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Home My WebLink About202-162CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Wallace, Chris D (OGC) To:Jesse Mohrbacher Cc:Scott Pfoff; Christian Wood; AOGCC Records (CED sponsored) Subject:RE: NCU 1B injection well fluid disposal (PTD 2021620), DIO 44 Date:Wednesday, October 8, 2025 1:28:02 PM Attachments:image001.png Jesse, Thanks for the email and call to discuss the cleaning and flushing plan. AOGCC agrees that the flushing/cleaning wastes meet the DIO 44 Rule 2 waste eligibility, and also the RCRA Exemption for Oil and Gas Exploration and Production, so can be disposed of via the NCU 1B Class II disposal well. As discussed, the plan/procedures should ensure only solids-free wastes are disposed of, and so the MIT frequency shall remain as 4 years. Next MIT due before or during August 2028. If you need additional clarification or have any additional questions, please get back to me. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 orchris.wallace@alaska.gov. From: Jesse Mohrbacher <jesse@solstenxp.com> Sent: Wednesday, October 8, 2025 12:01 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: Scott Pfoff <gspfoff@amaroqresources.com>; Christian Wood <CWood@solstenxp.com> Subject: NCU 1B injection well fluid disposal Hello Chris, Amaroq Resources is preparing to inject waste fluids from the Nicolai Creek Unit production operations prior to winter freeze up. Additional pre winterplans include draining and flushing the gas dehydration system and the injection disposal of the flushing/cleaning wastes. Below is Rule 2 from DIO 044,which states the allowable fluids for disposal. I am writing to confirm that any fluids (water/methanol/etc.) used in the flushing process can also beinjected into the NCU 1B well. Please let us know if the AOGCC agrees with this interpretation for Rule 2 or if Amaroq needs to formally request approvalfor injection of these wastes. Also, if a formal request is necessary, should that be in the form of a letter or other document? Best Regards, Jesse MohrbacherPresidentSolstenXP Inc.907-244-4537 celljesse@solstenxp.com MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, November 25, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Amaroq Resources, LLC 01B NICOLAI CK UNIT 01B Jim Regg InspectorSrc: 01B W SPT 2223 2021620 1500 360 360 360 360 280 290 290 290 Four Year Cycle Pass It took longer to pressure up with their little pump than it did to test, but we got it done. 30 MinPretestInitial15 Min Type Test Notes: Interval P/F Well Type Inj TVD PTD Test psi Tubing OA Packer Depth 990 1750 1745 1745IA 45 Min 60 Min 50-283-10020-02-00 202-162-0 Sully Sullivan 8/12/2024 Well Name Permit Number: API Well Number Inspector Name:NICOLAI CK UNIT 01B Inspection Date:Insp Num: Rel Insp Num: mitSTS241028100157 MITOP000010645 BBL Pumped:0.2 BBL Returned:0.2 Monday, November 25, 2024 Page 1 of 1 9 9 9 99 9 9 9 9 9 9 9 9 9 9 9 9 5(9,6(' James B. Regg Digitally signed by James B. Regg Date: 2024.11.25 10:45:49 -09'00' Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov September 17, 2024 Mr. G. Scott Pfoff President Amaroq Resources, LLC 4665 Sweetwater Blvd, Suite 103 Sugar Land, Texas 77479 Re: Docket OTH-24-006 Notice Of Violation - Late Mechanical Integrity Test (MIT) – Closeout Nicolai Creek Unit 01B (PTD 2021620) Disposal Injection Order (DIO) 44 Nicolai Creek Unit (NCU), Nicolai Creek Southern Undefined Upper Tyonek Gas Pool Dear Mr. Pfoff: On April 16, 2024, the Alaska Oil and Gas Conservation Commission (AOGCC) issued a Notice of Violation (NOV) relating to the apparent failure of Amaroq Resources, LLC (Amaroq)to provide information and testing that was required to be completed and submitted regarding the demonstration of mechanical integrity for disposal injector NCU 01B. The NOV required Amaroq to provide AOGCC with; - a state witnessed MIT of the inner annulus, with 48 hours witness notification, in accordance with DIO 44 Rule 4 and clarified in Industry Guidance Bulletin 10-02B; and - the post injection temperature survey. Amaroq to strive for continuous injection conditions (suitable volumes and duration of disposal) as appropriate for running the temperature log. Results to be provided to AOGCC along with a Form 10-404 summarizing the well work performed. The AOGCC has received and verified the Amaroq responses dated September 5 and 16, 2024. AOGCC considers this NOV closed. Sincerely, Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner cc: James Robinson, US Environmental Protection Agency, Region 10 Jim Regg Phoebe Brooks Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.09.17 12:19:11 -08'00'Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.17 12:49:43 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Monday, October 28, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Sully Sullivan P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Amaroq Resources, LLC 01B NICOLAI CK UNIT 01B Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/28/2024 01B 50-283-10020-02-00 202-162-0 W SPT 2223 2021620 1500 360 360 360 360 280 290 290 290 4YRTST P Sully Sullivan 8/12/2024 It took longer to pressure up with their little pump than it did to test, but we got it done. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:NICOLAI CK UNIT 01B Inspection Date: Tubing OA Packer Depth 990 1750 1745 1745IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSTS241028100157 BBL Pumped:0.2 BBL Returned:0.2 Monday, October 28, 2024 Page 1 of 1 9 9 9 9 9 9 9 9 9 9 9 99 9 9 James B. Regg Digitally signed by James B. Regg Date: 2024.10.28 13:37:40 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Temp log Amaroq Resources, LLC Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 3672 feet cmt ret 3500' MD feet true vertical 3618 feet feet Effective Depth measured 3560 feet feet true vertical 3546 feet feet Perforation depth Measured depth 2307-3575 feet True Vertical depth 2254-3521 feet Tubing (size, grade, measured and true vertical depth) 2-7/8" J-55 3396' MD 3342' TVD Packers and SSSV (type, measured and true vertical depth) G-77, 2275', 2222' G-77, 2436', 2372' G-77, 2761', 2707' VTA, 3145', 3091' No SSSV 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and G, Scott Pfoff Digital Signature with Date: Contact Name: Jesse Mohrbacher Contact Email:jesse@solstenxp.com Authorized Title: President Contact Phone: 907-244-4537 320-198 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Gas-Mcf 69 (annual 2024) 210 20 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 210 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 1300 Length 232' 1904' 232'Conductor Surface Intermediate Temp and pressure logs during produced water injection 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL 17585 & 391471 Nicolai Creek South Undefined Upper Tyonek & Beluga Undefined Gas STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 202-162 50-283-10020-02-00 4665 Sweetwater Blvd., Suite 103, Sugar Land, TX 77479 3. Address: Nicolai Creek Unit #1B Size 232' 10.75" 7" Liner 2186' 3650' Casing Structural 2137' 3594' 2186' 3650' MD 1580 3270 1530 2730 3130 4360 measured TVD Production Plugs Junk measured 2275, 2436, 2671, 3145 2223, 2382, 2617, 3091 1904' 1904' Burst Collapse 520 1130 20" 13.375" p k ft t Fra O s 202 6. A G L PG , C Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov 4665 Sweetwater Blvd., Suite 103 Sugar Land, Texas 77479 (832) 999-4603 September 11, 2024 Alaska Oil and Gas Conservation Commission Via Email: aogcc.permitting@alaska.gov 333 West Seventh Avenue Anchorage, AK 99501-3572 RE: Form 10-404 Report of Sundry Well Operations, Sundry # 320-198, Nicolai Creek Unit 1B well, PTD# 202-162 Please find enclosed Amaroq Resources, LLCs Report of Sundry Well Operations for the temperature log that was run on August 13, 2024 in the Nicolai Creek Unit (NCU) 1B well. The temperature log was run during the last hour of active produced water injection operations where a total of 69 bbls of 59o F water was injected on August 13, 2024. This limited volume is the total anticipated injection volume for 2024. Prior to the temperature logging operation, approximately 56 bbls of produced water was injected. The purpose of the temperature log is to confirm that the injection fluid is confined to the injection zone from 2307 to 2370 MD. The following information documents the work performed: AOGCC form 10-404, Report of Sundry Well Operations Current NCU 1B well schematic Daily operations report for the temperature log work Temperature and pressure survey plots for time plot, RIH, POOH, RIH POOH overlay and 2019/2024 temperature and pressure log overlay The data listed above shows a smooth temperature curve running in the hole (RIH NCU-1B temp 13AUG24) until the bottom of the perforations are reached at 2370 at which point the temperature of the fluid in the tubing rises rapidly below the bottom perforation. This rapid temperature rise indicates that injection fluid is not flowing below the bottom perforated interval. Above the injection zone, the temp log curve has a constant slope and does not show evidence that injection fluids are migrating above the injection zone. If you have any questions or require additional information, please contact me at your earliest convenience at 832-999-4603 or Jesse Mohrbacher at 907-244-4537. Sincerely, G. Scott Pfoff President Amaroq Resources, LLC Amaroq Resources, LLC Nicolai Creek Unit # 1-B Current Configuration (August 13, 2024) Drilled 26"Hole 20" 94# H-40 Conductor set at 232', Cmtd to surface w/300 sx "G". Drilled 17-1/2" Hole 10-3/4 casing (not shown) sidetracked with 8-1/2 window from 2186 to 2207 13-3/8" 54# J-55 Surface Csg at 1904'. Cmtd to surface w/ 1530 sx "G". Carya 2-1.2 Perfs: 2,307' -2326' MD 2,350' - 2370' MD (TVD 2254 '-2316') Carya 2-2.1Perfs: 2480' -2486' MD (TVD 2426' -2,434') Carya 2-2.2 Perfs: 2604' -2622' MD (TVD 2550' -2568') Carya 2-3 Perfs: 2837' -2842' MD 2862' -2867' MD 2913' -2918 ' MD (TVD 2,783' -2,864') Carya 2-4.2 Perfs: 3191' -32ll ' MD (TVD 3137' -3157') Carya 2-5.1Perfs: 3371 ' - 3401' MD (TVD 3307' -3348') Carya 2-6.1 Perfs: 3560' -3575' MD (TVD 3506' -3521') Float collar @ 3604' MD Float shoe @ 3648' MD TD @ 3672' MD (3617' TVD) Sliding Sleeve w/ X-profile @ 2263' (closed) G-77 Packer @ 2275' Hole in tubing @ 2294 Sliding Sleeve w/ X-profile @ 2359' (Open) G-77 Packer @ 2436' Tagged fill at 2569 13Aug24 WF P.O. Plug in tubing at 2602 Sliding Sleeve w/ X-profile @2749' (confirmed closed 12Jun2020) G-77 Packer @ 2761' X-nipple @ 2774' (PX plug in X-nipple) VTA Packer @ 3145' XN Ni pple @ 3184' Well completed with sand exclusion screens across the indicated perforations bottom at 3396'. J an 2013- tag at 3255' Cement Retainer @ 3500' Lower 3 completions treated w/ Weatherford Sand Aid 2010-11 7" 23# J-55 Production Csg @ 3650'MD (3595' TVD). Cmtd to surface w/ 82 bbls "G" lead at 12.5 ppg and 67 bbls "G" tail at15.8 ppg. I AmaroqWell:NCU-1BField:Nikolai Creek 08/13/20244550556065707580850500100015002000250014.5 15.0 15.5 16.0 16.5 17.0Temperature (Deg.F)Pressure (psia)Time (hrs)PressureTemperatureGauge Passes1900' - 2564' RKBPulling out of holeStatic/InjectingGoing in Hole Static/InjectingReport date: 10-09-24 Well: Field:08/13/2024Amaroq NCU-1B Nikolai Creek 45 50 55 60 65 70 75 80 85 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 0 250 500 750 1000 1250 1500 1750 2000 Temperature (Deg. F)Depth (feet) RKBPressure (psia) Pressure Perfs PKR 7"2 7/8" Sliding Sleeve 13 3/8"POOH Press Temperature POOH Temp Pressure-Temperature Profile 1. RIH-POOH Overlay 2. Static/Injecting Report date: 10-09-24 45 50 55 60 65 70 75 80 85 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 0 250 500 750 1000 1250 1500 1750 2000 Temperature (Deg. F)Depth (feet) RKBPressure (psia) Pressure Perfs PKR 7"2 7/8"Sliding Sleeve 13 3/8"Temperature Well: Field:08/13/2024Amaroq NCU-1B Nikolai Creek 35 40 45 50 55 60 65 70 75 80 85 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 0 250 500 750 1000 1250 1500 1750 2000 Temperature (Deg. F)Depth (feet) RKBPressure (psia) Pressure Perfs PKR 7"2 7/8" Sliding Sleeve 13 3/8"Press 2019 Temperature POOH 2019 Pressure-Temperature Profile1. RIH 2019 Baseline vs 2024 Injecting 2. Static/Injecting Report date: 10-09-24 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov April 16, 2024 CERTIFIED MAIL – RETURN RECEIPT REQUESTED 7018 0680 0002 2049 1150 Mr. G. Scott Pfoff President Amaroq Resources, LLC 4665 Sweetwater Blvd, Suite 103 Sugar Land, Texas 77479 Re: Docket OTH-24-006 Notice Of Violation Late Mechanical Integrity Test (MIT) Nicolai Creek Unit 01B (PTD 2021620) Disposal Injection Order (DIO) 44 Nicolai Creek Unit (NCU), Nicolai Creek Southern Undefined Upper Tyonek Gas Pool Dear Mr. Pfoff: On February 26, 2024, the Alaska Oil and Gas Conservation Commission (AOGCC) notified Amaroq Resources, LLC (Amaroq) of an investigation into potential missing information and testing that was required to be completed and submitted regarding the demonstration of mechanical integrity for disposal injector NCU 01B. Missing information was identified as including the following: - Subsequent Report of Sundry Well Operations (Form 10-404) as required by the Sundry application 320-198. - The initial post injection mechanical integrity test as required in Sundry 320-198 and Disposal Injection Order 44 (Rule 4) and clarified in Industry Guidance Bulletin 10-02B. - Subsequent temperature survey 1 month after commencing injection into NCU 01B. - Annual reservoir pressure survey of the disposal zone as required in DIO 44, Rule 6. The AOGCC was reviewing whether injection operations into NCU 01B comported with the requirements of the approved sundry and disposal injection order. Amaroq was requested to provide the above noted information by March 20, 2024. By letter dated March 20, 2024, Amaroq acknowledged the investigation notice, supplied a background and timeline, resubmitted the 2021 and 2022 Annual reservoir pressure surveys, and responded to AOGCC’s inquiry. On April 2, 2024, Amaroq also submitted the 2023 Annual reservoir pressure survey Notice of Violation – Late MIT NCU 01B Docket Number: OTH-24-006 April 16, 2024 Page 2 of 2 (Form 10-413) to AOGCC along with a revised 2022 report. Amaroq contends that “stabilized reproduceable long-term conditions” have not been achieved to date, and that this is justification for not performing the required post injection MIT and temperature survey. AOGCC acknowledges that the disposal operations at NCU 01B have been sporadic and not ideal for establishing a reproduceable temperature log profile. Amaroq has committed to a wellwork plan including a MIT and wireline work scheduled for “summer” 2024. To bring the well into compliance, AOGCC requests Amaroq complete on or before August 15, 2024: - a state witnessed MIT of the inner annulus, with 48 hours witness notification, in accordance with DIO 44 Rule 4 and clarified in Industry Guidance Bulletin 10-02B; and - the post injection temperature survey. Amaroq to strive for continuous injection conditions (suitable volumes and duration of disposal) as appropriate for running the temperature log. Results to be provided to AOGCC along with a Form 10-404 summarizing the well work performed. The AOGCC reserves the right to pursue an enforcement action in this matter according to 20 AAC 25.535. Failure to comply with this request is itself a regulatory violation. Should you have any questions about this violation notice, please contact Chris Wallace at 907-793-1253 or chris.wallace@alaska.gov. Sincerely, Brett W. Huber, Sr. Chair, Commissioner cc: James Robinson, US Environmental Protection Agency, Region 10 Jim Regg Phoebe Brooks Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.16 16:25:34 -04'00' 4665 Sweetwater Blvd., Suite 103 zz Sugar Land, Texas 77479z (832) 999-4603 March 20, 2024 Sent via electronic mail Alaska Oil and Gas Conservation Commission Attn: Brett W. Huber, Sr. Chair, Commissioner 333 West 7th Avenue Anchorage, Alaska 99501 RE: Docket OTH-24-006 Investigation of Late Mechanical Integrity Test (MIT) Nicolai Creek Unit 01B (PTD 2021620) Disposal Injection Order (DIO) 44 Nicolai Creek Unit (NCU), Nicolai Creek Southern Undefined Upper Tyonek Gas Pool Dear Mr. Huber, We are in receipt of your leƩer dated February 26, 2024 requesƟng informaƟon on the Nicolai Creek Unit (NCU) 1B well. Per that leƩer, the AOGCC is requesƟng the following informaƟon: x Subsequent Report of Sundry Well OperaƟons (Form 10-404) as required by the Sundry applicaƟon 320-198. x The iniƟal post injecƟon mechanical integrity test as required in Sundry 320-198 and Disposal InjecƟon Order 44 (Rule 4) and clariĮed in Industry Guidance BulleƟn l 0-02B. x Subsequent temperature survey 1 month aŌer commencing injecƟon into NCU 01B. x Annual reservoir pressure survey of the disposal zone as required in DIO 44, Rule 6.A BACKGROUND AND TIMELINE August, 2019 ApplicaƟon for Sundry (#319-346) approved. October 4, 2019 Sundry #319-346 work completed. October 21, 2019 Report of Sundry Well OperaƟons, Sundry #319-346, Nicolai Creek Unit 1B well, PTD# 202-162, AOGCC Form 10-404 submiƩed to AOGCC. October 29, 2019 DIO applicaƟon submiƩed to AOGCC. December 12, 2019 AOGCC hearing. January 28, 2020 DIO 44 issued approving disposal well NCU 1B. March 3, 2020 ClariĮcaƟon of Rule 6 request (email), Mohrbacher to Wallace and response. Docket Number OTH-24-006 March 20, 2024 2 May 8, 2020 Sundry NoƟce and Form 10-403 submiƩed to AOGCC. June 12-13, 2020 Wellwork performed including inner annulus and tubing MIT. June 19, 2020 Pre-InjecƟon MIT Report(s) 10-426 submiƩed to AOGCC. July-August, 2020 Facility work. August 21, 2020 Amaroq commences injecƟon operaƟons and to date has injected 21,446 bbls of produced water from the NCU gas Įeld. Days of injecƟon totaled 150 and the last date of Ňuid injecƟon was September 11, 2023. No solids laden Ňuids have been disposed of in the well. Surface pressures and rates were conƟnuously monitored during injecƟon and documented. Pressure never exceeded 900 psig as required by DIO 44. Records are available for AOGCC inspecƟon pursuant to Rule 6. Amaroq’s Response to Data Requests Subsequent Report of Sundry Well OperaƟons (Form 10-404) as required by the Sundry applicaƟon 320-198 AŌer receipt of the DIO on January 28, 2020, Amaroq requested clariĮcaƟon by email on March 3, 2020 of DIO 44 Rule 6, which required a post injecƟon temperature log and whether or not the iniƟal temperature log performed under Sundry #319-346 met this requirement as well as the meaning of stabilized injecƟon operaƟons. Chris Wallace of the AOGCC responded on March 5, 2020 (see aƩached email chain). In that email exchange, Mr. Wallace conĮrmed that a temperature survey would be required “aŌer suĸcient conƟnuous disposal operaƟons have been completed that Amaroq believes the well is experiencing stable reproduceable long term condiƟons”. Over the course of injecƟon operaƟons on the NCU 1B well, Amaroq has never established stable reproducible injecƟon condiƟons. Originally, Amaroq envisioned conƟnuous or near conƟnuous injecƟon operaƟons with the planned incremental producƟon from the NCU 10 well; however, while Ňow tesƟng the well, excessive water was produced, which was in excess of Amaroq’s daily disposal capacity in the NCU 1B well. As a result of this unanƟcipated produced water producƟon, the NCU 10 well is shut in and the remaining NCU wells only produce water in limited quanƟƟes that do not require conƟnuous or even near conƟnuous injecƟon. Because Amaroq has never established stabilized injecƟon, the follow on work speciĮed in Sundry 320-198 for a stabilized temperature log and witnessed MIT have not yet been performed nor has the accompanying form 10-404 been Įled. Amaroq has encountered an anomalous condiƟon of gas intrusion in the NCU1B well as stated in the annual injecƟon reports for the NCU 1B well (see Surveillance reports for 2021 and 2022 aƩached). The gas intrusion requires well diagnosƟcs to idenƟfy the source of the gas and a remedial program to miƟgate gas intrusion. This work will require mobilizaƟon of a slickline unit to the west side of Cook Inlet for running a temperature survey and possibly other logs. An MIT of the tubing x inner annulus would also be performed at this Ɵme and prior to any addiƟonal injecƟon operaƟons. Docket Number OTH-24-006 March 20, 2024 3 The iniƟal post injecƟon mechanical integrity test as required in Sundry 320-198 and Disposal InjecƟon Order 44 (Rule 4) and clariĮed in Industry Guidance BulleƟn l 0-02B. As discussed in the above paragraphs, since stabilized injecƟon operaƟons have never been established in the NCU 1B well, the post injecƟon MIT has not yet been performed but will be combined with future diagnosƟcs on the well. Subsequent temperature survey l month aŌer commencing injecƟon into NCU 01B. Similarly to the post injecƟon MIT, the temperature survey post stabilized injecƟon has not been performed. This log will follow the well diagnosƟcs and remedial well work, which will enable injecƟon operaƟons to be resumed. Annual reservoir pressure survey of the disposal zone as required in DIO 44, Rule 6.A Reservoir pressures have been esƟmated on an annual basis based on shut in wellhead pressures and accounƟng for a column of produced water in the tubing. These values have been reported on the annual injecƟon reports. Amaroq representaƟves are available next week (March 26 – 28) to meet with appropriate AOGCC personnel to answer any addiƟonal quesƟons you may have in regard to this maƩer. Sincerely, G. Scott Pfoff President Cc: James Robinson, US Environmental Protection Agency, Region 10 Jim Regg Phoebe Brooks Chris Wallace Jesse Mohrbacher From:Wallace, Chris D (CED) To:Jesse Mohrbacher; Schwartz, Guy L (CED) Cc:G Scott Pfoff Subject:RE: Amaroq Resources DIO 044 NCU 1B well Date:Thursday, March 5, 2020 10:15:07 AM Jesse, The Rule 6 requirement of the pre-injection baseline temperature survey and step rate test has been satisfied by the reported/completed sundry #319-346 work. The Rule 6 post injection temperature log should be completed after sufficient continuous disposal operations have been completed that Amaroq believes the well is experiencing stable reproducable long term conditions. Depending on the disposal times and volumes, this could be the one month time as required by rule 6 – but AOGCC would be open to a longer time say 6 months if volumes and injection durations would make this more prudent. Our database is still showing NCU 1B (PTD 2021620) as a 1-GAS producer and so the Sundry to convert the status/class to WDSP2 Class II disposal well has not been recorded. This new sundry should document any proposed wellwork to be completed for the conversion including the Rule 4 stabilized injection MITIA and the Rule 6 stabilized injection temperature profile log. AOGCC doesn’t have any MIT data in our database. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Jesse Mohrbacher <jesse@solstenxp.com> Sent: Tuesday, March 3, 2020 3:04 PM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov>; Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: gspfoff@amaroqresources.com Subject: Amaroq Resources DIO 044 NCU 1B well Gentlemen: I am writing to request clarification on Rule #6 of DIO 044 for the NCU 1B well. Rule 6 requires a baseline temperature log and step rate injection test prior to injection operations commencing. These activities were previously completed under Sundry #319-346 and the results were submitted to the AOGCC under form 10-404 as well as included in the Application for Injection Disposal for the NCU 1B well. Amaroq believes that this work satisfies the requirement for a baseline temperature log and step-rate test prior to initial injection as specified in Rule 6. Rule 6 also requires a temperature log one month after injection commences and Amaroq is planning for this requirement. It appears the document for DIO 044 was created from the Aspen #1 DIO, DIO 032, and the requirement for baseline temperature log and step rate injection test was left in the text for DIO 044. The temperature log and step rate injection test on the Aspen well were conducted nearly 7 months after the approval of DIO 032 to meet the requirements of Rule 6 in DIO 032. Please confirm if the injection test and temperature log already performed by Amaroq on the NCU 1B satisfies this requirement under Rule 6 of DIO 044. Best Regards, Jesse Mohrbacher 907-244-4537 1 Amaroq Resources, LLC Addendum to Nicolai Creek Unit 1B 2021 Annual Injection Report Disposal Injection Order 44 Rule 6 Surveillance Requirements Discussion In May, 2021 Amaroq commenced water injection operations utilizing permanent equipment and continued through October 2021 when injection operations were suspended as a result of operational and weather related issues. A total of 17,994 barrels of produced water were injected in 2021. Surface injection pressures were monitored continuously during the injection timeframe and ranged from 0 to 895 PSIG with an average daily surface injection pressure of 435 PSIG. Inner annulus pressure during the injection period and ranged from 30 psi to 545 PSIG with an average daily pressure of 242 PSIG. Injection rates were constant at 9.8 to 10 gpm throughout the injection period. During the last three months of injection (August – October), injection pressures rose but were never allowed to exceed the maximum allowable injection pressure of 900 PSIG specified in DIO 44. During this period, residual gas was encountered in the well. Amaroq believes that the gas encountered has seeped into the well from the disposal formation during shut in periods and the low injection rates of 10 gpm are insufficient to clear the gas from the tubing and push it back into the formation. The elevated injection pressure may be due to a combination of the gas intrusion and possibly scale and/or suspended solids in the injection stream that are lowering near wellbore permeability. Amaroq plans to recommence injection in 2Q of 2022. During the initial 30-day injection period, Amaroq intends to collect data to develop a remedial program to stabilize continuous injection operations. The data collection will include running a static temperature and pressure log on the well. Based on the temperature and pressure log results, additional diagnostic logs may be run, if warranted. This work will be subject to coordinating and sharing slickline equipment with Hilcorp on the west side of Cook Inlet and is anticipated to occur in latter June or July. Remedial well operations to improve injection performance may include acidizing the perforations to eliminate any scale buildup or reperforating the injection zone. It is possible that the source of gas is from deeper formations and seeping through the tubing plug below the injection zone. If this is confirmed, the tubing plug may need to be reset or sealed by other means. Based on estimates made during the initial NCU 1B Application for Disposal Injection Order, the current radius of influence is estimated to be 23 feet from the wellbore. This minimal calculated zone of influence suggests that sufficient reservoir exists to take the injected fluid but the near wellbore permeability may be compromised. Induced Seismicity Seismic activity in the vicinity of NCU Well 1B were monitored using University of Alaska Fairbanks’ Alaska Earthquake Center (UAF Earthquake Website ). The attached screen shots from the website document the lack of any seismic impact of Amaroq’s injection operations during April, 2021 through March, 2022. The two closest seismic events were approximately one mile away and both were approximately 40 miles deep. The shallowest seismic event was approximately four miles away and recorded at a depth of 4.5 miles. 2 3 4 5 1 Amaroq Resources, LLC Addendum to Nicolai Creek Unit 1B 2022 Annual Injection Report Disposal Injection Order 44 Rule 6 Surveillance Requirements Discussion Amaroq had plans to recommence injection in the 2Q of 2022; however, the excessive amount of water produced from Well NCU #10 in its first 24 hours of production resulted in a decision to shut in the well (NCU #10) and defer water injection until late in the summer. On August 21, 2022 Amaroq commenced water injection operations and continued through August 30, 2022 when injection operations were suspended for the winter. A total of 782 barrels of produced water were injected in 2022. Surface injection pressures were monitored continuously during the injection timeframe and ranged from 0 to 820 PSIG with an average daily surface injection pressure of 726 PSIG. Pressures rose but were never allowed to exceed the maximum allowable injection pressure of 900 PSIG specified in DIO 44. Injection rates were constant at 10 gpm throughout the injection period. Residual gas was encountered in the well. Amaroq believes that the gas encountered has seeped into the well from the disposal formation or from the tubing plug during shut in periods and the low injection rates of 10 gpm are insufficient to clear the gas from the tubing and push it back into the formation. The elevated injection pressure may be due to a combination of the gas intrusion and possibly scale and/or suspended solids in the injection stream that are lowering near wellbore permeability. Amaroq is planning a work program to ascertain the problem(s) and implement corrective measures. Amaroq intends to collect data to develop a remedial program to stabilize continuous injection operations. The data collection will include running a static temperature and pressure log on the well. Based on the temperature and pressure log results, additional diagnostic logs may be run, if warranted. This work will be subject to coordinating and sharing slickline equipment with Hilcorp on the west side of Cook Inlet and is anticipated to occur in latter June or July. A sundry notice will be submitted to the AOGCC once Amaroq’s plans have been finalized. Remedial well operations to improve injection performance may include acidizing the perforations to eliminate any scale buildup or re-perforating the injection zone. It is possible that the source of gas is from deeper formations and seeping through the tubing plug below the injection zone. If this is confirmed, the tubing plug may need to be reset or sealed by other means. Induced Seismicity Seismic activity in the vicinity of NCU Well 1B were monitored using University of Alaska Fairbanks’ Alaska Earthquake Center (UAF Earthquake Website ) and revealed lack of any seismic impact of Amaroq’s injection operations during 2022. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov February 26, 2024 CERTIFIED MAIL – RETURN RECEIPT REQUESTED 7018 0680 0002 2052 9556 G. Scott Pfoff President Amaroq Resources, LLC 4665 Sweetwater Blvd, Suite 103 Sugar Land, Texas 77479 Re: Docket OTH-24-006 Investigation of Late Mechanical Integrity Test (MIT) Nicolai Creek Unit 01B (PTD 2021620) Disposal Injection Order (DIO) 44 Nicolai Creek Unit (NCU), Nicolai Creek Southern Undefined Upper Tyonek Gas Pool Dear Mr. Pfoff: Upon review of the well history and available data, the Alaska Oil and Gas Conservation Commission (AOGCC) has identified potential missing information and testing that was required to be completed and submitted regarding the demonstration of mechanical integrity for disposal injector NCU 01B. Missing information includes the following: - Subsequent Report of Sundry Well Operations (Form 10-404) as required by the Sundry application 320-198. - The initial post injection mechanical integrity test as required in Sundry 320-198 and Disposal Injection Order 44 (Rule 4) and clarified in Industry Guidance Bulletin 10-02B. - Subsequent temperature survey 1 month after commencing injection into NCU 01B. - Annual reservoir pressure survey of the disposal zone as required in DIO 44, Rule 6. The AOGCC is reviewing whether injection operations into NCU 01B comported with the requirements of the approved sundry and disposal injection order. Amaroq is requested to provide the above noted information by March 20, 2024. The AOGCC reserves the right to pursue an enforcement action in this matter according to 20 AAC 25.535. Failure to comply with this request is itself a regulatory violation. Notice of Investigation – Late MIT NCU 01B Docket Number: OTH-24-006 February 26, 2024 Page 2 of 2 Should you have any questions about this investigation notice, please contact Chris Wallace at 907-793-1253 or chris.wallace@alaska.gov. Sincerely, Brett W. Huber, Sr. Chair, Commissioner cc: James Robinson, US Environmental Protection Agency, Region 10 Jim Regg Phoebe Brooks Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.02.26 10:59:16 -09'00' From:Wallace, Chris D (OGC) To:AOGCC Records (CED sponsored) Subject:FW: NCU 1B MIT and Temp Log Date:Monday, July 29, 2024 2:19:09 PM PTD 2021620 From: Jesse Mohrbacher <jesse@solstenxp.com> Sent: Monday, July 29, 2024 1:43 PM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: G Scott Pfoff <gspfoff@amaroqresources.com>; Christian Wood <CWood@solstenxp.com> Subject: RE: NCU 1B MIT and Temp Log Thanks Chris, Last September, over a period of 4 days, Amaroq injected 230 bbls and anticipatesthat no more than 3 or 4 days will be required to inject the available produced waterprior to the temperature log. We’ll plan on conducting the temperature log at theend of the injection operations to provide the best opportunity to obtainrepresentative temperature data for injection on the well. Best Regards, Jesse MohrbacherPresidentSolstenXP Inc.907-244-4537 celljesse@solstenxp.com From: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Sent: Monday, July 29, 2024 12:44 To: Jesse Mohrbacher <jesse@solstenxp.com> Cc: G Scott Pfoff <gspfoff@amaroqresources.com>; Christian Wood <CWood@solstenxp.com> Subject: RE: NCU 1B MIT and Temp Log Jessie, Reviewing the issued NOV and requirements, AOGCC is amenable to witnessing the MIT pre- injection but would prefer to witness the MIT once injection operations have stabilized (which we realize is a problem here). So whichever fits within operational plans and limitations will be OK. For the temperature survey, the NOV requires a temperature survey after 1 month of injection. My thoughts are centered around if two half days injection will be enough time/volume to establish a true injection temperature profile i.e. allowing us to establish that injection is not out of zone? If the well is intending to inject for longer - then I would prefer the temperature survey to be completed later at the end of this injection period if possible. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. You don't often get email from jesse@solstenxp.com. Learn why this is important Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. From: Jesse Mohrbacher <jesse@solstenxp.com> Sent: Monday, July 29, 2024 8:09 AM To: Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Cc: G Scott Pfoff <gspfoff@amaroqresources.com>; Christian Wood <CWood@solstenxp.com> Subject: NCU 1B MIT and Temp Log Hello Chris, Per our earlier correspondence, Amaroq is making preparations for the MIT of theNCU 1B well and a temperature log after injection operations are restarted. I amwriting to get clarification on the plans for both tasks. Please note that Amaroq hasnot injected produced water into the NCU 1B well since September 2023. Will the AOGCC require that the MIT be completed prior to any additional injectionactivity? If so, can the MIT be conducted with the well in static mode versus underinjection? Clarification on these questions would be most appreciated. Subsequent to a successful MIT, Amaroq plans to recommence full injectionoperations. Amaroq injects produced water on a ½ day shift basis, where theinjection operator injects fluid during the day and shuts the well in for the eveningand recommences injection the next day. At the end of the second day of injectionor any subsequent consecutive day of injection, Amaroq intends to run a temperaturelog from surface to 2395’ RKB. The results of this log will then be transmitted to theAOGCC in a 10-404 report. Upon receipt of guidance from the AOGCC on these issues, we’ll plan accordingly andcomplete the required tasks. Best Regards, Jesse MohrbacherPresidentSolstenXP Inc.907-244-4537 celljesse@solstenxp.com Best Regards, Jesse MohrbacherPresidentSolstenXP Inc.907-244-4537 celljesse@solstenxp.com N`Culat' C!�elC (tvltt �� Regg, James B (CED) P1 Z02—/(, ZO From: Brooks, Phoebe L (CED) Sent: Wednesday, July 22, 2020 11:27 AM��j� lIZZ'Z-0? To: Regg, James B (CED) 66 Subject: FW: Amaroq NC1 B --PTD 202-162--Pre-Injection MIT Report 10-426--1 Attachments: MIT NCU 01 B 06-12-20 Revised.xlsx; MIT NCU 01 B 06-13-20 Revised.xlsx Phoebe Brooks Statistical Technician II . Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 CONFIDENTIALITY NOTICE., This e-mail message, including any attachments, contains information from. the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and isfor 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.eov. From: J. Edward Jones <jejones@aurorapower.com> Sent: Friday, lune 26, 2020 6:44 AM To: Brooks, Phoebe L (CED) <phoebe.brooks@alaska.gov> Cc: Regg, James B (CED) <jim.regg@alaska.gov>; G Scott Pfoff <gspfoff@amarogresources.com> Subject: RE: Amaroq NC1B--PTD 202-162--Pre-Injection MIT Report 10-426--1 Phoebe, Here are the corrected reports with decimal numbers and OA values added. Thanks for your help. Regards, Ed From: Brooks, Phoebe L (CED) [mai[to:ahoebe. brooks Palaska.gov] Sent: Thursday, June 25, 2020 6:40 PM To: J. Edward Jones <ieionesCa aurorapower.com> Cc: Regg, James B (CED) <jim_rg,�-1,2alaska.eov> Subject: RE: Amaroq NC1B--PTD 202-162--Pre-Injection MIT Report 10-426--1 Ed, Attached are revised reports for MIT NCU O1B 06-12-20 & 06-13-20 adding the Well Name, correcting the PTD # format (should include a trailing zero and no dash), and including the witness waived verbiage in the remarks. The BBL Pump/Return should be numeric only (the database will not allow <) please advise what the decimal amount should be as well as the Initial and 15 Min. OA values. Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 CONF7DENTIALITYNOTICE: 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: J. Edward Jones <ieiones@aurorapower.com> Sent: Friday, June 19, 2020 12:33 PM To: Regg, James B (CED) <iim.rete@alaska.aov> Cc: G Scott Pfoff <gspfoff@amaroaresources.com>; Lyle Savage <Isavage@amaroaresources.com>; Brooks, Phoebe L (CED) <phoebe.brooks@alaska.eov> Subject: RE: Amaroq NC1B--PTD 202-162--Pre-Injection MIT Report 10-426--1 Jim, As per my previous email, the Form 10-426's have been redone and the form for the IA MIT on 6/13/20 is attached, along with the previously submitted supporting photos of the chart and gauges. Please let me know if you need additional information. Regards, Ed Jones Consultant for Amaroq Resources, LLC From: Regg, James B (CED) [mailto:iim.reae@alaska.gov] Sent: Thursday, June 18, 2020 6:01 PM To: J. Edward Jones <ieiones@aurorapower.com> Cc: G Scott Pfoff <gspfoff@amarogresources.com>; Lyle Savage <Isava¢e@a marogresources. com>; Brooks, Phoebe L (CED)<phoebe.brooks@alaska.eov> Subject: RE: Amaroq NC1B--PTD 202-162--Pre-Injection MIT Report 10-426--1 What you have submitted — one Form 10-426 — shows either a combination MIT (simultaneously applying pressure to Tubing and IA) or shows no tubing integrity. If these are separate tests —tubing on 6/12 and IA on 6/13 —we require a Form 10-426 for each test. Jim Regg Supervisor, Inspections AOGCC 333 W.7h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.eov. From: J. Edward Jones <ieiones@aurorapower.com> Sent: Thursday, June 18, 2020 10:42 AM To: Regg, James B (CED) <]im.retg@alaska.aov> Cc: G Scott Pfoff <gspfoff@amaroaresources.com>; Lyle Savage <Isavaee@amaroaresources.com> Subject: Amaroq NC1B--PTD 202-162--Pre-Injection MIT Report 10-426--1 Jim, Attached is the Form 10-426 for the Nicolai Creek Unit 1B (PTD 202-162) conversion to water disposal pre- injection MIT performed on 6/12/20 (tubing) and 6/13/20 (IA) with the witness waived. Also attached are photos of: 1) the calibrated gauge reading showing initial and final pressures of MIT on tubing and IA (second email); 2) the calibration stamp of that gauge; and 3) photos of the chart for each test (IA in second email). Please note that the charts used are Square Root Charts and that the recorder has a spring range of 0-2000 psi (and 24 hour clock). The readings on both charts are about 8.8, which converted to psi is 1549 psi (8.8 squared=77.44 divided by 100 to get % and multiplied times 2000 to get 1548.8 psi). Please see the second email for IA chart and gauge photos and let me know if you need more information. Regards, Ed Jones Operations Consultant Amaroq Resources, LLC 713-899-8103 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: Lm regpicalaska. aov: AOGCC.Insoector.Malaska oov phoebebrook.Aalaska oov OPERATOR: Amarog Resources, LLC FIELD / UNIT I PAD: Nicolai Creek Unit, Well No. 01B DATE: 06/12/20 OPERATOR REP: AOGCC REP: Chris .wallace0alaska aov Well 01B INTERVAL Codes Pressures: Pretest Initial 15 Min.. 30 Min. 45 Min. 60 Min. 4=Four Year Cycle PTD 2W1620 Type Inj W Tubing 0 1555• 1 1548- 1540• N = No Injeciin, Type Test P Packer ND 2210 BBLPump 0.5 IA 0 0 0 0 Interval Test psi 1500 -BBL Return 0.0 OA 240 - 240 240 240 " Result P Notes: Pre-injection test for conversion to WDSP. Tubing tested on 6/12/20. Witness Waived by Jim Reg, in email of W11/2020 Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPumpl IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Nates: Well Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer NO BBL Pump IA Interval Test psi BBL Return OA Result Notes: WeII Pressures. Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min, PTD Type Int Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type Inj Tubing Type Test Packer TVO BBL PumpIA Interval Test psi BBL Return OA Result Notes: well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Retum OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W=were, P= Pre— Test 1=initial Test P=Pax G=Ges 0= Other (describe In Net.) 4=Four Year Cycle F=Fall S=Slurry V= Recured by Variance 1=Inconclusive I=Ih inel Wssrsvale, 0= Olber(describe in notes) N = No Injeciin, Form 10-426 (Revised 01/2017) WT NCu 01B 061 Revised STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Subra l to: Lm reggltalaska.goe AOGCC Insoectors0alaska aov' ohoebe brooks(e alaslu aov OPERATOR: Amarog Resources LLC FIELD I UNIT I PAD: Model Creek Unit, Well No. 1B DATE: O6Ii3/20 OPERATOR REP: Lyle Savage AOGCC REP: chris.wallacelolalaska goy j T 7/zz l zc,z-c; Well 01B INTERVAL Codes Pressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min, 4=Four Year Cycle PTO 2021620 Typelnj W - Tubing 10 10 10 10 N = Not nienma Type Test P Packer TVD 2210 , BBL Pump 0.1 - IA 0 1546 - 1540- 1535 - Interval Test psi 1500 BBL Realm 0.0 OA 240 240 - 240 _ 240 ' Result P Notes: Pre-injection test for Conversion to WEEP. IA tested on 8113/20. Witness Waived by Jim Regg in email of6111=0 Well Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Tesl Packer TVD BBLPump IA Interval Test psi BBL Retum OA Result Notes: Well Pressures: Pretest Initial 15 Min. 3D Min, 45 Min. 60 Min. PTD Typelnj Tubing Type Test Packer TVO BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTDType Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min. PTO Type IN .Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Typelnj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Nates: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. PTD Type Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Nates: TYPE INJ Codes WPE TEST Codes INTERVAL Codes Result Codes W=Water P=Pressure Test 1=Insist Test P=Paris G=Gas 0= Other describe in Notes) 4=Four Year Cycle F=Fall s=Slurry V= Required by Variants I=Inconclusive = industrial waatexamr 0=aher (describe in notes) N = Not nienma Form 10-426 (Revised 0112017) MIT NCu 018 01 Revised N cis 113 Regg, James B (CED) From: Regg, James B (CED) Sent: Wednesday, June 17, 2020 4:09 PM (a 6h 7' 7 To: G Scott Pfoff Cc: Brooks, Phoebe L (CED) Subject: RE: NCU 1B Prelnjection MIT 06-12-13-2020 10-426 Resubmit. Separate reports are required for the MITT and MITIA — each report must include Tubing, IA and OA pressures observed. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or Iim.regg0alaska.gov. From: G Scott Pfoff <gspfoff@amarogresources.com> Sent: Wednesday, June 17, 202012:21 PM To: Regg, James B (CED) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prud hoe. bay@a laska.gov>; Brooks, Phoebe L (CED) <phoebe.brooks@alaska.gov>; Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Jesse Mohrbacher (jesse@solstenxp.com) <jesse@solstenxp.com> Subject: NCU 16 Prelnjection MIT 06-12-13-2020 10-426 Jim, Please see MIT report attached. Regards, aroq Resources, LLC G. Scott Pfoff, President 4665 Sweetwater Blvd., Suite 103 Sugar Land, Texas 77479 (832) 999-4603 - direct (713) 816-6870 - mobile gspfoff(D)amarogresources. com STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: limmorhatilaska cov. AOGCC.Inspect NhA.laska.gw ohoebe.brooks0alaska.aov OPERATOR: Ami esources, LLC FIELD/UNIT/PAD: Nicola, Creek Unit, Well No. 1B DATE: 6112 8 13/2020 OPERATOR REP: Lyle Savage AOGCC REP: Witness Waived by Jim Regg in email of 5/11/2020 ChriswallaceRDalaska gOv w-71 -Z-'Z�o WeII Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 50 Min. PTD 202-162 Type Inj W Tubing 0 1555 1548 154D Type Test P Packer TVD 2210 BBL Pump <j IA 0 1548 1540 1535 Interval Test psi 1500 BBL Return <1 OA 240 240 Result P Notes: Pre-injection lest for conven,on to WIDER Tubing lasted on 6112120 and IA tested on 6113120. Well Pressures'. Pretest Initial 15 Min, 30 Min. 45 Min. 6D Min. PTD Type Inj TubingType Test Packer TVD BBL Pump IA Inlerval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 50 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL RaWan OA Result Notes: WeII Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Typelnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: WeII Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Remm OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type Inj Tubing Type Tesl Packer TVD 8131 Pump IA Interval Test psi BBL Return OA Result Nates: TYPE INJ Codes W=water G = Gas S=slurry 1= industrial Wastewater N = Not Inlect og TYPE TEST Codes INTERVAL Codes P=Pmssure Test 1=label Test O= Other (describe In Notes) 4=Four Year Cycle V = Retained try Variance O=Other onscrue in retest Form 10425 (Revised 0112017) NCN 113 Prelnjeciion MIT 0612-13202010,126 Result Codes P=east F=Fab I = Immnslueire Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other Convert to WDSP2 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.W ell Name and Number: What Regulation or Conservation Order governs well spacing in this pool?NA Nicolai Creek Unit #1B Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): South Undefined Gas Tyonek & Beluga Gas 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 3672' 3618' 3600' 3546' 280 3500'2769' in tubing Casing Collapse Structural Conductor 520 psi Surface 1130 psi Intermediate 1580 psi Production 3270 psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): No SSSV No SSSV 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15.Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned G.Scott Pfoff Contact Name:Ed Jones President Contact Email:jejones@aurorapower,com Contact Phone: 713-899-8103 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 1-Jun-20 2-7/8 6.5# Halliburton G-77 Hydraulic Packers (3) & VTA 3560' Perforation Depth MD (ft): 2186' 2307-2370' 3650' 3596'7" 23# J-55 20" 94# H40 13-3/8" 54# J55 232' 10-3/4" 40.5# J-552186' 1904' 1530 psi 2730 psi 232' 1904' 232' 1904' J-55 TVD Burst 3396' 4360 psi MD 3150 psi 202-162 4665 Sweetwater Blvd., Ste 103, Sugar Land, TX 77479 50-283-10020-02-00 Amaroq Resources, LLC Length Size G77 @2275', 2438', 2761', VTA @ 3145" MD Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 17585 & 391471 Nicolai Creek COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): 2254-2434' m n P 66 t SPPPPPPPPPPPPPPP222222222222222222 By Samantha Carlisle at 10:52 am, May 11, 2020 320-198 5/8/20 CDW 5/13/2020 gls 5/13/20 + Submit Stabilized Temperature log to AOGCC for review per DIO 44 rule No. 6 + Witnessed MIT-IA required after stabilized injection per rule No. 5. DSR-5/11/2020SFD 5/11/2020 X WDSPL X Convert to WDSSPPPPPPPPPPPPPPPPPPPPPPPPPP222222222222222222222222222222222222222222 + Ongoing disposal injection operations to be in accordance with DIO 44. 10-404 Comm. 5/14/2020 dts 5/13/2020 JLC 5/13/2020 RBDMS HEW 5/15/2020 AMAROQ RESOURCES, LLC NICOLAI CREEK UNIT 1B CONVERT TO PRODUCED WATER DISPOSAL PTD 202-162 May 8, 2020 Version 1.1 STATUS OF WELL: Live well (280 psi SITP), with CASING: 7-inch 23#, K-55 casing set at 3672’ (Capacity= 0.0393 bbl/ft), PERFORATIONS: 23307-2326’, 2350-2370’, 2480-86’, 2604-2622’, 2837- 2842’, 2862-67’, 2913-2918’, 3191-3215’, 3373-3396’, 3557-3580’ MD PACKERS: G-77 at 2275’, G-77 at 2436’, G-77 at 2761’, VTA at 3145’. TUBING: 2-7/8” 6.5# J-55 EUE w/ 3-1/2” WF MonoPore screens at 2839-49’, 2860-70’, & 2909-19’, Locator Seal Assemblies stung into packer at 3145’, and 3-1/2” MonoPore Screens at 3192-3212’ and 3375-95’ with 3-1/2” tubing spacers and Bull Plug at bottom at 3396’. (Tubing Capacity=0.00579 bbl/ft) SLIDING SLEEVES: XD at 2263’, XD at 2365’, and XD at 2749’, all with X- profiles and XN nipple at 3184’. PX PLUG: PX plug without prong stuck in X profile at 2774’. PROCEDURE: 1. Give AOGCC inspector 48-hour notice of MIT in 4) below. 2. RU Pollard slickline unit. Pressure test lubricator with SI well pressure. 