab in perfs below 2260-2362' and flow test until clean and stable, as follows: 1) swab in,unloading fluid to shaker/possum belly until well is gassing and/or kicks off to flow; 2)when significant gas is at surface(whether swabbing or flowing) or the well is flowing, divert flow to test separator: a) shut down momentarily to light flare stack, then bring back on, adjusting choke size until well is flowing strongly to cleanup,but holding significant back pressure on it(probably start at 24/64's and adjust accordingly, target flow at 75%of SITP (expect SITP to be 1000+ psi, so target stabilized flowing tubing pressure above 750 psi). bi) Flow for an hour or more and until rate and pressure have stabilized for 15 minutes (i.e.,pressure on SPYDR changes less than 2 or 3 psi in 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, up to 15 bbl or rate has stabilized . Flow for a minimum of 1 hour. Probably more (2-3 hours), depending upon water production and cleanup. c) Test meter has 1-1127 orifice in it Flow rate in mcf/day= static reading(blue)X differential reading(red)X , (if temperature reading(green) is 5.5-6.0, slightly higher for lower green reading and lower for higher green reading). 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 w/the Daniel Sr. orifice fitting. d) Catch water samples thru out(downstream of test separator)—have tested by mud man 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 8.5 ppg—if water is trending in that direction, continue to flow until these properties have stabilized, if the gas rate is above 1000 mcf/day. Keep last sample of produced water to send to lab in Anchorage—label thoroughly. 3) SI for pressure buildup (at least 2 times longer than flow period or until pressure is building at less than 1 psi/15 minutes on SPIDR). III. 10.4 ppg Brine Formula (to be provided by Baroid) • • Aurora Gas, LLC 30"Conductor set at 80'in 36"hole,cemented w/300 sx NICOLAI CREEK UNIT#2 PTD#: 168-038 20"94#Surface Casing set at L.API#: 50-283-10021-00-00 , 286'in 26"hole,cemented w/ DF 23.7 ft 650 sx (To be run September 2013) - - 13-3/8"54.5#Surface Casing set at 1934'.Cement w/1600 sx 2 7/8 65#8rd EUE J-55 Tubing 2-7/8" x 5-1/2"annulus 3343' displaced with 9.3 ppg 3%KCI- NaCI packer fluid j 1 S i Sliding Sleeve @ 2140' Hydraulic Packer at 2170' Carya 2-1.0 , 2198-2212' Shrouded Sliding Sleeve at 2244-2260' a 2270' 2312-2322' Hydraulic Set Packer @ 2370' Carya 2-1.1 w/Safety Joint below it 2426-2476' E�1 Sliding Sleeve at 2585' Carya 2-1.2 C! EXISTING PERFS 2700-2716' Hydraulic Packer set at 2805' Carya 2-2.1 Ness 2870-76' Sliding Sleeve at 2935' 2893-2916' Arrowset 1X Packer at 3185' With On-Off Tool Original Perfs:Carya 2-2.3 3270-3315' Cemented over with 87 sx Bal New perfs:Carya 2-2.3 3268-3288' 3324-3336' 3 1/2"Sand Control Screens at 3220-50' U EOT @ 3251' PBTD @ 3450'MD 7"26#J-55 Casing to 3545'MD cemented w/ 1500 sx Drill 9-7/8"Hole to 5011' y S- 561( MD/4102'TVD � e 35 K i . Nicolai Creek No. 2 nProposed Nicolai Creek Field Alaska © Current Production 2 7/8"Production Tubing 36"Hole 30"@ 80' <� i CMTD to surface t. W/300 SX Attachment I f 26"Hole I N of 20"94#@ 286' 5 SPF @ 298'Squeezed w/200 sx in 1991 CMTD to surface '„l$' W/650 SX :M.€ f 17 1/2"Hole p 6 .; 5 SPF @ 677'Squeezed w/215 sx in 1991 l TOC @-1900'MD 13 3/8"54.5#@ 1934 in 13 3/8"X 7"annulus CMTD W/1600 SX ) 2.313"ID X-Nipple at 2288.8' Permanent Packer at 2327' ' 5"Meshrite Screen Perforate @ 5 SPF 2426'- 2476' - a Perforate @ 5 SPF 2700'-2716' 9 7/8"Hole 0 wv F4 Perforate®5 SPF 2893'to 2916' Original production perforations 4 1/2 SPF 4 from 3270'to 3315'cemented over —_ 87 Sk Class"G"Cement Plug 3102'-3537' during 1991 Suspension Procedure Plug(Baffle Plate) 7"26#@ 3585'MD '_ .. ' @ 3543'MD CMTD W/1400 SX TD @ 5011'MD 4086'TVD ERAWNG NOT TO SCALE NICOLAI CREEK No.2 FAIRWEATHER E&P Rev.01/DHV 05-Sept-02 SERVICES INC. 0 1.• Aurora Well See Nice Rig No. 1: Proposed 3M BOP Configuration j,Lola, c --ctkc ' 2... Bell Nipple with flow line to pits Fill Up Line 3 �� 3M Schaffer Annular Preventer r rl , Pipe Rams sized 4i to work string. L -k 11"3M Double Gate w1Z 7/ 'pipe j 1 rams installed. 11"3M Mud Cross i Blind Rams 3^gpp fy{anua{Va{ve(Ghake Line) 3" 5M ydiauli Valve(!{ill Line) \ /'- 3" SM Hydiaulic Valve ` . i�+6. ,f 3 5M Hydrau3ic Valve (Kill line) . ` _. (` (Choke Line) 1.11 +( 1_ a"1 " '.I'I811 Fluid flow direction while reverse circulating 1 ii 1 fl // K '_144, / 1!1 ,f, 1 11 x /oa0 DS A- . i8I .ini Cl ill IF--1- B4 T B7 ( # 1OI = B9 �/ C2 74 11 II till r Sf1 B11 ` CX i0..1 lo ! �� B6 B5 1111 f 14; 1(11 B2 BID B BL 11 F>< . t c„ 3 M A5 =i1111..'. ii■ l�� B14 (i•L ll�! B13 MI `il it• A6 u 1 �,,,� , ,„,,,,4 lia.iii A2 v A3 A4 Al t 1 i 3/ it 13 II OD CSG 2-7/8' LID TSG --- OD CSG ALL D{ME 4SlONS ARE APPROX. (A/afi"fv,SGU/-G) �+ • 0 • Schwartz, Guy L (DOA) From: Schwartz,Guy L(DOA) Sent: Thursday, September 05, 2013 12:23 PM To: 'George Pollock'; Bettis, Patricia K(DOA) Cc: Ed Jones;Wallace,Chris D(DOA) Subject RE:Aurora Gas NC2 Sundry(PTD 166-038) George, You have verbal approval to proceed with the RWO as proposed in your sundry application. (#313-475) . You will not be able to test well until a spacing exemption is approved as we discussed on the phone. Please modify step 13 to include a pressure test of the upper packer(MIT-IA). 2000 psi/30 min. BOP test pressure is 2500psi as per your procedure. � / In regards to the Injection order for gas storage. The storage order SIO00 S has expired (per 20 AAC 25.252(j) since no 'k gas storage injection was started within 24 months of approval. If Nicolai Crk#2 is again considered for gas storage it /l� would need a complete re-evaluation and re-issue of the Storage order due to completion changes to the well. Regards, Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: George Pollock[mrn tao'gpo ccJ: m aurOr'i uu.i,r urn] Sent:Thursday, September 05, 2013 12:07 PM To: Schwartz, Guy L(DOA); Bettis, Patricia K(DOA) Cr.:Fd lnnc Subject: Aurora Gas NC2 Sundry Guy, Aurora Gas, LLC requests verbal approval of our sundry application for the rig recompletion of the Nicolai Creek#2 well. Note,this well is currently an active gas producing well.Although Aurora Gas, LLC has secured an Storage Injection Order for this well,no injection has taken place to date nor is planned to occur. Thank you for your prompt attention. Regards, George Pollock Manager, Production Operations & Engineering Aurora Gas, LW 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 1 • Bettis, Patricia K (DOA) From: Ed Jones [jejones @aurorapower.com] Sent: Thursday, September 05, 2013 1:52 PM To: Bettis, Patricia K(DOA) Cc: 'George Pollock'; 'Robert Pledger' Subject: RE: Nicolai Creek Unit 2: Sundry Application (PTD 166-038) Attachments: NEW NCU LOG CORRELATIONS_nov2006.ppt; NC Carya 2-1.1 Structure Map.pptx; NC 2 Proposed WBD 0913.docx; NC 1B Final WBD 0706.doc; NC 9 Completion Diagram 9-06.doc Patricia, The reason that no spacing exceptions are required is that the proposed new perforations are not open in any of the other wells in the Section,with the possible exception of the proposed perfs at 2870-76' MD/2467-72'TVD in the Carya 2-2.1 interval (f.k.a.T2200 Sand), which are covered by CO 478, I believe. (Note that the sand interval names have changed since CO 478 was requested). Attached are: 1) log cross-sections showing the NCU #2 and the NCU #1B, 2) a structure map of the Carya 2-1.1 sand, and 3)well bore diagrams for proposed for#2,current for#1B, and current for#9 (all three wells share the same pad--#1B and#2 are directional and#9 is a straight hole). The shallowest perfs in the#1B are in the Carya 2-1.2 at 2307-2370' MD/2254-2316'TVD(note that the KB elevations of#13 and #2 are 44' and 46' above MSL, so TVD's are directly comparable—the#9 has a KB elevation of only 26', so ND's are 20' deeper SS wise). The shallowest proposed perfs in the#2 are above this interval both geological and SS TVD. The deeper proposed perfs in the#2 are in the 2-2.3 interval, which is not perforated in the#113. Regarding the#9,the deepest perfs are at 1904' MD/TVD (-1878' SS TVD) in a Beluga sand,which is 171' above the shallowest possible Top of Tyonek–at 2075' MD/TVD (-2049' SS TVD). As I revisited this in response to your email, it appears that the top 2 sets of perfs proposed for#2 may actually be Beluga, as the Top of Tyonek in the#2 appears to be about 2286' MD/2025' TVD (-1979'SS TVD). However, these proposed perfs at 2198-2260' MD/ 1962-2006'TVD (- 1916'-1960' SS TVD) are only 63' above the Top of Tyonek. Thus, even if these are Beluga sands,they are not open in the#9. Also, it might be noted that the#2 is believed to be fault separated from both the#1B and the#9. Please let me know if you need more information, or if you believe that a spacing exception CO is still required. (I can put this all into a table [spreadsheet] if that would be helpful, i.e.,the formation intervals [names] and perforated or proposed to perforate depths in each well MD/TVD/and TVD subsea—let me know). Thanks, Ed J. Edward Jones President Aurora Gas, LLC 6051 North Course Dr.,Ste 200 Houston,TX 77072 281-495-9957 (0) 713-899-8103(C) From: Bettis, Patricia K (DOA) [mailto:Datricia.bettis @alaska.gov] Sent: Thursday, September 05, 2013 2:44 PM To: Ed Jones Subject: Nicolai Creek Unit 2: Sundry Application (PTD 166-038) Good morning Ed, Please justify why no spacing exceptions are required per Conservation Orders 478 and 478A, and regulation 20 AAC 25.055(a)(4). 1 • • Conservation Order 478 specified that the Nicolai Creek Unit Well No. 2 was proposed to be perforated in the T1900 sand @ -2,070',T2000 sand @ -2242', and T2200 sand @-2419'. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage,AK 99501 Tel: (907)793-1238 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. III 2 STRATIGRAPHIC SECTION, DATUMED ON TOP TYONEK FORMATION WEST TEXACO AURORA GAS TEXACO TEXACO EAST NICOLAI CREEK , 2217 FEET NICOLAI CREEK < 3240 FEET • NICOLAI CREEK < 2029 FEET > NICOLAI CREEK - UNIT-1A UNIT-1 B UNIT-6 UNIT-2 SE N I DATUMED ON TOP TYO K FORMATIOFI 2100 2300- £ rw TYONEK 2100- 2100: -.. (CARYA I-1) __ _. 2200_ ., 2200 _-_ ._._.. 2400 -2200- CARYA 2-l.1 -s_.r-_.� 2500- 2300_. y..... 2 __ F _ y 2400- - 2400 __- 2600 `T 2400- 4 Y! � CARYA 1-1.2 2500 . :. 2500 ---.. 2700- 2500 I. 2600- 1 2800 2800-- - - ■ 2800 __.__ - _.. ..: S CARYA 2-2 1 ▪ --- ar 2700 - - 2900- -- 2700- 2700 � 2600- 2800 - 30 - T __y CARYA 2-22 O p � -2800 .. f _r _2900 - 3100- i 2800- 2900- ) __ f • f 3000 3200- }S 3000_ 3000-I __ - -- -- - 3300 4 CARYA 2-2 3 3100- '> 3100 3100- .... L 3200 3400- 7 3200- _. 3.# - 3500- - P CARYA 2-3 CARYA 2-1.2 3 _ 3300- _..-3300- . } . 3400- - r1 f ._ -�...-- ---. 3400 3600- . ----- -------- - L 3400-il 7733 _ CARYA 1-5 I ( _ .. .. ... _ _ -.._... - --> STRUCTURAL SECTION WEST TEXACO AURORA GAS TEXACO TEXACO EAST NICOLAI CREEK UNIT-1A NICOLAI CREEK VNIT-1B NICOLAI CREEK UNIT-6 NICOLAI CREEK UNIT-2 OP MILD 1 -r a. °.'-° °r Y a°° .. °. ° ° R.° , or -P .°1-°.4° °°4° -1900• 1< °° . ° -1900 _2900 -2000- _ (CARYA 2-1) -2000• 2000 - e4RYA 2-1.1 2100 2190- :: =- 2100-:... ` --2200 -2200- '.�...._ t .' - 2200 -2200 CARYA 2-2.2 { -2300- -2300- w -2300- -2300- -2300 u_ w -2400• ' -2400.. .- ...-... _ ._... _2400- -2400_ in 2400 co m -2500 -._._ ..2500 - - -. - -- -2500 - _- -2500- -- -2500- CARYA 2-2.2 0. o -2600• 2800 2800 2800- 2600- — E -2700' -2700- _.-- - " --2700- s - -2700- ' CARYA 2-2.3 E • -2800• -2�- .. -2800 1~m- y -2800- - -2800- CARYA 2-3 -2900 _2900 ..r_ 2900 -2 — _ . III -3000 -�- zr- -3000 i -3000- -3000- -3100. .--, 9100.=- _._-- - - -3100 -3100- -f . __ _ CARYA 2-1.2 1 -3200• -3200-. _. - -3200 - y _.__. .....4200 -_--.------ -3200- -_.F . 1Q �.-_._ .._ _�t - -.�_ _ - 2-5.1 ��°° �' .3300 1d -3300- -3300- .. ■ STRATIGRAPHIC SECTION, DATUMED ON TOP TYONEK FORMATION NORTH SOUTH TEXACO TEXACO AURORA GAS TEXACO NICOLAI CREEK - 3016 FEET > NICOLAI CREEK 6769 FEET >NICOLAI CREEK F- 2688 FEET > NICOLAI CREEK UNIT-5 UNIT-3 UNIT-1B UNIT-2 �. or KILO o-r ° °T .. 1 2_° '°°-`''r°5'°°1° - - 1800-- -._: - ____ _---_ __-- - - ..._- 2300 >:.- � _ raw TYONEK SECTION 15'DATJMED ON TOP TYON:�, FO ATU N 1800 2100- (CARYA T-IJ T 1700- 2400 M - i. 1900 2200-4 SS!_- CARYA 2 1.1 __T. ,- 1800- �._�a 2500- �° _ Lf ..- __ 2909 -._._-__._.'t_._-_ s 2300- __ {, 1900._ .6.1-_____ -. ._. J 2800 ■ , i T 2100 r 2000- 3 2100 >,� ( -r - CARYA 2-1.2 t 2700- -,, , -2500 t t- 2200 5 --4" 2100- ft- 21100 L- FF _ j i w 2300 �� _.__ ____ 2200- -- -- 2800 f . - -__ CARYA 2-21 2900-LL °o .__._ ._... 2400 S._ - i _-_ , N � i'- _._ _._. _ ... .2399... --._._ ._. - _-__ ._._..-3009- � CARYA I-22 • 2500 . 2400_ 2900 3100 h �- 2990- I-- 2800 ,- °,., y 3200- ,� a 1 3000- __ __. _- .. _--[-;-- -._.t 2700 - - 3300 �` CARYA 2-2 3 2800- H.-2800 - 4 3100- Yy 3400" y .....- \ l ...:.41 CARYA 2-3 TEXACO { \ 3500- �� NICOLAI CREEK UNIT-3 �0° = a. ..ao DT L _:_. _ _. 3600- Z„ NORTH _ - ,..° . .. .. 3400 L \ -1400 -- ar _. _ TEXACO SOUTH NICOLAI CREEK UNIT-5 -1500 STRUCTURAL SECTION a. ° n°,Y & -. 1700 noa- ` -1100 AURORA GAS TEXACO =` 4 'f NICOLAI CREEK UNIT-1B NICOLAI CREEK UNIT-2 -1600' -1800- , -1800 A4-- R,�° or -,_ - �. ° T °° 5-t 900 1900 1 L. o �ooaoo 1900 ^° '_° s 2000 2000- > 2W0 -_ .2000 - _—._2000 (CARYA • F- i ""- - - -� '� -- CARYA 2-1.1 w " Lil -2100- 2100- _. -2100 __ --- _ -2100 --- -- -2100- s S -2200- -2200- r -2200 \ -2200 - -_ ---- -2200. CARYA 2-1.2 m 0 2300 a -2300-_ . _2300 ( -- =2300 L........ _......\ -2300 - o _ f___FI - - - --- --_ uarA z-T I 6 -2400- -2400- 2 -2400 r _.. - -2400 2400" _- l -2500 --- - -- -2500- CARYA 2.22 >▪ -2500- -2500- - 2500 r . D 2800 -2600- -2800" -M 1 t::� , 7 -2700 �_ - 27oo -c -2700 -2700 f -2000 € 2800 -s -2800 } T -2900- -2900- & _2800 t -2900 3000. {r 8000 s 3000- } i�'t'i . . Structure Ma p • • Nicolai Creek Carya 2- 1 . 1 (with all wells on) Grid:nicolai carve 2-11 depth_6sep2007(cliff)(lightGreen),Dsta Type Depth(Active Contour nicolai carp 2-1.1 depth 22Nov2009(cliff)(Black),Data Type:Depth),Version:Pre75 V la 0 a Efai. 6.1 LOD€` ix i 1Jp:El ,•°CJ Y S- IA gel larat XN: 239600 a ci®° Fee! t 1_it 1 � 1Pa • .000111141.114. ' 1369 • I � ;:� 7263 1558 853 ars/� Iv _ '111w3 I �1 1823, . ., , ,,�� 1837 . i _ .WC ,0 . 2316 2277 zs06 bib d 2601 \ ; 2696 2796 - zees I ,..--- ,,,,, )f 2820 V'' 3075 20,36 r-•.,1 , 0 D ' i 3189 NG`:11 _ ,po y'CJ fY9 3261 �- • ��.(��1. _<. �� ' -411 ■ If ., 3543 0 1 ,,r 1Y'v.(i. I / Y _ 10020 b ^ _, 3601 Sri` l (if j � r 3676 �': �� ;� <�.�. • r-1 ---. 1. . __ 1002.- - ,.� �,7 i_._-- � GD:a _ i� ' I ' 1111 , _ �*/'• 0 m 1 0 2563800- 1 + ..ul+. e 1 • �� ,\., hij_______.?,, � / :was I 8335.o- - - �// • ...,,,....„. -----' I., 1.4r(y17',/7 ,:.-- ' SP s y.G rv� Fix f 1 /J ,z'`:1098 20064 _' h�� / NCI)6572:14CO3.6S - h7 l B:e6 --- �/ I _Scale.,'625 X238958.81,Y:2567255,64 Feet,Lat 61 01860639,Lon¢151A7155347,Depth 2195 Feet C.\araaram Flles 1.861\KinodamS:t Cahrhars 2`,Shaded Colors 80.CLB,Ed Culture:FidW.s ---E�.,,,'.y, _ 4i,,io,a Gas L L C • • 2 7/8 6.5#8rd EUE J-55 Aurora Gas, LLC ,4 ..147 eti: , ..Nicolai Creek#9 Current Completion a � 13-3/8" 54.5#K-55 Conductor January 2013 ` driven to 100' RKB—12.68ft - PTD#202-208 :' A e'v PI#50-283-20102-0000 724- 8-1/2"Pilot Hole to 620',Hole opened to 12-1/4"w/Hole 111014 ) 9-5/8"36#J-55 Surface Casing set at 620' opener Shoe Joint is 47#with Butt Thread Beluga Tops I =; Tsuga 2.5 Tsuga 2.6 Tsuga 2.7 0 r WXA Sliding Sleeve @ 1,047' Tsuga 2.8 - , ' Hydro 1 Packer @ 1,089' Perfs kll 1148-1170' �( VXO Sliding Sleeve @ 1,130'(open) 1190-1200' 1219-1223' Blast joints across perforations 1248-1264' - �°°� VXO Sliding Sleeve @ 1,270'(open) 1'll Locator Seal Assembly w/ t� —�—� Appowpak Seal bore packer @ 1,283' Original AD-2 stop at 1480' Pulled 1/31/13 Perfs DD Pack-off at 1478' 205 psi to 180 psi 1320-1330' F. i A Stop at 1476`; 6'of fill, 1343-1393' 1407-1447' 0 VXO Sliding Sleeve @ 1,482'(Open) 0 1 Hydro I Hydraulic Set Packer @ -- - 1.495'iiirsi—Perfs 1552-1562' 1624-1630' ..° 1641-1662' -. 1748-1758' WXO Sliding Sleeve @ 1,796'(Open) 1768-1778' .'- 0 xa: Hydro I,hydraulic set packer @ 1,806 , w/XN Nipple and 2.205"NoGo @ 1,815' LV (open) Perfs 1827-1837' 2-7/8"x 3-1/2"x 4-1/2"XO and 10' in, iiiii `'` Stratapak screens @ 1827'and 1894' e.,. 1 .3.Tr...;e:. and bull plug in bottom @ 1904' 1894-1904' 7"23#J-55 LTC Casing to 2,098'MD (TVD) PBTD @ 2,054' Drill 8-1/2"Hole to 2,102' r-. • • Aurora Gas, LLC Nicolai Creek Unit No. 1-B Current Configuration (2013) 4 `, t Drilled 26"Hole - ' "_ 20"94#11-40 Conductor set `; at 232 Cmtd to surface N� �.�9r � �A,rto- � f � �. ; ". w/300 sx"G". t1 1- „iq tE1, 1 2-7/8"6.5#J-55 tbg to surface fro Drilled 17 1/2"Hole [ 13 3/8"54#J-55 Surface Csg at , 1,904'. Cmtd to surface w/ l'- "x.` ,„ 1,530 sx"G". "4 ! ' _''t_� �� ° Sliding Sleeve w/X-profile @ 2,263' Carya 2-1.2 Perfs: ft G-77 Packer @ 2,275' (closed) 2,307' 2,326'MD x 2,350'-2,370'MD (TVD 2,254'-2,316') a�- Sliding Sleeve w/X-profile @ 2,359' �.�=-- G-77 Packer @ 2,436' (Open) Carya 2-2.1 Perfs: 2,480'-2,486'MD ff. , . (TVD 2,426'-2,434') Carya 2-2.2 Perfs: ..-- 2,604'-2,622'MD ;I , (TVD 2,550' 2,568') -- F Sliding Sleeve w/X-profile @ 2,749' -- (open-1/13) '" 717 G-77 Packer @ 2,761' Carya 2-3 Perfs: X-nipple @ 2,774' ;- Ill 2,837'-2,842'MD 2,862'-2,867'MD -- 2,913'-2,918'MD - (TVD 2,783'-2,864') iii --��- VTA Packer @ 3,145' - XN Nipple @ 3,184'w/PX Plug .e, 0 ::: i' '''''' Set Carya 2-4.2 Perfs: 3,191'-3,211'MD Well completed with sand (TVD 3,137'-3,157') exclusion screens across the i indicated perforations,bottom Carya 2-5.1 Perfs: at 3396'. Jan 2013-tag at 3,371'-3,401'MD 4 3255' (TVD 3,307'-3,348') ' �` �M. Cement Retainer @ 3,500' Carya 2-6.1 Perfs: 3,560'-3,575'MD Lower 3 completions treated w/ (TVD 3,506'-3,521') - Weatherford Sand Aid 2010-11 Float collar @ 3,604'MD �� 1 Float shoe @ 3,648'MD xT 7"23#J-55 Production TD @ 3,672'MD(3,617'TVD) Csg @ 3,650'MD(3,595' TVD). Cmtd to surface w/ 82 bbls"G"lead at 12.5 ppg and 67 bbls"G"tail at 15.8 ppg. Fairweather E&P Services, Inc. Lone Creek No. 1 Rev. 1.0 1 7/31/2006 WJP Drawing Not To Scale • .. • • 2 7/8 6.5#8rd EUE J-55 Aurora Gas, LLC , ,,4, W-1 4.6 A ( r - ' Nicolai Creek#9 Current Completion „ 13-3/8 54.5#K-55 Conductor January 2013 driven to 100' RKB-12.68ft fr ,t _ PTD#202-208 ° � ;, API#50-283-20102-0000 "9 8-1/2"Pilot Hole to 620',Hole opened to 12-1/4"w/Hole 36#J-55 Surface Casing set at 620' opener , Shoe Joint is 47#with Butt Thread Beluga Tops Tsuga 2.5 r«°A rl Tsuga 2.6 Tsuga 2.7 El§ WXA Sliding Sleeve @ 1,047' Tsuga �a.., g �rl Hydro 1 Packer @ 1,089' Perfs /;l1 , - °' 1148-1170' VXO Sliding Sleeve @ 1,130'(open) 1190-1200' �' 1219-1223' Blast joints across perforations 1248-1264' _ - VXO Sliding Sleeve @ 1,270'(open) I Locator Seal Assembly w/ — Appowpak Seal bore packer @ 1,283' Original if AD-2 stop at 1480' Pulled 1/31/13 Perfs DD Pack-off at 1478' 205 psi to 180 psi 1320-1330' A Stop at 1476' 6'of fill. 1343-1393' �-` -"°°"g i _ 1407-1447' CR a VXO Sliding Sleeve @ 1,482'(Open) 412,r ��-�� Hydro I Hydraulic Set Packer @ 1� 1.495' Perfs 1552-1562' ;'. 1624-1630' 1641-1662' 1748-1758' 1768-1778' El§ WXO Sliding Sleeve @ 1,796'(Open) ��. Hydro I,hydraulic set packer @ 1,806 __ - w/XN Nipple and 2.205"NoGo @ 1,815' (open) Perfs 1827-1837' 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' ...°- , a 7"23#J-55 LTC Casing to 2,098'MD (TVD) PBTD @ 2,054' Drill 8-1/2"Hole to 2,102' f I II • • Bettis, Patricia K (DOA) From: Bettis, Patricia K(DOA) Sent: Thursday, September 05, 2013 11:44 AM To: 'Ed Jones' Subject: Nicolai Creek Unit 2: Sundry Application (PTD 166-038) Good morning Ed, Please justify why no spacing exceptions are required per Conservation Orders 478 and 478A, and regulation 20 AAC 25.055(a)(4). Conservation Order 478 specified that the Nicolai Creek Unit Well No. 2 was proposed to be perforated in the T1900 sand @ -2,070',T2000 sand @ -2242', and T2200 sand @-2419'. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Patricia Bettis at(907)793-1238 or patricia.bettis @alaska.gov. 1 Aurora gets AOGCC approval for sage -May 09, 2010 -Petroleum News• Page 1 of 4 AskChesapeake.com AlaskaMiniStorage.com Drilling Software Haynesville Shale In TX&LA Natural Alaska's largest self storage network Torque & drag, drilling hydraulics Gas Drilling News. Learn More with 5 convenient locations cementing, centralizer placement Today c+~-w ~.~~~:b.a l'~.1 - ~~ i~~e. ccm ;,,,dc, I'~i~.p,... ~,,,.__ ~~..~v~~ Ns. ~ C'es~_~c: ~.~ ::omlHay".eSVi, .E _._-. _._ Vol. 15, No. 19 N ` v ~ ~ r tO~ ~ 03~ Week of May 09, 2010 Providing coverage of Alaska and northern Canada's oil and gas industry Aurora gets AOGCC approval for storage With permission from Division of O&G, Aurora can begin third-party gas storage at a depleted reservoir in the Nicolai Creek unit Eric Lidji For Pets°oleum News ~~~~~ MAC 1 "1 t A reservoir in the Nicolai Creek unit meets the standards for natural gas storage, according to an April ruling from the Alaska Oil and Gas Conservation Commission. I The ruling allows operator Aurora Gas to inject gas from 2,426 feet to 2,916 feet into the South Undefined Gas Pool at the unit using the existing Nicolai Creek Unit No. 2 production well. That corresponds to a true vertical depth of about 2,141 feet. The NCU 2 well, drilled by Texaco in 1966, must undergo mechanical integrity testing before injections begin. Those tests must be repeated at least once every four years. ~ Aurora must also provide the AOGCC will an annual report showing that the !, injected natural gas volumes are remaining in the reservoir and not migrating underground. In an accompanying order, the AOGCC determined that portions of freshwater aquifers deeper than 2,000 feet in the NCU 2 wellbore aren't currently sources of drinking water because they contain hydrocarbons, have high salinity or are otherwise impractical. The Nicolai Creek unit is located on the west side of the Cook Inlet basin. Oil & Gas 2010 Oil and Natural Gas Boom The Motley Fool's New Free Report. www Fou .coy,- Boulder Petroleum Supplies See Us for Gas Station Equipment, Pumps, POS Systems and More! vw.