3. Make gauge ring run through X profile in sliding sleeve at 2749 to tag PX plug left in well at 2769’. 4. Make a brush run as necessary to clean sliding sleeve and profile at 2749’. Close sleeve. 5.PRE-INJECTION MIT: Run PX plug and set in X profile in sliding sleeve at 2263’. 6. Pressure test tubing above top packer and IA to 1500 psi, on chart for 30 minutes, witnessed by AOGCC inspector. 7. Release pressure on tubing and connect to IA and test casing to 1500 psi on chart for 30 minutes, witnessed by AOGCC inspector. Release pressure. 8. Pull PX plug at 2263’. Release Pollard slickline. 9. Notify AOGCC of intent to start produced water injection in 10 days. 10.After 10 days, commence injection of produced water at 10 gpm (.24 BPM) or less, keeping pressure below 900 psi. 11.POST INJECTION STABILIZED TEMPERATURE SURVEY: 11.1. After 1 month of produced water injection. RU Pollard slickline with temperature-pressure memory tool. 11.2. After at least 12 hours of steady produced water injection and while continuing to inject, run injection background temperature/pressure survey from surface to top of plug set in # 5 above. & witnessed MIT-IA leak path POST INJECTION STABILIZED TEMPERATURE SURVEY: (top of plug at 2598 ft) Notify Inspector 24 hrs prior 4a. Run AD-2 stop and set at 2600ft. Run packoff and top AD-2 stop for tubing plug. pp PX plug without prong stuck in X profile at 2774’ Close SS 2749' Notify Inspector to witness MIT-IA (stabilizied) (above Packer) MIT-T MIT-IA PX @2263' 11.3. Run temp/pressure survey every 15 minutes for the next hour while injection (4 runs), running following temp surveys from top of plug set in #5 above to 1900’ZKLFKLV§400’ above the 10.75” x 7” casing window which is at 2186’-2207’. This will give ±400+’ survey coverage above and below the injection zone, assuming the plug in #5 above is set at 2749’. 11.4. Immediately after last run, SI well recording pressure fall-off until static for 30 minutes, record depth where static bhp taken. 11.5. Make temp/survey run after 15 minutes after shut-in, then 30 minutes later, then an hour later, then every hour until pressure is static or for 3 hours, whichever is greater. 12. Rig down and release Pollard. 13. Analyze data and submit to AOGCC as required for Report of Sundry Well Operations and Disposal Injection Order application. 14. Commence water disposal as needed. Ed Jones (Rev 5/8/20) Amaroq Resources, LLC Nicolai Creek Unit No. 1-B Current Configuration (10/7/2019) 7” 23# J-55 Production 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. 13 3/8" 54# J-55 @ 1904' Cmt'd to surface W/ 1530 Sks 12 1/4" Hole 10 3/4" 40.5# J-55 @ 3817' Cmt'd to surface W/ 900 Sks 20” 94# H-40 Conductor set at 232’, Cmtd to surface w/300 sx ”G”. Drilled 26” Hole Drilled 17 1/2” Hole Whipstock set in 10- 3/4” Casing At 2186’ and old 1-A well sidetracked back to near verticle. Carya 2-3 Perfs: 2,837’ – 2,842’ MD 2,862’ – 2,867’ MD 2,913’ – 2,918’ MD (TVD 2,783’ – 2,864’) Float collar @ 3,604’ MD Float shoe @ 3,648’ MD TD @ 3,672’ MD (3,617’ TVD) VTA Packer @ 3,145’ XN Nipple Carya 2-1.2 Perfs: 2,307’ – 2,326’ MD 2,350’ – 2,370’ MD (TVD 2,254’ – 2,316’) Carya 2-2.1 Perfs: 2,480’ – 2,486’ MD (TVD 2,426’ – 2,434’) Carya 2-2.2 Perfs: 2,604’ – 2,622’ MD (TVD 2,550’ – 2,568’) Well completed with sand exclusion screens across the indicated perforations, bottom at 3396’. Tagged fill at 3200’ in 2/28/2019. 2-7/8” 6.5 # J-55 tbg to surface Carya 2-4.2 Perfs: 3,191’ – 3,211’ MD (TVD 3,137’ – 3,157’) Carya 2-5.1 Perfs: 3,371’ – 3,401’ MD (TVD 3,307’ – 3,348’) Carya 2-6.1 Perfs: 3,560’ – 3,575’ MD (TVD 3,506’ – 3,521’) Sliding Sleeve w/ X-profile @ 2,749’ (OPEN?) G-77 Packer @ 2,761’ X-nipple @ 2,774’ (PX plug without prong left in place on 9/9/19) Annulus Sliding Sleeve w/ X-profile @ 2,263’ (Closed) G-77 Packer @ 2,275’ Cement Retainer @ 3,500’ Lower 3 completions treated w/ Weatherford Sand Aid 2010-11 Sliding Sleeve w/ X-profile @ 2,359’ G-77 Packer @ 2,436’ (Open) XN SS Carya 2-1.2 Perfs:y 2,307’ – 2,326’ MD,, 2,350’ – 2,370’ MD,, (TVD 2,254’ – 2,316’) SS Current Configuration (10/7/2019) X Injection zone Carya 2-1.2 Prong missing... leak path . gls SS CURRENT NOTE: hole in tubing at 2278 ft. Amaroq Resources, LLC Nicolai Creek Unit No. 1-B Proposed Configuration 7” 23# J-55 Production 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. 13 3/8" 54# J-55 @ 1904' Cmt'd to surface W/ 1530 Sks 12 1/4" Hole 10 3/4" 40.5# J-55 @ 3817' Cmt'd to surface W/ 900 Sks 20” 94# H-40 Conductor set at 232’, Cmtd to surface w/300 sx ”G”. Drilled 26” Hole Drilled 17 1/2” Hole Whipstock set in 10- 3/4” Casing At 2186’ and old 1-A well sidetracked back to near verticle. Carya 2-3 Perfs: 2,837’ – 2,842’ MD 2,862’ – 2,867’ MD 2,913’ – 2,918’ MD (TVD 2,783’ – 2,864’) Float collar @ 3,604’ MD Float shoe @ 3,648’ MD TD @ 3,672’ MD (3,617’ TVD) VTA Packer @ 3,145’ XN Nipple Carya 2-1.2 Perfs: 2,307’ – 2,326’ MD 2,350’ – 2,370’ MD (TVD 2,254’ – 2,316’) Carya 2-2.1 Perfs: 2,480’ – 2,486’ MD (TVD 2,426’ – 2,434’) Carya 2-2.2 Perfs: 2,604’ – 2,622’ MD (TVD 2,550’ – 2,568’) Well completed with sand exclusion screens across the indicated perforations, bottom at 3396’. Tagged fill at 3200’ in 2/28/2019. 2-7/8” 6.5 # J-55 tbg to surface Carya 2-4.2 Perfs: 3,191’ – 3,211’ MD (TVD 3,137’ – 3,157’) Carya 2-5.1 Perfs: 3,371’ – 3,401’ MD (TVD 3,307’ – 3,348’) Carya 2-6.1 Perfs: 3,560’ – 3,575’ MD (TVD 3,506’ – 3,521’) Sliding Sleeve w/ X-profile @ 2,749’ (CLOSED) with PX plug set in profile above sleeve. G-77 Packer @ 2,761’ X-nipple @ 2,774’ (PX plug without prong left in place on 9/9/19) Annulus Sliding Sleeve w/ X-profile @ 2,263’ (Closed) G-77 Packer @ 2,275’ Cement Retainer @ 3,500’ Lower 3 completions treated w/ Weatherford Sand Aid 2010-11 Sliding Sleeve w/ X-profile @ 2,359’ G-77 Packer @ 2,436’ (Open) IA Carya 2-1.2 Perfs:y 2,307’ – 2,326’ MD,, 2,350’ – 2,370’ MD,, (TVD 2,254’ – 2,316’) SS Isolated injection zone SS SS Proposed Configuration ------------------------------------------------------------------- XN Set AD-2 stop and packoff-plug at 2600 ft. verify sliding sleeve at 2749 'closed X PROPOSED 1 Carlisle, Samantha J (CED) From:J. Edward Jones <jejones@aurorapower.com> Sent:Tuesday, May 12, 2020 2:45 PM To:Schwartz, Guy L (CED) Cc:Wallace, Chris D (CED); Roby, David S (CED); Rixse, Melvin G (CED); G Scott Pfoff; Lyle Savage Subject:RE: NCU 1B conversion to disposal well. PTD 202-162 Attachments:NC 1B Current WBD 100719.doc; NCU 1B Procedure to Convert to SWD 051220.doc; NC 1B Proposed WBD 051220 V1.2.doc Guy, Aswediscussedinourbriefphoneconversationearliertoday,Ihaveconfirmed/updatedtheinfoonthe CurrentwellͲboreschematicanditisattached.Toansweryourquestions: 1)AsImentionedinourconversation,thepackͲoffplugandstopsat2400Ͳ2397’werepulledafterthetestinOctober 2019. 2)AsIreviewedtheProcedure,however,IsawthatIhadskippedthesettingoftheplugbelowtheinjectionperfs,soI haveaddedthattotheProcedure,Step5:settingapackͲoffplugwithstops,aswasrunintheinjectiontestbutsetita bitdeeper,at2468’,toallowforsomesolidsbuildupinthetubingbelowtheslidingsleeve(ontheearlierProposed WellͲboreDiagram,Ihadindicatedthatwe’dsetanotherPXplugintheprofileabovethesleeveat2749’,buttheprofile couldnotbelocatedwhenthePXplugwassetbelow,at2774’inSeptember). 3)Thereissomequestionaboutthestatusofthesleeveat2749’ontheCurrentWellBoreDiagram,buttheAmaroq fieldsupervisorbelievesittobeclosed,asmultiplepassedweremadethruitinSeptember2019.Nonetheless,the ProcedurecallsforthatsleevetobeconfirmedclosedinStep4. Iapologizefortheconfusionandhopethattheserevisionsclarifytheproposal.Pleaseletmeknowifyouhave anyquestions. Thanks,Ed From:Schwartz,GuyL(CED)[mailto:guy.schwartz@alaska.gov] Sent:Monday,May11,20206:07PM To:J.EdwardJones<jejones@aurorapower.com> Cc:Wallace,ChrisD(CED)<chris.wallace@alaska.gov>;Roby,DavidS(CED)<dave.roby@alaska.gov>;Rixse,MelvinG (CED)<melvin.rixse@alaska.gov> Subject:NCU1Bconversiontodisposalwell.PTD202Ͳ162 Ed, Waslookingatthesundrytoconverttodisposal.Thecurrentschematicdoesnotshowaviabletubingplug(thestuck PXplugbodyat2774’hasprongremoved).AtonepointaslicklinesetAͲstopwassetat2400ft.Isthisstill there?Ultimatelywhatisthebottomtubingplugusedtoconfinetheinjectiontotheupperzone?Irealizethe injectiontestsandtemperaturelogindicatedtheinjectionwasgoingintotherightzone.Also,TheD&Dholefinder teston10Ͳ5Ͳ19establishedthatthetubing(MITͲT)wasgoodabovetheholeat2278ft. Doesschematicneedupdating?AlsotheproposedschematichassomewritingmissingregardingtheSSstatusat2749 ft GuySchwartz Sr.PetroleumEngineer AOGCC 2 907Ͳ301Ͳ4533cell 907Ͳ793Ͳ1226office 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 Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). Wallace, Chris D (CED) From: Wallace, Chris D (CED) Sent: Thursday, March 5, 2020 10:15 AM To: Jesse Mohrbacher; Schwartz, Guy L (CED) Cc: gspfoff@amarogresources.com Subject: RE: Amaroq Resources DIO 044 NCU 1 B well Jesse, The Rule 6 requirement of the pre-injection baseline temperature survey and step rate test has been satisfied by the reported/completed sundry #319-346 work. The Rule 6 post injection temperature log should be completed after sufficient continuous disposal operations have been completed that Amaroq believes the well is experiencing stable reproducable long term conditions. Depending on the disposal times and volumes, this could be the one month time as required by rule 6— but AOGCC would be open to a longer time say 6 months if volumes and injection durations would make this more prudent. Our database is still showing NCU 1B (PTD 2021620) as a 1 -GAS producer and so the Sundry to convert the status/class to WDSP2 Class II disposal well has not been recorded. This new sundry should document any proposed wellwork to be completed for the conversion including the Rule 4 stabilized injection MITIA and the Rule 6 stabilized injection temperature profile log. AOGCC doesn't have any MIT data in our database. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7`^ Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallacec@alaska.eov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.aov. From: Jesse Mohrbacher <jesse@solstenxp.com> Sent: Tuesday, March 3, 2020 3:04 PM To: Wallace, Chris D (CED) <chris.wallace@alaska.gov>; Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: gspfoff@amaroqresources.com Subject: Amaroq Resources DIO 044 NCU 16 well Gentlemen: I am writing to request clarification on Rule #6 of DID 044 for the NCU 1B well. Rule 6 requires a baseline temperature log and step rate injection test prior to injection operations commencing. These activities were previously completed under Sundry #319-346 and the results were submitted to the AOGCC under form 10-404 as well as included in the Application for Injection Disposal for the NCU 1B well. Amaroq believes that this work satisfies the requirement for a baseline temperature log and step -rate test prior to initial injection as specified in Rule 6. Rule 6 also requires a temperature log one month after injection commences and Amaroq is planning for this requirement. It appears the document for DIO 044 was created from the Aspen #1 DIO, DIO 032, and the requirement for baseline temperature log and step rate injection test was left in the text for DIO 044. The temperature log and step rate injection test on the Aspen well were conducted nearly 7 months after the approval of DIO 032 to meet the requirements of Rule 6 in DIO 032. Please confirm if the injection test and temperature log already performed by Amaroq on the NCU 1B satisfies this requirement under Rule 6 of DIO 044. Best Regards, Jesse Mohrbacher 907-244-4537 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS RECEIVED OCT 2 3 2019 1. Operations Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing ❑�))� 11Performed: Suspend El Perforate Chan ❑ Other Stimulate ❑ Alter Casing ❑ e _ved g approrog m ❑ Plug for Rednll ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ MIT, injection test '❑ 2. Operator Amaroq Resources, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑+ Exploratory ❑ Stratigraphic ❑ Service ❑ 202.162 3. Address: 4665 Sweetwater Blvd., Suite 103, Sugar Land, TX 6. API Number: 77479 50-283-10020-02-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL 17585 & 391471 Nicolai Creek Unit #1B 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): No logs, injection test, pressure and temp survey data Nicola! Creek South Undefined Upper Tyonek & Beluga Undefined Gas 11. Present Well Condition Summary: Total Depth measured 3672 feet Plugs measured PX @ 2678 feet true vertical 3618 feet Junk measured feet Effective Depth measured 3560 feet Packer measured 2275, 2436, 2671, 3145 feet true vertical 3546 feet true vertical 2223, 2382, 2617, 3091 feet Casing Length Size. MD TVD Burst Collapse Structural Conductor 232' 20" 232' 232' 1530 psi 520 psi Surface 1904' 13.375" 1904' 1904' 2730 psi 1130 psi Intermediate 2186' 10.75" 2186' 2137' 3580 psi 1580 psi Production 3648' 7" 3648' 3594' 4360 psi 3270 psi Liner Perforation depth Measured depth 2307-3575 feet True Vertical depth 2254-3521 feet Tubing (size, grade, measured and true vertical depth) 2-7/8" J-55 3396' MD 3342' TVD Packers and SSSV (type, measured and true vertical depth) G-77@ 2275', 2436', 2671', VTA @ 3145' MD G-77 @ 2223', 2382', 2617', V-A @ 3091' TVD No SSSV 12. Stimulation or cement squeeze summary: Intervals treated (measured): NA Treatment descriptions including volumes used and final pressure: Injection test, 110 bbl, 160 OF, produced water injected at 1 bpm into perfs at 2307'-2370' MD. Max surface injection pressure of 745 psi at 1 bpm, well on vacuum at end of injection test. 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 13 0.13 200 60 PSI Subsequent to operation:[0 0 0 280 PSI shut in 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations ❑' Exploratory ❑ Develo ment p ❑ Service [I Siratigraphic ❑ Copies of Logs and Surveys Run 16. Well Status after work: O!I ❑ Gas E] W DSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ 6USP ❑ SPLUG❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-346 Authorized Name: G. Scott Pfoff Contact Name: Jesse Mohrbacher Authorized Title: President Contact Email: jeSSe(G�SOISteflXp.COrn L- Authorized Si nature: 17 Date: LO 2-t Contact Phone: 907-244-4537 1_a Form 10-404 Revised d 4/2017 �� G �� RBDMS�OCT 2 5 2019 Submit Original Only �7 aroq Resources, LLC 466 S,reutwaLer Ei:vd„ SLXL _�"3 Swgar,and.TX 77479 October 21, 2019 Guy Schwartz Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, AK 99501-3572 RE: Report of Sundry Well Operations, Sundry # 319-346, Nicolai Creek Unit 16 well, PTD# 202-162 Dear Mr. Schwartz: Please find the enclosed Report of Sundry Well Operations for the Nicolai Creek Unit (NCU) 16 well. Amaroq Resources, LLC performed the MIT and injection test work under Sundry 319-346 in support of a pending Application for Disposal Injection Order for the NCU 113 well. The following information documents the work performed: • AOGCC form 10-404, Report of Sundry Well Operations; • NCU 113 well schematic, • Daily operations reports for the slickline and hot oil unit; • AOGCC form 10-426, Mechanical Integrity Test and associated pressure test charts; • Temperature and pressure survey data for baseline, 1 hour, 2 hour and 3 hour warmback surveys (conducted on slickline); and • Injection pressure data including pressure and temperature gradients, and pressure and temperature versus time plots. If you have any questions or require additional information, please contact me at your earliest convenience at 832-999-4603 or Jesse Mohrbacher at 907-244-4537. Sincerely, 4, Scott Pfoff President Amaroq Resources, LLC 4665 Sweetwater Blvd., Suite 103 0 Sugar Land, Texas 77479 • (832) 999-4603 0 (832) 999-4382 2-7/8" 6.5 4J-55 tbg to surfs" A3naroq Resources, LLC Nicolai Creek Unit # 1-B Current Configuration (October 2019) 13-318"54#J-55 Surface Csg F at 1904'. Cmtd to surface w/ k/ 1530 sx 'G". Carya 2-1.2 Perfs - 7 2,307'-2326' MD 2.350'-2370'MD (TVD 2254'-2316) Carya 2-2.iPerfs: - 2480' -2486'MD (TVD 2426' -2.434') Carva 2-2.2 Parts: _ 2604 -2622' MD (TVD 2550'-2568') Carva 2-3 Parts: MT -2841 MD 2862'-2867' MD 2913' -2918' MD (TVD 2.783' -2-8,64') Carya 2-4.2 Perfs: 3191'-3211' MD (TVD 3137'-3157') Cana 2-5.1Perfs: 3371'-3401' MD (TVD 3307'-3348') Carve 2-6.1 Perfs: 3560' -3575' MD (TVD 3506'-3521') Float collar !a. 3604P MD Float shoe�a 3648' MD TD Iii' 367Z Di (3617 TVD) v Drilled 26"Hole ' 20"94#H-40 Conductor set at 232'_ Cmtd to sudface iv/300 sx "0". r, Drilled 17-1/2"Hole 10-3?4" casing (not shown) sidetracked with 8-1/2" window from 2186' to 2207' Sliding Sleeve w/X-profile'4 2263' (dosed) G-77 Packer a 2275' Hole in tubing ea � 2294' Sliding Sleecerd X-protile :a 2359' (Open) G-77 Packer ti 2436' TSliding Sleeve w/X-profile?a 2749' (open -1/13) G-77 Packer ti2761' X -nipple is 2774' (PX plug in X -nipple VTA Packer la 3.145' XN Nipple (,e3.184' Well completed with sand exclusion screens across the indicated perforations bottom at 3396'. Jan 2013 - tag at 3255' Cement Retainer Iii 3500' Lower 3 completions treated w' Weatlierford Said Aid 2010-11 7" 2M' J-55 Production Csg 3650'MD (3595' TVD). Cmtd to surfacew/ 82 bbls "Ci" lead at 12.5 ppg and 67 bbls "G" tail at15.8 ppg. AMAROQ WELL SERVICE REPORT Date: Work being done: Wireline Company: Wireline Unit Number: Tree Connection FLUID LEVEL: Supervisor: Zero Wireline at: Minimum Tubing ID: Start Tbg. & Csg. PSI 9/7/2019 Well Number: Location: AFE# / Charge Code: Pollard Wireline Crew: Total Wireline Miles: Swab Turn Count Max Depth (KB): Well KB: Max Tool OD: Ending Tbg & Csg PSI NCU 1-B M.I.T. SHIRLEYVILLE Pollard Wireline Inc. LOE WSE NC 1B Pollard RED RACER HENTHORNE, JON R, STEVE M. 2 7/8 8rd 10 N/A 15 LYLE 2800' Tubing Hanger 11.5' 2.205" 2.3" 80/220 0/0 Time Operation Details W/L valve 6:00 SAFETY MEETING, JOB SCOPE 6:40 STAND UP LUBRICATOR, PRESSURE TEST. 7:10 RIH W/ 2.29" LIB SIT DOWN 2292'KB WT - FALL THROUGH - DRIFT TO 2800'KB - POOH 7:55 RIH W/ 2 7/8" PX PLUG TO 2760'KB WT - CAN NOT LOCATE PROFILE @ 2749**. RIH TO 2780'KB WT - SEE OVERPULL AT 2770'KB - WT- SIT DOWN @ 2768'KB - DISCUSS WITH LYLE. PULL UP TO PROFILE AT 2359** - TAG PROFILE 2374'KB - POOH 10.00 RIH W/ 2 7/8" X -LINE W/ 2 7/8" PX PLUG TO 2800'KB - PULL UP TO LOCATE PROFILE 2793'KB - PULL UP TO 2768'KB WT - POOH - PLUG SET 10:45 RIH W/ 2" SB W/ PRONG(1.375 l TO 2767'KB WT - POOH - PRONG SET 12:15 RIH W/ 2 7/8" BO SHIFTING TOOL(CLOSE UP) TO 2378'KB WT - POOH - PIN SHEARED 13:30 RIH W/ 2 7/8" J -LATCH (CLOSE UP) TO 2378'KB WT - ENGAGES PROFILE SEVERAL TIMES. BEGINS TO SLIP OFF EACH PASS -APPEARS TO BE SHIFTED - POOH -ATTEMPT NEGATIVE TEST. FAIL. 14:40 RIH W/2 7/8" BO (CLOSE UP) TO 2378'KB WT - FRICTION BITE ONLY - POOH - PIN NOT SHEARED 15:45 RIH W/ SAME TO 2378'KB WT, CAN NOT LOCATE - POOH - DISCUSS WITH LYLE. WELL ON VAC. 17:30 RIH W/ 2 718" BO 142 (TO OPEN) TO 2380'KB WT - SHIFT OPEN AND PRESSURE INCREASED 18:20 RIH W/ 2 7/8" BO (TO CLOSE) TO 2378'KB WT - WELL GOES BACK ON VAC - POOH 19:00 LAY DOWN LUBRICATOR - SECURE WELL - HEAD TO CAMP. HOUR COST: 3 MAN CREW 1 ADD HOUR TOOL COST: 2.29" LIB $94, PX PLUG $187, X -LINE $187,2" SB $128, BO $128, BO -142 $155, J -LATCH $155. otal Hours Worked 1 13 1 Total Tool Cost Total Hour Cost Daily Cost: I Cumulative Cost: Well Downtime Hr. Shut in H2S PPM Approved by: Lyle Savage Code: AMAROQ HOT OIL SERVICE REPORT Date: Work being done: Supervisor H.O. Unit #: 9/7/2019 Well Number: Location: AFE# / Charge Code: Pollard Wireline Crew: NCU 1-a M.I.T. SHIRLEYVILLE LYLE KENWORTH. _ HENTHORNE, STEVE M, JON R TO FROM otal Hours Worked 1 12 1 Total Tool Costj I Total Hour Costj $ 2,85-0-051 Daily Cost:1 $ 2,800.00 ( Cumulative Cost: Approved by: Lyle Savage Code: AMAROQ WELL SERVICE REPORT Date: Work being done: Wireline Company: Wireline Unit Number: Tree Connection FLUID LEVEL: Supervisor: Zero Wireline at: Minimum Tubing ID: Start Tbg. & Csg. PSI 9/8/2019 Well Number: Location: AFE# I Charge Code: Pollard Wireline Crew: Total Wireline Miles: Swab Turn Count Max Depth (KB): Well KB: Max Tool OD: Ending Tbg & Csg PSI NCU 1-B M.I.T. SHIRLEYVILLE Pollard Wireline Inc. RIH W/ 2 7/8" GS W/ PACKOFF TO 2766'KB-WT- PACKOFF SET. FAIL TEST - PULL PACKOFF RED RACER HENTHORNE, JON R, STEVE M. 2 7/8 8rd RIH W/ 2 7/8" GS W/ 2 7/8" AD2 STOP TO 2461 WLM* (*CORRELATED DEPTH 2455'KB) - WT - POOH 2370 15 LYLE 2768' Tubing Hanger 11.5' 2.205" 2.29 0/0 0/0 Time Operation Details W/L valve 6'00 SAFETY MEETING, JOB SCOPE 6:40 STAND UP LUBRICATOR, PRESSURE TEST. 7:10 RIH W/ 2 7/8" GS W/ PACKOFF TO 2766'KB-WT- PACKOFF SET. FAIL TEST - PULL PACKOFF 9:15 RIH W/ 2 7/8" GS W/ 2 7/8" AD2 STOP TO 2280'KB SHEAR AD2 - POOH - REPIN AD2 STOP 10:15 RIH W/ 2 7/8" GS W/ 2 7/8" AD2 STOP TO 2461 WLM* (*CORRELATED DEPTH 2455'KB) - WT - POOH 11:15 RIH W/ 2 7/8" GS W/ 2 7/8" PACKOFF TO 2461 WLM* - WT - POOH - PACKOFF SET STANDBY FOR HOT OIL/TEST FAIL, 12:25 RIH WI 2 7/8" GS TO 2461' WLM* - WT - POOH - PULL PACKOFF 13:15 RIH W/ 2 7/8" GS W/ 2 7/8" PACK OFF TO 2461' WLM -WT - PACKOFF SET. HOT OIL TEST FAILS. 14:45 RIH W/ 2 7/8" GS TO 2461' WLM* - WT - POOH - PULL PACKOFF 15:35 RIH W/ 2 7/8" GS TO 2461' WLM* LATCH AD2 STOP - WT - POOH - PULL AD2 STOP. 16:30 RIH W/ 2" SB TO 2767'KB - WT - POOH -PRONG PULLED. 17:00 RIH W/ 2 7/8" GS TO 2768'KB - WT - 6 JAR LICKS @ 550# & 15 @ 1500# - SHEER OFF - POOH. 18:30 RIH W/ J-LATCH(OPEN DOWN) TO SLEEVE AT 2374'KB - WT - APPEARS TO BE SHIFTED AFTER SEVERAL PASSES, 20:00 RIH W/ 3/4" DD BAILER TO 2768'KB - WT - POOH BAILER EMPTY. 20:40 RIH W/ 2 7/8" GS TO 2768'KB - WT - 10 JAR LICKS @ 1800# - SHEER OFF POOH, LAYDOWN LUB. 21:30 ARRIVE BACK AT CAMP. HOUR COST: 3 MAN CREW 4 ADD HOUR TOOL COST: PX PLUG $187, X -LINE $187,2" SB $128,2 7/8" GS $187,2 7/8" PACKOFF $374, 2 7/8" AD 2 STOP $187. 2 7/8 J -LATCH $255. 3/4" DD BAILER $187. Stem - K.J. - O.J. and otal Hours Worked 1 16 1 Total Tool Costj I Total Hour Cost Daily Cost: Well Downtime Hr. Shut in Approved by: H2S PPM Cost: Code: AMAROQ HOT OIL SERVICE REPORT Date: Work being done: Supervisor H.O. Unit #: 9/8/2019 Well Number: Location: AFE# / Charge Code: Pollard Wireline Crew: NCU 1-a M.I.T. _ S_H_IR_L_E_YVILLE LYLE KENWORTH. _ HENTHORNE, STEVE M, JON R otal Hours Workedl 12 1 Total Tool Costj I Total Hour Cost Costal I Cumulative Cost: AMAROQ WELL SERVICE REPORT Date: Work being done: Wireline Company: 1 Vumber: Tree Connection FLUID LEVEL: Supervisor: Zero Wireline at: Minimum Tubing ID: Start Tbg. & Csg. PSI 9/9/2019 Well Number: Location: AFE# / Charge Code: Pollard Wireline Crew: Total Wireline Miles: Swab Turn Count Max Depth (KB): Well KB: Max Tool OD: Ending Tbg & Csg PSI NCU 1-B _ SLEEVE SHIRLEYVILLE Pollard Wireline Inc. RIH W/ 2 7/8" BO SHIFT TOOL TO 2374'KB -WT- POOH -APPEAR TO BE CLOSED PIN NOT SHEERED RED RACER _ HENTHORNE, JON R, STEVE M. 2 7/8 8rd LAY DOWN TOOL STRING, CHANGE TO 1.75 TOOL STRING. 2370 15 LYLE 2,768 Tubing Hanger 11.5' 2.205" 2.29 55 RIH W/ 2 7/8" BO 142 TO 2347'KB - WT - LOCATE - SPANG DOWN TO OPEN SLEEVE. Time Operation Details W/L valve 6:00 SAFETY MEETING, JOB SCOPE 6:40 STAND UP LUBRICATOR, PRESSURE TEST. 7-00 RIH W/ 2 7/8" BO SHIFT TOOL TO 2374'KB -WT- POOH -APPEAR TO BE CLOSED PIN NOT SHEERED 8:30 RIH W/ 2 7/8" GS TO 2756'KB - WT - LATCH PX PLUG - 15 JAR LICKS @ 1800 # - SHEAR OFF - POOH LAY DOWN TOOL STRING, CHANGE TO 1.75 TOOL STRING. 10:15 RIH W/ 2 7/8" GS TO 2756'KB - WT - 50 JARLICKS SHEAR OFF - POOH - SLIP CUT 20' WIRE 14:45 RIH W/ 2 7/8" BO 142 SHIFTING TOOL TO 2347' KB- WT - LOCATE - COUPLE SPANG LICKS FALLS THROUGH- POOH - 16:00 RIH W/ 2 7/8" BRAIDED LINE BRUSH - WT - POOH. 17:00 RIH W/ 2 7/8" BO 142 TO 2347'KB - WT - LOCATE - SPANG DOWN TO OPEN SLEEVE. 18:15 LAY DOWN LUBRICATOR SECURE WELL FOR NIGHT. 18:45 ARRIVE AT CAMP HOUR COST: 3 MAN CREW 1 ADD HOUR TOOL COST: PX PLUG $187,2 7/8" GS $187, BO SHIFTING TOOL $128, BO 142 $155: 2 7/8 J -LATCH $255, BRAIDED LINE BRUSH $68 Work String Detail: Size and Lenath otal Hours Worked 1 13 1 Total Tool Cost Total Hour Cost Well Downtime Hr. Shut in H2S PPM Approved by: Code: AMAROQ WELL SERVICE REPORT Date: Work being done: Wireline Company Wireline Unit Number: ee Connection Size/Type Present Operations Supervisor Zero Wireline at: Minimum Tubing ID: Start Tbg. & Csg. PSI 10/412019_ Well Number: Location: AFE# / Charge Code: Pollard Wireline Crew: Total Wireline Miles: Swab Turn Count Max Depth (KB): Well KB: Max Tool OD: Ending Tbg & Csg PSI NCU-18 SET PLUG, SHIFT SLEEVE AMAROO Pollard wireline Inc. ARRIVE IN SHIRLEYVILLE, LUNCH, GO OVER JOB RED RACER CODY B., MIKE H., DAWSON B. 2 718 8RD RIH W12,25" GRING TO 2768'KB POOH ON GOING 16 LYLE SAVAGE 2768' Tubing Hanger 11.5' 2.31 2.27^ 220-40 220-40 Time Operation Details W/L valve GOOD 9:00 ARRIVE AT SHOP GATHER TOOLS & CREW 9:45 ARRIVE AT AIRPORT FLY TO WEST SIDE, CHECK EQUIPMENT 12:30 ARRIVE IN SHIRLEYVILLE, LUNCH, GO OVER JOB 13:30 RIG UP .125 SIL 15:10 RIH W12,25" GRING TO 2768'KB POOH 15:40 RIH W/ 2 7/8 BO 42 W/ SELF RELEASING KEYS IN UPWARD POS. TO 2376'KB WIT PASS THROUGH MULTIBLE TIMES POOH 16:50 RIH W/ 2 7/8 GS W/ 2 718 AD -2 STOP TO 2410'KB WIT SET AD -2 STOP AT 24001KB POOH 17:20 RIH W/ 2 7/8 GS W12 718 W EATHERFORD PACK OFF PLUG TO 2396'KB W/T POOH 17:45 RIH W/ 2 7/8 A -STOP TO 2397'KB W/T POOH 18:00 LAY DOWN LUB, SECURE WELL 3 MAN CREW toots or debris otal Hours Worked I Total Tool Cost Total Hour Cost $ Well Downtime Hr. Shut In H2S PPM Approved by: .Grgrle S"zge Code: LOE WSE NC -1B Pollard Amaroq - ALASKA WELL SERVICE REPORT Date: Work being done: Wireline Company Wireline Unit Number: ee Connection SizelType Present Operations Supervisor Zero Wireline at: Minimum Tubing ID: Start Tbg. & Csg. PSI 10/5/2019 Well Number: Location: AFE# l Charge Code: Pollard Wireline Crew: Total Wireline Miles: Swab Turn Count Max Depth (KB): Well KB: Max Tool OD: Ending Tbg & Csg PSI NCUAB PULL PLUG WEST SIDE Pollard Wireline Inc. RED RACER CODY B., MIKE H., DAWSON B. 2 7/8 8RD ON GOING 15 LYLE S. 2365' Tubing Hanger 11,5' 2.205 2.31" 200-40 200-40 Time Operation Details w/L valve I uvuu 6:00 MORNING MEETING 6:30 START UP EQUIPMENT. RIG UP HOT OIL TRUCK 7:25 PUMP DOWN TUBING WELL GOS ON VACUME 8:00 PN LUB 8.45 RIH W/ PRONG DISCUS OTHER OPTIONS POOH 9:00 RIH W/ 2 7/8 BO 42 TO 2375'KB PASS THROUGH SEVERAL TIMES POOH - STAND BY FOR FLIGHT W/ TOOLS - FLUID LEVEL AT 2080' 10:45 RIH W/ 2 7/8 XLINE R.T. W/ 2 7/8 XLOCK W/ ISO, SLEEVE TO 2376'KB WIT PLUG SET POOH - FLUID LEVEL AT 2125' 11:30 PUMP DOWN WELL TO TRY AND PRESSURE UP TUBING, WELL GO'S ON VACUME 12:00 RIH W/ 2 7/8 GS TO 2376KB WIT COMES FREE POOH - W/ LOCK W/ ISO. SLEEVE 12:50 RIH W/ 2" JD W/ 2 7/8 D&D HOLEFINDER TO 2390 WIT SET AT 2388'KS, PUMP DOWN WELL DOES NOT PRESSURE UP, PULL UP TO 2379'KB, PUMP DOES NOT PRESSURE UP, PULL UP TO 2368'KB PUMP DOES NOT PRESSURE UP. PULL UP TO 2351'KB PUMP DOES NOT PRESSURE UP, PULL UP TO 2295'WLM PUMP DOES NOT PRESSURE UP, PULL UP TO 2288'WLM PUMP DOES NOT PRESSURE UP, PULL UP TO 2278'WLM WELL PRESSURES UP HOLD FOR 30 MINS POOH 1645 RIH W/ 2 7/8 JLATCH DOWN POS, TO SHIFT XD SLEEVE OPEN AT 2365'WLM WIr PASS THROUGH SEVERAL TIMES POOH 1740 LAY DOWN LUB, SECURE WELL 3 -MAN CREW/12 HRS Work String Detail: 1.5 RS STEM KJ OJ LSSJ Size and Len th Description o any NONE tools or debris left in the hole: Brief Summary of ISHIFT SLEEVE, SET ISO. SLEEVE, RUN HOLEFINDR TUBING PRESSUES UP WHEN SET AT 2278'WLM' Total Work OPEN SLEEVE Completed[- otal Hours Wo edl 12 1 Total 7001 Gost Total Hour Cost $ Ic ata y Daily Cost: ' Cumulative Coat: Well Downtime Hr. Shut In H2S PPM Approved by: Zq& 5"ayc Code: LOE WSE NC -1B Pollard AMAROQ - ALASKA HOT OIL SERVICE REPORT Date: Work being done, Supervisor H.O. Unit #: 101512019 Well Number: 1. _0 AFE# 1 Charge Code: Pollard Wireline Crew: NCU-16 AMAROQ L. SAVAGE KENWORTH HENTHORrdE, BROWN, BAKER 19 otal Hours Worked 12 Total Tool Costj I Total Hour Cost F- Daily Cost: Approved by: .Go S"49e Code: LOE WSE NC -1B Pollard Amroi -ALASKA WELL SERVICE REPORT Date: Work being done: Wireline Company Wireline Unit Number: ee Connection Size/Type Present Operations Supervisor Zero Wireline at: Minimum Tubing ID: Start Tbg. & Csg. PSI 1016/2019 Well Number: Location: AFE# I Charge Code: Pollard Wirellne Crew: Total Wireline Miles: Swab Turn Count Max Depth (KB): Well KB: Max Tool OD: Ending Tbg & Csg PSI NCu-1B SURVEY NICOLAI CREEK Poliard Wireline Inc. RED RACER CODY B., MIKE H., DAWSON B. 2 7r8 8RD ON GOING 16 LYLE S. 2396' Tubing Hanger 16' 2.31 1.51, 200 3 Detail: Size and otal Hours Worked I I Total Tool Costj I Total Hour Cost Well Downtime Hr. Shut In H2S PPM Approved by: _ tyle Saaage Code: LOE WSE NC -1B Pollard AMAROQ - ALASKA HOT OIL SERVICE REPORT Date: Work being done: Supervisor H.O. Unit #: 10/6/2019 Well Number: I_OCatlon: AFE# / Charge Code: Pollard Wireline Crew: NCU-1B Injection Test and Survey AMAROO L. SAVAGE KENWORTH HENTHORNE, BROWN, BAKER ,1i11M [total Hours Workedl 12 1 Total Tool Coet Total Hour Cost , ELI Cost: Cumulative Cost: Approved by: ., f* 54"#e Code: LOE WSE NC -1B Pollard Amaroq- ALASKA WELL SERVICE REPORT Date: Work being done: Wireline Company Wireline Unit Number: ee Connection Size/Type Present Operations Supervisor Zero Wireline at: Minimum Tubing ID: Start Tbg. & Csg. PSI 1 01712 01 9 Well Number: Location: AFE# ! Charge Code: Pollard Wireline Crew: Total Wireline Miles: Swab Tum Count Max Depth (KB): Well KB: Max Tool OD: Ending Tbg & Csg PS11 NCU-113 PULL PACK OFF PLUG NICOLAI CREEK Pollard wireline Inc. RIH W/ EQUALIZEING PRONG TO 2398'KB WIr POOH METAL MARKS RED RACER CODY B„ MIKE H , DAWSON B. 2 718 8rd RIH W/ SAME TO 2378'KB PICK NO SPANGS POOH BLOWN UP HOLE SLIP AND CUT WIRE COMPLETED 18 LYLE S. 2400' Tubing Hanger 11' 2.31 2.29° VAC - 200 190-200 Time 0oeratl21l_q,2jgjll W!L valve 7:30 MORNING MEETING 8:00 PICK UP LUB 8:15 RIH W/ EQUALIZEING PRONG TO 2398'KB WIr POOH METAL MARKS 8:45 RIH W/ 2 718 GS TO 2397'KB W/T POOH W/ ASTOP - COOLANT HOSE LEAKS REPAIR LEAK 10:10 RIH W/ SAME TO 2378'KB PICK NO SPANGS POOH BLOWN UP HOLE SLIP AND CUT WIRE 10:50 RIH W/ EQUALIZING PRONG TO 2043'KB W/T GOS DOWN TO 2049'KB PRESSURE COME UP 20PSI 11:05 RIH W/ 2 718 GS TO 2049'KB Wfr COMES FREE POOH W/ PACK OFF 11:50 RIH W/ SAME TO 2400'KB W/T POOH W/ AD -2 STOP 12:10 RIG DOWN v Tool Cost: Labor: 3 -MAN CREW/12 HRS otal Hours Worked 12 Total Tool Cost7atai Hour Cost 5 �� Cumulative Cost: Well Downtime Hr. Shut in H2S PPM Approved by: ' Code: AMAROQ HOT OIL SERVICE REPORT Date: 10!772019 Well Number: NCU 1-3 Work being done: M.LT. standby _ Location: SHIRLEYVILLE Supervisor LYLEIJOSH _ AFE# / Charge Code: H.O. Unit #: KENWORTH. Pollard Wireline Crew: HENTHORNE, BROWN, BAKER Total focal Hours Worka--dT_12 � Total Tool Cost Total Hour Cost & I ---� STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit.: iim. sdsm@alaska.aov: AOGCC. Insnectors(rialaska aov' phoebe.brookspalaska.aov OPERATOR: Amarog Resources, LLC FIELD/UNIT I PAD: Nicclai Creek Unit 181219 Pad DATE: 9172019 IA, 10/5/2019 Tubing OPERATOR REP: Lv Ie Saaage AOGCC REP: Waived chris..11hiceaalaska aov Well NCU 1B INTERVAL Codes I Pressures: Pretest Initial 15 Min. 30 Min. 45 MIn. 60 Min. 4=Four Year Cycle F=Fed PTD 202-162 Typelnj 4V Tubing 220 220 220 Type Tes[ P Packer TVD 2223' BBL Pump 0.25 IA 2245 2150 2150 Interval Test psi 2000 BBL Return 1 0.25 OA NA NA NA Result P Noes: Work conducted as part atwork program in Sundry number 319346, NCU 1B Pressures: Pretest Initial 15 Min. 30 Mi, 45 Min. 60 Min. PTD 202-162 Typelnj W Tubing 2100 2100 2100 Type Test P Packer TVD 2223' BBL Pump 0.25 IA 40 40 40 Interval I Test psi 2000 BBL Return 1 0.25 OA NA NA NA Result P Notes: Plug in tubing set at 2278' WLM fa- hutting MIT. Well Pressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min. PTD Typelnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi I BBL RturdI A Result Notes: Well Pressures'. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTDTypelnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min. PTD Typenj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min, 45 Min. 60 Min. PTD Typelnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Typelnj Tubing Type Packer TVD BBL Pump IA InterTest val Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min, 30 Min, 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Nates: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Cotler W=Waher P=Pressure Test I=Initial Test P=Pass G=Gas 0= gtier(desaibe In Nates) 4=Four Year Cycle F=Fed 5=51utry V= Reported by Variance 1=Inconclusive I = laddsdlal Warleeeter o=(Aher(desnnde in notes) N = Not In)eNn9 Form 10-426 (Revised 0112017) NCU 1 B MIT 10.426 rev1 Amaroq I Well: INCU-1B I Field: Nikolai Creek 10/06/2019 Report date: 1011812019 Amaroq I Well: JNCU-1B I Field: I Nikolai reek 10/06/2019 25 50, 751 100( m Y 125( t tZ N 150( 1750 2000 2250 2500 Pressure (psia) 0 100 200 300 400 500 600 700 OU eo /u /5 80 85 90 95 100 105 110 115 120 Temperature (Deg. F) Pressure — Perfs x PKR —7� -- 2 7/8" o Sliding Sleeve 13 3/8"POOH Press —10 3/4" —Temperature —POOH Temp Report date: 10/18/2019 Amaroq Well: INCU-IB I Field: Nikolai Creek 10/06/2019 25 50 75 100 m Y 1251 L w Q d) 150( 175( 200( 2250 2500 Pressure (psia) 0 100 200 300 400 500 600 700 bU tib /0 75 80 85 90 95 100 105 110 115 120 Temperature (Deg. F) Pressure — Perfs x PKK _.7^ ----2 7/6' o Sliding Sleeve 133/8"—POOH Press —10 3/4" —Temperature —POOH Temp Report date: 1011812019 Amaroq I Well: NCU-19I Field: INikolai Creek 10/06/2019 Temperature (Deg. F) —Pressure - Perfs x PKR —7" 2 7/8" n Sliding Sleeve —13 3/8" —POOH Press —10 3/4" —Temperature —POOH Temp Report date: 10/18/2019 Pressure (psia) 0 100 200 300 400 500 600 700 0 250 500 Pressure -Temperature Profile I 1. 2. RIH-POOH Overlay Static 3hr after Injection - _ 750 1000 ----- - -- _._ m d 1250 m _ 1500 1750 - I _ 2000 1 2250 x I I _ x- 2500 60 65 70 75 80 85 90 95 100 105 110 115 120 Temperature (Deg. F) —Pressure - Perfs x PKR —7" 2 7/8" n Sliding Sleeve —13 3/8" —POOH Press —10 3/4" —Temperature —POOH Temp Report date: 10/18/2019 Pressure (psia) 0 100 200 300 400 500 600 1000 m Y w 1250 0 L Q N 1500 1750 2000 2250 2500 40 45 50 55 60 65 70 75 80 85 _ ssure BasTemperature (Deg. F) Pree — Perfs x PKR ---7° 27/8" e Sliding Sleeve 133/8" —Press 3hr —103/4" —Temperature Base —Temp 3hr Pressure (psia) Temperature LDeg. F) —Pressure Base — Perfs x PKR —7 27/8" n Sliding Sleeve X13 3/8" —Press 3hr —103/4" —Temperature Base —Temp 3hr Amaroq I Well: NCU-16 I Field: Nikolai Creek 10/06/2019 GradientPressure - 04 01 OA 08 1 1 ® 11 .__ 1 111 1250 W 11 m: - Wit• �' — _ 1750 i a a 111- � m°'•�>.' - a a ate, _ --_�_ •eae:— _ 1 m i c • a a Temperature25007 Gradient- • Gradient --o- Pressure • -• - Report date: 10/18/2019 Amaroq I Well: NCU-1B I Field: INikolai Creek 10/06/2019 Pressure - Gradient (psi/ft) -0.4 0.0 0.4 0.8 1.2 1.6 25 501 75( 1750 2000 2250 2500 H -10 Report date: 10/16/2019 RIH Grad Static 3hr after Injection 7 -4 -1 2 5 Temperature -Gradient (Deg. F/100 ft) - —Pressure Gradient — Perfs a Temp Gradient ! 120 110 100 90 E 12 13 14 15 16 17 18 Time (hrs) —Pressure —Temperature 7o RE 50 40 19 N N N N PRESSURE VS DELTA TIME Company: Amaroq Location: NCU Date: October 06,2019 Serial# 6214 Max. Pressure: 744.765 DELTA TIME(HOURS) 6214 -TUBING (psia) Well: N U -1B Field: Nikolai Creek 10/06/2019 cob ,,' Cr-e6v- l/3 PM 20Z1 b z C Regg, James B (CED) From: G Scott Pfoff <gspfoff@amarogrescurces.com> Sent: Monday, October 21, 2019 1:30 PM 7\"q 1i)1al lei To: Regg, James B (CED); DOA AOGCC Prudhoe Bay; Brooks, Phoebe (CED); Wallace, Chris D (CED) Cc: 'Jesse Mohrbacher - SolstenXP Inc. Qesse@solstenxp.com)'; Schwartz, Guy L (CED) Subject: 10-426 MIT form Attachments: NCU 1B MIT 10-426 revl.pdf; NCU 1B MIT 10-426 revl.xlsx; NCU 1B IA MIT 7sepl9.xlsx.pdf; NCU 1B tubing MIT 5octl9.pdf Please find Form 10-426 and associated documents attached. A full Report of Sundry Well Operations has been submitted to Guy Schwartz electronically and originals by FedEx. Thank you, �F aroq Resources, LLC G. Scott Pfoff, President 4665 Sweetwater Blvd., Suite 103 Sugar Land, Texas 77479 (832) 999-4603 - direct (713) 816-6870 - mobile Please note new email address: gspfoff@amarogresources.com STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: Ilm.raggilgi8laskeAOV: AOGCGInsoectorstlalaskacov ph0ebe.brook.0.1aska.cov OPERATOR: Amarog Resources LLC FIELD/UNIT/PAD: Nicolai Creek Unit 113/2/9 Pad DATE; 99120191& 10/52019 Tubing OPERATOR REP: Lyle Savage AOGCC REP: Waived ch I II ®I k v Well NCU 113 INTERVAL Codes Pressures: I Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 4=Four Year Cycle F=Far PTO 202-162' Type Inj W Tubing I = I ani Wastewater 220 220 220 N= Na lc)eding Type Test P Packer TVD 2223' _ BBLPump 0.25 IA 2245 2150, 2150 Interval I Test psi 2000 " BBL Retum 0.25 -1 OA NA NA NA Result P Notes: Work conducted as part o/work program in 5untlry number 319_348. NCU 1B Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 202-182 Type Inj W Tubing 2100 2100 2100 Type Test P Packer TVD 2223' BBLPump 0.25 IA 40 40 40 Interval I Test psi 2000 BBL Return 0 25 OA NA NA NA Result P Notes: Plug in tubing set at£2T8'WLM for tubing MIT. Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, PTD Type IN] Tubing Type Test Packer ND BBLPump I IA Interval Test psi BBL Return I OA 0.esuR Note.: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnl Tubing Type Test Packer TVD BELL Pump IA Interval Testpsi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTDTypelnl I Tubing Type Test Packer TVD BBLPump I IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 3D Min. 45 Min, 60 Min. PTD Type lnj Tubing Type Test Packer TVD FULL Pump IA Interval Test psi BBL ReWrn OA ResuR Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, PTD Type Inj Tubing Type Test Packer TVD RBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTDType Inj Tubing Type Test Packer TVD BBLPump IA Interval Test psi BBL Return OA Result Notes: TYPE [NJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W=Water P=Pressure Test 1=Initial Test P=Pass G=Ga. 0= Miner (describe, In Noten 4=Four Year Cycle F=Far s=man' V= Reaulrea or Variance I=lnconclrene I = I ani Wastewater O=Omer (aeaume In nmes) N= Na lc)eding Form 10426 (Revised 01/201]) NCU to MIT 10426 revs THE STATE OIALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olasko.gov G. Scott Koff President Amaroq Resources, LLC 4665 Sweetwater Blvd., Suite 103 Sugar Land, TX 77479 Re: Nicolai Creek Field, South Undefined Upper Tyonek and Beluga Undefined Gas Pools, Nicolai Creek Unit 1B Permit to Drill Number: 202-162 Sundry Number: 319-346 Dear Mr. Pfoff: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, �2� Daniel T. Seamount, Jr. Commissioner DATED this today of August, 2019. R9DMSk4A)AU6 0 6 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25 280 E "�``. E- CW E--1 E to JUL2 J 2019 �/s%i9 ori 0r 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown El Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Sued Well ❑ Alter Casing ❑ Other: Injection test/11.1110 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Amaroq Resources, LLC Exploratory ❑ Development 0 Stratigraphic ❑ Service ❑ 202-162 3. Address: 6. API Number. 4665 Sweetwater Blvd., Suite 103, Sugar Land, TX 77479 50-283-10020-02-00 ' 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? NA Nicolai Creek Unit #1 B ' Will planned perforations require a spacing exception? Yes ❑ No EI ' 9. Property Dgsignation (Lease Number): 10. Field/Pool(s): r t ADL 17585 & 391471 1 Nicolai Creek South Undefined Upper Tyonek & Beluga Undefined Gas 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 3672' 3618' 3600' 3546' 280 None None Casing Length Size MD TVD Burst Collapse Structural Conductor 232' 20" 94# H40 232' 232' 1530 psi 520 psi Surface 1904' 13-3/8" 54# J55 1904' 1904' 2730 psi 1130 psi Intermediate Production 3650' 7" 23# J55 3560' 3596' 4360 psi 3270 psi Liner Perforation Depth MD (ft): Perforation Depth TVD ft) Tubing Size: Tubing Grade: Tubing MD (ft): 2307'-3575 2254' - 3521' 2-7/8" 6.5# J-55 3396' Packers and SSSV Type: Halliburton 07 (3) and VTA (1) packers Packers and SSSV MD (ft) and TVD (ft): G77 @ 2275', 2436, 2761' VTA @ 3145' MD No SSSV 12. Attachments: Proposal Summary ❑ Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 12 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 1 -Aug -19 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS I] WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: G. Scott Pfoff Contact Name: Jesse Mohrbacher Authorized Title: President, Amaroq Resources, LLC /r G 7q,Contact Email: 'esse solst 7�� '/� a Contact Phone: 907-244-4537 Authorized Signature: Date: COMMISSION USE ONLY Sundry Number: Conditions of approval: Notify Commission so that a representative may witness,, / Plug Integrity El BOP Test ❑ Mechanical Integrity Test L{I� Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS AUG 6 2019 D Spacing Exception Required? Yes ❑ Nod 1 Subsequent Form Required: lb-40"A APPROVED BY Approved by:42� COMMISSIONER THE COMMISSION Date: p C,Dw -711sl-ho y �/6fMii ORIGINAL -0 �rll Submit Form antl Form 10-403 Revised 42017 Approved application is valid for 12 months from the date of apprwo,,va�l. *,`_ _ qdachments in Dupplicaatte/ Amaroq Resources, LLC Nicolai Creek Unit No. 1-B Current Configuration (2013) e Drilled 26"Hole 7. 20" 94# H-40 Conductor set at 232', Cmtd to surface w/300 sx "G". 2-7/8" 65 # 3-55 tbg to %urface .'., Drilled 17112"Hole 13-3/8"54#J-55 Surface Csg at 1,9041. Cmtd to surface w/ 1,530 sx "G". Sliding Sleeve w/X-profile a 2,263' Carya 2-1.2 Perfs: G-77 Packer C 2.).75' (closed) /(B'h 2,307'-2.3 26' MD J 2,350'-2.370'MD 2a.rQ- (TVD 2,254'-2316') Sliding Sleeve w/ X -profile «2,359' G-77 Packer @ 2,436' (Open) Carya 2-2.1 Perfs: 2,480' -2.486' MD (TVD 2,426'-2.434') Carya 2-2.2 Perfs: 2,604'-2.622' MD _ (TVD 2.550'-2.568') Sliding Sleeve w/ X -profile @2.749' (open -1/13) G-77 Packer Q 2,761' Carya 2-3 Perfs X -nipple C 2,774' 183T-2.842' MD 2.862'-2.867'MD 2.913'-2.918' MD (TVD 2.783' -1864') VTAPacker Ca, 1145' XN Nipple 4,3,184' Carya 2-4.2 Perfs: 3,191'-3,211'MD Well completed with sand (TVD 3,137 -3,157) exclusion screens across the indicated perforations bottom Carya 2-5.1 Perfs: at 3396'. U an 2013 tag at 3,371'-3,40 I' M D 3255' (TVD 3.307' -3,348') _ 1'•'ti- Cement Retainer (P 3,500' Carya 2-6.1 Perfs: _ y. 3.560'-3.575' MD Lower 3 completions treated w/ (TVD 3-506'-3.521') Weatherford Sand Aid 2010-11 Float collar n 3,604' MD •y - Float shoe a 3,648' MD 7" 23# J-55 Production TD a 3,672' MD (3,617 TVD) Csg @ 3,650'MD (3,595' TVD). Cmtdtosurfacew/ 82 bbls "G" lead at 12.5 ppg and 67 bbls "G" tail at 15.8 ppg. AMAROQ RESOURCES, LLC NICOLA[ CREEK UNIT 1B Set Wireline Plug, MIT, Injection Test with Temperature Survey Data to Support Disposal Injection Order Application PTD 202-162 Version 1.1 (22 -Jul -19) STATUS OF WELL: Live well (280 psi SITP), with CASING: 7 -inch 23#, K-55 casing set at 3672' (Capacity= 0.0393 bbl/ft), PERFORATIONS: 23307-2326', 2350-2370', 2480-86', 2604-2622', 2837- 2842', 2862-67', 2913-2918', 3191-3215', 3373-3396', 3557-3580' MD PACKERS: G-77 at 2275', G-77 at 2436', G-77 at 2761', VTA at 3145'. TUBING: 2-7/8" 6.5# J-55 EUE w/ 3-1/2" WF MonoPore screens at 2839-49', 2860-70', & 2909-19', Locator Seal Assemblies stung into packer at 3145', and 3-1/2" MonoPore Screens at 3192-3212' and 3375-95' with 3-1/2" tubing spacers and Bull Plug at bottom at 3396'. (Tubing Capacity --0.00579 bbl/ft) SLIDING SLEEVES: XD at 22631, XD at 2365', and XD at 2749', all with X - profiles and XN nipple at 3184'. PROCEDURE: 1) Give AOGCC inspector notice of MIT in 4) below. 2) RU Pollard slickline unit. Pressure test lubricator with SI well pressure. 3) Make gauge ring run to X profile in sliding sleeve at 2749. 4) Make a brush run as necessary to clean sliding sleeve at 2359'. 5) Run PX plug and set in X profile in sliding sleeve at 2749'. (May be required to set CIBP in tubing just above packer (G77 pacer at 2436') at about 2430'). 6) Close sliding sleeve at 2359' and pressure test tubing and IA to 2000 psi (or as required by approved Sundry), on chart for 30 minutes, witnessgd by AOGCC inspector. 7) Open sliding sleeve at 2359'. Release Pollard slickline (unless memory tool is used in next step). 8) RU Pollard a -line truck with temperature/pressure survey tool. Using Pollard hot -oil truck, heat 120 bbl of clean produced water to 150-175 degrees. Run static background temperature/pressure survey. With Pollard SPYDR recorder set at 15 second intervals, get static pressure for 15 minutes then perform injection test by pumping into perforations at 2307-70', 100+/- bbl at 1 bpm, running temp/pressure survey every 15 minutes. Immediately after last run, SI well recording pressure fall-off until static for 30 minutes. Make temp/survey run after 15 minutes after shut-in, then 30 minutes later, then an hour later, then every hour until pressure is static or for 3 hours, whichever is greater. 9) Rig down and release Pollard and hot oil truck. 10) Analyze data and submit to AOGCC as required for Report of Sundry Well Operations. 7roq Resources, LLC 4665 Sweetwater Blvd, SLItC 103 Sugar Land, TX 77479 July 22, 2019 Ms. Jessie Chmielowski, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Re: Application for Sundry Approval — MIT and injection test, Nicolai Creek# 18 Well, PTD #: 202- 162, API#: SO -283-10020-02-00 Dear Ms. Chmielowski: Amaroq Resources, LLC hereby makes application for Sundry Approval to perform a mechanical integrity test (MIT) followed by an injection test in the Carya 2-1.2 perforated interval of the Nicolai Creek Unit (NCU) #16 well. The purpose of this work is to confirm the suitability of this interval for potential use as a disposal zone for produced water from the NCU field. Amaroq intends to incorporate the data collected from this injection test into a future application for a Disposal Injection Order for the NCU #113 well. The proposed work involves setting a plug via slickline in the profile at 2,749' to isolate all perforated intervals below the Carya 2-1.2 zone. An MIT will then be performed on the tubing and inner annulus followed by an injection test with hot water into the Carya 2-1.2 sands through the sliding sleeve at 2359'. In addition to recording injection rate and pressure data, a temperature survey will be run to verify containment of the injected fluid within the Carya 2-1.2 zone. Please find the attached information to support this Application: Form 10-403 Application for Sundry Approvals; Wellbore diagram illustrating the current well configuration; and Slickline, MIT and injection test procedure. If you have any questions or require any additional information, please contact me at 832-999-4603 or Jesse Mohrbacher at 907-244-4537. Sincerely, ✓��a� �� G. Scott Pfoff President 4665 Sweetwater Blvd., Suite 103 0 Sugar Land, Texas 77479 0 (832) 999-4603 0 (832) 999-4382 OF 711 S I//7 . THE THE STATE Alaska Oil and Gas ht ��'-9� of A T A �! tl 1 Conservation Commission �s='dd l 1�J1 5 - 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 P Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Manager goal) *l i_!1. 2 .0 Aurora Gas, LLC 17, 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Nicolai Creek Field, S. Undefined Upper Tyonek Gas Pool, Nicolai Creek 1B Permit to Drill Number: 202-162 Sundry Number: 317-276 Dear Mr. Pollock: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. The Alaska Oil and Gas Conservation Commission(AOGCC)approves the setting of a temporary plug in this well to provide isolation from the reservoir as a short-term barrier. This work does not meet AOGCC's regulatory requirements for suspension or plugging and abandonment of this well. Prior to relinquishing the lease back to the landowner, the operator is required by law to properly plug and abandon this well. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Hollis S. French Chair DATED this day of July, 2017. RBDIVis Li_,�� 12017 • • RECEIVED STATE OF ALASKAitiN - 6 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS fes' =� 20 AAC 25280 / 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Weil ❑ Operations shutdown 9 Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tublg 9 Change Approved Program 9 Plug for Redrill ❑ Perforate New Pool 9 Re-enter Susp Well 9 Alter Casing 9 Other.Temporary Plug 9 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Aurora Gas,LLC Exploratory ❑ Development ❑ ' 202-162' 3.Address: 1400 W.Benson Blvd.Suite 410 Straligraphic ❑ Service6.API Number- � So-A$3-toola-0A-«o Anchorage,AK 9950350-286.408294Y3 • IN) 7.If perforating: � 8.Welt Name and Number What Regulation or Conservation Order governs well spacing in this pool? (lJP Nicolai Creek#1 B Will planned perforations require a spacing exception? Yes ❑ Nor❑ >'A 9.Property Designation(Lease Number): 10.Field/Pool(s): U.13f onilt1.i A 1 ADL 17585 , 391'0) frig Nikolai Creek South Undefined4as c�n,a 2041 `rycl6 11• PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth1MD: Ef(ectivg_Dego?TVD: MPSP(psi): Plugs(MD): Junk(MD): 3672' 3617' PSI' (AA 380 psi None None Casing Length Size MD TVD Burst Collapse Structural Conductor 232' 20"901-140 232' 232' 1530 psi 520 psi Surface 1904' 13 3/8"54*J55 1904' 1904' 2730 psi 1130 psi Intermediate Production 3650' 7"23*J55 3560' 3595' 4360 psi 3270 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 2307'-3575' - 2254'-3521 2 7/8" J-55 6.5* 3396' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ftp: G-77 and Weatherford TVA packers 0-77 @ 2275',2436'&2761'and VTA @ 3145' 12.Attachments: Proposal Summary 9 Wellbore schematic 9 13.Well Class after proposed work: Detailed Operations Program 9 BOP Sketch ❑ Exploratory ❑ Stratigraphy 9 Development 9• Service ❑ 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: OIL 9 WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ - WAG ❑ GSTOR ❑ SPLUG 9 Commission Representative: GINJ ❑ Op Shutdown 9 Abandoned 9 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: George Poll. Contact Name: George Pollock Authorized Title: Manag7rod •.. Eng Contact Email: apallack(d aurorapower.com 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 317 - 274 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: cmpo Advi t'LL-L PGS ti=t t tr' "eC c .vniz'mcw-sT FO':. S"A-.Pr-I-3StC'h1 Op— ? ', -A Post Initial Injection MIT Req'd? Yes 9 No ❑ Spacing Exception Required? Yes ❑ No El Subsequent Form Required: i 0 ,,,,404 RBDMS L - JUL 1 1 2017 60:::S\s„ APPROVED BY I Approved by:y � COMMISSIONER THE COMMISSION Date: 1� 1,,,I�� 1 "V W/� 7(� n _,,_,(I i Submit Form and V' A/` Form 10-403 Revised 4/2017 /Rr44 4INOA jd for 12 months from the date of approval. Attachments in Duplicate Aurora Gas, L June 16,2017 Ms. Cathy Foerster, Chair RECEIVED Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 104 JUN 1 6 2017 Anchorage, AK 99501AOGCC Re: Application for Sundry Approval—Set Temporary Plug Nicolai Creek#1B Well PTD #: 202-162 API#: 50-283-10020-00 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 Undefined Gas Field on the west side of Cook Inlet, southwest of the Village of Tyonek. This well is currently producing gas from multiple zones in the upper Tyonek sands and is mechanically sound. Aurora Gas is currently in Chapter 11 bankruptcy protection while attempting to reorganize and emerge with new owners/investors. This application is being submitted as part of our Reorganization Plan filed with the bankruptcy court if liquidation actions are ordered. Aurora Gas, LLC will provide all potential new owners/investors notice of the impending action before on-site activity begins. The proposed work involves setting a plug via wireline in the profile at a depth of 2,263' 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, • Wellbore diagram illustrating the current well configuration, and • Slickline Temporary Plug Set- Generalized Procedure. If you have any questions or require any further information, please contact me at(907) 277-1003. Sincere 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 • 0 Aurora Gas, LLC Nicolai Creek Unit No. 1-B Current Configuration (2013) I :- . ,: . i.. Drilled 26"Hole 4 20"94#11-40 Conductor set ' - at 232',Crotd to surface w/300 sx"G". f 4„ � =d ,rv.4 "4 4 i :4 'i 's 2-7/8"6.5#J-55 tbg to surface 4 ,, lip ; ; '''s*' i" t°' r ,.' Drilled 17 1/2"Hole ,4%/ s *:9 •Y e 4 k4 13 3/8"54#J-55 Surface Csg at F 1,904'. Cmtd to surface w/ ,s 1,530 sx"G". " re' Sliding Sleeve w/X-profile*2,263' Carya 2-1.2 Perfs: G-77 Packer*2,275' (closed) 2,307'-2,326'MD r, 2,350'-2,370'MD (TVD 2,254' 2,316') ---'"4 m';"�"- Sliding Sleeve w/X-profile @ 2,359' 4.' +-*4 G-77 Packer*2,436' (Open) Carya 2-2.1 Perfs: r a' ._ 2,480'-2,486'MD ,,40 am"_" (TVD 2,426'-2,434') *, :Y Carya 2-2.2 Perls: 2,604'-2,622'MD (TVD 2,550'-2,568') Sliding Sleeve w/X-profile @ 2,749' . ,.*. (open-1/13) '' G-77 Packer*2,761' Carya 2-3 Perfs: _,. y X-nipple @ 2,774' 2,837'-2,842'MD Ell 2,862'-2,867'MD ' 2,913'-2,918'MD •• ! 10,4 (TVD 2,783'-2,864') _..' 'ir..- i •P.-A VTA Packer @ 3,145' , ; ,CN Nipple*3,184' 4 { Carya 2-4.2 Perfs: ,4 ' 3,191'-3,211'MD --•� Well completed with sand (TVD 3,137'-3,157') T 1f- exclusion screens across the indicated perforations,bottom Carya 2-5.1 Perfs: ii..._.. at 33%'. Jan 2013-tag at 3,371'-3,401'MD - . 3255' (TVD 3,307'-3,348') '. t ,�., ;,n;„� Cement Retainer*3,500' Carya 2-6.1 Perfs: A.I.,, p 3,560'-3,575'MD =dia Lower 3 completions treated w/ (TVD 3,506'-3,521') ,.- ., *s Weatherford Sand Aid 2010-11 Float collar @ 3,604'MD .';i , ;� a 41 Float shoe @ 3,648'MD d'' ':V70 16. 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 7/31/2006 WJP Drawing Not To Scale • 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 %z"tubing with 2.812"X landing nipple profile. Set PXX plug in uppeunost 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. ,�i�Qe Saua9e(6/11/2017) RECEIVED DEC 2 1 2006 www.aurorapower.com December 20, 2006 AI~$ka Oil & Gas Cons. Commission Anchorage John K. N onnan, Chainnan State of Alaska Oil and Gas Conservation Commission 333 W. 7tl1 Avenue, Suite 100 Anchorage, AK 99501 Re: Report of Sundry Operations (AOGCC fonn 1 0-404)....,..A.~.n;n 0 2007 Nicolai Creek Unit #lB Well iW'tl'U....... JAN 8 Production from Additional Intervals Dear Mr. Nonnan: Aurora Gas, LLC (Aurora) hereby submits for your review and approval the report of sundry well operations which allows production from certain stratigraphic intervals for the Nicolai Creek Unit No. 1B well in the Nicolai Creek gas field on the west side of the Cook Inlet. Attached are AOGCC Ponn 10-404, Slick-Line Procedures for Well Operations, Daily Report, Well Configuration Diagram, and down-hole equipment data. Specifically, Aurora has perfonned the following operations: ).> Set a plug at the XN nipple located at 3,184' MD stopping production from the Carya 2-4.2,2-5.1 and 2-6.1 perforations from 3,191' to 3,575' MD. ).> Opened the sliding sleeve at 2,375' MD directly above the packer at 2,440' MD allowing production from the Carya 2-1.2 perforations at 2,307' to 2,326' MD and 2,350' to 2,370' MD. ).> Opened the sliding sleeve at 2,742' MD directly above the packer at 2,765' MD allowing production from the Carya 2-2.1 and Carya 2-2.2 perforations at 2,480' .I to 2,486' MD and 2,604' to 2,622' MD. Should questions arise in connection with this request, please contact Mr. Ed Jones in the Houston office at (713) 977-5799. Respectfully Submitted By, ~~~ Bruce D. Webb Manager, Land and Regulatory Affairs attachments ;;JCfd--( <Od 2500 Citywest Blvd., Suite 2500· Houston, Texas 77042· (713) 977-5799· Fax (713) 977-1347 1400 West Benson Blvd., Suite 410. Anchorage, Alaska 99503· (907) 277-1003· Fax (907) 277-1006 · STATE OF ALASKA A ALAS Oil AND GAS CONSERVATION COMrvIW'0N REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon U Repair Well 1J Plug Perforations LJ Stimulate 1J Other ~ plug & open tubing Performed: Alter Casing 0 Pull Tubing 0 Perforate New Pool 0 WaiverO Time Extension 0 sleeves Change Approved Program 0 Operat. Shutdown 0 Perforate 0 Re-enter Suspended Well 0 2. Operator AURORA GAS, lLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 Exploratory 0 202·162 3. Address: 1400 W. Benson Blvd., Suite 410 Stratigraphic 0 Service 0 6. API Number: f)f,. Anchorage, AI< 99503 50-283.10020~ f. t·o1 7. KB Elevation (ft): 9. Well Name and Number: 35.5' AMSl (DF) Nicolai Creek #1 B 8. Property Designation: 10. Field/Pool( s): . State of Alaska ADl 17585 Nicolai Creek (South Undefined Gas) 11. Present Well Condition Summary: Total Depth measured 3,672 ' feet Plugs (measured) none true vertical 3,618 . feet Junk (measured) none Effective Depth measured 3,600 feet true vertical 3,510 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 232' 20" 232' 232' n/a n/a Surface 1,904' 13-3/8" 1,904 1,904 1,530 psi 520 psi Intermediate 2,186' 1 0-3/4" 2,186' 2,186' 3,580 psi 1,580 psi Production 3,648' 7" 3,648' 3,648' 3,740 psi 3,270 psi Liner Perforation depth: Measured depth: 2,307' - 3,575' True Vertical depth: 2,254' - 3,521' Tubing: (size, grade, and measured depth) 2-7/8" J-55 3,112' Packers and SSSV (type and measured depth) Weatheñord VT A 3,145' MD 12. Stimulation or cement squeeze summary: Intervals treated (measured): nla Treatment descriptions including volumes used and final pressure: nla 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Met Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 150 ' 10 290 psi 310 psi Subsequent to operation: 0 1900 0 290 psi 790 psi 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run n/a Exploratory 0 Development 0 , Service 0 Daily Report of Well Operations Dec. 16,2006 16. Well Status after work: OilO Gas 0 WAG 0 GINJ 0 WINJ 0 WDSPL 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. SUndry Number or N/A if C.O. Exempt: 306-354 Contact J. Edward Jones, V.P., Engineering and Operations (713) 977-5799 By Bruce D. Webb Title Manager, land and Regulatory Affairs Signaturè~ ~ )~ Phone (907) 277-1003 Date 12/20/06 Form 10-404 Revised 04/2006 þqi ~ 1'~'D-7 sUDm~..bmit O. ... " 'nal Only ~/k~? . . AURORA GAS, LLC SLICK-LINE PROCEDURES NICOLAI CREEK UNIT#1B DECEMBER 2006 NICOLAI CREEK #1 B CURRENT CONDITONS: SITP-320 psi (should be about 1200 psi). TUBING: 2-7/8". 6.5 # with Sliding Sleeves at: 2263' (packer fluid-closed) 2359' (closed) 2749' (closed) (all wi X profiles above the ports) and wi 2.313" X landing nipple at 2774' and XN landing nipple at 3184' Packers at 2275',2436',2761', and 3145' (see attached well bore and completion diagrams) NOTE: Well is moderately deviated wi most severe dogleg at whipstock @ 2186' PROBLEM: Lower completion is making water and may have sanded up tubing. SUMMARY OF PLAN: Run gauge ring to check for fluid level, sand, and confinn XN profile at 3184' is open. Clean out as necessary. Run and set plug in XN nipple at 3145'. Open sleeve at 2742'. Open well to flow. Swab well in ifit won't flow. PROCEDURE: 1) Pollard crew to fly into Beluga to get boom truck and drive to Shirleyville, stopping by the Moquawkie yard to get wire-line truck. 2) RU Pollard on Nicola Creek Unit #1 wi well house in place-may have to move well house slightly to center opening over tree. RU lubricator on tree cap (2-7/8" EUE box connection). Open well to pressure test lubricator-have pressure gauge on lubricator. Maintain pressure on well as high as possible. 3) RIH with 2-118" (or smaller) gauge ring, slowly. Determine fluid level and watch for sand plug. If clear, run in thru XN nipple at 3184' to check for fill inside sand screen below to 3396'. XN landing nipple has 2.313" profile wi 2.205" no-go. 4) If sand fill is encountered above XN nipple at 3184', run balers as needed to clean out to XN landing nipple. Do not attempt any cleanout below XN. Beware that pressure below any sand plug could be as high as 1200 psi at surface, so slowly bale sand and watch pressure gauge on lubricator for any sign of break thru. 5) Iflwhen XN profile is clear, set plug in profile (is there a PX plug that Aurora owns at the Pollard shop? Plan is to leave it in place long term). . . 6) After plug is in place, pick up shifting tool and open Halliburton "XD" Sliding Sleeve (opens down) at 2749' (deepest sleeve)-expect as much as 1000 psi behind sleeve. Well should have a fluid level at this point to cushion pressure differential. 7) With an Aurora Operator on site, open well to facility and insure that it will flow. If well will not well, swab in thru facility separator (gas line is open to vent and water dump is open to produced water tank). 8) When well kicks off, RD Pollard and release to go to TMC 2. 9) Turn well over to AG Operator and produce well to sales. Ed Jones (12/12/06) . . ~:Aurora Gas, LLC DAll Y REPORT Depth: I Date: 16-Dec-06 Company: Aurora Gas, llC AFE# SlW0121706 24 Hour Progress: I 00' Rig: Pollard Wireline Report # 1 last Casing: Well: NCU1B Days Since Spud RKB/Casinghead: Hole Section: Bit# BHA # 1 BHA #2 Total Depth: Serial # Hole Size: Size Depth In: Make Depth Out: Type Drl hrs: Depth In Cir hrs.: Depth Out Cum. Dr!. Hrs: Hours Cum. Cir. Hrs: Nozzles (TFA) PU Weight: ROP Down Weight: T/B/G Rot Weight: Mud Type WOB Rotating: Weight Rotary Speed: Viscosity Rotary Torque: PVIYP Flow Rate: PH PSI off BTM: Water loss PSI on BTM: Solid Content Sand Content Chlorides TD 0.00 TOTAL = 0.00 I Weather- I BOP Test: ¡Next BOP Test: I Operation details and comments Slow Pump Rate #1 MP From To Hours Depth MW SPM Pressure 10:00 11 :00 1.00 Flew to Tyonek-Drove to NCU1 11:00 12:00 1.00 Arrived @ NCU1-Pollard Rigging Up-Opened Well wI 700 psi SITP-RIH wI 2.29 GR-Tagged Fluid @ 1,430'-CRIH Slow Pump Rate #2 to XN @ 3,170' WlM (3,184' RKB)-POH Depth MW SPM Pressure 12:45 14:15 1.50 RIH wI PX Plug & Set in XN Nipple @ 3,184' RKB & Set RIH wI PX Prong & Set-POH-Prong Did Not Release- Redressed Tool & RIH wI Prong-Set Prong-POH Fuel Used: 14:15 16:15 2.00 RIH wI Selective Shifting Tool & Shift Sleeve @ 2,749' Fuel Received: Open-Pressure Dropped fl 700 psi to 640 psi-POH to Fuel on location: 2,359' & Shift Open Sleeve-Pressure Increased to 740 psi Daily Total: $7,456 Fluid level Rose to 1,200' & SITP Climbed to 800 psi Previous Total: $0 Turned Well Over to Production Cum Total: $7,456 06:00 Update: 18:00 21:00 3.00 Mob to TMCU2-Return to SV RU on MM#1 24 Hour Forecast: Incidents: Fairweather Supervision-$1 ,500 Pollard Wireline-$5,586 Transportation-$400 Personnel On location: FWX-1 Pollard-3 Total Hours: 8.50 ¡Operator Reps: Jack Keener I 2-7/8.. 6.5 # J-55 tbg to surface 13 3/8" 54# J-55 Surface Csg at 1,904'. Cmtd to surface wI 1,530 sx "G". Carya 2-1.2 Perfs: 2,307' - 2,326' MD 2,350' - 2,370' MD (TVD 2,254' - 2,316') Carya 2-2.1 Perfs: 2,480' - 2,486' MD (TVD 2,426' - 2,434') Carya 2-2.2 Perfs: 2,604' - 2,622' MD (TVD 2,550' - 2,568') Carya 2-3 Perfs: 2,837' - 2,842' MD 2,862' - 2,867' MD 2,913' -2,918' MD (TVD 2,783' - 2,864') Carya 2-4.2 Perfs: 3,191' - 3,211' MD (TVD 3,137' - 3,157') Carya 2-5.1 Perfs: 3,371' - 3,401' MD (TVD 3,307' - 3,348') Carya 2-6.1 Perfs: 3,560' - 3,575' MD (TVD 3,506' - 3,521') Float collar @ 3,604' MD Float shoe @ 3,648' MD TD @ 3,672' MD (3,617' TVD) . . Aurora Gas, LLC Nicolai Creek Unit No. I-B Current Configuration (12/16/06) Drilled 26" Hole 20" 94# H-40 Conductor set at 232', Cmtd to surface w/300 sx "G". Drilled 17 1/2" Hole Sliding Sleeve wI X-prome @ 2,268' G-77 Packer @ 2,280' (Closed) Sliding Sleeve wI X-profile @ 2,375' G-77 Packer @ 2,440' Sliding Sleeve wI X-profile @ 2,742' G-77 Packer @ 2,765' X-nipple @ 2,775' VTA Packer @3,145' XN Nipple @3,184' (plugged) Well completed with sand exclusion screens across the indicated perforations. Cement Retainer @ 3,500' 7" 23# J-55 Production Csg @ 3,650'MD (3,595' TVD). Cmtd to surface wI 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 7/31/2006 WJP Hft -I RT LlBURTON ENERGY SERVICES Pete Jackson, Account Representative 6900 Arctic Blvd. Anchorage. Alaska 99518 ....16 (907) 344-2929 Customer Cust0111èr Rt'pn:'~Pl1tdtivt' Wt'11 FiPld ID'" Aurora Gas LLC Ed Jones I Jack McDade Nicolai Creek 1 B Nicolai Creek 06/26/06 ....15 Ca,ingSize ClsingWeight Ca,illgGrade Frulll To Tubing Size Tubing W..ight Tubing Grade Tubing Thread 7" 23# K-55 0 3672' EUE Tubing Silt' Tubing W<:>ight Tuhillg Grddt:' From 10 Pick Up Weight SI<1rkuif\Vt'¡ght BlwkWeight \'vl:'ight un Locatm 27/8" 6,5# N-80 & J-55 0 2775,53' 28,000 Ibs 24,000 Ibs 8,0001bs o Ibs. -,61' Tubing Sizt' Tuhil1gWeight Tubillg Gradp Frum T0 ReleasE' G-'1terufPkr. Elem Original RT-TS PBTD 31/2" 9.3# N-80 & J-55 2776,16 3368,35 Max. Deviatoll Dpvi,¡tiol1 Thru PO;"rfs ,OP Relt",)S<:' CenkrofPkr, Elem Completion Fluid BHT SHP PNroratiollS :4-14 a 2913-2918'. b 2862-2867', c 2837-2842', d2604-10' & 2614-22', e 2480- 9,8 PPG Brine 85 deg F 2486', f 2350-2370', 9 2307-2312' & 2317-2326' iilf"'", }:»>:>7>tt,?>.~::!¡¡¡¡:: _. - RKB 11,50 0.00 17 ABB VETCO GRAY Hanqer 2.441 3.668 4,19 11,50 2-7/8" Tubing, EUE 6,5# wi (3) 4' Pup Jts, On top 2.441 3,668 2239.39 15.69 ....13 2-7/8" Pup Joint, EUE N-80 6,5 # 2.441 3,668 8,31 2255.08 16 2-7/S" HES 'XD' DuraSleeve SSD 2,313 3,920 3.96 2263,39 2-7/8" Pup Joint, EUE N-80 6.5 # 2.441 3.668 2,30 2267,35 2-7/8" Pup Joint, EUE N-80 6,5 # 2.441 3.668 4,50 2269,65 Crossover 27/8" EUE Box X 3 1/2" EUE Pin 2.441 3,668 0,78 2274,15 15 7" 22-26# HES G-77 Packer 2,980 6.015 6,09 2274,93 Crossover, 3 1/2 EUE Box x 2 7/8 EUE Pin 2.441 4,500 0,82 2281,02 :'4-12 2-7/8" Pup Joint, EUE N-80 6,5 # 2.441 3,668 6.18 2281 ,84 2-7/8" Tubinq, EUE 6,5# 2.441 3,668 64,73 2288,02 2-7/8" Pup Joint, EUE N-80 6.5 # 2.441 3,668 6,20 2352,75 14 2-7/S" HES 'XD' DuraSleeve SSD 2,313 3,920 3,99 2358,95 2-7/8" PuP Joint, EUE N-80 6,5 # 2.441 3,66S 4,17 2362.94 .... 11 2-718" Tubinq, EUE 6.5# 2.441 ,3,668 64.79 2367,11 2-7/8" Pup Joint, EUE N-80 6,5 # 2.441 3,668 4,12 2431,90 Crossover 27/8" EUE Box X 3 1/2" EUE Pin 2.441 3.668 0,86 2436,02 13 7" 22-26# HES G-77 Packer 2.980 6,015 6,08 2436.88 Crossover, 3 1/2 EUE Box x 2 7/8 EUE Pin 2.441 4,500 0.81 2442.96 ....10 2-7/8" PuP Joint, EUE N-80 6,5 # 2.441 3,66S 6.12 2443,77 2-7/8" Tubino, EUE 6,5# 2.441 3,66S 291 .29 2449,89 2-7/8" PuP Joint, EUE N-80 6,5 # 2.441 3,668 8.31 2741,18 12 2-7/S" HES 'XD' DuraSleeve SSD 2,313 3,920 3,96 2749.49 :4-9 2-7/8" Pup Joint, EUE N-80 6.5 # 2.441 3,668 2,30 2753.45 2-7/8" Pup Joint, EUE N-80 6.5 # 2.441 3,668 4,70 2755,75 Crossover 27/8" EUE Box X 3 1/2" EUE Pin 2.441 3,668 0.78 2760.45 :..-8 11 7" 22-26# HES G·77 Packer 2,980 6,015 6.10 2761.23 Crossover. 3 1/2 EUE Box x 2 7/8 EUE Pin 2.441 4,500 0.81 2767,33 .,... 7 2-7/8" Pup Joint, EUE N-80 6.5 # 2.441 3,668 6,18 2768,14 10 2-7/S" X Landing Nipple, 2.313" POIi$h Bore 2,313 3.680 1.21 2774,32 Cross Over 2 7/8" EUE Box X 3 1/2" EUE Pin 2.441 3.094 0,66 2775,53 3-1/2" 9,3# EUE Tubinq 2,992 4,240 62.97 2776,19 9 WFD Monopore Scen L-SO,30/S0,6ga,3 1/2-10UN 2,992 4,500 10.49 2839.16 J=~ 31/2" 9.3# EUE PuP Joint, WI combo CDI on top 2.992 4,240 9.61 2849.65 S WFD MonoPore Scen L-SO,30/S0,6!1a,3 1/2-10UN 2.992 4,500 11.49 2859,26 31/2" 9,3# EUE PuP Joint, WI combo cpl on top 2.992 4,240 6.64 2870.75 3-1/2" 9,3# EUE Tubinq 2.992 4,240 31,60 2877.39 7 WFD MonoPore Scen L-SO,30/S0,6ga,3 1I2·10UN 2.992 4,500 10.49 2908,99 3-1/2" 9,3# EUE Tubinq, WI combo cpl on top 2,992 4,240 220.D1 2919.48 3 1/2" 9,3# EUE Pup Joint 2,992 4,240 5,17 3139.49 ..-4 6 3.SS" Staight Slot Locator wi $eal a$$embly 2,992 4.4 70 0,61 3144,66 5 7" 23-29# HES VTA PKR 3.880 6,000 6,30 3145.27 Crossover, 5 1/2" API LC x 2 7/8 EUE Pin 2.441 5,530 0,55 3151.57 2-7/8" 6,5# EUE TUBING, 1 JOINT 2.441 3,680 32,35 3152,12 ..-3 4 2-7/S" XN Landina Nipple, 2.313" x 2,20S" 2.205" 3.680 1,21 3184.47 Crossover, 2-7/8" EUE Box x 3112 EUE Pin 2.441 3.680 0,65 3185,68 3 1/2" 9,3# EUE Pup Joint 2.992 4,240 5.18 3186,33 3 WFD MonoPore Scen L-SO,30/S0,6ga,3 1/2-10UN 2.992 4,500 20.40 3191.51 3-1/2" 9,3# EUE Tubinq, WI combo cpl on top 2.992 4.240 156.44 3211,91 ..-2 3-1/2" 9,3# EUE Pup Joint 2,992 4.240 6.17 3368.35 Z WFD MonoPore Scen L-SO,30/S0,6!1a,3 1/2-10UN 2,992 4,500 19,97 3374,52 1 WFD Bull Pluq nla 4,240 1,31 3394.49 ..- 1 3395,80 . .. LI H URTON ENERGY SH?\i1CfS 'H IUS Pete Jackson, Account Representative 6900 Arctic Blvd, Anchorage, Alaska 99518 .-16 (907) 344-2929 Custom..¡ Cu~tumt'r Rt'prh!:'ntdtivE' WI'II Field ID'''" I .-15 Aurora Gas LLC Ed Jones / Jack McDade Nicolai Creek 1 B Nicolai Creek 06/26/06 Ca,;ingSib' C¡,;ingWf'ight CJ~íngGr.¡d", Frum Tü Tubing Sizl-' Tubing Weight Tubing Gfddf' Tubing Thrf'dd T' 23# K-55 0 3672' EUE Tubing .,¡zt" TubingWf'ight Tubing GrJdt' F'''m T" Pick UpV,>,'pight SI.,\.-koii\V"ight BlorkW..ight vV",ight un lOCdt<H 27/8" 6.5# N-80 & J-55 0 2775.53' 28,000 Ibs 24,000 Ibs 8.0001bs o Ibs, -.61' Tubing Sizt' Tubingv\'pight Tubing Grddt> From Tü R.,I..cl"P O>ntE'ruipkr.EIt'm OrigirrJIRT-TS PBTD 31/2" 9.3# N-80 & J-55 2776.16 3368.35 1\-1.1.\. Devidturt OPvidti"n Thru Pprf, KOP R"'¡t'd,Æ' C...ntc>[oiPkr. EIt'r11 a 2913-2918', b 2862-2867', c 2837-2842', d2604-10' & 2614-22', e 9,8 PPG Brine 85 F 2480-2486', f 2350-2370', 2307-2312' & 2317-2326' Notes: a) 7" 22-26# HES G-77 Pkr's shear release 36,000 LBS Straight Pull .-13 b) T' HES VTA Pkr pulled with VTA Pulling tool, pkr shear release 20,000 Ibs. c) 3.88" Seal Assy: SSL-MSN-MSN-MSN-MSG, effective seal length is 2.40', SSL .61' above VTA no/go d) 27/8" HES SSD 'XO' Durasleeve ODens down I e\ WFO MonoPore Screen centralizer 00 6.125", screen iacket 00 4.50" ~12 __11 __10 __9 =--.8 I """7 __6 __5 __4 __3 __2 , Notes: __1 a) T' 22-26# HES G-77 Pkr's shear release 36,000 LBS Straight Pull b) T' HES VTA Pkr pulled with VTA Pulling tool, pkr shear release 20,000 Ibs, 'I T' 23# CSG c) 3,88" Seal Assy: SSL-MSN-MSN-MSN-MSG, effective seal length is 2.40' .. AURORA GAS RIG: AURORA WELL SVC#1 DESCRIPTION 1.0, TEST PSI THREADS PART NUMBER I SERIAL NUMBER G-77 PACKER # 1 ASSEMBLY G-77 PACKER 7" 22-26# 6.09 6.015 2,98 NA 3 1/2 EUE 101165097 G-77 PACKER # 2 ASSEMBLY PUP JOINT 2 7/8 N-80 6.5 # 4.5 3,668 2.441 2,35 2 7/8 EUE-MOD 8 RD NO PT # I NO SER # CROSSOVER 2 7/8 EUE BOX X 3 1/2 EUE PIN 0.78 3.76 2.441 2,35 2718 EUE X 31/2 EUE NO PT # I NO SER # G-77 PACKER 7" 22-26# 6.09 6.015 2.98 2.35 3 1/2 EUE 101165097 CROSSOVER 3 1/2 EUE BOX X 2 7/8 EUE PIN 0.82 4,5 2.441 2.35 3 1/2 EUE X 2 7/8 EUE NO PT # / NO SER # PUPJæNT2n8N~0~5# 6.18 3.668 2.441 2 7/8 EUE-MOD 8 RD NO PT # NO SER # . ___ ___...m____ TOTAL lENGTH 1S.37 G-77 PACKER # 3 ASSEMBLY EUE 8 RD PUP JOINT 2 7/8 N-80 6.5 # 4.12 3,668 2.441 2,35 500 2 7/8 EUE-MOD 8 RD NO PT # I NO SER # CROSS OVER 2 7/8 EUE B X 3 1/2 EUE P 0.86 3,76 2.441 2,35 500 3 1/2 EUE X 2718 EUE-MOD NO PT # I NO SER # G-77 PACKER 7" 22·26# 2,98 2,35 500 3 1/2 EUE X 2 7/8 EUE 101165097 CROSSOVER 3 1/2 EUE B X 2 7/8 EUE P 2.441 2.35 500 EUE-MOD B 2 7/8 EUE P NO PT # / NO SER # PUP JOINT 2718 N-80 6.5 # 2.441 2.35 500 2 7/8 EUE-MOD 8 RD NO PT # / NO SER # TOTAL lENGTH G-77 PACKER # 4 ASSEMBLY PUP JOINT 2 718 N-80 6.5 # 4.7 3,668 2.441 2.35 500 27/8 EUE-MOD 8 RD NO PT # I NO SER # ---------._- ---- --- CROSS OVER 2 7/8 EUE BOX X 3 1/2 EUE PIN 3,76 2.441 2.35 500 2 7/8 EUE-MOD X 3 1/2 EUE NO PT # / NO SER # G-77 PACKER 7" 22-26# 6.1 6,02 3 1/2 EUE 101165097 CROSSOVER 3 1/2 EUE BOX X 2718 EUE PIN 0.81 500 3 1/2 EUE X 2 7/8 EUE-MOD NO PT # / NO SER # . -- ---- ---- __·..._._··.n.___...__ PUP JOINT 2 7/8 N-80 6.5 # 6.18 3.668 500 2 7/8 EUE-MOD RD NO PT # / NO SER # TOTAL lENGTH 18.57 --------- SLIDING SLEEVE ASSEMBLY # 1 PUP JOINT 2 7/8 N-SO 6.5 # 2.875 3.668 2.441 27/8 RD NO PT # / NO SER # SSD 2.31 2718 EUE 6.5 # 3.53 3,92 2,313 2,21 3000 2 7/8 EUE-MOD 8 RD 100159432 PUP JOINT 2 7/8 N-80 6.5 # 9.82 3.668 2.441 2.21 3000 2 7/8 EUE-MOD 8 RD NO PT # / NO SER # __'______m____ TOTAL lENGTH Page 5 of 11 I ! 6.2 i 3.668 1···;.~~1T- 2,21 i I . -- ----r- --- 3.99 __I -- 3,92 i- 2:3J 3m f 2.21~n____ 4.17 3,668 I 2.441 I 2.21 5000 14.3611 :- j -- -1- --- -1- ni I---~ -1---- -T- ! 3.668 2.441 _I 2.21 ¡ i I i _3.~2_ _1_~::313_ ¡ 2.21_1 i 3,668 1_2,~4,1m '- 2,21 L -I l : ! i L J-- __ .j-__ i_ I ! I 1 ----- ---I _n ----- ---.-- -I ---- -- -- ---t---- ::~~ 1-;~;~;=t_~~9~i=-l--i30r_I_~ -- ~: 6.05 3,9_1_?'~~_ J 2.805 I NA , í : I 14.44 -- ~..._n - i-- ---I I -1 1- II Inn --l .. --j----- - _ - ~_ ._ _.__..1_______ ,__ __._ ,________ ____ I I, I i - ¡--+---- +- I _1..__ -L _j_ J ICU~TºME:~º~~~I . ---4- -1---- 1 4 i- §-875 i4 n _L?.8? _ I NA! 43/8-8 -Cn 4.49 f-.?:º-3?-r~---~ ,··f --.?:?~--i--- ~~___L __ 4_3/?.-_8._~ 0.58nl_~·º31__4 I 2.85 _1____~.A.___L_n__4..3/§.:..8_X_~1/?~UEP _~6.º_~_ _ : 4.25 2.9921 2.851___1\1_11.___)___ 3 1/2_EOUE B X P 15.12 I I AURORA GAS DESCRIPTION WELL: NIKOLl CR#1B LENGTH I O,D, 1.0. i AFE: NCU-1B-W06 DRIFT I TEST PSI ! -I -~ I i nt --- -- t --..\ "-i-'- 3.668 I. 2.44..1 1 2.21 - ¡n __ , 3.92 i 2.;313 J 2.21 l 3.6~8! __ 2.4'!1_J 2.21 \ 'i j -- I n¡ 1 I __ ---1-- _____ ___n \ ------- ---- ---._- SLIDING SLEEVE ASSEMBLY # 2 PUPJOIN!. 2 7/8 EUE 6.5 # SSD 2.31, 2 7/8 EUE PUP JOINT, 2 7/8 EUE 6.5 # TOTAL lENGTH - -. -¡-- - L__ i -! 5000 - --..,._..._._~-~_.._-- - -- " 5000 i ----I 5000 - - - __1__ 8.31 3.96 2.3 14.57 SLIDING SLEEVE ASSEMBLY # 3 PUP JOINT, 2 7/8 EUE 6.5 # SSD 2.31, 2 7/8 EUE PUP JOINT, 2 7/8 EUE 6.5 # TOTAL lENGTH SLIDING SLEEVE ASSEMBLY # 4 PUP.Jº~NT, 2 7/S EUE 6.5 # SSD 2.31, 2 7/8 EUE PUP JOINT, 2 7/8 EUE 6.5 # TOTAL lENGTH S.26 4 2.27 16.225 5000 5000 5000 ON I OFF TOOL ASSY PUP JOINT 3112 N-80 6.5 # º~-º¡:FTl,XL,7 X 3 1/2,2.750 X PF PUP JOINT 3 1/2 N-80 6.5 # TOTAL lENGTH --I ---I -- ---,--- i-- -- 1 PERMANENT PACKER ASSEMBLY 7" BWD PACKER SEAL BORE EXTENSION CROSSOVER 4 3/8 8 X 3 1/2 EUE PUP_J91\'}", 3 1/2 EUE 9.2 lB TOTAL lENGTH ---'--------,---- Page 6 of 11 THREADS RIG: I I I 2718 EUE-MOD 8 RD ___ _____ __ ___ _n_ ____ __. 2 7/8 EUE-MOD 8 RD -,---- '--..- - 2718 EUE-MOD 8 RD ~ 2718 EUE-MOD 8 RD 2 7/8 EUE-MOD 8 RD -- -- --- ---'.......---- 2 7/8 EUE-MOD 8 RD 2 7/8 EUE-MOD 8 RD 27/8 EUE-MOD 8 RD 2718 EUE-MOD 8 RD 3 1/2 EUE-MOD 8 RD 3 1/2 EUE 8 RD 3 1/2 EUE-MOD 8 RD - ----,----..--- AURORA WELL SVC#1 PART NUMBER / SERIAL NUMBER NO PT # / NO SER # 100159432 NO PT # I NO SER # NO PT # I NO SER # 100159432 NO PT # I NO SER # . NO PT # / NO SER # 100159432 NO PT # I NO SER # NO PT # I NO SER # 101268250 NO PT # / NO SER # . 101009275 120053135 100006911 NO PT # / NO SER # AURORA GAS WELL: NIKOLl CR#1B AFE: NCU-1B-W06 RIG: AURORA WELL SVC#1 DESCRIPTION LENGTH 0.0. TEST PSI THREADS PART NUMBER 1 SERIAL NUMBER SEAL ASSEMBLY PUP JOINT, 3 1/2 EUE 9.2 lB NA 3 1/2 EUE B X P NO PT # 1 NO SER # ---- - ----- SRAIGHT SLOT lOCATOR NA 3112 EUB X 312 NU P 100008599 SEAL UNIT EXTENSION NA 3 1/2 NU B X P 100008608 SEAL UNIT 4" NA 31/2NUBXP 100007212 SEAL UNIT EXTENSION NA 3 1/2 NU B X P 100008608 -'- ---- SEAL UNIT 4" NA 3 1/2 NU B X P 100007212 SEAL UNIT 4" NA 3 NU B X P 100007212 MULE SHOE NA 100007025 . TOTAL lENGTH X lANDING NIPPLE ASSEMBLY CROSSOVER, 3 1/2 EUB X 2 7/8 EUP 0.82 2,21 5000 3 1/2 EUE B X 2718 EUE P NO PT # I NO SER # X NIPPLE 1.21 2,21 5000 2 7/8 EUE B X P 100005672 CROSSOVER, 2 7/8 EUB X 3 1/2 EUP 0.64 5000 2718 EUE B X 3 1/2 EUE P NO PT # I NO SER # TOTAL lENGTH 2.67 --- - -1- 2 7/S" XNIPPlE NA 2 7/8 EUE B X P 100005672 ON OFF TOOl,2 7/8 CUSTOMER OWNED 2.313 2,21 NA 2 7/8 EUE B X P 55665 CROSSOVER, 2 7/8 EUEB X 3 1/2 EUP 0.81 3,76 NA 2 7/8 EUE B X 3 1/2 EUE P NO PT # NO SER # . 7" 22-26# HES VTA PACKER 6.3 5,99 3112 EUE 101034735 -- . ----.----,--- Page 7 of 11 AURORA GAS DESCRIPTION WELL: NIKOLl CR#1B LENGTH! O.D. I 1.0. SEAL ASSEMBLY, VTA PACKER STRAIGHT SLOT lOCATOR MOLDED SEAL UNIT MOLDED SEAL UNIT MOLDED SEAL UNIT MULE SHOE GUIDE ; 1.39 -¡- InO.9~ 1.01 1.00 0.53 I I I --t- I i I ì 4.46 1- , 2.992 \ -- T--i i__2-,ª~J I 2,992 I I 2.992 i 3,88 3.88 3,88 i 2.992 i-- I AFE: NCU-1B-W06 DRIFT I TEST PSI \ 2,35 2.35 2.35 2,35 In 2,35 .~ __ I- I RIG: THREADS I 1500 1500 ----._-.._--- 1500 1500 I 31/2 EUE B X 31/2 12NU PIN ------------...-.- 31/212NU 31/212NU 31/212NU 31/2 12NU BOX AURORA WELL SVC#1 PART NUMBER I SERIAL NUMBER 101015603 100007211 100007211 100007211 100007024 MEASURED BY: DATE: RECEIVED BY: SALES ORDER NO.: PHONE NO. RICHARD PIKE 6/19/2006 4456711 260-3246 . ¡ I , --t I i Page 8 of 11 1-- i- . . . FRANK H. MURKOWSKI, GOVERNOR AI,ASIiA. ORAND GAS CONSERVATION COMMISSION 333 W. 7'H AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Bruce D. Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC 2500 City West Blvd., Suite 2500 Houston, TX 77042 Re: Nicolai Creek Field, Nicolai Creek South Undefined Gas Pool, Nicolai Creek #1 B Sundry Number: 306-354 lie Dear Mr. Webb: 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. " DATED this ßday of November, 2006 Encl. QtQ-f~~ · . ~lAulOra Gas, LLC www.aurorapower.com October 30, 2006 John K. Norman, Chairman State of Alaska Oil and Gas Conservation Commission 333 W. ih Avenue, Suite 100 Anchorage, AK 99501 RE' '·C.., E'.\!F .1 \i """ OCl :} 0 2 Alaska Oil 8¡ Re: Application for Sundry Approval Nicolai Creek Unit #lB Well Production from Additional Intervals (2,307'-2,370' and 2,480'-2,622' MD) Dear Mr. Norman: Aurora Gas, LLC (Aurora) hereby requests approval to allow production from certain stratigraphic intervals for the Nicolai Creek Unit No. 1B well in the Nicolai Creek gas field on the west side of the Cook Inlet. Attached are Applications for Sundry Approval for the two intervals referenced above. Specifically, Aurora seeks permission to open the sliding sleeve at 2,375' MD directly above the packer at 2,440' MD to allow production from the Carya 2-1.2 perforations at 2,307' to 2,326' MD and 2,350' to 2,370' MD; as well as the sliding sleeve at 2,742' MD directly above the packer at 2,765' MD to allow production from the Carya 2-2.1 and Carya 2-2.2 perforations at 2,480' to 2,486' MD and 2,604' to 2,622' MD, respectively. The Carya 2-1.2 and Carya 2-2.1 sands are also producing from the Nicolai Creek Unit No.2 well. However, pressure obtained following the perforating of these sands indicate that they are not in direct communication with the same sands in the #2 well, i.e., the / pressure found in the #lB well upon perforating is much higher than concurrent pressure in the #2 well. While we intend to continue producing from the lower two completions of the #lB well, now open, for some time; when it becomes necessary to open the upper sleeves and start producing from the upper two completions, we would like the ability to do so. Although the Sundry Applications indicate an estimated date for commencing operations as December 1, 2006, Aurora seeks the ability to open or close these completions, at its sole discretion, as necessary for production, at any time after December 1, 2006. 10333 Richmond Avenue, Suite 710· Houston, Texas 77042· (713) 977-5799· Fax (713) 977-1347 1400 West Benson Blvd., Suite 410. Anchorage, Alaska 99503· (907) 277-1003· Fax (907) 277-1006 . . Mr. John Norman AOGCC October 30, 2006 Page 2 Accompanying the Sundry Applications is supporting well and engineering data, which include well completion diagrams, well test results and Nicolai Creek log correlations. Should questions arise in connection with this request, please contact Mr. Ed Jones in the Houston office at (713) 977-5799. Respectfully Submitted By, ---¿ U~ Bruce D. Webb Manager, Land and Regulatory Affairs attachments 1. Type of Request: Abandon 0 Suspend 0 Operational shutdown 0 Perforate 0 Alask'å' !1Ws:g as Có?ftlffi~ n- Alter casing 0 Repair well 0 Plug Perforations 0 Stimulate 0 Time Extension ~, ;"age -..N ",C¡.uí - Change approved program 0 Pull Tubing 0 Perforate New Pool 0 Re-enter Suspended Well 0 ~ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: '" AURORA GAS, LLC Development 0 Exploratory 0 202162 - 3. Address: Stratigraphic 0 Service 0 6. API Number: 2500 City West Blvd., Suite 2500, Houston, TX 77042 50-283-10020-02-00 - 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes 0 No 0 Nicolai Creek Unit # 18 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ß 1". 7'~ State of Alaska Lease ADL 17585 - 35.5' AMSL (DF) Nicolai Creek ~"u.l-Å. tLlA.ck£ <74~ "'- 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 3,672' - 3,618' p 3,600' 3,510' none none Casing Length Size MD TVD Burst Collapse Structural Conductor 232' 20" 232' 232' n/a n/a Surface 1,904' 13·3/8" 1,904' 1,904' 1,530 psi 520 psi Intermediate 2,186' 10·3/4" 2,186' 2,186' 3,580 psi 1 ,580 psi Production 3,648' 7" 3,648' 3,584' 3,740 psi 3,270 psi Liner Perforation Depth MD (ft): perfOration Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 2,480' ·2,622' 2,426' - 2,568' 2-7/8" 6.5 #, J·55 3,112' Packers and SSSV Type: Baker G-77 Packer, no SSV Packers and SSSV MD (ft): Packer at 2,765' MD 13. Attachments: Description Summary of Proposal 0 14. Well Class after proposed work: -- Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Development 0, Service 0 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: December 1, 2006 Oil 0 Gas 0 Plugged 0 Abandoned 0 17. Verbal Approval: Date: WAG 0 GINJ 0 WINJ 0 WDSPL 0 Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact J. Edward Jones (713) 977-5799 Printed Name Bruce D. Webb, Manager, Land and Regulatory Affairs Title Vice President, Engineering and Oper. Signature ~l~~ Date ID/3c)/OCe> COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 30b - 3S'f Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: #// c?'J1d,k~ ðf Co 4r8A,tJll<ehtð,/'n ÎJJ ¡:a¡/ -, H;Za~ ~ eHt:cI _ ~ Subsequent Form Required: '-\()~ "---~\C(!L~<"\~O\,~ ~\' '~C~\ ~Jh APPROVED BY //-5,06 Approved by: /....·vl C~SIONER THE COMMISSION Date: """" '""<.../ - .d/·7·~ - . STATE OF ALASKA 1J11,~;ðÞ t RE'C' E-'IV'E'.'D- ALA OILANDGASCONSERVATION'é'åfv1 N ~ j -- ~ APPLICATION FOR SUNDRY APPR ALS H~ 0 CT 3 0 Z006 20 AAC 25.280 " · '¡:::::, - Form 10 403 Revised 06/2006 OR \ G\ NA!DMSBFl 1 () 2006 ~;;;; 2-7/8.. 6.5 # J-55 tbg to surface 13 3/8" 54# J-55 Surface Csg at 1,904'. Cmtd to surface wI 1,530 sx "G". Carya 2-1.2 Perfs: 2,307' - 2,326' MD 2,350' - 2,370' MD (TVD 2,254' - 2,316') Carya 2-2.1 Perfs: 2,480' - 2,486' MD (TVD 2,426' - 2,434') Carya 2-2.2 Perfs: 2,604' - 2,622' MD (TVD 2,550' - 2,568') Carya 2-3 Perfs: 2,837' - 2,842' MD 2,862' 2,867' MD 2,913'-2,918'MD (TVD 2,783' - 2,864') Carya 2-4.2 Perfs: 3,191' -3,211' MD (TVD 3,137' - 3,157') Carya 2-5.1 Perfs: 3,371' - 3,401' MD (TVD 3,307' - 3,348') Carya 2-6.1 Perfs: 3,560' - 3,575' MD (TVD 3,506' - 3,521') Float collar @ 3,604' MD Float shoe @ 3,648' MD TD @ 3,672' MD (3,617' TVD) Aurora Gas, LLC Nicolai Creek Unit No. I-B Current Configuration (6/26/06) Dritled 26" Hole 20" 94# H-40 Conductor set at 232', Cmtd to surface w/300 sx "G". Drilled 17 1/2" Hole Sliding Sleeve wI X-profile @ 2,268' G-77 Packer @ 2,280' (Closed) Sliding Sleeve wI X-profile @ 2,375' G-77 Packer @ 2,440' (Closed) Sliding Sleeve wI X-protïle @ 2,742' G-77 Packer @ 2,765' X-nipple @ 2,775' (Closed) VTA Packer @ 3,145' XN Nipple @ 3,184' Wet! completed with sand exclusion screens across the indicated perforations. Cement Retainer @ 3,500' 7" 23# J-55 Production Csg @ 3,650'MD (3,595' TVD). Cmtd to surface wI 82 bbls "G" lead at 12.5 ppg and 67 bbls "G" tail at 15.8 ppg. J:'~in^,,O.~thQ.r I=R.D ~t:\.n/i"'Qc In,... I I Ana rrCoclr f\Jn 1 Rc\/ 1 n 7/~1/?()()R \M IP nr~n^,inr'1 hint Tn _~"'-;:J,IQ AURORA GAS, LLC NICOLAI CREEK UNIT NO.1B WELL TEST RESULTS SUMMARY--JUNE 2006 WORKOVER DATE INTERVAL (MD) DATUM MCFPD FTP SITP of PKR PLUG (mid perf) (Calc BHP) 6126/2006 TEST TOP PERF BTM PERI TVDss psig psig COMMENTS SAND STATUS AFTER PERFORATING W/ RBP AND PKR 6/15-17/2006 3150 3500 140 280 1200 W/2-3 BWPH Carya 2-4 & 2.5 OPEN . 3191 3401 -3297 [1283] 2002 perfs Water in well bore? 6/18-19/2006 2816 3150 260 420 1260 new perfs: Carya 2-3 2837 2918 -2788 [1350] OPEN 6/20/2006 2457 3155 556 556 1140 new perfs Carya 2-3 & 2-2 Isolated by Pius & Sldg Slvs 2480 2913 some open in NCU #2 6/22/2006 2295 2468 1405 820 1000 new perfs Carya 2-1 Isolated by Pkrs & Sldg Slvs 2307 2370 -2250 [1040] open in NCU #2 AFTER RUNNING COMPLETION PACKERS, SCREENS, AND SLEEVES 6/27/2006 2761 3500 420 350 1200 commingled old Carya 2-3 to 2-6 OPEN 2837 3401 -3033 [1276] + some new (all unique to NCU 1 B) 6/28/2006 2436 2761 196 200 1000 new perfs Carya 2-2.1 & 2-2.2 Isolated by Pkrs & Sldg Slvs 2480 2622 -2462 [1045] (the 2-2.1 is open in #2) 6/28/2006 2275 2438 914 590 1000 new perfs Carya 2-1.2 Isoiated by Pkrs & Sldg Slvs 2307 2370 -2250 [1040] (common to NCU 2) . KB Elev= 35.5' Nicolai Creek No.2 Nicolai Creek Field Alaska Production D Proposed ŒJ Current 133/8" 54.5# @ 1934' CMT'D W11600 SX 36" Hole Attachment I 26" Hoie 20" 94# @ 286' CMT'D to surface WI 650 SX 5 SPF @ 298' Squeezed wi 200 sx in 1991 17 1/2" Hole 5 SPF @ 677' Squeezed w/215 sx in 1991 TOC @ -1900' MD In 13 3/8" X 7" annulus 2.313" ID X-Nipple at 2288.8' Permanent Packer at 2327' 5" Meshrite Screen Pe ITorate @ 5 SPF 2426' - 2476' Perforate @ 5 SPF 2700' - 2716' 97/8" Hole Perforate @ 5 SPF 2893' to 2916' Original production perforations 41/2 SPF from 3270' to 3315' cemented over during 1991 Suspension Procedure -- 7" 26# @ 3585' M D CMT'D W/1400 SX 87 Sk Class "G" Cement Plug 3102' - 3537' Plug (Baffle Plate) @ 3543' MD TO @ 5011' MD 4086' TVD DRAWING NOT TO SCALE NICOLAI CREEK NO.2 FAIRWEATHER E&P Rev. 01 I DHV 05-Sept-02 SERVICES INC I 2 ( '. ~''',", ·..··········..·1 -<~. ~"'~~~=-_......, -2800 - "i- ~:::-.... I -2900 - ~ \~ r -3000 - r; r"'- \ ': 1 -3100 ¡ I ),~.- .\rt--------- i ~~ <'"^ -3300 - ,~. J> ~ ~, ~ ~:::::::. I CARYA 2-3 -2900 -I §......:;.~~'" <';:~""n11T_' I -3000 -I F~ \.c:> ¿ -31 00 -I ~ ;=-" -3200 -I J l c~· -3300 -I L.;~;.,,_ ~ ........... t~·_···..·· .' ~ ~::~~. L -<ç T.-- ~=.:.~~~ 5'/="""'" ."., t:,~.. ) ~ .; I, {~' \- ~~. \..m....-'-'-!.!. -2800 - ... ~ CARYA 2-2.3 -2700 - -1900 -2300 -2400 -2500 - ] 1-2600 - "È:" ~..." CARYA 2-2.2 -?: ~':'::':a" .:.... ~,.. ~. ¡:==.. f ~ -....-' 7- .J.JII.- ..~ - CARYA 2-2.1 CARYA 2-1.2 ====~~.~...~.,~...'......:....··,··ì~,·-..,.=·~-1t~~~-jlt,=-~t--~:~::~:t_: -2100 -.¿' £;;;:.:=- ( --- -- --1c~-::::---~~:.~c--- --I TOP TYONEK (CARYA 2-1) CARYA 2-1.1 OT ILD SP DT ILD SP DT ILD EAST TEXACO NICOLAI CREEK UNIT -2 TEXACO NICOLAI CREEK UNIT -6 AURORA GAS NICOLAI CREEK UNIT-1S TEXACO NICOLAI CREEK UNIT-1A STRUCTURAL SECTION -3300 ( 1-2900 -I }~- -3000 - <; '7.: \. (~::~ ..-..-...----.... .,'1 ~ -3200 j.,'.',',','.'.',"""""'" ,····,·····'·1 -2900 1 -3000 ..'",'..'" '" I -;nuu ..'. ~ ) I -2000 ---- ---- - I -- I -2100 I ')')00 L~ :,.'.:.;.:,:,'.'.:.' ,',.,'.'.....~.~''Vv ~----------[ -2300 ~ 1 -2400 ~ ~ D:~:: ~ j 1 -2800 .{ -2700 .. '-t- -2800 ' '".. d, ~ :....JWi' ~ I -1900 1- 1 -2000 - 5 1 -2100 } ,-..uu ~ 1 -2300 f~ 11 -2400 ~ I -nuu - {' -2600 /p::= ~~::,..~ DT ':-"'=:~'....:; SP ILD SP . \" I I ) '2 2100 - .~;;,"'."..;.-' . \ ... -:::::::---- ~:..,,-""" ( .::>. I::'" ~ ..?iI:. ,i' 2100 _ ~"I 2100 J;' I ,.,...'..., 2300 TOP TYONEK ?'YJ" 2200(':-:>"! ). -----\1 --.------~--'- ,~' --~,- : ,~:'= :0"" (CARYA 2-1) J.::".__...... " '). 2200 _ .-- 2200 c.,;;' -----. n :'400" Ç.~,- ?';'........""..._. "',"",,"" ~ \¡' , ,n ' "'Ç' .w. 5:-= i -..- ;.-- I.> CARYA 2-1.1 r, > :r; -., <ow - ,-- ~ - 2300 f,c __ " , 2500 "'S;: 2400 ¿~~..._ .{ ) ~ \ - -----~-- 2400 c,_ '< Y', ". C-- -------- 2400 _ I----~ Ç==- 2600 :~=-. \ ~~. _.. "'0 _ '" ~~' . __,.n... J ." "~'25ÓÔ 1!;=- ..'''':i I~ ' 2500 _ "".",' ~ :? 5 1)1) !;"",_..-' ~_un.. t 2700 3~"",,,-...,:: CARYA 2-1.2 ~ ./ ~...........¡ { f:'~:::::·::·,,"- ,':' }~ ~ . 1 JK .,,'!:.. r- ....,........ ...., ......... 2600 ,. t 2 i: "1- '0::-::'::::;"_-" _ ~:> ~ Of ~ 800 -=.:j J ~",,:..... ~ ,~ ì ,?~;~.~'~'"};, l ?;:__ :1~' \ 2700 - ¡,.e- - _ - 2700 ,~-'- __________? 2900 ,~~ c- CARYA 2-2_' L 2800 ¡ í ,. ~ - ¿ -t -=::, t..í .r-' 2800 -....... ---I·-"--I--·""3"omr-,- " .. ~ ¿~:::;,._.~i:' ~ ,"'vv ~_} ~ ,:;' CARYA 2-2.2 2900 ~,.. J '.,,,,, ~;'" ? :::í ~;:: _ }. 2900 - "", ..................,. ..~.,...,... 2~UU ,_...~=- "" 3100 - F= "'.,.,.,"..""....J '..'" < ~'~. ~ .~(~,,,........._.... ;:~ 3000 <.or _. ~ ~ "\... ¡ 3000 _ ~ 3000""·' 3200-¡ 3100 _ t-' " <, F; )' ,~ :=,,'- ? ;~ _ L 3100 -r 3100 " .- 3300 t I CARYA 2-2_' J 3200 > -=- > ~- /' -;'" <¡ r- -------- --' -e---------'-h2tJ<r - . 3200' c 3400!.. -.::~ ¿ 3300 I " { t:- j'E~ ¡~ -.; ~ "00 _I '~_ "',-, , , ' ._C 3300- r;= _ ) '\ oouu þ_ ~ : 3500 ~ { CARYA 2-' '" 1,--. ¿' I '400 I ' I ç 3400 _,_ ~ ¡. 3600 -I .~,,:,;¡ S1 ,~TIGRAPHIC SECTION, DATUMED ON TOP TYONEK FORMATION AURORA GAS TEXACO 7 NICOLAI CREEK < 3240 FEET > NICOLAI CREEK < 2024 FEET UNIT-1S UNIT-6 DT ILD SP DT ILD SP DT ILD EAST TEXACO 7 NICOLAI CREEK UNIT -2 SP DT ILD SP 2217 FEET TEXACO NICOLAI CREEK ~ UNIT-1A ) CARYA 2-5.1 CARYA 2-4.2 L5 lJ} cc ::) lJ} ~ w o ð ~ w > w ::) c£ t- t- w ~ WEST CARYA 2-5.1 CARYA 2-4.2 GJ w u.. ~- w o o ~ ::) ~ ¿ WEST ¿¡ ?,,' :;:. I TEXACO / ·""3 '14UU '.,,',' "- -~-~~-_._--------- ,;; -;?:~". " :OLAI CREEK ':;j r- :: SOUTH UNIT -5 ¿ ,." -1500 t~ë=~ ":0-" ' "".'.. STRUCTURAL SECTION -= ::~ ILD DT ..:: . ...,...' -1600 ...... ~ I ) ~ ~ "=;,~:.:;.,,,,,,- "'r,? AURORA GAS TEXACO ~ -1700 ~~:;:!O-. 'r f -1700 i~;;"""· """-"" ~ s,~~S ~..... NICOLAI CREEK NICOLAI CREEK \ ¿ -1800 - ( -1800 ""~ UNIT-1B UNIT - 2 ) (:;:".~.."'.,~.. { ? f- ~f: ···................=::1 >- ;~. ? ~..... SP ILD DT ~, SP ILD DT -1.:.O\l~' ');" "$ -1900 1< I -1900 -I . ,~ . . I I ,::" \ ")nnn ¡ ¡--.., "'-'i f.:~- -' ;~:". TOP TYONEK -2000 ";,:.;;"" .'" 1 -2000 ."",.......,.......,.............................,,, (CARYA 2-1) ~, (:'<" ...,.." ~ ,~:::~- \ -2000 ,~::,_ -.?, ¡ <:; "-.-.. -'-'- { r¿-:-- i""'" ... CARYA 2-1.1 ;:¡ -2100 - -·I:~ ~ ' .. ·Š·· -. ': ~'21 cia .. ··C" .-. """ ..,; -. ','" 1--.... . ...'..,.. -2100 -2100 "'M'''''"~ ~ ~ ~ ,,:::'7.,: " ,.,' ) ,~~~. \; 5 j ......nn .'.:,. .: ?'" n "'.~ c .,~ .._--~ :'( -2200 --i--J:::~ ", ,',,',',', ..,..,n..... '.',,',',,',",', ",.,' :> ~.,. -e} i. ... ~._~._-- -...,......... ~=-- CARYA 2-1.2 n <-;:. r~"""""-" c\ " ¡: < :... '" -;¿3UU \ ,'.' " ",. .', -2300 -2300 - u J { Em .. \ :) ~;=.,,-- 'c'" ~ ..., \ ~ { ~ "'~> \ -- ~ ., ....................,................. ...-..... .' -2400 - -2400 ;;. - ¡-..'.w / -2400 ~ .;' ~ -2400 - ,~?~. .::{ CARYA 2-2.1 ¡3 ~ \ ,'.. > ;. :':-- ~- :; JJ ì ;~ .' < :> .', -2500 - ..', .,.,..".'""".."" -2500 ~.tt' ~, ~ J::::=- ....,r CARYA 2-2.2 :: t¡;,:;:: ) l~ -.:..¡.,¡vv -'" ~< -2500 - ~ "'-, ~..s . J. 5~;:' :::::::.".,- Ì ~....~. ): "\ >~,.=,_. '," : 1'\ .... -2600 ~ ....:~ -2600 - ) -2600 ,.', ,.., .- -2600 - < -< ~: ç ^' / J r··..-'..--....."....·..···...... f 1 } ;--:..:.:.:':::='"'' " " , ..,.-: ..' ~< ¡. -2700 - ¡ -2700 \,;,.~~ '" ~ -.:../VY ~:~ -270U - t~~ : (. ( r , ",.~~~l I 'l J ~=- " , '(...... -;¿ClUU J } -2800 ~,... :~. .. ...',.... -2800 '(~ .\ "'" ( ( ~ ",..", _J ~ < ~ , C .....--_...... .;;> :...;,-.--..-....... } -2900 .~=~:::~.. ~':::;- -2900 - .'=- ¿ .~ '<; -2900 - :Ç:~~' ;."....=0""'''''"... ? ') ~ .J 1 í " ~ -'-"1-!l ,'''1 " ')nnn ........n..... i·n' .. .. .Ç' "-"~ .~IJ\ d ../ ~ -3000 - ¡ t· - ) ~ ~\ ;, "'" ~!,;~"1~7 ;:. ì i >.~,......~",.".."".. < 1_, Jt.'fJ I ~ 1'-..... " " CARYA 2-3 DT ILD SP DT TEXACO NICOLAI CREEK UNIT -3 ILD SP ~~_____~____.__~____.~~_____,______~______._______n~~~____ 3600 3500 CARYA 2-2.3 CARYA 2-2.2 CARYA 2-2.1 2700 CARYA 2-1.2 2600 2500 CARYA 2-1.1 ..~1:00 ~...~....~Wo'o.....~'.... TOP TYONEK (CARYA 2-1) 2100 - I I. . I. . I .' I , 2300- DT C' I. SP ILD DT DT ILD SP ILD SP SOUTH TEXACO 7 NICOLAI CREEK UNIT -2 S\ lTIGRAPHIC SECTION, DATUMED ON TOP TYONEK FORMATION TEXACO AURORA GAS 7 NICOLAI CREEK < 6769 FEET > NICOLAI CREEK < 2688 FEET UNIT-3 UNIT-1B TEXACO NICOLAI CREEK ~ UNIT -5 3016 FEET ) NORTH ~ t' W C C ~ :::> ~ ::;: NORTH File Nicolai (202-162) Sundry Application 306-354 Aurora Gas, LLC shallow .2, Carya 3,000' of sands that are requests to at their discretion, to regular Carya 2-2.2 sands within well NCD to gas production NCD 2. Recommendation Aurora's request. resources will if approval is Regulatory History Conservation Order No, exception to purpose drilling NCD 2 well. Aurora's subject to 2003. Subsequently, Aurora On 5, 2006, authorization to work over NCD Carya sand On of NCD 1 B could not be Index Map: Nicolai Soutb Participating Area to IB on 1, 2006, that noted requirements to be the would from NCD lB. Aurora subsequently met those conditions. NCU lB: Note to File November 8, 2006 502831002002 502831002100 709ft AURORA NICOLAI CK UNIT 113 1999 FSL 186 FWL TWP: 11 N Range: 12 W - Sec. 29 AURORA NICOLAI CK UNIT 2 1999 FSL 209 FWL TWP: 11 N - Range 12 W - Sec. 29 500 o -500 -1000 -1500 -2000 -2500 Unit Southern Participating Area Cross NCD lB to NCD 2 2 -1000 -2500 NCU IB: Ndteto File November 8, 2006 . . Page 3 of3 On October 5, 2006, Aurora requested an administrative amendment from the Commission to allow regular gas production from the NCU 1B, NCU 2 and NCU 9 wells. Administrative Approval No. CO 478A.01, issued October 27, 2006, noted Aurora's shortcomings with respect to CO 478A, and listed Aurora's actions and submittals to remedy those shortcomings. CO 478A.01 also discussed letters from the affected landowners and surface owners (BLM / DNR, and DNR / Trust Land Office, respectively) acknowledging awareness that some intervals perforated within NCU 1B lie outside of the existing Southern Participating Area and consenting to regular production from the well. Aurora is the sole owner and operator of the NCU and all affected leases. Technical Justification Perforations in the Carya 2-1.2, Carya 2-2.1 and Carya 2-2.2 intervals within NCU 1B and NCU 2 lie between 900' and 1,100' apart. All of these perforations lie inside the current map boundaries of the Nicolai Creek Unit Southern Participating Area (see Index Map, above). Perforations within the Carya 2- 2.2 interval lie beneath the vertical section of the Southern Participating Area as currently defined by the DNR (see Cross Section, above). Exclusion of the Carya 2-2.2 interval from the vertical extent of the Southern Participating Area was apparently a clerical error on the part of the DNR. To correct this, Aurora submitted an application to stratigraphically expand the Participating Area to the DNR on July 28, 2006. No decision has been issued. Pressure measurements obtained after perforating the Carya 2-1.2, Carya 2-2.1 and Carya 2-2.2 intervals in NCU 1B (1,040 to 1,045 psig 1) are much higher than current pressure measurements in correlative sands that are producing in NCU 2 (221 psig as of Feb. 17,20062). Accordingly, the Carya 2-1.2, Carya 2-2.1 and Carya 2-2.2 sands are not in direct communication between these two wells. If approval is not granted to open these Carya intervals to production in NCU 1B, gas trapped in these sands near NCU 1B will likely not be produced, and waste will occur. BLM, DNR and TLO, the affected landowners and surface owners, provided letters of consent to the Commission supporting regular production from NCU lB. BLM, DNR and TLO are aware of the close spacing ofthe perforations in the NCU 1B and NCU 2 wells. They are also aware that the Carya 2-2.2 perforations within NCU 1B lie outside of existing Southern Participating Area. Conclusions CO 478, CO 478A and AA 478A.01 grant the necessary approvals to allow drilling, testing, and regular production from NCU 1B, NCU 2 and NCU 9. NCU 2 and NCU 9 have been on regular gas production since December 2003. BLM, DNR and TLO have consented to regular production from NCU lB. The Carya 2-1.2, 2-1.1 and 2-2.2 perforations in NCU 1B and NCU 2 will lie within the boundaries of the Nicolai Creek Unit Southern Participating Area. These perforated zones in NCU 1B and NCU 2 are likely not in direct communication. A waste of gas resources may occur if Aurora's request to open the Carya 2-1.2, Carya 2-2.1 and Carya 2-2.2 perforations in NCU 1B is not approved. Regular gas production from these intervals in NCU 1B is based on sound engineering and geoscience principles and will prevent waste. It will not jeopardize correlative rights or increase risk of fluid ~. Steve Davies Sr. Petroleum Geologist November 8, 2006 I Aurora Gas, LLC, 2006, Well Test Results Summary - June 2006 Workover, an attachment to Aurora's Application for Sundry Approvals No. 306-354, received by the Commission on October 30, 2006. 2 Aurora Gas, LLC, 2006, Nicolai Creek Unit Wells No. lB,2 and 9 Reservoir Surveillance Report, received by the Commission on September 14,2006. Page 1 of 1 Maunder, Thomas E (DOA) From: Stephen Davies [steve_davies@admin.state.ak.us] Sent: Monday, August 28, 2006 3:01 PM To: Ed Jones Cc: 'Chad Helgeson ; 'Andy Clifford' Subject: Re: Follow-up NCU 1 B & LC 1 -~- t C1~. ~~~ Attachments: steve_davies.vcf .~ Ed, We have a few more i ~~®t~a concerning NCU 1B: 1. Concerning DNR's decision establishing the Southern and Beluga PAs at Nicolai Creek Unit, what were the reactions of BLM and other interested parties to the PA boundaries established by DNR? 2. Did BLM and other interested parties concur, acquiesce, or object to DNR's decision? 3. Did BLM comment on the Southern PA and its restriction to state land only? 4. Could you please describe Aurora's reporting of production and royalties to BLM and DNR? 5. Have these reports been made retroactive to the first day of production? 6. Are royalty payments being made as required by Conservation Order 478A? Thanks, Steve Davies Ed Jones wrote: Steve, Any word yet on the Nicolai Creek 1 B or Lone Creek 1, as to when we might be able to produce them? Please let us know when you get word or if there is any thing else needed. Thanks, Ed Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage f A *~;i~ ~ ~ 1. ~ ~'~ 1 ~ ~ ~ 2/ 14/2008 Page 1 of 2 • Maunder, Thomas E (DOA) From: Cammy Taylor [Camille_Taylor@law.state.ak.us] Sent: Monday, August 28, 2006 10:52 AM To: steve_davies@admin.state.ak.us Cc: dave_roby@admin.state.ak.us; tom_maunder@admin.state.ak.us Subject: [Fwd: Re: NCU 1 B: Notes to File] Steve, The 3 C's have rescheduled my meeting from 3 pm to 1 pm. Will you have a few minutes this afternoon I could talk with you some more about this? Thanks, Cammy »> Stephen Davies <steve_davies@admin.state.ak.us> 8/28/2006 9:18:46 AM »> Cammy, Aurora Gas would like to bring their Nicolai Creek Unit 1B well ("NCU 16") on production. There are complications. Would you mind winding you way through several sources that explain what's going on? Could you please give us you opinion as to whether a second spacing exception is needed to bring the well on production? Spacing exception 478A (htfp:Jjwww.aogcc.aiaska,gov/orders/co1co400_49/co478a.ht) allows regular production from NCU 1B along with two others IF several conclusions and conditions in the order were met. Some were not. My attached Note to File and the attached map were built as I worked my way through the order and events. The map is my best attempt to compiled from two separate map sources. You'll note that the grids and well courses don't overlay exactly due to either map stretch or possibly differen ces in map projection. The emails below reflect discussion amongst the West Team. Thanks for helping us sort this out. Steve Davies -------- Original Message -------- Subject:Re: NCU 1B: Notes to File Date:Mon, 21 Aug 2006 11:01:25 -0800 From:Dave Roby <c~ave_roby@admir~.state.ak.us> Organization:State of Alaska To:Thomas Maunder <tom_maunderC~admin.state,ak.us> CC:Stephen Davies <st~ve_davies c~ admin,state,ak._us> References: <44E65F5A.6000406~admin.state.ak.us> <44E9E055.3000208~admin.state.k.us> <44E9E12D,80004admin,state.ak.us> Additional Comments: 1) CO 478A does have the language to allow administrative changes. 2) Reading Aurora's response to the question of expanding the PA closer they appear to NOT have acted in good faith to expand the PA. They 2/ 14/2008 Page 2 of 2 i • state "With minor exceptions (about 5-acres total in the corners of three aliquots), this proposed PA of about 470 acres would have included all lands within 1500' of the take points of the productive sands in NCU 1B and NCU 2." Therefore, regardless of the actions that the DNR took to reduce the size of the PA the fact remains that Aurora, by their own admission, did not propose a PA in the first place that would meet the conditions CO 478A Rule 1. 