~w.Li_tle;o~asEc~.pcie~i_.cc http://www.petroleumnews.com/pnads/502185257.shtml 5/8/2010 Aurora gets AOGCC approval for,,~orage -May 09, 2010 -Petroleum New The unit consists of two participating areas, North and South, separated by the Nicolai Cross Fault. NCU 2 is in the South participating area, where Aurora i plans to store up to 1 billion cubic feet of natural gas in three upper Carya sands of the Tyonek formation. According to the AOGCC, the NCU 2 well had produced 806 million cubic feet of gas by December 2009 and should produce around 947 mmcf total before being converted to an injection well. Working storage is expected to be between 600 mmcf and 700 mmcf. Aurora does not yet have a source of gas for storage, but will either store excess gas from its own production base or buy volumes from another producer or a utility in the region. Storage big during session Additional storage in Cook Inlet could smooth seasonal demand somewhat in the Southcentral region. Extreme temperature swings in the sub-Arctic mean far more natural gas is needed in winter than in summer, but declining deliverability and slim storage capacity make it harder to call up additional resources without damaging reservoirs. The Cook Inlet Recovery Act passed this year adds clarity to the regulatory process for storage facilities and creates a tax credit for gas storage opened between 2011 and 2015. Aurora still needs a storage lease froln the Alaska Division of Oil and Gas before it begins injections. As of press time, the division was still reviewing the application. Did you find this article interesting? Tweet it Di it ~ ~ i Submit it to another favorite Social Site or Article Directory. ~~~®®~®~ ©Q~®^~^~ Email it to an associa_ tc. Print this sto-y .,:° ,~~ _-.._ ,~ -- , F Jr'~.~J=..rakin~ , f ,~ ~ai.i:e« uu tE~.z_:_~ ~~:~__ Oil and Gas Pipeline Data High-Return Partnership Opportunity More USA, Canada, Mexico Pipeline Data Spatially Information Available on Site! accurate Detailed Data 0 Click here to mead the PDF version of th_i_s stogy. I Print this story Email it to an associate. Page 2 of 4 ~.~.,~ Psul tMMon, ~..~.~.. A•L ii KIA 1,907.348.1919 COYER-,ALL ~°'"Y Brown, .rth..w a~ f~~,~ 1.907.848.121!1 Innovative Building Solutions www.awerMi.~.t http://www.petroleumnews.com/pnads/502185257.shttnl 5/8/2010 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RECEIVED DEC 3 1 2003 " ~~~ W~n~~ 0 OP ~~ ~L1?~ !tOT~~ll~L T~~~~ ~~ ~9: ~ ~,~ ~ 1a. Test: I . Constant Time 0 Isochronal 0 Other -~- 2. Operator 5. Date Completed: 11. Penn it to Drill Number. Name: Aurora Gas, LLC 8/9/2002 166-038 3. Address: 6. Date TD Reached: 12. API Number: 10333 Richmond, Ste 710, Houston, TX 77042 10/24/1966 50- 283-1 0021-00 4a. location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number. Surface: 1999' FSL, 209' FWL, SEC 29 T11 N R12W, SM 24 NICOLAI CREEK UNIT #2 Top of Productive 8. Plug Back Depth (MD + 14. FieldlPool(s): TVD):3119' MD (2672' TVD) Horizon:.~ 1154' FSL, 702' FWL, SEC 29, T11N, R12 '; 9. Total Depth (MD + TVD): NICOLAI CREEK GAS FIELD Total Depth: 4b. location of Well (State Base Plane Coordinates): 5011' MD (4102' TVD) Surface: y- 2,565,250.463 Zone- 10. land Use Permit: 15. Property Designation: x- 241,545.305 ADL-17585 TPI: x- 241,944.90 y- 2,564.283.87 (mid) Zone- 16. Type of Completion (Describe): TotalDepth: x- 242,748.505 y- 2,562,964.463 Zone- Cased and perforated, wI sand control screens 17. Casing Size Weight per foot, lb. 1.0. in inches Set at ft. 19. Perforations: From To 7" 26 6,276 3545 18. Tubing Size Weight per foot, lb. I.D. in inches Set at ft. 2426-2476',2700-2716', 2893-2916' (MD) 2-7/8" 6,5 2.441 2327 20. Packer set at ft: 21. GOR cf/bbl: 22. API liquid Hydrocarbons: 23. Specific Gravity Flowing Fluid (G): 2327 NA NONE 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): Tubing [8) Casing D 77 p 1075 psia @ Datum 2309' TVDSS 15 psia 25. length of Flow Channel (l): Vertical Depth (H): Gg: % CO2: %N2: %H2S: Prover. Meter Run: Taps: 2671' 2309' 0.560 0 1.06 0 5.761" Flange 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow line X Orifice psig hw of psig of psig of Hr. No. Size (in.) Size (in.) 1. 5.761 X 2.0 524 .. 24 934 130 1.0 2. 5,761 X 2.0 524 .. 29 896 130 1.0 3. 5.761 X 2.0 508 .. 32 851 130 1.25 4. 5.761 X 2.0 487 .. 38 776 130 4.5 5. Basic Coefficient -,/ hwPm Pressure Flow Temp. Gravity Factor Super Comp. Rate of Flow (24-Hour) Pm Factor Factor Q,Mdd No. Fb or Fp Ft Fg Fpv 1. 4350 ? NOT AVAILABLE- CALCULATED ELECTRONICALLY BY ASRC WELL TEST UNIT 5510 3. 6490 4- 7410 ~ 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 671.84 4. Critical Temperature 343.48 5. ssion Form 10-421 Revised 2/2003 CONTINUED ON REVERSE SIDE Submit in Duplicate SCAN N E[); JAN 1 ¿1 2004 ORIGINAL Pf 1075 Pf2 1,155.625 Pc _1016 --- Pc2 1,033,256_- No. pt PF Pc2-Pt2 Pw Pw2 Pc2-PWZ Ps PS2 Pf2_Ps2 1. 949 900,601 131.655 1030 1,060.900 94,725 2. 911 829,921 202,335 1007 1,014,049 141.576 3. 866 749,956 282,300 979 958,441 197,184 4. 791 625,681 406,575 927 859,329 296,296 5. 25. AOF (Mcfd) ~~~~3 Remarks: n -.9.500 -- I hereby certify that the foreg . AOF Fb Fp Fg Fpv Ft G Gg GOR hw H L n Pa Pc Pf Pm Pr Ps pt Pw Q Tr T Z is true and correct to the best of my knowledge. Title É~ec. Vice P.!.esident ----- Date 12/~~E3 DEFINITIONS OF SYMBOLS Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the prod~.face were reduced to zero psia Basic orifice factor Mcfd/-ýhwPm Basic critical flow prover or positive choke factor Mcfd/psia Specific gravity factor, dimensionless Super compressibility factor= -{1/Z dimensionless Flowing temperature factor, dimensionless Specific gravity of flowing fluid (air=1.000), dimensionless Specific gravity of separator gas (air=1.00), dimensionless Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) Meter differential pressure, inches of water Vertical depth corresponding to L, feet (TVD) Length of flow channel, feet (MD) Exponent (slope) of back-pressure equation, dimensionless Field barometric pressure, psia Shut-in wellhead pressure, psia Shut-in pressure at vertical depth H, psia Static pressure at point of gas measurement, psia Reduced pressure, dimensionless Flowing pressure at vertical depth H, psia Flowing wellhead pressure, psia Static column wellhead pressure corresponding to Pt, psia Rate of flow, Mcfd (14,65 psia and 60 degrees F) Reduced temperature, dimensionless Absolute temperature, degrees Rankin 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 BOTTOM HOLE TEMP, of: GAS GRAVITY: H~ GRAVITY, 'Yw: CONDo GRAV., °API: TVD, FT: 2,309 MEAS. DEPTH, FT: 2,671 Condo Correl. (y/N): N Corrected- Tc, OR: 343.48 Corrected- Pc, Psia: 671.84 Pressure Base, Psis: 14.730 TUBING 10, IN.: t Wlchert.Azlzcôrrection fOr contaminants, If any ,-"... Ryder Scott ': Reservoir .' \..::.;.. (Public) ~..... (Protected) 77 0.560 1.005 WELL NAME: FIELD: LOCATION: RESERVOIR: NICOLAI CREEK UNIT NO.2 NICOLAI CREEK T11N, R12W SM. Kenai Borough, West Sdie Cook Inlet, Alaska Upper Tyonek, 2426.2916' MD 10,000 - - - - - - - - - . - . . , . . , , . . , , . . . ' . ' . . . ... .. ... SOUR GAS N2 CO2 H~ MOLE % 1.06 0.00 0.00 .., <:) ..- )( Options D Check, If Injection Well D Smooth Pipe Roughness ~ 8:. 1,000 "'; a. "'- a. 2.441 RESUL T8 AOF, Mcf/d: C: POINT NO. Test Data FLOWING (Automatic) Q, Mcf/d SCPO BWPO FTP, Psia WHT, of BHP, Psis SHUT-IN 0 0 0 1,016 25 1,075 --- 1 4,350 0 0 949 24 1,030 2 5,510 0 0 911 29 1,007 3 6,490 0 0 866 32 979 4 7,410 0 0 791 38 927 These results were prepared using Reservoir Solutions Software. This is not Ryder Scott work product. Job Log Job Log . Entry Time 11/21/03 0:30 11/21/03 4:00 11/21/035:10 11/21/03 5:30 11/21/03 5:56 11/21/03 6:45 11/21/03 7:30 11/21/03 7:45 11/21/03 8:30 11/21/03 8:40 11/21/03 8:50 11/21/03 9:00 11/21/03 9:07 11/21/03 9:30 11/21/03 9:45 11/21/03 10: 15 11/21/03 10:45 11/21/03 11:00 11/21/03 11:15 11/21/03 11 :30 11/21/03 11 :45 11/21/03 11:50 11/21/03 11:55 11/21/03 11:57 11/21/03 12:00 11/21/03 12:30 11/21/03 13:00 11/21/03 13 :02 11/21/03 13:05 11/21/03 13:30 11/21/03 14:00 11/21/03 14:30 11/21/03 15:00 11121/03 15:30 11121/03 16:00 11/21/03 16:30 11/21/03 17:00 11/21/03 17:30 11/21/03 17:31 11122/03 4:47 Comment Start rig up on inlet Rig up complete Open Well To Manifold for SIP. Open Well To Separator, Set Adjustable Choke to 14/64 2" Oriface plate Reset Totalizers, start 28/64 test End 28/64 Choke Test, Open Choke To 32/64. Reset Totalizer, Start 32/64 Choke Test. End 32/64 Choke Test. Closed. choke to 28/64.Rate too high for flare tip. Gas Gravity .572. Choke at 28/64 Shut well in to change flare tip. Lowered. Flare. Remove Flare Tip and Adapter Flange. Installed New Flare Tip. Raised. Flare. Shut Down Generator for Oil Check. Having Problems Re",Starting Generator. Generator Back On Line, Line Well Up To Unit. Bringing Well Back On Getting Hydrated. Started. Methanol injection. Set Choke To 32/64, Separator Building Pressure. Stabilizing Flow and Back Pressure. Set Choke To 36/64. Stabilizing New Choke Setting. Reset Totalizers, Start 36/64 Choke Test. End 36/64 Choke Test. Set Choke To 40/64. Stabilizing New Choke Setting. Reset Totalizers, Start 40/64 Choke Test. Well Stable Test In Progress. Well Stable Test In Progress. Well Stable Test In Progress. Well Stable Test In Progress. Tubing and Vessel Pressure Slowly Droping. Tubing and Vessel Pressure Slowly Droping. Tubing and Vessel Pressure Slowly Droping. End 40/64 Choke Test. SJI @ Choke Manifold, Monitor SII Pressure. End Monitoring WHP, Remove header on 1b, open SSV Page 1 ~ NC-02 NC-02 NC-02 NC-02 NC-02 NC-02 NC-02 NC-02 NC.,02 NC-02 NC-02 NC-02 NC-02 Nc',02 NC-02 NC-02 NC-02 NC-02 NC,,02 NC-02 NC-02 NC-02 NC-02 NC,,02 NC-02 NC-02 NC-02 NC-02 NC.,02 NC-02 NC-02 NC-02 NC-02 NC,,02 NC-02 NC-02 NC-02 NC-02 NC"O2 NC-02 15 Min Reads Well Head Skid BS&W Vessel Gas VVg"", ..., III"'" If A Of A Choke Cut Solids Carbolite Gas liquid Size Rate Increment Total Reading Time Location (Psig) (Pslg) (Psig) (DegF) Setting % % % (Psig) (DegF) (DegF) (In) (mmscffd) (mscffd) (mscffd) 11/21/035:15 NC-02 0 0 23 0 0 0.00% 0.00% 0.00% 0 46 53 1 0.00 0.00 0.00 11/21/035:30 NC-02 0 0 1001 0 14 0.00% 0.00% 0.00% 1 45 53 0 0.00 0.00 0.00 11/21/035:45 NC-02 0 0 1001 0 14 0.00% 0.00% 0.00% 531 54 58 0 0.01 0.00 0.00 11/21/03 6:00 NC-02 0 0 952 0 14 0.00% 0.00% 0.00% 499 32 40 0 0.01 0.00 0.01 11/21/036:15 NC-02 0 0 952 0 14 0.00% 0.00% 0.00% 508 26 35 0 0.01 0.00 0.06 11/21/036:30 NC-02 0 0 952 0 14 0.00% 0.00% 0.00% 510 25 34 0 0.01 0.00 0.11 Start 45 min 28/64 Choke Test 11/21/03 6:45 NC-02 0 0 983 0 28 0.00% 0.00% 0.00% 511 24 34 2 1.13 0.00 0.00 11/21/037:00 NC-02 0 0 930 0 28 0.00% 0.00% 0.00% 517 25 34 2 3.86 3.09 22.27 11/21/037:15 NC-02 0 0 930 0 28 0.00% 0.00% 0.00% 520 24 34 2 4.40 2.93 66.49 11/21/03 7:30 NC-02 0 0 934 0 28 0.00% 0.00% 0.00% 524 24 35 2 4.35 2.84 109.56 End 4S min 28/64 Choke Test, Start 45 Min 32/64 Choke Test. 11/21/037:45 NC-02 0 0 896 0 32 0,00% 0.00% 0.00% 525 26 36 2 4.71 0.00 0.00 11/21/03 8:00 NC-02 0 0 896 0 32 0.00% 0.00% 0.00% 526 27 38 2 5.49 3.67 54.86 11/21/03 8: 15 NC-02 0 0 896 0 32 0.00% 0.00% 0.00% 530 28 39 2 5.02 3.63 109.54 11/21/038:30 NC-02 0 0 896 0 32 0.00% 0.00% 0.00% 524 29 39 2 5.51 3.62 163.98 End 45 Min 32/64 Choke Test. 11/21/038:45 NC-02 0 0 919 0 28 0.00% 0.00% 0.00% 521 30 40 2 4.32 2.98 219.00 11/21/03 9:00 NC-02 0 0 919 0 28 0.00% 0.00% 0.00% 525 28 39 2 4.71 0.00 0.00 11/21/039:15 NC-02 0 0 4 0 28 0.00% 0.00% 0.00% 0 4 10 2 0.00 0.00 22.09 11/21/039:30 NC-02 0 0 4 0 28 0.00% 0.00% 0.00% 0 18 20 2 0.00 0.00 22.09 11121/03 9:45 NC-02 0 0 9 0 28 0.00% 0.00% 0.00% 0 23 25 2 0.00 0.00 22.09 11/21/03 10:00 NC-02 0 0 4 0 28 0.00% 0.00% 0.00% 1 25 28 2 0.00 0.00 22.09 11/21/03 10:15 NC-02 0 0 4 0 28 0.00% 0.00% 0.00% 0 27 30 2 0.00 0.00 22.09 11/21/03 10:30 NC-02 0 0 9 0 28 0.00% 0.00% 0.00% 0 28 32 2 0.00 0.00 22.09 11/21/03 10:45 NC-02 0 0 4 0 28 0.00% 0.00% 0.00% 0 29 33 2 0.00 0.00 22.09 11/21/03 11 :00 NC-02 0 0 4 0 28 0.00% 0.00% 0.00% 0 30 35 2 0.00 0.00 22.09 11/21/03 11: 15 NC-02 0 0 4 0 28 0.00% 0.00% 0.00% 0 31 36 2 0.00 0.00 22.09 11/21/03 11 :30 NC-02 0 0 9 0 28 0.00% 0.00% 0.00% 0 32 37 2 0.00 0.00 22,09 11/21/03 11 :45 NC-02 0 0 987 0 28 0.00% 0.00% 0.00% 59 27 35 2 0.02 0.01 22.20 11/21/03 12:00 NC-02 0 0 855 0 36 0.00% 0.00% 0.00% 499 25 35 2 6.69 4.67 53.53 11/21/03 12:15 NC-02 0 0 851 0 36 0.00% 0.00% 0.00% 508 29 40 2 6.76 4.71 120.16 Start 1/2 Hour 36/64 Choke Test. 11/21/03 12:30 NC-02 0 0 851 0 36 0.00% 0.00% 0.00% 513 31 41 2 6.58 0.00 0.00 11/21/03 12:45 NC-02 0 0 851 0 36 0.00% 0.00% 0.00% 509 31 42 2 6.51 4.52 68.07 11/21/03 13:00 NC-02 0 0 851 0 36 0.00% 0.00% 0.00% 508 32 43 2 6.49 4.51 135.80 End 1/2 Hour 36/64 Choke Test. 11/21/03 13:15 NC-02 0 0 799 0 40 0.00% 0.00% 0.00% 498 35 45 2 7.64 5.32 214.43 Start 4 Hour 40/64 Choke Test. 11/21/03 13:30 NC-02 0 0 799 0 40 0.00% 0.00% 0.00% 496 35 46 2 7.63 0.00 0.00 11/21/03 13:45 N C-02 0 0 795 0 40 0.00% 0.00% 0.00% 496 36 46 2 7.61 5.28 79.19 11/21/03 14 :00 NC-02 0 0 791 0 40 0.00% 0.00% 0.00% 496 36 47 2 7.59 5.27 158.34 11/21/03 14:15 NC-02 0 0 791 0 40 0.00% 0.00% 0.00% 496 36 47 2 7.58 5.27 237.38 11/21/03 14:30 NC-02 0 0 791 0 40 0.00% 0.00% 0.00% 495 36 48 2 7.57 5.26 316.30 11/21/03 14:45 NC-02 0 0 791 0 40 0.00% 0.00% 0.00% 494 37 48 2 7.55 5.24 395.04 11/21/03 15:00 NC-02 0 0 791 0 40 0.00% 0.00% 0,00% 494 37 48 2 7.53 5.23 473.61 11/21/03 15:15 NC-02 0 0 791 0 40 0.00% 0.00% 0.00% 493 37 48 2 7.52 5.22 552.03 11/21/03 15:30 NC-02 0 0 791 0 40 0.00% 0.00% 0.00% 492 37 49 2 7.51 5.21 630.31 11/21/03 15:45 NC-02 0 0 791 0 40 0.00% 0.00% 0.00% 492 38 49 2 7.49 5.20 708.42 11/21/03 16:00 NC-02 0 0 783 0 40 0.00% 0.00% 0.00% 491 38 49 2 7.48 5.20 786.41 Page 1 .. 15 Min Reads 11/21/03 16:15 NC-02 0 0 783 0 40 0.00% 0.00% 0.00% 490 38 49 2 11/21/03 16:30 NC-02 0 0 780 0 40 0.00% 0.00% 0.00% 490 38 49 2 11/21/03 16:45 NC-02 0 0 780 0 40 0.00% 0.00% 0.00% 489 38 49 2 11/21/03 17:00 NC-02 0 0 776 0 40 0.00% 0.00% 0.00% 488 38 49 2 11/21/03 17:15 NC-02 0 0 776 0 40 0.00% 0.00% 0.00% 487 38 50 2 11/21/03 17:30 NC-02 0 0 776 0 40 0.00% 0.00% 0.00% 487 38 50 2 End 4 Hour 40/64 Choke Test. 11/21/03 17:45 NC-02 0 0 949 0 40 0.00% 0.00% 0.00% 0 26 33 2 11/21/03 18:00 NC-02 0 0 952 0 40 0.00% 0.00% 0.00% 0 33 38 2 11/21/03 18:15 NC-02 0 0 952 0 40 0.00% 0.00% 0.00% 0 35 41 2 11/21/03 18:30 NC-02 0 0 952 0 40 0.00% 0.00% 0.00% 0 37 43 2 11/21/03 18:45 NC-02 0 0 952 0 40 0.00% 0.00% 0.00% 0 38 44 2 11/21/03 19:00 NC-02 0 0 957 0 40 0.00% 0.00% 0.00% 0 38 45 2 11/21/03 19: 15 NC-02 0 0 957 0 40 0.00% 0.00% 0.00% 0 39 46 2 11/21/03 19:30 NC-02 0 0 960 0 40 0.00% 0.00% 0.00% 0 40 47 2 11/21/03 19:45 NC-02 0 0 960 0 40 0.00% 0.00% 0.00% 0 40 48 2 11/21/03 20:00 NC-02 0 0 960 0 40 0.00% 0.00% 0.00% 0 41 49 2 11/21/0320:15 NC-02 0 0 960 0 40 0.00% 0.00% 0.00% 0 42 49 2 11/21/0320:30 NC-02 0 0 968 0 40 0.00% 0.00% 0.00% 0 42 50 2 11/21/0320:45 NC-02 968 11/21/0321:30 NC-02 967 11/21/0321:45 NC-02 967 11/21/03 22:00 NC-02 972 11/21/0322:15 NC-02 972 11/21/0322:30 NC-02 975 11/21/03 22:45 NC-02 975 11/21/0323:00 NC-02 975 11/21/0323:15 NC-02 975 11/21/0323:30 NC-02 978 11/21/0323:45 NC-02 978 11/22/03 0:00 NC-02 979 11/22/030:15 NC-02 979 11/22/03 0:30 NC-02 979 11/22/03 0:45 NC-02 979 11/22/03 1 :00 NC-02 983 11/22/03 1:15 NC-02 983 11/22/03 1 :30 NC-02 983 11/22/03 1:45 NC-02 983 11/22/03 2:00 NC-02 983 11/22/032:15 NC-02 983 11/22/03 2:30 NC-02 986 11/22/03 2:45 NC-02 986 11/22/033:00 NC-02 986 11/22/033:15 NC-02 986 11/22/033:30 NC-02 987 11/22/033:45 NC-02 987 11/22/03 4:00 NC-02 987 11/22/034:15 NC-02 987 11/22/03 4:30 NC-02 987 Page 2 7.47 5.19 864.29 7.46 5.18 942.02 7.44 5.17 1019.62 7.43 5.16 1097.11 7.42 5.15 1174.49 7.41 5.15 1251.74 0.00 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 DEÇ-22-03 09:27 AM INDUSTRIAL INSTRUMENT EG&G Chandler Engineering Model 292 BTU Analyzer Test time: Dec.12 03 11:12 Test #:1 Methane Bthane ( C6+ ) Moisture Nitrogen --- Standard/Dry Analysis--- Mole' BTU* R.Den.* GPM** 98.853 1000.75 0.5476 0.081 1.44 0.0008 0.0217 0.001 0.04 0.0000 0.0004 0.000 0.00 0.0000 1.065 0.00 0.0103 907 283 7766 P.06 Calibration #:Default Location No. :2 Saturated/Wet Analysis Mole\ BTU* R.Den.* 97.132 983.33 0.5380 0.080 1.41 0.0008 0.001 0.04 0.0000 1.740 0.88 0.0108 1.047 0.00 0.0101 Total 100.00 1002.2 0.5587 0.0221 100.00 * : Uncorrected tor compressibility at 60.0F & 14.730PSIA. **: Liquid Volume reported at 60.0F. Molar Mass = Relative Density = Compressibility Factor ~ Heating Value = Heating Value. Absolute Gas Density = Wobbe Index = Standard/Dry Analysis 16.183 0.5596 0.9980 23448. Btu/lb 1004.2 BtU/CF 42.8262 lbm/l000CF 1320.34 985.7 0.5598 Saturated/Wet Analysis 16.214 0.5608 0.9979 23015. Btu/lb 987.7 Btu/CF 42.9150 Ibm/1000CF C6+ Last Update: GPA 2261-~U. C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.Wt. AURORA GAS NCU #2 Sample Date: 11-22..03 Run Date: 12-12-03 Press: 550# RUN 1 92.00. Re: Nicolai Creek Production Subject: Re: Nicolai Creek Production From: Thomas Maunder <tom maunder@admin.state.ak.us> Date: Mon, 08 Dec 2003 10:12:22-0900 <steve_davies~admin.state.ak.us>,' Steve McMains <ste v e _mc mains~admin, state .ak. us> BCC:'Daniel T Seamount JR. <dan_seamount@admin.state.ak.us> Thanks much Duane. information. Tom Maunder, PE AOGCC duane vaagen wrote: Tom: We will look forward to receiving the testing Per our phone conversation this morning, this email is being submitted on behalf of Aurora Gas, LLC. We just recently wrapped up testing of the NCU lB, NCU 2, NCU 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 an& gathering lines to begin production from the (3) Nicolai Creek wells located in a cluster on the beach near Shirleyville. 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 lB, NCU 2, and NCU 9 have individual flow meters for production allocation and that there is a site master meter as well. 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. 1 of 2 12/8/2003 10:12 AM Page 1 of 1 Maunder, Thomas E (DOA} From: Ed Jones [jejones@aurorapower.com] Sent: Tuesday, August 26, 2003 6:21 PM r To: Tom Maunder ~~`~ ~~~ Cc: 'Duane Vaagen'; 'Andy Clifford'; Randy Jones; Scott Pfoff Subject: Production of the Nicolai Creek No. 1 B, 2, and 9 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 l: 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 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 c; J 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 #1. 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; 'jejones@aurorapower.com'; 'gspfoff@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~om them will receive a permit ~lication 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 i ~~ Maunder, Thomas E (DOA) From: Jeff Osborne [josborne@fairweather.com] Sent: Thursday, October 24, 2002 2:26 PM To: Tom Maunder (E-mail) Subject: Nicolai Creek #2 & #1 B Tom, FYI - Ed Jones, Auora Gas, has asked me to inform the commission that Aurora will be testing both NCU #2 and NCU #1B from October 24-26, 2002 (Thurs, Fri, Sat). While testing, gas will be flared. Anticiapated amounts are one million cubic feet per well for all three days. If you have any questions or concerns, please call or email at your convenience. Regards, Jeff Osborne Project Manager Fairweather E&P Services, Inc. josborneCfairweather.com (907) 258-3446 office (907) 441-6600 mobile 3 As-Built NCU 9 Subject: As-Built NCU 9 Date: Thu, 3 Apr 2003 08:34:04 -0900 From: duane vaagen <duane~fairweather. eom> To: 'Tom Maunder' <tom_maunder~admin.state.ak.us> 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 '._ "- ] Name: NCU 9 asbuilt.pdf ~NCU 9 asbuilt.pdt] Type: Acrobat (application/pdf) Encoding: base64 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-buiiting the NCU #8 and #9 locations, they as-built the #lB and #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 11/7/2002 3:51 PM hi o~ SEC~ON 30 r~ / / / / / / / / I / .-- ..- -" PAD LIMITS \ \ GRID N: 2565238.3:'14. ~9 ~l~lf \ 241533.129 ~_. GRID E: LAllTUDE: 61'00'48.409" LONGI'rUDE: - 151 '27'24. 459" LEGEND 0 r~ · scr ~/2 NOTES 1) B.~ OF I~X~IIDINA'IE$ IS ~J.~A ~TA1E ~ N~ ~ ~E ~ ~ IS ~ A ~ ~E ~ ~ HO. 312~. 4) ~ ~ ~ ~ ~ID. ELEV. 33.2 FT. MLLW~ \ _ ~ / GRID N: 2565284.791 \\ ~ "~ 295' FWL -~ ~1~/ GRID E:24.1620.232 SECTION 29 ~ / ~ LA~DE: 61'00'~.as6' ~ TO~SIHP 11 NOR~ / ...... / m ~ J LONGI~DE: -151'27'22.713" RANGE 12 ~ST / ZO1 PWL' / =J T ELEV. 33.6 FT. M~W ( 209' F~. ~1~ ~ j' tI SEWARD MERIDIAN, AK I 186' F~- =~ Ir ~ ~/ ~ ............ ~. r · / 1% I ~ID E:241585.426 I~ / ~ J [ ~J LA~OE: 61'00'4e.517" AIRSTRIP I~ /' / F % LONGI~DE:-151'27'23.402" I = / I I ~ ELEV. 32.9 FT. M~W ......... ~Q / / ~ .~o LiUITS ....... GRID :E' 24150~ 651 LA~DE: 6~'00'48.~05" 1999' FSL 2048' FSL LONGI~OE: -151'27'24.935" SECnON LINE -. S88'44'34"E PROTRACTED SECTION CORNER GRID N: 2563243.909 GRID E: 241284..057 LATITUDE: 61'00'28.720' LONGI'RJDE: - 151 '27'28.610" ~ BY Ho~z. SCN..[I' - 80' ~ NG 02.1,1~2 8HEET ALASKA OIL AND GAS CONSERVATION COMMISSION PETROLEUM WELL RECORD - Commission use only - 10/10/2002 PERMIT I API NUMBER NUMBER WELL WELL LEASE 2 020 ADL0017585 166-038-0 283-10021-00 NICOLAI CK UNIT OPERI OPERATOR I CODE I NAME CODE .......... 110800 AURORA GAS LLC +- GEOLOGIC ONOFF I MULTI ..... 820 COOK INLET BASIN ON -+ FLDPOL FIELD AND POOL CODE I -NAME ...... 560500 NICOLAI CREEK, UNDEFINED + 000000 000000 000000 000000 0000..00 _-.~ ........................... 1966.' 5011 DEr 1-GAS DEV 1-GAS DEV~~ '"~.~ R~ 56101 + PERMIT I PERMIT DA~ [ DATE DATE OF RECORD CONFID .......... I ..............., ~-'~-~.~ ......... ~ ............... 08/22/1966 08/22/1966 09/21/i.966'"--t0/23/196 10/13/2000 04325 Aurora Gas, LLC www. aurorapower, com 28-September-2002 Ms. Cammy Oechsli-Taylor, Chair Alaska Oil & Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: End of well completion report, Form 10-407 for NCU 2. Dear Commissioner Taylor: Aurora Gas, LLC hereby submits the required final completion paperwork for work done on the Nicolai Creek Unit No. 2 this past summer. Please find attached information required by 20 AAC 25.070 (3) for your review. Pertinent information attached includes the following: 1) Two (2) originals: AOGCC Form 10-407 for the well; 2) Two (2) copies: Description of well work activities with summary of daily well operation, including diagrams of final well configuration. This well was tested briefly during perforating operations but has not undergone a full multi-point back-pressure test. In the interest of safety and economies, full production testing will occur when other well work activities are completed on the site and rig equipment has been removed. Results of this testing will then be reported when available. If you have any questions or require additional information, please contact the undersigned at (713)977-5799, or Duane Vaagen at (907) 258-3446. Sincerely, Aurora Gas, LLC ///~.~ Edward Jones {.~xecutive Vice Pre~ CC: Andy Clifford Duane Vaagen RECEIVED SEP 30 2002 OR. gI .IAL Oil,& Gas gons. ~mimbmlon Anchorage 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 , STATE OF ALASKA , ,,'" ALASKA O~' ~ND GAS CONSERVATION (~' AMISSlON ' WELl. COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL: GAS: X SUSPENDED: ABANDONED: SERVICE: 2. Name o~ Operator 7. Permit Number Aurora Gas LLC 166-038 3. Address 8. APl Number Resolution Plaza, Suite 710, Anchorage AK 99501 50- 283-10021-00 , 4. Location of well at surface 9. Unit or Lease Name 1999' FSL, 209' FWL, S29, T11N, R12 W SM ASP~~PE 241533.13 Nicolai Creek Unit At Top Producing Inlerval At 2426' MD ~ ...... ; 10. Well Number 1154' FSL, 702' FWL, S29, T11N, R12W SM ~ D,.~ .,~. i NCU ft2 At Total Depth At PBTD 3119' MDI ........ 11. Field and Pool s o, 5. Elevation in feet (indicate KB, DF, etc.) 16. Le~jnd Serial No. Nicelai Creek Gas Field 23.?' DFI ADL 17585 5011' MD (4102' TVD,) 3119' MD (2672' TVD) Yes: No: X NA feet MD NA 22. Type Electric or Other Logs Run GR/CCL Correlation 7129/2002 23. CASING, LINER AND CEMENTING RECORD SE'I'rING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED ~ . , , 30' LP 0 80' 36' 300 sx 0 20" 94~' H-40 '0 286' 26' 650 sx 0 13 3/8' 54.5ft U-55 0 1934. 17 1/2' 1600 sx ' 0' , , 7' 26~ N-80 0 3545' 9 7~8" 1500 sx 0 , , ~ , 24. Perforatio~ts open to Production (MD+'~VD of Top and Bottom and 25. ' TUBING RECORD ' ' ' interval, size and number) SIZE , DEP'~'H SET (MD) PACKER SET (MD) 2 7~8' 2290.6' 232.7'.26' · . ,, 2426' - 2476' MD (2141' - 2177' TVD) 5 SPF 4 112 HSD 2700' - 2716' MD (2342' - 2355' TVD) 5 SPF 4 112 HSD 26. ' ACID, FRACTURE, 'CEMENT SQUEEZE, ETC. 2893' - 2916' MD (2493' - 2511' TVD) 5 SPF 4 1/2 HSD DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED · , , , ,, · , '27. ' PRoDuCTION TEsT Da{e First Production ' ' I Method Of operation (Flowing, gas lift, etc.) ' ' ~,Flowing Gas through Choke and Seperator Date of Test · Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF ~ATER-BBL CHOKE SIZE ~ GAS-OIL RATIO ' TEST PERIOD => 0 0I NA Flow Tubing Casing Pressure ' CALCULATED OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-APl (~=orr) ' ' Press. 0 24-HOUR RATE --> 0 0 0 NA ~8.' ' ' CORE DATA ' Brief d~ScrJption of lithOlogy, porosity, fractures, apparent dips' and presence Of oil, gas or w;,ter. Submit cora chips." None R ' Ei'VED SEP 30' 2002 Alasla 011 & 6~ ~ns. Gommi~ior~ Anchorage Form 10-407 Rev. 7-140 CONTINUED ON REVERSE SIDE Submit in duplicate NAME Include interval tested, pressure date, all fluids recovered and gravity, ME. AS. DEPTH TRUE VERT. DEPTH GOR, and lime of each phase. Perfs @ 'Tyonek 2426' - 2476' 2141' - 2177' Flow I hr on 36164" choke, FTP 700 psi, rate 2.29 mmcfd. Flow I hr on 40/64" choke, FTP 725 psi, rate 3.13 mmcfd. Flow 1 hron 32/64" choke, FTP 760 psi, rate 3.18 mmcfd. SITP at 1 min, 920 psi. SlTP at 2 min, 930 psi. SITP at 15 min, 960 psi. SITP at 1 hour 960 psi. Totel water produced during test, 34 bbls. Perfs ~} Tyonek 2700' - 2716' 2342' - 2355' Flow 15 min on 28164" choke, FTP 480 psi, rate 3.656 mmcfd. Flow 1.5 hour 20/64" choke. FTP 550 psi and rate 4.26 mmcfd. Flow -45 rain 12/64" choke, FTP 875 psi and rate 1.76 mmcfd until choke washed out. SITP at I min 940 psi, 30 min SITP 995 psi, 1 hour SITP 1010 psi. Totel water recovery during test 19.24 bbl. Perfs ~} Tyonek 2893' - 2916' !2493' - 2510' Flow test 1 hour thru 28164" choke. FTP 849 psi. Rate 4.7 - 4.8 mmcfd. SITP 1090 after I hour. Total water produced during test, 12 - 14 bbls. Separator water meter not working. SEP 30' Alaaka Oil & Ga; Cons, Comrmss~or '31. LIST OF A~ACHME~T$ ' ' ' Wellbore schematic, Completion telly, Summary of Rig Workover Operations , INSTRUCTIONS General: This form is designed for submitting a complete and correct well cemplefion report and Icg 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 stete 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 (DF, KB, etc.). Item 23: Attached supplementel records for this well should show the details of any multiple stege 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. Form 10-407 Item 28: If no cores teken, indicate "none". WELL RE-ENTRY AND RE-COMPLETION REPORT NICOLAI CREEK UNIT NO. 2 Shirleyville, Alaska .~Aurora Gas, LLC 26-September-2002 Background Information: The Nicolai Creek Unit No. 2 well which was drilled in 1966, was suspended in 1991 by placing a series of cement retainers and cement plugs in the wellbore. Aurora Gas LLC submitted and received approval of an Application for Sundry Approval submitted to re- enter and re-complete the well as a gas producer. Well re-entry and re-completion activities on the Nicolai Creek Unit No. 2 began on July 16th, 2002 when the rig, Aurora Well Service Rig No. 1 and ancillary equipment were mobilized across the Cook Inlet via barge and transported to the well site. The location was prepared by laying down a gee-textile felt and herculite to create an impermeable barrier between the rig and ground. The rig, tanks and pumps were then moved into place and the perimeter was blocked with sills to provide a berm of sufficient size to contain a possible spill. The following well work summary details the re-entry 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: 16-July-2002 Mobilize rig across Cook Inlet via barge from OSK dock in Nikiski to Tyonek. Rig components then moved to NCU 2 well site. Secondary containment placed (felt and herculite) on ground and rig mats placed. Move in rig and RU. 17-July-2002 Spot tanks, haul in brine and continue RU. 18-July-2002 RU, install BOPE, choke manifold and kill line. Install rig floor. 19-July-2002 Continue RU, prepare for BOP test. 20-July-2002 Continue RU, prepare for BOP test, conduct preliminary BOP test. 21-July-2002 BOP test with AOGCC witness, test all equipment 250/3000 PSI. All tested successfully. Informed state would require annular preventer. Originally OK'd to nm double gate / rotating head assembly. Raise rig floor to allow access and modify stack. 22-July-2002 Finish RU with annular on BOP, test all, OK. Re-install floor, and finish plumbing. RU and test power swivel, OK. Prepare to drill out. 23-July-2002 24-July-2002 25-July-2002 26-July-2002 27-July-2002 28-July-2002 29-July-2002 Test annular to 1500 psi and retest accumulator unit, OK. RU to drill cement with conventional circulation. PU 6 1/8" bit, DC and power swivel, drlg cement. Break tour for 24 hour rig operations. Drill hard cement to 230 ft. RU for 2 7/8" work string and reverse circulation. Install packoff/rotating head assembly. Drill to top of 1 st retainer at 240 ft. Drill out retainer, retainer rotating, vary parameters to break up. Circulate retainer debris to surface, clean well, shut in and flow check for 10 min. Drill cmt to 287 ft, POOH for bit. RIH w/bit No. 2, service rig and drill cement to 553 ft. Drill into void and lose 30 bbls mud. Circulate and regain 100 % circulation. Drill cement to top of retainer No. 2 at 585 ft. Circulate hole clean and POOH for mill. PU and RIH with mill and proceed to mill up retainer. Begin drilling cement again and drill to 645 ft. Drill cement to 773 ft. Single in hole to tag cement at 992 ft. Drill up cement stringer to 1050 ft. Single in hole to 1844 ft, RU power swivel and wash to 2800 ft. Condition mud, prepare to wash out settled barite. Wash / ream settled material to 2943 ft. Repair pumps, clean hole to 3119.5 ft, tag hard cement. Circulate hole clean, test casing to 1500 psi, OK.. Clean out pits and swap over to clean 3% KCL. POOH for 7 in casing scraper nm. POOH, LD mill and PU 7" casing scraper. RIH to 3119 fi, no fill, circulate hole clean. Continue to circulate hole clean, stop circulation for flow check, POOH and LD BHA. Repair valve on choke manifold, repair accumulator system and perform BOP test. Repair accumulator unit. Remove Washington rotating head and prepare for e-line logs. RU Schlumberger, RIH Run #1 GR / CCL correlation log from 3119 to surface. Install test plug in wellhead, replace innermost kill line valve on BOP stack. Re-test stack 250 / 3000 PSI for 15 minutes, OK. Prepare for perforating nm #1. Hold safety meeting, RU Schlumberger and RIH. Perforate Tyonek formation from 2916' - 2893' w/5 SPF, 4 ½ HSD. Immediate pressure at surface to 150 psi and rising. Close blind rams and attempt to remove e- line lubricator. Annular preventer would not open completely. Trouble shoot accumulator unit, found regulator had failed. Swap control lines to unused / alternate control valve. Determine seals on annular preventer blown. Pull lubricator free with rig blocks. LD all e-line equipment, all shots fired. Install 2 7/8" tubing joint with collar at bottom, safety valve on top and close pipe rams on same to insure dual barrier at surface with blinds and pipe rams closed. 30-July-2002 31-July-2002 01-Aug-2002 02-Aug-2002 03-Aug-2002 Well pressure build to 770 psi and stable. Repair mud pump #1, clean mud tank and prepare to build kill fluid system. Plumb in test separator. Nipple up rotating head and wait on barge with kill fluid chemicals and pump for kill operations. Hold safety meeting, prepare KCL / Bromide 10.5 ppg kill fluid. Hold another safety meeting, commence well kill with bullhead method, pumping at 2.4 bpm / 1500 psi. Total fluid pumped 115 bbls. Close in well, observe press drop to 200 psi / 1 hr. Bleed to "0" psi, well dead. RU and RIH with packer / swab assembly. Set packer at 2800', prepare to swab in well. Monitor well and wait until AM for beginning swab operations. Attempt test on packer at 2800', leaks. Multiple attempts from 2800' - 250' unsuccessful. RIH to 3075', set packer and test OK. POOH and test at 193', packer leaks. POOH and LD packer, RIH with 1 jt tubing and leave as kill string while working on packer. Dismantle and inspect packer. Rebuild and configure as RH set RBP. RIH with RBP and set at 2809 fi, pressure up and test annulus at 1000 psi, holds. Release packer and circulate / condition wellbore fluids. Re-set packer and RU for swab operations. Hold safety meeting, swab in well and flow test. Well swabbed in with 2 runs from 900'. Flow well 2 hrs for clean up. Test through 28/64" choke for 1 hour. FTP steady at 840 psi with flow at 4.8 mmcfd. SITP immediately at 1080 psi, and build to' 1090 in hour. Kill well, POOH. RIH, set RBP at 2800', spot 4 sks sand on top of plug, POOH for perforating nm #2. Install test plug in stack, RU and test Schlumberger lubricator to 1000 psi. LD lubricator and remove test plug. Hold safety meeting, RU and re-install lubricator, RIH with e-line and perforate 2716' - 2700' at 5 SPF with 4 ~A HSD guns. Check for and observe no flow or pressure build-up after perforating. POOH LD perforating equipment and lubricator. Rill and set RBP at 2647'. RU and prepare to swab in well. Test lubricator to 1000 psi. Observe well and wait until AM to begin swab and test operations. Swab in well with 2 runs from 1100'. Well kicked off flowing. Flow well 15 minutes on 28/64" choke. FTP recorded at 480 psi with rate at 3.65 mmcfd. Reduce choke to 20/64" flowed 1 ~A hour 04-Aug-2002 05-Aug-2002 06-Aug-2002 07-Aug-2002 08-Aug-2002 09-Aug-2002 with FTP to 550 psi, and rate at 4.26 mmcfd. Shut in well and observe SITP at 940 psi after 1 minute SI. At 1 hour SITP recorded at 1010 psi. Kill well, POOH lay out packer, RIH and retrieve bridge plug, circulate out gas below packer and condition wellbore fluids. Re-set plug at 2615', spot 4 sks sand on top of plug and POOH. Troubleshoot and repair accumulator unit and annular preventer. Well sealed with downhole BP and blind rams. Troubleshoot and repair accumulator unit and annular preventer. Well sealed with downhole BP and blind rams. Finish rePairs on accumulator and annular preventer. Pressure test all OK. Install lubricator and RU Schlumberger for perforation mn #3. RIH and perforate 2426' - 2476' at 5 spf, 4 ~A HSD guns. No pressure build or flow observed at surface. POOH and RD e-line. RIH, set packer and swab in well. Initial SITP after gas to surface 800 psi. Flow one hour on 36/64" choke with 700 psi FTP and 2.29 mmcfd. Open choke to 40/64" and observe FTP of 725 psi and rate at 3.13 mmcfd for one hour. Reduce choke to 32/64" and observe FTP of 760 psi and rate at 3.17 mmefd. Observe small amount of water produced throughout three hour test. SITP of 920 psi at 1 minute, 930 psi at 2 minutes, 960 psi at 15 minutes and 960 psi at 1 hour. Kill well, circulate condition fluids, unseat packer and POOH with same. Continue POOH, LD packer. RIH with retrieving tool for RBP, circulate out sand, balance packer pressure, pull free. Strip in well to 3040' and tag fill. Hold safety meeting, kill well, circulate out and condition well fluids. POOH and LD BHA. RU and RIH with 7" casing scraper, tag fill at 3040'. Wash sands to 3119'. Appears to be 90% formation sand coming back at surface. Circulate, clean pits and build completion fluid. Continue circulate and build fluid. POOH, LD 7" casing scraper and BHA. RU floor for completion, PU and assemble Meshrite screen completion and BHA. RIH and follow with 2 7/8" tubing. Set packer and hang off screen completion assembly at 2327' POOH with 2 7/8" tubing and LD collars. PU seal assembly, R/H, stab in, space out for tubing hanger. PU and unseat from seal, circulate / condition well fluids, displace well with Concor 303A packer fluid. Drop rod and test tubing to 3000 psi. RU and RIH with wireline to retrieve rod / plug from x-nipple. Make up tubing hanger, stab seal assembly and land tubing with slight compression on packer. Lock down tubing hanger, set BPV, nipple down BOPE, nipple up production tree, and test all to 3000 psi / 15 minutes, OK. Release rig for move to NCU lA. Proposed Current Nicolai Creek No. 2 Nicolai Creek Field Alaska Production ~,~,/ 2 718" Production Tubing J 36" Hole 30" @ 80' CMT'D to surface W/300 SX 26" Hole Attachment I 20" 94# @ 286' CMT'D to surface W/650 SX 5 SPF @ 298' Squeezed w/200 sx in 1991 17 112" Hole 5 SPF @ 677' Squeezed wi 215 sx in 1991 13 3/8" 54.5# @ 1934' CMT'D W/1600 SX 5" Meshrite Screen 9 718"Hole TOC @ ~ 1900' M D in 13 318" X 7" annulus 2.313" ID X-Nipple at 2288.8' Packer at 2327' Perforate @ 5 SPF 2426' - 2476' Perforate @ 5 SPF 2700' - 2716' Perforate @ 5 SPF 2893' to 2916' Original production perforations 4 112 SPF from 3270' to 3315' cemented over during 1991 Suspension Procedure 7" 26~ @ 3585' M D CMT'D WI1400 SX TD @ 5011' M D 4086' 'rVD 87 Sk Class "G" Cement Plug 3102' - 3537' Plug (Baffle Plate) {~ 3543' M D DRAWING NOT TO SCA LE FAII~WEA THER E&P SERVICES ZNC. NICOLAI CREEK No. 2 [ Rev. 01 / DHV 05-Sept-O2 [ AURORA GAS LLC NICOLAI CREEK # 2 2-9/16" 5,000 Tree Run 7-1/16" 3,000 2-9/16" 5,000 Wing 2-1/16" 5,000 13-5/8" 3,00O 2-1 / 16" 5,000 13-3/8 CSG .~ 7".CSG 2-7/8" TBG ~ CAME RON David 8hsw,~x:horage ,Ak O4/O4/O2 / / / / / SECTION 30 SECTION 31 NOTES I) .BASIS OF COORDINATES IS ALASKA STATE pLANE NAD 27 'ZONE' 4. ANO IS FROM A DIRECT TIE TO ADL NO. 31270. 2) BASIS OF ELEVATION IS FROM DIRECT TIDAL OBSERVATION ON g-22-93, DATUM IS MLLW. ALL ELEVATIONS SHOt~IN HEREON WERE TAKEN ON GROUNO. 3) SECTION LINES ~HOWN HEREON ARE BASED ON PROTRACTED VALUES. 4,) 8EARtNGS SHOVIN HEREON ARE GRID. ~9"W ' j GRID N: 25652,.38.314. _ _ _ .. / GRID E:24.1533.129 ' ' j' LATITUDE: 61'00'48.409" . /,, LONGITUDE: - 151'27'24.459" .' ~ . ELEV. 33.2 FT. MLLW ] ' . \ ' ' . /-'-- WELL #6 .. \ / ~_j,~f GRIO E: 24-1620.252 ' \, ~ ' ' "~ 295' F'WL.. " / /. GRID N:2565284.791 , / ~. LATITUDE: 61'00'4.8.886" \ ' ?) 261' FWL / . ~_j ~r- LONGITUDE: -151'27'22.713" \' ~- 209' FWL . =_/j&~ . {~ ' · ELEV. 33.6 FT..MLLW ' 186' FWL IF i/! ~, GR~D N: 256524.8.120 ~. GRID E: 24.1585.4.26 ~ LATITUDE: 61'00'48.517" ' ~._ LONGITUDE: -151'27'23.402" ELEV. 32.9 FT. MLLW ' PAD LIMITS 1999' FSL SECTION 29 2010' FSL 2048' FSL GRID N: 2565238.429 GRID E: 24.1509.651 LATITUDE: 61'00'48.405" LONGITUDE: - 151'27'24.935" ELEV. 32.5 FT. MLLW SECTION 29 TOWNSIHP 11 NORTH RANGE 12 WEST SEWARD MERIDIAN, AK AIRSTRIP SECTION 32 PROTRACTED SECTION CORNER GRID N: 256,3243.909 GRID E: 24128¢.057 LATITUDE: 61'00'28.720" LONGITUDE: - 151'27'28.6] 0" 1999' FSL SECTION LINE s88'44'3 "E J · To: Tom Maunder AOGCC RECEIVED AUG 0 0 From: David Morris Drlg Supervisor Fairweather Aurora Gas, LLC NCU ~r2 & #1A Tom, Per our phone conversation, this date, Aug 19, 2002, ! submit the following per your request. There have been minor incidents relating to well control that have been quickly resolved with immediate safety meetings and training, in response to our conversation about two particular incidents, following is a bdef summary. Incident #1: Following a perf job, we realized an instant increase in wellbore pressure. With the blind rams closed against presssure, we had difficulty removing the Schlumberger lubricator from a tight annular packoff rubber. As a second barrier, I installed a pup joint with safety valve, and dosed pipe rams on the pup. ( Collar on bottom also, will not pass rams ). Sometime later, I heard the aux air pumps running on the Koomey unit. I investigated, and found them running out of control, ( Someone had opened the air bypass ), and manifold pressure was rising to 4000 psi. I immediately had an emergency safety meeting with drillers, pushers, and roughnecks, explaining the danger of damaging the Koomey with pressure on the well. I also removed the bypass valve completely. Incident #2: AWS driller had been pulling out of the hole with packer / test assembly, when I noticed the crew lining the mud pump up on the well. He had failed to fill the hole and had pressure at surface. Safety valve was stabbed, and the stripper head was holding annulus pressure. I informed him that filling the hole was far too late, as we now had a well "kill" to perform, not a simple hole fill. i killed the well, and resumed tdp out of hole. No further mishaps. Respectfully, David K. Morris ALAS~ OIL AND GAS CONSERVATION COPl~vIISSION / / / i / TONY KNOWLES, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 August 20, 2002 Mr. Ed Jones Vice President Aurora Gas 1029 West 3~d Avenue, Ste 220 Anchorage AK 99501 Dear Mr. Jones: AOGCC has conducted 2 on-site inspections at the Nicolai Creek Unit (NCU) #2 since work began 'in mid July. The purpose of the inspections has been to assure that the operations are being conducted "...in a safe and skillful manner in accordance with good oil field engineering practices..." [20 AAC 25.526]. One focus of the inspections has been the proper installation and maintenance of the required well control equipment. Both Inspectors documented various items needing repair and also observed rig crews' behavior. There was quite a contrast in the observation conducted prior to beginning the operations and after well work had begun that calls into question Aurora's commitment to maintaining a safe operation. The AOGCC is concerned and is initiating an investigation regarding the conduct of operations at NCU #2. By copy of this letter, Aurora Gas is directed to provide the Commission copies of the operational records of the activities on the recently completed NCU #2. The operational records include, but are not limited to, the IADC tower sheets, any "companion" drilling/work reports, drilling fluid records, geolograph charts, pit level records, waste disposal records and any other documents or records that would help understand the sequence of events during the work on Nicolai Creek #2. Copies of well control training certificates for the key individuals (Company Men, Toolpushers and Drillers) are also requested. Please provide this information to the Commission no later than 12:00 noon, August 22, 2002. Please be aware that if the Commission determines there was a violation or a failure to comply with a statuei regulation, Commission Order or permit approval, the Commission Ed Jones ( {" August 20, 2002 Page 2 of 2 may revoke or suspend a permit approval, impose civil penalties or require corrective action or remedial work. If you have any questions, please contact Tom Maunder at 793- 1250 or Jim Regg at 793-1236. ~ammy Oechsli Taylor) Chair Sincerely, Daniel T. Seamount, Jr. Commissioner Ru~ 0.2 02 01:43p p.1 Attention Mr Tom Maunder RECEIVED AUG 0 From ' Dave Morris Aurora Gas, NCU #2 Ru~ 02 02 01:44p po2 John Spaulding, I apologize again for you not receiving the test info on BOPE repairs. As I said, I'm on a cell phone modem here, and my computer only connects at 4600 on the best day. Maybe that's why you did not receive the Email. We have a fax machine now, so in the future I will fax all correspondence that way. Please understand, I would not deliberately refuse to send these test results. I realize the importance of this information to you and the state of Alaska. We repaired the annular regulator, replaced the inner kill line valve, and re-tested entire BOP as requested. All tests were successful. Again, my apologies for the inconvenience. Regards, Dave Morris Aurora Gas, LCC ,RuC 02, 02 01:44p STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Repo~ p.3 OPERATION: Drlg:_____ Drlg Contractor. Operator. ~ ,, Well Name: Casing Size: 7 Test: ~itial IEPll I . , Workover: X Aurora Well Sen"vice Rig No. Aurora Gas LCC NCU ~2 Set @ 3,585 Weekly X Other PTD # Rep.: Rig Rep.: Location: Sec. DATE: 7/29/2002 '166.038 Rig Ph.