3) CO 478A Rule 2 states that "Aurora shall keep the Commission timely informed in writing of the status of its proposed changes in the NCU and PA." Did they do this? I don't think that there is any problem with what Aurora wants to do, but since the did not attempt to fully comply with the original CO I don't know if is appropriate for us to administratively amend it. Dave Thomas Maunder wrote: > I agree. From the record, it appears that Aurora attempted to get the > PA set up appropriately but that DNR reduced the area. On doing the > spacing administratively, it will depend on if that rule is in the > prior orders. > Tom > Dave Roby wrote, On 8/21/2006 8:33 AM: » I concur. We should investigate whether or not we can provide the » spacing exception administratively since the affected parties have » previously commented on this issue. » Dave » Stephen Davies wrote: »> My thoughts are attached. »> I wil be back on Tuesday. »> »> Steve 2/ 14/2008 ~i # Maunder, Thomas E (DOA) From: Stephen Davies [steve_davies@admin.state.ak.us] Sent: Friday, August 18, 2006 4:46 PM To: Tom Maunder; David Roby Subject: NCU 1 B: Notes to File Attachments: 060818_2021620_NCU_1 B_Regular_Production_Note_to_File.doc; steve_davies.vcf i 1 060818_2021620_ steve_davies.vcf NCU_iB_Regular_ (379 B) My thoughts are attached. I wil be back on Tuesday. Steve 3 · . ~AulOra Gas, LLC www.aurorapower.com RE: Report of Sundry Well Operations Aurora Gas, LLC: Nicolai Creek Unit #lB (pTD ~:tØ) I?SCI2 -4 IV~D 44$.(: ú G 0 Ii Oil cf} 2 lOa ' Gas Co '6 4/Jcl¡, o/Js. C. Or8g, 011"}¡¡z . '8 'Ssio/J July 31, 2006 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Dear Commissioner Norman: Aurora Gas, LLC hereby submits its Report of Sundry Well Operation for the work performed in working over its Nicolai Creek Unit #lB gas production well in the Nicolai Creek Gas Field on the west side of Cook Inlet. Please fmd enclosed the following information for your files: 1) Form 10-404 Report of Sundry Well Operations 2) Workover Operations Summary 3) Well Test Summary 4) Wellbore Diagram (A copy of the Schlumberger Completion Log was previously provided to Mr. Steve Davies in person on July 24th). If you have any questions or require additional information, please contact me at (713) 977-5799 or Bill Penrose at Fairweather at 258-3446. Sincerely, AURORA GAS, LLC &~ J. dward Jones ice President, Eng enclosures c: Mr. Bill Penrose - Fairweather 10333 Richmond Avenue, Suite 710. Houston, Texas 77042. (713) 977-5799· Fax (713) 977-1347 1400 West Benson Blvd., Suite 410· Anchorage, Alaska 99503· (907) 277-1003· Fax (907) 277-1006 . STATE OF ALASKA . ALA OIL AND GAS CONSERVATION COM ION REPORT OF SUNDRY WELL OPERATIONS Representative Daily Average Production or Injection Data Gas-Met Water-Bbl Casing Pressure 550 26 wi sand 0 420· 48 some load 0 15. Well Class after work: ExploratoryO 16. Well Status after work: Oil 0 Gas 0, WAG 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. . 1. Operations Abandon Performed: Alter Casing 0 Change Approved Program 0 2. Operator Name: Repair Well Pull Tubing0 Operat. ShutdownO Aurora Gas, LLC 3. Address: 1400 W. Benson Blvd, Suite 410 Anchora e AK 99503 7. KB Elevation (ft): 35.5' AMSL DF 8. Property Designation: ADL 17585 11. Present Well Condition Summary: Total Depth measured 3,672 feet true vertical 3,618. feet Effective Depth measured 3,500 . feet true vertical 3,454 feet Casing Length Size Structural Conductor 232' 20" Surface 1,904' 13-3/8" Intermediate 2,186' 10-314" Production 3,648' 7" Liner Perforation depth: Measured depth: 2,307' - 3,575' True Vertical depth: 2,254' - 3,521' Tubing: (size, grade, and measured depth) Packers and SSSV (type and measured depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: 13. Oil-Bbl Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations o o N/A Attached Contact Bill Penrose 258-3446 Printed Name Form Plug Perforations Perforate New Pool 0 Perforate 0 4. Well Class Before Work: Development 0 ' StratigraphicO Stimulate Other WaiverO Time ExtensionO Re-enter Suspended WellO 5. Permit to Drill Number: ExploratoryO 202-162 ServiceD 6. API Number: 50-283-10020-02 9. Well Name and Number: Nicolai Creek Unit #1 B 10. FieldlPool(s): Plugs (measured) Junk (measured) Nicolai Creek eJ,,,, RECEIVED j1> ßo; 3500' NoneAUG 0 2 2006 Alaska Oil & Gas Cons Comm" . . /ss/on Anchorage MD TVD Burst Collapse 232' 232' N/A N/A 1,904' 1,904' 1,530 psi 520 psi 2,186' 2,186' 3,580 psi 1,580 psi 3,648' 3,595' 3,740 psi 3,270 psi 2-7/8" J-55 3,396' Weatherford 7" G-77 pkrs @ 2,280',2,440',2,765'. VTA pkr @ 3,145' N/A R.BDM,S B, Fl NQV.l.á..ZPD6 900l ~I ~ {ION 'l:JB SnutRI Tubing Pressure 1100 350 Development 0 Service 0 GINJ 0 WINJ 0 WDSPL Sundry Number or NIA if C.O. Exempt: 306-195 o Title Vice President, Engineering & Operations Phone Date Î/~I lab , .I ~ I/'S· Submit Original Only .ø. {~tb& 713-977-5799 "1~ . . OPERATIONS SUMMARY Aurora Gas, LLC NCU #IB June 3. 2006 Finish rigging up on well. Set BPV, NID tree, NIU BOPE. June 4. 2006 Finish NIU BOPE, pull BPV, install2-way check. Test BOPE and PVT system. June 5. 2006 Test BOPE. Found pressure under 2-way check. Could not bleed off. Close 2-way check, NID BOPE, NIU tree. Lubricate 2-way check out. RIU to pump down well. 700 psi on tbg, 200 psi on backside. Reverse kill, lost 10 bbls 9.8 ppg brine while pumping. SID, monitor pressure. Tbg pressure rose from 0 to 150 psi in ~ hr. Mix 18 bbls of 10.0 ppg brine. Bullhead down tbg at 1/3 bpm, 500 psi. Monitor SITP - fell to 100 psi. Bleed back 1-1/2 bbls - well dead. Bleed off gas bubble in annulus and replace volume with 10.0 ppg brine. Well dead. June 6. 2006 Set BPV, NID tree, NIU BOPE. Remove BPV, install2-way check. Test breaks per regs. Pu1l2-way check, CBU. BOLDS, POH wI seal assy. PIU packer picker, RIH, latch onto pkr. Took pit gain. S/I wI 150 psi on csg. Circulate out bubble. Stay on choke while evening out brine system at 9.8 ppg. Well still flowing, bring weight up to 9.9 ppg. June 7. 2006 Jar on pkr, would not come. Release from fish, POH for new BRA. PIU tubing anchor, RIH, latch onto pkr. RIH wI sinker bar, tag fill at 3,379' (10' into second screen). RIU to freepoint. Run freepoint, found pkr free wI movement to 3,283'. POH wI wireline and RID same. Unlatch from tbg anchor. June 8. 2006 Wait on 3-1/2" tbg from yard. POH, SIB 2-7/8" tbg. LID fishing tools, change rams to 3- 1/2", test to 250/3000 psi. RIH wI tbg anchor, latch pkr. RIH wI jet cutter on WL, make cut at 3,264' in middle of joint. RID WL and work fish. June 9.2006 Work fish loose. Pull 2 jts, CBU, POH wI fish. LID fish, MIU milling assy on tbg, RIH wI same. Mill on stub. June 10. 2006 Mill on stub, 8" total. POH, LID mill, MIU fishing assy, RIH. Latch onto fish and commence jarring. Fish came loose after 6 hrs jarring. Establish circulation. Gas . . breaking out, raise MW to 10.0 ppg. Commence POH. Well kicked - 5 bbl gain. SII, circ out through choke. June 11. 2006 Circulate kick out, CBU, no flow. POR, LID screens. LID DC's. RIB wI 6-1/8" bit. Well started flowing at 2,900'. SII and circ out gas bubble under choke. RIR to 3,300', CBU. Wash to 3,550', R/U to reverse. June 12. 2006 Reverse circ until clean. POR, LID 3-1/2" tbg. Change rams to 2-7/8". Test BOPE, annular element failed. Troubleshoot same. June 13. 2006 Repair and test annular - OK. RIB wI bit and scraper, tag sand at 3,538'. CBU long way, then reverse circ while filtering brine to 5 microns. POH w. bit and scraper, R/U shooting flange and lubricator. Test same to 600 psi. June 14. 2006 -' Log wI GR/CCL. Set cement retainer at 3,500'. MIU Perf Gun #1, RIB, shoot 2,913'- 2,918'. POH, MIU Perf Gun #2, RIB, shoot 2,862' - 2,867'. POR, MIU Perf Gun #3, RIR, shoot 2,837' - 2,842'. POH, MIU Perf Gun #4, RIB, shoot 2,614' - 2,622' and 2,604' - 2,610'. POR, MIU Perf Gun #5, RIB, shoot 2,480' - 2,486'. POH, MIU Perf Gun #6, RIR, shoot 2.350' - 2,370'. POR, MIU Perf Gun #7, RIB, shoot 2,317 - 2,326' and 2,307' - 2,312'. RID WL, lubricator and shooting flange. RIB wI bit and scraper and reverse circulate while filtering brine. POR. June 15.2006 PIU pkr, RIB and set at 3,150'. R/U to swab, R/U separator and flare stack. Swab 30 bbls brine. Turn well to separator to unload. Unloaded 10 bbls brine wI 200 psi on tbg. Shut in well for 1 hr, SITP = 600 psi. Open well, loaded up and died. Shut in well to allow pressure to build, drop 2 soap sticks, SITP after 7-1/2 hrs = 650 psi. June 16. 2006 Flow well wI 12/64" choke. Bled from 650 psi to 0 psi in 15 minutes, gained 20 bbl of 9.8 ppg brine. Well continued to flow an additional 30 bbls of brine to pits. SI well for pressure buildup: 1,240 psi in 3 hrs. Flow well on 14/64" choke, FTP 200 - 300 psi wI 3- 5 bph fluid resembling drilling mud. SI well, 1,080 psi in 1-1/2hrs. Flow well 2-1/~ hrs. Pressure stabilized at 300 psi in ~ hr. SI well, drop 2 soap sticks. Built to 1,000 psi in 1 hr. SITP after 7 hrs = 1,180 psi. June 17.2006 Flow well 7 hrs. ISITP 1,200 psi, FFTP 280 psi wI 2-3 bph H2O and 140 mcfd through W' orifice. Open valve in pkr and kill well. POH. MIU RBP and RIB. Attempt to set at 3,140', failed to set. POR. June 18. 2006 Finish POR. No apparent damage to RBP. RIB wI pkr, RBP and add'l DC's. Set RBP at 3,155' after several attempts. Pressure testto 1,500 psi - OK. Set pkr at 2,816'. Swab . . well until well started flowing. Stabilized in 4 hrs at 360 psi on 14/64" choke. SII well, pressure rose to 1,250 psi in 3-1/2 hrs. June 19.2006 Flow test well from perfs 2,837'-2,918' @ 260 mcfd wi 420 psi FTP. SI well- pressure rose to 1,260 psi. Kill well, release pkr, POH, left RBP at 3,155'. Test BOPE. June 20. 2006 RIH wi test pkr, set at 2,457'. Swab in well and turn to separator. Flowed @ 460 mcfpd on 16/64" choke at 450 psi FTP. Recovered 25 bbls brine. Drop 2 soap sticks, well pressured up to 1,140 psi. Flow test well - stabilized at 556 mcfpd on 18/64" choke wi 420 psi FTP. Recovered 32 bbls brine. SI well, pressure built to 1,140 psi in 1-1/2 hrs. June 21. 2006 Monitor SI well pressure (1,140 psi). Flow well for 5 hrs - rate stabilized at 590 mcfpd. Kill well, release pkr, RIH to RBP at 3,155 and latch onto it. Unseat RBP, move it to 2,468' and set it. Set test pkr at 2,295'. Swab in well and turn production to separator. June 22. 2006 Flow well on 18/64" chk at 700 psi FTP, making 1,122 mcfpd for 7 hrs. SI well, pressure rose to 1,000 psi in 6 min and stabilized there. Flow well on 18/64" chk at 820 psi FTP, making 1,405 mcfpd for 2-1/2 hrs. Kill well, release RBP, POH. LID RBP, RIH wi pker and set at 3,165'. June 23. 2006 Swab well to 2,000' and attempt to flow. Loaded up with water and died. Drop 2 soap sticks and shut in. Attempt to flow well - no good. Kill well, unseat pkr, POH, LID pkr. RIH wi bit and scraper. Wash from 3,285' to 3,345'. June 24. 2006 Wash from 3,345' to 3,498'. Filter brine to 5 microns. POH, LID excess tbg. Run bottom completion assy on 2-7/8" tubing. Space out and set VT A completion packer 3,145'. June 25. 2006 Shear off of pkr. LID 24 jts tbg, POH wi remainder. R/U to run 3-1/2" completion wi screens. RIH wi same, space out completion l' above locator on pkr assy. June 26. 2006 Land tubing, drop ball & rod. Set pkr wi 3,000 psi for 20 min. Test top pkr from backside to 1,500 psi for 30 min. Set two-way check. NID BOPE, N/U and test tree to 5,000 psi. RIH wi slick line, open sleeve at 2,250'. Reverse in 67 bbls corrosion inhibited brine. Use slick line to close the sleeve, retrieve ball & rod from x-nipple at 2,776', pull RHC plug from profile in x-nipple at 2,776'. RID slickline. Swab in well. June 27. 2006 Swab in well. Flow well to separator - unloading brine. SI well, pressure built to 860 psi. Drop 2 soap sticks. Flow test - unloading brine. Change orifice to ~" . Well . . flowing at 420 mcfpd, 350 psi on 14/54" choke. SI well, pressure built to 1,200 psi. RJU slickline and RIH wi tubing plug. Set in x-nipple profile at 2,775'. June 28, 2006 RIH wi slickline, open sleeve at 2,749'. POH wi WL. Attempt to flow well fÌ"om perfs at 2,480'- 2,610', tbg pressure bled to O. RIH wi shifting tool to verify sleeve open. Hit fluid level at 1,300'. Well started unloading while prep to swab, turned to separator. Slowly cleaned up, final flow rate 195 mcfpd wi 200 psi on 14/64" choke. SI well, tbg pressured to 1,000 psi in 1 hr. RIH wi shifting tool, close sleeve at 2,749', POH. Flow well f/ perfs at 2,307' to 2,370'. Well tested at 935 mcfd wi 590 psi on 18/64" choke. SI well, built up to 1,000 psi in 14 min. Remained at 1,000 psi. RIH wi shifting tool and close sleeve at 2,375', POH. RIH wi plug pulling tool and pull plug at 2,778'. Release ng. AURORA GAS, LLC NICOLAI CREEK UNIT NO. 1B WELL TEST RESULTS SUMMARY-..JUNE 2006 WORKOVER DATE INTERVAL (MD) MCFPD FTP SITP of PKR PLUG TEST TOP PERF BTM PERF pslg pslg COMMENTS SAND AFTER PERFORATING W/ RBP AND PKR 6/15-1712006 3150 3500 140 280 1200 W12-3 BWPH Carya 2-4 & 2.5 . 3191 3401 2002 perfs 6/18-19/2006 2816 3150 260 420 1260 new perfs: Carya 2-3 2837 2918 6/20/2006 2457 3155 556 556 1140 new perfs Carya 2-3 & 2-2 2480 2913 some open in NCU #2 6/22/2006 2295 2468 1405 820 1000 new perfs Carya 2-1 2307 2370 open in NCU #2 AFTER RUNNING COMPLETION PACKERS, SCREENS, AND SLEEVES 6/27/2006 2761 3500 420 350 1200 commingled old Carya 2-3 to 2-6 2837 3401 + some new (all unique to NCU 1B) 6/28/2006 2436 2761 196 200 1000 new perfs Carya 2-2,1 & 2-2.2 2480 2622 (the 2-2.1 is open in #2) 6/28/2006 2275 2438 914 590 1000 new perfs Carya 2-1.2 2307 2370 (common to NCU 2) . 2-7/8" 6.5 # J-55 tbg to surface 13 3/8" 54# J-55 Surface Csg at 1,904'. Cmtd to surface wI 1,530 sx "G". Carya 2-1.2 Perfs: 2,307' - 2,326' MD 2,350' - 2,370' MD (TVD 2,254' - 2,316') Carya 2-21 Perfs: 2,480' - 2,486' MD (TVD 2,426' - 2,434') Carya 2-2.2 Perfs: 2,604' - 2,622' MD (TVD 2,550' - 2,568') Carya 2-3 Perfs: 2,837' -2,842' MD 2,862' - 2,867' MD 2,913' - 2,918' MD (TVD 2,783' - 2,864') Carya 2-4.2 Perfs: 3,191' -3,211' MD (TVD 3,137' - 3,157') Carya 2-5.1 Perfs: 3,371' - 3,401' MD (TVD 3,307' - 3,348') Carya 2-6.1 Perfs: 3,560' - 3,575' MD (TVD 3,506' - 3,521') Float collar @ 3,604' MD Float shoe @ 3,648' MD TD @ 3,672' MD (3,617' TVD) Fairweather E&P Services, Inc. Aurora Gas, LLC Nicolai Creek Unit No. I-B Current Configuration (6/26/06) Lone Creek No.1 Rev. 1.0 11131/2006 WJP Drilled 26" Hole 20" 94# H-411 Conductor set at 232', Cmtd to surface wlJOO sx "G". Drilled 17 1/2" Hole Sliding Sleeve wI X-profile @ 2,268' G-77 Packer @ 2,280 Sliding Sleeve wI X-profile @ 2,375' G-77 Packer @ 2,440' Sliding Sleeve wI X-profile @2,742' G-77 Packer@2,765' X-nipple @ 2,775' VIA Packer @ 3,145' XN Nipple @ 3,1114' Well completed with sand exclusion screens across the indicated perforations. Cement Retainer @ 3,500' 7" 23# J-55 Prodnction Csg @ 3,650'MD (3,595' TVD). Cmtd to surface wI 82 bbls "G" lead at 12.5 ppg and 67 bbls "G" tail at 15.8 ppg. Drawing Not To Scale e e DATA TRANSMITTAL Please reply to: AURORA GAS, LLC 10333 RICHMOND, STE. 710 HOUSTON, TX 77042 ATTN: ANDY CLIFFORD State of Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue. Suite 100 Anchorage. AK 99501 ATTENTION: Howard Okland Enclosed From Area Paper Prints/1 CD Aurora Gas. LLC NCU-1B well. Cook Inlet. Alaska Date: 2 July. 2006 1. One set of paper prints from the NCU-1B well: Completion Record: Halliburton EZ Drill Squeeze Packer & Free Point Indicator. 2. One CD containing digital log data from the NCU-1B well: Completion Record: Halliburton EZ Drill Squeeze Packer & Free Point Indicator. <)nC\"' ¡;;;;'j¡~!ilAiU. ~.~if"\ lin 1 X LJUti ,"-,wN "~.1:'iø. t:.J \./v "'."..... 1; PLEASE ACKNOWLEDGE RECEIPT OF DATA BY SIGNING BELOW AND SENDING A COPY BACK TO-AURORA GAS FOR OUR FILES. Received by: cY. ël- Date: 1/1f'J/((;., / AURORA GAS, LLC, 10333 RICHMOND, STE 710, HOUSTON, TX 77042 TEL: 713-977-5799, FAX: 713-977-1347 .+ ..;td -I b:J I 3S'9:G • Page 1 of 1 Maunder, Thomas E (DOA) From: Stephen Davies [steve_davies@admin.state.ak.us] Sent: Thursday, July 13, 2006 3:40 PM To: Ed Jones Cc: Tom Maunder; David Roby Subject: NCU 1 B -Information Needed Attachments: steve davies.vcf Mr. Jones, a O~ In response to your request concerning requirements to commence regular production from NCU 1B, please provide the Commission with the following information: 1. A structural cross-section presenting GR, resistivity and porosity well log curves for NCU 1B and NCU 2. The well log curves should be displayed in true vertical depth, with both measured depths and true vertical depths annotated in the depth tracks (if your geologic workstation software permits). On this cross-section, please annotate clearly: . sand tops for all sands that are productive or considered productive by Aurora in both wells (e.g. Carya 2-4.2, Carya 2-5.1, Carya 2-6.1, and so on), . zones perforated prior to the most recent workover in NCU 1 B, . zones opened by the most recent NCU 1 B workover, and -•-~- - -w --~ - .~_••--~:. . the vertical extent of the NCU Southern Participating Area defined in the AK Div of Oil and Gas Decision of the Director issued March 10, 2005. 2. An index map that legibly displays: .the shoreline of the Cook Inlet, . the Southern Participating Area boundaries, . the trajectories of the NCU wells within the Southern Participating Area, • sand tops clearly annotated along each well trajectory for all sands that are productive or considered productive by Aurora in the Southern Participating Area (e.g. Carya 2-4.2, Carya 2- 5.1, Carya 2-6.1, and so on), and • a scale bar. 3. A statement as to why regular production from common zones spaced less than 3,000' apart (as prescribed by Commission regulations) will not cause waste or decrease ultimate recovery from those zones. Thanks for your help, Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission 907-793-1224 2/14/2008 e e .2-02. - /~ 2-- Subject: FW: Conditional Approval and Questions Concerning Nicolai Creek Unit WelllB From: "Randall D. Jones" <rjones@aurorapower.com> Date: Thu, 08 Jon 200614:05:03 -0500 To: steve _ davies@ad:min.state.ak.us CC: 'Scott Pfoff' <gspfoff@aurorapower.com>, 'Andy Clifford' <acclifford@aurorapower.com>, 'Ed Jones' <jejones@aurorapower.com> Thank you for your email questions below. OUr replies to your questions are as follows: 1. Yes. Aurora is the only owner and operator within 3000' for all wells. 2. Yes. 3. No, but pursuant to 11 AAC 83.301-11 AAC 83.395 a PA may include only land reasonably estimated through the use of geological, geophysical, or engineering data to be capable of producing or contributing to the production of hydrocarbons in paying quantities;5//':/>h\!'~~~t.fd therefore, the DNR decision was to include into the South PA only the\o:\¡,;,(f\,· ~ aliquots which met said criteria. The DNR Decision only allowed 40.461 acres to the South PA. In order to have placed lands into the PA which extend 1,500' in all directions an approximate 70 additional acres from the BLM AA-8426 lease would have had to have been placed into the South PA and an additional 20 acres each from DNR ADLs 17585 and 17598 even though such lands were deemed not to contribute to the reservoir. 1 0.··~ ....~ ~ Likewise, the Beluga PA, which comprises 80.753 acres, would have had to have placed into it an additional 20 acres from AA-8426 and an additional 10 acres from DNR ADL 17585 and 20 acres from 17598. However, I respectfully submit to you that in my opinion Conservation Order 478A did not require all lands within 1500' be placed into the South PA. I interpret the Spacing Exception Order 478A requiring only that lands "within 1500' of each of the 3 wells will be included, in whole or in part, in the expanded PA" or PAs. That requirement was met to the extent lands falling within that distance from the wellbore AND reasonably estimated through the use of geological, geophysical, or engineering data to be capable of producing or contributing to the production of hydrocarbons in paying quantities as to the reservoir were placed into the PA. So Aurora isn't in any violation there because that condition was met. 4. No. The iB well is currently open to zones deeper than the currently open zones in the 2 well. The 1B open zones are the 2-4.2, 2-5.1 and the 2-6.1 and the planned zones to be added are the 2-3, 2-2.2, 2-2.1 and 2-1.2 with only the "planned zones to perf of " 2-2.1 and 2-1.2 being stratigraphically equivalent to the currently open zones in the 2 well. These 2 stratigraphically equivalent zones in the IB won't be produced until said zones in the 2 well deplete; however, isn't the purpose of Spacing Exception Order 478A to allow common zones to be simultaneously producible from 2 wells within 3,000' from each other? Therefore, I ask you to visit the Spacing Exception Order 478A to see if it allows such in the broadest sense. I will remind you both the IB and 2 wells are allocable to the same Southerly PA so there is no injury to any royalty or ORRI owner by allowing both wells to produce from the same intervals simultaneously. 5. "Yes" to the 2 well and "No" to the 9 well. The 3,000' limit in your question will encompass the NCU IB, 2 and 9 wells. The answer is "Yes" to the 2 well and "No" to the 9 well because the No.9 well's open zones fall within 1,320'MD and 1,477' MD. The common open zones in the IB, which are planned to be perfed and the No.2 well, will be the 2-2.1 and 2-1.2 zones, but said zones in the IB aren't presently planned to be produced in IB until said zones deplete in the 2 well. 6. Yes. To summarize our conversation today, I will check with the DNR if the definition of the Southerly PA needs to be reformed/modified to include the deeper zones in the IB from which Aurora has been producing namely the 3,191'-3,575' MD, but I note to you the last 2 PODs covering same have described our production from these depths and each have been approved by the DNR. Additionally, I will check and see if the 2-2.1 and e e 2-1.2 zones in the IB and 2 are fault separated, but I think not as their take points tops are only a few hundred feet apart, but by copy of this note to Andy I will ask for both intervals' distances. Finally, you will check the Spacing Exception Order 478A to see if it allows these 2 zones can be produced simultaneously form the 2 wells, which to me seems to be one of the essential purposes for granting spacing exceptions. Thank you for opportunity to furnish these answers to your email questions and please call me if any further questions arise. Randall D. Jones, CPL Manager, L 20 AND & Negotiations AURORA GAS, LLC 10333 Richmond Avenue, Suite 710 Houston, TX 77042-4176 Telephone 713-977-5799 Facsimile 713-977-1347 Mobile 713-409-2378 rjones@aurorapower.com rskn@houston.rr.com -----Original Message----- From: Stephen Davies [mailto:steve davies@admin.state.ak.us] Sent: Tuesday, June 06, 2006 12:33 PM To: ACClifford@aurorapower.com; rjones@aurorapower.com Cc: jejones@aurorapower.com Subject: Conditional Approval and Questions Concerning Nicolai Creek Unit Well IB Randy and Andy, Yesterday afternoon I received Aurora's application for well operations in Nicolai Creek Unit 1B ("NCU IB") that included perforating additional, shallower sands within the Tyonek Formation. Because Aurora's rig was on standby, the Commission granted provisional approval for the proposed operations, including perforating and limited-duration testing of these additional sands. However, regular production from NCU IB will not be approved until the Commission is satisfied that all conditions and requirements of Conservation Orders 478 (the spacing exception) and 478A (the order allowing regular production) have been met. Please provide answers, with detailed supporting evidence, to each of the following questions: 1. Is Aurora the only owner and operator within 3000 feet of wells NCU IB, 2 and 9? 2. Are the State of Alaska and the Federal Government the only landowners within 3000 feet of wells NCU IB, 2 and 9? 3. Have all properties within 1500 feet of wells NCU IB, 2 and 9 been included in the expanded PA as required by Conservation Order 478A? 4. According to the Alaska Division of Oil and Gas findings and decision document dated March 10, 2005 and titled "Approval of the Revised Nicolai Creek Unit Area, Revised Participating Areas A and B, and Formation of the Beluga Participating Area," Gas Pool PA-A (renamed the Southern Participating Area) is limited to the stratigraphic interval in the Tyonek Formation encountered between 2422 and 2918 feet measured depth in well NCU 2. Do all intervals that have been perforated or that will be perforated during the proposed operations in NCU IB fall within this expanded PA as required by Conservation Order 478A? 5. Will the additional perforations in well NCU IB open intervals that are currently open to production in other wells within 3000' of NCU IB? 6. Do previous and currently planned operations in well NCU 1B conform to all other requirements !lPablished by Conservation Orders 478A? e 478 and Thanks for your help. Steve Davies AOGCC 907-793-1224 Re: Aurora Gas NCD-IB Workover e e Subject: Re: Aurora Gas NCU-IB Workover From: Thomas Maunder <tom _ maunder@admin.state.ak.us> Date: 08 Jun 2006 -0800 Bill and Ed, Your proposal is acceptable. I think the proposed setting depth will wind up being not much shallower than originally planned. Good luck getting the equipment out of the hole. Tom Maunder, PE AOGCC Bill Penrose wrote, On 6/8/2006 11:12 AM: Tom, In attempting to de-complete well NCD-IB, Aurora Gas has found the completion sanded in and cannot pull it in its entirety. (See the attached schematic of the current wellbore configuration.) Fill in the tubing has been tagged with a sinker bar at 3,379' (in the second sand screen) and a free point indicator shows the tubing free above 3,283' (the packer has been intentionally pulled loose) . Aurora Gas wishes to cut the tubing as deeply as possible between the top and middle sets of perfs, set a bridge plug just above the point of recovery and not have to go below the bridge plug in the future when the well is permanently P&A'd. Aurora proposes that the bridge plug be treated as the bottom of the well when it is eventually abandoned with cement per the Commission's regulations. The cement required to abandon the current top set of perfs would extend from the bridge plug to 100' above those perfs, thereby additionally isolating the perfs below the bridge plug. Please let me know if this plan adequately sets up the bottom two sets of perforations for future permanent abandonment without having to intervene below the proposed bridge plug. Regards, Bill Penrose Vice President / Drilling Manager Fairweather E&P Services, Inc. 2000 E. 88th Avenue, Suite 200 ôL1"'ÄîU~it:.:-~ 1'J~1 <I . 'ìr " ~r'i.J';t,~..f.; 'oJ; ¡\ .L :1 !...JD') Anchorage, Alaska 99507 907-258-3446 1 of I 6/8/20062:18 PM e Subject: Conditional Approval and Questions Concerning Nicolai Creek Unit WelllB From: Stephen Davies <steve_davies@admin.state.ak.us> Date: Tue, 06 Joo2006 09:32:52 -0800 To: ACClifford@aurorapower.com, rjones@aurorapower.com CC: jejones@aurorapower.com BCC: Daniel Seamooot <dan_seamOoot@admin.state.ak.us>, Cathy P Foerster <cathy joerster@admin.state.ak.us>, Tom Maooder <tom_maooder@admin.state.ak.us>, David Roby <daveJoby@admin.state.ak.us> e ~.~/':z_" Randy and Andy, Yesterday afternoon I received Aurora's application for well operations in Nicolai Creek Unit 1B ("NCU 1B") that included perforating additional, shallower sands within the Tyonek Formation. Because Aurora's rig was on standby, the Commission granted provisional approval for the proposed operations, including perforating and limited-duration testing of these additional sands. However, regular production from NCU 1B will not be approved until the Commission is satisfied that all conditions and requirements of Conservation Orders 478 (the spacing exception) and 478A (the order allowing regular production) have been met. Please provide answers, with detailed supporting evidence, to each of the following questions: 1. Is Aurora the only owner and operator within 3000 feet of wells NCU 1B, 2 and 9? 2. Are the State of Alaska and the Federal Government the only landowners within 3000 feet of wells NCU 1B, 2 and 9? 3. Have all properties within 1500 feet of wells NCU 1B, 2 and 9 been included in the expanded PA as required by Conservation Order 478A? 4. According to the Alaska Division of Oil and Gas findings and decision document dated March 10, 2005 and titled "Approval of the Revised Nicolai Creek Unit Area, Revised Participating Areas A and B, and Formation of the Beluga Participating Area," Gas Pool PA-A (renamed the Southern Participating Area) is limited to the stratigraphic interval in the Tyonek Formation encountered between 2422 and 2918 feet measured depth in well NCU 2. Do all intervals that have been perforated or that will be perforated during the proposed operations in NCU IB fall within this expanded PA as required by Conservation Order 478A? 5. Will the additional perforations in well NCU 1B open intervals that are currently open to production in other wells within 3000' of NCU 1B? 6. Do previous and currently planned operations in well NCU 1B conform to all other requirements established by Conservation Orders 478 and 478A? Thanks for your help. Steve Davies AOGCC 907-793-1224 Steve Davies c')::] CJ r:~L:':':::¡ t'::) ;" ,,", ~ (,'I ,'\ (t!J II ), \~ ß LJ l U) .'~ I) 1 ß \ '<, ' Ô æ) U h lJ r: ,_ J t~,!rl' Q)) K\lì\ , FRANK H. MURKOWSKI, GOVERNOR I ALASKA. OIL AND GAS / CONSERVATION COMMISSION /" 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Edward Jones Vice President, Engineering and Operations Aurora Gas, LLC , " " ",_¡ ¡; .,1 '\ l 20Då 1400 W. Benson Blvd, Suite 410 ~jCA~NE.L, .",Uh .:. ;t \~~ Anchorage, AK 99503 ~O â-- Re: Nicolai Creek Unit, 1'yunek Undefined Gas Pool, Nicolai Creek Unit IB Sundry Number: 306-195 Dear Mr. Jones: Enclosed is the approved Application for Sundry Approval relating to the referenced well. Please note the conditions of approval set out in the enclosed form. The application for this work was received on May 30 but was misdirected within our office, which caused some delay in processing. Although the application was misdirected, 20 MC 25.285 (g) requires that a copy of the approved Sundry be on location. The planned work was begun without Commission approval. In addition, in the course of staff review it appears that the requirements of Conservation Order 478A that allows the subject well and other wells at the drill site to produce have not been fulfilled. Discussions on this matter are ongoing with members of your staff. In the interim, Aurora is specifically allowed to complete the planned well work including 30 cumulative days of testing. However Nicolai Creek Unit IB may NOT be placed in regular production without further approval by the Commission. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for 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. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Aurora Gas, LLC .. Nicolai Creek Unit 1~ Sundry Number: 306-195 e Jf~ " -t~ DATED this ~ day of June, 2006 Encl. • • t~i~~~a ~~~ ~~~ ~~~ ~®nse~rat~.~~ C~n~.~s~i~~. 333 4'aTest 7th ~-1~ anus, Su~.E~ 100 ~nz`h.~ra~~, AI6 99501-3339 ~'h~n~: (907) 279-1433 Faxa (907) 275-7542 Fax Tra~asrn~ssian The information contained in this fax is confidential and/or privileged. This fax is intended to .E reviewed initially by only the individual named below. If the reader of this transmittal page is na the intended recipient or a representative of the intended recipient, you are hereby notified tha any review, dissemination or copying of this fax or the information contained herein ~ prohibited. If you crave received this fax in error, please immediately notify the sender b telephone and return this fax to the sender at the above address. Thank you. - ~ -tO To. ~ ~~ Fax #: ~--~ t~ From: ~Q C"~~~u~~E- - Date: ~.~'l~C ~ ~c~~.J~J Phone #: Pages (including -- ,7 Subject: cover sheet): Message: ~~~ F~~ ~. ~ 200 ~~ ~~ ~~~ ~~ w ~~~~~ ~~ ~~tls `tom ~~ ,~ , ~c~; ~~ 1 ~~~5~ b~ C~_ If you do not receive all the pages or have any problems with this fax, please call for assistance at 907 793-1223. • • JOB STATUS REPORT TIME 06/05/2006 16:00 NAME AOGCC FAX# 9072767542 TEL# SER.# BR02J2502370 DATE,TIME 06/05 15:59 FAX N0./NAME 2771006 DURATION 00:00:57 PAGES? 03 RESULT OK MODE STANDARD ECM JOB STATUS REPORT TIME 06/05/2006 16:03 NAME AOGCC FAX# 9072767542 TEL# SER.# BR02J2502370 DATE,TIME 06/05 16:02 FAX N0./NAME 2795740 DURATION 00:00:47 PAGE(S) 03 RESULT OK MODE STANDARD ECM • • Sundry Application 306-195 Review Discussion: Aurora Gas, LLC submitted the subject Sundry Application for proposed work on the Nicolai Creek Unit # 1 B well. On the application the `Plug Perforations' box was checked under Type of Request. The detailed description of the work to be done made no mention of plugging any perforations so I called Mr. Bill Penrose with Fairweather, Aurora's local representative, regarding this issue. Mr. Penrose indicated that this mark was in error and they are not proposing to abandon any perforations at this time. Mr. Penrose also indicated that there is an error in the Summary Procedure submitted with the application. The error is in item 9, which reads "Run and set CIBP ay 3,600"' per Mr. Penrose this should read "Run and set cement retainer at 3,500"'. Since they are not proposing to abandon any existing perforations I did not do a thorough analysis of potential effects on reserves. However a cursory review indicates that the well is currently a very poor producer. During the approximately two and a half years since the well was completed it has only produced for a total of eight days in the two and a half years since it was originally completed. Cumulative production from this well has been 2,155 mcf and 62 bbls of water. Recommendation: Since the operator is not proposing to abandon any completions, and is in fact intending "extensive flow testing of all old and new perforated intervals", I recommend their request for proposed work be granted. D.S. Roby`G`~%~ Reservoir Engineer 6/5/06 ~~ ~5~ S i r ~-~ ~ c~c--E S~.~~~o~F- ~t~~s~ ~vE ,~ TiPr~sv~~ -~hcr Ps~v--~~s Cs \~51,~c p~~~,.~•c-~ < ~~ ~ ~ C.o f 5 ~, ~• ~~ ~s~~ Ic~'.~S ~~;c~ ~ o S'~4~ c~~~~~a~s ~. :=:% Protracted Sections 19, Nicolai Nort , PA, I NORTH 20, 29 and 30, T11 N, Nico{ai South's PA & R12W, SM, AK Beluga PA Tracts ~--- -[ F':i~~ I ~~~~ ~ '~ SEC '~ 8 SEC 1 ~ 2 1 2005 ~~ ! ron~ of _-_ __. _-_ ___ _._ D GA __ ___ _-- ~r/1 f.,~f ~'%~i f, ~,~,, f s .~ ~ , c,~ ~ ~. ;r~icot:ai c~c~~~c 'r:~;f l1NIT a ~-.~r, U~l1T 5 ~/', / ~,/ ~, SEC 19 ~ /,~~/ ~~~r,,~SEC2Q 'ti C =~il_AI hhr F ~ i*.:. ~~j/f_,rf f ~ ~r~~f`/~f~J,.r~f ~~ .~ ~~~~ t„ __ ~_ __ _ .iii--$~~~h _ i. ! v~F 5~lEET;'2 ~a , F I i ,IV%::= i V ~I} ~ At Cv -~ WIYII I ~~' _. i ..---.---- NiC ~L~t:i :7t~!_I I ~ i'rt 7.:X!14,T~: s i _`j ~~~N~vl 3 ! ~ ~ ~ ~, _ ~_ _., .~ , . ', t _ . .-_ -- ~_ __'-._. - I A.C~^ 1 ~=5~~ SEC 31 SEC 32 ~~ . T11 N ___ SHEET: 1 of 3 n,y, YIw1IwP ~ e.0. ~v ~N ~eua°r ut eNN ~. 2? ~6 ,~.~'~ ~°'""~""'S^°"° ; Aurora Gas, LLG ... ,~,.,~ „ M~.K ram _ • NICOLAI SOUTH PA TRACTS within Sec 29 and 30 T11 N NoRrr~ R121N SM AK I ~- EXHIBIT "A" ' '~ Page 2 of 3 ,JAN 2 2005 ;; D!V! ON OF _ '` OtL A D GAS } ,: ~I ~~~ ~~- r 1~ ~, ,._ ~ - TPACT 2 ~ -- - - ~ _~" __ ~. y~q ts.r+ w ns+ ~ ; +~~. ~, v~t`#.iC ALK. ~;ra ~sx ~-*t ar~~ w TRACT 4 ~,so~ ~~ ~~ TRACT 3 2~. ~c apt ia5&5 _._...____ 17 .___ ~ ~ ___'1~ as ga ;.. COOK /NLET i Vs ~.FE.a9E-.LYMIIS NQIFiHO-~fik 3~~ iA MM I17 eiw?i l,w +3rf!iLt~FNORATtS~YwM j.TJ19 Ml~m IiH '1d11f5 lMf!i altl ~i LYlM79Wi~i [p'FiMY A.YR +Y7. ~191ii 't4 ~!: pE -0E to LT's1096iT1t'#!'aIN 7'.Ym tf~lT'-'Jn '~ MME: $Mt ~~: P:HbI ALR 1?9E6 to ., 30 29 31 32 MIDIS . ~,...o~...Kr.r.~~~ar a win. aouorm ne.uu awn wwaaoR.vse~r ne o~im~~wrars. sn.nrrsuas~m '/y ni.~iaw~nmra~~ aowi~iamriawamna •nerrHr.r.w~ vdeaRwnwee.m~snn sera. vrwmrsswo.amrwwn nauoru a~rrrW°a ai~sn~,awresmxn~~oa GRAPHIC SCALE .~ (nr Fssr ) 1 inch 400 1L SHEET: 3 of 3 ~_ Aurora Gasp LLC ~" ;'~ _.. s,.~, BELUGA PA TRACTS within Sec 29 and 30 { "oR-rH T 11 N R 12W S M AK EXHIBIT "A" 1 Page 3 of 3 i `~~ ~ \~, ~~ =, 2 12005 p,, ~~ `r., u;~,~ tON OF TRACT 2 ~ ®~~- No cas PGLp t£4 COR ~ ~~ i ~ I ~~~~~ ~(_ .~l7~ ~ I 2 (x f+3 ( ~ +A C ~ _ ~~~~~ _', ~s ~ .1~ -_ _ ~s - - - - - __ - wcMc 7M/MEANIrCiF1WA~ERtl1E ', WCMCADLCt WGACHDLG VHtADL3673S ~,. PO TRACT 4 ~° ~ '~ ~~ 7.903 AC ~ ` ,e-ol,~~ TRACT 3 27.550 AC ~ »s~ ~ _ ~.. >~ z~ ~~ y_3 s,..,~~_.. ~.rraM~..~. 1 ;;~ ~ ~ COOK /NLET '^~` ~ I i T Pt 5w . SW . NW . 10.000 M 647E i~lS IV O P2 rfY.NE ~9E . 10.001 M647E R.nc ,.~ ~. . . - ru,r sNw.,.,a ...,c m, .r. - P3 NriIYa NW$SWY. 99E4 M617E - _ v..,.r P/ r~Y.myY,gy1Y• 9A50 M6418 cnv<crnr. ar+ os~++mc.=n.x n. rn.w.x ,-ewl P5 SEY NWY+EwY IYM'NORTH OF 6FAV 1.9616 M617E - P8 $1MiMMY 34Y ~lYMClIORTH OF 6Al/1N 1.1515 M8470 wu. n.,r.~w r..Y .rr.~.-.. ~+: PT 9EY. tEY BE LYM('NORTH~4IFIW 7!.9,1365 M647E ....° Po 9EY4 NE Y gEY~ LYRK' SOUTH OF YtlI 7909 /i0L 17336 - P9 9WY. N1YY. 87MY. lYWO BOUTN OF /AiW 3.162 AOL 17565 .v w. - sc..., P1O 9EY NWY 9W Yi LYMIC SOUTH OF IkH1 3.064 Ad, tT536 .- „.,>. Pi 7 Y. Y. GRAPHIC SCALE 30 2s ' 31 32 (nY xs~r ) 1 inch = 400 !t SHEET: 2 d 3 _ _ ~ s.` `~~,,~ ..... _ c~.iii~cn6. ' .. _ ra Gas, LLG ;, r ,... w,~ :,,. ~ .rT --- _ .. -- -- __ ..._ dry ~ ~ ~ Subject: Re: Nicolai Creek Unit 1B (202-162) From: Thomas Maunder <tom_rnaunder c~admin.state.ak.us> Date: Mon, OS Jun 2006 11:1:39 -0800 Ta: Ed JO11CS ~~jejon~s~u aurorapower.c~~n1> ('C': Bill Peni~~~sa <bill~a'fairw°eather.cam>, C`athy Foerster ~cath~ foerster cradmin.stateak.us> Ed and Bill, Please be advised that Aurora's original sundry application has been found. It was received by the Commission on May 30. The document was evidently misplaced due to a combination of a staff member vacation and hurried departure of another staff member due to a medical emergency. We are reviewing your work application and will be in touch with you in the early afternoon when all staff members have completed their review. Tom Maunder, PE AOGCC Thomas Maunder wrote, On 6/5/2006 10:14 AM: Ed and Bill, It appears that workover operations on Nicolai Creek Unit 1B are underway also appears that no Application for Sundry Approvals (Form 403) has been approved for this work. It I have spoke to Commissioner Foerster with regard to this matter and she has instructed me to inform you that Aurora should complete what work is necessary to make the well safe and halt operations pending resolution of the required work authorization. Call or message with any questions, Tom Maunder, PE AOGCC 1 of 1 6/5/2006 11:42 AM .....,...».. .............. .v ~~..,... ..,.,i • Subject: Read: Nicolai Creek Unit 1B (202-162) From: Ed Jones <jejones@aurorapower.com> Date: i~!Ion, OS Jun 2006 13:24:42 -000 ~'o: tarn_mattndzr~,adinin.stateak.us Your message To: Ed Jones Cc: Bill Penrose; Cathy Foerster Subject: Nicolai Creek Unit 1B (202-162) Sent: 6/5/2006 1:14 PM was read on 6/5/2006 1:24 PM. Reporting-UA: EdDel1LT; Microsoft Office Outlook, Build 11.0.5510 Final-Reci Tent: rfc82~; 'e'ones;~a~.:roraoower.r_~om p __....._..._._..__........ 7 ._ 7.._._....__._..__._.._......._---...._ ~,_...---._.....__.......___._._. Original-Message-ID: <44~'7477.:?050409'~aumin.state.ak.us> Disposition: manual-action/MDN-sent-automatically, displayed Content-Type: message/disposition-notification Part 1.2 Content-Encoding: 7bit 1 of 1 6/5/2006 10:26 AM r ~ • Subject: Return Receipt (displayed) - 202-162) From: Cathy_foerster@adnlin.state.ak.us Date: Mon, OS Jun 2006 11:19:06 -0800 Ta: tam maunderC!admin.state.ak.us This is a Return Receipt for the mail that you sent to ~~at-'_~_f_°_` _ster=admin. st~,tc . ak. us . Note: This Return Receipt only acknowledges that the message was displayed on the recipient's computer. There is no guarantee that the recipient has read or understood the message contents. 'Content-Type: message/disposition-notification MDNPart2.txt Content-Encoding: 7bit 'Content-Type: text/rfc822-headers MDNPart3.txt 'Content-Encoding: 7bit 1 of 1 6/5/2006 11:22 AM e e ~urora Gas, LLC www.aurorapower.com May 22, 2006 Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 West ih Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Sundry Approval: Workover ofNCU #IB (PTD No. 202-162) Dear Mr. Norman: Aurora Gas, LLC hereby applies for approval of its plans to work over the Nicolai Creek Unit #IB gas well in the Nicolai Creek gas field on the west side of Cook Inlet. The workover is expected to commence the first week in June. This workover will involve adding perforations in intervals shallower than those presently existing in the well, extensive flow testing of all old and new perforated intervals and the running of a multi-packer completion to allow selective testing and production of all intervals. Enclosed please find a Form 10-403, Application for Sundry Approval, for this work. Also enclosed are a summary work plan and a current NCU #IB wellbore schematic. The BOP system to be used for this workover is the same as that previously used on the A WS # 1 rig and is on file with the Commission. If you have any questions or require additional information, please contact me at (713) 977-5799 or Bill Penrose at 258-3446. Sincerely, AUR,ORA GAS, LLC , ~ ' ~)r-' . ( ./ .,/". - / / /' ~£-?-- / ~~ ~ ~ /' YEdward Jones // / (~'/Vice President, EngiÍleêring and Operations enclosures cc: Bill Penrose - Fairweather 10333 Richmond Avenue, Suite 710. Houston, Texas 77042· (713) 977-5799. Fax (713) 977-1347 1400 West Benson Blvd., Suite 410· Anchorage, Alaska 99503· (907) 277-1003· Fax (907) 277-1006 STATE OF ALASKA t#I ~~ ,¡ --C- A~~~~~I~~ ~~~O;~~~~~~~~M~~~~:-Y ~ 20 MC 25.280 Operational shutdown Perforate 0 Waiver Plug Perforations 0 tl/lr. Stimulate 0 Time Extension 0 Perforate New Pool 0 ~ Re-enter Suspended Well 0 4. Current Well Class: 5, Penn it to Drill Number: AbandonO Alter casing 0 Change approved program 0 2. Operator Name: 3, Address: 1400 W. Benson Blvd, Suite 410, Anchorage, AK 99503 7, KB Elevation (ft): 1, Type of Request: 8, Property Designation: 11, Total Depth MD (ft): 3,672' Casing Structural Conductor Surface Intennediate Production Liner Perforation Depth MD (ft): . 3,191' - 3,575' . Packers and SSSV Type: Other 0 Suspend 0 Repair well 0 Pull Tubing 0 Aurora Gas, LLC Development 0 Stratigraphic 0 Exploratory 0 202-162 Service 0 6. API Number: 50-283-10020-02 35.5' AMSL (DF) 9, Well Name and Number: Nicolai Creek Unit #1B 10. Field/Pools(s): ADL 17585 Nicolai Creek Total Depth TVD (ft): 3,618' Length PRESENT WELL CONDITION SUMMARY Effective Depth MD (ft): Effective Depth TVD (ft): 3,600' 3,510' Junk (measured): None Collapse Plugs (measured): None Size TVD 20" 232' 232' 13-3/8" 1,904' 1,904' 10-3/4" 2,186' 2,186' 7" 3,648' 3,594' Burst 232' 1,904' 2,186' 3,648' N/A 1,530 psi 3,580 psi 3,740 psi N/A 520 psi 1,580 psi 3,270 psi Perforation Depth TVD (ft): Tubing Size: 3,136' - 3,521' Baker SC-1 packer, no SSSV Tubing Grade: 2-7/8" J-55 Packers and SSSV MD (ft): Tubing MD (ft): 3,112' Packer at 3,113' MD 12. Attachments: Description Summary of Proposal Detailed Operations Program 0 BOP Sketch 0 14, Estimated Date for Commencing Operations: 16. Verbal Approval: J 13, Well Class after proposed work: Exploratory 0 Development 15. Well Status after proposed work: Oil 0 ¡lIlt Gas 0 WAG 0 fÞ. I, GINJ 0 .::._0 I.' ... Contact Bill Penrose 258-3446 o Service 0 0 Abandoned 0 0 WDSPL 0 61512006 Plugged WINJ Date: Commission Representative: N/A 17. I hereby certify that the foregoing is true and correct to the best of my knowledge, Printed Nam ard Jones Title Phone 713-977-5799 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: .:!:fJ~' , qS Plug Integrity 0 BOP Test ~ Mechanical Integrity Test 0 Location Clearance 0 Other: ~ooa ßb~ \-<t'?\- Q> ç>\o..."",Q. A~~t""C>~Q.\ '\ '> <9\,,)Cè~ -\0 <î)",,~ \~ -\-~ ~ \-..0 '^'~ ""-,, ~.. ~IL \ . "-':':t ';iJ~ ~ "- ÇJ<;C~~0 ""'\\~\- ~-.).-\4.- ~WO", ~"'Cè. <:..c~~\«>::'<>\ù"t T<èS~~ ,,\ \",4~\<> '\~ \'-K.,~cl ~ 5>O~"")\".1\~~<..)«<~'t~f Approved by: COMMISSIONER APPROVED BY THE COMMISSION Date: 6...~-06 ORIGINAL RBDMS BFl JUN 14 2006 Form 10-403 Revised 07/2005 Submit in Duplicate #- ~/'6 e e AURORA GAS, LLC NICOLAI CREEK UNIT 18 2006 WORKOVER PLUG BACK, ADD PERFORATIONS, AND REPLACE SAND SCREENS SUMMARY PROCEDURE 1. Remove well house and disconnect production piping and controls. 2. Move in and rig up workover rig and associated equipment. 3. Blow well down through choke manifold and kill well by bullheading 9.8 ppg KCIlNaCL brine. 4. N/D tree and NIU BOPE. Test BOPE to 2,000 psi. 5. MIU to tubing hanger and un-sting seal assembly from permanent packer. Circulate well to ensure it is dead. 6. POH wi completion. 7. Mill over and retrieve permanent packer. 8. Run bit and scraper to 3,600'. '-.<è~. ~ Vb- '\1'.(t" Q.. 'SSQtJI ~<t:ç-~,\"\ ~~">Jè. 9, Run and set'€IDr at 3,600', filter brine. bj ~ 10. RU Schlumberger wireline unit and lubricator. PU and RIH wi 4-1/2" HSD guns wi 5 or 6 SPF jet charges and perforate: a) 2913-2918' b) 2862-2867' c) 2837-2842' d) 2604-10' and 2614-22' (20' gun) e) 2480-2486' f) 2350-2370' g) 2307-2312' and 2317-2326 11. Lubricate additional brine into well if necessary. Ensure well is dead. 12, Run casing scraper to 3,600' and re-filter brine. POH e e 13. Using a multiple-set test packer and swabs, perform extensive swabbing and testing operations on the old and new perforated intervals. 14. At the conclusion of testing, run a casing scraper to the CIBP and re-filter brine. POH. 15. Run production string: Three packers will likely be run, and well will most likely be set up with a selective completion to isolate shallower zone(s). Exact configuration will be determined by the peñorating and testing. However, assuming all zones are productive, the completion string will be as follows, from bottom up: --Bull plug --20' of 3-1/2" MicroPak 30/50 screen at 3375-95' --X-O (3-1/2" EUE X 3-1/2" 10 Rd) --3-1/2" tubing spacer -- X-O --20' of 3-1/2" MicroPak screen 3192-3212' --X-O --3-1/2" tubing spacer --7" Arrowset IX Mechanical-set Packer wi 2.31" X profile nipple 1 joint above or below, packer set at about 3150' --3-1/2" tubing spacer --X-O --10' of3-1/2" screens at 2910-20',2860-70' and 2835-45' (all +1-) wi 3-1/2" tubing spacers and X-O's. --X -0 --Extended 3-1/2" On-Off Tool --1 jt 3-1/2" tubing --2.31" X Profile Nipple --3-1/2" tubing spacer (1 jt) --7" HPR Hydraulic Packer at about 2765' (+1-) --3-1/2" tubing spacer --3-112" RIV Sliding Sleeve wi 2.31" X profile at about 2650'. --3-1/2" tubing spacer --Weatherford 7" X 3-1/2"" HRP Hydraulic Packer at about 2440' --2 jts 3-1/2" tubing spacer --3-1/2" RIV Sliding Sleeve wi 2.31" X profile at about 2375' --3-1/2" tubing spacer -- Weatherford 7" X 2-7/8"" HRP Hydraulic Packer at about 2280' --1 jt 2-7/8" tubing --2-7/8" XA Sliding Sleeve wi 2.31 X profile --2-7/8" tubing to surface 16. Set packers, space out and land tbg. N/D BOPE, NfU tree. 17. Using sliding sleeve above top packer, circulate in packer fluid containing biocide and corrosion inhibitor. e ¡e 18. By setting a plug in the x-nipples, selectively flow-test each of the three intervals isolated by the packers. Flow through the test separator. 19. Set BPV in tree, RID and release rig and place well on production. e (e D Proposed CD Completed Nicolai Creek No. 1 B Nicolai Creek Field Alaska Producer 2 7/S 6.5# EUE SRD J·55 Production tubing 26" Hole 20"94# H-40 @ 232' CMrD to suñace WI 300 Sks Whipstock @ 645' in 17 1/2" hol 17 1/2" Hole 133/8" 54# J-55 @ 1904' Cmt'd to suñace WI 1530 Sks Top Whipstock @ - 2186' Baker WindowMaster Bottom Set Whipstock Bridge Plug set at 2212' Peñorations: 3615' - 3630', 2 spf 121/4" Hole 103/4" 40.5# J-55 @ 3817' Cmt'd to suñace WI 900 Sks 9 7/8" Hole Attachment I Original NCU 1A TD'd 1966, Plugged Back 1991. See original NCU 1 & 1A well records for peñoration and squeeze information 7"' stage collar installed at 1832' and baffle plate at 1789'. Stage collar not u~ed during cementing procedure. O2 Inhibited KCL packer fluid "Con cor 303" in 2 7/S" X casing annulus to suñace above Packer X-nipple at 3080' Permanent Packer Baker SC-1 @ - 3112.7' 3 1/2" J-55 Production Tubing Spacer between screen intervals 51/2" Meshrite Screen 3192' - 3215' 3373' - 3396' 3557' . 3580' Well peñorations 3191' - 3211' 3371' - 3401' 3560' - 3575' @ 5 spf, 60-degree phasing 41/2 HSD guns 7" 23# J·55 Csg. @ 3650' MD(3595' TVD) Cmtd to suñace wI 82 bbls 12.5 ppg lead 67 bbls 15.8 ppg tail 7" Float Collar at 3604' NCU 1B 7" Guide Shoe at 364S' TD at 3672' MD CRAWlIII3 NOT TO SCALE NICOLAI CREEK No, 18 FAIRWEATHER E&P Rev:01 fDHV SERVICES INC OIH)c,"bec-!12 rage 1 of 1 • Maunder, Thomas E (DOA) From: Ed Jones [jejones@aurorapower.com] ~~~~ t Sent: Tuesday, August 26, 2003 6:21 PM To: Tom Maunder Cc: 'Duane Vaagen'; 'Andy Clifford'; Randy Jones; Scott Pfoff Subject: Production of the Nicolai Creek No. 1 B, 2, and 9 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 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--geologylgeophysics--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 Yage I of 1 Maunder, Thomas E (DOA) From: Tom Maunder [tom_maunder@admin.state.ak.us] Sent: Monday, June 09, 2003 7:10 AM To: duane vaagen Subject: Re: NCU 1 B 10-407 Attachments: tom maunder.vcf • Duane, I hate to bother you, but could you send over another copy of the 1 B 407. I don't know what has happened to the original. Thanks much. Tom duane vaagen wrote: Tom:The body of the document describing the final well report and completion were dated Oct. Stn The actual 10-407 was dated Oct. 16th, the date it was signed by Ed Jones.Please call if you need another copy. Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane@fairweather.com Office: (907)258-3446 Cell: (907)240-1107 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 %- ~~ 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. josborne@fairweather.com (907) 258-3446 office (907) 441-6600 mobile 3 Maunder, Thomas E (DOA) From: Bill Penrose [bill@fairweather.com] Sent: Friday, September 06, 2002 2:26 PM To: Tom Maunder (E-mail) Subject: NCU 1 B Cement Tom, Couldn't get you on the phone so thought I'd drop an e-note. In Nicolai Creek #1B, the yield for the 2nd stage lead cement is 2.09. Give a call or drop a note if you need anything else. Meanwhile, have a good weekend. Regards, Bill 4 e e MICROFilMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs _ Inserts\Microfilm _ Marker.doc Permit to Drill 2021620 /, okcZ"'~~"~~'-~ '-\ DATA SUBMITTAL COMPLIANCE REPORT 8/2/2004 Well Name/No. NICOLAI CK UNIT 1 B Operator AURORA GAS LLC <~Y¡ Vv 1. Il~ ~)... API No. 50-283-10020-02-00 MD 3672./ TVD 3618 / ----~--~_._---~ REQUIRED INFORMATION -- DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Data Type ~g , L~/ L../ 6P9'/ Log ro' C Electr Dataset Number Name t,........Réservoir Saturation ~oration cYement Ev~tuation See Notes Digital Med/Frmt SPt/ ~ ~. '-E'Ó C ./'/ 11191 See Notes See Notes l.s-ee Notes 'see Notes '\ ./ Uf'1192 See Notes ~. ¿2ée Notes L-L--og ED 0 Leompletion See Notes ~) r ~ "=.og......... cJ.óg ,..1:;09"'...'."- "'~'~..''''''..''.' ....._. tL.eg"- . Completion Status 1-GAS ç~~:~.... Completion Date 7/22/2002 Mud Log No ...-....--...-.--......- -' ffiductioMlnc:JiGtivity'" '-é¡~liper log . . ..C~ntEvaJuatian. .. ./ ~ic Log 'log. LO"g J.,Qg Formation Tester . Density.'..," Neutron-. - . -. Gamma Ray.. -~-_._..-- Current Status 1-GAS Samples No Directional Survey No (data taken from Logs Portion of Master Well Data Maint) Log Log Run Scale Media No 5 Cot 1 5 Col 5 Col 5 Col Interval Start Stop 33 3612 33 3612 1000 3612 2080 3675 2206 3672 2206 3672 2206 3672 2206 3672 1800 3675 1800 3675 2000 2470, 1800 3675 ~. OH/ CH Received Comments Case 11/1/2002 .."...,. Case 11/1/2002~~7V J~À~ú )... Case 11/1/2002'...."" I J) J,y{Î Â.v'o .ì... Case 11/1/2002 Best DT Final Result Open 1 0/14/2002 tp.¡¡f~1 Well Report Open 1 0/14/2002 t'~al Well Report Open 10/14/2002 [grmation Log Open 10/14/2002 FCmnation Log Open 10/14/2002 vÐlgital Data of AIT/PEX/DSI/FMt Open 10/14/2002 iÞ1:r1fBore Micro Imager MD and TVD Open 10/14/2002 .:...-t(j:5" EZ Drill Plug ..l8 iJ v,.l"- G ( À Open 10/14/2002 Bridge Plug, Gamma Ray and Casing Collar Locator 5 Col t-.-. 1800 3675. Open ~ 0/1 '11?002 MD .aRd TVD -- 5 Col 1 1800 3675 Open 10/16/2002 ¿ÞJID and TVD , .. ".""" .......>,-......"" .. ".'.'-. ».""".__..,^,~'_...m&_.w__.....GGI-M....."..-1'-'_.'.~m..._.' _.1.0.QO..._..~36.:t2-..--.ef)efl--.4-.Qt1.6/.2002.-- 5 Col 1 1800 3675 Open 1 0/16/2002 <~..- 2 Col 2206 3672 Open 1 0/16/2002 . '''''»'''''5'-'' '.".~"eol""~.""1m"~".'-''''~'M+8eO''--''''"367v--'€)peft><-4Q/1-4f~OQ2-"~'-MfJðnd TVD "".."'.'."-.'--"'.'. "'"".".'.."'~""~-'"".'".""""''''N~'-'5'''.'.-'''.eol-."'---'1.'."'"'."~"-"-'."-'+8QQ,.._....~3S7-5-~-~~~---M.D-a.:Q..:I:\£Q. ., -,r. ...",..........-.~~~,--eo-t------4--.-4ß~ Open 1.Ot~.st2002 iv1D and TVD 2 2 Col Col 5 Cot 5 Col --"".þ, .-.....--._--.._~----......----_..._-,.þ.. DATA SUBMITTAL COMPLIANCE REPORT 8/2/2004 Permit to Drill 2021620 Well Name/No. NICOLAI CK UNIT 1 B Operator AURORA GAS LLC API No. 50-283-10020-02-00 MD 3672 TVD 3618 Completion Date 7/22/2002 Completion Status 1-GAS Current Status 1-GAS UIC N ----~-- ------.-- . Log - ------- '> .--.'---. . -."-.-Sp----...-..-...-.--.>- - ,.-. .-.. - --'----- "--'--'''_._'->'----''->§-----~.-C-oi--,>-->j._,.._--_._-~-iOO~-'-361'-5--' Open 1eM~B-'a-nd-TVD-- - ---ÉO C 4-1"209 See Notes 1 2206 3672 Open 10/16/2002 --,.,.-.. ,fiog ~duction/Resistivity 5 Col 1800 3675 Open ,)..og '--Ðensity 5 Col 1800 3675 Open ..A.og ¿.AiIeutron 5 Col 1800 3675 Open ...Á..og ~~amma Ray 5 Col 1800 3675 Open Æ.og vSP 5 Col 1800 3675 Open 4::"og '-"Caliper log 5 Col 1800 3675 Open Log Caliper log 5 Col 1800 3675 Open 10/14/2002 Dual Axis ~gg.--/ !.5Onic 5 Col 1800 3675 Open 10/14/2002 (...Mt) and TVD ~/ D Directional Survey 0 3762 Open 10/16/2002 ~t Directional Survey 0 3762 Open 10/16/2002 JÓ C V.11208 Induction/Resistivity 1800 3675 Open 1 0/16/2002 v."-~-- 1 0/16/2002 MD and TVD 1 0/16/2002 MD and TVD 1 0/16/2002 MD and TVD 1 0/14/2002 MD and TVD 1 0/14/2002 MD and TVD 1 0/14/2002 MD and TVD ~ Well Cores/Samples Information: [~ Name Cuttings Interval Start Stop 2190 3672 Sent Received Sample Set Numb~~~ >fomments -' ..- 1 090 .' <~c.".., "-'>- ,"",..~>....--,,,::r',;_.' ,"~ -." ADDITIONAL INFORMATION y@' Chips Received? ~ Daily History Received? ~ì/N ~N ~/ Well Cored? Formation Tops Analysis Received? '¥7~.-,- ----- Comments: Compliance Reviewed By: , : ¡ : ~~ Date: I ~- ~~ ~'c) ,.{ --~----- ---- 1a. Test: ) STATE OF ALASKA') RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION ~~....a GAS WELL OPEN FLOW POTENTIAL TEST RI:P'URtOO3 Initial I]J Annual 0 Special 0 1b. Type Test: Stabilized d Non A~ff<tJ~ Gas_!rt~miss'on Constant Time 0 Isochronal D Other h . Ane orane 5. Date Completed: 11. PermIt to DrRl'Numbe1:" 9/23/02 202-162 2. Operator Name: Aurora Gas, LLC 3. Address: . 10333 Richmond, Ste 710, Houston, TX 77042 6. Date TO Reached: 9110/02 12. API Number: 50- 283-1 0020-02 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): Surface: 1999' FSL, 186' FWL, SEC 29 T11N R12W, 8M 36' 8. Plug Back Depth (MD + To~ of~roductive TVD):3600' MD (351 0' TVD) Horizon. 1625' FSL, 291' FWL, SEe 29, T11 N, R12 'IV 9. Total Depth (MO + TVD): Total Depth: 4b. Location of Well (State Base Plane Coordinates): 3672' MD (3618' TVD) 10. Land Use Permit: Surface: x- 241,509.647 y- 2,565,238.396 Zone- TPI: x- 241,373.05 y- 2,564,908.37 (mid) Zone- TotalDepth: x- 241,406.605 y- 2,564,864.648 Zone- 17. . Casing Size Weight per foot, lb. I.D. in inches 7" 23 6.366 13. Well Name and Number: NICOLAI CREEK UNIT #1 B 14. FieldlPool(s): NICOLAI CREEK GAS FIELD 15. Property Designation: ADL-17585 16. Type of Completion (Describe): Cased and perforated, wI sand control screens Set at ft. 19. Petforations: From To 3648 18. Tubing Size 2-7/8" 20. Packer set at ft: 3112 Weight per foot, lb. 6.5 21. GOR cf/bbl: NA I.D. in inches 2.441 Set at ft. 3112 3191-3211',3371-3401',3560-3575' (MD) 22. API Liquid Hydrocarbons: NONE 23. Specific Gravity Flowing Fluid (G): 0.57 + water (varies) 24d. Barometric Pressure (Pa): 15 24a. Producing through: 24b. Reservoir Temp: Tubing rn Casing 0 94 25. Length of Flow Channel (L): Vertical Depth (H): 3383' 3328' FO 24c. Reservoir Pressure: 1644 psis @ Datum 3328' TVDSS Gg: % CO2: % N2: % Hß: 0.572 0.31 3.35 0 Prover: psis Meter Run: Taps: 5.761" Flange 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow Une X Orifice psig hw of psig of psig of Hr. No. Size (in.) Size (in.) 1. 5.761 X 1.0 504 38 979 0 2.0 2. 5,761 X 1.0 505 35 1077 0 14.75 3. 5.761 X 1.0 493 26 1175 0 1.25 4. 5.761 X 1.0 495 31 1340 0 1.0 5. Basic Coefficient Pressure Flow Temp. Gravity Factor Super Comp. Rate of Flow (24-Hour) -JhwPm Pm Factor Factor Q, Mcfd No. Fb or Fp Ft Fg Fpv 1. 1700 ? NOT AVAlLABLE- CALCULATED ELECTRONICAlLY BY ASRC WELL TEST UNIT 1300 3. 1240 4. 430 5- Temperature for Separator for Flowing Pr T Tr z Gas Fluid No. Gg G 1. 0.57 2. NOT CALCULATED -USED RYDER SCOTT SPREADSHEET 3. SEE ATTACHED Critical Pressure 667.67 4. Critical Temperature 340.64 5. Form 10-421 Revised 212003 CONTINUED ON REVERSE SIDE Submit in Duplicate ~G\NAL Pel 2,277,081 ) Pc 1509 No. pt pt2 Pel-Pt2 Pw 1. 994 988,036 1,289,045 2. 1092 1,192,464 1,084,617 3. 1190 1,416,100 860,981 4. 1355 1,836,025 441,056 5. 25. AOF (Mcfd) 3108 Remarks: 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 Pf 164~ ) Pfl 2,702,736 Pwl P&-Pwl PS2 1,225,449 1,452,025 1,682,209 2,166,784 Pfl_Ps2 1,477,287 1,250,711 1,020,527 535,952 Ps 1107 1205 1297 1472 n 1.000 . true and correct to the best of my knowledge. Title Exec. Vice President Date 12129/03 DEFINITIONS OF SYMBOLS Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psi a Basic orifice factor Mcfd/-ýhwPm Basic critical flow prover or positive choke factor Mcfd/psia Specific gravity factor, dimensionless Super compressibility factor= ~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 psi a 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, psi a 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, psi a Rate of flow, Mcfd (14.65 psi a 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 212003 Side 2 ) ') I~,...., ...... . .. Ry4erStott - -..... .. . .;..... . .... ..Re.Servoil" ;tì~~.,.\......... ...... s;::x .u (Protected) BOTTOMHOLE TEMP, of: GAS GRAVITY: Hz«» GRAVITY,1w: CONDo GRAV., °API: TVD, FT: 3,328 MEAS. DEPTH, FT: 3,383 Cond. Correl. (Y/N): N 0 Check, If Injectton Welt Corrected* Tc, OR: 340.64 0 Smooth Pipe Roughness Corrected* Pc, Psia: 667.67 Pressure Base, Psia: 14.730 TUBING 10, IN.: -, - . . *tlVk:hert~AZlzcørrection for ~Inaltt$, .lfany WELL NAME: FIELD: lOCATION: RESERVOIR: NICOLAI CREEK UNIT NO. 18 NICOLAI CREEK T11N R12W SM, KENAI BOROUGH, WEST SIDE COOK INLET, ALASKA UPPERTYONEK, 3560-75', 3371-3401' & 3191-3211' MD SOUR GAS N2 CO2 H:zS I MOLE % 3.35 0.31 0.00 ..""8O. - - - - - -:- -.. -.. - -...... -.... ,', Options ... ~, ><. ':'!! . cfi,ooo ~-: Q. .' .' ,. k . , , , , . þ õ: . . 2.441 RESULTS AOF, Mcf/d: 3,108 C: 0.001150 100 - ' n: 1.000000 100 1;000 10,000 FIowRate,Mcfld POINT NO. Test Data FLOWING (Automatic) Q, Mcf/d BCPD BWPD FTP,Psia WHT, OF BHP, Psia COMMENT SHUT-IN 0 0 0 1,509 21 1,644 SIBHP 1 1,700 0 50 994 38 1,107 20/64 chk 2 1,300 0 29 1,092 35 1,205 16/64 chk 3 1,240 0 5 1,190 26 1,297 12/64 chk 4 430 0 0 1,355 31 1,472 8/64 chk These results were prepared using Reservoir Solutions Software. This is not Ryder Scott work product. Job Log Entry.' lme 11/22/0.3 6:55 11/22/0.37:07 11/22/0.37:14 11/22/0.3 7:16 11/22/0.37:24 11/22/0.3 7:36 11/22/03 7:42 11/2210.3 7:45 11/2210.3 7:50. 11/221038:04 11/2210.3 8:08 ll/22/0.38:11 ll/2210.38:15 11/22/038:18 ll/2210.3 8:52 11/22103 10:00. ll/22/03 10.: 15 11/22/0.3 10:34 ll/22/03 10:41 11/22/0.3 10:50. 11/22/03 11 :00 ll/22/0311:15 11/22/03 11 :30 ll/22/0313.:15 11/22/03 13.:57 11/22/03 14:13. 11/22/0.314:15 11/22/0314:45 ll/22/0315:03 11/22/03 15:15 11/22/03 15: 18 11/22/03 15:25 ll/22/03 15:26 ll/22/03 15:46 11122/03 16:03 11122/0.3 16:10. 11/22/0.3 16:30. 11122/03 17:30. ll/22/0.3 17:30 11/22/03 18:16 11122103 18:30. 11/22/0.3 18:45 11/22/03 20:00 ll/22/03 21 :00 11122/03 22:00. 11/22/0323:00 11/23/03 0:00 11123/03 1 :00 11/23/0.3 2:0.0 11123/0.33:0.0. 11123/0.3 4:00. 11/23/0.3 5 :0.0. 11/23/0.3 6:00 11/23/03 7:0.0. 11123/03 7:05 11123/03 8:0.2 11123/038:0.8 11123/038:15 11/23/03 9:04 11123/039:10. 11/23/03 10.:20. 11123/0.3 10.:30. ) Job Log ) Location NC-o.lb NC-o.lb NC..olb NC.o.lb NC-o.lb NC-o.lb NC..olb NC-Olb NC..olb NC..olb NC-Olb NC-Ol b NC-Olb NC..olb NC..olb NC-Olb NC..olb NC-olb NC-Olb NC.o.lb NC..o 1 b NC-Olb NC.o.lb NC..ol b. NC-o.lb NC..olb NC.o.lb NC..olb NC..olb NC-Olb NC..olb NC-Olb NC..olb NC..olb NC-Olb NC..olb NC..olb NC..ol b NC-Olb NC-Olb NC..olb NC-o.lb NC-o.lb NC..olb NC..olb NC.o.lb NC-Olb NC-Olb NC-ol b NC-Olb NC-olb NC.Dl b NC..olb NC..olb NC-olb NC-olb NC-olb NC-Olb NC-olb NC-olb NC-olb NC..olb Comment Open Well To Manifold. Open Well To Separator On 16/64 Adj. Choke Increased Choke To 18/64. Increased Choke To 22164. Increased Choke To 24/64. Increased Choke To 26/64. Decreased Choke To 24/64. Decreased Choke To 22164. Decreased Choke To 12164, Start MEOH Inj. Fluid To Surface. Switch To 1" Orifice Plate. Increased Choke To 18/64. Decreased Choke To 16/64. Decreased Choke To 14/64. Increased Choke To 18/64 To Obtain 50.0. mscf/d Rate Inoreased Choke To 20/64. Increased Vessel Back Pres.wre To. 500. psig. Increased Choke To 22/64. Decreased Choke To 20./64. WHP Going Under 1000.. 12,0.00. ppm Chloride Fluid Sample. 2% Solids Barite. Visible Fluid Level In Site Glass Of Separator. 2% Solids Barite, 10,000 ppm Chloride. Wtr Sample 8.3 Ibs Per Gallon. Divert To. 20/64 Positive Choke. Adjustable Choke Plugging. Water 3% S..olids (Barite), 10,000. ppm Chlorides. Divert To Adjustable Choke@ 18/64. Divert To 20/64 Positive Choke. Water 3% Solids (Barite). Water 3% Solids, 1.5% Formation Sand, 1.5% Barite. SII Well Per Leak In Tank. Repairing. Opened Well on 10164 Adjustable Choke. Opening Choke Slowly To. 20./64. Divert To 20/64 Positive Choke. WHP Bleeding Off, Orifioe Plate Not Lowered Yet. Lowered Orifioe Plate Start Metering Gas. Divert To 16/64 Adjustable Choke, To Reduce Sand Production. Divert To 16/64 Positive Choke. Water Sample 9,000 ppm Chloride, 20% Solids(Mud). Water Sample 9010 (Barite). Gas Gravity .58 Vao Truck On Location, Sucking Fluids Out Of Tank. Vao Truck Transfered 30. bbl off Tank. Water Sample 2% (Barite). 2.5% Solids (Barite), Chloride 10.,0.0.0 2% Solids (Barite) 2% S.olids (Barite). 2.5% Barite, Chlorides 9000. ppm 1.5% Barite, Chlorides 9000 ppm 1.5% Barite, Chlorides 900.0. ppm 2.0%Barite, Chlorides 9000. ppm 1.0% Barite, Chlorides 10.,0.00 ppm 1.5% Barite, Chlorides 10,0.00 ppm 1.0% Barite, Chlorides 10,00.0. 1.0.% Barite, Chlorides 10.,00.0. Divert thru adjustable ohoke Divert thru 12164 positive choke Divert thru 8/64 adjustable choke Divert Thru 8/64 Positive Choke Blowing Out Sand Drains On Separator. SII Well @ Manifold Monitor SII Build Up Blowing Fluids Out Of Separator. Unit De-Inventoried and Zero Energy State. Begin Rigging OffNC-Olb. Page 1 WeD Head I VA I OIA I I Choke Reading Time Location (Psig) (P$íg) (P$íg) (DegF) Setting 11122/037:00 NC-01b 0 0 1494 0 24 11/22/037:15 NC-Olb 0 0 1442 0 18 11122/037:30 NC-Olb 0 0 1400 0 24 11/22/037:45 NC-01b 0 0 1284 0 22 11/22/038:00 NC-01b 0 0 1317 0 12 11/22/038:15 NC-Olb 0 0 1250 0 16 11122/038:30 NC-01b 0 0 1227 0 14 11122/038:45 NC-01b 0 0 1205 0 14 11/22/039:00 NC-Olb 0 0 1156 0 18 11/22/039:15 NC-Olb 0 0 1118 0 18 11/22/039:30 NC-Olb 0 0 1092 0 18 11/22/039:45 NC-Olb 0 0 1103 0 18 11/22/03 10:00 NC-Olb 0 0 1133 0 18 11/22/0310:15 NC-Olb 0 0 1058 0 20 11122/03 10:30 NC-Olb 0 0 1096 0 20 11/22/03 10:45 NC-Olb 0 0 1013 0 20 11/22/03 11:00 NC-Olb 0 0 1013 0 20 11122/0311:15 NC-Olb 0 0 1107 0 20 11122/03 11:30 NC-Olb 0 0 1043 0 20 11/22/03 11:45 NC-01b 0 0 1080 0 20 11/22/03 12:00 NC-Olb 0 0 1107 0 20 11122/0312:15 NC-Olb 0 0 1058 0 20 11/22/03 12:30 NC-01b 0 0 1077 0 20 11122/0312:45 NC-Olb 0 0 1103 0 20 11/22/03 13:00 NC-Olb 0 0 1107 0 20 11/22/0313:15 NC-01b 0 0 1062 0 20 11/22/03 13:30 NC-01b 0 0 1043 0 20 11/22/03 13:45 NC-01b 0 0 1058 0 20 11122/03 14:00 NC-Olb 0 0 1137 0 18 11/22/03 14:15 NC-Olb 0 0 1073 0 20 11/22/0314:30 NC-Olb 0 0 1050 0 20 11/22/0314:45 NC-Olb 0 0 1039 0 20 11122/03 15:00 NC-01b 0 0 1039 0 20 11/22/03 15:15 NC-Olb 0 0 1291 0 10 11/22/03 15:30 NC-01b 0 0 1080 0 10 11122/03 15:45 NC-Olb 0 0 945 0 20 11/22/03 16:00 NC-Olb 0 0 979 0 20 11/22/0316:15 NC-Olb 0 0 1050 0 16 11122/03 16:30 NC-01b 0 0 1066 0 16 ll/22/03 16:45 NC-Olb 0 0 1050 0 16 11/22/03 17:00 NC-Olb 0 0 1050 0 16 1lI22/0317:15 NC-Olb 0 0 1047 0 16 1lI22/03 17:30 NC-Olb 0 0 1047 0 16 11122/03 17:45 NC-Olb 0 0 1050 0 16 11122/03 18:00 NC-Olb 0 0 1050 0 16 11/22/03 18:15 NC-Olb 0 0 1050 0 16 11122/03 18:30 NC-01b 0 0 1050 0 16 11122/03 18:45 NC-01b 0 0 1058 0 16 11122/03 19:00 NC-Olb 0 0 1050 0 16 11/22/0319:15 NC-Olb 0 0 1050 0 16 11122/03 19:30 NC-Olb 0 0 1050 0 16 11122/03 19:45 NC-Olb 0 0 1058 0 16 11122/0320:00 NC-Olb 0 0 1066 0 16 1lI22/0320:15 NC-Olb 0 0 1077 0 16 11122/0320:30 NC-Olb 0 0 1073 0 16 11122/0320:45 NC-Olb 0 0 1073 0 16 11/22/0321:00 NC-Olb 0 0 1073 0 16 1lI22/0321:15 NC-Olb 0 0 1077 0 16 1lI22/0321:30 NC-Olb 0 0 1080 0 16 11/22/0321:45 NC-01b 0 0 1073 0 16 11122/0322:00 NC-Olb 0 0 1066 0 16 11122/0322:15 NC-Olb 0 0 1080 0 16 1lI22/0322:30 NC-Olb 0 0 1070 0 16 11/22/0323:15 NC-Olb 0 0 1077 0 16 11/22/0323:30 NC-Olb 0 0 1077 0 16 11/22/0323:45 NC-Olb 0 0 1077 0 16 11/23/03 0:00 NC-01b 0 0 1073 0 16 1lI23/030:15 NC-01b 0 0 1077 0 16 ) 15 Min Reads Skid BS&W Vessel BS&W I Solids I Carbo/íte I Gas 1 Liquid ('(o) "" "" (Psig) (DegF) (DegF) 0.00% 29.00% 30.00% 0 61 68 0.00% 0.00% 0.00% 26 41 46 0.00% 0.00% 0.00% 94 36 36 0.00% 0.00% 0.00% 148 21 21 0.00% 0.00% 0.00% 86 24 26 100.00% 0.00% 0.00% 217 30 32 100.00% 0.00010 0.00% 131 23 26 100.00% 0.00% 0.00% 122 23 27 100.00% 0.00% 0.00010 158 23 25 100.00% 0.00% 0.00% 135 20 23 100.00% 0.00% 0.00% 141 20 24 100.00% 0.00% 0.00% 100 19 22 100.00% 0.00% 0.00% 56 20 24 100.00% 0.00% 0.00% 502 40 41 100.00% 0.00% 0.00% 473 32 36 100.00% 0.00% 0.00% 472 30 34 100.00% 2.00% 0.00% 539 36 43 100.00% 2.00% 0.00% 377 31 46 100.00% 2.00% 0.00% 716 42 45 100.00% 2.00% 0.00% 605 37 45 100.00% 2.00% 0.00% 535 38 45 100.00% 2.00% 0.00% 612 41 46 100.00% 2.00% 0.00% 433 33 47 100.00% 3.00% 0.00% 445 36 47 100.00% 3.00% 0.00% 434 34 47 100.00% 3.00% 0.00% 553 38 47 100.000/0 3.00% 0.00% 512 39 47 100.00% 3.00% 0.00% 530 40 47 100.00% 3.00% 0.00% 433 37 47 100.00% 3.00% 0.00% 491 36 48 100.00% 3.00% 0.00% 489 37 48 100.00% 3.00% 0.00% 481 39 49 100.00% 3.00% 0.00% 498 41 51 100.00% 3.00% 0.00% 1 38 49 100.00% 3.00% 0.00% 472 32 48 100.00% 3.00% 0.00% 488 34 49 100.00% 3.00% 0.00% 504 38 48 100.00% 3.00% 0.00% 494 39 48 100.00% 3.00% 0.00% 501 37 48 100.00% 3.00% 0.00% 492 36 48 100.00% 20.00% 0.00% 562 38 47 100.00% 20.00% 0.00% 487 35 47 100.00% 20.00% 0.00% 486 35 47 100.00% 9.00% 0.00% 519 36 47 100.00% 9.00% 0.00% 499 35 47 100.00010 9.00% 0.00% 487 36 47 100.00% 9.00% 0.00% 458 3S 46 100.00% 9.00% 0.00% 434 33 46 100.00% 9.00% 0.00% 461 35 47 100.00% 2.00% 0.00% 459 35 47 100.00% 2.00% 0.00% 542 37 47 100.00% 2.00% 0.00% 505 37 47 100.00% 2.00% 0.00% 516 37 47 100.00% 2.00% 0.00% 489 36 47 100.00% 2.00% 0.00% 499 36 47 100.00% 2.00010 0.00% 498 36 47 100.00% 2.00% 0.00% 502 36 47 100.00% 2.00% 0.00% 499 36 47 100.00% 2.00% 0.00% 496 36 47 100.00% 2.00% 0.00% 502 36 47 100.00% 2.00% 0.00% 50S 36 47 100.00% 2.00% 0.00010 498 36 47 100.00% 2.00% 0.00% 508 35 47 100.00% 2.50% 0.00% 499 35 47 100.00% 2.50% 0.00% 501 35 47 100.00% 2.50010 0.00% 505 35 47 100.00% 1.50% 0.00% 512 35 47 100.00% 1.50% 0.00% 508 35 47 Pagel ') Gas VI"'''''' I I I Size Rate Inçrement Total (in) (mmsçfJd) {mscffd} {mscfld} 2 0.00 0.00 0.00 2 0.01 0.00 0.00 2 0.04 0.00 0.00 2 0.06 0.00 0.00 1 0.00 0.00 0.00 1 0.70 0.48 1.09 1 0.43 0.30 6.53 1 0.40 0.28 10.87 1 0.52 0.36 15.91 1 0.44 0.31 20.82 1 0.47 0.33 25.52 1 0.34 0.24 29.67 1 0.19 0.15 32.70 1 0.68 0.17 35.51 1 0.13 0.09 40.61 1 0.52 0.35 46.92 1 1.01 0.71 53.56 1 0.27 0.24 62.80 1 0.48 0.34 66.83 1 0.97 0.60 74.12 1 0.83 0.61 83.32 1 1.08 0.69 90.90 1 0.71 0.57 100.86 1 0.90 0.66 110.31 1 0.44 0.41 117.43 1 1.18 0.80 126.51 1 1.47 1.02 141.73 1 1.49 1.04 157.32 1 1.19 0.56 171.93 1 1.07 l.l6 180.98 1 1.67 1.15 198.95 1 1.67 1.16 216.46 1 1.74 1.21 233.98 1 0.00 0.00 238.40 1 0.03 0.02 238.84 1 0.03 0.02 239.35 1 1.70 1.17 255.08 1 1.03 0.72 268.21 1 1.36 0.89 280.44 1 1.28 0.89 293.42 1 1.16 0.81 306.00 1 1.22 0.85 319.03 1 1.22 0.85 331.46 1 1.18 0.82 343.81 1 l.l6 0.82 356.21 1 1.20 0.83 368.56 1 1.20 0.83 380.99 1 0.74 0.81 393.40 1 1.22 0.86 405.65 1 1.21 0.84 418.15 1 l.l6 0.80 430.08 1 l.l5 0.79 442.54 1 1.23 0.85 454.86 1 1.29 0.90 467.77 1 1.33 0.95 480.77 1 1.21 0.85 493.61 1 1.24 0.82 506.43 1 1.04 0.85 519.44 1 1.09 0.83 532.31 1 1.30 0.86 545.47 1 1.26 0.88 558.40 1 1.15 0.87 571.40 1 1.34 0.89 584.75 1 1.21 0.88 624.32 1 1.25 0.88 637.47 1 1.28 0.89 650.75 1 1.30 0.87 664.01 1 1.26 0.91 677.46 Liquid Rate Ilnçrement I Total (bblld) (bbl) {bbl} 4.6 0.0 0.0 4.6 0.0 0.0 4.6 0.0 0.0 4.6 0.0 0.0 4.6 0.0 0.0 4.6 0.0 0.0 4.6 0.0 0.1 4.6 0.0 0.1 4.6 0.0 0.1 4.6 0.0 0.2 4.6 0.0 0.2 4.6 0.0 0.3 4.6 0.0 0.3 0.0 0.0 0.0 0.4 0.0 0.0 0.0 0.0 0.0 0.4 0.0 0.0 0.4 0.0 0.0 0.0 0.0 0.0 0.4 0.0 0.0 0.4 0.0 0.6 0.4 0.0 0.6 0.0 0.0 0.7 0.4 0.0 1.0 43.3 0.0 2.8 57.4 0.0 2.9 391.3 0.3 5.9 271.6 0.2 7.4 100.2 0.1 10.6 0.0 0.0 10.8 237.7 0.2 11.4 153.3 0.1 14.3 0.0 0.0 14.9 0.0 0.0 15.5 0.0 0.0 15.7 0.0 0.0 15.7 240.3 0.2 17.0 166.7 0.1 19.2 61.2 0.0 20.3 0.0 0.0 20.5 0.4 0.0 20.5 0.0 0.0 20.5 67.5 0.1 21.9 0.0 0.0 22.3 255.0 0.2 23.2 0.0 0.0 24.5 0.0 0.0 24.5 154.6 0.1 25.5 0.0 0.0 26.7 0.4 0.0 26.7 63.7 0.0 27.9 75.3 0.1 28.6 139.2 0.1 29.9 0.0 0.0 30.5 36.8 0.0 30.5 132.8 0.1 31.8 0.4 0.0 32.4 0.0 0.0 32.4 0_0 0.0 33.7 141.8 0.1 34.1 103.4 0.1 35.6 0.0 0.0 36.4 0.0 0.0 36.4 0.0 0.0 382 49.6 0.0 39.0 120.7 0.1 39.5 44.5 0.0 40.3 0.0 0.0 40.4 ) ) 15 Min Reads 11/23/030:30 NC-Olb 0 0 1077 0 16 100.00% 1.50% 0.00% 508 36 47 1 1.31 0.87 690.62 0.4 0.0 40.9 11/23/030:45 NC-Olb 0 0 1077 0 16 100.00% 1.50% 0.00% 511 36 47 1 1.32 0.90 703.90 0.0 0.0 41.2 11/23/03 1:00 NC-Olb 0 0 1077 0 16 100.00% 1.50% 0.00% 510 35 47 1 1.29 0.89 717.19 86.1 0.1 42.3 11/23/03 1:15 NC-Olb 0 0 1077 0 16 100.00% 1.50% 0.00% 510 35 47 1 1.27 0.89 730.61 81.6 0.1 42.8 11/23/03 1:30 NC-Olb 0 0 1077 0 16 100.00% 1.50% 0.00% 503 35 47 1 1.31 0.92 744.11 77.2 0.0 43.1 1lI23/03 1:45 NC-Olb 0 0 1080 0 16 100.00% 1.50% 0.00% 496 35 47 1 1.26 0.90 757.49 0.4 0.0 43.9 11/23/032:00 NC-Olb 0 0 1077 0 16 100.00% 1.50% 0.00% 501 35 47 1 1.31 0.91 770.73 59.8 0.0 44.3 11/23/032:15 NC-01b 0 0 1077 0 16 100.00% 1.50% 0.00% 513 35 47 1 1.30 0.89 783.94 71.4 0.0 44.6 11/23/032:30 NC-Olb 0 0 1080 0 16 100.000/0 2.00% 0.00% 515 35 47 I 1.31 0.91 797.48 0.4 0.0 45.1 11/23/032:45 NC-Olb 0 0 1077 0 16 100.00% 2.00% 0.00% 511 35 47 I 1.30 0.89 811.03 0.0 0.0 45.3 11/23/033:00 NC-Olb 0 0 1077 0 16 100.00% 2.00% 0.00% 513 35 47 1 1.28 0.89 824.54 0.0 0.0 45.7 11/23/033:15 NC-Olb 0 0 1077 0 16 100.00% 2.00% 0.00% 515 36 47 1 1.31 0.90 838.13 62.4 0.0 46.0 1lI23/033:30 NC-Olb 0 0 1077 0 16 100.00% 1.00% 0.00% 505 35 47 1 1.29 0.90 851.69 45.2 0.0 46.3 11/23/033:45 NC-Olb 0 0 1073 0 16 100.00% 1.00% 0.00% 528 36 47 I 1.30 0.91 865.28 0.4 0.0 46.4 11/23/034:00 NC-Olb 0 0 1077 0 16 100.00% 1.00% 0.00% 530 36 48 I 1.30 0.91 878.76 43.9 0.0 46.7 11/23/034:15 NC-Olb 0 0 1080 0 16 100.00% 1.00% 0.00% 500 35 48 I I.l2 0.89 892.26 0.0 0.0 47.3 1lI23/034:30 NC-Olb 0 0 1077 0 16 100.00% 1.500/0 0.00% 502 35 47 1 1.22 0.90 905.71 61.2 0.0 47.6 11/23/034:45 NC-Olb 0 0 1080 0 16 100.00% 1.50% 0.00% 507 35 47 I 1.25 0.86 918.83 90.6 0.1 48.3 11/23/035:00 NC-Olb 0 0 1080 0 16 100.00% 1.50% 0.00% 506 35 47 I 1.30 0.91 932.43 0.0 0.0 48.7 1lI23/035:15 NC-Olb 0 0 1077 0 16 100.00% 1.50% 0.00% 500 35 47 1 1.30 0.92 946.05 75.3 0.0 49.0 11/23/035:30 NC-Olb 0 0 1080 0 16 100.00% 1.50% 0.00% 502 35 47 1 1.27 0.89 959.53 0.4 0.0 49.5 11/23/035:45 NC-Olb 0 0 1084 0 16 100.00% 1.00% 0.00% 496 35 47 I 1.19 0.88 972.83 0.0 0.0 49.5 11/23/036:00 NC-Olb 0 0 1080 0 16 100.00% 1.00% 0.00% 500 35 47 1 1.26 0.90 986.15 0.0 0.0 49.5 ll!23/036:15 NC-Olb 0 0 1084 0 16 100.00% 1.00% 0.00% 506 35 47 1 1.30 0.87 999.47 0.4 0.0 49.6 1lI23/036:30 NC-Olb 0 0 1077 0 16 100.00% 1.00% 0.00% 501 35 47 1 1.23 0.89 1012.81 0.0 0.0 50.3 1lI23/036:45 NC-Olb 0 0 1077 0 16 100.00% 1.00% 0.00% 505 35 47 1 1.30 0.88 1026.17 71.4 0.0 50.7 11/23/037:00 NC-Olb 0 0 1167 0 16 100.00% 1.00% 0.00% 486 35 47 1 0.07 0.31 1038.26 189.7 0.0 51.7 11/23/037:15 NC-Olb 0 0 1167 0 12 100.00% 0.00% 0.00% 492 32 47 1 1.21 0.69 1047.30 0.0 0.0 51.9 1lI23/037:30 NC-Olb 0 0 1167 0 12 100.00% 0.00% 0.00% 497 29 47 1 1.24 0.66 1057.60 0.0 0.0 51.9 1lI23/037:45 NC-Olb 0 0 1171 0 12 100.00% 0.00% 0.00% 494 28 47 1 1.19 0.65 1067.70 0.0 0.0 51.9 1lI23/038:00 NC-Olb 0 0 1175 0 12 100.00% 0.00% 0.00% 493 26 47 1 1.24 0.71 1077.61 0.0 0.0 51.9 11/23/038:15 NC-Olb 0 0 1250 0 8 100.00% 0.00% 0.00% 491 29 47 1 0.04 0.23 1083.64 0.0 0.0 52.0 11123/03 8:30 NC-Olb 0 0 1257 0 8 100.00% 0.00% 0.00% 502 31 47 1 0.38 0.29 1088.06 0.0 0.0 52.0 11/23/038:45 NC-Olb 0 0 1220 0 8 100.00% 0.00% 0.00% 501 31 47 I 0.33 0.29 1092.41 0.4 0.0 52.0 1lI23/039:00 NC-Olb 0 0 1340 0 8 100.00% 0.00% 0.00% 495 31 47 1 0.43 0.35 1097.29 0.0 0.0 52.0 11/23/039:15 NC-Olb 0 0 1434 0 8 0.00% 0.00% 0.00% 61 22 41 I 0.01 0.00 1098.56 0.0 0.0 52.0 llf23/039:30 NC-Olb 0 0 1461 0 8 0.000/0 0.00% 0.00% 59 27 41 1 0.01 0.00 1098.62 0.0 0.0 52.0 11/23/039:45 NC-Olb 0 0 1468 0 8 0.00% 0.00% 0.00% 1 29 41 1 0.00 0.00 1098.62 0.4 0.0 52.0 1lI23/03 10:00 NC-Olb 0 0 1461 0 8 0.00% 0.00% 0.00% 0 32 41 1 0.00 0.00 1098.62 0.0 0.0 52.0 11/23/0310:15 NC-Olb 0 0 1412 0 8 0.00% 0.000/0 0.00% 4 33 42 1 0.00 0.00 1098.62 0.0 0.0 52.0 11/23/03 10:30 NC-Olb 0 0 9 0 8 0.00% 0.00% 0.00% 3 35 41 1 0.00 0.00 1098.63 0.4 0.0 52.0 1lI23/03 10:45 NC-Olb 0 0 4 0 8 0.00% 0.00% 0.00% 2 35 41 1 0.00 0.00 1098.63 0.0 0.0 52.1 11/23/03 11:00 NC-Olb 0 0 9 0 8 0.00% 0.00% 0.00% 2 35 41 1 0.00 0.00 1098.63 0.0 0.0 52.1 ll!23/03 11:15 NC-Olb 0 0 4 0 8 0.00% 0.00% 0.00% 2 35 42 1 0.00 0.00 1098.63 0.0 0.0 52.1 1lI23/03 11:30 NC-Olb 0 0 9 0 8 0.00% 0.00% 0.00% 2 35 42 1 0.00 0.00 1098.63 0.0 0.0 52.1 Page 2 DEC-22-03 09:26 AM !o INDW~TRIAL INSTRUMENT ) 907 283 7766 P.04 ) EG&G Chandler Engineering Model 292 BTU Analyzer Test time: Dec.12 03 10:29 Test #:1 Calibration #:Default Location No. :1 Methane Ethane Moisture Nitrogen ( CO2 ) --- Standard/Dry Analysis--- Mole' BTU* R.Den,* GPM*. 96.224 974.13 0,5330 -- 0,115 2.03 0.0012 0,0307 0.000 0.00 0.0000 3,353 0.00 0.0324 0.309 0.00 0.0047 Saturated/Wet Analysis Mole' BTU* R.Den.* 94.549 957.18 0.5237 0.113 2.00 0.0012 1,740 0.88 0.0108 3,295 0.00 0.0319 0.303 0.00 0.0046 Total 100.00 976.2 0.5713 0.0307 100,00 * : Uncorrected for compressibility at 60,OF & 14.730PSIA. **: Liquid Volume reported at 60.0F. 960.1 0.5722 Standard/Dry Analysis Saturated/Wet Analysis Molar Mass = 16.547 16.572 Relative Density := 0.5722 0.5731 compressibility Factor = 0.9981 0.9980 Heating Value II!: 22336. Btu/lb 21933. Btu/lb Heating Value = 978.1 Btu/CF 962.0 Btu/CF Absolute Gas Density := 43.7884 lbm/10OOCF 43.8606 lbm/1000CF Wobbe Index = 1271.78 C6+ La~~ update: GPA ~261-90. C6+ BTU/CF 5065.8, C6+ Ibm/Gal 5.64250, and C6+ Mol.Wt. 92.00. AURORA GAS NCU # 1 B Sample Date: 11..22-03 Run Date: 12-12-03 Press: 550# RUN 1 Re: Nicolai Creek Production ) ) Subject: Re: Nicolai Creek Production From: Thomas Maunder <tom_maunder@admin.state.ak.us> Date: Mon, 08 Dec 2003 1 Ü: 12:22 -0900 rO:,.d~ane vaagen<duane@fairWeather.com>. .. . ... .. ,. .... ÇC.= John D Harti <jack~hartz@admiri.statë~*.~U$?,. ~t¥ye:Davies:::-,.:'..: ~ -' '. :..;. <steve_dayies~a~mìll.state.ak.us>,:S~è~e'Mc¥ajps;::'...' .. ,..., . ;~~~;D~:~~=~~s~te~~~S~ount~111štate;ak.uS?t.'.\i<.h";!:Hi:... '.J. Thanks much Duane. We will look forward to receiving the testing information. Torn Maunder, PE AOGCC duane vaagen wrote: t\ :) ~ &.Od - \ <0:) l<O\o-()S~ (;}.() ó--- dO~' ~<-\.J \ \~ Torn: \ \ Per our phone conversation this morning, this email is being submi tted on behalf of Aurora Gas, LLC. We just recently wrapp.ed up testing of the NCD 1B, NCD 2, NCD 9, and Mobil Moquawkie No.1 (late November, the results of which were just received from the testing contractor). Aurora has installed the production facility and gathering lines to begin production from the (3) Nicolai Creek wells located in a cluster on the beach near Shirleyville. 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 1B, 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. 10f2 12/8/2003 10:12 AM ?-~Aurora Gas, LJC www.aurorapower.com 16-0ctober-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 lB. Dear Commissioner Taylor: ~Od- \ <0 d-- Aurora Gas, LLC hereby submits the required fmal completion paperwork for work done on the Nicolai Creek Unit No. 1B this past summer. Please fmd attached the following information required by 20 AAC 25.070 (3) for your review. Two (2) originals: AOOCC Form 10-407 for the well; 1) 2) Two (2) copies: Description of well work activities with summary of daily well operations. Includes diagrams of fmal well configuration. 3) Two (2) copies: Final well survey with floppy disk containing digital survey information. This well was testeJ briefly during perforating operations but has not undergone a full multi-point back-pressure test. It is anticipated that well test procedures will be performed mid October 2002, with the results of this testing being reported as soon as is practically possible thereafter. 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 ard Jones xecutive Vice President ~ RECEIVED JUN 0 9 2003 cc: Andy Clifford Duane Vaagen Alaska Oil & Gas Cons. Commission Anchorage Attachments 10333 Richmond Avenue, Suite 710. Houston, Texas 77042. (713) 977-5799 . Fax (713) 977-1341 1029 West 3rd Avenue, Suite 220 . Anchorage, Alaska 99501 . (907) 277-1003. Fax (907) 277-1006 STATE OF ALASKA ALASKA ( )AND GAS CONSERVATION }MMISSION . WELL COMPLETION OR RECOMPLETION REPORT AND ~OG 1. Status of Well Classification of Servioe Well . OIL: GAS: X 2. Name of Operator Aurora Gas LLC 3. Address Resolution Plaza, Suite 710, Anchorage AK 99501 4. Location otwell at surfaoe 1999' FSL, 186'~L, S29, T11N, R12 W SM ASPN 2565238.429, ASPE 241509.651 At Top Producing Interval At 3191' MD 1625' FSL, 291' FWL, S29, T11N, R12W SM At Total Depth 3672' MD 1625' FSL, 289' FWL, S29, T11N,R12W SM 5. Elevation in feet (indicate KB, DF, etc.) 35.5' AMSL (DF) 12. Date Spudded 13. Date T.D. Reached 8/11/2002 9/10/2002 17 . Total Depth (MD+ TVD) 18. Plug Back Depth (MD+ TVD) 3672' MD (3618' TVD) 3600' MD (3510' TVD) 22. Type Electric or Other logs Run GRlCCl Correlation, CBl, RST, CO 23. SUSPENDED: ABANDONED: SERVICE: 7. Permit Number 202-162 8. API Number 50- 283-10020-02 9. Unit or lease Name Nicolai Creek Unit 10. Well Number NCU #1 B 11. Field and Pool 6. lease Designation and Serial No. ADL17585 14. Date Comp., Susp. or Aband. 9/2312002 Completed 19. Directional Survey Yes: X No: Nicolai Creek Gas Field 15. Water Depth, if offshore 16. No. of Completions NA feetMSL 1 20. Depth where SSSV set 21. Thicknes$ of Permafrost NA feet MD ~A CASING SIZE WT. PER FT. GRADE 20" 94# H-40 13 3/8" 54# J-55 103/4" 40.5# J-55 7" 23# J-55 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM 0 232' 0 1904' 0 2186' 0 3648' HOLE SIZE 26" 17 1/2" 12 1/4" 8 1/4" CEMENTING RECORD 300 sx 1530 sx 900 sx 149 bbls AMQUNT PULLED I . 0 0 0 0 SIZE 27/8" TUBING RECORD DEPTH SET (MD) 3112' PAq<ER SET (MQ) 3112' 24. Perforations open to Production (MD+lVD of Top and Bottom and interval, size and number) 25. 3191' - 3211' MD (3136' - 3156'lVD) 5 SPF 41/2 HSD .5" Diameter 3371' - 3401' MD (3317' - 3347' TVD) 5 SPF 41/2 HSD .5" Diameter 3560' - 3575' MD (3506' - 3521' TVD) 5 SPF 41/2 HSD .5" Diameter 26. ACID, FRACTURE, CEMENT SQUEEZE,; ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF fTERIAL U~ED Date of Test PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.) Flowing Gas through Choke and Seperator PRODUCTION FOR OIL-BBL GAS-MCF TEST PERIOD => 0 Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MCF Press. 0 24-HOUR RATE => 0 0 28. CORE DATA Brief descóption of lithology. porosity, fractures. apparent dips and presenoe of oil, gas or water. Submit core chips. Hours Tested WATER-BBL CHOKE SIZE GAS-OIL RATIO 0 ~ WATER-BBL OIL GRAVITY-API (corr) 0 NA 27. Date First Production None r 1/ I -- \..')1 Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate 29. ') 30. GEOLOGIC MARKERS NAME )MATION TESTS Indude interval tested, pressure data, all fluids recovered and gravity, TRUE VERT. DEPTH GOR, and time of each phase. Tyonek MEAS. DEPTH Perfs @ 3191' - 3211' 3371' - 3401' 3560' - 3575' 1430 - 1400 hrs: 3136' - 3156' 3317' - 3347' 3506' - 3521' 1520 hrs: 1530 hrs: 1540 hrs: 1551 hrs: 1630 hrs: 4 swab runs to 1500 ft, well flowing, flow until gas to surface, recover 23.5 bbl water. SI and direct flow to choke and test separator. SITP 230 psi Flow to separator on 10/64" choke FTP inc to 640 psi on 16/64" choke FTP inc to 800 psi on 16164" choke At 1060 psi, choke plugged offw/sand, SI and clea~ out choke 30 bbls total water recovered, SI SITP 1400 psi, open well for four (4) hours, vary chóke sizes to 36/64'\vlbp on separator of -400 psi and FTP - 1150 - 1225 psi Final flow rate = 1407 mcfpd at 1190 psi. Recovered 42 bbls water during test, (35.6 bbl to btm perf + fluid lost to perfs). 4.8 bph (8.8ppg) final water s)roduction rate. 1630 hrs: 1631 hrs: 1635 hrs: 1730 hrs: NOTE: Final FTP at shut in, 1190 psi. SITP at 1260 psi SITP at 1340 psi SITP at 1475 psi. Flow test time and rate limited due to sand screens. Cannot perform AOFP test until proper screen break performed. 31. USTOF ATTACHMENTS Wellbore schematic, CompletionTally, Summary of Well Work and Operations, Survey Report, CBl, Sonic & Induction logs (Hardcopy & Digital), 32. I hereby certify that the foregoing is true and correct to the best of my knowledge . Signed ~ ~~ TrUe Vice President C P'" - - INSTRUCTIONS Date /0/10/02.- General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other space on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the productin intervals for only the interval reported in item 27. Submit a separate fonn 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 supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing. Gas lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Fonn 10-407 ') ) WELL RE-ENTRY, RE-DRILL, AND RE-COMPLETION REPORT NICOLAI CREEK UNIT NO. IB ShirleyviUe, Alaska /~?-yAurora Gas, LLC 9-0ctober- 2002 ') ) Background Information: The Nicolai Creek Unit No. lA well was drilled to TD in 1966. After producing gas commercially for a short time, the well was shut in until 1991, at which time it was suspended by placing a series of cement retainers and cement plugs in the wellbore. Aurora Gas, LLC submitted a Sundry Application to re-enter and a Permit to Drill Application to sidetrack the NCU 1 A well and complete it as NCD 1 B, a gas producer. Well re-entry and re-completion activities on the Nicolai Creek Unit No.1 B well began August 11 th 2002, when the rig, Aurora Well Service Rig No.1 was moved from the adjacent, recently completed Nicolai Creek Unit No.2. The location was prepared by laying down a geo-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 daily operations carried out during the re- entry, drilling and completion work on the NCU IB well. Attachment I is a schematic of the well as completed and Attachment II is a tally and diagram of the actual completion e,quipment 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: l1-Aug-2002 12-Aug-2002 13-Aug-2002 14-Aug-2002 15-Aug-2002 16-Aug-2002 17-Aug-2002 18-Aug-2002 19-Aug-2002 Layout felt and Herculite, spot rig components. Rig up continued. . . Rig up continued, modify pit system, and general rig mods. Nippl~ up 11" 5M annular Rig up continued, modify pit system, and general rig mods. Nipple up 11" 5M annular Rig up continued, fabricate trip I pill tank, repair stairs, spot MWD, install Swaco shaker. RU continued.... Rig up continued, fabricate flow line BOP to shaker and flange up. Modify pits, continue repairs and modifications. Rig up continued, fabricate flow line BOP to shaker and flange up. Modify pits, continue repairs and modifications. RU continued. .. 20-Aug-2002 21-Aug-2002 22-Aug-2002 23-Aug-2002 24-Aug-2002 25-Aug-2002 26~Aug-2002 27-Aug-2002 28-Aug-2002 ) ') RU continued. Perfonn BOP test, choke manifold leaking and blind rams leaking. Replace seals on blinds and grease repair valves on choke manifold. Replace 3" pop off valve on PZ7 pump. Perform BOP test, AOGCC witness waived by Mr. Tom Maunder. Test successful. PU 9.875" 6-blade Baker Oil Tool mill, begin drilling cement in NCU lA, drilling fluid is Na/KCL with viscosifier as needed. Mud weight 9.3 ppg, depth 73 ft. Drill hard cement, slow going. Welder performing rig modifications. Mud weight 9.3 ppg, depth 267 ft. Drill hard cement, notice gas in mud at 4 - 50 units, begin weight up of drilling fluid. Welder performing rig modifications. Mud weight 9.3 ppg, depth 462 ft. Drill hard cement, power swivel stalling out with 10K WOM. Gas in mud at 4 - 50 units. Welder performing rig modifications. Mud weight 9.3 ppg, depth 668 ft. Drill hard cement, POOH and lay down mill, PU Varel LH2 bit. RIH, drill cement to packer at 698 ft. Drilling packer, packer spinning and power swivel locking up. Welder working on rig modifications. Mud weight 9.3 ppg, depth 698 ft. Drill out EZSV, drill cement and plug debris to 2414 ft. Circulate and condition mud scraper trip. Welder working on rig modifications. Mud weight 9.3 ppg, depth 2414 ft. Circulate, work pipe to clean EZSV debris from hole. TOH, flow test, TOH. Test BOP and gas detection system. BOP annular locked in half closed position, troubleshoot. Gas detection system not functioning properly, troubleshoot. Welder working on rig modifications. Mud weight 9.3 ppg, depth 2414 ft. Work annular on BOP, rinse free possible junk from below piston. Open / close numerous times, works fine. PU and RIH with 1 0 ~" casing scraper to 2414 ft, no restrictions, circulate condition fluids. Flow check, POOH, LD casing scraper. Safety meeting, RU ScWumberger eline, set bridge plug at 2212 ft, POOH, RD and release ScWumberger. P-test 10 3!.J" casing to 1500 psi / 30 min, OK. RIH, tag and verify BP depth at 2212 ft. Circulate, condition fluids, clean pits, repair mud pwnps. Welder working on rig modifications. Mud weight 9.8 ppg, depth 2212 ft. 29-Aug-2002 30-Aug-2002 31-Aug-2002 1-Sept-2002 2-Sept-2002 ~ c... '-.) \ - ~ " 3-Sept-2002 4-Sept - 2002 5-Sept-2002 6-Sept - 2002 7-Sept-2002 ') ) Installing hydraulic catheads, mix milling fluids and roll fluids in hole. Clean repair rig equipment and pumps. Welder working on rig modifications. Prepare whipstock for RIH. Mud weight 9.8 ppg, depth 2212 ft. Installing hydraulic catheads, prepare milling fluids. General rig repair and modifications. Prepare whipstock for RIH. Mud weigJ;lt 9.8 ppg, depth 2212 ft. Installing hydraulic catheads, prepare milling fluids. General rig repair and modifications. Prepare whipstock for RIH. Mud weigbt 9.8 ppg, depth 2212 ft. Mix mud, POOH, RU floor to pick up whipstock / mill assembly. Service rig, install ditch magnets in shaker, move BRA to pipe racks for pick-up. Replace tong gauge, PU whipstock / mill / MWD assembly. Circulate to test MWD tool, OK, RIH. Mud weight 9.8 ppg, depth 2212 ft. Pre-Job safety meeting, work on desander and RU lines to degasser. RIH, RU power swivel and circulate well. Orient and set whipstock. Top of whipstock at 2186 ft. Hold safety meeting and begin casing milling operations. Mud weight 10 ppg, depth 2200 ft. Milling window, circulate and clean hole with sweeps. Mud V weight 10 ppg, depth 2204 ft. ~C~ \ - ~ Pre-job safety meeting, pump sweep, POOH. LD 6 in collars and inspect mills. Test BOPE, OK. Change BRA, RIH, PU power swivel, break circulation, mill window. Mud weight 10.2 ppg, depth 2204 ft. Mill, circulate high-vis sweep. Had 15 gallon diesel spill on location, reported and cleaned up. Mud weight 10.2 ppg, depth 2218 ft. Circulate and condition mud. Perfonn FIT with MWE @ 17 ppg. POOH and lay down mill assembly, pick up directional drilling assembly. TIH begin drilling. Mud weight lOA ppg, depth 2370 ft. Drilling, power cable to desander rubbed through, and shorted out, repair cable. Drilling. Mud weight 10.4 ppg, depth 2680 ft. 8-Sept-2002 9~Sept-2002 lO-Sept-2002 II-Sept - 2002 12-Sept-2002 1.3-Sept-2002 14-Sept-2002 ) ) Drilling, circulate and condition mud, pump dry job, short trip to 2185 ft, no problems. TIH and drilling. Mud weight 10.4 ppg, depth 2949 ft. Drilling, circulate and condition mud, drilling. Mud weight 10.6 ppg, depth 3317 ft. Drill to TD at 3672 ft, circulate and condition mud. Short trip to 2648 ft, hole tight from 3423 - 3360 ft and from 2957 - 2896 ft. Mud weight 10.6 ppg, depth 3672 ft. Safety meeting, TIH, condition mud and hole for wire-line logs. POOH and LD BHA. Pull wear bushing, set test plug and test BOPE. Pipe rams failed, open rams and clean out cuttings, close and re-test. Re-test BOP stack and accumulator. RU Schlumberger, RIH with Platfonn Express and following sensors: DSI "Dipole Shear Sonic Imager" and the AITH "Array Induction Imager Tool (H). Hole tight at 2850 ft and 3300 ft. Wireline TD at 3675 ft, no corrections applied. Mud weight 10.6 ppg, depth 3672 ft. POOH with logging suite, TIH, circulate and reciprocate pipe while condition hole for casing. Waiting on set of 7" rams ordered out of Bakersfield, California. Rams required before running casing. Have decided to run 7" from TD to surface as opposed to original plan of just running 7" liner, and plan is to stage cement the same in place. Mud weight 10.6 ppg, depth 3672 ft. WIO on 7" rams. Rams arrive, POOH, LD BHA and pull wear bushing, set test plug. Change out 7" rams, test to 1000 psi. Pull test plug, prepare to run 7" casing, hold safety meeting. Pick up 7'.' casing, MU shoe and float collar. Running 7" casing. Mud weight 10.6 ppg, depth 3672 ft. Running 7" 23# J-55 casing from surface to TD at 3650 ft while installing centralizers on way in hole. Circulate and condition mud while reciprocating pipe. Detennined 2-stage cement job not possible as baftle plate installed in wrong location, i.e., right below stage collar. Cementing program revised to cement casing as a single stage with cement deliberately under-displaced to ensure sufficient cement in shoe area. No plugs dropped due to location of baffle plate. ~ Casing cemented as follows: 5 bbls fresh water followed with 30 bbls of 10.5 ppg spacer, 83 bbls of 12.5 ppg lead slurry, 67 bbls of 15.8 ppg tail slurry displaced into place with 142 bbls 10.5 ppg 15-Sept-2002 16-Sept-2002 17-Sept-2002 18-Sept-2002 19-5ept-2002 20-Sept-2002 ) drilling mud. Cement was displaced until 2 bbls 14 ppg cement observed at surface. After displacing system into place, well shut in with 280 psi backpressure on casing. Set slips wi 160,000 Ibs. Prepare to nipple down. WOC. Test 7" hanger pack-off to 500 psi, ND and rough cut 7" casing. ND and remove BOP. NO tubing head, test all seals to 3000 psi I 30 min, OK. NU BOP, test all to 3000 psi, OK. Modify flow line, test all and transfer fluids. Hold safety meeting, make up 6 1/8" bit and BHA. RIH with emergency stage shifting tool. RIll, spud into stage tool at 1818 ft due to stand miscount. Drill out dart, stage tool and baffle plate. RIH to 3425 ft, wash and circulate, observed trace of green cement in returns. Rotate and RIH to float shoe at 3604 ft. Circulate well clean with trace cement at shakers. Pump pill and POOH. LD bit and pick up watermelon and string mill and TIH to 1817 ft and dress stage collar / baffle plate areas. Note ledges and mill out. POOH, LD mill's and PU bit and casing scraper assembly. RIH to 3100 ft. Rotate and clean out to 3600 ft with some residual cement at 3350 ft. Circulate and clean up wellbore until clean returns at surface. ~C:~L Continue to displace out mud with 9.5 ppg KC . brine. POOH for logs and perforating. RU Schlumberger for D L run. Log 3612- 1000 ft. Note good to fair bond from 1730 ft - TD. POOH, LD CBL and PU RST/GR. Log GR at surface and from 3612 - 2000 ft. Log RST CO from 3600 - 3100 ft, 2800 - 2300 ft and from 700 - 550 ft. POOH, LD logging tools. Redress test plug and begin BOPE test, witness waived by Tom Maunder AOGCC. Testing BOPE, replace pipe ram rubbers, re-test, OK. Test all valves and pump lines, OK. Remove flow nipple, install Wireline lubricator, test to 1000 psi. RU eline to begin perforating operations. RIH perforating run No.1; shoot 3560 - 3575 noting well on vacuum losing "-J 7 bblslhr after shots. Perforating run No. 2 from 3381 - 3401 ft. Perforating run No.2 from 3371 - 3381 ft. All perforations were 4 Y2 HSD gun at 5 spf and 60 degree phasing and all shots were fired. Wait on firing head replacement for perforating run No.4. Wait on Schlumberger firing head. Firing head arrives, RU and RIH for perforating run No.4 from 3191 - 3211 ft. POOH, LD and release Schlumberger. PU and RIH with 7" casing scraper, no restrictions / obstructions. Circulate and condition well fluids, POOH, LD BHA. PU completion equipment, make up Meshrite 21-Sept - 2002 22-Sept-2002 23-Sept-2002 ) screen and packer assembly RIH with drillpipe and set at 3112.7 ft. Drop ball, pressure to 4200 psi, shear and set packer. Pressure test packer to 2500 psi / 15 minutes, OK. Release set tool and flow check. POOH, LD 3 Yz" drillpipe and packer set tools. Change out rams to 2 7/8" and test BOPE to 3000 psi, OK. Make up seal assembly and RIH with 2 7/8" J55 EUE production tubing. Sting into packør and space out, make up pups and tubing hanger. Sting out of packer; circulate inhibited packer fluid "Concor 303". Freeze protect well by pumping 1 bbl diesel down 2 7/8" X 7" annulus, sting into packer, land tubing hanger into head and lock down. Set plug in x -nipple, test tubing to 2500 psi and 2 7/8" X 7" annulus t<) 1500 psi, all OK. Layout test equipment, RD rig floor and begin nipple down BOPE. Nipple up BOPE, forgot to pull plug out of x-nipple. RU lubricator and pull plug. Bullhead to kill well, set back pressure valve. Nipple down BOPE for move to NC #8. RIH with swab, fluid level at 30 ft. Well kicked off flowing after 4 runs, swabbing from,..., 1500 ft. Flowed well and recovered 23.5 bbl fluid before strong gas to surface. SI and direct flow to choke manifold. SITP = 230 psi at 1520 hrs. Flow well to test separator on 10 /64" choke. Open to 16/64" choke with FTP to 640 psi at 1530 hrs, 800 psi at 1540 hrs, and 1060 psi before choke plugged off with sand. Shut in well, clean out sand and blow down lines. A total of 30 bbls of water recovered when SI at 1551 hrs. SITP recorded at 1400 psi at 1630 hrs. Open valve to flow test for 4 hours on chokes to 36/64" while holding +/- 400 psi backpressure on separator and 1150 - 1225 psi on various chokes with icing downstream of separator. Final flow rate of 1407 mcfpd at 1190 psi. Recovered total of 42 bbls fluid during testing, 35.6 bbls of well bore plus fluid lost to perforations. Final water production at ---4.8 bbls/hr of 8.8 ppg fluid. Well shut in at 1630 hrs with FTP of 1190 psi. SITP at 1260 in 1 minute, 1340 psi at 5 min, and 1475 psi at 1 hr. Testing run at minimal flow rate due to sand screens. Begin nipple down BOPE. Install Back Pressure Valve and continue nipple down operations. Install production tree and test all valves to 3000 psi. Test primary and secondary seals to 3000 psi and flag tree as BPV installed. Release rig and prepare to mob to NC # 8. Cannot move rig as mast carmot be scoped down. Repair mast and continue rig down for move. Rig Released at 1200 hrs. I ) Proposed I X 1 Completed 26" Hole .-) Nicolai Creek No.1 B Nicolai Creek Field Alaska Producer ) ~ 2 7/8 6.5# eUE SRO J-55 Production tubing 20"94# H-40 @ 232' CMT'D to surface WI 300 Sks - :::fJ1' . «. ~ Whipstock @ 645' in 17 1/2" holö ~.~ 17 1/2" Hole 133/8" 54# J-55 @ 1904' Cmt'd to suñace WI 1530 Sks Top Whipstock @ - 2186' Baker WindowMaster Bottom Set Whipstock Bridge Plug set at 2212' Perforations:.3615' - 3630', 2 spf 12 114U Hole 10 3/4" 40.5# J-55 @ 3S17' Cmt'd to suñace W/900 Sks Attachment I See original NCU 1 & 1A well r~cords for perforation and squeeze infor"ation 7" stage collar installed at 1832' .nd baffle plate at 1789t~ Stage collar not u~ed during cementing procedure. O2 Inhibited KCL pac~er fluid "Concor 303" in 2 71S<i, X casing annulus to surface abpve Packer Xaonipple at 30S0' 9 7/S" Hole : : Permanent Packer Baker SC..1 @ - 3112.7' 3 1/2" J-55 Production T~bing Spacer between screen intervalJ¡ 5 1/2" Meshrite Screen 3192' - 3215' 3$73' - 3396' 3557' - 3580' Well perforations 3191' .. 3211' 3371' ~ 3401' 3560' .. 3575' @ 5 spf, 60-degree phasing 4 1/2 HSO guns' 7" 23# J-55 Csg. @ 3650' Mq(3595' TVD) Cmtd to surface wI 82 bbls ~ 2.5 ppg lead 67 bbls :15.8 ppg tail 7" Float Collar at 3604' NCU 1 B 7" Guide Shoe -at 3648' TO at 3672' MD Original NCU 1A TO"d 1966, Plugged Back 1991. DRAWlNGNOTTOSCAlE NICOLAI CREEK No. 18 FAIRWEATHER E&P SERVICES ING. 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""T :" -' . ¡ .¡i ¡. I C A SURFAcE 103/4' ~f .. ,,:;,:.!' ,/;.. ,,!. '; I ~- N _M~~. . I,' G PRQ" r"~. Í3IIl rei 3<»72 '. ~65 ~!~ .! I NEW COMPLETION SIde track RIG ~s . ^..YfS.'1 QEŠCR,p:n~ ElEVAT~ RK8 Rig Floor I Tbg Head Tubing Hanger 2-71886.5# API MOD EUE 8RD TUBING 2-7'!f" 6.5# API MOD E~E 8RD PUP 2-7/fr 6.51 API MOD EUE 8RD PUP 2-7/8" 6.5# API MOD EUE SRD PUP 2-7/fr 6.5#.API MOD EVE 8RD TUBING X NipPle. 2-7/fr 6.5# API MOD EVE 8RD ONE TUBING JOINT Locator Sub Seal Assy. 5.5 ft seals . PIa. Baker, SC4, .,. - 26# . . Mill Out Extension . XO 5"lTC box X 3112 butt Pin XO PUP. 3 112 butt box X 3 112 ~e pin Tbg, 3 112, 9.3#, ~,$\JØ F) XO. 3 1fl eue box X 5 LTC pin Meshrite Screen . XO. 5 l TC box X 3 112 eue pin Tbg. 3 112, 9.3#, L80, eue (5) XO, 3 112 eue box X 5 LTC pin Meshrite Screen XO 5" LTC box X 3112 eue Pin ~p, ;J 112, 9.3#, L80. eue (1) . Tbg..3 112, 9.~. L80. eue (5) XO. 3 112 eue bo1' X 5 LTC pin Meshrlle Screen Bull Nose iì IA IT AiÃiMI=NT II 5.~ FTr - 21.000. Uf' ::~. ~ 1,600 PSI 4.200 SEAL LENGTH: 8.009 lBS. STRING WEtGKT: 3,112.71 FT. SET OOWN WEIGHT: 2.37 INCH. UP WT 3,672 Fl. PBTD. ..... 3.~ 19 CTlON Of CSG MILLED: 2200 . 2218 fISH' NlA NG TESTED AT. 2,500 PSI ANNULUS TESTED AT: AWE OF SHEAR RING -.' . - RFS (3560. 3575) {3381 . ~~ (3371 . 3381) ~91 .3211 :C1ltriiii~~:' .- _.~:",;:...::>"..Þr~!?~,~~~~~lt;k ~~ - ;: :. -.;..~~."~ ':"'~'J~~~.~ 'f":£';~~;.J~~~'~~~. ~ - AURORA GAS LLL ) NICOLAI CREEK UNIT 1 B ) . 2-9/16" ~,OOO Wing 2-9/16" 5,000 Tree Run ~~~- -~~- 11" 3,000 -fD) .rljl~ ~r~Y r;}~o r-) ~l ;}~rJ D[ 0 0 0 ~I 0 0 D ~- ~ L) -.3 (;- -.3 . (m ,', .) I r. L-) ~, c(~ ~- ...J = L-o 2-1/16" 5,000 13-5/8" 3,000 u" , r-b - ...J (;- ~ 2-1116" 5,000 13-3/8 eSG . 