# 907-943-5027 Ed Jones David Morris 29 T. 11N R. `12W Meddian SM MISC. INSPECTIONS: Location Gen.: OK Housekeeping: ,O,K (Gert) PTD On Location YES Standing Order Posted Well Sign YES ! Dd. Rig OK Hazard Sec. , ,,,,, BOP STACK: Annular Preventer f Pipe Rams f Lower Pipe Rams ·. Blind Rams 1 Choke Ln. Valves `1 ---:--~: ~ .... HCR Valves f . . Kill Line Valves 2 Check Valve Quan. Test Press. 200/'1500 2OO/30OO 2OO/3OOO 2OO/3OOO P/F P P P FLOOR SAFETY VALVES: Upper Kelly / IBOP Lower Kelly I IBOP `1 Bali Type ' ;/' Inside BOP `1 Test Quan. Pressure 20013000 200130OO 20013000 P/F CHOKE MANIFOLD: No. Valves ff No. Flanges 52 Manual Chokes `1 Hydraulic Chokes `1 Test Pressure 200/3000 200/3~ 2OO/3OO0 200/3000 PIF P P P ACCUMULATOR SYSTEM: ...... :...-: System Pressure 3100 [ P Pressure After Closure 1750[, P MUD SYSTEM: Visual Alarm 200 psi Attained After Closure '/ minutes 50 sec. Trip Tank N/A OK System PressUre Attained 2 minutes 55 sec. Pit Level Indicators OK OK Blincl Switch Covers: Master: YES Remote: YES Flow Indicator , ,, OK , OK Nitgn, Btl's: 12120 9aI Meth Gas Detector O__.~K .... OK 'lg00 psi .... Psig. H2S Gas Detector OK OK , . i,u ,, "' ..... ::-. ':'-' ....... ~ ....... ." ' '." .... . · " ' .TEST RESUL~rS. .. .' . : " Number of Failures: 3. ,Test Time: ll,0'"'H0Um. Number of valves tested f4 Repair Or' ReplaCement of'Faile~' Equipment will be made within f days~ Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office ati 'Fax No. 276-7542 Inspector North SlOpe Pager No. 659-3607 or 3687 if your call is not returned by the inspector wi~in 12 hours please contact the P. I. Supervisor at 279-1433 REMARKS: ___. Annular regulator failed, repaired,_m-tested following day. Inner kill valve i inner choke valve ieaked.~G ,re,.ased choke va..l,,ve, replaced kilt valve following day. Re-tested all cornpo-n~'-S'~°ii°wing day:~ '. ' Ali tests su, ccessfu/., Distribution: grig-Welt File c - Oper./Rig c- Database c -Trip Rpt File c- Inspector F!~021L (~e. v,. ! 2~4.,) STATE wITNESS REQUI~'D? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Witnessed By: John Spautding Blank BQp T~.~ ,Rug 02. 02 01:44p 1:,.4 iRIG NAME DATE INITIAL RIG-UP PRECHARGE TEST Accumulator working pressure 3000 psi Recommended pre, barge pressure 1000 psi 1. Close offpower supply to ail accumulator pumps. 2. Release accumulator fluid system pressure to reservoir using manifold bleeder valve. 3. Remove protective cap from accumulator. 4. Attach precharge manifold with test gauge. Record acxual pressure and adjusted pressure below. A~ua]"' Aclju~ed ...... Actual " A~Usted Pressure Pressure Pressure Pressure I 1050 11 1000 ,., 2 1050 12 1000 3 1000 13 4 1050 ......... 14 ' '' , 5 1000 15 6 1000 16 ? oso · I ...... . ] .... ,J,' 8 1050{ I$ 9 I000 [ I9 ~ o _ ~ ooo ...... l, , 29 .... Maximum Acceptable Precharge Pressure ] 100 psi Minimum Acceptable Precharge Pressure 900 psi NOTE: 1) ~) 4) ~) ?) Pressure may vary with ambient temperature changes. Only nitrogen gas can be used to precharge the accumulator. Remove suction strainers and clean. Test must be repeated every 30 days. TOOL PUSHER ;Ioe Kunsman RIG NO. I DATE 7 / 29/02 .Ru~ 02,02 01:~5p AURORA WELL SERVICES, LLC. CLOSING SYSTEM PUMP CAPACITY TEST AIR AND ELECTRIC SYSTEM (PREFERRED SYSTEM) 1. .Remove accumulator unit from service. (Shut in precharge bottles) 2. Ele~,'tric pump system only (shut offair supply to air pump); open the hydraulically - operated gate valve; close the annular preventer; maintain minimum of 1200 psi on closing system manifold throughout the test, within two minutes or less. Time 1 rain 55 sec Pressure I750 3. Air pumps only. Same requirements as #2. Time 2 rain lsec Pressure 1550 NOTE: EACH INDEPENDENT PUMP SYSTEM MUST BE ABLE TO SATISFY THESE REQUIREMENTS. TOOLPUSHER Joe Kusman AURORA WELL SERVICES, LLC. ~A u ~ 02, 01: 46p ACCUMULATOR VOLUM~ TEST 1. Position joint ofdriI1 pipe in stack. 2. Close offpower supply to ali accumulator pumps. 3. Record initial accumulator pressure (working pressure of accumulator). 4. Adjust annular regulator to 1500 psi. 5. Close control valves one at a time in sequence starting at bottom preventer. Open hydraulic operatin§ valve. Re,rd time required to close each one. NOTE: In order to simulate volume requirements for blind rams and any other ram, preventer is not closed. The pipe ram preventer can be opened and closed as required. #1 Bottom preventer time 8 sec #2 Preventer time #3 Preventer time #4 Preventer time 10se~ Annular time 18 sec HCR Valve 2 sec 6. Record final accumulator pressure 7. Minimum final accumulator pressure After test · 1500 psi represents 50% excess volume required. · Accumulator working pressure is 3000 psi. Precharge I000 psi NOTE: Sizej __]13M 1750 ..... 1500 If test pressure is below I500 psi, it may be an indication of incorrect precharge, insufficient accumulator volume, a faulty gauge, a preventer seal leak, or line leak. The closing system must be capable of closing each ram preventer within 30 seconds. Closing time for annular should not exceed 30 seconds for annular preventer smaller than 20 inches and 45 seconds for annular preventers 20 inches and larger. TOOLPUSHER Joe Kusman AURORA WELL SERVICES, LLC. ./'RE: Nicolai Creek #2 and the Rig Subject: RE: Nicolai Creek #2 and the Rig Date: Wed, 15 May 2002 10:33:11 -0800 From: duane vaagen <duane@fairweather. com> To: 'Tom Maunder' <tom_maunder(~admin.state.ak.us> Tom: Aurora Gas LLC has teamed up with Boelens Well Service out of Thermopolis WY and dedicated a rig, now known as Aurora Well Service Rig 1, for work in Alaska. The rig, a Franks Model 300 with a 96' 215K mast, has been completely rebuilt in anticipation of doing work for both Aurora and other operators as well, should the opportunity come up. Attached; please find digital photos. The rig will be equipped with a Bowen power swivel and most of the procedures will be performed in a reverse circulating mode. We do not have an actual scaled drawing of the rig and ancillary equipment as set up at this time. Just a preliminary drawing of the planned layout. This whole thing with the BOPE is still a work in progress. The BOP and Choke diagrams pretty much depict our planned approach, though the actual equipment has not been purchased yet. At this time it is Aurora's intent to use an 11" double gate 5M rated set of rams (3M shorty if we can locate one) with a rotating head as an alternative to an annular preventer (is this OK?). Records indicate maximum recorded pressures of 1625 psi when the well was initially tested in the zones to be produced. As soon as the actual equipment has been purchased we will get a copy of the specifications and ratings to you, this applies to the accumulator unit as well. The mud pit is being built as I write this. The design calls for a -228 bbl pit with dividers and gates. The suction and settling sections will be 80+ bbls each and the shaker pit will be - 40 bbls. An additional -200 bbl pit will be set up in conjunction with the mud pit and will be used to catch cuffings (1/2 of the pit) and the other half will be used for flare). Regarding the pit monitoring equipment, we intend to use a system from Quadco for pit level and well monitoring. The rig should arrive in the state some time in June, at which time it will be moved to a yard in Nikiski and will be completely set up. At that time, the pit monitoring system as well as the gas monitoring system will be ~ted and perhaps installed. The gas monitoring system will utilize H2S and Combustible (Methane) detectors placed in the cellar, at the rig floor level and on the shaker pit. Once we know we have all components accounted for, the rig will then be mobilized across the Inlet for work. On the well testing and atmospheric gas buster issue, we were thinking that while testing during the re-completion process, we would test with the coke upstream of the gas buster. This would leave the gas buster in a Iow pressure condition and allow us to get a handle on how much water we were getting back during the flow test. We will check to ver'~y that the gas buster will handle the volumetric through put before we do this though. Appreciate the quick initial preview of the Sundry submittal. As soon I can get some equipment specifications, I'll forward that on to you. Thanks, Duane ..... Original Message .... From: Tom Maunder [mailto:tom maunder~admin.state.ak, uS] 1 of 2 6/18/2002 1:46 PM RE: Nicolai Creek #2 and the Rig Sent: Monday, May 13, 2002 1:35 PM To: Duane Vaagen Subject: Nicolai Creek #2 and the Rig Duane, I just got the program for Nicolai Creek #2 and have a couple of questions. 1--I knew you (or Aurora) planned to bring up a rig. Could you please provide some information regarding it. This should include drawings of the well control equipment (some provided) and the pits and what provisions there are for necessary pit monitoring equipment/ 2--Your stack drawing has 2 rams and a rotating head. Although you are not planning to make new hole, you will be drilling out plugs. Is the rotating head an alternative to an annular? 3--In your program, you propose to test using the rig gas buster. This is unusual especially with the plan to flow the well at 800 psi. Gas busters that I am familiar with are atmospheric pressure vessels designed to allow small amounts of gas to be released from drilling fluids. I don't think up to 1MM cuft is a small amount of gas. Please look at these issues and give me a call and we can discuss. Thanks. Tom Maunder, PE AOGCC [-~.~loversize Ioad.JPG Name: oversize Ioad. JPG Type: JPEG Image (imageljpeg) EnCoding: base64 oversizeIoad3.JPG Name: oversize Ioad3.JPG Type: JPEG Image (image/jpeg) Encoding: base64 [~ oversize Ioad4.JPG Name: oversize Ioad4.JPG Type: JPEG Image (image/jpeg) Encoding: base64 r~-~. oversize Ioad5.JPG Name: oversize Ioad5.JPG Type: JPEG Image (image/jjpeg) Encoding: base64 r,-~. oversize Ioad6.JPG'l EnCoding: base64 Name: oversize Ioad6.JPG Type: JPEG Image (imageljpeg) '1' Name: PA8MdPmp01.jpg ~PA8MdPmD01 .i[x~I Type: JPEG Image (image/jpeg) I Encoding: base64 Name: PA8MdPmp02.jpg ~PA8MdPmD02.i[~_~ Type: JPEG Image (image/jpeg). Encoding: base64 2 of 2 6118/2002 1:46 PI~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 1. Type of Request: [ ] Abandon [ ] Suspend [ ] Plugging [ ] '13me Extension [X ] Perforate [ ] Alter Casing [ ] Repair Well [ ] Pull Tubing [ ] Variance [ ] Other [ ] Change Approved Pro~lram [ I Operation Shutdown IX ] Re- Enter Suspended Well [ ] Stimulate Annular Injection 2. Name of Operator 5. Type of well: 6. Datum Elevation (DF or KB) Aurora Gas, LLC [X] Development 46' RKB [ ] Explorator~ 3. Address 10333 Richmond Ave [ ] Stratigraphic 7. Unit or Property Name _ Suite 710 [ ] Service Nicolai Creek Unil Houston, TX 77042 4. Location of well at surfac~ 8. Well Number 2018' N, 205' E from SW Corner, Sec 29, T11N, R12W, SM 2 At top of productive interval (3315'i 9. Permit Nurnber~ 685' N, 983' E from SW Comer, Sec 29, T11N, R12W, SM 166-038 At effective depth (3540') **Well currently plugged back to surface I10. APl Number 583' N, 1060' E from SW Corner, Sec 29, T11N, R12W, SM 50-283-1.0021-00 At total depth (5011') 11. Field and Pool 246' S, 1603' E of NW Comer, Sec 32, T11N, R12W~ SM Nicolai Creek 12_ Prasent. well coni:lition summaB Total depth: measured .5011 feet .Plugs (measured) Baffle Plate 3537', 3102'-3537' true vertical 4102 feet Retainers @ 590' & 248' Effective depth: measured 3540 feet 590°-677', 248'-298', Surface - 248' .true vertical 2999 .feet Junk (measured) None Casing' Length Size Cemented M D TVD Structural Conductor 58' 30" 300 SX 80' 80' Surface' 266' 20" 650 SX 286' 286' · intermediate .1916' 1 3-318" .1600 SX .1934' 1773' Production 3569' 7" 1500 SX 3585' 3035' Liner Perforation depth: measured 298', 5 spf, squeezed, 677' 5 spf, squeezed, 3270'-3315' 2 ~,~eCe~t V ED True vertical 298', 5 spf, squeezed, 677' 5 spf, squeezed, 2790'-2826" 2 spf, cemm3tad MAY 200 . Tubing (size, grade and measured depth) None Alaska Oil & Gas C(~ns. CommissiO~ Packers. and. SSSV (type and. measured, depth). None AltCtl0Fag9 13. Attachments [X] Description of Summary Proposal [ X] Detailed Operations Program [ X] BOP Sketch 14. Estimated date for commencing operation 15-J un-02 15. Status of well classification as: 1'6. If'proposal'was verball'y approved [ ] Oil' [ ]'Gas [X] Suspended' Name of approver Date Approved Service ...... ' Contact Engineer NamelNumber: Ed Jonpr~ 713-977'5799 Prepared By NamelNumber: Duane vaagenlD07-258-3446 17. I'hereby certifier the~re,going is tru~ {~nd/~orrect to the best of my knowledge Signed ~..-'~~ ~ 4'""/ /., J. Edged Jo~e~ . . ' ,/'/ "' Title Vice President . . Date ~.~//'~-//'~ , // /_/ u.. Conditions of Al:i~oval: Notify Com~d'ssion so representative.r~a witness ~3~,{~[::)~ ~1~ .~J~.. IApproval No...~e~ -/~..~ ' Plug integrity ' SOP'Test ~,~ ' Location' Clearance Mechanical Integrity Test; . . v ' Subsequent,form required. 1~ Ong~nal ~ By Approved by order of the Commission Camay Ola~di T, fld~W' Commissioner Date Form 10-403 Rev. 06115188 ' ' - Sul~ n~t' Ir~ Friplicate ORIGINAL AURORA GAS Proposal for Well Re-Entry and Workover Nicolai Creek Unit No. 2 PTD 66-38 APl No. 283-10021 1.0 Background Information and Present Condition The Nicolai Creek Unit No. 2 well was spudded by Texaco Inc., on September 21, 1966 from a surface location at the end of the Shirleyville airstrip adjacent to Cook Inlet. The well was directionally drilled in a south easterly direction under the mud fiats of Cook Inlet and achieved a total depth of 5;011' MD (4,086' TVD) on October 12, 1966. After casing was nm and cemented, the well was perforated from 3270 - 3315 feet, tested and put on production from October 1968 through November 1969. The well was shut in from December 1969 through December 1991. On July 15, 1988 Unocal and Marathon Oil Company acquired the Nicolai Creek Unit fi'om Texaco Inc. and Mobil Oil Company. Due to poor operating economics at the time, the decision was made to plug and suspend all well's in the Nicolai Creek Unit Until such time that the economics of producing them improved. Nicolai Creek No. 2 was ~i subsequently re-entered in September 1991, the tubing pulled and cement plugs plac~d for suspension of the well. Aurora Gas, LLC became operator of the Unit in the year 2000 and is now planning on re-entering and re- completing the well as a gas production well. All depths referenced in this application are based on original RKB, which was approximately 46.00 feet AMSL, with a surface grade elevation recorded as being 30.4 feet AMSL. A 20 inch conductor isiset at 286 feet and cemented to surface. 13 3/8 inch surface casing is set at 1934 feet and is cemented to surface also. The well was drilled to 5011 feet MD (4086 feet TVD) prior to running the 7 inch production casing which is set at 3550 feet and cemented with 1500 sacks of cement. A cement bond log showed cement from 1900- 3550 feet, with g6od bond characteristics from 2500 - 3550 feet. In 1991, the well was re-entered to l~lug for suspension. An 87 sack balanced cement plug of 15.8 ppg class "G" cement Was placed ~om 3102 - 3537 feet to cover the original open production perforation. The 7 inch casing was then perforated with 5 spf at 677 feet, a cement retainer was set at 590 feet and after an unsuccessful attempt at breaking circulation up the annulus,. 215 sacks of 15.8 ppg Class "G" cement were pumped through the retainer to squeeze cement the 7 inch x 13 3/8 inch annulus. After un-stinging, 10 sacks of cement wer~ placed on top of the retainer. The 7 inch casing was then perforated with 5 SPF at 298 feet, a cement retainer was set at 248 feet, circulation was established up the 7 ~X 13 3/8 inch annulus and 135 sacks of 15.8 ppg class "G" cement were pumped with cement observed at the surface. The annulus valve was then closed at surface and a 200 sack squeeze job was performed on the perforations and annulus with 15.8 ppg Class "G" cement pumped at 400 psi and 2 bbl / min. After un- stinging from the retainer, 4 sacks o~ cement were placed on top of the retainer, the upper wellbore fluids were circulated and finally, a 50 sack plug of 15.8 ppg class "G" cement Fairweather E & P Services, Inc. Nicolai Creek Unit No. 2 Rev. 3.1 Page 1 of 7 4/25/2002 was placed from 248 feet to surface with returns observed at surface. Attachment II shows the current configuration of Nicolai Creek Unit No. 2. 2.0 Summary of Proposed Well Work In order to effectively re-enter and re-complete the Nicolai Creek No. 2 as a gas production well in accordance with AOGCC regulations, the following tasks must be completed: Drill out the cement plug at surface, the two cement retainers and subsequent cement plugs and clean out ,any fill to the top of the cement plug placed at 3102 feet. . . Verify the integrity of the 7 ~ch casing through pressure testing. Re-perforate the 7 inch casing at various zones of interest and test flow potential. 4. Re-complete the well as a g~ producer and install surface production equipment. 5. Remove drilling equipment, ~lean well site and prep for production. The above work will be performed ig compliance with the regulations presented in Alaska Oil and Gas Conservation Commission Alaska Administrative Code: Title 20 Chapter 25. . 3.0 Proposed Operations Prog~, am The following Operations Program ~ddresses the work scope to be performed in the course of reentry and re-completing Nicolai Creek No. 2 only. The construction of surface production facilities and eve.hmal connection of Nicolai Creek No. 2 to a gas transmission line will be carded out at a later date. 1. Obtain all required permits ~d regulatory approvals before starting job. Anticipated permits and forr~ s for the well work include the following: · Application for Simdry Approvals, Form 10-403(AOGCC) · Coastal Zone M .afiagement Program 2. Mobilize all required person~, el and equipment to the Nicolai Creek No. 2 location on an as needed basis via barge and aircraft. The proposed personnel and equipment spread are as follo~ws: Personnel: Working Supervisors (1) Fairweather E & P Services, Inc. Nicolai Creek Unit No. 2 Rev. 3.1 Page 2 of 7 4/25/2002 3~ 4~ 5, e Rig Operators (2) Roughnecks/Roustabouts (8) Vac Truck Operators (2) Equipment/Forklift Operators (l) Cementers (3) Wireline Crew (3) Medic (1) Equipment: 1 Dfilling/Workover fig BOP equipment and accumulator Choke manifold 966 loader Fuel Truck Cement pump unit Bulk cement silo Cell Phone communications Drilling Fluid Additives Drilling Fluid mix water I Lot: Oil Spill Contingency Equipment Tools, sufficient for any contingency 3 ½ inch drillpipe (worksu'ing) 2 7/8 inch production tubing (for completion) Test separator I Office bunk shack Gas detection system Pit volume/flow monitoring system Well testing equipment Cement Retainers Permanent packers Bridge plugs Hold safety meeting before Starting work on the well. Notify AOGCC of intent to begin operations. Move in fig and rig up. Hook up tanks, pumps, gas detection system, and pit monitoring system as per 20 AAC 25.033 and 20 AAC 25.066. Give AOGCC 24 hour notice of pending BOP test so that they may witness same. Check well-head for pressures, both on the annuli and the 7" easing. Function test and lubricate valves as necessary (Well should effectively be dead due to cement plugs placed in 1991). Remove 7 1/16 inch blind flange and install a 7 1/16 X 11 inch double stud adapter and install BOPE. ~[~v,~)e.~.k-~,~-" ~-~th.k~-k ~x-~Cob-~"~~l'~ Nipple up 11 inch x 3M double gate BOP stack, rotating head, choke manifold, accumulator, choke and kill lines. Function test all and pressure test to 3000 psi.. Test all valves, lines and manifold for pressure integrity and functionality. Fairweather E & P Services, Inc. Nicolai Creek Unit No. 2 Rev. 3.1 Page 3 of 7 4/25/2002 . Treat 100 bbl 9 - 9.5 ppg recycled mud to be used during the re-drilling of Nicolai Creek No. 2. . Pick up 6 inch bit on workstring (3 ½ inch drillpipe) and four 4 % inch drill collars. Drill out cement plugs and retainers and clean to top of cement plug at 3102 feet with mud. Tag and determine depth of TOC but do not drill into plug. If no cement is evident, and pressure testing in step 9 fails, it may be necessary to RiH and set a CIBP at --'3100 feet. The need for this will be determined in Step 9 below. , Pressure test casing to 3000 Psi. If test fails, pull bit and pick up retrievable packer, isolate leak, squeeze with cement (cementing procedure to be provided). If squeeze job is performed, drill out and retest casing to 3000 psi. Repeat as necessary to produce satisfactory pressure test. 10. When casing has successfully pressure tested, pick up bit and casing scraper. TIH, drilling out residual cement as necessary to TOC as determined in step 8. Circulate out mud with clean, recycled 3% KC1 brine, displacing high vis sweeps of HEC-10 as necessary until clean returns are observed at surface. 