10-314" CSG ;d 2-7/8"TBG ~ e CAMEIRON David Shaw Anchorage M 04104.102 . (þ Sperry-Sun Drilling Services Alaska Cook Inlet Nicolai Creek Unit#1 - Nicolai Creek #18 Job No. AKMW22147, Surveyed: 11 September, 2002 Sperry-Sun Survey Report 25 September, 2002 Your Ref: API 502831002002 Surface Coordinates: 2565238.43 N, 241509.65 E (61000' 48.4053" N, 151027' 24.9350" W) Grid Coordinate System: NAD27 Alaska State Planes, Zone 4 Surface Coordinates relative to Project H Reference: 2434761.57 S, 258490.35 W (Grid) Surface Coordinates relative to Structure: 10.43 N, 2.65 E(Grid) Kelly Bushing: 35.50ft above Mean Sea Level Elevation relative to Project V Reference: 35.50ft Elevation relative to Structure: 35.50ft Survey Ref: svy94 HALLIBURTON ~. "-" Sperry-Sun Drilling Services HALLIBURTDN Alaska Cook Inlet Survey Report for Nicolai Creek Unit#1 Your Ref: API 502831002002 Job No. AKMW22147, Surveyed: 11 September, 2002 Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (°/1 OOft) ~ Nicolai Creek Unit #1 0.00 0.000 0.000 -35.50 0.00 0.00 N 0.00 E 2565238.43 N 241509.65 E 0.00 Good Magnetic 589.50 0.000 0.000 554.00 589.50 O.OON O.OOE 2565238.43 N 241509.65 E 0.000 0.00 634.50 0.500 125.000 599.00 634.50 0.118 0.16 E 2565238.32 N 241509.81 E 1.111 0.07 669.50 2.000 175.000 633.99 669.49 0.818 0.34 E 2565237.62 N 241509.99 E 4.919 0.70 729.50 2.750 179.000 693.94 729.44 3.298 0.46 E 2565235.14 N 241510.11 E 1.279 3.08 788.50 3.250 184.000 752.86 788.36 6.378 0.36 E 2565232.06 N 241510.01 E 0.956 6.09 884.50 5.750 180.000 848.55 884.05 13.90 8 0.17 E 2565224.53 N 241509.82 E 2.623 13.44 1007.50 10.250 176.000 970.33 1005.83 30.99 8 0.94 E 2565207.44 N 241510.59 E 3.684 29.82 1100.50 12.250 177.000 1061.54 1097.04 49.108 2.03 E 2565189.33 N 241511.68E 2.161 47.12 1192.50 13.000 176.000 1151.31 1186.81 69.178 3.26 E 2565169.26 N 241512.91 E 0.849 66.28 1254.50 13.250 177.000 1211.69 1247.19 83.22 8 4.12 E 2565155.21 N 241513.77 E 0.545 79.70 1309.50 12.000 192.000 1265.37 1300.87 95.11 8 3.26 E 2565143.32 N 241512.91 E 6.358 91.44 1354.50 12.000 196.000 1309.39 1344.89 104.18 S 1.00 E 2565134.25 N 241510.65 E 1.848 100.79 1410.50 13.250 199.000 1364.04 1399.54 115.858 2.69W 2565122.58 N 241506.96 E 2.520 113.01 1529.50 17.000 200.000 1478.90 1514.40 145.108 13.09 W 2565093.33 N 241496.56 E 3.159 143.91 ~ 1623.50 18.750 200.000 1568.35 1603.85 172.21 8 22.95 W 2565066.22 N 241486.70 E 1.862 172.61 1716.50 18.750 201.000 1656.42 1691.92 200.21 8 33.42 W 2565038.22 N 241476.23 E 0.346 202.32 1859.50 18.250 201.000 1792.03 1827.53 242.57 8 49.68- W 2564995.86 N 241459.97 E 0.350 247.36 2058.50 18.500 201.000 1980.88 2016.38 301.138 72.16 W 2564937.30 N 241437.49 E 0.126 309.64 Tie On Point MWD Magnetic 25 September, 2002 -13:05 Page 20f5 DrillQuest 3.03.02.002 Sperry-Sun Drilling Services HALLIBURTDN Alaska Cook Inlet Survey Report for Nicolai Creek Unit#1 Your Ref: API 502831002002 Job No. AKMW22147, Surveyed: 11 September, 2002 Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (0/100ft) -' Nicolai Creek #1 B 2186.00 18.180 201.000 2101.91 2137.41 338.59 S 86.54 W 2564899.84 N 241423.11 E 0.251 349.47 Window Point 2206.00 18.250 201.600 2120.90 2156.40 344.41 S 88.81 W 2564894.02 N 241420.84 E 1.001 355.67 2219.00 18.310 201.990 2133.25 2168.75 348.20 S 90.33 W 2564890.23 N 241419.32 E 1.048 359.71 2250.00 15.480 203.140 2162.91 2198.41 356.52 S 93.78 W 2564881.91 N 241415.87 E 9.192 368.62 2281.00 12.770 204.620 2192.97 2228.47 363.44 S 96.83 W 2564874.99 N 241412.82 E 8.819 376.08 2312.00 10.750 206.610 2223.31 2258.81 369.14 S 99.55 W 2564869.29 N 241410.10 E 6.645 382.27 2343.00 8.640 217.470 2253.87 2289.37 373.57 S 102.27 W 2564864.86 N 241407.38 E 8.979 387.23 2375.00 6.530 229.320 2285.59 2321.09 376.67 S 105.11 W 2564861.76 N 241404.54 E 8.175 390.93 2407.00 4.080 235.280 2317.45 2352.95 378.50 S 107.42 W 2564859.93 N 241402.23 E 7.837 393.27 2438.00 1.600 242.670 2348.41 2383.91 379.33 S 108.71 W 2564859.10 N 241400.94 E 8.070 394.39 2469.00 0.390 322.590 2379.41 2414.91 379.44 S 109.16W 2564858.99 N 241400.49 E 5.094 394.61 2501.00 0.560 5.140 2411.41 2446.91 379.20 S 109.22 W 2564859.23 N 241400.43 E 1.185 394.39 2562.00 0.630 21.060 2472.40 2507.90 378.59 S 109.07 W 2564859.84 N 241400.58 E 0.293 393.76 2656.00 0.600 27.590 2566.40 2601.90 377.67 S 108.65 W 2564860.76 N 241401.00 E 0.081 392.77 2751.00 0.640 18.310 2661.39 2696.89 376.73 S 108.26 W 2564861.70 N 241401.39 E 0.114 391.75 ~ 2841.00 0.620 50.860 2751.39 2786.89 375.94 S 107.72 W 2564862.49 N 241401.93 E 0.393 390.86 2933.00 0.700 47.520 2843.38 2878.88 375.25 S 106.92 W 2564863.18 N 241402.73 E 0.096 390.00 3026.00 0.790 42.600 2936.37 2971.87 374.40 S 106.07 W 2564864.03 N 241403.58 E 0.119 388.96 3120.00 0.120 57.490 3030.37 3065.87 373.87 S 105.55 W 2564864.56 N 241404.10 E 0.718 388.32 3213.00 0.170 79.220 3123.37 3158.87 373.79 S 105.33 W 2564864.64 N 241404.32 E 0.079 388.19 3306.00 0.200 88.590 3216.37 3251.87 373.76 S 105.03 W 2564864.67 N 241404.62 E 0.046 388.09 3399.00 0.280 75.530 3309.37 3344.87 373.70 S 104.65 W 2564864.73 N 241405.00 E 0.104 387.93 3493.00 0.390 88.790 3403.37 3438.87 373.63 S 104.11 W 2564864.80 N 241405.54 E 0.142 387.74 3587.00 0.250 79.310 3497.37 3532.87 373.59 S 103.59 W 2564864.84 N 241406.06 E 0.159 387.57 3618.00 0.260 97.430 3528.37 3563.87 373.58 S 103.45 W 2564864.85 N 241406.20 E 0.261 387.53 25 September, 2002 -13:05 Page 3 of5 DrillQuest 3.03.02.002 HALLIBURTDN Sperry-Sun Drilling Services Alaska Cook Inlet Survey Report for Nicolai Creek Unit#1 Your Ref: API 502831002002 Job No. AKMW22147, Surveyed: 11 September, 2002 Measured Sub-Sea Vertical Local Coordinates Global Coordinates Dogleg Vertical Depth Incl. Azim. Depth Depth Northings Eastings Northings Eastings Rate Section Comment (ft) (ft) (ft) (ft) (ft) (ft) (ft) (o/100ft) ~/ 3672.00 0.260 97.430 3582.37 3617.87 373.62 S 103.21 W 2564864.81 N 241406.44 E 0.000 387.50 Projected Survey All data is in Feet (US) unless otherwise stated. Directions and coordinates are relative to Grid North. Vertical depths are relative to Well. Northings and Eastings are relative to Well. Global Northings and Eastings are relative to NAD27 Alaska State Planes, Zone 4. The Dogleg Severity is in Degrees per 100 feet (US). Vertical Section is from Well and calculated along an Azimuth of 194.110° (Grid). Coordinate System is NAD27 Alaska State Planes, Zone 4. Grid Convergence at Surface is -1.274°. Based upon Minimum Curvature type calculations, at a Measured Depth of 3672.00ft., The Bottom Hole Displacement is 387.61ft., in the Direction of 195.442° (Grid). Comments Measured Depth (ft) Station Coordinates TVD Northings Eastings (ft) (ft) (ft) Comment ~. 2058.50 2186.00 3672.00 2016.38 2137.41 3617.87 301.13 S 338.59 S 373.62 S 72.16 W 86.54 W 103.21 W Tie On Point Window Point Projected Survey 25 September, 2002 -13:05 Page 4 of5 DrillQuest 3.03.02.002 HALLIBURTDN Sperry-Sun Drilling Services Alaska Cook Inlet Survey Report for Nicolai Creek Unit#1 Your Ref: API 502831002002 Job No. AKMW22147, Surveyed: 11 September, 2002 Survey tool proqram for Nicolai Creek Unit#1 - Nicolai Creek #1 B From Measured Vertical Depth Depth (ft) (ft) To Measured Vertical Depth Depth (ft) (ft) Survey Tool Description 0.00 2058.50 0.00 2016.38 2058.50 3672.00 2016.38 Good Magnetic(Nicolai Creek Unit #1) 3617.87 MWD Magnetic(Nicolai Creek #18) ~" 25 September, 2002 -13:05 Page 5 0'5 DrillQuest 3.03.02.002 ''\ ) ,/ ) J(J '(;l-l ~ ~. ( Aurora Gas, LLC Nicolai Creek Unit #1 B Upper Cook Inlet, Alaska Final Well Report September 11, 2002 ( John Morris - Sr. Logging Geologist Tim Smith - Sr. Logging Geologist U 3POCI-: ( (' ( ( ( Aurora Gas, LLC Nicolai Creek Unit #1 B ( TABLE OF CONTENTS WELL RESU ME.. ... .......... ............... ....... ....... ...... ........ .... ......... ....... ............. ... .... ............ 3 GEOLOGICAL DISCUSSION ...... ... ......... ..... ... .... ..... ........ .................... ... .... ...... ..... ........5 DAILY ACTIVITY SU M MARY.. ...... ..... ..... .............. ............ ....... ..... .................... .... .........6 LITHOLOGY AN D COM M ENTS ..... ........... ........... ........... ...... ........ ............ ... ... ... ............ 8 SU RVEY IN FORMATION......... ............................. ......... ...... ....... ..................... ........ ..... 12 DAILY MUD PROPERTIES..... ........ ........... ......... ........ ..... ...... ..... .......... ..... ... ..... ........... 13 BIT RECORD.. ...... ... ...... .......... .... ... ... ................. ...... ........ .......... ... .............. ...... ...... ..... 14 MORNING REPORTS.............................................................. .................. ....15 lOGS........... ....................................................................... ......... Appendix 1 ~ EPOC:-:: ( Company: Well: Field: Region: Location: Coordinates: Elevation: County, State: API Index: Kick off date: ( Total Depth: Contractor: Company Representative: RigfType: Epoch Logging Unit: Epoch Personal: Company Geologist: ( ( Aurora Gas, LLC Nicolai Creek Unit #1 B ( " WELL RESUME Aurora Gas, LLC. Nicolai Creek Unit #1 B Nicolai Creek Field Upper Cook Inlet, Alaska Sec. 29, T 11 N, R 12W, Seward Meridian 2018' FSL, 195'FWL 35.5' RKB, 16' GL Kenai Borough, Alaska 50-283-10020-20 September 2, 2002 3672' MD, 3617.87' TVD, September 11,2002 Boelens Well Services Dave Morris, Dave Lancaster Aurora Well Service #1 I Power Swivel Single #12 John Morris Tim Smith Fletcher England Mike Krahmer Dick Ebright Barry Wright Andy Clifford ~ 3?OCH Aurora Gas, LLC Nicolai Creek Unit #1 B ( Casing Data: Window in 10 %" casing @ 2186' 7" casing @ 3672' Hole size: 8 %" from 2186' to 3672' Mud Type: Flow Pro to 3672' Logged Interval: Monitor Gas 300' to 2186' Full Logging 2186' to 3672' Electric Logging Co: Schlumberger ( ( ~ E?OC== ( ( ( Aurora Gas, LLC Nicolai Creek Unit #1 B ( GEOLOGICAL DISCUSSION Aurora Gas Company commenced milling a window in 10 3/4" casing on the existing Nicolai Creek #1 well on September 2, 2002 with Aurora Well Service Rig #1. Drilling of the Nicolai Creek 1 B well progressed well with some rig delays and a total depth of 3,672 feet was reached on September 11,2002. The primary objectives of this Nicolai Creek Unit well were well developed gas bearing sands of the Tyonek formation. Epoch Well Services provided RIGWA TCH 2000TM Drilling Monitoring services and DML TM Mudlogging Service. Hydrogen flame ionization (FID) Total Gas and (FID) Gas Chromatograph detectors were employed to detect and analyze formation gases. Constant mud gas was generated by Texaco's patented Quantitative Gas Measurement (QGMTM) electrically driven gas trap located at the shale shaker header box and extracted continuously from the trap to the unit by sample pumps. The gas trap was frequently cleaned and positioned to obtain optimum sampling, and the gas system was tested and calibrated on a regular basis. Cuttings samples were collected at regular 30' intervals as directed by Aurora Gas Company's sampling program. ~ ~JOC----=-- ~ ----.J...... ...... --- Aurora Gas, LLC Nicolai Creek Unit #18 ( DAILY ACTIVITY SUMMARY 9/2/2002 P JSM. Welders continue installing desander and gas buster. Run into hole with three stands of drill pipe and one single. Rig up power swivel and circulate well. Set packer on whipstock, shear mill off whipstock and start milling window in 10 %" casing at 2186'. Continue milling window to 2200'. Sort and separate drill pipe and repair Hydrilleaks. 9/3/2002 P JSM. Continue milling window from 2200' to 2202' in 12 hours. Perform rig maintenance. Pump high viscosity nut plug sweep. Mill casing from 2202' to 2202.1' in 12 hours. Pull out of hole and check mill. 9/4/2002 Continue pulling out of hole. lay down spiral drill collars. Stand back flex collaras and lay down bumper sub. Inspect casing mills. Rig up and test BOPE. Run into hole with milling assembly. Circulate bottoms up at 2204'. Continue milling window. ( 9/5/2002 Continue milling window from 2204' to 2208'. Pump high viscosity sweep and circulate bottoms up. Mill window from 2208' to 2218'-end of milling operation. Pump high viscosity sweep and circulate bottoms up. 9/6/2002 Lay down one joint of drill pipe and continue circulating. Perform FIT test to 16.9 ppg equivalent. Pump dry job, pull out of hole. Make up new BHA. Orient BHA. Tag formation at 2218' and drill with mud motor from 2218' to 2390' . 9/7/2002 PJSM. Drill from 2370' to 2636'. Pump washed out. Switch to PJ-8 pumps to circulate while working on the PZ-7 pump. Drill from 2636' to 2648'. Shut down PZ-7 and generator to remove separated power line to de-sander. Resume drilling from 2648' to 2680'. 9/8/2002 Drill from 2680' to 2900'. Circulate bottoms up and pump high vis sweep. Circulate hole clean, check for flow, pump dry job and pull out of hole. 9/9/2002 Continue wiper trip, run into hole and continue drilling to 3175'. ( 9/10/2002 Continue drilling to 3180', encountered drilling break with gas show with 700 units gas. Checked for flow, checked mud weight, drill to 3610'. ~ 3?OCE Aurora Gas, LLC Nicolai Creek Unit #1 B ( 9/11/2002 Continue drill ing from 361 OJ to 3672' (Final depth). Circulate bottoms up pump sweep, circulate hole clean, pump dry job, short trip to 2648', circulate bottoms up, pump sweep, circulate hole dean. Pump dry job, pull out of hole, lay down BHA, test BOPE. ( ( ~ 3?OC3 Aurora Gas, LLC Nicolai Creek Unit #1 B ( ( LITHOLOGY AND COMMENTS 2220' Sand = predominantly transparent to white translucent, abundant multi-colored grains primarily bluish gray to gray hues; lower fine to lower medium; well to moderately sorted; subrounded to subangular; high to moderate spheroidal sphericity; 100% unconsolidated; 30% quartz, 30% chert, 40% metalithic fragments; no fluorescence, no cut. 2270' Coal = brownish black to very dusky red; very firm to moderately hard; sub brittle to crumbly; irregular to blocky fracture occasionally conchoidal; wedge-like to tabular cuttings habit; earthy to waxy luster; smooth to clayey texture, occasionally woody to fibrous; sub-bituminous to bituminous grading to carbonaceous shale; no visible gas bleeds. 2335' Tuffaceous Claystone = very light gray to light olive gray; very soft to soft; low to moderately cohesive, moderately adhesive; curdy to mushy; amorphous clumps infused with sand; dull luster; thin interbedded with sand and coal. ( 2385' Sand = milky white, clear, light to dark gray, occasional medium to dark greenish gray; clasts range from very fine upper to medium upper with rare coarse to very coarse grains; angular to rounded, dominantly subangular to subrounded; poorly sorted; composed of 70% quartz and other siliceous minerals, 30% igneous and metamorphic lithics; occasional appears in lumps of clay. 2435' Coal = black, dusky brown, dusky yellowish brown; firm; moderately brittle; platy and blocky cuttings; matte to slightly shiny luster; smooth surface texture; occsionally appears woody; scattered claystone laminations. 2470' Sand/Sandstone = light gray overall; friable; clasts range from very fine upper to medium upper; angular to subround; poorly sorted; composed of 80% quartz, 20% volcanic and metamorphic lithic fragments; silty, argillaceous matrix; mostly matrix supported grains; slight acid reaction from bulk sample; estimated poor to fair porosity and permeability. ( 2520' Carbonaceous Shale = olive gray to olive black; moderately firm to very firm; crumbly, occasionally sub brittle; irregular to planar fracture; platy to tabular cuttings habit; dull ~ ~JOC--- ~ ~ ...-.....J --- ...-.. --- (' Aurora Gas, LLC Nicolai Creek Unit #18 ( luster; smooth to slightly silty texture; subfissile; abundant carbonaceous material laminae. 2560' Sand/Conglomeratic Sand = light gray to very light gray overall, individual grains white to light bluish gray, occasionally medium gray, light greenish gray; predominantly ranges between lower fine and lower medium, occasionally very fine to very coarse; coarser grains subround to rounded, finer grains subangular to subround; locally well sorted, o/w moderately to poor; high to moderate sphericity; unconsolidated, trace calcareous cemented sandstone; 20% quartz, 40% chert, 40% other siliceous lithic fragments; very poor estimated porosity for sandstone cuttings; trace bright yellow mineral fluorescence in samples. 2660' Coal = black to dusky yellowish brown; firm; brittle to crumbly; platy and blocky cuttings; matte to slightly shiny luster; occasionally appears woody; locally common thin claystone laminations. ( 2690' Sand/Sandstone = light gray overall; friable when consolidated; cfasts range from very fine upper to medium lower; angular to subround; moderately sorted; composed of 70% quartz and other siliceous minerals, 30% igneous and metamorphic lithic grains; dominantly appears loose in samples with common grains embedded in soft claystone lumps; estimated fair porosity and permeability. 2765' Tuffaceous Claystone = pale yellowish brown, light to medium brownish gray; very soft to soft, rarely slightly firm; appears dominantly as irregularly shaped lumps, occasionally as poorly indurated mushy cuttings with irregular habit. dull luster, moderately abrasive texture; non to occasionally slightly calcarous; commonly ashy appearing with scattered volcanic glass shards. 2820' Sand/conQlomerate (2840') = multi col w/common clear, white, light to medium gray, scattered light to medium greenish gray, occasional black; grains range from very fine upper to pebble fragments, moderately sorted in the medium to coarse range; angular to well rounded, dominantly angular to subangular; pr sorted; 70% quartz, 30% igneous / metamorphic lithics; variable grain/matrix supported with asy clay; estimated fair porosity and permeability. 2900' Tuffaceous Claystone = very light gray to light olive gray; very soft to soft; low to moderately cohesive, moderately adhesive; curdy to mushy; amorphous clumps infused with sand; dull luster; thin interbedded with sand and coal. ( 2935' U EPOC3 Aurora Gas, LLC Nicolai Creek Unit #1 B ( Tuffaceous Claystone = pale yelsh brn, light to medium brownish gray, occasional olive gray; very soft to soft, rarely slighlty firm; common appears as irregularly shaped lumps, occasionally as poorly indurated mushy cuttings with irregular habit. dull luster, moderately abrasive texture; non to occasionally slightly calcarous; locally silty, ashy, occasional with abundant carbonaceous matter, grades in part to carbonaceous shale. 3010' Sand = clear, white, light to medium gray, black, occasional light to medium greenish gray; clasts range from very fine upper to coarse upper, dominantly fine grain; angular to rounded, dominantly angular to subangular; moderately sorted in the fine to medium range; 70% quartz and other siliceous minerals, 30% igneous/metamorphic lithic grains; clay matrix material is present as thin crusts on a few grains; very slight acid reaction on bulk sample. 3070' Tuffaceous Siltstone = medium gray to light olive gray; soft to slightly firm; pasty to mushy; washed sample very hydrated, slightly less so at shaker; moderately soluble; irregular fracture; amorphous cuttings habit; dull luster; silty to gritty texture; interbedded with and grading to claystone and thin sand. ( 3120' Coal = brownish black to black; moderately hard to occasionally very firm; brittle to occasionally crumbly; blocky to conchoidal to splintery fracture; wedge-like to tabular cuttings habit; vitreous luster, occasionally dull; smooth to matte texture; bituminous with sparse clay laminae and occasional gradation to poorly developed carbonaceous material; abundant visible gas bleeds in fresh wet cuttings. 3195' Sand = white to light gray, yellowish gray to light bluish gray; transparent, occasionally light red; predominantly upper very fine to upper medium, overall ranges from silt to very coarse, rare bit broken pebble size; subangular to angular, occasionally subround to rounded; fair to poor sorting overall; moderate to high spheroidal sphericity, rare discoidal; unconsolidatd in sample, likely clay matrix cemented with dominant grain support inferred from rare indurated cutting; 30% quartz, 40% chert 30% other siliceous fragments; fair to poor visually estimated porosity. 3275' Tuffaceous Claystone = pale yellowish brown, light gray, medium brownish gray, occasional olive gray; very soft to soft; easily hydrated; appears dominantly as clay lumps; rarely appears as roughly formed irregular shaped cuttings; matte luster; moderately gritty texture; non to locally slightly calcareous; locally silty, grading in part to siltstone; ashy appearance. 3325' ( ~ ~JOC~---- ~ ...-.....J........ ........ ........ Aurora Gas, LLC Nicolai Creek Unit #1 B ( Coal = black to occasional dusky yellowish brown; firm; brittle to occasional crumbly; blocky and flaky cuttings; matte to slightly shiny luster; smooth surface texture; scattered ashy clay laminations. 3355' Sand = clear, milky wht, light gray, rarely light to medium greenish gray; clasts range from very fine upper to medium upper, dominantly fine to medium range; lower portion of interval with scattered pebble fragments; angular to rounded, dominantly subangular to subround; moderately sorted; composed of 80% quartz, 20% igneous and metamorphic lithics; appears loose in samples; occasional chunks of ashy clay- possibly matrix material; no acid reaction from bulk sample; estimated good fair to good visual porosity and permeability. 3425' Tuffaceous Claystone = medium gray, medium brownish gray; very soft to soft; dominantly appears as irregular shaped clay lumps, rarely as poorly indurated cuttings; matte luster; moderately gritty texture; non to occasional slightly calcareous; locally silty; commonly with ashy appearance. ( 3470' Sand/Conglomerate = multi colored, dominantly white, clr, light to medium gray, black; clast sizes range from very fine upper to pebble fragments, dominantly medium range; angular to well rounded, dominantly subangular to subround; moderately sorted in the fine to medium range; 70% quartz, 30% igneous/metamorphic lithics; trace jasper; estimated fair porosity and permeability. 3515' Coal = olive black to black; moderately hard to very firm; brittle to sub brittle occasionally crumbly; blocky to splintery fracture; platy to tabular cuttings habit; dull to vitreous luster; smooth to matte texture; bituminous to subbituminous;sparse visible gas bleeds. 3570' Sand/Sandstone = light gray overall, individual grains white translucent to transparent, very light gray to light bluish gray to medium gray, occasionally light red; overall grain ranges lower very fine to very coarse with occasional pebble size, predominantly upper fine to upper medium; fair to poorly sorted; finer grains mostly subangular to angular with abundant subrounded to rounded, coarser grains predominantly angular; high to moderate spheroidal sphericity generally; washed samples 60-80% unconsolidated sand, balance of sand content soft to easily friable sand stone; clay matrix cemented; grain/material matrix supported; poor estimated porosity from less hydrated cuttings; 40% quartz, 40% chert, 20% other siliceous lithic fragments. ( ~ EPOC2: (" Aurora Gas, LLC ( Nicolai Creek Unit #1 B ( SURVEY INFORMATION Angle Direction TVD Northings Eastings Vertical Dog Depth 8ection Leg 2186 18.18 201.00 2137.41 338.598 86.54 W 349.470.00 2206 18.25 201.60 2156.41 344.428 88.81 W 355.681.00 2219 18.31 201.99 2168.75 348.208 90.32W 359.721.05 2250 15.48 203.14 2198.41 356.528 93.77W 368.63 9.19 2281 12.77 204.62 2228.47 363.448 96.83W 376.088.82 2312 10.75 206.61 2258.82 369.148 99.55W 382.276.65 2343 8.64 217.47 2289.38 373.588 102.26W 387.248.98 2375 6.53 229.32 2321.10 376.678 105.11 W 390.938.17 2407 4.08 235.28 2352.96 378.51 8 107.42W 393.277.84 2438 1.60 242.67 2383.92 379.338 108.71 W 394.398.07 2469 0.39 322.59 2414.91 379..458 109.16W 394.61 5.09 2501 0.56 5.14 2446.91 379.21 8 109.21 W 394.391.19 2562 0.63 21.06 2507.91 378.608 109.07W 393.76 0.29 2656 0.60 27.59 2601.90 377.688 108.65W 392.770.08 2751 0.64 18.31 2696.90 376.738 108.26W 391.760.11 ( 2841 0.62 50.86 2786.89 375.958 107.72W 390.870.39 2933 0.70 47.52 2878.89 375.258 106.92W 390.000.10 3026 0.79 42.60 2971.88 374.408 106.07W 388.960.12 3120 0.12 57.49 3065.88 373.878 105.54W 388.320.72 3213 0.17 79.22 3158.88 373.798 105.33W 388.190.08 3306 0.20 88.59 3251.87 373.768 105.03W 388.090.05 3399 0.28 75.53 3344.87 373.708 104.65W 387.940.10 3493 0.39 88.79 3438.87 373.648 104.10W 387.740.14 3587 0.25 79.91 3532.87 373.598 103.58W 387.570.16 3618 0.26 97.43 3563.87 373.598 103.45W 387.540.25 3672 0.26 97.43 3617.87 373.628 103.20W 387.51 0.00 ( U 3POC== ,~ /~'\ /~ Aurora Gas, LLC Nicolai Creek Unit #1 B DAILY MUD PROPERTIES Date Depth Den. Vis PV YP Gels FiI Cake Solids Sand MBT PH CI Ca 9/2/02 2200 10.0 58 10 37 23/30/32 9 2 7 0.1 10 10 28000 400 9/3/02 2216 10.0 50 10 38 23/27/29 8 2 7 0.5 10 9.5 24000 400 9/4/02 2205 10.2 58 9 44 25/31/33 8 2 7 0.5 10 9.5 24000 400 9/5/02 2218 10.1 52 10 42 23/29/30 9 2 7 0.5 9.3 9.3 25000 20 .~ 9/6/02 2390 10.4 54 10 44 22/25/27 8 2 10 0.75 5 8.5 30000 20 9/7/02 2680 10.3 52 14 41 15/25/26 6.5 2 9 1.0 7.5 8.5 29000 20 9/8/02 2894 10.4 46 12 37 12/16/27 6.5 2 8 0.75 8.5 8.5 32000 20 9/9/02 2960 10.5 52 16 36 10/16/19 7.0 2 10 1.0 10.0 9.0 31000 80 9/10/02 3570 10.6 54 18 35 11/20/25 7.0 2 9 1.0 12.0 9.0 30000 120 9/11/02 3672 10.5+ 61 21 34 13/20/24 6.5 2 8 0.75 10.0 9.0 32000 120 ~c ~ ~JOC~--- ~ ~~ ....... ---- 13 Aurora Gas, LLC Nicolai Creek Unit #1 B BIT RECORD Bit Grading 10 D L B GO 1\ U U 0 EAT 1\ T LeA U H EE L A R G E R R TIE R C I N RR HOG CO A N S V W R SS C H A R R E A S 0 N P U L L E D Bit No. Size Make Type SIN Jets Depth In Depth Out Drilled Hours Ave Ave Ave Ave FT/HR WOB RPM PSI 32.1 18.6 N/A N/A 3 3 WT A E I N TD 1 8~ ~ SEC XSCl 756259 2X16, 2186 lX15 3672 1486 .70.5 g 3?OC3 "- 14 ,--- Daily Report Aurora Gas ') Nicolai Creek 1B REPORT FOR Dave Morris DATE Aug 28, 2002 TIME 06:00:00 CASING INFORMATION SURVEY DATA BIT INFORMATION NO. SIZE 3 9 7/8 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW FC ') MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY PRESENT LITHOLOGY ) ) Page 1 of 1 DAILY WELLSITE REPORT [j EPOCH DEPTH 2414 YESTERDAY 2414 PRESENT OPERA TION= Work on annular 24 Hour Footage 0 DEPTH AZIMUTH VERTICAL DEPTH CONDITION T/B/C CURRENT AVG Gels pH REASON PULLED ft/hr amps Klbs RPM psi CL- Ca+ CCI INCLINATION TYPE Varel INTERVAL SIN JETS IN OUT FOOTAGE HOURS 5x8 HIGH LOW AVERAGE @ @ @ @ @ @ @ @ @ @ DEPTH: N/A VIS PV yp FL SOL SD OIL MBL TRIP GAS= WIPER GAS= SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENTBACKGROUN~AVG GAS DESCRIPTION HIGH LOW AVERAGE DAILY ACTIVITY SUMMARY Function test stack and surface equiment, attempt to test annular, will not fully open, work on annular. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith @ @ @ @ CHROMATOGRAPHY(ppm) @ @ @ @ @ @ @ @ @ @ LITHOLOGY/REMARKS C:\WlNDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020828.htm 9/16/02 Daily Report ) Aurora Gas ) Page 1 of 1 ) DAILY WELLSITE REPORT [j EPOCH Nicolai Creek 1 B REPORT FOR Dave Morris DATE Aug 29,2002 TIME 06:00:00 DEPTH 2412 YESTERDAY 2412 PRESENT OPERATION= Circulate 24 Hour Footage 0 CASING INFORMATION SURVEY DATA DEPTH BIT INFORMATION NO. SIZE 3 9 7/8 JETS 5x8 INTERVAL IN OUT 13.7 TYPE Varel SIN DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE HIGH DRILLING MUD REPORT MW VIS SOL PV SD FC ) MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS HIGH LOW @ @ @ @ CHROMATOGRAPHY(ppm) METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUT ANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL @ @ @ @ @ @ @ @ @ @ INCLINATION AZIMUTH VERTICAL DEPTH FOOTAGE CONDITION T/B/C REASON PULLED HOURS @ @ @ @ @ LOW AVERAGE @ @ @ @ @ DEPTH: N/A yp FL OIL MBL CCI CURRENT AVG ft/hr amps Klbs RPM psi Gels CL- pH Ca+ AVERAGE TRIP GAS= 340/115 WIPER GAS= SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENTBACKGROUND/AVG LITHOLOGY/REMARKS LITHOLOGY PRESENT LITHOLOGY GAS DESCRIPTION DAILY ACTIVITY Continue work on annular, TIH with 9 7/8" casing scraper, circulate and condition well, get back 340 units trip gas, POOH, RIU SUMMARY wireline and RIH to set plug, test casing and plug to 1500, RID wireline, TIH and tag plug at 2212', pull up to 2208' and circulate, get back 115 units gas, circulating at report time. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020829.htm 9/16/02 Daily Report Aurora Gas ) Nicolai Creek 1 B REPORT FOR Dave Morris DATE Aug 30, 2002 TIME 06:00:00 CASING INFORMATION SURVEY DATA BIT INFORMATION NO. SIZE 3 9 7/8 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW FC ) MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUT AN E(C-4) PENT ANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY PRESENT LITHOLOGY ) DAILY WELLSITE REPORT DEPTH 2412 YESTERDAY 2412 24 Hour Footage 0 DEPTH INCLINATION AZIMUTH TYPE Varel INTERVAL SIN JETS IN OUT FOOTAGE HOURS 5x8 13.7 HIGH LOW AVERAGE @ @ @ @ @ @ @ @ @ @ DEPTH: N/A VIS PV yp FL SOL SO OIL MBL HIGH LOW AVERAGE @ @ @ @ CHROMATOGRAPHY wpm) @ @ @ @ @ @ @ @ @ @ LITHOLOGY/REMARKS DAILY ACTIVITY SUMMARY Continue circulating, clean mud pits, work on pumps, rig maintenance. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020830 .htm Page 1 of 1 ) [j EPOCH PRESENT OPERA TION= VERTICAL DEPTH CONDITION T/B/C REASON PULLED CURRENT AVG ft/hr amps Klbs RPM psi Gels CL- pH Ca+ CCI TRIP GAS= WIPER GAS= SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENT BAC KG ROUND/AVG GAS DESCRIPTION 9/16/02 Daily Report AURORA GAS ) Nicolai Creek 1 B REPORT FOR DAVE MORRIS DATE Aug 31,2002 TIME 06:00:00 CASING INFORMATION SURVEY DATA BIT INFORMATION NO. SIZE 3 9 7/8 TYPE Varel DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW VIS SOL FC MWD SUMMARY ) INTERVAL TOOLS TO GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY PRESENT LITHOLOGY ') DAILY WELLSITE REPORT DEPTH SIN JETS 5x8 DEPTH 2412 YESTERDAY 2412 24 Hour Footage 0 INTERVAL IN OUT 13.7 HIGH @ @ @ @ @ PV SO HIGH @ @ LOW @ @ Page 1 of 1 ) (j EPOCH PRESENT OPERATION= Prepare rig INCLINATION AZIMUTH FOOTAGE HOURS LOW AVERAGE @ @ @ @ @ DEPTH: N/A yp FL OIL MBL AVERAGE @ @ @ @ @ CHROMATOGRAPHYwpm) @ @ @ @ @ LITHOLOGY/REMARKS DAILY ACTIVITY SUMMARY Rig maintenance and preparation. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020831.htm VERTICAL DEPTH CONDITION T/B/C REASON PULLED CURRENT AVG ft/hr amps Klbs RPM psi Gels CL- pH Ca+ CCI TRIP GAS= WIPER GAS= SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENTBACKGROUND/AVG GAS DESCRIPTION 9/16/02 Daily Report AURORA GAS ') Nicolai Creek 1 B REPORT FOR Dave Morris DATE Sep 1, 2002 TIME 06:00:00 CASING INFORMATION SURVEY DATA BIT INFORMATION NO. SIZE TYPE 3 97/8 Varel DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW FC MWD SUMMARY ) INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUT ANE(C-4) PENT ANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY PRESENT LITHOLOGY ') Page 1 of 1 ') ;' DAILY WELLSITE REPORT [j EPOCH DEPTH SIN JETS 5x8 VIS SOL DEPTH 2412 YESTERDAY 2412 PRESENT OPERA TION= Preparing rig 24 Hour Footage 0 INCLINATION AZIMUTH INTERVAL IN OUT 13.7 FOOTAGE HOURS HIGH LOW AVERAGE @ @ @ @ @ DEPTH: N/A yp FL OIL MBL @ @ @ @ @ PV SD HIGH @ @ LOW @ @ AVERAGE @ @ @ @ @ CHROMATOGRAPHYwpm) @ @ @ @ @ LITHOLOGY/REMARKS DAILY ACTIVITY SUMMARY Continue rig maintenance and preparation, mix mud. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith ) C: \ WlNDOWS\Desktop\NCU-lB\Reports\Morning Reports\2002090 l.htm VERTICAL DEPTH CONDITION T/B/C REASON PULLED CURRENT AVG ft/hr amps Klbs RPM psi Gels CL- pH Ca+ CCI TRIP GAS= WIPER GAS= SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENTBACKGROUND/AVG GAS DESCRIPTION 9/16/02 Daily Report AURORA GAS ) Nicolai Creek 1 B REPORT FOR Dave Lancaster DATE Sep 2, 2002 TIME 06:00:00 CASING INFORMATION SURVEY DATA BIT INFORMATION NO. SIZE 4 8.5 TYPE Baker Mill DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW FC ) MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUT ANE(G-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY PRESENT LITHOLOGY Page 1 of 1 ) DAILY WELLSITE REPORT [:I EPOCH DEPTH 2412 YESTERDAY 2412 PRESENT OPERATION= Run in hole 24 Hour Footage 0 DEPTH INCLINATION AZIMUTH VERTICAL DEPTH VIS SOL INTERVAL SIN JETS IN OUT 9x12 HIGH @ @ @ @ @ PV SD CCI CONDITION T/B/C REASON PULLED FOOTAGE HOURS LOW AVERAGE @ @ @ @ @ DEPTH: yp FL OIL MBL CURRENT AVG ft/hr amps Klbs RPM psi Gels CL- pH Ca+ HIGH LOW AVERAGE @ @ @ @ CHROMATOGRAPHYwpm) TRIP GAS= WIPER GAS= SURVEY= @ @ @ @ @ @ @ @ @ @ CONNECTION GAS HIGH= AVG= CURRENT CURRENTBACKGROUNrnAVG LITHOLOGY/REMARKS GAS DESCRIPTION DAILY ACTIVITY SUMMARY Continue to mix mud and rig work, POOH, make up BHA, RIH to 284' and test MWD, continue RIH at report time Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020902.htm 9/16/02 Daily Report Aurora Gas ) Nicolai Creek 1 B REPORT FOR Dave Lancaster DATE Sep 03, 2002 TIME 06:00:00 CASING INFORMATION SURVEY DATA BIT INFORMATION NO. SIZE TYPE DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW VIS FC SOL MWD SUMMARY ) INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUT ANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL Page 1 of 1 ') ') DAILY WELLSITE REPORT [:I EPOCH DEPTH 2210 YESTERDAY 2186 PRESENT OPERATION= Milling casing 24 Hour Footage 24 DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SIN INTERVAL CONDITION REASON JETS IN OUT FOOTAGE HOURS T/BlC PULLED HIGH LOW AVERAGE CURRENT AVG 14.9 @ 2197 1.1 @ 2191 3.3 1.2 ft/hr @ @ amps 9 @ 2210 @ 2188 6.1 9.7 Klbs @ @ RPM @ @ psi DEPTH: PV yp FL Gels CL- SD OIL MBL pH Ca+ CCI HIGH 17 @ 2186 @ LOW 5 @ 2203 @ AVERAGE 9.6 TRIP GAS= 90 WIPER GAS= SURVEY= 3560 @ 0 @ 0 @ 0 @ 0 @ CH ROMATOG RAPHYwpm) 2186 1070 @ 2203 @ @ @ @ CONNECTION GAS HIGH= None AVG= CURRENT CURRENT BACKGROUND/AVG 10 1836.7 0.0 0.0 0.0 0.0 None LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Milled casing steel, cement, slight trace sand. PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Finish RIH, RlU power swivel, circulate and get back 90 units trip gas, set PKR and shear off whipstock bolt, start milling casing at 2186', milling at report time. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020903.htm 9/16/02 Daily Report Aurora Gas ) Nicolai Creek 1 B REPORT FOR Dave Lancaster DATE Sep 04, 2002 TIME 06:00:00 CASING INFORMATION SURVEY DATA BIT INFORMATION NO. SIZE TYPE DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW VIS FC SOL MWD SUMMARY ) INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENT ANE(C-5) HYDROCARBON SHOWS INTERVAL Page 1 of 1 ) ') DAILY WELLSITE REPORT [j EPOCH DEPTH 2206 YESTERDAY 2200 PRESENT OPERATION= Milling 24 Hour Footage 6 DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SIN INTERVAL CONDITION REASON JETS IN OUT FOOTAGE HOURS T/B1C PULLED HIGH LOW AVERAGE CURRENT AVG 3.7 @ 2204 0.4 @ 2205 2.8 0.9 ft/hr @ @ amps 8 @ 2202 @ 2205 6.4 7.3 Klbs @ @ RPM @ @ psi DEPTH: PV yp FL Gels CL- SO OIL MBL pH Ca+ CCI HIGH LOW AVERAGE 11 @ 2205 5 @ 2203 9.8 @ @ CHROMA TOGRAPHY(ppm) 2230 @ 2205 1070 @ 2203 1951.7 0 @ 0 @ 0.0 0 @ 0 @ 0.0 0 @ 0 @ 0.0 0 @ 0 @ 0.0 TRIP GAS= None WIPER GAS= SURVEY= CONNECTION GAS HIGH= N/A AVG= CURRENT CURRENT BACKGROUND/AVG 11 LITHOLOGY/REMARKS DESCRIPTION GAS LITHOLOGY Steel filings, decreasing cement, trace to 30% sand. PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Mill from 2200' to 2206'. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith ) C: \ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020904.htm 9/16/02 Daily Report ') ) Aurora Gas DAILY WELLSITE REPORT Nicolai Creek 1 B REPORT FOR Dave Lancaster DATE Sep 05, 2002 DEPTH 2205 TIME 06:00:00 YESTERDAY 2205 24 Hour Footage 0 CASING INFORMATION SURVEY DATA DEPTH INCLINATION AZIMUTH BIT INFORMATION INTERVAL NO. SIZE TYPE SIN JETS IN OUT FOOTAGE HOURS DRILLING PARAMETERS HIGH LOW AVERAGE RATE OF PENETRATION 0.0 @ 0 @ SURFACE TORQUE 0 @ 0 @ WEIGHT ON BIT 0 @ 0 @ ROTARY RPM 0 @ 0 @ PUMP PRESSURE 0 @ 0 @ DRILLING MUD REPORT DEPTH: MW VIS PV yp FL FC SOL SD OIL MBL MWD SUMMARY ) INTERVAL TO TOOLS GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 0 @ 0 @ CUTTING GAS @ @ CH ROMATOG RAPHYwpm) METHANE(C-1) 0 @ 0 @ ETHANE(C-2) 0 @ 0 @ PROPANE(C-3) 0 @ 0 @ BUT AN E(C-4) 0 @ 0 @ PENT ANE(C-5) 0 @ 0 @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS Page 1 of 1 ) g EPOCH PRESENT OPERATION= Milling VERTICAL DEPTH CONDITION T/BlC REASON PULLED CURRENT AVG ft/hr amps Klbs RPM psi Gels CL- pH Ca+ CCI TRIP GAS= 75 WIPER GAS= SURVEY= CONNECTION GAS HIGH= N/A AVG= CURRENT CURRENT BACKGROUND/AVG 5 GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY Milled casing steel, trace sand, cement. DAILY ACTIVITY SUMMARY POOH, inspect mill, test BOP, install wear bushing, RIH with starting mill and string mill, tag at 2204', mill on window. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020905.htm 9/16/02 Daily Report ') Aurora Gas Nicolai Creek 1 B REPORT FOR Dave Lancaster DATE Sep 06, 2002 TIME 06:00:00 CASING INFORMATION SURVEY DATA BIT INFORMATION NO. SIZE TYPE DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW VIS FC SOL MWD SUMMARY ) INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENT ANE(C-5) HYDROCARBON SHOWS INTERVAL Page 1 of 1 ') ) DAILY WELLSITE REPORT [j EPOCH DEPTH 2218 YESTERDAY 2205 PRESENT OPERATION= Milling 24 Hour Footage 13 DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SIN INTERVAL CONDITION REASON JETS IN OUT FOOTAGE HOURS T/BlC PULLED HIGH LOW AVERAGE CURRENT AVG 41.7 @ 2212 2.0 @ 2207 11.4 3.6 ft/hr @ @ amps 14 @ 2214 2 @ 2218 7.8 8.3 Klbs @ @ RPM @ @ psi DEPTH: PV yp FL Gels CL- SD OIL MBL pH Ca+ CCI HIGH LOW AVERAGE 11 @ 2205 4 @ 2211 7.6 @ @ CH ROMATOG RAPHY(ppm) 2230 @ 2205 959 @ 2211 1345.3 0 @ 0 @ 0.0 0 @ 0 @ 0.0 0 @ 0 @ 0.0 0 @ 0 @ 0.0 TRIP GAS= n/a WIPER GAS= n/a SURVEY= n/a CONNECTION GAS HIGH= none AVG= none CURRENT none CURRENT BACKGROUND/AVG 5 LlTHOLOGY/REMARKS DESCRIPTION GAS LITHOLOGY Sand, milled casing steel, trace cement. PRESENT LITHOLOGY 70% sand, 30% steel and cement. DAILY ACTIVITY SUMMARY Mill on window from 2204' to 2218', milling at report time. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020906.htm 9/16/02 Daily Report ) Aurora Nicolai Creek 1 B REPORT FOR Dave Lancaster DATE Sep 07, 2002 TIME 06:00:00 CASING INFORMATION SURVEY DATA BIT INFORMATION NO. SIZE TYPE 2 81/2 Security XSC1 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW VIS FC SOL MWD SUMMARY ) INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C.1) ETHANE(G-2) PROPANE(C-3) BUTANE(C-4) PENT ANE(C-5) HYDROCARBON SHOWS INTERVAL ) ) Page 1 of 1 DAILY WELLSITE REPORT [j EPOCH DEPTH 2330 YESTERDAY 2219 PRESENT OPERA TION= Drilling 24 Hour Footage 111 DEPTH INCLINATION AZIMUTH VERTICAL DEPTH INTERVAL CONDITION SIN JETS IN OUT FOOTAGE HOURS TIBIC 756259 3x16 2218 HIGH LOW AVERAGE CURRENT AVG 87.4 @ 2308 7.3 @ 2219 36.8 28.2 @ @ 14 @ 2219 @ 2226 6.9 7.5 @ @ @ @ DEPTH: PV SO Gels yp OIL FL MBL pH HIGH LOW AVERAGE 62.8 210 @ 2318 4 @ 2230 @ @ CHROMATOGRAPHY(ppm) 42998 @ 2319 815 @ 2230 20 @ 2319 1 @ 2302 0 @ 0 @ 0 @ 0 @ 0 @ 0 @ REASON PULLED ft/hr amps Klbs RPM psi CL- Ca+ CCI TRIP GAS= 11 WIPER GAS= SURVEY= 11759.8 4.2 0.0 0.0 0.0 CONNECTION GAS HIGH= None AVG= CURRENT CURRENT BACKGROUND/AVG 50 None LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Sand, coal, claystone, siltstone, carbonaceous shale. PRESENT LITHOLOGY 40% coal, 20% claystone, 30% sand, 10% conglomeratic sand. DAILY ACTIVITY SUMMARY Circulate well, perform integrity test, POOH, UD mill, P/U BHA, RIH, tag @ 2218', break circulation, drill. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith ) c:\ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020907.htm 9/16/02 Daily Report ) Aurora Gas Nicolai Creek 1 B REPORT FOR Dave Lancaster DATE Sep 08, 2002 TIME 06:00:00 CASING INFORMATION SURVEY DATA BIT INFORMATION NO. SIZE 2 8 1/2 TYPE Security XSC1 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW FC ) MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUT ANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL Page 1 of 1 ') ) DAILY WELLSITE REPORT g EPOCH DEPTH 2670 YESTERDAY 2330 PRESENT OPERA TION= Drilling ahead 24 Hour Footage 340 DEPTH AZIMUTH VERTICAL DEPTH INCLINATION SIN 756259 INTERVAL JETS IN OUT 3X16 2218 HOURS CONDITION T/BIC REASON PULLED FOOTAGE VIS SOL HIGH LOW 93.2 @ 2505 2.1 @ 2528 @ @ 21 @ 2403 2 @ 2374 @ @ @ @ DEPTH: PV yp SD OIL CCI AVERAGE 32.4 CURRENT AVG 18.7 ft/hr amps Klbs RPM 13.6 15.7 psi Gels CL- FL MBL pH Ca+ HIGH LOW AVERAGE 644 @ 2352 12 @ 2528 164.3 @ @ CHROMATOGRAPHY~pm) 147948 @ 2352 2588 @ 2528 33891.0 61 @ 2354 1 @ 2579 16.3 0 @ 0 @ 0.0 0 @ 0 @ 0.0 0 @ 0 @ 0.0 none LITHOLOGY/REMARKS TRIP GAS= n/a WIPER GAS= n/a SURVEY= none CONNECTION GAS HIGH= 225 AVG= 225 CURRENT none CURRENT BACKGROUND/AVG 120 GAS DESCRIPTION LITHOLOGY Sand/sandstone/conglomeratic sand, coal, tuffaceous claystone, carbonaceous shale. PRESENT LITHOLOGY 40% tuffaceous claystone, 30% coal, 20% sand, 10% carbonaceous shale. DAILY ACTIVITY SUMMARY Drill from 2330' to 2670' at report time. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020908.htm 9/16/02 Daily Report Page 1 of 1 ) ) ) Aurora Gas DAILY WELLSITE REPORT ~ EPOCH Nicolai Creek 1 B REPORT FOR Dave Lancaster DATE Sep 09,2002 TIME 05:00:00 DEPTH 2894 YESTERDAY 2671 PRESENT OPERATION= Drilling after short trip 24 Hour Footage 223 CASING INFORMATION SURVEY DATA DEPTH 2841 INCLINATION 0.62 AZIMUTH 50.86 VERTICAL DEPTH 2786.89 BIT INFORMATION NO. SIZE 2 8 1/2 TYPE Security XSC1 SIN 756259 INTERVAL JETS IN OUT 3x16 2218 FOOTAGE HOURS CONDITION T/B/C REASON PULLED DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW FC VIS SOL HIGH LOW 141.7 @ 2718 2.5 @ @ @ 36 @ 2680 @ @ @ @ @ DEPTH: PV SD 2723 AVERAGE 30.0 CURRENT AVG 28.7 2787 10.6 15.4 ft/hr amps Klbs RPM psi YP OIL FL MBL Gels CL- pH Ca+ CCI ) MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS HIGH LOW AVERAGE 194.6 TRIP GAS= WIPER GAS= 175 SURVEY= METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENT ANE(C-5) HYDROCARBON SHOWS INTERVAL 85904 @ 32 @ 0 @ 0 @ 0 @ 410 @ 2714 100 @ 2787 @ @ CHROMA TOGRAPHY(ppm) 2714 19774 @ 2787 2869 8 @ 2789 0 @ 0 @ 0 @ 38283.8 18.3 0.0 0.0 0.0 CONNECTION GAS HIGH= none AVG= none CURRENT none CURRENT BACKGROUND/AVG 150 none LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY sand/sandstone/conglomerate, tuffaceous claystone, coal, carbonaceous shale. PRESENT LITHOLOGY 40% sand/conglomerate, 20% coal, 30% tuffaceous claystone, 10% carbonaceous shale. DAILY ACTIVITY SUMMARY Drill from 2670' to 2894', circulate bottoms up, wiper trip 11 stands to shoe, RIH to bottom, break circulation, drilling 2900' with no lagged returns at report time. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C:\ WINDOWS\Desktop\NCU-lB\Reports\Morning Reports\20020909.htm 9/16/02 Daily Report Page 1 of 1 ) ) Aurora Gas DAILY WELLSITE REPORT ~ EPOCH Nicolai Creek 1 B REPORT FOR Dave Lancaster DATE Sep 10, 2002 TIME 05:00:08 DEPTH 3266 YESTERDAY 2895 PRESENT OPERATION= Drilling ahead 24 Hour Footage 371 CASING INFORMATION SURVEY DATA DEPTH 3120 INCLINATION 0.12 AZIMUTH 57.49 VERTICAL DEPTH 3065.88 BIT INFORMATION NO. SIZE 2 8 1/2 TYPE Security XSC1 INTERVAL CONDITION SIN JETS IN OUT FOOTAGE HOURS TIB/C 756259 3x16 2218 1048 45 HIGH LOW AVERAGE CURRENT AVG 298.9 @ 3139 3.9 @ 3029 31.2 42.2 @ @ 36 @ 3140 3 @ 3237 14.8 6.6 @ @ @ @ DEPTH: 2960 REASON PULLED DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE ft/hr amps Klbs RPM psi DRILLING MUD REPORT MW 10.5 VIS 52 PV 16 yp 36 FL 7.0 Gels 10/16/19 CL- 31000 FC 2 SOL 10 SD 1.0 OIL 0 MBL 10.0 pH 9.0 Ca+ 80 CCI ) MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 725 @ 3192 57 @ 3051 185.3 TRIP GAS= n/a CUTTING GAS @ @ WIPER GAS= n/a CH ROMATOG RAPHYwpm) SURVEY= none METHANE(C-1) 148491 @ 3192 11550 @ 3124 31034.4 CONNECTION GAS HIGH= none ETHANE(C-2) 122 @ 3192 7 @ 3142 24.3 AVG= n/a PROPANE(C-3) 0 @ 0 @ 0.0 CURRENT none BUTANE(C-4) 0 @ 0 @ 0.0 CURRENT BACKGROUND/AVG 155 PENTANE(C-5) 0 @ 0 @ 0.0 HYDROCARBON SHOWS none INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Sand/sandstone, conglomeratic sand, tuffaceous claystone, tuffaceous siltstone, coal, carbonaceous shale. PRESENT LITHOLOGY 40% sand, 10% conglomeratic sand, 30% tuffaceous claystone, 10% tuffaceous siltstone, 10% carbonaceous shale. DAILY ACTIVITY SUMMARY Drill from 2894' to 3081', slide from 3081' to 3091', drill from 3091' to 3266' lagged depth at report time. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-lB\Reports\Morning Reports\2002091 O.htm 9/16/02 Daily Report Page 1 of 1 ) ) Aurora Gas DAILY WELLSITE REPORT [I EPOCH Nicolai Creek 1 B REPORT FOR David Lancaster DATE Sep 11,2002 TIME 05:00:00 DEPTH 3672 YESTERDAY 3267 PRESENT OPERATION= Circulating hole for short trip 24 Hour Footage 405 CASING INFORMATION SURVEY DATA DEPTH 3618 INCLINATION 0.26 AZIMUTH 97.43 VERTICAL DEPTH 3563.87 BIT INFORMATION NO. SIZE 2 8 1/2 TYPE Security XSC1 INTERVAL CONDITION SIN JETS IN OUT FOOTAGE HOURS T/B/C 756259 3x16 2218 1454 62.4 HIGH LOW AVERAGE CURRENT AVG 129.5 @ 3411 5.4 @ 3655 32.8 19.2 @ @ 40 @ 3485 @ 3453 15.7 18.6 @ @ @ @ DEPTH: 3570 REASON PULLED DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE ft/hr amps Klbs RPM psi DRILLING MUD REPORT 9 SD 18 1.0 YP 35 FL 7.0 Gels OIL 2 MBL 12.0 pH 11/20/25 9.0 CL~ 30000 120 CCI MW FC 10.6 2 VIS SOL 54 PV Ca+ ) MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS HIGH LOW AVERAGE 185.6 TRIP GAS= n/a WIPER GAS= nla 585 @ 3378 46 @ 3485 @ @ CH ROMATOG RAPHY(ppm) @ 3378 9482 @ 3485 @ 3408 15 @ 3298 @ 0 @ @ 0 @ @ 0 @ 39913.6 95.8 0.0 0.0 0.0 SURVEY= none CONNECTION GAS HIGH= none AVG= nla CURRENT none CURRENT BACKGROUND/AVG 30 METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENT ANE(C-5) HYDROCARBON SHOWS INTERVAL 146615 359 0 0 0 none LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Sand, sandstone, conglomerate, tuffaceous claystone, carbonaceous shale, coal. PRESENT LITHOLOGY 40% sand, 20% sandstone, 10% conglomeratic sand, 30% tuffaceous claystone at bottoms up. DAILY ACTIVITY SUMMARY Drill from 3267' to 3672', circulating hole for short trip to shoe at report time. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C:\ WlNDOWS\Desktop\NCU-lB\Reports\Moming Reports\20020911.htm 9/16/02 Daily Report Page 1 of 1 ') / ) ) Aurora Gas DAILY WELLSITE REPORT [j EPOCH Nicolai Creek 1 B REPORT FOR DATE Sep 12, 2002 TIME 05:00:00 DEPTH 3672 YESTERDAY 3672 PRESENT OPERA TION= RIU Schlumberger 24 Hour Footage 0 CASING INFORMATION TYPE Security XSC1 DEPTH INCLINATION INTERVAl SIN JETS IN OUT 756259 2x16,1x15 2218 3672 HIGH LOW @ @ @ @ @ @ @ @ @ @ AZIMUTH VERTICAl DEPTH SURVEY DATA BIT INFORMATION NO. SIZE 2 8 1/2 FOOTAGE 1454 HOURS 62.4 CONDITION T/B/C REASON PULLED TD DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE AVERAGE CURRENT AVG ft/hr amps Klbs RPM psi DRILLING MUD REPORT MW FC VIS SOL DEPTH: n/a PV yp FL Gels CL- SO OIL MBL pH Ca+ CCI .) MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS HIGH LOW AVERAGE @ @ @ @ CHROMATOGRAPHY(ppm) TRIP GAS= WIPER GAS= 390u SURVEY= METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL @ @ @ @ @ @ @ @ @ @ CONNECTION GAS HIGH= AVG= CURRENT CURRENT BACKGROUND/AVG n/a LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY Finish short trip, circulate and condition mud, get back 390 units wiper gas, POOH, UD BHA, remove wear bushing, test BOP, pipe ram failure, clean cuttings from ram facing, finish test BOP, test manifold, RIU wireline at report time. Epoch Personel On Board= 4 Daily Cost $2250 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-lB\Reports\Morning Reports\20020912.htm 9/16/02 Daily Report ) Page 1 of 1 ) Nicolai Creek 1 B DAILY WELLSITE REPORT [j EPOCH ) Aurora Gas, LLC REPORT FOR David Lancaster DATE Sep 13, 2002 TIME 05:00:00 DEPTH 3672 YESTERDAY 3672 24 Hour Footage 0 CASING INFORMATION SURVEY DATA DEPTH BIT INFORMATION NO. SIZE SIN INTERVAL JETS IN OUT TYPE DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE HIGH DRILLING MUD REPORT MW VIS SOL PV SD FC ') MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS HIGH LOW @ @ @ @ PRESENT OPERATION= Circulating after TIH INCLINATION AZIMUTH VERTICAL DEPTH FOOTAGE CONDITION T/BlC REASON PULLED HOURS @ @ @ @ @ LOW AVERAGE @ @ @ @ @ DEPTH: yp FL OIL MBL CCI CURRENT AVG ft/hr amps Klbs RPM psi Gels CL- pH Ca+ AVERAGE TRIP GAS= 466u WIPER GAS= n/a SURVEY= n/a CHROMATOGRAPHY~pm) METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUT ANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL @ @ @ @ @ @ @ @ @ @ CONNECTION GAS HIGH= n/a AVG= n/a CURRENT n/a CURRENT BACKGROUND/AVG 3Q..40u LlTHOLOGY/REMARKS LITHOLOGY PRESENT LITHOLOGY DAILY ACTIVITY SUMMARY GAS DESCRIPTION RIH with wireline, E-Iog hole, POOH and RID schlumberger, RIH to condition and clean hole, circulate, get back 466 units gas at bottoms up, circulating at report time. Epoch Personel On Board= 2 Daily Cost $1970 Report by: T. Smith C: \ WINDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020913 .htm 9/16/02 Daily Report ) Page 1 of 1 ) Nicolai Creek 1B DAILY WELLSITE REPORT U EPOCH ) Aurora Gas, LLC REPORT FOR David Lancaster DATE Sep 14, 2002 TIME 05:00:46 DEPTH 3672 YESTERDAY 3672 24 Hour Footage 0 CASING INFORMATION SURVEY DATA DEPTH BIT INFORMATION NO. SIZE SIN INTERVAL JETS IN OUT TYPE DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE HIGH @ @ @ @ @ DRILLING MUD REPORT MW VIS SOL PV SD FC MWD SUMMARY ) INTERVAL TOOLS TO GAS SUMMARY(units) DITCH GAS CUTTING GAS HIGH LOW @ @ @ @ CHROMA TOGRAPHY(ppm) TRIP GAS= nla WIPER GAS= nla SURVEY= nla METHANE(C-1) ETHANE(C-2) PROPANE(C-3) BUT ANE(C-4) PENT ANE(C-5) HYDROCARBON SHOWS INTERVAL @ @ @ @ @ @ @ @ @ @ PRESENT OPERA TION= Running 7" casing INCLINATION AZIMUTH VERTICAL DEPTH FOOTAGE CONDITION T/B/C REASON PULLED HOURS LOW AVERAGE @ @ @ @ @ DEPTH: YP FL OIL MBL CURRENT AVG ft/hr amps Klbs RPM psi Gels CL- pH Ca+ CCI AVERAGE CONNECTION GAS HIGH= nla AVG= nla CURRENT nla CURRENT BACKGROUNDIAVG none LlTHOLOGYIREMARKS LITHOLOGY PRESENT LITHOLOGY GAS DESCRIPTION DAILY ACTIVITY SUMMARY Finish circulating hole, POOH, install?" rams in BOP, pull wear bushing, running in?" casing at report time. Epoch Personel On Board= 2 Daily Cost $1970 Report by: T. Smith C:\ WlNDOWS\Desktop\NCU-IB\Reports\Morning Reports\20020914.htm 9/16/02 As-Built NCU9 ) ') Subject: As-Built NCU 9 Date: Thu, 3 Apr 2003 08:34:04 -0900 From: duane vaagen <duane@fairweather.com> To: 'Tom Maunder' <tom_maunder@admin.state.