11. TOOH with work string, rig up eline and perforate the interval from 2870 - 2918 feet at 6 SPF (max expected BH pressure at this point is less than 1100 psi, at +/- 2500 feet TVD) 12. Notify AOGCC of intent to flow test and chance to witness same. 13. TH-I with tubing and retrievable packer, setting at =70 feet above the perforations shot in Step 11 above. Swab well in ' c ' '~'~,,&,~,,x.~--~rN ~lll~._~, keeping FTP aboVe 800 psi after unloading tubing. Record pressures c.kq~ '~ ~~'-~x-" _and obt~ gas and water production rates while venting gas to atmosphere. 14. Kill well with 3% KCL brine. Pull tubing and packet. If rate appears commercial, PU and RIH with retrievable bridge plug, set at =2800 feet, pressure test to 1000 psi and proceed to step 16. If rate is appears to be sub-commet¢ial (less than 1000 mcfd), go to Step 15. 15. If rate appears sub-commercial, set CIBP =100 feet above perforations shot in step I l, pressure test to 1500 psi, and drop 2 sacks class "G" cement on top of bridge plug. 16. RU eline and RIH to perforate from 2700 - 2722 feet with 6 SPF, repeating test procedure used in steps 12 - 14, retrieving RBP and resetting above all open perforations prior to adding new perforations. Fairweathet E & P Services, Inc. Nicolai Creek Unit No. 2 Rev. 3.1 Page 4 of 7 4/25/2002 17. RU eline and RIH to perforate 2426 - 2476 feet with 6 SPF and repeat test procedures used in steps 12-14. If well has a rate > 2 mmcfd with water production < 10 bpd, go to step 19. 18. If well is not commercial at this point, set CIBP at 2350 feet. Run USIT. If cement bond is good, perforate and test the intervals from 1834 - 1850 feet, 1790 - 1805 feet, and from 1441 - 1478 feet, repeating steps 12 - 14. Go to Step 19. If cement bond is not acceptable, remedial cementing will be required (procedure will be provided). 19. Pull tubing and packer, retrieve RBP, PU and RIH with bit and casing scraper. Circulate hole clean. Check for flow, pull bit and scraper. 20. Run 5" Meshrite Screens across all open perforations with 3 ~A inch tubing spacers. Hang on permanent packer ~100 feet above highest perforation. Run 2 7/8 inch production tubing. Space out, sting into packer and hang off in tubing hanger and lock down. Set plug in tubing, ND BOPE, NU tree. Attachment II shows the proposed completion configuration of Nicolai Creek Unit No. 2. 21. Swab well in and nm 4-point test after flow cleans up and has stabilized. 22. When well has flow tested successfully, shut in, RD rig and ancillary equipment and mobilize off site to next well. Clean up site in preparation for installation of production facilities. 23. File new Form 10-407 with AOGCC describing final status of well. Fairweather E & P Services, Inc. Nicolai Creek Unit No. 2 Rev. 3.1 Page 5 of 7 4/25/2002 Proposed [~As is Nicolai Creek Unit No. 2 Granite Point Alaska Suspended 36" Hole Attachment 30" @ 80' CMT'D to surface Wi 300 SX 26" Hole 20" 94# @ 286' Ck~T'D to surface W/650 SX 17 1/2" Hole Cement P~ug: Surface - :248' Cement Retainer at 248', 135 Sks cmt circulated through perfs at 298' up annulus to surface 5 SPF @ 298' 10 Sks cmt on top of retainer Cement Retainer at 590' 5 SPF@677' Squeezed w! 215 s× 14 ppg Mud 13 3/8°' 54.5# @ 1934' CMT'D W!1600 SX TOC @ - 1900' MD in 13 3!8" X 7" annulus 14 ppg Mud 9 7!8' Hole Original production perforations 4 1!2 SPF from 3270' to 3315' cemented over during 1991 Suspension Procedure 7" 26# @ 3585' M D CMT'D W!1400 SX TD@5011' MD4086'TVD 87 Sk C~ass "G'" Cement Plug 3102' - 3537' P~ug (Baffle Plate) @ 3543' MD DRAWING NOT TO SCALE NICOLAI CREEK No. 2 FA1R WEATHER E&P ,5'ER VICES LVC, Rev. 01asis / DFA/06-Sep-01 Fairweather E & P Services, Inc. Nicolai Creek Unit No. 2 Rev. 3.1 Page 6 of 7 4/25/2002 36" Ho~e 3o- @ 8o' CMT'D to surface Wi 300 SX NicoJai Creek Unit No. 2 Granite Point A~aska Production Production Tubing Attachment 26" Hole 20" 94# @ 286' CMT'D to surface W! 650 SX 17 1/2" Ho~e 5 SPF @ 298' Squeezed w/200 s× in 1991 5 SPF @ 677' Squeezed wi 215 s× in 1991 13 3/8" 54.5# @ 1934' CM T'D WI1600 SX TOC @ ~ 1900' MD in 13 3/8" X7'" annulus Permanent Packer at 2326" 5" Meshrite Screen 9 7/8" Ho~e Original production perforations 4 1/2 SPF from 3270' to 3315' cemented over during 1991 Suspension Procedure ~ 7" 26# @ 3585' CMTD W1t400 SX TD @ 5011' M D 4086' TVD Perforate @ 12 SPF 2426' ~ 2476' Perforate @ 12 SPF 2700' - 2722' Perforate @ t2 SPF 2870' to 2918' 87 Sk C~ass "G" Cement Plug 3102' - 3537' Plug (Baffle Plate) @ 3543' M D i DRAW1NG NOT TO SCALE SER VICE,~~ NiCOLAI CREEK No, 2 Rev. 02prop / DHV 23-Apr-02 Fairweather E & P Services, Inc. Nicolai Creek Unit No. 2 Rev. 3. Page 7 of 7 4/25/2002 Aurora Well Service Rig No. 1 BOP Equipment to be furnished on site with Rig for summer 2002 Nicolai Creek well work. 1 - 11" X 3M Shaffer Annular Preventer 1 - 11" X 3M Shafco Double Gate (rebuilt, Shaffer LWS type), double studded, w/blind rams and 3 ½" pipe rams. (Will be using 3 ½" DP for work string) 1 - Koomey Accumulator System 3000 psi w/6 stations and 120 gallon capacity. Will have Remote Control Panel (drillers station) w/6 stations and 100' umbilical. 1 - 5M Choke manifold with remote actuated hydraulic choke on skid. (Unit is not trimmed for H2S) 1 - 3M drilling spool 1 - Grant rotating head Proposed 3M BOP Configuration for NCU No. 2 Well re-entry and workover procedures using reverse circulation. Returns taken up workstring and through power swivel to pits. 3M Washington Rotating Head 7 1116" X 11" 3M Double Stud ^dapter.~...~.~ 2" 3M Manual Valve (Kill Line) 2" 3M Hydraulic Valve (Kill Line)'"~ Fluid flow direction ~ while reverse circulating Pipe Rams sized to work string. Blind Rams 2" 3M Manual Valve on spool for either pumping into or taking returns above rams. 11" 5M Double Gate 13 3/8"X 7 1/16" 3M Tubing Spool ,2" 3M Manual Valve (Choke Line) 2" ~ 3M Hydraulic Valve ~ (Choke Line) 2 1/16" 3M Manual Valves On Wellhead 13 5/8'~( 3M Well Head Fluid flow DraWing Not to Scale Fairweather E&P Services, Inc. Nicolai Creek No. 2 BOP Syslm~ Rev. 01.0 I DHV 26-April-02 , NCU No. 2 Proposed Choke / Kill Manifold Configuration All valves are 2" rated at 3000 psi. Inlet from Power Swivel (Reverse Circulation Mode) Manual Choke Inlet from BOP Choke Line Output to Pits Ail Valves: 2'3M Rated Bleed Flare Line to Open Flare Pit Hydraulic Remote Activated choke To Gas Buster "Atmospheric Degasser" IDrawing Not to Scale Faitweather E&P Sen/ices, Inc. Nicolai Creek No. 2 Choke/Kill Manifold Rev. 01.0 / DHV 26.Al)ril-02 AURORA GAS LLC NICOLAI CREEK # 2 2-9/16" 5,000 Tree Run 2-9/16" 5,000 Wing 7-1/16" 3,000 2-1 / 16" 5,000 13-5/8" 3,000 2-1/16" 5,000 13-3/8 CS(} 7" CSG 2-7/8" TBG CAMERON David Shaw Anchorage Ak 04/04/02 E & P SERVICES, IN~. Mr. Tom Maunder Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Ste. 100 Anchorage, AK 99501 July 9, 2002 Tom: Please find enclosed a copy of the NCU 2 Sundry application as previously submitted. As per past correspondence and conversations concerning our work program, Aurora Gas LLC., will not perform any well testing while flowing through the gas buster. If you could please let us know when we can start operations on the well, would sure appreciate it. Right now, as mentioned previously, we should be rigging up on the well sometime next week. Are still coordinating the arrival of all the parts at Peak's yard in Nikiski, and hope to have all assembled by Friday the 12th of July. Hopefully will have all fabrication and component fitting finished, so we can barge everything across the Cook Inlet starting on the following Monday. Please do no hesitate to call me at 258-3446 at the office, or on the Cell at 240-1107 if you need any more info. Thanks Duane ~ LLG April 30, 2002 Ms. Cammy Oechsli Taylor, Chairman Alaska Oil and Gas Conservation Commission 333 West 76 Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Sundry Approval; Re-Entry of Nicolai Creek Unit No. 2, Granite Point Alaska Dear Ms. Taylor, Aurora Gas LLC, hereby applies for Sundry Approval of its plan to re-enter and re- complete Nicolai Creek Unit No. 2, as a gas production well. This project is within the scope of Aurora's ongoing gas development plans on the northwest side of the Cook Inlet. Aurora plans to begin well re-entry and work-over operations on June 15th, 2002. Upon receipt of all necessary permits and approvals, contractors will prepare and repair as necessary: the original NCU No. 2 access road and well-site. The rig, Aurora Well Service No. l, and support equipment will then be mobilized to the site to begin well work operations. The well is currently suspended as depicted in Attachment I. When the rig is in place, a BOP stack and associated well control equipment will be installed and tested, and the attached re-entry procedures will be initiated. During the original well suspension procedure, cement plugs and two cement retainers were placed along the course of the wellbore. Aurora intends to drill out the surface cement plug and both retainers to gain access to the lower cased hole section. The deepest point in the wellbore after access, is gained will be the top of the cement plug placed from 3102 fi- 3537 fi across original production perforations and above the 7 inch casing shoe interval. At this time we request that the BOPE test pressure to be used during this re-entry and completion procedure be limited to 3i000 psi. Calculations show that at 3102 i~ MD (2652 f~ TVD), assuming the wellbore has been unloaded of all fluid and only gas remains, a 3000 psi surface pressure equates to an equivalent mud kill weight of over 21.7 ppg. There is no procedure Aurora plans to undertake on the NCU #2 well, which would require a pressure in excess of 3000 psi. Original test records from the perforated interval 3270 - 3315 fl MD --(2780- 2815 f~ TVD) indicated a maximum stabilized shut in tubing pressure of 1180 psig, or 1253 psig bottom hole pressure. Aurora Gas intends to use BOPE rated at 3000 psi for NCU No. 2 well work operations. Ms. Taylor Page 2 Pertinent information attached to this application includes the following: 1) Form 10-403 Application for Sundry Approval - 3 copies 2) A copy of the proposed m-entry and re-completion procedure 3) Schematics showing the current and planned wellbore configuration 4) BOP and choke manifold schematic. If you have any questions or require additional information, please contact the undersigned at (713)977-5799, or Duane Vaagen at (907)258-3446. Sincerely, AURORA GAS, LLC · Executive Vice President / Production Manager Enclosures cc: Duane Vaagen Andy Clifford Nicolai Creek ~2 and the Rig SUbject: Nicolai Creek #2 and the Rig Date: Mon, 13 May 2002 13:35:17 -0800 From: Tom Maunder <tom_maunder@admin.state.ak. us> To: Duane Vaagen <duane@fairweather. com> Duane, I just got the program for Nicolai Creek #2 and have a couple of questions. 1-1 knew you (or Aurora) planned to bring up a rig. Could you please provide some information regarding it. This should include drawings of the well control equipment (some provided) and the pits and what provisions there are for necessary pit monitoring equipment/ 2--Your stack drawing has 2 rams and a rotating head. Although you are not planning to make new hole, you will be drilling out plugs. Is the rotating head an alternative to an annular?. 3--In your program, you propose to test using the rig gas buster. This is unusual especially with the plan to flow the well at 800 psi. Gas busters that I am familiar with are atmospheric pressure vessels designed to allow small amounts of gas to be released from drilling fluids. I don't think up to 1MM cu ft is a small amount of gas. Please look at these issues and give me a call and we can discuss. Thanks. Tom Maunder, PE AOGCC Tom Maunder <tom maunder~.admin.state.ak.u$> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission lofl 5/13/02 1:37 PM DEPT. OF ENVIRONMENTAL CONSERVATION TONY KNOWLES, GOVERNOR DIVISION OF ENVIRONMENTAL HEALTH SOLID WASTE PROGRAM 410 WILLOUGHBY AVE JUNEAU, ALASKA 99687 http://www.state.ak.us/dec/deh ~'. Reference: Mr. G. Scott Pfoff, President Aurora Gas, LLC 1029 West 3rd Ave. Suite 220 Anchorage, AK 99501 October 23,2001 Telephone: (907) 465-5162 Fax: (907) 465-5362 o#- Issuance of Permanent Closure Approval for Inactive Reserve Pit located at Nicolai Creek State 1 & A-l, Nicolai Creek Unit 2 .and Nicolai Creek Unit 6, all located on same drilling pad on the West Side of Cook Inlet The Alaska Department of Environmental Conservation (ADEC) has completed review and Public notice for permanent closure approval of the inactive reserve pits located in the above referenced drilling site. The same reserve pits were used for 3 drill holes. The closure applications provided the required information describing the history of the reserve pit(s), the present condition of the reserve pits(s), results of any required water sampling and an assessment of the potential risks posed by the drilling waste to human health and the environment. At this location, the ADEC stipulated corrective actions be conducted for de-watering, backfilling and reseeding the area of the reserve pits. After corrective actions were comPleted, a final inspection of the site was conducted on September 20, 2001. ADEC coordinated the requirement for corrective actions and all field inspections with the landowner, Alaska Mental Health Trust. Public notice requesting comments on the closUre requests .was published September 20 and 21, 2001 in the Anchorage Daily News and posted on the state web site September 21,2001. No public comments objecting to closure approval were received in response to this public notice. ADEC has determined that the reserve pit at this site meets the closure requirements of 18 AAC 60.440. Closure Approval Under authority of 18 AAC 60.440 (j), ADEC grants permanent closure approval to Aurora Gas LLC for the inactive reserve pits at the site that contains the following wells: Aurora Gas, LLC Mr. G. Scott Pfoff October 23,2001 Page 2 of 2 Well Name Nicolai Creek St. I & IA Nicolai Creek Unit 2 Nicolai Creek Unit 6 API Number 50-283-10020-00(01) 50-283-10021-00 50-283-20064-00 MTRS Sec 29, T 11N,R 12W SM Sec 29, TI IN,RI2W SM Sec 29, TI IN,RI2W SM Landowner Mental Health Trust Mental Health Trust Mental Health Trust Terms and Conditions This final closure approval is subject to the following terms and conditions: 1) In accordance with 18 AAC 60.440(1), the Department will require additional investigation, assessment, monitoring or remediation if new information regarding conditions at the reserve pit facilities indicates that further actions are necessary to protect human health or the environment. 2) The approval granted by this letter is for the inactive drilling waste reserve pit(s) only. Closure for the pad as awhole (if required) must be coordinated between the owner/operator and the appropriate land owner/manager. Any person who disagrees with any portlon of this deciSion may request an adjddicatory hearing in accord,ance with 18 AAC 15,200-310. The reque.st should be mailed to the. COmmissioner of the Department of Environmentai Conservation, 555 Cordova Ave. Anchorage, AK 99501. If a hearing is not requested within thirty (30) days of the date of this letter, the right of appeal is waived. If an adjudicatory hearing is requested and granted, this decision remains in full effect during the adjudicatory process. Sincerely, Heather Stockard Solid Waste Program Manager Heather, Stockard @envircon.state.ak.uq cc.' Tom Maunder, AGOCC Mike Franger, Mental Health Trust Jeff C. Osborne, Fairweather E&P Services, Inc. J. Edward Jones, Aurora Gas, LLC, 10333 Richmond Avenue, Houston, Texas 77042 Harry Eaton, Unocal Alaska DEPT. OF ENVIRONMENTAL CONSERVATION DIVISION OF ENVIRONMENTAL HEALTH SOLID WASTE PROGRAM 410 WILLOUGHBY AVE JUNEAU, ALASKA 99687 http://www.state.ak, us/dec/home.htm January ! 1, 1999 John Beitia Unocal Corporation P.O. Box 196247 Anchorage, AK 99519-6247 TONY KNOWLES, GOVERNOR '/A Pro Telephone: (907) 465-5162 Fax: (907) 465-5362 Reference: Notice that reserve pit the closure plan is not approved for Nicolai Creek Wells 1, 2 and 6 located on the west side of Cook Inlet. Dear Mr. Beitia: The Alaska Department of Environmental Conservation (ADEC) has issued final closure approval of all Nicolai reserve pits submitted by Unocal except Nicolai Creek l, 2 and 6. At this three well site, two of the wells have been in suspended status since 1966 and one well (Nieolai Creek # 6) was plugged and abandoned in 1979. There are three open reserve pits at this site; two have ponded water in contact with drilling waste. Results of reserve pit water analyses show that barium, chromium and zinc concentrations exceed state water quality standards. Unocal has not adequately addressed the risk of these water quality exceedanees to the environmental receptors that inhabit the area. We do not concur with the conclusion that the risk is negligible. In addition, the reserve pits at the site have not been backfilled in accordance with Alaska Oil and Gas Conservation Commission regulations. ~ The closure plan is not approved. In accordance with 18 AAC 440(i), ADEC requests that Unocal submit a corrective action plan to de-water and backfill the open reserve pits. Please give me a call if you have any questions in this regard. ~Sincerelyfk' eters~ ~,eserve Pit Closure Coordinator rjpeters~..envircon.state.ak.us - 7g CC; Wendy Mahan, AOGCC, Anchorage Dave Thomas, Mental Health Trust G:\HOME\RJPETERS\RSVP175UNOCAL\NiCOLAi. DOC ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J, HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 August 19, 1994 Kevin Tablet, Land Manager UNOCAL P O Box 196247 Anchorage, AK 99519-6247 Re: Suspended Wells Compliance with regulations Dear Mr. Tablet: UNOCAL has 15 suspended wells as shown on the attached'list: ALASKA SUSPENDED WELLS AS OF AUGUST 199A. The applicable regulation is as follows: 20 AAC 25.110 SUSPENDED WELLS (a) Upon application by the operator under 20 AAC 25.105(e), the commission will, in its discretion, approve the suspension of a well if the well (1) encounters hydrocarbons of sufficient quality and quantity to indicate the well is capable of producing in paying quantities as reasonably demonstrated by well tests or interpretive formation evaluation data; or (2) is reasonably demonstrated to have future value as a service well. For each well on the attached list of suspended wells, please provide data showing that the well meets the criteria of (1) or (2) above or advise as to your plans to abandon the well. Wells'that meet the criteria of (a) above that you wish to maintain as suspended, as required by 20 AAC 25.110(e), must have well site inspections as appropriate this year prior to snow covering the locations. , 'Chairman c: Blair Wondzell encl bew/llunsusp PERMIT API NUMBER OPERATOR 00-0146-0 133-10145-01 UNION OIL CO 61-0045-0 133-10144-01 UNION OIL CO 66-0008-0 283-10020-01 UNION OIL CO 283-10021-00 UNION OIL CO 66-0038 0'' - . 67-0007-0 283-20003-00 ONION OIL CO 67-0023-0 733-'20018-00 U~ION OIL CO 67-0042-0 733-20032-00 UNION OZL CO 72-0007-0 133-20237-00 UNION OIL CO . 75-000B-0 283-20045-00 I:I~TIONOIL CO 77-0017-0 733-20300-00 U~ZON OIL CO 78-0096-0 733-20119-00 UNION OIL CO 79-0017-0 733-20441-01 UNION OIL CO 81-0022-0 733-20339-00 UNION OIL CO 90-0041-0 733-20302-01 T31~ION OIL CO 90-0071-0 733-20417-00 LT~iON OiL CO ALAS~CA SUSP~V~ED W~LLS AS OF AUGUST 1994 SWANSON RIVUN=T 14-1S SWANSON RIVUN=T 43-15RD N=COLAI CK ST 1-A NZCOLAZ =UNIT '2_.' GI~ANITE PT ST 187429 GRANITE PT ST 18742 10 SWANSON RIVUNIT 24-33 1'VAN RI--v'~RLT~ZT 14-31 MGS ST 17595 16 G~NITE PT ST 18742 31 =~ITE PT ST 18742 T~ING BAY ST A-20D T~ING BAY~IT M-0~ WELL CLASS DEr DEV DEV DEV DEV DEV D~'V D~V DEV DEV D~'V WELL STATUS STATUS DATE 11/o8/91 8/2o/91 8/14/91 9/18/91 9/o2/91 9/16/89 9/29/88 4/01/9~ 8/18/75 2/05/92 10/07/88 9/20/91 4/21/82 4/23/90 7/03/90 SECT 16 15 29 29 20 12 31 04, 01 31 31 31 31 04 33 TWP 08N 08N 11N 11N 11N 10N 12N 07N 13N 09N 11N 11N 09N 09N 009W 009W 012W 012W 012W 012W 011W 009W 009W 012W 011W 011W 011W 013W 013W . ,' STATE OF ALASKA " ' Al[ .A OIL AND GAS CONSERVATION COMM{,'"' tN REPORT OF SUNDRY WELL OPERATIONS 1. Operations performed: Operation shutdown __ Stimulate__ Plugging __ Perforate __ Pull tubing .2f... Alter casing __ Repair well ._~ Pull tubing __ Other 2. Name of Operat({rUNOCA1-' ) Union 0il Company of California 3. Address P.O. Box 190247, Anch., AK, 99519 5. Type of Well: Development Exploratory Stratigraphic Service 6. Datum elevation (DF or KB) 46' 7. Unit or Property name ADL 17585 feet 4. Location of well at sudace 2018 ' N & 205 ' E from SW Corner, Sec. 29, TllN, R12W SM At top of productive interv~ 315 ' 685 ' N & 983 ' E from SE Corner, Sec. 30, TllN, R12W SM At effective depth 15', 2018' N & 205' E from SW Corner, Sec. 29, TllN, R12W SM ~Attomld, nth 5011', 246' S & 1603' E from S]~ Corner, Sec. 32, TllN, R12W, SM 12. Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical 5,011' ,f~t 4,102 ~et 3,540' fe~. 2,999' ~et Plugs(measured) Junk (measured) 8. Well number Nicolai Creek #2 "'9. Permit rju_mber/approval number '10. APl ndmber 50-- 11. Field/Po(~icolai Creek Baffle Plate 3537' Cement 3102' Retainers 248' and 590' Cement surface Casing Length Structural Conductor 58 ' Surface 2 6 6" Intermediate 1916 ' 3'569 ' Production Liner Perforation depth: measured true vertical size 3'0" 20" 13-3/8" 7 i, ..Cemen~d Measumdde~h ~ueverticaldepth 300 sacks 80' 80' 650 sacks. 