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 , ! INCU 9 asbuilt.pdfj Type: Acrobat (application/pdf)! ¡ r Encoding: base64 i i'vH'1:':'w."Y~Y,(Y'>i'I<r/~'~"i'~'XW""'W~}tX(~Y.:«W"M',\¡(fO({:w.Z)ol.'<:"i"W<''('. )oX)M¡.'If""I?'''''X»w.-:f""/.1''''ff"(f;l-''«'''W'l/.¡¡:WI1'C»Y"KXt'J}X ~. -i-¡IU¡w..w-~:_'t:w.r.'~y,.rv.t""("H''''''''{r'¡'U- '~'''''rxx<¡y.i'~''Y'f"l''Y'; w z 3: ::i'O z,!O 0 ex) ¡=: p ü ~ wO (J) (J) ~, + SECTION 30 SECTION 31 WELL #9 GRID N: 2565248.120 GRID E: 241585.426 LATITUDE: 61'00'48.517" LONGIWDE: -151'27'23.402" ElEV. 32.9 FT. MLLW - - - - - - - - - - - - - PAD LIMITS ---------------- ------------------------ .. ------------------, -- -- --- PAD LIMITS \ r-- \ / \ / \ / \ / \ / \ ! WE~~ \ / GRID N: 2565238.314 \ I GRID E: 241533.129 '- LATITUDE: 61'00'48.409" - - - ï ~ LONGITUDE: -151'27'24.459" ...... " " ELEV. 33.2 FT'ML.L¡W . \ 295' FWL /) 261' FWL ( 209' FWL . I; 1 186' FWl I~ ~ ) J . ~ 0 If!! I~ :::J 1° « .-10- C~-=--=-------- WELL #1 GRID N: 2565238.429 GRID E: 241509.651 LATIWDE: 61'00'48.405" LONGITUDE: -151'27'24.935" ELEV. 32.5 FT. MLLW / WELL #6 GRID N: 2565284.791 . ~ GRID E: 241620.232 LA TITUDE: 61"00'48.886" .. LONGITUDE: -151'27'22.713" ELEV. 33.6 FT. MLLW 1999' FSL 2010' FSL 1999' FSL 2048' FSL SECTION 29 SECTION 32 PROTRACTED SECTION CORNER GRID N: 2563243.909 GRID E: 241284.057 LATITUDE: 61'00'28.720" LONGIWDE: -151'27'28.610" SECTION LINE 588'44'34"E LEGEND ~ 0 FOUND 1/2 REBAR W/NClANE CN> . SET 1/2 REBAR W/N~E CAP e VÆLL NOTES 1> BASIS Of' CDDRDINA'ŒS IS ALASKA STA'Œ PLANE NAD 27 ZONE ., AND IS FROM A DIRECT liE 10 ADl NO. 31270. 2) BASIS Of' EL£VAlION IS FROM DIRECT lIDAL 08SERVAlION ON 9-22-1/3. OAlUM IS NLLW. AlL ELEVAlIONS SHO\WII HEREON Yl£RE TAKEN ON GROUND. 3) SEClION UNES SHO.,.,.. HEREON ARE BASED ON PROTRACTED VALUES. 4) BEARINGS SHO'MII HEREON ARE GRID. \ \ \ \ \ \ ~----------------------- SECTION 29 TOWNSIHP 11 NORTH RANGE 12 WEST SEWARD MERIDIAN. AK AIRSTRIP "')"~'II't fí:~.1 ~f(~ ~'ð(~¡ ¡..¡ II: \~#~~J~f ~ ~ I ;¡ !~ Ii" d ~ ~~ w ~~ 0 0 i C'-I~ g- ~~~j ~~~i ~~~i s ~ ~ ~ ~ 11 \T g> !l. 11: l!f!!! ..:..J \l "N ~ ¡.;. i!õT ~ u~:! ~i¡i j Ix \) i ::r c:I is': CRAWN BY lSC . CHECKED BY pea HPAZ. SCA1£1" . 80' YERT. SCALE N/A PAW. NO. D23I02 SHEET 1 Re: Well sign information ) ) d[);)-/~~ Subject: Re: Well sign information Date: Wed, 06 Nov 2002 12:33:26 -0900 From:.Tom Maunder <tom_maunder@admin.state.ak.us> To: Jeff Osborne <josborne@fairweather.com> Jeff, The suggestion over here is to send in a copy of the as built for the wells. You can fax it and we will put the information in the files. With regard to the location for the well signs, I would use the best information you have (the new stuff). Tom Tom Maunder wrote: > Jeff, > I will check on this matter. Things are close. There may be a need to send in > sundry notices regarding the updated surface locations. I will get back to you. > > Tom > > Jeff Osborne wrote: > > > Tom, > > Aurora Gas needs to replace a well sign for Nicolai Creek Unit #2. It has > > come to our attention, that the well data on the sign matches that on the > > approve permit to drill. > > However, when the surveyors were locating and as-builting the NCU #8 and #9 > > locations, they as-built the #1 Band #2 locations. These locations are > > different from the original data that has been used since #1 and #2 were > > originally spudded. » > > Forexample, > > 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 1117/20023:51 PM aOd-}0~ DATA TRANSMITTAL Please reply to: Aurora Gas, LLC 10333 Richmond, Ste. 710 Houston, TX 77042 Attn: Andy Clifford Alaska Oil & Gas Conservation Commission 333 W. ih Avenue. Ste.l00 Anchorage. AK 99501 ATTENTION: Bob Crandall Enclosed are 4 paper prints of logs From Aurora Gas. LLC Field Nicolai Creek Wells NCU #IB RECEIVED NOV 0 12002 Alaska Oil & Gas Gons. Commission Anchorage Paper Prints: 1. NCU#IB RST Sigma & CO Modes 5t"inch Log 2. NCU#IB Perforating Record 3. NCU#IB Cement Bond 5-inch Log 4. NCU#IB BestDT* Final Result Log Received ~(£Jpo~ Date: AURORA GAS, LLC, 10333 RICHMOND, STE 710, HOUSTON, TX 77042 TEL: 713-977-5799, FAX: 713-977-1347 J ~ ~ ~ \ <i 0 n w Z ~ :::¡: 0 Z ~ 0 CXJ - 0 f- . U .- w 0 (/) (/) ~ SECTION 30 SECTION 31 --------------------\ - - - PAD LIMITS \ r \ / \ / \ / \ / \ / \ II ~ \ WELL #2 - / GRID N: 2565238.314 \ I GRID E: 241533.129 "- - I LA TITUDE: 61"00'48.409" - - "\ LONGITUDE: -151"27'24.459" t.... ....... ELEV. 33.2 FT. MLLW ....... ....... \ 295' FWL /) 261' FWL ( 209' FWL I 186' FWL ) I~ I~ ¡::J I~ .-1Q C-=--=--=-~------ " LEGEND 0 fOUND 1/2 REBAR W/"'CLANE CAP . SET 1/2 REBAR W/"'CLANE CAP @) I'ÆLL Q NOTES 1) BASIS OF COORDINATES IS AlASKA STATE PLANE NAD 27 ZONE 4. AND IS fROI.I A DIRECT TIE TO ADL NO. 31270. 2) BASIS OF ELEVATION IS fRON DIRECT TIDAl OBSERVATION ON 9-22-93. DATU... IS ...u.w. AlL ELEVATIONS SHOWN HEREON I'ÆRE TAKEN ON GROUND. 3) SECTION LINES SHOWN HEREON ARE BASED ON PROTRACTED VAlUES. 4) BEARINGS SHOWN HEREON ARE GRID. 0 \ \ \ \ \ \ \ ~ ~!~~{:~i~~i'li~:~;;:'402. L - - - - - - - - - -A:S~R: - - - - - - - - - - - - - - - - - - - - - - - - _E:~ :;;~~~~;~ - - - - -- - - - - - - - - - - - - - - - - - - - - - - - -- WELL #1 GRID N: 2565238.429 GRID E:241509.651 LATITUDE: 61"00'48.405" LONGITUDE: -151"27'24.935" ELEV. 32.5 FT. MLLW 1999' FSL 1999' FSL SECTION 29 SECTION 32 PROTRACTED SECTION CORNER GRID N: 2563243.909 GRID E: 241284.057 LA TITUDE: 61"00'28.720" LONGITUDE: -151'27'28.610" / WELL #6 GRID N: 2565284.791 r J? GRID E: 241620.232 . LA TITUDE: 61"00' 48.886" LONGITUDE: -151"27'22.713" .. ELEV. 33.6 FT. MLLW 2010' FSL 2048' FSL SECTION LINE S88"44' 34"E SECTION 29 TOWNSIHP 11 NORTH RANGE 12 WEST SEWARD MERIDIAN, AK """\":~'t~"I,, j"~~~.<1~~\ =~~\J - :\~ ~~~~~+iý >- "" ~ ~ 0 ~... ~~ <; 0... ~~ ~z gã < 0 > 0: NN ~~ 0 ... N 0 0 Z (\I~ ~~g- '-' ~ ~~ D... . ~ ~êm; ~ ~ ~g 3~j: -....... v O~ ()~ Zs ~ ¡;; ~ < 0 " Z 0... ~(ft :::I ".." <:> ",., '- ~en \.T '-en ~] ~ ~Q) :g ~ ~ <-¡;; ~ ~ ~§ ~ ~ ~~: ~q¡ ~:~ t: ,"'- <1:1 "" -! ZO ~ ~~ ¿ ~~ ORAYoN BY LSC CHEO<ED BY PCO HORZ. SCAlE I" - 60. vERT. SCAlE NIA DRWC. NO- 023102 SHEET 1 - ) ) " ~Aurora Gas, I.I.C www.aurorapower.com October 10, 2002 Robert P. Crandall AOGCC 333 W. ih Avenue, Ste. 100 Anchorage, AK 99501 RE: NICOLAI CREEK UNIT #l-B/ #2 LOG DATA Dear Bob: Please find enclosed a complete set of final logs, in both paper copy and digital format, from the recently completed NCD #l-B well plus some further data from the NCD#2 well for the AOGCC files. We have also attached a transmittal detailing the enclosed data. We would appreciate a signed copy to acknowledge receipt of data. If there are any questions regarding the data submitted for this well or any other matter, please don't hesitate to call. (¡~~~ ill_liVID OCT 1412002 A181èa0l' GaB Qøns. COmmllSlon Anchorage A. C. (Andy) Clifford Vice President Exploration Aurora Gas, LLC enclosure acc/ oct 10 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 ') DATA TRANSMITTAL Please reply to: Aurora Gas, LLC 10333 Richmond, Ste. 710 Houston, TX 77042 Attn: Andy Clifford Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue. Ste.100 Anchorage. AK 99501 ATTENTION: Bob Crandall Enclosed are 2 CDs/2 floppy disks/6 prints plus 1 report with enclosed logs From Aurora Gas. LLC Field Nicolai Creek Wells NCU #IB/NCU #2 aOð..¡ Iod. / 101o-ö~ CD-ROMs: ~ Schlumberger Run#1 AIT/PEX/DSI/FMI from NCU#IB ~ Epoch Final Well Data including DML/LAS/PDF/Report from NCU#IB Floppy Disks: ¿ NCU#IA Bridge Plug, GR/CCL 8/28/2002 ¿ NCU#2 Completion Record 4.5" HSD PowerJet SSPF 8/6/2002 Paper Prints: ~ NCU#IA Completion Record q: NCU#2 Completion Record g:- NCU#IB FMI Log tt:" NCU#IB DSI Log ~ NCU#IB GR/Caliper Log 6<-' NCU#IB AIT/Density/CNL/GR/SP/Caliper Log RICI1VIÐ OCT 1 4 2002 Report: ~,-_Ga8GonLComm\SS\on y Epoch NCU#IB Final Well Report . - AnchOrage Received~~ Date: AURORA GAS, LLC, 10333 RICHMOND, STE 710, HOUSTON, TX 77042 TEL: 713-977-5799, FAX: 713-977-1347 ') SCHLUMBERGER WELL SERVICE~ A uì~ISION OF SCHLUMBERGER TECNOLOGY CORPORATION HOUSTON, TEXAS 77251-2175 a~¿ 10~ SEP 1 6 2002 PLEASE REPLY TO: Schlumberger Well Services 49420 Kenai Spur Highway Kenai, AK 99611 Attn: Shelley Ramsey Aurora Gas, LLC 0 10333 Richmond Avenue, Suite 710 Houston, TX 77042 TTFNJION: Enclosed are 4 prints/2 CD or floppies Company Aurora Gas, LLC Well Nicolai Creek Unit #1 B Field Nicolai Creek Additional prints are being sent to: 1 prints Aurora Gas, LLC 1029 West Third Avenue, Suite 220 Anchorage, AK 99501 , Attn: J. E. Jones of the Run 1, 9/12/02 logs listed below on: County Kenai State Alaska prints prints Array Induction/Density/CNUGR/SP/Caliper Fullbore Micro-Imager _Dual Axis Caliper Log Dipole Shear Imager prints -_......--._"" ___.0- ,- -----.-. ----.. ".. ,. . . ------"---~'- prints prints prints prints The film is returned to RI€b'~ n Received~ ~~ Qlae.Qøn8. GOm~ NØj!I. Ar.ct,OtnQt Date: Vve appreciate the privilege of serving you. Very truly yours, Schlumberger Well Services Billy Anthony Field Service Manager ') ~Aurora Gas, I.LC Septel11ber 5, 2002 Ms. Cammy Oechsli- Taylor, Chair Alaska Oil & Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Sundry Approval: Nicol~i Creek Unit No. IB Change Approved Program - 7" Casing Dear Commissioner Taylor, Aurora Gas LLC, hereby submits an Application For Sundry Approval. Application is made to change the approved program. The new program will run 7" 23# J-55 LTC casing from TD to surface in the NCU IB well. The approved plan called for a 7" liner cemented to TD, hung off in the 10 %" at 1850' MD. Although pressure testing found the 10 %" casing to be of sufficient integrity, an uncertainty still exists about the ultimate condition and economic life of this string. For safety, environmental and economic reasons, Aurora Gas LLC will run the 7" to surface as the preferred completion method. For the original PTD application, design calculations were performed on the 7" 23# J-55, and all requirements are met. With the changed casing scheme, the cementing procedure has changed as well. The program will install a stage collar at ~1850'. Cement the first stage (8-1/2" OH x 7" casing) with 15.8 ppg Class "G" cement from TD to ~ 1850. Cement the second stage (10-3/4" Csg x 7" Csg annulus) with 220 sks of 12.5 ppg lead cement followed by 70 sks 15.8 ppg cement tail. ECD computations indicate the 2-stage cementing program to be necessary. Attached with the Application For Sundry Approval is the revised Nicolai Creek Unit No. IB Cleanout and Sidetrack Procedure 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, Enclosures cc: Duane Vaagen Andy Clifford ') k-q fj ;?:j { Co o~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL 1. Type of Request: [ ] Abandon [ ] Suspend [ ] Alter Casing [ ] Repair Well [X] Change Approved Program [] Operation Shutdown Aurora Gas, LLC [ ] Plugging [ ] Time Extension [ ] Perforate [ ] Pull Tubing [ ] Variance [ ] Other [ ] Re- Enter Suspended Well [] Stimulate 5. Type of well: 6. Datum Elevation (OF or KB) [X] Development 16' KB [ ] Exploratory [ ] Stratigraphic 7. Unit or Property Name [ ] Service Nicolai Creek Unit 8. Well Number NCU1B 9. Permit Number 202-162 10. API Number 50-283-10020-02 11. Field and Pool Nicolai Creek Gas Field 2. Name of Operator 10333 Richmond Avenue,.Suite 710 Houston, Texas 77024 4. Location of well at surface 2018' FSL, 195' FWL, Sec.29, T11N ,R12W, SM At top of productive interval - 3325' MD 1637' FSL, 97 FWL, Sec.29, T11N, R12W, SM At effective depth 3. Address At total depth - 3653' MD 1637' FSL, 97' FWL, Sec.29, T11N, R12W, SM 12. Present well condition summary Well currently plugged & abandoned Total depth: measured 9302' Plugs (measured) true vertical 9149' meqsured feet true vertical feet Cement 3002'-3880' Effective depth: Junk (measured) Casing Length Size Cemented MD TVD Structural Conductor 232' 20" 300 sks to surface 232' 232' Surface 1904' 13-3/8" 1530 sks to surface 1904' 1869' Intermediate 3817' 10-3/4" 900 sks to surface 3817' 3690' Production Liner 4518' 7" 300 sks shoe, 380 sks sqzd 8298' 8194' Perforation depth: measured True vertical Tubing (size, grade and measured depth) Packers and SSSV (type and measured depth) 13. Attachments [X] Description of Sumary Proposal [ ] Detailed Operations Program 15. Status of well classification as: [ ] BOP Sketch 14. Estimated date for commencing operation 21-Aug-02 16. If proposal was verbally approved Tom Maunder 4-Sep-02 Name of approver Date Approved Service Contact Engineer Name/Number: Mr. J. Edward Jones / (713) 977-5799 Prepared By Name/Number: Jeff Osborne / (907) 258-3446 17. I hereby c ify that the foregoing i tru and correct to the best of my knowledge Signed ç . (~~.Æ. Title Vice President Commission Use Only Notify mission so representative may witness Plug i grity BOP Test Location Clearance Mechanical Integrity Test Subsequent form required 10- ~~\5\~~<t."{'\...~~ cÁ- '-\0\ e~;\,,,~'Jc.. \ ~-\; \\ "'r>? \'1 . Approved by order of the Commission Gt.~ ~~~ Form 10-403 Rev. 06/15/88 IRIII [ ] Oil [ ] Gas [X] Suspended Date 9/.510 2- Commissioner I Approval No. ~oZ ".? fir 4()~ Q v..)t\\<ë.~ , Date ~~ Ò~ SUb~it In )"riplicate ) AURORA GAS, LLC NICOLAI CREEK UNIT NO. 1-8 CLEANOUT AND SIDETRACK PROCEDURE WELL INFORMATION: KB Elev.-46', KB-16'; PBTD-16' (surface); Original PBTD-3659' (MD). In 1991 Set cmt plugs @: 3002-3663', perfd 650', 705', 720-721'. EZSV @ 690' Sqzd w/ 230 sx cmt- TOC 601'. Set cmt plug to surface. Sqzd Tyonek Perfs (2 JSPF) at: 3420-3462' and 3615-3630' (57 feet of perfs over 210 feet gross interval) CASING: 10-3/4", 40.5#, J-55 Casing from surface to 3817' (produced w/ cmt plug @ 3663'). Cmtd w/ 900 sx to +/- surf. CAPACITY: 0.0981 bbl/ft or 196.2 bbl to 2000'. 13-3/8" set at 1904'. TUBING: None. Hole now filled w/ 13.6 ppg mud between cmt plugs-well suspended by Unocal in Aug. 1991 by setting above cmt plugs. PRODUCTION: Tested--7.35 MMCFDP @1147 psi FTP. Cum. Production-117.4 MMCF (3 mo.). PRESSURES: Max SITP=I555psi, Max BHP=I709 psi @ +/-3400' SURF. LOCATION: 2018' FSL, 195'FWL, Sec. 29, TIIN, RI2W, Seward Meridian, Kenai Borough, Alaska. WORKOVER PROCEDURE: 1. Cameron to inspect wellhead and design tree. 2. Move in Rig w/ power sub/swivel and w/ II" X 3000 psi (or greater) BOP (May need 13- 5/8" X 11" spool to attached to tree due to lack of sufficient seal around 1 0-3/4"). Rig up. Move in mud pump and tanks: (a) 500-bbl for water and 400-500 bbl tank for mud storage, (b) open 200-400 bbl steel mud pit w/ gas buster, mixing hopper, pill tank, and shaker, and (c) 400-bbl cuttings/flare pit (open tank). 3. Remove 13-3/8" blind flange. Install 13-5/8" 3M X II" 3M double-studded adapter. NU 11" 3000-psi BOP stack. Test to 250/2500 psi. 4. Mix 150 bbl 9.5 ppg, 35-40 vis mud (salvage from #3 workover?). RU PVT and flow indicators on mud system. 5. Pick up 9-7/8' (or 9-3/4") bit. Drill out cement, picking up 6 4-3/4" drill collars, then work string (3-1/2" DP). Drill out cement plug and EZSV to +/- 720'. Circulate hole clean, using high-vis (2.5 ppb Xanvis) mud sweep. 6. Clean out to 2400'. Circ hole clean. POOH w/ bit, DC's, and workstring. 7. PU 10-3/4" casing scraper above bit and run to 2400'. POOH, LD csg scraper. 8. RU electric line. Run GR-CCL correlation log. (Consider running TDT log to evaluate upper zones that would be encountered in #8 well-also could help with selection of KOP). PU packer and whipstock seat on electric line and run to 2250'. Orient to kick off toward surf location (to NE) w/ angle of about 17 deg, and set top at +/- 2200' (MD), avoiding csg collars. (Want to drill an essentially vertical hole out of window-hole has about a 17 deg, inclination at this point, so we want to drop the angle back to 0 deg. 9. PU and run casing whipstock assembly w/ starting mill on workstring w/ 1 stand of HWDP but w/o drill collars. Lock whipstock into packer, shear off starting mill, and cut hole in casing. ) 10. fOOH wi staring mill and LD. PU sidetracking bit/mill and watermelon mill, run in hole and cut window in casing and start pilot hole outside casing (+1-30'). POH. 11. PU tapered mill, watermelon mill, short DC, watermelon mill, and DC's and run in hole. Expand and dress window in casing. Perform Leak-Off- Test. POR. 12. Replace tapered mill wi 8-3/4" bit, run in hole and drill a.head wi watermelon mills (first bit run only). Circulate hole clean wi sweeps as needed. Consider conversion to KCI- based mud. 13. RU mud logger. 14. Drill 8-3/4" hole to 3600' TVD or about 3650' MD wi mud wts of9.8-10.0 ppg (expect gas cut mud throughout section, stop and circ out as needed, maintaining mud wt only slightly overbalanced). Circ and condition hole to Jog. POOH. IS. RU Schlumberger and log wi SP-DIL wi MicroSFL (?), OR-Sonic, and GR-Density- Neutron from TD to casing window. (Exact logging requirements to be decided at time when needed) 16. RIH wI bit and circ and condition hole for casing. POOH, LD DC's. 17. Run 7" casing (23#, J-55 LTC) :trom TD (shoe at 3650' wI float collar at +1-3610') to surface wI stage collar at ~18'50'. Cement fitst stage (8-112" OH x 7" casing) wI 15.8 ppg Class ''iG'' from TD to ~ 1850'. Cement second stage (10-3/4" casing x 7" casing annulus) wI 220 sks of 12.5 ppg lead cmt followed by 70 sks 15.8 ppg cmt tail. 18. PU 6-1/8" bit and casing scraper and clean out 7" casing to float collar (at +1-3610'). Close BOP and test liner to 2500 psi. Mix (have available) 350 bbl clean 3% KCI water. 19. On bottom, pump 50 bbl mud pill wI 2.5 ppb Xanvis viscosifier while rotating and reciprocating and diplace mud from hole wI KCI water. When returns are KCI water, short trip to liner top. Move mud to external tanks. Clean rig pit (wI pump and shaker), and circulate btms up 2-3X over shaker to clean. 20. Pull bit and scraper, tallying out of hole wI tubing, keeping hole full. 21. RU lubricator (3000-5000 psi) and wireline. Run OR-CCL log from PBTD to 100' above liner top, corr~late wI open hole-logs. 22. Pick up 4-l/2"guns and run on wireline (4 runs) to perforate 7" casing at equivalent of present perfs (3420-60'and 3615-30') and possibly equivalent of3325-35' (all dependent upon log analysis) wI Schlumberger 4-1/2" RSD guns w/6 SPF, 60-degree phasing (43NS charges for 0.83-inch hole, 6.49 sq in/ft of perfs). Keep hole full while perforating. (Results will be 65 net feet over 305' gross interval). RD lubricator. 23.. RIH wI bit and 7" csg scraper to PBTD. Circ 20 bbl high vis (HEC-IO) pill to clean out perforating debris. Circ btms up 2X or until clean returns. 24. POH and lay down bit, scraper, and DC's. Pick up and kIH wI MeshRite Assembly (310' of assembly wi 5" Meshrite screen across each perforated section, 3-1/2" tubing spacer, bull-nose shoe, and packer) on workstring. Rabbit as run, and dope only pin end wi small amount of dope on 1" paintbrush. Use screen table and worktable plates when running and hanging off screen. Tally in hole: top of packer should be at +1-3200'; running slowly (3 min./stand). Set packer. Release from packer and POOH, laying down workstring. 25. PU and run packer seal assembly wi locator and 2.81" X profile nipple above locator on 2-7/8", J-55, 6.5# 8Rd EUE Mod tubing. Circ packer fluid--+I- 200 bbl KCI water wI 02 scavenger. Stab in to packer, test seals to 2000 psi. Land tubing and set BP valve in tubing hanger. 26. ND BOP stack and NU tree. Test tree to 2500 psi. Rig up test separator and lines. 27. Swab well in to test separator. 28. When well is flowing satisfactorily, rig down rig and other equipment. 29. Proceed wi well cleanup and testing. Re: Nicolai Creek Unit NO.1 B ) Subjéct: Re: Nicolai Creek Unit No.1 B Date: Wed, 04 Sep 200207:04:57 -0800 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: duane vaagen <duane@fairweather.com> cc: 'Ed Jones' <jejones@aurorapower.com>, Bill Penrose <bill@fairweather.com> Duane, Bill, et al: I support your plan. I think this is a very good idea. A sundry notice with the proposed changes should be submitted. I don't think there will Qe any problems with an approval. Tom Maunder, PE AOGCC duane vaagen wrote: Tom: Aurora Gas LLC. will run 7" 23# J-55 LTC casing from TD to surface in the NCU 18 well. In the original plan submitted and approved, the intent was to just run and cement a 7" liner to TD, hung off in the 10 %" at 1850' MD.Despite the fact that pressure testing found the 10 %" casing to be of sufficient integrity, an uncertainty still exists about the ultimate condition and economic life of this string.Therefore; for safety, environmental and economic reasons, Aurora Gas LLC.feels running the 7" to surface is the preferred completion method. For the original PTD application, design calculations were performed on the 7" 23# J-55, and it all requirements are met. Since the casing scheme has changed, a change in the cementing procedure was called for as well.We now intend to install a stage collar at -1850'.We will cement the first stage (8 %" OH X 7" casing) with 15.8 ppg Class "G" cement from TD to -1850.The second stage (10 %" Csg X 7" Csg annulus) will be cemented with a 220 sks of 12.5 ppg lead cmt followed by 70 sks 15.8 ppg tail.ECD computations indicated the 2 stage cementing program to be necessary. ! I hope this meets with your approval. I I will be out of the office until Monday, the 9th at the soonest.Please let us know if this is acceptable. Please call Bill Penrose here in the office with any concerns. I Aurora Gas LLC.'s fax number is 277-1006. The latest news is they were milling the window today, will perform a BOP test, LOT and then start the OH drilling.Sounds like all is going well. The rig phone and fax# is 943-5027.The new company man on location filling in for David Morris is Dave Lancaster.The new rig email addressis:ncu218~aol.com Hope the jury duty is going ok. Regards, Duane Vaagen Fairweather E&P Services, Inc. duane~fairweather.com Office: (907)258-3448 I Cell: (907)240-1107 Tom Maunder <tom maunder~admin.state.ak.us> Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 10f2 9/612002 3:52 PM ) ') STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report 8/2812002 907-943.5027 - Ed Jones David Morris R. 12W Meridian DATE: 1 PTO # 202..162 Rig Ph.# Rep.: . Rig Rep.: Location: Sec. 29 T. 11N X Workover: Aurora Well Serv~ Rig No. Aurora Gas LCe NCU #1 A Set@.. Weekly OPERATION: Drlg: Drlg Contractor: Operator: Well Name: . Casing Size:. 103/4 Test: Initial SM 3,817 X Other .:..TES1::ÖATA: . Test Quan. Pressure FLOOR SAFETY VALVES: Upper Kelly I IBOP Lower Kelly I IBOP Ball Type Inside BOP P/F , MISC. INSPECTIONS: Location Gen.: OK Housekeeping: OK (Gen) PTD On Location YES Standing Order Postea-- Well Sign Yes Drf. Rig OK Hazard Sec. - 'I 1 1 200/3000 P 200/3000 P 200/3000 P Test Pressure P/F 200/3000 P 200/3000 ~- P 20013000 P 200/3000 P BOP STACK: Quan. Test Press. P/F Annular Preventer 1 200/1500 P Pipe Rams 1 200/3000 P Lower Pipe Rams Blind Rams 1 200/3000 P Choke Ln. Valves 1 200/3000 P HCR Valves 1 200/3000 - P KJIJ Line Valves 2 200/3000 p Check Valve MUD SYSTEM: Visual Alarm Trip Tank OK OK Pit Level Indicators OK OK Flow Indicator OK OK Meth Gas Detector OK YES H2S Gas Detector OK YES CHOKE MANIFOLD: No. Valves No. Flanges Manual Chokes Hydraulic Chokes 11 52 1 1 ACCUMULATOR SYSTEM: Syste m Pressure 3100 P Pressure After Closure 1700 P 200 psi Attained After Closure 2 . minutes 0 sec. System Pressure Attained 3"" minutes -¡¡) sec. Blind Switch Covers: Master: YES Remote: YES Nitgn. Btl's: 12 J 20 gal 1000 psi Psig. TEST RESULTS Number of Failures: 0 ,Test Time: 1.0 Hours. Number of valves tested 14 Repair or Replacement of Failed Eq uipment will be made within 1. days. Notify the Inspector and follow with \Mitten or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-3607 or 3687 If your call is not returned by the inspector within 12 hours please contact the P - I. Supervisor at 279-1433 Re-tested gas detection system, all systems { alarms I lights, operating. Ma~n power source wired to Epoch unit with UPS backup. Can NOT be unplugged. REMARKS: STATE WITNESS REQUIRED? . YES X NO Waived By: Distribution: 0 rig-We II File c - Oper./Rig c - Database c - Tñp Rpt File c - Inspector Chuck Sheavey, Tom Maunder Witnessed By: 24 HOUR NOTICE GIVEN YES X NO RECEIVED AUG 3 0 200Z AtaskaOii itG8 Cons. COmmisSiOn Adoiage Test 828 02 FI-021 L (Rev.12J94) t . d ~J~1!~ ,) rr¡ì r?r. I : I : ì ~u ~~~~~~ TONY KNOWLES, GOVERNOR AI,ASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 J. Edward Jones Vice Persident Aurora Gas 1029 West 4th Avenue Anchorage AK 99501 Re: Nicolai Creek Unit IB Aurora Gas Permit No: 202-162 Surface Location: 1637' FSL, 97' FWL, Sec. 29, TllN, R12W, SM Bottomhole Location: 1637' FSL, 97' FWL, Sec. 29, TIIN, RI2W, SM Dear Mr. Jones: Enclosed is the approved application for permit to redrill the above development well. The permit to redrill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. ill addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. Aurora Gas assumes the liability of any protest to the spacing exception that may occur. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below the surface ca~Íng shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission petroleum field inspector on the North Slope pager at 659-3607. Sincerely, Cæ~~U' kA~ Cammy Gtchsli Taylo;---ð- Chair BY ORDER ~~ THE COMMISSION DATED this.B1JJ. day of August, 2002 cc: Department ofFish & Game, Habitat Section w/o enc1. Department of Environmental Conservation w/o encI. STATE OF ALASKA ALASKP '11L AN~~~~~¥~~~V~r~N CO~lISS'ON 20 MC 25.005 , 1 a. Type of work [ ] Drill [X ] Redril, 1 b. Type of well [ ] Service [ XJ Development Gas [ ] Single Zone [X] Re-Entry [J Deepen ( JExploratory \ (J Stratigraphic Test. . .. [ J Develo~ment9i1 2. Name of Operator Aurora Gas LLC. 5. Datum Elevation (DF or KB) 10. Field and Pool 16' KB 6. Property Designation ADL 1 (585 7. Unit or Property Name Nicolai Creek Unit 8. Well Number NCU1B 9. Approximate spud date Amount $200,000 6-Aue-02. ... ; 14. Number of acres in property 15. Proposed depth (MD and TVD) . 5620 Acres 3653' MD (3600' TVD) 17. Anticipated pressure {see 20 AAC 25.035 (e) (2)} , Maximum surface 1555 . psi~ ~ At total depth (TVD) Setting Depth Specifications Top Bottom - Weight Grade Coupling' Len9th MD TVD MD TVD . 3. Address 10333 Richmond Ave. Ste 710 Houston, TX 77042 4. Location of well at surface 2018' FSL, 195' FWL, S29, T11N, R12W, SM At top of productive interval 3325' MD 1631' FSL, 97' FWL, See 29. T11N, R12W SM At total depth 3653' MD 1637' FSL, 97' FWL, See 29, T11N, R12W SM ."12:~~~~~~t~;~~ r=~~nL~eLn' ..113. ~~s~~(~~ ~e:t~~~= 16. To be completed for deviated well$ Kick Off Depth 2200. MD .1$.'.Ca5In9 Program Size ~ Hole Casing. Maximum Hole Angle 20 [ X] Multiple Zone Nicolai Creek Gas Field 11. Type Bond (See 20 MC 25.025) Letter of Credit Number NZS429815 1709 psip . Quantity of Cement Qnclude stage data) 8 1(2" K-55 LTC 180Q' 1850' ' 1818' "3650' 3600' 711 23# .19. TQ'be completed for Redrill, Re-entry, and Deepen Operations. Present well condition summary Well Currently Suspended Total depth: measured true vertical Effective depth: measured true vertical feet feet feet feet 9302 Plugs (measured) 9149 0 Junk (measured) No Junk, EZSV @ 690' MD 0 Casing Length Structural Conductor Surface Intermediate Production Liner Size Cemented MD TVD 20" 300 Sks to surface 232' 232' 13 3/8" 1530 Sks to surface 1904' 1869' 103/4" 900 Sks to surface 3817' 3690' 7" 300 Sks shoe, 380 Sks Sqzd 8298' H 8194' :¡\"~I E I \\1 ";':., 232' 1904' 3817' 4518' Perforation depth: measured true vertical Please see Attachment I, Well has 17 sets of perfor~~~Œ [ X] Filing Fee [ X] Property Plat [ X] BOP Sketch [ ] Diverter Sketch [ X] Drilling Program' [ Xl Drilling Fluid Pr~Qram ( J Time vs Depth Plot t J~~fraction Analysis [ ] Seabed Report [ XJ 20MC25.050 Req. Contact Engineer NarnelNumber: Mr. J. Edward Jonesl (713)977-5799 Prepared By NarnelNumber: Duane Vaagen / (907)258-3446 21. I hereby ce' tha.lt t~. t oreg. 9 Is rue and consct to the best of ~y knowled}7. ' 7 / _Signed &/. . Tille 0é¿ rr¿'J/~A'/ Date ~$c;/oZ-- Commission Use Only I Number . /\.-.. Approval Date I See cover letter S'D- Zb3 - / (...o{"....ì 2-D -<:::) '--. _I. ¡ ? l O~ for other requirements Samples Required: [ J Yes ~o ., Mud Log Required [ ] Yes 1<fNo Hydrogen Sulfide Measures: [ J Yes Þ<fNo Directional Survey Req'd Þ{ Yes [ ] No Required Working Pressure for BOPE: [] 2M, [] 3M, [] 5M, [] 10M, [] ~M 0~" ~~~~T Other: ~~~ Cc~'<;"'~\C"~t"f ~,",~<L '-, '" ~\"Qc...C!:.è)~~~\ Ongmal SIgned By by order o! . dl'2~ . 'ì. Cammy Oochsli T 3y10f Commissioner the commiSSion Date g 'Z ~ ~ Sub t In npllcate 20. Attachments Permit Nu r: 2Ó;L-/6 Conditions of Approval: Approved By Form 10-401 Rev. 12-01-85 ORIGINAL AS SURVEYED R 13 W R 12 W 30 29 Approximate high water mark \ PROPOSED DRILLING SITE LAT. 61° 00' 48.30" X : 241,507 195. ýYJ LONG. 1510 27 '.3.4.98" Y , 2,565.228 .:~ q, - "I eX) ~ eX) 00<11 ~ .f 0 - <1" 0 rC'. " 1048 ~7 "V. /.f C'... o/. ~ 0" ~+ ... BOTTOM OF WE L LAT 610 00' 24.6'" X= 240,228 LONG. 1510 27' 49.85" Y= 2,562,850 '- 31 32 T 10 N SEWARD MERIDIAN, ALASKA Scale ,": 2,000' ,,",,....~ -~¡ ~ ~ ~~/...,.. ....~ .." ~--~ . .... . .~. ~ t'd~ . ,~. "4~" .." 4::;..~ - ........... ~~.. . . ~NQ.~ ... '. } . At') .I"r~.. ,~ , ( t ~ .. ..,,~~:~..: ~~"4..:"'ik) ~~~ ...'::t~ ~'~'\~~' t\~~ -::,~ .:....-~~. . ~~~~-,. T II N Certificate of Surveyor I hereby certify that I am properly registered and I icensed to practice land surveying In the State of . Alaska and that th is plat represents a location st.;rvey mode by me or under my supervision) and that 011 dimensions and other details are correct ~~//~ /Y~5 DATE þ~,&~~/ SUR V EY6rc PLAT OF Surveyor's Note: The location of Nikolai Creek State NO.1 was accompli shed using BLM control point -CET 10 and Native Hub at Granite Point. NIKOLAI CREEK STATE NO.1 SURVEY FOR TEXACO INC . 131 5 TH. AVE. ANCHORAGE ,ALASKA, SURvEYED BY fM. LINDSEY 6 ASSOCIATES LAND SURVEYOR': a CIVIL ENG. 1415 w. NORTHE'1N LlGH7S BLVO ANCHOR AGE AL ASK A ) ) ~/A 1/ rr~~~cc> I ~ c. @ ~ .~1:J J- aY' O-:~~ PETROLEUM PRODUCTS Mr. Thomas R. Marshall, Jr., Executive Secretary, State of Alaska, Oil & Gas Conservation Cownittee Anchorage, Alaska Dear Sir: P. O. Box 664 Anchorage, Alaska October 14, 1965 This letter serves to supplement our Application for Permit to Drill (form P-l) dated September 16, 1965. Due to operational conditions existing near the well site, it is necessary to move the location of subject well from its ... original location 30 feet due north. The exact location of our Nicolai Creek State #1 well is 2,018' North, 195' East of S. W. Corner of Sec. 29, TllN, R12W, 3 S.M., AAA. Because the original location, on form P-l was approximate, the final surveyed location above and the original approximate location do not correlate. No other changes are anticipated. Very truly yours, ORIGINAL AS DRILLED CORRECTION c: d :::z;:;~ E. D. Turner, J- Ass't. Sup't. P-AD ~~~VATION 101 ~ ~ -... , . ORIGINAL KB 16.11 AGL ..~.. . ~ . '¡....' Nicolai Creek .,. .) Nicolai Creek Unit 18 WP02 Eastings (Well) Scale: 1 inch = 40ft -120 I ST Exil:Dir @ 12.000"/1000, as.oo" left TF : 2200.000 MD, 2150.04ft TVD Begin Dir @ 10.000"/1000 : 2220.00ft MD, 2169.03ft TVO c::;nDr"r"v-sUl'1 Alaska DAI"'L,I",q Â:~~~~:":: Cook Inlet ') 2200 - 2400 - 2600 - :::=- -a; š: ;; 2800 - - 0.. Q,) 0 -æ (.) t Q,) > 3000 - 3200 - 3400 - Begin 8-3/4" ST Exit:Dir @ 12.0ooo/100ft, 85.00° left TF : 2200.00ft MD, 2150.04ft TVD egin Oir @ 10.000"/10Oft : 2220.00ft MD, 2169.03ft TVD End Dir, Start Sait @ 0.000° : 2404.70ftMD,2350.55ftTVD &600.00 Vertical Origin: Horizontal Origin: Measurement Units: North Reference : Grid North Convergence: Dogleg severity : Vertical Section Azimuth: Vertical Section Description: Vertical Section Origin: Coordinate System: Measured Incl. Depth 2200.00 2220.00 2404.70 3654.15 DrillQuest~ -80 1 Begin 8-3/4" ~ Q) ~ C/) C) ~.5 o..c .q-t: 1\ 0 ..c:Z 0 .£ '"'" J8oo.00 18.111 18.470 0.000 0.000 JOOOOO #200.00 .¡J4oo00 z ñ 0 Æ - -360 End Dir, Start Sail @ 0.000° : 2404.7OOMD,2350.55ftTVD Total Depth; 3654.15ftMO,3600.0OOTVD - 0000 Niælai Creek 1 B T1 8 3600.00ft TVD æ: 381.27 S:98.32 W 23ÙO.~ i œ .:t "D ß - -400 å) (ij 0 (/) Proposal Data for Nicolai Creek 1 B WP02 WeU Well ft Grid North -1.275° Degrees per 100 feet (US) 194.110° Well 0.00 N,O.OO E NAD27 Alaska State Planes, Zone 4, US Foot Azim. Vertical Northings Eastings Vertical Dogleg Depth Section Rate 201.000 2150.04 346.58 S 89.61 W 357.97 193.433 2169.03 352.57 S 91.46 W 364.23 12.000 0.000 2350.55 381.27 S 98.32 W 393.74 to.OOO 0.000 3600.00 381.27 S 98.32 W 393.74 0.000 Current Well Properties Well: Horizontal Coordinates: Ref. Global Coordinates: Ref. Structure: Ref. Geographical Coordinates: RKB Elevation: Nicolai Creek Unit 1B WP02 2565258.00 N, 241507.00 E 30.00 N, 0.00 E 61° 00' 48.5974" N, 151027' 24.9975" W 22.00ft above Mean Sea Level 22.000 above Structure -1.2750 Grid North Convergence: North Reference: Units : Grid North Feet (US) (") ~ i g ãi C'\I ::E II ;g ..c: ... i}6OO.00 g .\icolai Creek 1 B Tl .- 360(WOjt TVD ":": 3600 -. ~¡,n27 S. 98.32 IV Q) ì LIner ro 3654.15ft MD á5 3600.000 1VD Total Depth: 3654.15ftMO,36OO.0OOTVD I I I I 300 500 700 900 Scale: 1 inch = 200ft Section Azimuth: 194.110° (Grid North) Vertical Section (Well) Drill Quest 2.00.09.006 Aurora Gas, LLC Sper. i-Sun Drilling Sel Jices Proposal Data.. Nicola; Creek Unit 1 B WPS .. Nicolai Creek 1 B WP02 Approved Plan ¡ MO ¡ Delta )¡..nclin. ¡ Azimuth ¡ TVD .'1..'009 . ¡ No$ings! È~¡ DogI~ ..i'.A.B~iId.j A Tum I. Tóotfaœ! VS{194°) I \ (ft) I MD (ft), (") .I rr .: (ft)TVO (ft)! (ft) ¡ (ft) . (o/100ft) l (1)/100ft) ¡ (o/100ft) i(O) ¡ (ft) ! [1fl;I~~~f~~1~~¡.fi~~EII:s~li~7*~t<4j[i.~i~:i?~i11 : 4' :.:36~:.15L~4QA5! ~,OOL~~~.~J~600.~--.:!?491-~1~ ~!~? Sf ~_.32 W ;--Q~Qj._-,__O.~i_~.~OP!_:. O.OOL_~.__~~3.1J 2 July, 2002. 18:21 -1- DrlllQuest Inlet Nico/ajCr.eek, ot Nicolai Creek 1 B WPS Nicolai Creek Untt 18 WPS - Nicolai Creek 1 B WP02 Revised: 2 July, 2002 '-' PROPOSAL REPORT 2 July, 2002 Surface Coordinates: 2565258.00 N, 241507.00 E (61000' 48.5974" Nt 151027' 24.9975" W) Sutface Coordinates relative to Project H Reference: 2434742.00 S, 258493.00 W (Grid) Sutface Coordinates relative to Structute: 30.00 N, 0.00 E (Grid) KeNy Bushing: 22.00ft above Mean Sea Level =:tJ-I~\I-SLJI'1 P.." u...Lf,t~L~-..- jŠ~~.Vl~;'U; À Halliburton com~.ny Proposal Ref: pro85 Sperry-Sun Drilling Services . Proposal Report for Nicolai Creek Unit 18 WPS Revised: 2 July, 2002 Cook Inlet Alaska Nicolai Creek Measured Sub-Sea Vertical Locat Coordinates Vertical Depth Incl. Azlm. Depth Depth Northlngs Eastlngs Section Comment (ft) (It) (ft) (ft) (ft) Nicolai Creek #1 Reca ~" 0.00 0.000 0.000 -22.00 0.00 256525å.QO N 241507.00 E 0.00 100.00 0.000 0.000 78.00 100.00 . . ,.. 565258.()O N 241507.00 E 0.000 0.00 200.00 0.000 0.000 178.00 200.00 258.00 N 241507.00 E 0.000 0.00 300.00 0.000 0.000 278.00 300.00 5258.00 N 241507.00 E 0.000 0.00 400.00 0.000 0.000 378.00 400.00 2565258.00 N 241507.00 E 0.000 0.00 SOD. 00 0.000 0.000 478.00 500.00 2565258.00 N 241507.00 E 0.000 0.00 600.00 0.267 125.000 578.00 600.00 2565257.97 N 241507.05 E 0.267 0.02 700.00 2.549 178.164 677.96 699.96 2565255.45 N 241507.44 E 2.399 2.37 800.00 3.899 182.466 777.81 799,.i1 2565250.07 N 241507.28 E 1.370 7.62 900.00 6.807 178.584 877.38 &99.38 . 2565240.93 N 241507.22 E 2.929 16.SO 1000.00 10.379 176.07ß 998;23 32.06 S 1.01 E 2565225.94 N 241508.01 E 3.590 30.84 1100.00 12.356 176.851 '1Ö96.24 51.86 S 2.18 E 2565206.14 N 241509.18 E 1.983 49.77 1200.00 13.084 176.343 ,.";1193.71" 73.89 S 3.58E 2565184.11 N 241510.58 E 0.737 70.79 1300.00 11.998 192.355 1291.29 95.92 S 3.09E 2565162.08 N 241510.09 E 3.629 92.27 1400.00 13.344 199.032 1388.96 116.50 S 2.92W 2565141.50 N 241504.08 E 1.988 113.69 1500.00 16.496 199.891 1463.57 1485.51 140.76 S 11.51 W 2565117.24 N 241495.49 E 3.159 139.32 1600.00 18.564 200.000 1558.88 1580.88 169.20 S 21.86 W 2565088.80 N 241485.14 E 2.069 169.43 ,~ 1700.00 18.750 200.968 1653.58 1675.58 199.31 S 33.08 W 256S058.69 N 241473.92 E 0.361 201.36 1800.00 18.411 201.000 1748.36 1770.36 229.06 S 44.50 W 2565028.94 N 241462.50 E 0.339 233.00 1900.00 18.318 201.000 1843.30 1865.30 258.38 S 55.76 W 2564999.62 N 241451.24 E 0.093 264.18 2000.00 18.443 201.000 1938.20 1960.20 287.82 S 67.06 W 2564970.18 N 241439.94 E 0.126 295.49 2100.00 18.362 201.000 2033.06 2055.06 317.37 S 78.40 W 2564940.63 N 241428.60 E 0.082 326.90 2200.00 18.111 201.000 2128.04 2150.04 346.58 S 89.61 W 2564911.42 N 241417.39 E 0.251 357.97 ST ExltDir @ 12.000"/1000, 85.00" Lt TF: 2200.000 MD, 2150.04ft TVD 2 July, 2002 - 18:22 Page2of4 DrlllQuest 2.00.09.006 Sperry-Sun Drilling Services Proposal Report for Nicolai Creek Unit 18 WPS Revised: 2 July, 2002 . Cook Inlet Alaska Nicolai Creek Measured Sub-Sea Vertical Local Coordinates Global Coordinates .!;;:~\;tÅPogleg Vertical Depth Inct. Azlm. Depth Depth Northlngs Eastings Northlngs eastin .:)!;;1f!.~ate Section Comment (ft) (ft) (ft) (It) (ft) (ft) t~t10Oft) Nicolai Creek 18 WP02 2220.00 18.470 193.433 2147.03 2169.03 352.57 S 91.46 W 2564905,43 N 12.000 364.23 Begin Dlr @ 10.00Qó/100ft: 2220.00ft MD. 2169.03ft TVD 2300.00 10.470 193.433 2224.43 2246.43 371.99 S 96.10 W ~.2564886:01 N 241410.90 E 10.000 384.20 2400.00 0.470 193.433 2323.85 2345.85 381.25 S 98.31 W 2664876.75 N 241408.69 E 10.000 393.72 2404.70 0.000 0.000 2328.55 2350.55 381.27 S . 98.32 W 2564876.73 N 241408.68 E 10.000 393.74 End Dir, Start Sail @ 0.000° : 2404. 70ftMD ,2350.55ftTVD 2500.00 0.000 0.000 2423.85 2445.85 2564876.73 N 241408.68 E 0.000 393.74 2600.00 0.000 0.000 2523.85 2545.85 98.32 W 2564876.73 N 241408.68 E 0.000 393.74 2700.00 0.000 0.000 2623.85 2645.85 98.32 W 2564876.73 N 241408.68 E 0.000 393.74 2800.00 0.000 0.000 2723.85 27 45,Jì~,^ 98.32 W 2564876.73 N 241408.68 E 0.000 393.74 2900.00 0.000 0.000 2823.85 284~:85, 98.32 W 2564876.73 N 241408.68 E 0.000 393.74 3000.00 0.000 0.000 2923.85 2945.85 98.32 W 2564876.73 N 241408.68 E 0.000 393.74 3100.00 0.000 0.000 3023.85 3045:&5 381.21 S 98.32 W 2564816.73 N 241408.68 E 0.000 393.74 3200.00 0.000 0.000 . . 3123.85> 3145.85 381.27 S 98.32 W 2564876.73 N 241408.68 E 0.000 393.74 3300.00 0.000 0.000 3223:.a5 3245.85 381.27 S 98.32 W 2564876.73 N 241408.68 E 0.000 393.74 3400.00 0.000 0.000 323]35'~W>3345.85 381.27 S 98.32 W 2564816.73 N 241408.68 E 0.000 393.74 3500.00 0.000 0.000 23.85 3445.85 381.27 S 98.32 W 2564876.73 N 241408.68 E 0.000 393.74 3600.00 0.000 0.000 3523.85 3545.85 381.27 S 98.32 W 2564876.73 N 241408.68 E 0.000 393.74 ,,-, 3654.15 0.000 0.000 3578.00 3600.00 381.27 S 98.32 W 2564876.73 N 241408.68 E 0.000 393.74 Total Depth: 3654.15ftMD.3600.00ftTVD 7" Liner Target - Nicolai Creek 1 B T1, Drillers Target All data is În Feet (US) unless otherwise stated. Directions and coordinates are relative to Grid North. Verticat depths are relative to Well. Northings and Eastings are relative to Well. Coordinate System is NAD27 Alaska State Planes. Zone 4, US Foot. Grid Convergence at Surface Is -1.275° . Coordinate System Is NAD27 Alaska State Planes. Zone 4, US Foot. Magnetic Convergence at Surface is -21.98r (02-Jut.02) The Dogleg Severity is in Degrees per 100 feet (US). Vertical Section is from Well and calculated along an Azimuth of 194.110° (Grid). Based upon Minimum Curvature type calculations, at a Measured Depth of 3654.15fl, 2 July, 2002 - 18:22 Page 3 0'4 OrH/Quest 2.00.09.006 Alaska Sperry-Sun Drilling Services Proposal Report for Nicolai Creek Unit 1B WPS Revised: 2 July, 2002 The Bottom Hole Displacement Is 393.74ft., in the Direction of 194.460<> (Grid). Comments ~ Measured Depth (ft) 2200.00 2200.00 2220.00 2404.70 3654.15 Casing details Station Coordinates TVD Northings Eastlngs (ft) (ft) (ft) 2150.04 2150.04 2169.03 2350.55 3600.00 From Measured Vertical Depth Depth (ft) (ft) 2200.00 21S0.04 346.58 S 346.58 S 352.57 8 381.27 S 381.27 S To. . Measured Vërtiçal oepth ... Depth (It) .. (ft) Targets associated with this weHpath Target Name Nlcotai Creek 1 B T1 2 July. 2002 M 18:22 Comment 89.61 W 89.61 W 91.46 W 98.32 W 98.32 W Begin 8-3/4" . . . . 8T Exit:Dir @12;OOO~/1~~ _85.00° Left TF : 2200.0Oft MO, 2150.04ft TVD Begin O' tOóOOÖ"l10on': 2220.00ft MD. 2169.03ft TVD En Sè!t@;ö.oooo : 2404.7OftMD,2350.55ftTVD 3654:lSftMO.3600.0OftTVD Casing DetaU .00 7" Liner Target Entry Coordinates TVO Northlngs Eastlngs (ft) (ft) (ft) Mean Sea LeveVGlobal Coordinates: Geographical Coordinates: 3600.00 3578.00 381.27 S 98.32 W 2564876.73 N 241408.68 E 61" 00' 44.8223" N 151° 27' 26.8196" W Page4of4 . Cook Intet Nicolai Creek Target Target Shape Type Point Drillers Target DrlllQuest 2.00.09.006 WELL DfT ,\ItS ANTI-COLLISION SETnNGS ~~~~~ ~~~~.OO ~~!WI: ~g5~00 MUJlÙnUffi t~e: 794.00 Refetenee: Plan: NCUillB wp62 " ". COM!' Mol" £JET AILS SLfRv1!V'I'R0(1{t,\M I)c¡1ù<Fm !À,¡>1h To S'''''J<iMon 2200.00 3bS'l.15 P"'mod: NCU#II\ w¡\l)2 VI NM)Ù Ni.S No"hMl[' e..III¡l latitude LOI1¡ti¡udo Sk>, AUt'Cta (j~. U.c E:.W C1ikul.t\i:ß\ Moúmd: M_C"""",,,, Eo.,..". S""lOn>: ¡SCW!!" Soa" MOlhod: Troy C.- North W:::~:d; ~"~.'df; NCU.I 0.00 0.00 2S6515R.f>O 141507.00 61'00'411.5'17'< 151'Z"U.mw T-¡!¡\ =30Ö -250 From Colour 0 2000 2250 2500 2150 3000 3250 3500 3750 4000 4250 4500 4750 ~200 -150 -100 ----50 -0 -50 -100 6 ~ -:t. ~ ; -150 ~200 &:0 -250 1200.(>1) 18.11 ZOI.OO 2220.00 IM7 19:\.43 2404.70 \1.00 1).0f' .1(>54.15 0.00 0.00 =3~ TraveUìng Cylìnder Azimuth (TFO+AZI) [deg) vs Centre to Centre Separation [ lOOMn] ToMD 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 MD ,\;<Ò ¡,,¡; WELLPATU Df.TAtlS Tool MWO P1a,,,,NCU#IB !'Brot\ W"f.pa,1\; Tìc on MQ; NClf<Il :UUO.OO Rig: R.~r. Oi\!um: NCU~b 12' RKI\ V~lton ^""" Origtt NI-S rt r...' T.£.GfNO -. = ~U~g:~~ ~~:'~~k - NCUII6 (NCUM), ~r Ro.k - "'CU#8 \NCL<ii1i). M"mor RJ.,k - PIa",NCU#IB -- NCU#IB y,jII'Z "La" v.. ...,.. PIM: NCU#IB ..p(¡Z (NCl!#\!I'1m: NCU" CI'COIOd B)': P\:ac11 tlotøn." CIr.>ck..'<I;-~_._~. R~w.:d:..._-_ø. 1\J'j>fO""'¡:_------ I , SECTION PE,MLS TV!) NI.s f'f.W {)toe; Hate vs.:c T..~ ZISO.~ .346.S8 .59061 0.00 0.00 356-18 2169-03 ..152.57 .91.46 \Vil 275.1X\ 362.44 2350$5 .J8\.Z1 ..9it~2 10.00 180.00 391.74 3600.00 .381.27 .9HZ 0.00 0.00 31'1.14 12,00!\ o,,>¡;i<1 f'f-W SW1mR. f'tom TVO f.tC .~ ()a¡",t ; - 0.."-- Do!c:_---- D<t!o:_--- " ) Sperry-Sun Anticollision Report .) . Company: Aurora Gas, LLC Fiêkl: Cook lmet . Retereoœ Sik': Nicolai Creel< Unit , Referenet' WeU: NCUil1 Rd'~J.'eDeeWeJlpattt: Plan: NCU#1B . ~ GLOBAL SCAN APPLIED: AD weUpaths 'l'tithin 204""- 100/1000 of reference Interpolation Method: MD Intenal: 25.00 ft . Depth Range: 2200.00 to 5952,00 ft l\fa:dmum Radius: 794.00 ft Date: 07103/2002 Tbne: 11:11:17 Page: Co-ontinøte(NE) Refel'el1ft: Vertical fTVD) Referwce: Well: NCU#1.. Grid North NCU#1: 2Z RKB 22.0 Referenee: Error Model: Smn Method: Error 8urfa£e: Db: Oracle Principal Plan & PLANNED PROGRAM ISCWSA Ellipse Trav Cylinder North Ellipse I Survey Prognm. for Definitive Wellpath Date: 07/0312002 Validated: No VeJ'8ion: 0 Planned From To Survey Tookode Tool Name ft ft 576.00 2200.00 NCU#1 (0) CB-MAG-SS Camera based mag single shot 2200.00 3654.15 Planned: NCU#1 B wp02 V1 MWD MWD - Standard Summary . i <-~---:------- OftSet WellpQth ---------------> Reference OtDJet L'tJ'-Ctr No-Go Allowable ~ l Site WeB Wellp8th MD MD ßi.stançe Area. De...iation. Wa-rmng ft ft ft ft ft : - Nioolai Creek Unit NCV#1 NCV#1 V1 5952.00 5952.00 0.00 236.75 -143.51 FAIL: Major Risk J ' ~ Nicolai Creek Unit NCU#2 NCU#2 V2 2204.79 2350.00 740.59 106.16 661.43 Pass: Major Risk Nicolai Creek Unit NCU#6 NCU#6 V4 2217.18 2250.00 278.08 78.11 200.99 Pass: Major Risk Nicolai Creek Unit NCU#8 NCU#8 V1 2400.61 2486.00 469.83 884.31 -364.90 FAIL: Major Risk Site: NicQlai Creek Unit WeB: NCU#1 Rule Assigned: Major Risk WeJlpath: NCU#1 Vi Inter-Site Error: 0.00 IT . I ,. Reference onset Semi-Major ADs Ctr-Ur No-Go AUowable MD TV1> MD TVI) Ref Offset TFOtAZI TFO-R.'3 Cusing Dlstam:e Area De\iatlQn Wa:rnbtg ft It ft ft ft ft dag deg in ft ft ft f 2200.00 2150.04 2200.00 2150.04 9.54 10.10 21.00 0.00 7.000 0.00 72.40 -55.56 FAIL 2225.00 2173.80 2225.00 21ì3.80 9.65 10.29 201.00 0.00 7.000 0.00 73.52 -56.27 FAIL 2250.00 2197.58 2250.00 2197.58 9.74 10.49 201.00 0.00 7.000 0.00 74.51 -56.94 FAIL 2275.00 2221.35 2275.00 2221.35 9.77 10.70 201.00 0.00 7.000 0.00 75.38 -57-53 FAil 2300.00 2245.13 2300.00 2245.13 9.80 10.91 201.00 0.00 7.000 0.00 76.25 -58.11 FAIL 2325.00 2268.91 2325.00 2268.91 9.84 11.12 201.00 0.00 7.000 0.00 77.11 -58.69 FAIL 2350.00 2292.68 2350.00 2292.68 9.87 11.32 201.00 0.00 7.000 0.00 77.96 -59.26 FAIL 2375.00 2316.46 2375.00 2316.46 9.90 11 .52 201.00 0.00 7.000 0.00 78.79 -59.83 FAIL 2400.00 2340,24 2400.00 2340.24 9.93 11.72 201.00 0.00 7.000 0.00 79.62 -60.39 FAIL 2425.00 2364.01 2425.00 2364.01 9.96 11.91 201.00 0.00 7.000 0.00 80.44 -60.95 FAil 2450.00 2387.79 2450.00 2387.79 9.99 12.11 201.00 0.00 7.000 0.00 81.28 -61.51 FAIL 2475.00 2411.57 2475.00 2411.57 10.03 12.32 201.00 0.00 7.000 0.00 82.18 -62.11 FAIL 2500.00 2435.37 2500.00 2435.37 10.08 12.52 201.00 0.00 7.000 0.00 83.07 -62.70 FAIL 2525.00 2459.17 2525.00 2459.17 10.12 12.73 201.00 0.00 7.000 0.00 83.94 -63.28 FAIL 2550.00 2482.99 2550.00 2482.99 10.16 12.93 201.00 0.00 7.000 0.00 84.81 -63.86 FAIL 2575.00 2506.81 2575.00 2506.81 10.20 13.12 201.00 0.00 7.000 0.00 85.68 -64.44 FAIL 2600.00 :2J::.3).65 2600.00 2530.65 10.24 13.32 201.00 0.00 7.000 0.00 66.54 -65.01 FAIL 2625.00 2554.50 2625.00 2554.50 10.29 13.51 201.00 0.00 7.000 0.00 87.42 -65.60 FAIL 2650.00 2578.40 2650.00 2578.40 10.34 13.71 201.00 0.00 7.000 0.00 88.31 -66.20 FAIL 2675.00 2602.35 2675.00 2602.35 10.39 13.91 201.00 0.00 7.000 0.00 89.19 -66.79 FAIL 2700.00 2626.35 2700.00 2626.35 10.44 14.10 201.00 0.00 7.000 0.00 90.07 -67.38 FAIL 2725.00 2650.38 2725.00 2650.38 10.49 14.29 201.00 0.00 7.000 0.00 00.96 -!fl.97 FAIL 2750.00 2674.40 2750.00 2674.40 10.55 14.48 201.00 0.00 7.000 0.00 91.84 -68.56 FAIL 2775.00 2698.41 2775.00 2698.41 10.60 14.67 201.00 0.00 7.000 0.00 92.71 -69.14 FAIL 2800.00 2722.41 2800.00 2722.41 10.65 14.86 200.95 0.00 7.000 0.00 93.59 -69.73 FAIL 2825.00 2746.44 2825.00 2746.44 10.71 15.05 200.68 0.00 7.000 0.00 94.50 -70.31 FAIL 2850.00 2770.50 2850.00 2770.50 10.77 15.24 200.41 0.00 7.000 0.00 95.40 -70.89 FAIL 2875.00 2794.59 2875.00 2794.59 10.83 15.43 200.13 0.00 7.000 0.00 96.30 -71.47 FAIL 2900.00 2818.70 2900.00 2818.70 10.89 15.61 200.15 0.00 7.000 0.00 97.19 -72.06 FAIL 2925.00 2842.81 2925.00 2842.81 10.95 15.80 200.42 0.00 7.000 0.00 98.07 -72.67 FAIL 2950.00 2866.92 2950.00 2866.92 11.01 15.99 200.69 0.00 7.000 0.00 98.95 -73.27 FAIL 2975.00 2891.01 2975.00 28-91.01 11.07 16.17 200.96 0.00 7.000 0.00 99.82 -73.87 FAIL ) Sperry-SUD ) Anticollision Report Company: Aurora Gas, LLC Date: 07lO3l2OO2 Tinle: 11:11:17 Page: 2 Fiekl~ Cook Inlet . Refeteøee Site: Nicolai Creek Unit Co-onUnate(NE) Reference: Well: NCV#l.Grid North . RefennœWdI: NCU'1 Vertical (TVD) Reference: NCU#1: 2Z RKB22.0 Reference WèIlpath: P1an: NCU#1 B Db: Oracle , Site: Nicolai Creek Unit WeD: NCU#1 Rule AssIgned: Major Risk WeHpatb.: NCU#1 V1 Inter-Site Error: 0,00 ft Reference Offset Semi-Major Ads Ctr..o.. No-Go Allowable MD TV» MD TV» Ref OtTsèt TFO+AZI TFO.HS Casing Dbtance Area Devtation Warning ft It It It It It dég deg in ft ft ft 3000,00 2915.08 3000.00 2915.08 11.14 16.37 201.25 0.00 7.000 0.00 100.74 -74.49 FAIL 3025.00 2939.09 3025.00 2939.09 11.21 16.56 201.52 0.00 7.000 0.00 101.66 -75.11 FAil 3050.00 2963.02 3050.00 2963.02 11.29 16.76 201.78 0.00 7.000 0.00 102.59 -75.72 FAIL 3075.00 2986.89 3075.00 2986.89 11.36 16.95 202.04 0.00 7.000 0.00 103.51 -76.33 FAIL , 3100.00 3010.69 ' 3100.00 3010.69 11.45 17.16 202.33 0.00 1.000 0.00 104.52 -76.95 FAIL 3125.00 3034.42 3125.00 3034.42 11.53 17.37 202.60 0.00 7.000 0.00 105.54 -77.56 FAIL 3150.00 3058.07 3150.00 3058.07 11.62 17.58 202.66 0.00 7.000 0.00 100.56 -78.16 FAIL 3175.00 3061.64 3175.00 3081.64 11.72 17.79 203.12 0.00 7.000 0.00 107.61 .78.78 FAIL 3200.00 3105.17 3200.00 3105.17 11.82 18.01 203.39 0.00 7.000 0.00 108.71 -79.40 FAIL 3"5.00 3128.66 3225.00 3128.66 11.93 18.23 203.66 0.00 7.000 0.00 109.80 -80.03 FAIL 3250.00 3152.11 3250.00 3152.11 12.03 18.44 203.92 0.00 7.000 0.00 110.88 -80.65 FAIL 3275.00 3175.53 3275.00 3175.53 12.15 18.66 204.00 0.00 7.000 0.00 111 .99 -81.27 FAIL 3300.00 3198.95 3300.00 3198.95 12.27 18.89 204.00 0.00 7.000 0.00 113.12 ..a 1.90 FAIL 3325.00 3222.36 3325.00 3222.36 12.38 19.11 204.00 0.00 7.000 0.00 114.24 -82.52 FAIL 3350.00 3245.78 3350.00 3245.78 12.51 19.33 204.00 0.00 7.000 0.00 115.37 -83.15 FAIL 3375.00 3269.20 3375.00 3269.20 1263 19.55 204.37 0.00 7.000 0.00 116.53 -83.80 FAIL 3400.00 3292.61 3400.00 3292.61 12.76 19.77 204.64 0.00 7.000 0.00 117.68 -84.45 FAIL 3425.00 3316,03 3425.00 3316.03 12,89 19.99 204,90 0.00 7.000 0,00 118,63 -85.09 FAIL 3450.00 3339.45 3450.00 3339.45 13.02 20.21 205.00 0.00 7.000 0.00 119.99 -85.73 FAIL 3475.00 3362,89 3475.00 3362.89 13.15 20.43 205.00 0,00 7.000 OJ)O 121,15 -86.36 FAIL 3500.00 3386.35 3500.00 3386.35 13.29 20.65 205.00 0.00 7.000 0.00 122.30 -86.99 FAIL 3525.00 3409.84 3525.00 3409.84 13.42 20.87 25.00 0.00 7.000 0.00 123.29 -87.61 FAIL 3550.00 3433.35 3550.00 3433.35 13.55 21.08 205.53 0.00 7.000 0.00 124.63 -88.30 FAIL 3575.00 3456.90 3575.00 3456.90 13.69 21.29 206.07 0.00 7.000 0.00 125.80 -88.98 FAIL 3600.00 34a0.50 3600.00 3480.50 13.82 21.50 206.63 0.00 7.000 0.00 126.96 -89.67 FAIL 3625.00 3504.13 3625.00 3504.13 13.96 21.71 207.00 0.00 7.000 0.00 128.12 -90.34 FAIL 3650.00 3527.79 3650.00 3527.79 14.10 21.92 207.00 0.00 7.000 0.00 129.26 -90.97 FAIL 3675.00 3551.48 3675.00 3551.48 14.24 22.13 207.00 0.00 7.000 0.00 130.40 -91.60 FAIL 3700.00 3575.20 3700.00 3575.20 14.37 22.34 207.00 0.00 7.000 0,00 131.53 -92.23 FAIL 3725.00 3598.94 3725.00 3598.94 14.51 22.54 207.25 0.00 7.000 0.00 132.69 -92.89 FAIL 3750.00 3622.69 3750.00 3622.69 14.66 22.75 207.61 0.00 7.000 0.00 133.85 -93.56 FAIL 3775.00 3646.45 3775.00 3646.45 14.80 22.95 207.98 0.00 7.000 0.00 135.00 -94.24 FAIL 3800.00 3670.21 3800.00 3670.21 14.94 23.15 208.35 0.00 7.000 0.00 136.14 -94.92 FAIL 3825.00 3693.98 3825.00 3693.98 15.08 23.35 208.72 0.00 7.000 0.00 137.28 -95.59 FAIL 3850.00 3717.76 3850.00 3717.76 15.22 23.56 208.32 0.00 7.000 0.00 138.41 -96.17 FAIL 3875.00 3741.69 3875.00 3741.69 15.38 23.71 205.14 0.00 7.000 0.00 139.39 -96.44 FAIL 3900.00 3765.75 3900.00 3765.75 15.51 23.97 200.77 0.00 7.000 0.00 140.73 ..96.82 FAIL 3925.00 3789.86 3925.00 3789.86 15.64 24.15 196.12 0.00 7.000 0.00 141.65 -97.52 FAIL 3950.00 3814.01 3950.00 3814.01 15.76 24.33 193.15 0.00 7.000 0.00 142.70 -98.38 FAIL 3975.00 3838.19 3975.00 3838.19 15.68 24.50 191.58 0.00 7.000 0.00 143.79 -99.17 FAIL 4000.00 3862.40 4000.00 3862.40 16.00 24.66 189.96 0.00 7.000 0.00 144.83 -100.00 FAIL 4025.00 3886.64 4025.00 3886.64 16.12 24.85 188.27 0.00 7.000 0.00 145.82 -100.89 FAIL 4050.00 3910.90 4050.00 3910.90 16.24 25.02 187.77 0.00 7.000 0.00 146.81 -101.59 FAIL 4075.00 3935.16 4075.00 3935.16 16.36 25.20 187.49 0.00 7.000 0.00 147.81 -102.24 FAIL 4100.00 3959.41 4100.00 3959.41 16.48 25.37 187.22 0.00 7.000 0.00 148.81 -102.90 FAIL 4125.00 3983.67 4125.00 3983.67 16.60 25.54 187.00 0.00 7.000 0.00 149.81 -103.55 FAIL 4150.00 4007.92 4150.00 4007.92 16.73 25.72 188.01 0.00 7.000 0.00 150.90 -103.96 FAIL 4175.00 4032.17 4175.00 4032.17 16.86 25.90 188.85 0.00 7.000 0.00 151.96 -104.42 FAIL 4200.00 4056.41 4200.00 4056.41 16.99 26.08 189.67 0.00 7.000 0.00 152.99 -104.89 FAIL 4225.00 4080.63 4225.00 4080.63 17.12 26.26 190.17 0.00 7.000 0.00 154.05 -105.43 FAIL t 4250.00 4104.82 4250.00 4104.82 17.26 26.45 190.45 0.00 7.000 0.00 155.13 -106.02 FAIL ) Sperry-SUD ') Anticollision Report I 0710312002. . Company: Aurora Gas, L1.C Da~: Time: 11 :11 :17 Page: 3 Field: Cook 1nlet . Reference Site: NîcoIai Creel< Unit Co-onlinate{NE) Reference: Wen: NCU#1, Grid North . Refenmce Well: NCU#1 Vertical (TVD) Refere.nce: NCVI1: 22' RKB 22.0 I Referenee Wellpath; Plan: NCU#'8 Db: Oracle Site: Nicolai Creek Unit WeB: NCU#1 Rule Assigned: Major Risk Wettpath.: NCU#1 V1 Inter-Site Error: 0.00 ft - . Referenctt Offset Semi-Major Am Ctr-a.. No-Go Allowable fdD TVD MD TV» 1ùf OOset TFO+AZl TFO-HS Casing Distance Area Deviation WlUUing ft ft ft ft ft It deg deg in ft ft ft 4275.00 4128.98 4275.00 4128.98 17.40 26.63 190.71 0.00 7.000 0.00 156.19 -106.61 FAIL 4300.00 4153.09 4300.00 4153.09 17.54 26.81 190.96 0.00 7.000 0.00 157.25 -107.20 FAIL 4325.00 4177.18 4325.00 4177.18 17.69 27.01 191.23 0.00 7.000 0.00 158.37 -107.80 FAIL 4350.00 4201.25 4350.00 4201.25 17.84 27.20 191.50 0.00 7.000 0.00 159.48 -108.39 FAIL 4375.00 4225.30 4375.00 4225.30 17.99 27.39 191.77 0.00 7.000 0.00 160.59 -108.99 FAIL 4400.00 4249.34 4400.00 4249.34 18.14 27.58 192.05 0.00 7.000 0.00 161.70 -109.58 FAIL 4425.00 4273.32 4425.00 4273.32 18.31 27.78 192.48 0.00 7.000 0.00 162.85 -110.17 FAIL 4450.00 4297.23 4450.00 4297.23 18.47 27.97 192.88 0.00 7.000 0.00 163.98 -110.76 FAIL 4475.00 4321.08 4475.00 4321.08 18.65 28.18 193.35 0.00 7.000 0.00 165.17 -111.35 FAIL 4500.00 4344.93 4500.00 4344.93 18.8-3 28.39 193.87 0.00 7.000 0.00 166.47 -111.96 FAIL 4525.00 4368.78 4525.00 4368.78 19.01 28.59 194.39 0,00 7.000 0.00 167.77 -112.57 FAIL 4550.00 4392.64 4550.00 4392.64 19.19 28,80 194.91 0.00 7.000 0,00 169.07 -113.18 FAIL 4575.00 4416.50 4575.00 4416.50 19.37 29,00 195.44 0.00 7.000 0,00 170,35 -113.79 FAIL 4600.00 4440.37 4600.00 4440.37 19.55 29.20 195.96 0.00 7.000 0.00 171.62 -114.41 FAIL 4625.00 4464.24 4625.00 4464.24 19.73 29.40 196.49 0.00 7.000 0.00 172.88 -115.03 FA!L 4650.00 4488.11 4650.00 4488.11 19.91 29.60 197.00 0.00 7.000 0.00 174.14 -115.65 FAIL 4675.00 4511.98 4675.00 4511.98 20.10 29.81 197.18 0.00 7.000 0,00 175.42 -116.31 FAIL 4700.00 4535.84 4700.00 4535.84 20.30 30.01 197.34 0.00 7.000 0.00 176,70 -116.96 FAIL 4725.00 4559.69 4725.00 4559.69 20.49 30.22 197.51 0.00 7.000 0.00 177.97 -117.61 FAIL 4750.00 4563.53 4750.00 4563.53 20.68 30.42 197.67 0.00 7.000 0,00 179,24 -118.26 FAIL 4775.00 4607.35 4775.00 4607.35 20.87 30.62 197.83 0.00 7.000 0.00 180.51 -118.91 FAIL 4800.00 4631.17 4800.00 4631.17 21.06 30.82 197.99 0,00 7.000 0.00 181.77 -119.55 FAIL 4825.00 4654.99 4825.00 4654.99 21.26 31,03 198.42 0.00 7,000 0,00 183,06 -120.22 FAIL 4850.00 4678.82 4850.00 4678.82 21.45 31.23 198.85 0.00 7.000 0.00 184.34 -120.88 FAil 4875.00 4702.67 4875.00 4702.67 21.65 31.43 199.30 0,00 7.000 0.00 185.61 -121.55 FAIL 4900.00 4726.53 4900.00 4726.53 21.85 31.63 199.75 0.00 7.000 0,00 186.88 -122.21 FAIL 4925.00 4750.40 4925.00 4750.40 22.04 31.83 200.20 0.00 7.000 0.00 188.13 -122.88 FAIL 4950.00 4774.29 4950.00 4774.29 22.24 32.03 200.66 0.00 7.000 0.00 189.38 -123.55 FAIL 4975.00 4798.20 4975.00 4798.20 22.44 32.23 201.00 0,00 7.000 0.00 190,63 -124.22 FAIL 5000.00 4822,11 5000.00 4822.11 22.63 32.43 200.60 0.00 7.000 0.00 191,92 -124.85 FAIL 5025.00 4846.01 5025.00 4846.01 22.83 32.63 200.30 0.00 7.000 0,00 193.08 -125.34 FAIL 5050.00 4869.92 5050.00 4869.92 23.02 32.83 200.00 0.00 7.000 0.00 194.11 -125.73 FAil 5075.00 4893.83 5075.00 4893.83 23.22 33.03 200.32 0.00 7.000 0.00 195.13 -126.14 FAIL 5100.00 4917.75 5100.00 4917.75 23.42 33.23 200.63 0.00 7.000 0.00 196.14 -126.55 FAIL 5125.00 4941.67 5125.00 4941.67 23.62 33.42 200.94 0,00 7.000 0.00 197.14 -126.97 FAIL 5150.00 4965.59 5150.00 4965.59 23.82 33.62 201.26 0.00 7.000 0.00 198.14 -127.38 FAIL 5175.00 4989.52 5175.00 4989.52 24.02 33.82 201.57 0.00 7.000 0.00 199.13 -127.80 FAIL 5200.00 5013,46 5200.00 5013.46 24.22 34.01 201.89 0.00 7.000 0.00 200.12 -128.21 FAIL 5225.00 5037.39 5225.00 5037.39 24.44 34.21 202.39 0.00 7.000 0.00 201,15 -128.66 FAIL 5250.00 5061 .26 5250.00 5061.26 24.66 34.42 202.98 0.00 7.000 0.00 202.21 -129.13 FAIL 5275.00 5085.09 5275.00 5085.09 24.89 34.63 203.55 0.00 7.000 0.00 203.26 -129.60 FAIL 5300.00 5108.85 5300.00 5108.85 25.11 34.83 204.09 0.00 7.000 0.00 204.30 -130.06 FAIL 5325.00 5132.56 5325.00 5132.56 25.34 35.04 204.60 0.00 7.000 0.00 205.42 -130.52 FAIL 5350.00 5156.21 5350.00 5156.21 25.56 35.24 205.09 0,00 7.000 0.00 206.59 -130.98 FAIL 5375.00 5179.79 5375.00 5179.79 25.79 35.44 205.57 0.00 7.000 0.00 207.74 -131.44 FAIL 5400.00 5203.31 5400.00 5203.31 26.01 35.64 206.00 0.00 7.000 0.00 208.88 -131.89 FAIL 5425.00 5226.79 5425.00 5226.79 26.27 35.86 206.18 0.00 7.000 0.00 210,14 -132.33 FAIL 5450.00 5250.24 5450.00 5250.24 26.53 36,09 206.35 0,00 7.000 0,00 211.39 -132.77 FAIL 5475.00 5273.67 5475.00 5273.67 26.79 36.31 206.52 0.00 7.000 0.00 212.64 -133.21 FAIL 5500.00 5297.08 5500.00 5297.08 27.06 36.53 206.68 0.00 7.000 0.00 213.89 -133.65 FAIL 5525.00 5320.45 5525.00 5320.45 27.32 36.74 206.85 0.00 7.000 0.00 215.13 -134.08 FAIL ) Sperry-SUD ) Anticollision Report I Aurora Gas, LLC 07103/2002 ¡ Company: Date: Time: 11:11:17 Page: . 