286' 286' 1600 sacks '1934' 1773' 1500 sacks 3585' 3035' 327Q'-3315' :2790'-2826' Tubing (size, grade, and measured depth) .None RECEIVED Packers and SSSV (type and measured depth) . None 13. Stimulation or cement squeeze summary ' ' ' 298' squeezed with 200 sacks cement Intervals treated (measured) · 590'. sQueeZed with 215 sacks cement Treatment description including volumes used and final' pressure OCT 2 3 1991 Alaska 0il &'Gas Cons. C0m[mss~, Anchorage Prior to well operation Subsequent to operation Representative Daily Average Production or InjeCtion Dat~ OiFBbl Gas-Mcf Water-Bbl Casing Pressure 14. None 15. Attachmehb " '116. Status of well classification as: Copies of Logs and Surveys run X I Daily Report of Well Operations ~ , Oil __ Gas ~_ Suspended k' Service 17. I hereby ce~hat the foregoing istrue and correct to the best of my knowledge. · ',~' G~r~] S. ~tsh ~ t . Regional Drilling Manager Signed k'¢/~c~, ~---~' ~;) ~~ . Title. Form 10-404 Rev~tlS/~ , ' Tubing Pressure Date £ ¢) ,,-'( ~. ,.. o% ~ SUBMIT IN DUPLICATE KB = NICOLAI CREEK 15.4' CURRENT . 30" 0 80' CMT'D N 300 SX TC- 1.5' #2 SPUD 9-21-66 PLATE NELDED BETNEEN THE ;~0" G 30' CBMBI~ PLLTG SURFACB - 248' 20" O 286' CUT'O w/650 TC -. 15' 17 1/2" HOLE 105. PCF ~ BBTAIHBR AT 24,8' 298' 5 SPY St~.1BBBZBD' 1EI'K 200 83: CEMBHT' BBTAIRBB: AT 590,- 677'** 5 SPF' 8QUBBmUD WITH:' 2t5 aX 13 3/8" 54.5# · 1934' OIdT~) W/ 1600' SX TC =' t, 5' 12 1/4" HOLE TO 2322i.. 9 7/8' HOLE. ?0 113 . . ?' 26#' N-80 O: 3585' Cm"O w/ 15oo'sx TC - +/- 2000,: TO =, 5011' ~ '= 4086'. 105 PLT' "RECEIVED '.OCT 2 ~ 1991 · Alaska Oil & Gas Cons. Commissio~. . ., .. . .... ,, ' .. Anchorage cnnT'PLO;..'.~ou a~o~', - %a";'" · "... ., ,'.' .' 2 1/2' SI=~"FRoId 3270, - 33:i.5~ ""' 2 7/e-, 6.5#, d-55 TUBING TO 35oe' , . . .',".".... . . .. , . Fff. Z,'. AT 3537' ..... '". ...... ,.':...:".:'.". 'i.':'..":':::": .. "' ,.,.'..'...? '.." . ,,. ',., .,, DATE 9/11/91 NICe' %I CREEK #2 WELL HISTORY MW / ~ COMMEN~ . MOVED AND SET COMPONENTS AT WELL#2. STARTED GENERATOR, RAISED DERRICK, FINISHED CLEANING THE MUD PIT. CONTINUED TO REPAIR BERM AT WELL #2. VERY MUDDY. SET THE DEAD MEN. PULLED UP PIT LINER AT WELL #4. 9/12/91 RIG UP PITS, AIR, WATER, AND ELECTRICAL COMPONENTS. RAISED THE SUBBASE, TIGHTENED THE GUIDE WIRES. INSTALLED THE RIGHT ANGLE DRIVE. RIGGED UP THE FLOOR, PICKED UP THE KELLY AND FUNCTION TESTED THE PUMPS. ACCEPTED GRACE RIG # 211 AT 1400 HRS. SET CAMP UNITS AND SUPPORT BUILDINGS. TRANSFERRED MUD TO THE MUD PITS. RIGGED THE KILL LINE TO THE TREE AND CHOKE LINE TO THE ANNULUS. TESTED THE LINES TO 3000 PSI. PULLED THE BACK PRESSURE VALVE. 9/13/91 78 3504 RIGGED lip WIRELINE AND PRESSURE TESTED THE LUBRICATOR TO 3000 PSI. RIH WITH SINKER BARS, A CCL AND A 2" GAUGE RING TO 3504' (WLM). POOH. DISPLACED WELL WITH 78 PCF MUD PUMPING DOWN THE TUBING AND TAKING RETURNS THROUGH THE CHOKE AND GAS BUSTER. CIRCULATED AND CONDITONED MUD. TO 78 PCF. SET BACK PRESSURE VALVE. REMOVED THE TREE AND INSTALLLED 7-1/6" 3M XO, 13-5/8" 3M X 13 5/8" 5M DSA AND BEGAN INSTALLING THE 13-5/8" BOPE. 9/14/91 80 3504 INSTALLED 13-5/8" 5M BOPE. PRESSURE TESTED THE BOPE TO 3000 PSI HIGH AND 250 PSI LOW. RIGGED UP THE TRIP TANK AND PULLED THE 2-7/8" X 7 1/16" HANGER TO THE FLOOR. CIRCULATED. CHECKED FOR FLOW, NEG. POOH AND STOOD BACK 89 JOINTS OF 2-7/8" TUBING. 9/1.5/91 RECEIVED OCT 3 1991 Alaska Oil & Gas Cons. commi$~'t~n AnchoraOe 3543 CHANGED PIPE RAMS TO 3-1/2" AND PRESSURE TESTED TO 250 PSI LOW AND 3000 PSI HIGH. RIH WITH A 6-1/8" BIT. AND 7" CASING S'CRAPER AND TAGGED FILL AT 3519'. 'CLEANED OUT FROM 3519' - 3537'. CIRCULATED AND INCREASED CHLORIDES' TO 50,000 PPM. POOH RIGGED UP WIRELINE AND' RAN A TDT/CCL/GR LOG FROM 3543' - 300' (WLM). RIH WITH 3-1/2"' DRILL PIPE AND 695' OF 2-7/8" TUBING TO 6537'. CIRCULATED. 9/16/91 105 3102 RIGGED UP CEMENTERS AND TESTED LINES TO 2.000 PSI . PUMPED 87 SXS OF CLASS "G" CEMENT WITH 0.5% A-7, 1 GAL/100 SX FP- 6L, AT 118 PCF. BALANCED THE CEMENT PLUG FROM 3537' TO 3070'. CIP AT 0158 HRS. POOH TO 2819' AND REVERSE DATE 9/16/91 CONT'D NICQ[.AI CREEK #2 WELL HISTORY MW ~ COMMEN<' . CIRCULATED THE TUBING CLEAN. POOH. RIH WITH A 6-1/8" BIT AND A 7" CASING SCRAPER AND TAGGED THE TOP OF CEMENT AT 3102'. TAGGING WITNESSED BY LOU GRIMALDI OF THE AOGCC. CIRCULATED AND CONDITIONED THE MUD TO 105 PCF. POOH AND LAID DOWN 3-1/2" DRILL PIPE. RIGGED UP WIRELINE AND RIH WITH SCHLUMBERGER'S 4-1/2" 51-B GUN. 9/17/91 105 590 RIH WITH 4-1/2" 51-B GUN AND PERFORATED THROUGH TWO STRINGS OF CASING AT 677' WITH 5 1/2" HOLES. RIH AND SET 7" EZSV CEMENT RETAINER ON WIRELINE AT 590' (WLM). RIH WITH STINGER ON 3-1/2" DRILL PIPE AND STABBED INTO THE RETAINER AT 590'. ATTEMPTED TO ESTABLISH CIRCULATION UP THE 13-3/8" X 7" ANNULUS, NEG. ESTABLISHED INJECTIVITY AT 4 BBL/MIN AND 800 PSI. NO PRESSURE BUILDUP ON THE 13-3/8" X 7" ANNULUS WITH 40 BBLS PUMPED. FORMATION HOLDS 200.PSI WITH THE PUMPS OFF AND BLEEDS OFF SLOWLY. ATTEPTED TO PUMP INTO THE 13- 3/8" X 9-5/8" ANNULUS, PRESSURED UP TO 800 PSI WITH 4 BBLS PUMPED. BLED TO 700 PSI IN 15 MINUTES. RIGGED UP CEMENTERS AND PUMPED 215 SX OF 15.8 PPG "G" CMT WITH 0.8% FL-32, 0.3% CD-31, 0.2% A-2, 1.2% A-7, 1 GAL/100 SX FP-6L, 3.5 BBL/MIN AT 750 PSI. UNSTABBED FROM THE RETAINER. CEMENT IN PLACE' 0745 HRS. LEFT 12 SX ABOVE THE RETAINER. PULLED UP TO 440' AND CIRCULATED. POOH. RIH WITH 4-1/2" 51-B GUN ON WIRELINE. PERFORATED THE 7" CASING AT 298'. POOH AND MADE UP 31~.~.,~..~.~,...,CEMENT RETAINER AND RIH~ SET THE RETAINER AT 248'. CIRCULATED UP THE' 13-3/8" X 7" ANNULUS' WITH 105 PCF MUD. RIGGED UP CEMENTERS. ESTABLISHED BREAK DOWN, 150 PSI AT ~ BBL/MIN. MIXED AND PUMPED. 155 SX. OF 1'5.8' PPG "G" CMT WITH 1.% A-7', 1GAL/lO0 SX' FP6L, CEMENT RETURNS TO' SURFACE WITH 135 SX PUMPED. CLOSED' THE ANNULUS AND SQUEEZED THE REAMINING. 20 SX.MIXED AND D PUMPED 180' SX OF 15.8 PPG "G".WITH 0.8'% RECEiV~ FL-32., 0.3.% CD-31, 0.2% A-2, 1.2% A-7', ! GAL/IOOSX FP'6L, 400 PSI AT 2BBL/MIN, 0CT R~ ~ UNSTABBED FROM THE RETAINER AND LEFT 4 SACKS ON THE RETAINER. CEMENT IN PLACE ~0il&Gasgons. GommiSsl°'" AT'ISIO HRS. PICKED UP TO 245' AND CIRC. POOH. RIH WITH 2-7/8" TUBING TO. ~h0~ TO 248'. RIGGED UP THE CEMENTERS. PUMPED 50 SACKS OF 15.8 PPG "G" CMT WITH 1.5% A-7, 1. GAL./1000 SX FP-6L. CEMENT RETURNS TO SURFACE. CEMENT IN PLACE AT" 1805, HRS/. POOH AND LA. YED DOWN"TUBING. WASHED THE STACK AND LINES. DATE 9/18/91 ~w ('"' 105 15 NIC0. I.AI CREEK #2 WELL HISTORY .. COMMEN~" CONTINUED REMOVING BOPE AND SHIPPED MUD TO STORAGE. CLEANED THE MUD TANKS. RELEASED GRACE RIG #211 AT 1900 HRS. BEGAN DEMOBILIZATION. RECEIVED .... .... OCT Alaska Oil & Gas Cons. CommissiOn "' Anchorage MEMORANDUM TO: Lonnie C Smi~'~ Commissioner/ FM: Louis R Grimaldi J [~"'7"~ Petr Inspector STATE OF ALASKA Alaska Oil and Gas Conservation Commission DATE: September 15, 1991 FILE: LG915 SUBJECT: Wellbore.plugs Unocal Nicolai Cr St #2 Nicolai Creek Permit # 66-38 I traveled this day to the west side of Cook Inlet to witness the tag on the bottom plug in Unocal's well Nicolai Creek State #2. The rig tagged the plug at 3102 (RKB 17.6) and placed 10,000 lbs down. The plug appeared very solid, and I detected no sticking as they were pulling up. In summary: I witnessed the successful tag of the bottom plug in Unocal's Nicolai Creek State #2. Attachment 4/80 '~SKA OIL & GAS CTi'NSERVATfON CO.~Y{.,,~ Plug & Abandonment Rep~' Date, ~ION ?X O~erator Company Repr Least'No. Total Depth Elevation Mud Wt. Casing= Drive Pipe "O.D. Set at Conductor ~ O "O.D. @ ~O Ft. w/ Pent. Production 7// / "O.D. @ $ ~'~t. Plugging Data: 1. Open hole plugs: 2. Open hole isolation plug: Perforation plugs (if any] 5. Casing stub plugs 6. Surface plug: Casing removal: "casing cut at ' REMARKS: "casing cut at ' z~spec~or/s OaG #11. Ar_So~, ~0 ~ C..EFI£FtT "/~ETAIN~R · . AT' i/ NICOLAI CREEK KB = 15' CURRENT SPUD 9-21-66 2r Ha..E 20" e 2al 17 1/~'" Ha.[ 1:2 1/,P ~ TO 2.122' I 7/a' Ha.Z TO 10 I 1/1 ~F F~M 331~' -- 327'0' I /' 7''. J.., 'll.J~.ll ?O ~ Cb'i~ W/ 1~4)0 SX : 10 m 5011' [ : ~n 5/m/9 ! KB == 15' NICOLAI CREEK i/J2 PROPOSED 2lI Hnl~ 2Q' e 2Bf / c~n) w/L~o sx 17 i/2" lille 13 3/8" S4.,.~ · ct/rOW/ IIQO SX ~:: 12 1/4' HCI.E TO 2322' I 7/B' HCLE TO *ID ClAD W/ I~0 SX SPUD 9-21-66 SQUEEZE 671' - SBO' 1/2 SPf' I~OM ,151~' - 3270' 5/12/91 Unocal North America,,- Oil & Gas Division Unocal Corporation P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL Alaska Region June 21, 1991 Alaska O&G Conservation Commission Attn: Lonnie C. Smith 3001 Porcupine Drive. Anchorage, AK 99504 Dear Mr. Smith: Unocal is proposing to suspend the three Nicolai Creek wells:.#l-A, #2.and #3. Presently, the calculated quantities of gas and low reservoir pressure make completing these wells uneconomic. Unocal however has future plans to install compression facilities in the Granite Point area. It is anticipated that offshore gas reserves will be developed and compression facilities installed sometime in the mid-1990's. Once compression facilities are installed we will again be able to evaluate the economics of completing the Nicolai wells. Unocal does not wish to accept the economic and environmental risk associated with leaving the three wells in their present condition until gas compression facilities are available. All three wells are presently completed without packers and have gas under pressure at the surface. The Nicolai #i-A and #2 wells are at the end of the Nicolai Creek Airstrip and gas is leaking from the annulus between the 20" and 13-3/8" casing in the Nicolai #i-A well. For these reasons Unocal is proposing to suspend the three wells thereby removing pressure from the surface. On July 15, 1988 UNOCAL and Marathon Oil Company purchased the Nicolai Creek Unit from Texaco, Inc. and Mobil Oil Company. The working interest in the Nicolai Creek Unit is 50% UNOCAL and 50% Marathon Oil Company. All of the wells were originally drilled by Texaco, Inc. from 1965 to 1979. The following is a short history of the wells we are proposing to work on. JUL 10 Alaska .Oil & ,Gas ~o~ls. Commission AOGCC JUNE 21, 1991 PAGE 2 Texaco, Inc. commenced drilling operations on Nicolai Creek State #1 on October 31, 1965. On November 23, just after the 13 3/8" casing was cemented, gas began blowing to the surface for 4-5 hours. The gas flow slowed to a slow leak, was seen coming out of the ground at several points around location and out of the nearby water well. Several cement squeezes were performed and the gas flow slowed. The well was drilled to a depth of 9302' by April 9, 1966 and the 7" casing was run to surface. The Hemlock oil sands from 6685' to 7850' were tested and showed no oil accumulations. The Hemlock sands were abandoned with cement and the 7" casing was pulled from 3780'. The Tyonek gas sands between 3420' and 3630' were perforated, tested and completed. The well work was completed on May 2, 1966. Nicolai Creek #i-A was produced for a total of three months from December 1968 through February 1969, the well was shut in during March 1969 when the well sanded in. The well has been idle since March, 1969. The average peak rate was 1.8 MMCFD and produced a total of 117 MMCF. As unit operator UNOCAL is proposing to suspend the well in the manner indicated by the attached schematic. Texaco, Inc. commenced drilling operations on Nicolai Creek State #2 on September 21, 1966. After cementing the 20" casing into place on September 30 a small gas flow was observed between the 20" casing and the 30" casing. This well is 20' away from the Nicolai Creek #1-A well, and it is believed that the gas was from that well. The well was drilled to 5011' and 7" casing was run to 3585'. 'No oil accumulations were encountered. The gas sand between 3270' and 3315' was perforated and tested on October 23, 1966. Drilling operations were completed on October 29, 1966. Nicolai Creek #2 was produced, from October 1968 through November 1969. The well was shut in during December 1969 and has been idle since then. The .average peak rate was 1.0 MMCFD and produced a total of 51 MMCF. As unit operator UNOCAL is proposing to suspend the well in the manner indicated by the. attached schematic. l?£e£1V£D JUL 1 1 199t Alaska Oil & ~as Cons. Commission AnChorage AOGCC JUNE 21, 1991 PAGE 3 Texaco, Inc. commenced drilling operations on Nicolai Creek State #3 on March 19, 1967. The well was drilled to a total depth of 8841' in an attempt to locate a Hemlock oil accumulation. No significant reservoirs were encountered. The well was plugged back to 2522' and a 7" liner was run and cemented from 1941' to 2522'. On May 2, 1967 the gas sands between 2000' and 2380' were perforated and tested. Drilling operations were completed on May 5, 1967. Nicolai Creek #3 was produced from March 1969 through August 1977. The well produced a total of 893 MMCF of gas and was shut in during September 1977. The average peak rate was 1.8 MMCFD. As unit operator UNOCAL is proposing to suspend the well in the manner indicated by the attached schematic. Sincerely, George R. Buck Drilling Engineer Attachment GRB/lew CURRENT PROPOSED NICOLAI CREEK # 1-a KB -., 16' ~ LEAKINO TO ~URFACE SPUD 10-31-65 I II J 20 OEO UA~ DEV~ATION 10 3/4', 40~tl · 3111," -/ 1140' I~E PEH~ltATIOIi I 7/8' 8rd · 3S33' J-OS 3420' - ~ 7"' CUT AM) PUJ. ED AT 3780' DoC. I~l'I · II' II - I~ I~ I~ IO ~ 674O* SQZ'O W/~00 SX Ill, DUE R.UO AT ~ KB = 16' NICOLAI CREEK #I-A / 13 3/1" · tIM' / IQ 3/4% 40J~l · 3111" -/ ~IXI 7- 2M & ~op i 8~8' 102 II,CI,* IdtO KEg = NICOLAI CREEK 15' CURRENT #2 SPUD 9-21-66 .I~ HOLE 26"' HOLE CU~ W/r~o sx 17 1/'z" HOL~ CUT'D W/ 1~0 SX 12 1/4' HOL~ TO 2322' 9 7/8' HOLE TO TO 2 1/2 SPF FROM 33 lS' -- 3270' 2 7/8% ~ TI.IBff(O TO ,-w.--. ~':.J L. : : · · : : : : : · 10 ,- 5011' .: : WD ,, 4086' .. ................... GaB ~/12/91 NICOLAI CREEK #2 KB = 15' PROPOSED SPUD 9-21-66 2eI HaLE · )" H ~' CUI~ W/8~ ~ 17 3/8" S4.~ · cin'o w/ HOLE TO aa2~ I ?/~' HOLE TO TD : : · : : · : : · · I COI~NI' ~ PL.U~ / I'ROM 3.q40' - 3100' 1/2 SI~ FROM 331~ - ~ GP, B 5/12/91 KB = 16' NICOLAI CREEK CURRENT I I CU~D W/720 Sx UAX ~NCL '11 DEO CUT'D WITH 1770 SX · *r/r .ct,; ')", 2~#, N--eO Ir/ II41' - 2522' CI~JENTED WITH 220 ~X COJENT PLUO F/7221' - 7318' SPUD UARCH 19. 1967 _ I /NOTE~ NO PACXER OR JEWELRY 2 SIRr 200S' - 2020' 2201' - 2231' 23O2' - 2328' 2 ~IF ~0~ - 2380' NICOLAI CREEK KB - 16' PROPOSED SPUD UARCH 19, 1967 i _ I WB/J4F. J~ IN PL&~ 21~ ~ · ~ M]JENT IIU~ IIROM 101~ TO SURIrA¢£ 17 1/2- ~ StoLE sam 2 3/fi'. 4.E~. N,-eO u s/o-. s4.M. · noo~ · 7/0., Ha.E 2 ~FF 2302' -- 232B' 7". 2~. N-ID !'/ 1141' GEMENT PLU~ Ir/~17' - ~ (~JENT PLU~ F/7221' '{ STATE OF ALASKA ~ ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request: Abandon __ Suspend ~ Alter casing __ Repair well ~ Change approved program __ 2.~ame of O~er. ator k u-,u~.z.u_, ~ 5. Type of Well: unzon u~I Company of California Development.X_ Exploratory __ 3. Address Stratigraphic __ Service __ 4. Location of well at sudace ~.018, N'& 205' E from S,W, Corner Sec 29, TllN, R12W, SM At top of productive interval 3315 ' 685 ' N 983' E from S.W. corner Sec. 29, TllN, R12W SM At effective depth 3540 · 583 ' N 1060' E from S.W. corner Sec. 29, TllN, R12W SM At total depth 5011' 246· S 1602' E from N.W. corner, Sec. 32, TllN, R12W SM Operation shutdown __ Re-enter suspended well X Plugging _F,.. Time extension __ Stimulate __ Pull tubing x' Variance __ Perforate __ Other X 6. Datum elevation (DF or KB) 46' 12. Present well condition summary Total depth: measured true vertical Effective depth: ./measured true vertical Casing Structural Conductor Sudace Intermediate Production 58' 266' 1916' 3569· Length 5,011 4,102 3,540 2,999 Size feet Plugs (measured) feet feet Junk (measured) feet Cemented 30" 20" 13-3/8" 7" 300 650 1600 1500 sacks sacks sacks sacks feet 7. Unit or Property name 8. Well number .. 9. Permit number O38 ~10. APl number 0-2B3- I OO 11. Field/Pool Nicolai Creek BAFFLE PLATE 3540' NONE Measureddepth 80' 286' 1934' 3585' True vertical depth 80' 286' 1773' 3035' Liner Perforation depth: measured true vertical Tubing (size. grade, and measured depth) 3270'-3315' 2790'-2826' 2-7/8", 6.4#, Packers and SSSV (type and measured depth) None N-80 at 3508' 13. Attachments Description summary of proposal __ Detailed operations program .X BOP sketch .X.. 14. Estimated date for commencing operation Aug 1, 1991 16. If proposal was verbally approved Oil __ Name of approver Date approved Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed GARY S. BUSH ~ Title REGIONAL DRILLING FOR COMMISSION USE ONLY ,, Conditions of approval: Nqti~ Commission so representative may witness Plug integrity .,X, BOP Test __ Location clearance __ Mechanical Infe~ity Test __ Subsequent form required 10- ORIGINAL SI~NEO BY LONNiE C. SMITH Approved by order of the Commission Approved C~P¥ _.,=,~rneq Form 10-403 Rev 06/15/88 15. Status of well classification as: Gas __ Suspended Commissioner MANAGER Date I Approval No. 4:~/_ / ~['(~ SUBMIT IN'IIRIPLICATE ~:~ NICOLAI CREEK #2 i · · · · Se · · · · 10. MOVE IN AND RIG UP. KILL WELL WITH 105 PCF MUD. INSTALL AND TEST BOPE TO 3000 PSI. POOH WITH THE TUBING. CLEAN OUT TO ETD. RUN A THERMAL DECAY LOG ROM 3500' TO 1000'. LAY A BALANCED CEMENT PLUG FROM 3540' TO 3100'. WAIT ON CEMENTAND TAG THE TOP OF THE CEMENT. IF THERE IS STILL LEAKING GAS ON LOCATION, PERFORATE THROUGH TWO STRINGS OF CASING FROM 675' TO 680'. SQUEEZE THE PERFORATIONS WITH 200 SX OF CEMENT. 11. HOLD PRESSURE ON THE SQUEEZE AND MONITOR THE SURFACE GAS. 12. LAY A BALANCED CEMENT PLUG FROM 670' TO 300'. 13. LAY A B~CED CEMENT PLUG FROM 300' TO SURFACE. 14. 15. THE WELLHEAD IS NOT TO BE REMOVED· RIG DOWN AND MOVE OUT. NICOLAi CREEK #2 15' CURRENT SPUD 9-21-66 ,3S" HCX.E 28" HCX.E 20" ~ 2B8' CUT'D W/6~0 SX 17 1/2" HQLE: ANNIE.US ~ INHIBITED FRESH WATER 12 1/4' Ha.E TO 2322' g 7/8' HOI~ TO TD 2 ~2 ~PF FROU 3315' -- 3270' / ( 2 7/8'. 6.4~ TUriN. TO 350B' 5011' - 4086' UAXildUU ~(I.INATION 44 DEO ..-.-~.: ~ ~ .?~'--~:_. NICOLAI CREEK #2 KB = 15" PROPOSED SPUD 9-21-66 36" HCIL,E 2~ HGLE: cato w/6~o sx 17 1/2' HOLE 1:3 3/8" .,q4.odJ · Ig34' curo w/ 12 1/4" H01E TO 23~A' 9 7/f HOLE TO 'm 7" 26Ji N-BO · 3585' -i CEUENT ABJd, IDQNIdENT PLUG FROM 354O' -- 3100' 1/2 SPF' FROII 3.11f - 3270' GRB ~/12/91 BELL NIPPLE I FLOWLINE MINIMUM 2" KILL LINE WITH (2) 2" 3M VALVES I d; , KILL LINE FROM MUD PMP & CEMENT UNIT CONTRACTOR PROVIDE OPERATOR PROVIDE 13 5/8 3000 PSI ANNULAR IBLIND RAMS I I PIPE RAMS SPACER SPOOL I I 1 ISINGLE GATE 3M 13 5/8 3M FLANGE .~,, CHOKE: LINE WITH ONE REMOTE & 1 MANUAL .3" 3M VALVE rb r_r;~ I CONNECTED TO CHOKE MANIFOLD (SEE MANIFOLD DRAWING) SINGLE GATE 3M 13 5/8 3M FLANGE ADAPTER FROM 13 5/8 3000# FLANGE I 1,3 5/8" 3M BOPE STACK NICOLAi CREEK #l-A, 2, .3, UNION OIL COMPANY OF CALIFORNIA (dba UNOCAL) DRAWN: GRB SCALE: NONE DATE: 6/7/91 I II I TO WORKING PITS HYDRAULIC ACTUATED CttOKE TO RESERVE PRESSURE GAUGE PITS TO BOPE ~ 6?' MANUAL CHOKE CHDKE MANIFOLD UNaCAL REQUIRE]] 3"-3000 PSI MIN EXIBIT "B" ~ ~ TN~NER ~ FORM SA - I B 125.5M 8~67 MEMORANDUM TO: I-- -_ S~ate of Alaska.... "- DT, VXGXC~-G~ C,_XL ,M~-GAS check Co=~.)lecc, d ~:tt:egrator* calU:~ratt.~u.~ at 10:.~t ~.m. mb/ Xet'c fbg Am:borage,. ,a~i.v/.ug ar. 11310 a.m. and a.l: hom~ at: I1.:30. XXDCtX'xxxxxxxxxxx Wa1.terJ . Rieke 1 t Gogentor Jauuat:,. 11. 1967 ItEr: Ni- 1al Creek State' 2 'feøce . 1Rcorporated, Operator * .Cl.-' .It'OWA ~~,1aeoI'þør at" ',,0. - 664 Aukør..-. Ai_ka"" 1 lea. HI" 11:_: fti8 18 to _tit" .,... tMt the loll..!.. _terlalon ,. .. ject_ll U8..aot Mer.."""": I. 1Wocøp'..øf tbecømpletiml ~.t. 2. TIe. CØf1..ø! tbewl1 hi.tor, . It I... t:....ttW thatthfAutøial .. !oar.". Þ t.1t&.. olft.at ~ _.lie.' CODy_inc.. 'fo.- WI'1uul1 ~ -'1. *....11. J't *' 'airole.. 1--"180:- 11&/ )st Form P~7 SUBMIT IN DUPLI~L ! STATE OF ALASKA (see ~- ........ ~: structions on OIL AND GAS CONSERVATION COMMISSION reverse side) WELL COMPLETION OR RECOMPLETION REPORT AND LOG* la. TYPE OF W.:LL: OZL WELL [--1 GAS [~ ' WELL DRY [~ Other b. TYPE OF COMPLETION: NEW ~'1 WORK WELL OVER F~ 2. NAME OF O~TOR DEEP- EN ~] PLUG BACK [~ DIFF. RESVR. O Other TEXACO INC. ADDRESS OF _ P.O. Box 66A .Anchorage, Alaska 4. LOCATZON OV WE'.'. (~epor~ ~o~.o~ ~e~.,V ~.~ ~,, ~o~o~,,oe ~o~, ,a~? S~e .e~r~,)* At,~ 2018'N ~d 205'E. SW Cur :'~ec. 29 At ~ p,~. lnterval/_~,e~o~te4/~bel°w ~~ ~ /~.~:~:~ g~/~~ I Effective: July 1, 1964 '.~.'., .. · 5. LEASE DESIGNATION AND SERIAL' NO. ~?~.d NAME ?. UNIT AOREEMENT NAME ~. FARM OR LEASE NAME State of Alaska 9. WELL NO. Nicolai Creek Unit 10. FIELD AND POOL, OR WILDCAT Nicolai Creek 11. SEC., T., R., M., OR BLOCK AND SI~RVEY OR. AREA Surf Sec. 29-11N-12W At total depth :"', BTM Sec 32-11N-12W 2285 ' S and 1518' E I ~' PERMXT ~,O.' DATE ISSUED ~2. Bo~o,u~ ." 'l:' ~3. a'ATE.. of surface . [ 66-38 I 8-22-66 . Ke,nai [ A~ska ~. ~' ~'~.~ I~. ~, ',~.'~-~-i= ~,~ ~o~. ~,,,.,~ ,~o,.,. ~ ~. ~w,,o~ ~,. ~,. ~.',, ~,~.,. ~. ~,'~.. 9/~,/~~ I 10/19/66 I ~0/23/66 I ' ~:, .' il0' above · 4. PRODUCING z~','muVAL(S), OF THIS COMPLETION~TO~, BOi'x'OM, NAME (M~ AND TVD)*. '25. WAS DIRECTIONAL Ye~' Top MD 3270 TVD277~:: BT~ :~ tt,15 TVD28]& I~ddl~;?-Xen~i' ', .. 26.. '~.xr= .;~;azc ~D 0~ LOG~R~N IEs BCS, CDM, . ~L, ~R'/coll~r ,..,*, u> . . ~S. ' -~ ~v ~-" /20" .. ~ 9~B40':~ 286. I ;::;'.~6' :':' ~.~n ,~.'.'"- / 's "s I' :':I ',;;'.'..', · ': ~;' 80: z~' ,; LZ~aA~COaD ;.,~ .... '' . ~ , ' ': ' ,,,. SACKS CEM~"I i~~'~CREEN i(MD).. SIzE .i ~.)f~..!. ,, '' '' ('i182. ACID, SHOT DEP~ i~RyAL (MD) , . .. · , , '"I 'SZZE TOP (MD) BOTTOM ., ~o~ EECORD ~ e.~ ~ 2-~'...ho!es/FT...'. 3270,33.15. MD. ~'RO~,~¢TION' '. DATE ,FIRST PRODUCTION I PRODUCTION METHOD '(.~]OW~g, ga~ ~'~, pumping-'~z-~,ze a~(~ .t~pe oI pump) ~66 ...... Fl'owing ....... ~"" °' ""' '" I ~°~" '""'"~ I ~°~' "='.~ 6 7/16 ~ ':~'~"~''' "" ~" "'-~' 730 27. WAS WELL CORED N0 , ,, , . . , ,, 'AMOUi'¢T ~;ULLED i TUBING. RECORD D~.~. SET,__(MD). PACKER 'SET (MD) ,, FRACTURE, 'CEMENT SQUEEZE,'ETC .... . , AMOUNT AND .KI~D OF MATERIAL USED' ,. ,, I' WE£L STATUS (Pro~UcOq~ or - l: ' .Au;-**)' ". .. PROD'N. FOR TEST PERIOD 34. DZS~pSZTZ0~! OF OAS (~'o~, .~.e~ .for .fu~ · .. 35. LIST OF A~ACHMENT8 ..Q. GAS--MCF.. WA, TER--BEL. I GAS-OIL' RATIO WATER--EEL.' '" I'OIL GRAvZ'Tx-ipI..., ,,, (coda.),, JTES'T WITNESSED B~'; ' : · ,K, Oilbreth [ '' ._ * , ' 36. I nere~y certify that the~attached i~-ormation is eo~~l~e~4~t~-~.~l~.~f~~ all a~ailable records ..' " ~ '~ ~-. ANCHO~GE ~ ;~~ ,.',~ ......... ~ ,m~ ~man DATE' 1-17-67 ~ . . · (See I,,~mcfio,~ ~,~ $~ce, [or ~d~ffio.ml ~m~a on Reverie $i~e) ' 37. SUMMARY OF POROUS ZONES: " ' - , ':.;-'. -' · SHOW ALL IMPORTAI~T._ ZONES OF POROSITY AND CONTENTS THEREOF; CORED '~TERVALS; AND ALL .DRILL-S~EH ~BSTH, INCLUDIN~ ~8. - GEOLOGIC MAR~RS : DE~H INTERVAL TESTED, CUHHION USED, TIME TOOL OPEN; ~LO~VING AND SHU~IN PREH~UREH, AND ~COVERIE8 "~ . _ .. . -FORMATION ~' TOP ..' B~TO~ '.~' DESCRIPTION, CONTENT~, ETC. ' ..... TOP " . ~ ' ~ i , . ' ' ~ ; f;: ' "f- -' -' - ~--' : ' ' -"~ ' MEA~. DEPT~ TRUE ~ERT. ~ ' '.- : - "~ '- ': ~ii~ ' ', ' · · - ~"' at 3270 ";3315 -Nat~a ~-: o' .. - ...... e..'Te e '- ;~ .... . ' ":... --.~-". ""' -. -- : lot"detail~-~f:10~2~ 66 :.?- . All -~, . . . fj~ ....... . - '. ~ Point Test -" ~'~ ~. ?;-. ..... .. . - .~ s. Ke~a~f : .._: _ : _ ~: p. ~ - j ~ j[-~ : ;: ,.-.- . :.: ...; .-, ' : -.' -' _-- ? C~ .... .2 ..f. .: ..... - - [' t ' : ...... ,"'~ - ' .~ ~. - : . .. . ., *. . ~ ~ " ~ . , ~ ~ ?-~ (-?' j.,- ....... .fi :"". ..... -- ' ' .... ,.:. ,' '~'~ -: 1 2'2 ?'. _--'..] -:~[~' -.., '~ - -; -.;. ~ -,f - . . % '.. f- . .. [. -.~ · '-' - f ~'i- . , .-. . -:'--. :j_ ?.. ~- - · _ ..(.~ :. :. .-. ~ - · ..... .[ .'2~ -' ~.~. . ' . . ..4 .. - .... _ ..... .. ,-- .~ , '¥~. - . ~'% . ~ - -.: - . ' ': - .... -= ·" ' .... ~'-: ]~ [- "" :~ ... ~- i ; -- '" . : C-.]> --f "' 7~ . ~ r,-: ' '}~ '"" . a'f: ' - ) ..,- .. . , . -t->? ~. . ~-~ , -. ;- · .... ~ :'~ : _- " ~"' ":' "" : ' , '~ .~. ~ --~ -._ r.- - --~.fi, -'' .... - · . ~-.: :.- : ---~ [:- , ,..; . . ...... . .... - ~ ... .... :..' : l' ' ?: '' - '~ =--~ -.- .- ~;... ~ - ' '- , .- l- ~_~ ~ ---, · , - ~ - . ,_.' '.~ -. · -' ~_ -.. '~_ ~ :~.z- ~ .-.,.. . - - ..' :') ; ~1' ' ..... i"J 0 i.~ f-? -.: :: ' - " "' -'" .. . . ' ,::. .-: .. , 'lin ..'] A-' .: _F . ' : ' ._ ~- - :% ._. . · ~.. ..-~.. ~, ':: ;.~- . ;'-; - -: "- 4 O' : 'b q:~: ""~ . _- p--: _. ;-,;; --; -.~ ~ --- ~ - - . .. , . . .,~:- , ,~; -- ..-. ,. :%- -- :~. -. ,~0~ - :- ~: _ . .... . . ~ _ %. . ... .: : . . .... _ . . .... -.,_ . ~ ~.: ~-~ ', . ._ ,' - . _ _., .- INSTRUCTIONS ~.. :.:' ~ .. . : . ~..~ :.., 1. :.. ~.~. · General: This form is designed for submitting a complete and correct Well completion report and log on all ~ypes ' ' ':; :" b; .... - of lands.~nd le .~e.4[to et~er a _~era[1 agency or a Sta~e or bo~l~ pursuant to applicable Federal and./or State laws :~n.d regu~.ations. ~.An},'n,e. cessar..y, special..instru.cti?ns conc~.rning'the' use of this form and tl~ number of copies to be submitted, particularly with re§~ird to local, area, or regional proceaures ana:pr, ac[ices, ei[ner are snqwn oelow or will be:.issuedlb¥; 'or maY~be 0btainid, from, the local Fed6~al . and/or State office. ::-:.See instructions on items 22 and 24, and 38, below regarding separate-repot.ts for separate comp. l~tionzT' ' ~ :'..--~ -'.0 · '.~. :'.:. If not- filed prior to She time this 'summary. record is submitted, 'copies of all currently available ~Ogs' (.drillers, geolog/s'ts, 'sample dH/1 ~core afi~lysi~, all tY~es electric, etc[~', .forma- tion and pressure te~ts, anti directlo~'al surveys, should be attached hereto, to the extent required, by' applicable Fetleral and/0~-'State laws and. regul~[tions. All attachments should be listed on .this fo~m, see item 35. ' ........ · ..~ - . :., · I~em 4i: If there ar6 no applicable State requirements, locations on Federal or'Indian land should be described in. accordance ~'/th Federal requirements. Consult 10~i'.'~tate or Federal office for, Specific instructiohs. -- --. -:.:- - - -:- c_. .... : .... I,em ]8: Indicate which elevation is~used as' reference (where not otherwise shown) for depth measurements given in other spa'ces'-on thi~-for~and in any attachmenJ~':-'[ '- I~ems 22 and 24: If 'this well is completed for separate production from more than one interval zone (multiple completion ).[ so : state in' item,22, and in'item 24 show the producing interval, or intervals, top(s), bqttom(s) and. name(s) (if: any) for only the interval reported in item/~. Submit a sep..ara.te reliort. (page) on'this form, adequately Sdentified, for each additional;interval to i~e separately produced, showing the additional data pertinent to such interval.- ] _ : ]~'..-~: _.- : -[ ' ' :-_". : ~-2~ .- ~.~ . :-~ ::~ .' I~em 2~: ".~laclcs ~__~,~": Attached supplemental records.for'this well should show..the details of .any multiplF stage c~_m~ting ...~_ d-'the lodation~6f the '/~ementing tool. I~em~: . m~ .j' . _ . .:.. .,~ ~ :,. ....... ' ~' ' Sub '. a separate completion report on this form for-each interval to be separ~/_tely produced. (Se6 instruction for it~-22 and 24 above.) - . . . - .. ! ._. -- ."~- ?~! . ! _ . . ~-:. ,.--] :j -:~ . . .- . ...'~ _, -~. ~,~:_ -.... -.,-., ~ C: '_ ........ ' ~ -"J ;':-; -:D . " ::.':-. :' -. '. , '.~. . - , '%: ..,.- ~" ,.- ., - -: ..../,.-;.. :. · ;- '!'( :': ~-~ -' '"' '~' "'"" ' ..: - -. I .: ~ ... ~,-: .~ ... ~ : .... A.,,~ '. CODE. :: * ~-.:_ _ - ...... _ Re*lease Date State of Alaska Department of Natural Resources DIVISION OF MINES AND MINERALS Petroleum Branch INDIVIDUAL WELL RECORD S Meridian Permit No.. 66-38 Issued_. 8_.22.66 Operator Texaco_. Tpc., .... Location (Surface)2018'F8~. & 205' FI4I~, Sec, 29 Lease No. -ADL 17585 ...... or Owner ___Ni_c_p_lai Creek_ On_it ~... Loc. (Bottom) 2286'S & 161~9' E DE surE. loc. · - - = 266" I~L & 1624r'i~; S~(~*-32--~in S&c. 32) We 1 i NOD : Spud Date ....... 9,._..-21-.66, Area :. ~_i_co!ai_ Creek .Dril ling Ceased.., / VD 6086' ...... Total Depth ND 5011' Suspended_ _ _. Abandoned Completed (F-GL-P). :::_10_'23'66, Gas 3760.._,.......,~CF/D, Bean_ _'32 Elevation Casing:: Size Oepth~ SxCmt 30" 80' 300 20" ' 286' 650! 13'3/8~ 1936 1600 B/D, Grav APl 3565 ' 1500 _ :- :: : ,,. ~J., _ ..... ::__ 7:- ii iu ...... GEOLOGIC FORNA?I ONS PRODUCTIVE HORIZONS Surface Lowest Tested Name , Depth Contents VELL STATUS Year Jan Feb. Nar ,,,Apr May June July Aug Sept Oct Nov Dec ~L-:~:_~: ~':.:::~:::: ~"--" '-:!;;-"-'"--'-- :?' ~-:' - :":::: ::~? .... :!- : ..... -'" : ......... :-'-~':_" -'-_- :~:L:~-~: 't,' .... :- i' '~": _"' ', :__'--':' _;"_'-'-7':'-':':~-':"''' 1 AREA: WELL NO.: SURFACE LOCATION: BOTTOM HOLE LOCATION: DATE TEXACO INC. COMPLETION REPORT - NEW WELL jAN ,:, .. Granite Point, Alaska Nicolai Creek State $2 ANCHORAGE 2018' North and 205' East from the Southwest corner of Section 29, Township 11 North, Range 12 West, S.M. 2284.20' South and 1418.55' East of surface location (at depth 5011 ') January 19, 1967 R. L. Patton General Superintendent DRILLED BY: Reading & Bates DATE COMMENCED DRILLING: September 21, 1966 DATE C.OMpLE.TE~ DRILLING: October 24, 1966 DATE OF OPEN FLOW POTENTIAL TEST: October 23, 1966 SUMMARY ELEVATION: 30.4' GL; 46.0' KB TOTAL DEPTH: 5011'. PLUGGED DEPTH: 3540' CASING: 20" 91~ from 286' to surface cemented solidly to surface 13-3/8", 54.55 from 1934 to surface cemented solidly to surface 7" 26~, N 80 from 3550' to surface cemented with 1500 sacks. (Cement bond log showed solid cement to 2500 ') PERFORATIONS.: Two holes per foot 3315' to 3270' TEXACO Inc. Completion Report Nicolai Creek State $1 Sec. 29, T.11 N., R.12 W., s.M. -2- September 21, 1966: Spudded at 4:00 A.M. and drilled to 80'. Ran 30" conductor pipe to 80' and cemented with 300 sacks of cement. Had cement returns to the surface. .Septe_mber, 22, 1966: Cemented around top of 30" conductor pipe. and drilled ahead to 140~ with a 12~" bit. September 23 ~ 1966: Drilled to 290'. 19" bit. Opened the 19" hole to 26"° Septe_mb.er 2.4~ 1966: Drilled out cement 68 pcf mud Opened the hole from 80' to 290~ with a 75 pcf mud Raised mud weight to 82 pcf to stop caving gravel. Pulled the hole opener 'to check cutters and dropped 27½" of rotary bushing in the hole. September 2,,5,~ 1966: Attempted to recover rotary bushing fish° S~eDte~,e,r 26 ,_ 196,,6,: Hung open end drill pipe at 272' (top of fish) and pumped in 315 sacks of cement mixed with 10% sand and'8 sacks of CaC12. After four hours located top of cement at 199'o September., ,...2,7, 1.966: Drilled out cement from 199' to 203' with a 17½" bit. Drilled with a 12%" turbo drill from 203' to 312 '. Opened the hole to 19" from 203' to 312'. 78 pcf mud TEXACO Inc. Completion Report Nicolai Creek State %1 Sec. 29, T.11 N., R.12 W., S.M. -3- ~eDt~mber 28., .1966.: Opened the hole to 26" from 199' to 300'. Ran 9 joints of 20", 91%, casing with the shoe at 286'. Cemented the casing with 650 sacks of neat cement using inlet water. Float collar at 255'. Had good cement returns. S~eptember 29~ .... 1966: Welded on a Cameron casing head. Had slight gas.blow between the 30" and 20" casing. Welded a steel plate between the 30" and the 20" casing. Installed a 1" connection and valve and a 1" flow line to bleed off the gas blow. .September 30, .... 1966:. Installed the BOPE, choke and kill line. October 1,~ 19~.6: Pressure tested the BOPE at 600 psi for 15 minutes. Pressure tested annulus, okay. Pressure tested Casing below cement collar~ took fluid at 400 psi. Drilled out cement collar at 255' and cement to 299~. Placed a 50' cement plug across the shoe. Located top of cement at 280'° 83 pcf mud October 2.,. 1946: Drilled out cement from 282' to 299~ with a 12¼" bit. 94 pcf mud Qctober3, ..196.5: Drilled to 1290' weighted up mud to 100 pcf 0qt.°be~__.5, .19_6~6: Opened the 12%" hole to 17%" from 286~ to 385'o Reduced to a 12.%" bit and drilled to 1950'. 99 pcf mud .TEXACO Inc. --4- Completion Report Nicolai Creek State ~1 Sec. 29, T.11 N., R.12 W., S.M. .0q.tober 6, 1966: Opened the. 12¼" hole to 17½" from '385' to 1300'. 102 pcf mud October 7, 1966: Opened the 12%" hole to 17½".from 1300' to 1950', hit tight spot at 1540'. pctober.8~ 1966: Reamed tight hole at 900'. Ran IES log from 286' to 1950'. Commenced running casing, stopped at 320'.' Pulled out and ran a 17½" hole opener to bottom. Oct ober_ 9, _19 6.6.: Conditioning the hole and reaming. 102 pcf mud --October 10,. 1966: Ran 49 joints of 13-3/8", 54.5%, J-55 casing with shoe at 1934' and fill-up collar at 1896'. Cemented the annulus solidly with neat cement. Removed 20" BOPE~ installed secondary packing and installed 13-3/8" BOPE. October 12, ...... 1966: Cleaned out hand cement with a 12%" bit from 1896' to 1928'. Drilled to 2322'. 99 pcf mud O_cto_ber --13,_ 1966 Drilling, surveys, and making trips, 9-7/8" hole from 2281' to 2700 °. October~_7 ,. 19.66: Drilling, today's depth 4488'. 91 pcf, mud TEXACO Inc. -5- Completion Report Nicolai Creek State 51 Sec. 29, T. 11 N., R. 12 W., S.M. Octob.~e.r. '19, 1966.: Drilled to 5011'. Ran IES, dipmeter and sonic log. October 20,.. 1966: Ran 7", 265, N80 casing with shoe at 3550' and baffle plate at 3508'. Prepared to cement. .Q~qtob. e.r 2!, 1966: Cemented the 7" casing through the shoe at 3545' with 1500 sacks of cement. Had good fluid returns but no cement.. Landed casing in slips through BOPE and packed off. Removed the BOPE and installed the. tubing head and adapter.spool. Reinstalled and pressure tested the BOPE at 1500 psi. Ran a 6-1/8" bit on tubing to baffle. Measured out of hole. Effective plugged depth is 3540'. Octobe,r__~2, 196~: Ran Schlumberger gamma and bond log. Good bond from bottom to 2500' fair from 2500' to 1900' and no cement above 1900' Gun perforated two holes per foot from 3315' to 3270'. Made up and ran Haliburton tester on tubing. 'Set at 3225'. ..October 23, 19.66.: Opened the tester valve at 7':10 A.M. and had gas to the surface in one minute (no cushion used). Flowed on %" choke cleaning up. Tested at the following rates: Choke T..ubi.nq Press~u_re .F. ~low~ Rat.e 20/64" 995 psi ~ 2460 MCF/D 24/64" 800 " 2760 28/64" 740 " 3600 32/64" 630 " 3760 (Open flow potential was calculated to be 6,600 MCF/D). Rate approved by State of Alaska representative as evidencing lease validation. Pulled the tester, circulated to kill. Ran open end tubing to 3508'. Removed the ROPE, installed the tree. TEXACO Inc. -6- Completion Report Nicolai' Creek State ~1 Sec. 29, T. 11 N., R. 12 W., S.M. Qct.o~er. 24, 1966.: Circulated the well with inlet water, killed the well. Released the rig at 1:00 P.M., October 24, 1966. .3 t . ,F¡<!b'm No. P-4 { STATE OF ALASKA (' OIL AND GAS CONSERVATION COMMITTEE EfCeetive: July 1, 1964 LAND Of"FlCE Anchorage LEASE NUMBER 175g5 LEASe: OR UNIT NAME Nicolai Surface AN 034161 ~. 'ß Creek LESSEE'S MONTHLY REPORT OF OPERATIONS State -m-mAl.a.ska---mm--___m- B oroug h -______K~~~~._-_____--mm------- Field m_--_--~ ~-~-~_~_~.~m~=-!!~_____.---m----m__u__n_- The followint is a correct report of operations and production (includint drillint and producint wells) for the month of n____De.c.emb_(!T-__---------------, 19~_~_, --------______mn_nnn_mn________mn___m_____-----__n______nn- A~ en t' B. add;: B ~m p It:~::x---66l.- - noon - no m __mm,- n n- m_- 0 ~ m pan Yi;Em - - ~~A ç Q --!~Ç - ~ ¿¿: - - -- -- - - - m- -. --.- ---___Aw:hQ27~:î8i5h_hmm_h_,__m__mh m______-- -- -_om _mh- &v.e~ __om - - - ~ð"h- -_----_m __"m_- m--m- Phone -----------___----n_____- _m____m______-------------------------_--_--__m___- Atent 8 t e --F-J...e.ld- -For-eman.__- -- _m_______m_- BBC. AND Twp. RANGB WNBOL.L DAY. BARRBLS 01' OIL GRAVITY CU" FT. 01' GAS ~ 01' ~ PBQDVO8n (In thousands) GALLONS OF BARRELS OF REMARKS GASOLINB W ATBR (If (If drU1inc. depth; if shut down, Gause; RECOVERED none, so state) date and result of teet for caaoliDe oontent of þ8) 29 NW-SW 111 12W 2 0 Nico18i Creek Unit Well shut in entire month. ~ 7Qt:!c C> W t:;/ ~/è)r I- ¡:~ 7 ,~ r~tftv- m~' '¡¡.$/> änlu> .,I¡f~- ¡Is. '7.i::ohf~ c£a?'f'~, ~.. )-1 ì-fÞ~ Ct [~~ I , \\. ¡r' , \:l f f) .JAN 1 õ J!9,61 DIVISION Of MiI'H:S & MINERAL:) ANCHORAGE NOTE.-There were """""--00""9.........--................. runs or sales of oil; ........00.00...0.............00....00........ M cu. ft. of gas sold; ....................oo....................Q............... runs or sales of gasoline during the month. (Write "no" where applicable.) NOTE.-Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Division of Mines & Minerals by the 6th of the succeeding month, unless otherwise directed. Form No. ,, STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE LESSEE'S MONTHLY REPORT OF OPERATIONS Effective: Suly 1, 1964 J~(4 · ~o .~,c~ Anchorage ~,~,~ L~A.E.,,M.~. ADL 17585 ~ ~ ~'~ ~. Nicolai Creek Surface Lease ~03~161 State ....... ~3_a~ka .................... Borough .........K~ma-i ..................... Fiel,t ......... Nicola~---¢r-eek ............................... T~e followin~ is a eorreot report of operations and prod~tion (in~l~din~ drillin~ and produ~in~ we~Zs) for t~,e mont~, of ....... ~_0y_ember ................ , z9_6~ ................. Dece~er.__8.r__t.9(:~ ..................... · 4~er~'s address~.,l h ;~;r ~'! t,. ......... ~"* O*"-B°'x--~(~I; ............................ Corr~pan?] ......... ?~-~i;(~oo--- -~'1~:,- ........................ ..................... o-'.~ _7 /~.~./'~ ~"' -/" --C--O~ -"~ e-r- - ----,. a~,,..a o~nea ............ ~: ........... -_>_.,.. _~._(,_.c_~:.~ ........... Phone .... ......... 2.7.'7__.]_ 8_1__5 ................................................... //gent's t~tle .... Ei.~ld..F~:~.~n ................... ~EC. AND ~4 o~ ~ ?w~. ll~ 291W/-SW No 1 BARRE~ OF OIL Lcolai Cr Well ORAVIT' eek shu Or. Fe. oF GAS (In' thousands) ~nit in ent j (][ALLONS OF GASOLINE RECOVERED ~e mont BARRE~ OF WA~mR (If none, so state) .~ of No REMARKS (If. drilling, del)th; if shut down, oauoe; mate end result of teet for g,~,ollae content of eas) 7ember. NOTE.--There were ..................... 11(1 .................... runs or sales of oil; ...................1~.0 ....................... M cu. ft. of gas sold; ................................... 11~ .................. runs or sales of gasoline during the month. (Write "no" where applicable.) NOTE.--Report on this form is required for each calendar month, regardless of the status of operations, a~,n.d rn~st,~. · ?"-'.. ~..,, ,,,.., ,.,. , ,. be filed in duplicate with the Division of Mines & Minerals by the 6th of the succeeding mor~.h,i:..uriles~,,,, o~h'~'Wi, se ii ) directed. ~'~. ~ .... ~,...... ,~ ' .; ',. GAS '( =LL OPEN FLOW POTENTIAL TEST 4-POINT TEST Test ,nitial ~-] Annual r-] DRT Special Field j Reservoir Nicolai Creek Kenai Formation Operator J Lease Texaco Inc. A.D.L. ~17585 Test Date 10-23-66 Jv,,'en ×o. ~2 Nicolai Creek county Kenai J Location j co~o~o~ ~a~e j To,a~ge~m Peninsula Borouqh Sec. 29 TllN-R12W, SB&M 10-24-66 5011 TBG. J CSG. Tempera%ute 'Temperature X 120 ~F 64~F 7" 26 6.276" 3550' T/Pay Producing Interval 3270'3270-331! 2~" 6.50 2-7/8" 2.441" 3225' 0.575J 3225' Pipeline Connection J Type Taps None ] Critical Flow Prover Gas-Liquid Iiydr0carb0n Ratio MCF per Bbl. -- Gravity of Liquid (Api) ~%Iultiple Completion (Dual or Triple) J Type production from each zone Single j Dry Gas . OBSERVED D2~TA Flow Data Time (Prover) (Choke) Press. Diff. Tubing Casing Flowing No. of Flow (Line) (Orifice) Prover h Press. Press. Temp. Hours Size Size psig w psig psig °F s~ - - - 1180 - 1180 - - ~... ........ 2:33 2 '.' 2.4/64 '.~ .800 - 8.00 - 64 ~. 0: 33 , 2, 2 8/64, 74 0 - 74 0 - 64 ,. 2 :o.s I" . - .... - _.. FLOW CALCULATIONS Coeffi- ~hW Prover ~X Gravity Compress. AIo. eient P Pressure Factor Factor Rate of Flow (24 Hr.) m ' psis, X~Xt~ F F . Q MCF/D g pv ' , ~.... 39.77 - 1010 17.32 - . 1. 065 2.460 -- ~. 56.58 - 815 17.45 - 1. 045 2~ 760 ~. 81, 09 - 765 17.45 - 1. 040 3[ 600 ,._ 101.p - . 645 17.45 - 1 030 3,760__ PRESS'C RE CALCULATION~ P p w Cal. 'i;' (psia) P":t Fe q (F c q)~ (Fe Q)'" X 1-e's prxv pre -- Pz'w Pw P w t c z. SEE ~ACHi~ NTS .... , ,,, Absolute Potential J n 6,..~QQ 5~CF/D,J 0. 676 " Los Angeles Division, CERTIFICATE: I, the undersigned, state' that I am theMan~V' of the (company), and that I an, authorized by said company to make this report; and(~aqq~)re~'tX~gre-Inc' pared under my supervision and direction and that the facts stated therein are true, correct and COmplete to' the best of my knowledge. DIVISION OF: Mtb4ES & MINERALS ANCHORAGE 'Signature T. L. Kunkel Alaska Oil and Gas Conservation Commission Gas Well Open Flow Potential Test Report (4-Point Test) Form No. Authorized by Order No. Effective October 1, 1958 0 0 0 1.0 2.5 3 4 RATE OF ii. FLOW ;~ 8 ':~ I O MMCF /DAY ~E C. F 1 V E ,,g DEC i I966 PlVI~ION U~' MINES ~ MINERALS ANCHORAGE CALCUIATION OF ABSOLUTE OPEN FLOW POTENTIAL TEXACO-SUPERIOR NICOLAI CREEK Calculation of the open flow potential of Nicolai Creek %2 was based on the plot of flow rate as calculated from surface measure- ments vs. bottom hole pressure data as measured directly on subsurface charts during the flow test. Test Period (10-23-66) 7 .-10 AM-8:45 AM 8:52 AM-il :25 AM 11:28 AM-l:33 PM 1:37 PM-2:10 PM 2.-10 PM-2:42 PM 2:42 PM-3.'35 PM Basic test data is given below: Surface Stabilized Tbg Stabil. Btm. Surface _Choke Pressure, . Hole Pressure TemD. 16/64" 880 psig - 24/64" 800 " 1060 psig 32/64" 630 " 930 " 64 28/64" 740 " 960 " 64 2 0/64" 995 " 1090 " 64 0 1180 " 1253 " 62 58" F 64 Flow rates were calculated by the method described in the Engineering Data Book of the Natural Gasoline Supplyman's Association, 1957, page 6. Open flow potential was determined from the attached graph. GKR: JMcN 11-22-66 i. I966 OF MII'qF,S & M!NERAL$ ANCHORAGE '5- Solve for the value of flow rate Q where p2 BHF euals 14.7 psia. p2 - (14 7)2 BHS · = 2,84'6,000 -216 = 2,845,784 Extrapolate the liue t~hrough the 2 uppermost poiuts to t'his value. The flow rate at this point is 17,700 MCF/D. Note that the slope of this line is 0.813. Also note that the maximum pressure draw- down d~ring t~his test was 75% of the Sh~t-in pressure. Texaco Iuc. -4- 0._037,,6)( O. ~75_) (3,~2~) (518) (o.845) = 1.190 ~4%~4" e ¢o.o~?,5)¢o.5~)(3%~.) = ]- ].85 · (5~2') (o~ ~5~) ;- ' 32/,64" e (.0'037'6)(0,~-5)(35...25) (52%)(0.880) = 1.179 Solving for values of p2 (Where - . ..... BHF PWHF is prover pressure, absolute) ~rifice __ 24/64" _Values of P2BHF __ (1.192)(2.289 x l06 + 0.053 x 106) - 0.053 x l06 = 2.737 x l06 (1.190) (2.079 x 106 + 0.368 x lO6) - 0.368 x lO6 = 2.547 x 106 (1.185)(1.812 x 106 + 0.664 x l0`5) _ 0.6,64 x lO6 = 2.271 x 106 (1.179)(1.350 x 106 + 1.625 x 106) - 1.625 x l0'5 = 1.880 x 10,6 Solving for (Bottom Hole Static Pressure )2 minus (Bottom Hole Flowing Pressure )2 · 1 _ ,1 11,111 j., 111 , , , , ,11 ~ _ _ , ,lllll L. I I - IL Note: P2BHS = (1,687)2 = 2.846 x 106 Orifice --: 11 z~/~4" ~o/~4" 24/64" 32/,64'" v~?~t~ o~ ~,~s,~~ _ _ 2,846 x lO6 - 2.737 x lO6 = 109,000 2.84,5 x 106 - 2.547 x 106 = 299,000 2.846 x 106 - 2.271 x 106 = 575,000 2.84.6 x 106 - 1.880 x 106 = 966,000 Determination of Absol'ute Open Flow Potential - 'PlO~ t'~e fOllowing' values"'of Q v'~rs~mS .... P2BHS - P2BHF o.'n 2 cycle log-log paper: Orifice ©.. ]-2/.54." ].,.~o ].o9, ooo 24/.64,, 4,840 575, ooo 32/64. 7,350 966,000 -3- Solution friction head of only 1+ psi, but in 292' the head due to the gas column is 12+ .psi. Greater accuracy results from using mid perf depth). p2 BHF = B (P2wHF + A) - A where A = 0.O000151 Z2 T2 Q2 0. 0376 GL and B= e T~. Values of compressibility (~) were determined for each flow rate, using values of PR and TR previously listed. Compressibility was corrected to t'he average-value in t'he flow stream, by applying the increase of 0.02 found in the calculation of E for determination of static bottom 'hole pressure. The tabulation below Shows values for Z for surface ~nd flow-string conditions: Orifice ~ur~Ce_ ~Z~4" o. ~5 2o/.64'? o 825 32/64" o. 86o ~olving for valMes of A ___ Orifice C, 0mp~essibility. (,~,) Flow n o.~5 o ~45~ O.88O Values of A __ , 111 _~__ _(o.ooooi5i)(o 835)2(5i5)2(i,~I~o)2 = 5.29 x io4 ...... (°'°°°°i5i)(°'845)2(5i8)2(3 690)2 3 68 x 105 ' ~°'9.°q°~)(°'8~8)~(~)~(4,84o)~ = ~.~4 x ~o~ (~.45~)~..~~ ......... __ (o.oooo151)(o 88o)2(525)2(7,35o)2 '- i~.44i)~',~] ~Solving for values of B _ ~,__ 0rific___._._~e ~Values of B ( o. o~,76 )(o.~95) (~) i2/64" e - (SIS) = 1.625 x 106 = 1.192 -2- Calculation of Absolute Open Flow Potential ...... (C0ntinued~ Orifice 'Dilator., i'n c P _ ~ ~ Fpv 12/64 14.47 1513 2.26 1.49 1. ll5 20/_64 39 77 3~ 14590 . i 2 2.14 i 1.110 24/.6~ 56.58 1 2.00 1 1'. 099 32/.64 101.8 11~2 1.72 1.52 1.081 24/~64 56.58 1317 1.96 1.50 1.097 20/64 39.77 1372 2.04 1.50 1.099 12/64 14.47 1433 2.13 1.49 1.110 T 515 518 522 522 518 Q, 3,690 4,840 7,350 4,690 3,45o 1,330 .Calculation of Static Bottom Hole Pressure ,(?RI-IS_,) _~L : _ ' . : HII IJl[ j'il ,, I .. : - , , ,., ,iii Well'head static pressure (PwHs) = 1546 psia Gas gravity (G) = 0.575 Average temperature of gas in the tubiug = .Su~rf. ~e~mp. (50°F) + res,_ temp.....(.10~°F) + 460 2 = 537°R 'Depth of well (L) = 3525'. (depth to mid-perfs) GL No~.~: Compressibility (N) is first determine.d at surface temperature and pressure to 'be 0.80. The equation for PBHS is t'hen solved. .PBHS = 1690 psia. Next, for mean pressure between 1546 and 1690 psia, B is determined to 'be 0.82. The equation is then solved with this corrected compressibility. Corrected PBHS = 1687 psia, which is the value of static bottom bole pressure 'used in the following calc'uls~ons Calculati.on of... plowing Bottom, H,o!e _.,Pressure Kn0~ data -- -- _111 I _I Q = flow rate, MCP/D, at 14.7 psia and 60°F PWHS = well "head static pressure, psia (1531) PBHS = bottom 'h01e static pressure, psia (1687) L = length of gas cOlumn, feet (3525) G = gas gravity (0.575) - °R (variable) T - average flow temp. in well, D -~ inside diameter of tubing, i:nches (2.441) (Note: L is dept'h to midperfs instead of the full length of t'he tubing, because the difference of :72~2' produces Calculation of Absolute Open Flow Potential Texaco-Superior Nicolai Creek #1 _ .May_ 12.-1%, 196.6 . Summary of Basic Data Orifice Tubing Casing ~iam..in.: P~r~e~s s .psi8 Press.p~siE Prover Temp. Pres.s,psiE °F Shut in 1531 1531 - 50 12~64 1498 1509 1498 55 20~4 1427 1448 1427 58 24~64 1331 1375 1331 62 32~64 1147 1269 1147 65 24~64 1302 1347 1302 64 20~64 1357 1379 1357 62 12/64 1418 1420 1418 58 Shut in 1496 1496 - - Gas gravity = 0.575 N2=O (assumed) CO2 = 0.2% Reservoir temperature = 105O. F C~alcul.a. tion of_fi.ow .Fate Time Hr:min. Remarks - Shut in 2:15 Trace mud 4:06 Clear 12:02 Clear 7:07 Clear 2:08 Clear 1:47 Clear 1:00 Clear 44:17 Shut in ~here Q = flow rate, MCF/D C = orifice coefficient for 2" prover, Engineeri~ng 'Data Book, Natural Gasoline Supplym~ns Association, 1957, page 6. P = prover pressure, psia pv = superexpansability factor, from 'California Natural Gasoline Association Bulletin No. TS-461 G = specific gravity (air = 1.000) T = temperature at prover, °R ., lln determining ~pv.. : Pc = 672, critical press'ute and Tc = 348, critical temperature. Values of PR, pseudo-reduced pressure, ~nd TR.~,~' pseudo-reduced temperature, obtained from CNGA Bulletin TS-461, are tabulated below. Also listed are otlher values 'used in the flow rate equation and t'he calculated flow rates. PAYING QUANTITIES TEST NICOLAI CREEK #2 TEXACO INC. Texaco men on location: Jim Barber. Engineer; Don Hartman, Geologist; and Ray Strahan. Drilling Foreman Perf 3315 to 3270. DST #1 PBTD 3543 Csg shoe 3585 7" 26~ N 80 - Time T. P. _ . 7:10 a.m. 7:22 a.m. 7:28 a.m. 7:31 a.m. 7:40 a.m. 7:47 a.m. 7:55 a.m. 8:00 a.m. 8:30 a.m. 8:45 a.m. 8:52 a.m. 8:57 a.m. 9:00 a.m. 9:05 a.m. 9:30 a.m. 9:39 a.m. 9:58 a.m. 10:07 a.m. 10:18 a.m. 10:28 a.m. 11:08 a.m. 11:2-2 a.m. 11:25 a.m. ' 11:28 a.m. 11:40 a.m. 12:23 a.m.., 12:38 a.m. 12:42 a.m. 12:44 a.m. 12:48 a.m. 12:53 a.m. 12:58 a.m. 1:01 p .m. 1:20 p.m. 1:30 p.m. 1:30 p.m. 1:37 p.m. 1:38 p.m. 1: 47?p.m. 1:52 p.m. 2:07 p.m. ..C. hpke~' Size '~emperatur.e , , . Opened tool - GTS 30 sec. opened 1/4"bean 880 1/4 44 44 900 1/4 52 52 892 1/4 54.5 C.I. to tighten leak Opened up again 1/4" bean TPCI 1050 990 1/4 50 960 1/4 53 880 1/4 58 S.I. to change choke to 3/8 Opened on 3/8 choke 610 3/8 56 650 3/8 58 7O5 3/8 6O 760 3/8 62 763 3/8 64 770 3/8 64 770 3/8 64 770 3/8 64 770 3/8 64 8OO 3/8 65 8O0 3/8 65 $.I. to change to 1/2 Opened on 1/2 choke 580 1/2 64 540 1/2 64 540 1/2 64 580 1/2 64 600 1/2 64 600 1/2 64 620 1/2 64 620 1/2 64 630 1/2 64 630 1/2 64 630 1/2 64 C.I. to change to 7/16 choke Opened on 7/16 choke 910 7/16 54 750 7/16 62 740 7/16 62 740 7/16 64 Remarks ........ (1505 MCF) Clear Heavy mist Heavy mist Heavy mist Heavy mist Heavy mist Heavy mist Heavy mist Lt. mist (2876 MCF) Lt. mist Lt. mist Lt. mist Lt. Mist Very light mist Very light mist Very light, mist Very light mist (4.22 MMCF) 2.7 MMCF PAYING QUANTITIES TEST, NICOLAI CREEK #2, TEXACO INC. (Cont'd) Time T.P. Choke Size Temperature Re~arks 2:07 p.m. C.I. to change to 5/16 choke 2:10 p.m. Opened on 5/16 choke 2:15 p.m. 1000 5/16 61 2:20 p.m. 995 5/16 62 2:25 p.m. 995 5/16 62 2: 40 p .m. 995 5/16 62 Clear Clear Clear Clear (2.52 MMCF)' O. K. Gilbreth, Jr. Petroleum Engineer October 23, 1966 OKG/cjh SYMBOL OF SERVICE REPORT of SUB-SURFACE DIRECTIONAL SURVEY TEXACO, INCORPORATED COMPANY NICOLAICREEK N NIGOLAI WELL NAME CREEK LOCATION ALASKA JOB NUMBER. L9 - 9766 TYPE OF SURVEY SINGLE SHOT DATE SEPT.- OCT. 1966 SURVEY BY LONG BEACH OFFICE ,,mm .RECORD OF SURVEY' ..,0, o, .~, :, Dso ~ l Co~ot~on ~5' -- ' " ~UE M EABU R ED DRI~ VE~CAL DEVIA~N ~E~ ...... r - ~ DE~H ANGLE DE~H ~Sx[ : 30, 85 5 37~ O0 ~'~' 3~ 73 ~a~..~.~.-.': . 558 lO0 1~'~~ 553 ~0 [~ ~° 00, T3~ e~ s 33' ~,x 8~ 3 53Tx . n 834 ~ ~6'~, 8~]T5 3 o ~ x3x7 6o ~, ~395 ~ 1632 ~ '~' 15~ 63 33 55 418 ~5 . 218 ~6~ 95 22 ~ ~ ~ 33~'~' 16~ 02 ~ · g ~'g ~ 3~9~ 19~ :~ ~' 1~ ~66 ;~ ~~' 1863168 T~ ',8 E Z5 ~311 O0 43' 00' 20~ 8716~ ~ S ~ O0'E 800 16 ~8 91 NI00~ . .... ~ ' . , ~' .- i i _ i i i i · i lB i 'I'RUB' COURB~' DRIIrT' .R~CTANGUL&R COORDINA'r~'B MF..ABURED DRIFT VERI'ICAL frATION DEPTH ANGLE: DEPTH DEVIATION DIR"r~TION ' ' -- ' ' ' ' - , , , ~71,7 O0 39"30' 23'5266 128 '~98.29'00'1~ 10~.~29 ; 01 - I 31 34].~- I00 3g"30, 2(388 1~9 58 ,13 32'00'~ 1;4.05 ~]. 11~. 1501 889 12 3, 3592 O~ ~,30' 302? ~ ~ $ 33'0O ... O0 3~65 ~ ~99 Z~ S 33'00'Z ' ' · ~2°30' 15 25 S 35'00'~ - .~. 5Oli,oo ~i-oo, i~69 s ~5'oo,~ ._ 55 · . _ i i i i jl _ i i__ il/~:a:'~.: RECORD OF SURVEY ..0, 0,,,~., ~D Dec ' 1 Correetion 2~' -. ' i !. I i i i -.,^.u.,.~ o.,n u~ .ATIO" DE~H ANGLE VER~AL COUPE DRI~ R ~ C 7 A N.-G U ~ A R C O O R D ' N A ~. .~v,A~. ~~ ~~ ' ~U~H I '~ W~ 2 1 oo -3o, 8D 2 35 $ '~ .. ... ~ ~ 2~0 '- 10 iO0 14°00' 73a aa~ s ~3'~,E _. 81 53 T1 ~~ " ,. ~1 83~ 16'~ 8~ 75 2~ 81 S. 31-~,E :: -102~ ~ 66 ~9 . ~ 9~ ~ ~5, ~9 3~ ~ ~ s 3~0~,~ 2~ ~ 8~~ ~o~ i~ ~' ~ 3~ s 33' ~'~ ~ ~ .. ~,~ ~:~,~o~ ~~o ~ ~-oo,. ~ ,~~ - , - I~ 34'~, 52 ~S.33~E,.: ~21 ~ ~. ~ .,oo~. '~, 15~63 3355 S . ~'E '- ~18 ~D49 .. . 21 O0 ~'~, 16~ 95 T2 89 S' ~,~ . . ~3 B9 19~ ~ 3 e~' 1~4 82: 57'S ~8e~,K ~6 ~ ~~' ~B63 68 7~ ~ ~S ~'~"E 6~ 03 387 9~ ~ ~3~ oo ~3' oo' ~o4~ 87 ~67 o9 s -~ oo'E .- 8oo ~6 ~ 9~ ~-~ . .-~ ~ ~.~ . : ..... ' ...... L m .--.' i i m mm I I i II m i TRUE COURBlf DRIPT R E. C T A N C~ U L A R C O O IR D I N A 1' ME. ASU RED DRIIrl' VERTICAL ' . .... :~TATmON DEI~I'H ANOI. mm.. D[PTH DEVIATION DIR[CTION NORTH BOUTH EA~r '-~6 252.5 oo ~.;;'oo, 2~96 80 25 271,T oo 39"3o' 2352 66 128 ~9 s ~9'oo'$.: 3.043. 29 605 oo 30 ~ 59 :~5 76 8 3x'oo,~ :L].57 66 33. 3J412:00 3~30' 28138~3 1.1.9 58 ,~ 32: O0,E :I~.05 ~! 8~,677 3S 3592 30 ~ 30~f Bp. ~ s 3.3'00 44 88.9 O0! · 3~5 28 Z99 ~f S0o! 35 , 4~°30' 15 25 S 35'00'E - 1-g97 31 1222 ..~ 5on oo 4].-oo, ~_p.:69 s 3ff'oo,m;' .- z4~ .5.5 CLO~]li~ L:,688 8~, S 31° 50 . . . NZ¢OL&3[ ~ ~ ~ mm I" · 200' ., DEPTH - 5011' SOUTH - 228420' EAST - 1418.55' CLOSURE 2688.84' S ~,I"50'E NICOLAI CREEK N~. 2 L9 -9766 ,O~%lX r Operator: TEXACO~ INC. Well: Nicolai Creek State,# Comp letion Date: Oct. 23, 1966 Release Date: Nov. 23, 19.~8 The. Files contain the following material: Office File 1. Permit to drill and location plat ........... 2. Reports of operations and sundry notices ....... 3. Well history ....................... 4. Completion report........ ......... . . . 5. Directional survey 6. Electrical log, Induction. , , ,, ........... , and sepia 7. Lithology or mud log, and sepia: . . . . ..... . . . 8. Other log 9~ Four Peint ,Open Flow Potential Test Release File Remarks: There are samples available for this well/. FORM SA-I B 100M 9/65 MEMORANDUM State of Alaska Pedro H~nera~s Lea~ f~-tg DATE : }~vembe~ 16s 1'966 ~i.cola£ Creek .~o, 2 - ADL 175~5 r~reseuCa'.~ive o.~ =his of~ce. ~ ~h~ .ces~ ~he ~l p~oduce~ fl~ ~as !~ ,..'.. ?.,.~ ...,/ Form SA I HE. HORANDUM To Thomas R. Marshall Petroleum Supervisor I t,k 3V,t Pedro Denton Minerals Leasing Officer LJA'I'i SIJBII.CT November 14, 1966 Well Capable of Producing Oil and/or Gas in Paying Quantities. Application for determination of the below identified well as capable of production in paying quantities and shut-in has been filed. Please inform us whether the available technical evidence supports such determination of well status. Texaco Nicolai Creek No. 2 gas well ADL 17585 REP/pb RECEIVED N,:OV 1 b '1966 ,QIVI$1ON OF MINES & MINERAL~ ANCHORAGE Form No. P--4 ,, ., STATE OF ALASKA '~ OIL AND GAS CONSERVATION COMMITTEE :i Effective: July 1, 1964 ~ · ,,,,,.:, .-,,-,-.,-,- Anchorage ,~,~>'. · ,-,,~,-,,,..,,,..,~,~ ~:;DL 17585 ",'"'..", ...... '~ ,., .~..~. Surface Lease AN 134161 LESSEE'S MONTHLY REPORT OF OPERATIONS State ............. Alaska ............. B , , r o u g t , ......... K .e. .n. . _a_ _ :k .................... F i e l , t ............. '., ~ '.m. . c. . _o. _ .l. . .a. _i. . . _ . .C. . .r. . _e. . .e. .k. ........................... TI~e following is a eorreot report of operations and prodz~etion (inel~din~ drillin~ an, d prod~ei~ ~ezzs) for t~e ~o~t~ of ................. D_c~_eher_ ........ ]9_6.6. ................. ~Lo..v._,__._.l..,._.~.=9.6_.6.. .............................. · ~lie~t's address ..... ~..Q - ._Box.__6_6_4_ ................................ Company ........... ~.e~a..6~...]I_n_..c__, ....... ~' .............. .... Anchor.a_.ge ~ A~aska $~ned ............ ..~q~.~__~_..?_.~_ Pl~one ................................................................................... .~I~er~ffs ti t/e~--;---F-i~l d---Fcrz:e4~n .................. ation of ling Nic( lO/1 sg. She P: 10/2 d cement dri!ied 10/3 - 12-~" hol. opened 1o/7 ~og. 10/8 d to run /8" csg. :t.o/.9, 17½,, hoZ. 10/10 ," casi: th shoe SX' C e] lO/ll ;mented 2, Set s 12" ser': lO/12 9 7/8" h, o 5011' r logs. .. 10/20 6# N~0 c. ~543'. 10/21 through shoe': wit 10/22 s and 'pa. , tore 61 alled BO: CBL les per ~315 to on tubin 10/2~ .uction t 'itnessed P.O. te~ ran and ee, disp mud wit] .nd shut ll. e remain 'f period. OALLONS OF (~ASOLINE RECOVERED )lai Cr, .aced 51 ~head i: ;o 17½" Stopp~ ~t 193~ ~ips an~ :D. Raj 1500 ~ ~o~ t. nd gaz 270. by Nr. landed inlet ~ARRETZt OF WATER (If non~, ~ ~e) ~ek Uni~ sx pl 12¼" to 195( at 3: Ceme packi: 1ES, ~x ceme Lnstall ~a/coll. gade UP O.K. G: tubing water ~ R DI¥1$1C REMARKS (If drillinL deoth: if shut down, eauoe; date and reault o! te~t for f~motin~ confront of &,as) #2 .g across shoe. ~ole to 10lO'. 0f. ~ted through shoe ~g. Changed CS and .t. .~d tubing head and -~.r logs. Shot and r'an [lbreth, State of , installed unloaded EC[:IV[O ~0V 1 1961S OF MINES & MINERAL8 ANCHORAGE NOTE.--There were ........... 1~.0 ............................... runs or sales of oil; ........ N.O .................................. M cu. ft. o£ gas sold; ......................... ~O ............................ runs or sales of gasoline during the month. (Write "no" where applicable.) NOTE.~Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Division of Mines & Minerals by the 6th of the succeeding month, unless otherwise directed. For~;~ No. P~4 ,', STATE OF ALASKA '{ OIL AND GAS CONSERVATION COMMITTEE Effective: July 1, 1964 ~, .... ..-r,c. A ,cnorag'e $u~ace Lease AND 3416] LESSEE'S MONTHLY REPORT OF OPERATIONS State A q ~.glra Borough ....... ~...6..z..z.~.~_. ....................... Field .......... ~:~.~:-~%~-~..._~,~.~.~.~I ............................ T~e followin~ is a eorreo~ repor~ of operations and production (incl~di~ drilli~ and prod~cin~ werrs~.. / /~¢~r tke mont~ w~ ..... , 19_ ~ ~ ~ " ~ '~ ' ~ '~ ~ ................ ~ ............................................. V ...... ,.._.,.,_,...,..,.... ................... ~', addre,, ......... l~-.-O-.---~x---~ ............................. Oompan~ ......... -~o-~a~o---~n~.- ........................ ........ ............................................ ....... ............ P~o~, ............... 2-7-7~8-1~ ................................................. ~,~*, *~l'~---~-~-o-l~---~o-r.~ma~ ................... SEC. AND CU. FT. OF (~&8 ~/~ OZ~ ~ BAszm~s or 0~. (In thousands) 9/21 9/22 9/2~ 9/2& 9/~5 9/26 9/_27 9/28 9/29 9/30 ~M 9//2 ;ation target 30" £ mast ;op hard d through ~nd pack !0t' BOPE Nicolai and 205 on $26© in' 36" h .led 12¼" to 26" t ling in h at 19~ to 26" )f 20"', 9 at 286' surface i~c!udi GA~IA'INS OF RECOVERED Sreek U E fro cours o!e ho~e ti 290 ' ;ole. and and ~ 300'. ~#' H-z~C ~ncl sta ~g sing BARRE~ OY WATER (If none, so state) nit #2 m SW 0¢ e from o lbO ' ishing. 8% cac casing bin col le g~te REMARKS (If drlllinL del)th; ii shut down, aauee; date ~nd result o~ test for eo~te~t a[ r Sec 29 surface. lo o lar at 256'. and Hydril. RECEIVED NOV 1 1966 )IVI$10N OF MINES & MINERA~ ANCHORAGE NOTE.--There were ................................................runs or sales of oil; ................................................ M cu. ft. of gas sold; ............................................................ runs or sales of gasoline during the month. (Write "no" where applicable.) NOTE.~Report on this form is required for each calendar month, regardless of the status of operations, and must be filed in duplicate with the Division of Mines & Minerals by the 6th of the succeeding month, unless otherwise directed. FOk~:::~A-I B 100M 9/65 .. MEMORANDUM State of Alaska DIVISION OF MINES AND MINERALS TO: ~Thomas R. Marshall, Jr. ~ Petroleum Supervisor DATE : October 28, 1966 FRoM:O. K. Gilbreth, Jr. Petroleum Engineer SUBJECT: Paying Quantities, Texaco Nicolai Creek State ~/2 CONF!,DENTIAL On Sunday, October 23, 1966, I went to the subject location by company charter plane to witness a gas test to determine if the well would produce in "paying quantities" for lease validation purposes. A DST was underway when I arrived and the well was flowing gas. Field measurements and volumes are shown on the attached table. At approximately 3:00 p.m. after eight hours of testing, I advised Texaco personnel that I was satisfied that the well would produce in paying quantities. The well was closed in for BHP buildup and operator planned to kill well and pull test tools. Final completion equipment is to be installed immediately and well is to be shut in waiting for market. I was advised that Texaco has been negotiating with Mobil to furnish standby and make-up gas for Mobil's Granite Point onshore crude storage facilities. Also, they have discussed furnishing fuel for the Drift River facility, but do not actually have the output contracted at this time. I arrived back in Anchorage at approximately 5:00 p.m.by company charter plane. Approximately two hours of travel time were involved on this trip and there was no time spent waiting on operator. OKG/cJh ~ Enc. cc: J. A. Williams, Director, Division of Hines and Minerals (w/o enc.) NOTE: This well tested at a maximum rate of 4.22 million SCF of gas per day With a tubing pressure of 630 p.s.i. Production was from the perforated interval 3270' to 3315'. Texaco personnel believe this is producing from a different pool from the field discovery well. OKG/kp FORM SA-I B 100M 9/65 MEMORANDUM FROMP. 1~. Gilbreth, Jr. State of Alaska DATE : SUBJECT: Potlut!o.~ Observations on ~ietd 'Pctp. to Texaco ~reek ~tate ~2 On October 23, 1'966~ I £1~ to the subject iocacion by T~xaco cha~te~ ~ri~. ~e took .o££ a~ approxtmate, ly 9:1~ a.u~ .~ .t~'t ~fore .on the Inlet C~t ~e~ed Co. be..= oil slick, I as~ ~ ~iloc Co t~ o~t to l~k a'C it i~ he ~eed, ~ 8~t tn .~sti~ .~ered i~lcate~ this ~ts ~t oti,. but .~ t~e. of t~ ~ o~ a br~ish corr. As ~ t~ ~ ~ t~ Inlet, s~eral ~.1t~ areal ~.t~t ~e ~~ ~re the $~i.t~ enters ~ tie vas c~inS ia at this t~, t~ debr~ o.bs~ ~en=ly C~ ritz. 'I might ~inc ~ t~t /rom a tist~e oi ~p'~~tel.y ~ miles of ~'o,iI slic~, t~~ this va~ ~t t~ case. Oi~/I lc .ih LA~%rD D~P~.i~TZ~ENT LOS -~%i,~G~LES. CALIF. October 3~ !986 STATE OF AI~ASI{~-. LEASE 3~L 17585 Director, Division of Land State of Alaska 344 6th Avenue Anchorage ~ Alaska Gentlemen: We are hereby notifying you that we have'spudded the Nicolai Creek State ~ v~2 well on the.subject leased land on 9-21-66 at the following a~proximate location: 2018 feet North and 205 feet East from the Southwest corner of Section 29, Township 11 North~ Range !2.West, SM. Yours very truly, T~XACO Inc. TLH: rq Air Mail Cert. Mail OOT'i i !9Ii6 ANC.HOI;[AG~ TEXACO Form G-6 RECEIVED SEP 2 9 1986 OIYI'~ION OF MINES & MINERA, i.~ ANCHORAG~ -' 3001 Porcupine l:~rive Anchorage. Alaska 99M1,~ v, 1966 Wells ~nclosed please ~t~l '~he. approved p.~~ ~o .drill for .mib,$ect ~e.ll, A ~,~ viii ~ ~o~~ ~. ~ In ~ ~ ~e. 'IC all~ ~ ~t~8 re~,sC~ tot chis ~11 ~ s~ipul.~C, es' C~C p~~C:l~ viii ~ ,al.~a~ be~n t'~' 8as ~l~s in a ~ ~ ~. ~t ~ut ia a fie~ s~.'~ or~r ~ich viii. be issued be.tore p~~i~ t~ ,e'i~ ~ ~. 1 .or ~. 2 ~11 ~'11 be ~ld. Tho~ 'R, .~arshal. l, Jr, Pe.c~oleum Supervisor FORM SA-I B 100M 9/65 :' MEMORANDUM TO.. ~, .,~,, ~illia~S, Bi~ec~.o~ Div. o£ ~Lnes and ~.lnerals FROM:~/IO~J R. ~ars.~all, Jr. Petroleu~ Superviaor State of Alaska DATE : ~U~at 22, 1966 ,SUBJECT: Filin~ Fee ~l~closed is check i~. I-2~8'11 fo~ $50.00 and approved application for pe~ait ~o drill Hf¢olai C~eek ~ni~ ~2 froa~ Texaco Ina. ... Form P--1 Slp, TE OF ALASKA OIL AND GAs CONSERVATION COMMISSION SUBMIT IN TI~' CATE' (Other tnstruc~,~-,s on reverse side)., APPLICATION FOR PERMIT TO DRILL, DEEPEN, OR PLUG BACK 'fa. ~'z~'n OF WORK DRILL I~ DEEPEN I--! PLUG BACK [-] b. TYPE OF WELL OIL WELL ~] OAS SINGLE WELl, [~ OTHER ZONE ~] MULTIPLE [~ ZONE 2. NAME OF OPERATOR -- 'TEXACO ~nc. S. ADDRESS OF OPERATOR 3350 Wllshire Blvd. Los Angeles, Calif. 900.05 ' 4. LOCA-EiON OF WELL (Report location clearly and in accordance with any State requirements. ) At_surface 2_018~ N. & 2051 E. from Southwest corner of ~ec. 29, 'TllN, R12W, S.M, ' At proposed prowl, zone _ 2610' S. 26° 3]$z E. from surface location. 14. Di~,£A~,a IN M!r.msl AND DIREC'~ON FROM NEAREST TOWN OR POST O]FFICE' TO NEAREST WELL, DRILLING, COMPLETED, 21. mv.mVA~io~S (~c-w wh~-_--~ DF, RT, OR, etc.) 11.~? miles S 72 W Tyonek Po.st Office 1§. DISTANCELOCATiON FROMTo NEARESTPROPOSED' . H ii 10. NO. OF ACRES IN LEASE P,oPEE,, OR LEAS, LINE. l 00' 5655 (Also to nearest drlg. unit line~ if an~) ~.. DISTANCE FROM PROPOSED LOCATIONS 19. PROPOSED .DEPTH - ,,P...~ POE. o, ,Hi~ =~E. ~. 2200 z' B. 5000 z Approx 10', Mmmw (ar) 2S. Effective: July 1, 1964 pROPosED CASING AND CEMENTING PROGRAM --'~E~SE DESIGNATION AND 8RR.TAL NO. urf Anch 0~1 Rtm Hole ADr. 17~ ~. IF Z~DXAN, ALLOTTEE OR TRINE 7. UN~ AG~EMENT NAM~ 8. FARM OR .LEASE 'NAME State of Alaska 9. WELL NO. Nicolai Creek Unit 1'0. ~imLD Ale~ POOL, 'OR WILDCAT , Kem~ Pen. NO. 'OF AC]~S 'ASSIGNED TO THIS W~LL 6.o ' Pool ' ~1. BEC., T., R., M., OR BLUr. AND SURVEY OR AREA' _Btm:NW~. Sec 32-11N-12W 12. B.O~tOUOH sHI 18. STATE I Alaska 20. ROTARY,:OR :~A~LE TOOLS Rota~y J '22[:. ApPnox. D£TE WORX Wlr, L START* I .8-eo-66 Well deViated offshore as shallow water will not accommodate 'drilling vessel. RECEIVED AUG ! 1966 DIVISION OF MINES & MINERAl. ANCHORAOI~ Statewide 0il & Oas Bond No. B-17, January 18, 196~, in mount of $100,000.00 ZN ABOVE SPACE DESCRIBE PROPOSED PROGRAM: If proposal Is to deepen or plug back, give data on 'present productive zone and p.rOposed new productive zone. If Proposal is to drill or deepen directionally, give pertinent data on subsurface locations and measured and true v~rtieal d~pth8. ~ .Gl'Ye blowout preventer program, if any. . .. . 24. I hereby 'ce~;ifF that the Foregoing is True and C~rect.- -..__,..----.--------- · ,.G~,~ '~'/ ~ TITLE ASSr · Division Ma~.. a~er AT,. ___7"2 6-- 66 ('This space for Federal Or State office use) , '' ~O~AS R. MARSHALL,,'J~ A~J0VJD BJ ~Z~LnExecutive Secretary eo~mo~s o~, ~: " Alaska Oil & Gas ~n~ation ~mmi,ee ~B~T ~ ~ONSE~VATION 0~ ~}28.' *See In,ruction, On Referee Side SUMNARIZED WORK ORDER NICOLAI CREEK UNIT July 26, 1966 SURFACE LOCATION: +-2018 N & 205 E from SW Ocr. Sec. 29, TllN-R12W SUBSURFACE BOTTOM HOLE LOCATION: +_2610' S 26' 34' E from surface · location. ELEVATION: G.L. 31 ' 1. Drill +-26" hole and cement solid 80' of 20" conductor pipe. . Drill +-12~" hole to B20'. Open hole _to +_17~1" from shoe o'f ' conductor to B20'. Run BOO' of 1B-B/8", 54.5~, J-55 casing and cement solidly through shoe at +-B15". If cement does not return to surface do an outside cement Job. Install BOPE. Drill 12~" directed hole to 2020' and log well as directed K0P 350' Buildup at B°/~i~00' to 40° then hold at 40' Direction S 26° 34' E Run +_2000' of 9-5/8", 40#, N-80 casing. Cement solidly through shoe'. If cement does not return to surface do an outside cement Job. Install BOPE.. 5. Drill 7-5/8" hole to 5000' required. Run logs and other services as 5 Run +-3100' of 5~", 17# blank liner. Hang liner at +-1900' With shoe at 5000'. Cement solidly from shoe of liner to the liner top. 7. Obtain WSO above gas sands and in liner lap. 8. Perforate gas sands and complete well as directed. NOTE: Coordinates of well bore from surface location will be as. follows: Coordinates 'Depth soUth .... Ea~ Vertical Dept,h 3555' 1493.2 746.7' 3000' 5000' (TD) 2334.7 ' 1167.4. ~10.7' RECEIVED AUG 1 1966 DIVISION OF MINES & MINi~RAL,S AJ'~ICHOEAGE 15 N =200 NICOLAI CREEK N~ 2 ,~ , DEPTH - 5011' SOUTH - 2284.20' EAST - 1418.55' CLOSURE 2688.84' S :51°50'E L9 - 9766