4 Fidd: Cook Inlet . RekftJIDe Sitr: Nicolai Creek Unit CO-Q.nIinate(NE) Rderetlff. Well: NC.U#1. Grid North . Reference WeD: NCU#1 Vertical (rVD) RefertJlce: NCl}#1: 2Z RKB 22.0 Reference WeIlpath: Plan: NCU#1 B Db: Oracle ~ SIte: Nicolai Creek Unit WeU: NCU#1 Rule Assigned.: Major Risk Wellpatlu NCU#1 V1 Inter-Site Error: 0,00 ft , t Rdemnee OtTset Semi-l\~ajOl' ADs a.....etr No..Go Allowable MD TVD MD TV» Ref OfI'set TFO+AZI TFO-HS .CasJng Distance.Uea De\iation Warning , I ft ft ft ft It ft: deg deg tn ft ft ft: \ ' 5550.00 5343.81 5550.00 5343.81 27.58 36.96 207.00 0.00 1.000 0.00 216.37 -134.51 FAIL j 5575.00 5367.12 5575.00 5367.12 27.85 37.18 207.87 0.00 7.000 0.00 217.70 -135.08 FAIL 5600.00 5390.40 5600.00 5390.40 28.12 37.39 208.70 0.00 7.000 0.00 219.00 -135.65 FAIL 5625.00 5413.63 5625.00 5413.63 28.40 37.61 209.50 0.00 7.000 0.00 220.29 -136.22 FAIL 5650.00 5436.82 5650.00 5436.82 28.67 37.82 210.22 0.00 7.000 0.00 221.55 -136.81 FAIL 5675.00 5460.02 5675.00 5460.02 28.95 38.04 210.84 0.00 7.000 0.00 222.83 -137.41 FAIL 5700.00 5483.24 5700.00 5483.24 29.23 38.26 211.47 0.00 7.000 0.00 224.11 -138.02 FAIL 5725.00 5506.48 5725.00 5506.48 29.50 38.47 212.10 0.00 7.000 0.00 225.36 -138.64 FAIL 5750.00 5529.74 5750.00 5529.74 29.78 38.69 212.74 0.00 7.000 0.00 226.60 -139.27 FAIL 5775.00 5-553.02 5775.00 5553.02 30.06 36.90 213.39 0.00 7.000 0.00 227.83 -139.91 FAil 5800.00 5576.33 5800.00 5576.33 30.34 39.11 214.04 0.00 7.000 0.00 229.04 -140.56 FAIL 5825.00 5599.65 5825.00 5599.65 30.61 39.32 214.71 0.00 7.000 Q.oo 230.23 -141.22 FAIL 5850.00 5622.99 5850.00 5622.99 30.89 39.53 215.00 0.00 7.000 0.00 231.49 -141.76 FAIL 5875.00 5646.37 5815.00 5646.37 31.11 39.76 215.00 0.00 7.000 0.00 232.79 -142.19 FAIL 5900.00 56mG8 5900.00 5669.18 31.45 39.98 215.00 0.00 7.000 0.00 234.01 -142.62 FAil 5925.00 5693.22 5925.00 5693.22 31.72 40.19 215.00 0.00 7.000 0.00 235.36 -143.05 FAIL 5950,00 5716,69 5950,00 5716,69 32,00 40.41 215,00 0,00 7.000 0.00 236,64 -143.47 FAIL 5952.00 5718.57 5952.00 5718.57 32.02 40.43 215.00 0.00 7.000 0.00 236.15 -143.51 FAIL Sit...: Nicolai Creek Unit WeD: NCU#2 Rule Assigned: Major Risk WeUpath: NCUt12 V2 Inter-Site Error: 0.00 ft Rtfe.renœ Offsri Smn-MaJor Axis Ctr-Ctr No-Go Allowable MD TVD l\ID TVD Ref OtTset TFO+AZl TFO-HS Casing Distan£e Area Deviation Warning ft ft. ft ft ft ft deg deg in ft ft ft 2204.79 2154.59 2350.00 2080.67 9.56 24.24 129.74 288.74 7.000 740.59 106.16 661 .43 Pass 2225.25 2174.04 2375.00 2098.85 9.65 24.69 129.76 288.76 7.000 754.64 107.72 674.57 Pass 2245.69 2193.48 2400.00 2116.99 9.74 25.14 129.78 288.78 7.000 768.74 109.24 681.78 Pass 2266.29 2213.07 2425.00 2135.10 9.76 25.51 129.80 288.80 7.000 782.90 110.60 701.20 Pass Site: Nicolai Creek Unit WeD: NCU#6 Rule AssIgned: Major Risk Wellpath: NCU#6 V4 Inter-Site Error: 0.00 ft Referenœ Ot'f.!ret Semi-Major AØ C'tr-C.'1r No-Go Allowable MD TVD MD TVD Ref O~ TFO+AZI TFO-HS Casing Distance Area DevtPiion Wamlng ft ft ft ft. ft ft deg deg in ft ft ft 2217.18 2166.37 2250.00 2175.26 9.62 12.33 105.08 264.08 7.000 278.08 78.11 200.99 Pass 2241.54 2189.53 2275.00 2198.21 9.73 12.59 105.32 264.32 7.000 283.71 79.29 205.52 Pass 2265.86 2212.66 2300.00 2221.13 9.76 12.85 105.56 264.56 7.000 289.40 80.28 21 0.29 Pass 2290.16 2235.77 2325.00 2244.03 9.79 13.11 1OS.81 264.81 7.000 295.13 81.24 215.14 Pass 2314.45 2258.87 2350.00 2266.90 9.82 13.36 106.05 265.05 7.000 300.92 82.19 220.06 Pass 2338.72 2281.96 2375.00 2289.74 9.85 13.60 106.29 265.29 7.000 306.75 83.12 225.04 Pass 2362.99 2305.03 2400.00 2312.58 9.88 13.84 106.53 265.53 7.000 312.63 84.OS 230.08 Pass 2387.24 2328.10 2425.00 2335.35 9.91 14.08 106.77 265.77 7.000 318.57 84.96 235.19 Pass 2411.47 2351.15 2450.00 2358.11 9.94 14.31 107.02 266.02 7.000 324.55 85.86 240.35 Pass 2435.69 2374.18 2475.00 2380.85 9.97 14.58 107.26 266.26 7.000 330.58 86.86 245.48 Pass 2459.93 2397.23 2500.00 2403.57 10.01 14.85 107.50 266.50 7.000 336.64 87.87 250.63 Pass 2484.16 2420.29 2525.00 2426.27 10.05 15.11 107.74 266.74 7.000 342.72 88.88 255.81 Pass 2508.38 2443.34 2550.00 2448.95 10.09 15.37 107.99 266.99 7.000 348.83 89.88 261.03 Pass 2532.58 2466.40 2575.00 2471.61 10.13 15.63 108.24 267.24 7.000 354.97 90.86 266.30 Pass 2556.78 2489.45 2600.00 2494.24 10.17 15.88 108.49 267.49 7.000 361.15 91.84 271.61 Pass Î 2580.96 2512.49 2625.00 2516.86 10.21 16.14 108.75 267.75 7.000 367.35 92.83 276.93 Pass Sperry-SUD ) Anticollision Report Company: Aurora Gæ, LLC Date: 0710312002 Time: 11:11:17 Page: 5 I . Field: Cook Inlet I Reference Sik: Nicolai Creek Unit CO-iJ.rdirQtte(NE) Re.feJ't"nce: Well: NCU#1. Gríd North , Reference WeD: NCU#1 Vertlc:aJ (TVD) RefereJlCe: NCU#1: 2Z RKB 22.0 j .Reference Wellpatlr. Plan: NCU#1 B Db: Oracle SIte: Nicolai Creek Unit Well: NCU#6 Rule Assigned: Major Risk Wellpath.: NCU#6 V4 Inter-Site Error: 0.00 ft ~ i Reference Offset Semi-Major A:ñs Ctr-Ctr No-Go Allowable ! MD TVD MD TVD Ref OtTset TFO+AZ1 TFO-HS Casing. Distance Area Devlati:on Waming ¡ ft ft 11 ft It ft deg deg in ft ft It 2605.13 2535.54 2650.00 2539.45 10.25 16.42 109.00 268.00 7.000 373.60 93.88 282.27 Pass 2629.33 2558.63 2675.00 2562.03 10.30 16.70 109.27 268.27 7.000 379.90 94.93 287.65 Pass 2653.51 2581.76 2700.00 2584.58 10.35 16.97 109.55 268.55 7.000 386.25 95.99 293.10 Pass 2677.65 2604.89 2725.00 2607.12 10.40 17.25 109.85 268.85 7.000 392.65 97.03 298.62 Pass 2701.75 2628.03 2750.00 2629.63 10.45 17.51 110.17 269.17 7.000 399.10 98.06 304.20 Pass 2725.78 2651.13 2775.00 2652.13 10.50 17.77 110.49 269.49 7.000 405.61 99.07 309.86 Pass 2749.79 2674.20 2800.00 2674.61 10.55 18.03 110.80 269.80 7.000 412.18 100.09 315.57 Pass ¡ 2773.81 2697.27 2825.00 2697.08 10.60 18.31 111.09 270.09 7.000 418.79 101.15 321.28 Pass 2797.89 2720.39 2850.00 2719.57 10.65 18.58 111.37 270.37 7.000 425.43 102.20 327.03 Pass 2822.42 2743.96 2875.00 2742.07 10.71 18.86 111.62 270.91 7.000 432.08 103.30 332.77 Pass 2846.94 2767.55 2900.00 2764.58 10.76 19.14 111.88 271.44 7.000 438.73 104.38 338.53 Pass 2671.46 2791.17 2925.00 2767.10 10.62 19.42 112.14 271.97 7.000 445.36 105.46 344.30 Pass 2895.56 2814.42 2950.00 2809.64 10.68 19.68 112.40 272.40 7.000 452.04 100.52 350.09 Pass 2919.05 2837.07 2975.00 2832.18 10.94 19.93 112.67 272.31 7.000 458.74 107.51 355.96 Pass 2942.52 28-59.70 3000.00 2854.73 10.99 20.18 112.92 272.30 7.000 465.50 108.51 361.88 Pass 2965.98 2882.32 3025.00 2877.30 11.05 20.44 113.15 272.29 7.000 472.31 109.52 367.83 Pass 2989.47 2904.95 3050.00 2899.66 11.11 20.71 113.37 272.25 7.000 479.12 110.55 373.76 Pass 3013.01 2927,sa 3075.00 2922,43 11.18 20.96 113.57 272.18 7.000 485.94 111 .57 379.66 Pass 3036.58 2950.18 3100.00 2944.99 11.25 21.21 113.74 272.10 7.000 492.75 112.58 385.57 Pass 3060.16 2972.73 3125.00 2967.56 11.31 21.45 113.89 272.00 7.000 499,55 113.59 391 .46 Pass 3083.68 2995.16 3150.00 2990.12 11.39 21.69 114.01 271.87 7.000 506.34 114.59 397.33 Pass 3107.13 3017.47 3175.00 3012.69 11.47 21.92 114.11 271.70 7.000 513.13 115.00 403.17 Pass 3130.59 3039.71 3200.00 3035.25 11.55 22.15 114.19 271.53 7.000 519.92 116.60 409.01 Pass 3154.05 3061.89 3225.00 3057.62 11.64 22.36 114.24 271.34 7.000 526.70 117.59 414.64 Pass 3177.42 3083.92 3250.00 3060.38 11.73 22.62 114.26 271.13 7.000 533.49 118.63 420.62 Pass 3200.70 3105.83 3275.00 3102.96 11.83 22.87 114.30 270.89 7.000 540.33 119.72 426.42 Pass 3223.96 3127.69 3300.00 3125.56 11.92 23.12 114.30 270.65 7.000 547.22 120.82 432.28 Pass 3247.20 3149.48 3325.00 3148.16 12.02 23.36 114.28 270.39 7.000 554.17 121.90 436.19 Pass 3270.83 3171.62 3350.00 3170.78 12.13 23.61 114.25 270.25 7.000 561.16 123.02 444.12 Pass 3294.82 3194.09 3375.00 3193.41 12.24 23.86 114.20 270.20 7.000 568.19 124.16 450.04 Pass 3318.80 3216.55 3400.00 3216.05 12.36 24.11 114.14 270.14 7.000 575.23 125.30 455.98 Pass 3342.67 3238.91 3425.00 3238.70 12.47 24.37 114.09 270.09 7.000 582.29 128.44 461.94 Pass 3365.76 3260.55 3450.00 3261.37 12.59 24.63 114.04 269.77 7.000 589.36 127.62 467.90 Pass 3388.85 3262.17 3475.00 3284.06 12.70 24.88 114.00 269.48 7.000 596.42 128.78 473.86 Pass 3411.92 3303.78 3500.00 3306.76 12.82 25.14 113.96 269.19 7.000 603.49 129.94 479.83 Pass 3435.02 3325.42 3525.00 3329.48 12.94 25.39 113.91 268.91 7.000 610.56 131.09 485.80 Pass 3459.02 3347.91 3550.00 3352.21 13.07 25.66 113.85 268.85 7.000 617.62 132.29 491.70 Pass 3483.04 3370.44 3575.00 3374.96 13.20 25.92 113.80 268.80 7.000 624.63 133.48 497.57 Pass 3507.07 3392.99 3600.00 3397.73 13.32 26.18 113.75 268.75 7.000 631.61 134.67 503.42 Pass 3530.67 3415.16 3625.00 3420.51 13.45 26.43 113.71 268.59 7.000 638.56 135.84 509.26 Pass 3552.96 3436.13 3650.00 3443.31 13.57 26.68 113.70 268.11 7.000 645.52 136.99 515.18 Pass 3575.22 3457.11 3675.00 3466.12 13.69 26.93 113.70 267.62 7.000 652.51 138.13 521.13 Pass 3597.46 3478.09 3700.00 3488.95 13.81 27.17 113.71 267.13 7.000 659.53 139.26 527.13 Pass 3619.99 3499.39 3725.00 3511.79 13.93 27.43 113.72 266.72 7.000 666.59 140.42 533.12 Pass 3644.10 3522.20 3750.00 3534.63 14.06 27.70 113.71 266.71 7.000 673.66 141.65 539.04 Pass 3668.21 3545.05 3775.00 3557.48 14.20 27.97 113.71 266.71 7.000 680.72 142.87 544.96 Pass 3692.33 3567.92 3800.00 3580.34 14.33 28.24 113.72 266.72 7.000 687.76 144.08 550.87 Pass 3715.98 3590.38 3825.00 3603.19 14.46 28.50 113.73 266.73 7.000 694.80 145.28 556.80 Pass 3738.73 3611.99 3850.00 3626.06 14.59 28.74 113.77 266.32 7.000 701.87 146.40 562.80 Pass 3761.47 3633.59 3875.00 3648.92 14.72 28.98 113.80 266.02 7.000 708.97 147.54 568.85 Pass I 3784.17 3655.17 3900.00 3671.79 14.85 29.23 113.83 265.72 7.000 716.11 148.66 574.93 Pass 1 ' ') Sperry-SUD Anticollision Report ) Company: Aurora Gas, LLC Fidei: Cook Inlet Reference Sik': NicolaiCreet< Unit Reference Well: NCU#1 Rd'erence WeUpatlc. Plan: NCU#18 Site: Nicolai Creek Unit WeB: NCU#6 WeUpath: NCU#6 V4 : I . I Date: 07/03/2002 TOOe: 11 :11:17 Page: 6 I: Co-onlinate(N£) Rekf't'lWe: Well: NCU#1.Gríd North Vertkal(TVD) Reference: NCU#1: 2Z RKB22.0 Db: Oracle ~ererence MD TV» ft ft 3806.86 3676.73 3829.52 3698.28 , 3861.78 3729.01 Offset. MD TVD ft ft 3925.00 3694.67 3950.00 3717.55 3975.00 3740.45 Senü-M.-jor Axis Ref Offset TFO+AZI TFO-HS .CasJng It . ft deg deg in 14.98 29.46 113.86 265.41 7.000 15.11 29.70 113.90 265.11 7.000 15.30 30.06 113.83 266.94 7.000 Rule Assigned: Iø.tel.'-Site ElWr: Ctr.Ctr No-Go Distance Area It 11: 723.28 149.78 730.49 150.89 737.65 152.49 Major Risk 0.00 ft ADowable . Deviation Wøming ft . 581.06 Pass 587.23 Pass 592.87 Pass 3921.01 3786.01 4000.00 3763.39 15.62 30.58 113.53 276.66 7.000 743.96 155.18 596.63 Pass 3958.65 3822.37 4025.00 3786.37 15.80 30.90 113.50 280.88 7.000 749.26 156.69 600.41 Paee j , 3988.33 3851.10 4050.00 3809.39 15.94 31.18 113.55 282.83 7.000 754.24 158.20 604.17 Pass 4018.10 3879.95 4075.00 3832.43 16.08 31.46 113.63 284.88 7.000 758.88 159.63 607.61 Pass 4045.13 3906.17 4100.00 3855.50 16.21 31.71 113.76 285.76 7.000 763.20 160.86 610.83 Pass 4070.57 3930.85 4125.00 3878.58 16.34 31.96 113.90 286.36 7.000 761.31 162.10 613.91 Pass 4096.04 3955.57 4150.00 3901.69 16.46 32.21 114.05 286.79 7.000 771.22 163.29 616.80 Pass 4120.00 3978.82 4175.00 3924.81 16.57 32.45 114.20 287.20 7.000 774.93 164.45 619.53 Pass 4143.85 4001.95 4200.00 3947.95 16.70 32.68 114.39 286.59 7.000 778.49 165.61 622.14 Pass 4166.34 4023.77 4225.00 3971.10 16.81 32.91 114.58 286.02 7.000 781.95 166.72 624.68 Pass 4188.85 4045.59 4250.00 3994.27 16.93 33.14 114.77 285.47 7.000 785.31 167.81 627.13 Pass 4211.50 4067.55 4275.00 4017.44 17.05 33.37 114.96 284.96 7.000 788.58 168.92 629.47 Pass 4236.42 4091.69 4300.00 4040.61 17.18 33.60 115.13 284.83 7.000 791.87 170.12 631.69 Pass SffJi!: Nicolai Creek Unit WeD: NCU#8 Rule Assigned: Major Risk WeDpath: NCU#8 V1 Inter~Site Error: 0.00 ft Reference Olfset Sesni-MaJor Axis Ctr-Ctr Nø-Go AHowab1e I I MD TVD MD TVD Ref Offset TFO+AZI . TFO-HS Casing Dlst8me Area . Deviation Warning I ¡ ft ft. ft .ft ft ft. deg deg in ft ft ft 2200.00 2150.04 2275.00 2275.00 9.54 280.11 21.26 180.26 7.000 404.58 769.12 -320.68 FAIL 2223.34 2172.22 2300.00 2300.00 9.65 285.61 21.25 180.25 7.000 412.34 783.80 -327.02 FAIL 2247.49 2195.19 2325.00 2325.00 9.74 291.01 21.25 180.25 7.000 420.08 798.21 -333.11 FAIL 2271.27 2217.80 2350.00 2350.00 9.77 296.30 21.25 180.25 7.000 427.80 812.18 -338.62 FAIL 2295.04 2240.42 2375.00 2375.00 9.80 301 .50 21.24 180.24 7.000 435.53 825.92 -343.90 FAIL 2318.82 2263.03 2400.00 2400.00 9.83 306.62 21.24 180.24 7.000 443.25 839.43 -348.97 FAIL 2342.59 2285.64 2425.00 2425.00 9.86 311 ,65 21,23 180.23 7.000 450.98 852.72 ..J53.84 FAIL 2366.37 2308.25 2450.00 2450.00 9.89 316.60 21.23 180.23 7.000 458.70 865.81 -358.50 FAIL 2390.15 2330.87 2475.00 2475.00 9.91 321.48 21.23 180.23 7.000 466.43 878.70 -362.98 FAIL 2400.61 2340.82 2486.00 2486.00 9.93 323.60 21.22 180.22 7.000 469.83 884.31 -364.90 FAIL ) ') Aurora Well Service Rig No.1 BOP Equipment to he 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 L WS type), double smdded, wI blind rams and 3 ~" pipe rams. (Will be using 3 ~" DP for work string) 1 - Koomey Accumulator System 3000 psi wI 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 Aurora Well Servjc~ Rig No.1: Proposed 3M BOP Çonfiguration for well re-entry and worl )er procedures using reverse cir)ation. System designed to work in reverse circulation mode, where returns taken up workstring and through power swivel to pits. I~ I J ./' /1 Spool ~ ~ 3M Grant Rotating Head for 3 1/2" DP 3" 3M Manual Valve on spool for either pumping into or taking returns above rams. 3M Schaffer Annular Preventer . . Pipe Rams sized to work string. 11" 3M Double Gate wI 3/12" pipe rams installed. 11" 3M Mud Cross Blind Rams " . F~::~:!:~~?~~ ~ ::;~;;;r;;;:~~~:~ while reverse circulating ~ II 13 5/8''X 3M cqß:: Braden Head' 13 318" X 11" 3M Tubing Spool (tb 2" 3M Manual Valves On Wellhead , .. Fluid flow .,. .,. Drawing Not to Scale Fairweather E&P Services, Inc. Nicolai Creek No.1 B BOP System Rev. 02.01 I DHV 3O-July-02 Aurora WeD Service ~ No.1 Proposed Choke I Kill Ma.o. ifold Configuration All valves are 3" rate,--át 5000 psi. } Inlet from Power Swivel (Reverse Circulation Mode) Output to Pits 2" SM Rated Valves Hydraulic Remote Activated choke 3" SM Rated Valves "-<~~-"-v:9Il {I II ~. ;$ H :.: ¡:OJ ~.:r':::~ð:;::;:t:r B;I;~~ Flare Line to 3" SM Rated ~. ..~ Open Flare Pit Valves t ;i .1 Inlet from BOP Choke Line 3" SM Rated Valves f~l:' .... v.... ..~.... . ..~_.........I - ~. ., ~,-,--1..~.'......"'..'~.....m.. ~... r""~i¡o¡':;;:;"",.""""~;",...¡,;;~"";¡~,~"""",,,,,, " ',' - - 2" SM Rated Valves .. ;'~:::..:.~=~~:~~.':.:)'.~'l Manual Choke To Gas Buster "Atmospheric Degasser' Drawing Not to Scale FaifWeather E&P Services, Inc. Nicolai Creek No.1 B Choke/Kill Nlanifold Rev. 02.01 I DHV 3O-July-02 34' 16' ,,-. MUD PUMP #1 MUD PUMP #2 ICL 'WELL I I ! 7' I t I V#####ff############/. I // // /~ // // // // // // // // // // // // //~// i IIII Øðððððððððððð'»ððð#ð {/¿æ!,~ð¿/ðð1 ?'ðððððððððððððððððð/ý# ;r'l~~ß~ , ~ ~ //~~~1 MOBILE DRILL RIG >< '# WHþ-__C_L~_ELL ~ ~1://///////~~ IIII ~/Yðððððððððððððððððð/:';;//~J:'#'//////~~~ V#;;~ðððððððððððððð/ý~/~~~~~ ~ððððððß~ 3-STAGE MUD TANK: 228 BBL 80.5 BBL 80.5 BBL 67 BBL ~, AVIS RIG NO.1 LAYOUT 3/32" = 1'-0' -. ) ') AURORA GAS Proposal for Well Re-Entry, Sidetrack and Completion Nicolai Creek Unit No. 1B PTD 166-008 1.0 Background Information and Present Condition The Nicolai Creek Unit No.1 well was spudded by Texaco Inc., on October 31, 1965, from a surface location at the end of the Shirleyville airstrip adjacent to Cook Inlet. The objective was to drill the well directionally in a south westerly direction under the mud flats of Cook Inlet. The well was spudded and drilled with a 12 ~" hole to 232' , a 17 'lj" hole opener was run followed by a 26" hole opener. The 20" 94# surface cònductor pipe was then run and cemented into place at 232' with 594 sks of cement with good returns observed at surface. A 12 ~" hole was then drilled to, and a whipstock was set at 645' MD to begin directional operations. The well was then drilled to 700' at which time a gas producing coal seam was encountered, which required weighting up the mud system to '" 12.3 ppg. Gas cut mud presented a problem which required continual weighting up of the mud system and circulating out of the gas at each coal seam. The wellbore was eventually drilled to 1905' MD, the wellbore was logged, a 17 'lj" hole opener was run and 13 3/8" 54# casing was set at 1904' MD. The casing was cemented into place with 1530 sks of 15.38 ppg cement with good returns observed at surface. While waiting on the cement it was decided to unflange the BOPE to drain residual cement from the stack. A 1 'lj" hole was cut in the 20" conductor and the well proceeded to blow cement out of the hole. The BOPE studs were retightened while the well continued to unload cement out of the hole in the 20". A strong flow of cement followed by gas was observed for'" 5 hours at which time it slowed. Gas was observed to be flowing out of the 20" X 13 3/8" annulus as well as coming up the OD of the 20" conductor and out of several fissures in the ground surrounding the rig. Gas flow eventually breached a nearby water well and began flowing there as well. Operations were shut down untjl the location could be cleaned up and the gas flows could be stopped. The water well was pumped full of cement and the cellar was filled with 18 ppg mud to stop the gas from bubbling up from under the rig. When the gas flow had abated sufficiently to where the rig could safely be restarted, tubing was run to 1100', the mud weight was brought up to 13.5 ppg and the mud system was circulated out and conditioned. The 13 3/8" casing was perforated at 1140', but circulation could not be established. The tubing was then pulled up to 1070', and the casing was again perforated and again, circulation could not be established. A larger perforating gun was then brought to site and the casing was perforated at 720' and 1040'. Communication was immediately established and 150 bbls of mud were pumped into the formation followed by 840 sacks of cement squeezed into the formation at 1040'. The perforations at 720' were then isolated and a total of980 sacks of cement were squeezed into the formation. Gas was still observed to be flowing up the 13 3/8" X 20" annulus so the 13 3/8" casing was perforated at 400' and 430 sacks of cement were squeezed away. After waiting on cement and observation, it was deemed safe for drilling operations to proceed. The cement and float equipment was drilled out, the mud was Fairweather E&P Services, Inc. 7/30/2002 Page 1 of 13 Rev 1.2 ) ) conditioned and drilling operations continued to 3818' MD when 10 %", 40.5#, J-55 casing was run to 3817' MD, and cemented back to surface with 900 sacks of cement. After WOC, gas was observed to be bubbling to surface between 10 %" and 13 3/8" casing. The blind rams were closed and 800 psi was held on system for 24 hours. When rams were opened, gas flow had stopped. The BOP was removed and a "barber seal" ring was installed and welded into place to seal the 10 %" X 13 3/8" annulus. The BOP was re-installed and the system was successfully tested to 1500 psi. A 97/8" bit was then picked up, the float equipment was drilled out and OR drilling commenced. Operations continued until NCD 1 achieved a total depth of 8338' MD before becoming stuck in the hole. With the top offish at 6155', a cement plug was placed above the fish from 5800' - 6155', and the well was sidetracked to drill around the fish. The BRA again became stuck at 5976' with coal coming over the shakers. The fish was pulled and the decision was made to plug back to the shoe and sidetrack the well. A 240 sack cement plug was placed in NCU No.1 open hole with TOC at 3831' inside the 10 %" intermediate casing string. The Niçolai Creek Unit No. fA sidetrack was spudded oh March 10, 1966. The well kicked off ofNCU No.1 at 3831' MD and a 9 7/8" hole was drilled, again in a southwesterly direction under the mud flats of Cook Inlet. The NCU lA well was drilled to TD at 9302' MD (9149' TVD). Wireline logs were run and 7" casing was set at 8298' and cemented in place with 300 sacks of cement. A CBL was run and it was determined that poor cement bond characteristics were evident which required remedial perforate and squeeze techniques be performed prior to perforating and flow testing the well. Perforation and squeeze operations were performed at 7580' and 7790'. The well was then sequentially perforated and tested over several intervals from 7850' - 6685'. During the flow testing it was discovered that there were no producible quantities of oil present and it was decided to plug the well back and test the upper hole section for gas. A series of retainers and cement plugs (See Attachment I) were placed and the 7" casing was cut and pulled from 3780' to surface. Another cement plug was placed across the top of the exposed 7" casing stub into the 10 %" intermediate casing to effectively seal the wellbore from 3659' - 3880'. The 10 %" casing was perforated at 3318' for a Water Shut Off test and squeeze. The well was then perforated from 3615' to 3630' and the well was flow tested. The well was then killed and perforated from 3420' - 3462' and flow tested again. After extensive testing, the well was completed as a gas producer and the rig was removed. NCU lA was produced commercially for 3 months until sand plugged off the production string and the well was shut ifl. On July 15, 1988, Unocal and Marathon Oil Company acquired the Nicolai Creek Unit from Texaco Inc. and Mobil Oil Company. Due to poor operating economics at the time, the decision was made to plug and suspend all wells in the Nicolai Creek Unit until such time that the economics of producing them improved. The well was left shut in until 1991 , when the well was re-entered and suspended as follows: A balanced cement plug was placed from 3002' to 3659' to cover and seal the open production perforations. The casing strings were then sequentially perforated and squeezed at 720' (980 sks), 705' (230 sks) and 650' (400 sks). An EZSV was set at 690' and a cement plug was placed from 690' to surface (Attachment I). The well was left with the wellhead in place. Fairweather E&P Services, Inc. 7/30/2002 Page 2 of 13 Rev 1.2 Aurora Gas, LLC became operator of the Unit in the year 2000, and now intends to re-enter and re-complete select wells in the Nicolai Creek Operating Unit. Nicolai Cteek Unit No. lA has been selected as a candidate for re-entry and sidetracking to exploit untapped gas reserves on top of the structure. 2.0 Summary of Proposed Well Work In order to effectively re-enter, sidetrack and complete the Nicolai Creek No. 1B well as a gas production well in accordance with AOGCC regulations, the following tasks must be completed: 1. Drill out the cement plug at surface, the EZSV, and cement plug immediately below along with any residual cement to the KOP. 2. Orient and set a whipstock, and cut a window in the 10 %" casing to begin sidetrack operations. 3. Sidetrack the well and drill to the proposed target. 4. Run, set and cement in a 7" liner to TD. 5. Perforate the 7" liner at various zones of interest and test flow potential. 6. Install Meshrite screens for sand control and complete the well as a gas producer and install surface production equipment. 7. Remove drilling equipment, clean well site and prep for production. The above work will be performed in compliance with the regulations presented in Alaska Oil and Gas Conservation Commission Alaska Administrative Code: Title 20, Chapter 25. 2.0 Proposed Operations Program The following Operations Program addresses the work scope to be performed in the course of re- entry, sidetracking and completing the Nicolai Creek No. 1B only. The construction of surface production facilities and eventual connection of Nicolai Creek No. 1B to a gas transmission line will be carried out at a later date. 1. Obtain all required permits and regulator approvals before starting job. Anticipated permits and forms for the well work include the following: . Application for Permit to Drill, Form 10-404 (AOGCC) . Coastal Zone Management Program 2. Mobilize all required personnel and equipment to the Nicolai Creek No. 1B location on an as needed basis via barge and aircraft. The proposed personnel and equipment spread are as follows: Fairweather E&P Services, Inc. 7/30/2002 Page 3 of 13 Rev 1.2 Personnel: Equipment: Fairweather E&P Services, Inc. 7/30/2002 '} Company Man Tool Pusher Rig Operators RoughneckslRoustabouts Vac Truck Operators Equipment/Forklift Operators Cementers Wireline Crew ToolHand(~p~ock) Directional / Survey Hand Directional Driller Tool Hand (Liner) Mud Loggers ") (1) (1) (2) (8) (2) (1) (3) (3) (1) (1) (1) (1) (2) 1 Drilling/W orkover Rig BOP equipment and accumulator Choke manifold 966 loader Fuel Truck Cement pump unit BVlk cement silo Cell Phone communications Drilling Fluid Additives Drilling Fluid mix water 1 Lot: Oil Spill Contingency.Equiptnent Tools, sufficient for any contingency 4 %" Drill Collars (12) 6 1/4" Drill Collars (w/4 Y2" IF connection) (16) 5" HWDP (w/4 Y2" IF connection) 3 Y2 inch drillpipe (workstring) 2 7/8 inch production tubing (for completion) Slips and collar clamps for all tubulars Test Separator 1 Office bunk shack Gas detection system Pit volume/flow monitoring system Well testing equipment Cement Retainers / Bridge plug Permanent packers Test Packers Cross-overs ~pstock Window Mills Junk Mills Drillbits 6 1/8", 8 Y2" & 9 7/8" Mill Tooth Page 4 of 13 Rev 1.2 ') 7" liner Liner Hanger Assembly Ditch Magnets E-line truck MeshRite Screen for Completion Epoch Mud Logging Unit Sperry-Sun MWD Unit 3. Hold safety meeting before starting work on the well. Notify AOGCC of intent to begin operations. 4. Move in rig 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. 5. Give AOGCC 24 hour notice of pending BOPE test so that they may witness same. Check well-head for pressures, both on the 1 0 ~" id and the 1 0 ~" X 13 3/8" annuli. Function test and lubricate valves as necessary (well should be dead due to cement plugs placed in 1991). The 13 5/8" blind flange will be removed and a 13 3/8" X II" double stud adapter will be installed. An II" 3M double gate BOP stack, a II" 3M annular preventer, a Washington rotating head and flow lines will be installed and the system will be tested to 2500 psi. A 5M choke manifold will be used for well control. 6. Prepare 150 bbl of 9.5 - 10.0 ppg recycled mud to be used while drilling the cement plugs and bridge plug. 7. Pick up a 9 7/8" drill bit, crossover and collar to begin drilling out surface cement plug. Drill down six 4 %" collars and start picking up 3 ~"drill pipe while drilling. An EZSV should be encountered at ~ 690 feet. 8. Drill out the bridge plug to gain access to the cement and mud below. Drill up any remaining cement and cement stringers and RIH to ~2400' MD with bit assembly, circulate hole clean with high-vis (2.5 ppb Xanvis) sweep(s) as necessary to clean out cement and debri. Close pipe rams and test casing integrity by pressuring up to 2500 psi. If pressure test is successful, POOH, strapping pipe on way out, lay down bit and pick up 10 %" casing scraper and proceed to step 10. If casing integrity test fails, check for pressure on 13 3/8" X 10 %" annulus by viewing gauge or cracking annular valve to visually check for flow. POOH, strapping pipe on way out, lay down bit, pick up 10 %" casing scraper and proceed to Step 9. 9. RIH to clean casing id to 2400', circulate hole clean with high-vis sweep(s) to remove cement and debri. POOH, LD casing scraper and PU test packer, RIH, stopping every 500 feet (depth interval to be decided at time of test initiation), set packer and pressure test. Proceed to test casing while tripping in hole to 2400' , alternately pressuring up on casing ID and 10 %" casing X 3 ~"DP annulus. If leak is found to be above 2400', isolate leak by testing with smaller depth intervals, until packer is directly above leak, initiate an injection rate if possible, recording pressures and flow and develop a plan Fairweather E&P Services, Inc. 7/30/2002 Page 5 of 13 Rev 1.2 ) forward to remediate with squeeze cement job. If leak is determined to be below 2400' , POOH, and proceed to step 11, leak will be isolated when bridge plug is run and set for bottom trip whipstock. 10. RIH to clean casing id to 2400', circulate hole clean with high-vis sweep(s) to remove cement artd debri. POOH, LD casing scraper. 11. RU Schlumberger eline and RllI with GR-CCL correlation log. (May run TDT log to evaluate upper zones that would be encountered in the NCU No.8 well. This may help in selecting a KOP as well). PÖOH and RIH with gauge ring to verify drift to 2300' MD. PU and RIH with bridge plug on eline and set at ----2250'MD, or ----2' above a casing collar. Window will start 27' above the top of the bridge plug. Completed window length will be 21' +1-. 12. POOH, m.ake up and orient the starting mill, whipstock and MWD (see Attachment ~~B_ker Oil Tools Window Master, Bottom Trip Whipstock procedure's" and RIH. Be extra careful while passing through the BOP stack and wellhead~ When at depth, orient and set whipstock, per instructions of on-site Baker Oil Tool representative. Insure ditch magnets have been installed at shakers to remove metal cuttings generated by milling process. Consult with onsite MI Mud Engineer to treat mud system as necessary to attain a satisfactory milling fluid (Attached Mud Program.). Again: Follow procedure outlined in above document and recommendations of onsite whipstock I milling hand for setting the whipstock and milling the window. While milling, it will be necessary to have personnel monitoring shaker system to remove metal. Caution is warranted as shavings and slivers are very sharp. Metal cuttings should be removed and stored separately from regular mud and cement cuttings for disposal. 13. When milling is complete, circulate hole clean to remove metal cuttings from milling procedure. Pull assembly back through window and perform LOT, recording results. POOH and LD mill assembly. RU and RIH with 8 Y2" bit on steerable BHA per Directional drillers recommendations (Attachment VI). RIH to 2100', orient BHA to high-side, shut off pumps. (Do not have mud motor turning when approaching top of whipstock and window. Do not begin pumping until bit has cleared window). 14. Bring pumps on line and orient motor, verify MWD is working properly, begin directional drilling program per Sperry-Sun directional program (Attached). Directionally drill well to vertical as quickly as possible attempting to achieve ---- 10° 1 100' doglegs while surveying every connection or, as required by directional driller. When vertical, rotate BHA and drill to TD, surveying every 500' minimum. Monitor BHA characteristics while rotating, if poor ROP's or excessive torque is observed, it may be necessary to POOH, pick up pendulum rotary BHA assembly and drill to TD at ----3653' MD (3600' TVD). While directionally drilling, it will be necessary to survey the wellbore every 100' minimum. When the wellbore has reached vertical, a survey every 500' will be necessary. Be very observant of drilling characteristics. Many drilling breaks in the Cook Inlet region are actually coal beds. When a coal is encountered, pick up immediately to clear BRA of coal stringer and circulate, keeping pipe moving. Fairweather E&P Services, Inc. 7/30/2002 Page 6 of 13 Rev 1.2 .) ) Coals are plastic in nature and tend to flow, a characteristic whicb is more pronounced at greater depths due to the increased overburden pressure. Stuck pipe could result if attempts are made to drill through without allowing coals to stabilize. After a short period of circulating, run BHA assembly through drilled section while circulating and rotating, cut some more hole and pull back out again. Repeat this process until succe:r¡sfully through the coaL If excessive totque, overpullor drag are observed while working pipe through coal, pull clear immediately and repeat above sequence. Weighted viscous sweeps and spotting of fracture sealing additives may be necessary. REMEMBER: Millions of dollars have been spent on lost BHA's and attempts at retrieving tþe same in the Cook Inlet Region! The majority of these cases were because of the coals. 15. Condition mud while çirculating bottoms up, short trip and circulate bottoms up again and POOH, strapping pipe while doing so. Keep watch on pits for gas cut mud and signs of flow. Gas cut mud will likely appear so circulate out as it appears. Be prepared to take action immediately if well appears to be flowing. 16. RU wireline BOP's and lubricator and logging suite, with SP -DIL, MicroSFL, GR- Sonic and GR-Density Neutron from window to TD. (The actual suite of logs to be run will be determined prior to the run. At this time an NMR, or CMR (fifth generation NMR) are being contemplated as well). POOH and RD eline. 17. PU bit and collars, RIH to TD. Work pipe while circulating bottoms up. When mud is conditioned properly, POOH, lay down bit and BHA. PU and run ---1800' 7" 23# K-55 liner with shoe at bottom and float collar placed one joint above the shoe or --40' uphole. Prior to running, the liner needs to be drift checked "rabbited", strapped, and tallied accordingly while running. When making up the liner, the shoe joint, and float collar need to be Baker-Locked. 18. Please see Attachment, "Model D, Liner HangerlPacker running and cementing Procedure. Use centralizer schedule as outlined in (Attached). Notify cementing company of pending cement job and insure cement company is on location by time liner is on bottom. Give AOGCC 24 hour notice of intent to cement liner in place and chance to witness testing of same. Run liner, pick up liner hanger, setting tool and workstring. RIH to TD, break circulation. Reciprocate liner while circulating. 19. RU cementers, install cementing head and while reciprocating, pump 30 - 50 bbl preflush / spacer ahead of cement. Displace sufficient cement (70 bbls @ 30% excess) to cover entire liner interval from 3650' MD to liner hang off point at 1850' MD. Please see Attachment(s), "Model D, Liner HangerlPacker running and cementing Procedure" & "BJ Services 7" Liner cementing Program". When cement has been displaced, release pump-down plug at surface and displace cement into position with 13.7 bbls mud while reciprocating pipe. When cement has been placed, set liner packer at 1850' MD, release setting tool and pull free from liner top. Initiate reverse circulation to remove excess cement back to surface for disposal. Circulate until uncontaminated mud returns are observed. POOH, close in well and WOC. Due to dynamics of drilling and hole Fairweather E&P Services, Inc. 7/30/2002 Page 7 of 13 Rev 1.2 ) ) conditions, cementing program is subject to change, all placement and displacement calculations must be checked and verified by both on-site Cementing Supervisor and Company Representative prior to cementing liner. Prior to beginning cementing operations, a meeting will be held with all involved personnel to insure everyone is in total understanding of their role in performing the cementing and liner hanging procedure. Cementing operations wül not begin until all materials and equipment required to successfully complete job are on location. 20. PU and RIH with 9 7/8" bit and casing scraper. TIH cleaning wellbore to top of liner hanger at ~ 1850' MD. Do not spud bit into top of liner hanger. POOH and lay down 9 7/8" assembly. 21. PU and RIH with 6 1/8" bit, 7" casing scraper and collars to clean out ID ofT' liner. RlH to top of float collar at ~3610' MD while circulating. When on bottom, close in BOP on pipe and pressure test liner to 2500 psi. When done pressure testing, open rams and while on bottom, pump 50 bbl mud pill w/2.S ppb Zanvis viscosifier while rotating and reciprocating pipe. Displace mud from hole with clean KCL brine. When clean returns are observed at mud tanks, stop circulating, close in BOP, and transfer contaminated mud from pits to onsite storage tanks, clean pits and fill with clean KCL brine. KCL will be weighted as necessary for well control during completion operations. 22. When done swapping pit fluids, open BOP, pull pipe so casing scraper is ~t top of liner hanger and RIH back to bottom. Circulate bottoms up twice, POOH and lay down casing scraper and bit. 23. RU eline with lubricator and wireline BOPE. RIH with OR-CCL logging tool to TD. Log from PBTD to 100' above liner top and correlate with open hole logs. POOH, LD OR-CCL tool. 24. For the perforating sequence, which will result in 65' of perforations over an interval of 305' of formation, 4 Y2" HSD guns with 6 SPF at 60-degree phasing will be used (43 NS charges for 0.83" holes, or 6.49 in2/lineal ft of perforations). First run in and perforate the interval from 3630' - 3615'MD, or as determined from logs. POOH, pick up gun #2, RIH and perforate from 3460' - 3420' MD, or as determined from logs. POOH, pick up gWl #3, RIH and perforate from 3335' - 3325' MD, or as determined from logs. Keep hole full while perforating. POOH, RD lubricator and eline BOPE's. 25. PU and RIH with 7" casing scraper to PBTD. Circulate 20 bbl high vis (HEC-10) pill to clean out perforating debris. Circulate bottoms up 2 (two) times, or until clean returns while reciprocating casing scraper over perforations. POOH, LD BHA and 250' of workstring. 26. Pick up and RIH with MeshRite Screen assembly. Assembly will consist of 5" MeshRite Screen (sufficient to cover each perforated interval) separated by 3 Y2" tubing spacers, a bull-nose shoe, and packer. All tubing will be rabbited as it is run to verify drift. During assembly, the pin ends only will be doped lightly with a 1" brush, and a screen table and Fairweather E&P Services, Inc. 7/30/2002 Page 8 of 13 Rev 1.2 ") ) worktable plates will be used. Extreme care should be exercised during the assembly and running of the screen assembly. When complete, the assembly will be run and set in place using the work string. 27. Slowly (3 min./stand minimum), run screen assembly to bottom. Be extremely careful when approaching and passing over the liner lap interval with the screen. Tally all pipe while running to insure packer is set at ",3200' MD. Set packer, release from packer and POOH, laying down workstring. 28. PU and run packer seal assembly with locator and 2.81" X-profile nipple above locator on 2 7/8", J-55, 6.5Ib/ft 8Rd EUE tubing tp top of packer. Circulate packer fluid (approximately 225 bbls KCI brine with O2 scavenger. Stab into packer, test seals to 2000 psi. Space out, land tubing and set BPV in tubing banger. 29. ND BOP stack and NU tree. Test tree to 2500 psi. Rig up test separator and lines. Pull BPV, swab well in to test separator. Please see Attachment III, for production initiation sequence as required for proper screen life. 30. When well has unloaded fluids and is flowing satisfactorily, close in well, rig down rig and remove all equipment not pertinent to production testing operations of well. Clean up site and mobilize equipment to next well. 31. File new F OrIn 10-407 with AOGCC describing final status of well. Attachment II depicts the final proposed completion ofNCU No. lB. Fairweather E&P Services, Inç. 7/30/2002 Page 9 of 13 Rev 1.2 ) ) 3.0 Pressure Information The maximum anticipated bottomhole pressure expected, based on historical well data, when area was originally drilled is 1709 psig, this equates to a maximum tubing pressure at surface of 1555 psig. Permission is requested to test BOPE to 2500 psig, maximum. Fairweather E&P Services, Inc. 7/30/2002 Page 10 of 13 Rev 1.2 ') ) 4.0 Liner / Casing Program and Analysis For the NCD 1B well, a 7" liner is being proposed from 1800' +/-, to TD at 3653' MD (3600' TVD). The liner will be 7", 231b/ft K-55 grade pipe with LTC. The attached Figure(s) 4.1 and 4.2, detail the analysis. The attached documents, "Model D, Liner Hanger/Packer running and cementing Procedure" & "BJ Services 7" Liner cementing Program", detail the actual hardware requirements as well as running and cementing protocol. An analysis was performed for the proposed final casing/liner configuråtion. The first analysis (Figure 4.1) was performed to insure that the 10 %" casing, which will be exposed above the 7" liner hanger, is of sufficient structural strength to contain any pr~ssures it may be subjected to during the course of drilling and completing the well. Analysis shows a sufficient safety factor exists for any conceivable scenario. A minimum SF range of 1.5 -1.8 was used during the calculations. Even when, during the burst calculations, an ASP of 2468 psig is used (calculated to be the maximum possible at the 7" liner set depth of3600' TVD), a safety factor of 1.25 is still available. Where: ASP = Frac Grad - Gas Grad) * Set Depth TVD of next casing string (.796 - .11) * 3600' 2469 psig @ .7" liner set depth = Burst Rating of 10 %" casing:;: 3130 psig ~ Top Burst SF = 3130/2469 = 1.26 ~ Bottom Burst SF = (3130 + 3600* .465) / 2469 = 1.9 Analysis of the 7" liner was performed assuming a worst case scenario, where the liner would be run from surface to TD. Again, analysis shows (Figure 4.2) that the liner has sufficient structural integrity to handle any predicted pressures which may be encountered during the course of completing and ptoducing the well. The liner and hanger/packer assembly will be run according Baker Oil Tools recommended running protocol, which is attached. Fairweather E&P Services, Inc. 7/30/2002 ) Page 11 of13 Rev 1.2 WelllD Nicolai Creek Unit 1 B . Min. S.fety Factors To Be Used: Body Yield: Jt. Strength: ;Collapse Collapse While Cementing Top Bur$t 'Bottom Burst -Casing String No.2 Properties: , . Casing Properties: Size OD: Grade: : Welght þpf: Coupling: . Set Depth ft Next Casing Depth 10 3/4 J-55 40.50 LTC 2000.00 (ft)MD 3653.00 (ft)MD ,Collapse Resistance (psi) ;-Intemal ìYield (psi) Joint Str:ength (psi) x 1000 ~Body Yield (psi) x 1000 'Fluid Properties: ~Material Mud Weight ~nticipa~ed Mud Wt Next Csg pt. Calcula~ed Bouyancy Factor @ Mud Wt: Anticipa~ed Cement Weight (ppg) :Sea W~ter Gradient (ppg) , Frae Gradient at Shoe(ppg) Gas G~dient (psilft) Mud Backup Gradient ppg % Flufd :Orop for Collapse Calculatìon (Enter#). 1.5 1.8 1.5 1.5 1.5 1.5 ) 1960.00 (ft)TVD 3600.00 (ft)TVD 1580.00 3130.00 420.00 629.00 420,000.00 '" Tensile Limits 629,000.00 '" Tensile Limits Weight ppg Gradient psilft 10.00 0.520 psi/ft 9.50 0.494 psilft 0.85 15.8 0.822 psi/ft 8.94 0.465 psi/ft 15.3 0.796 psi/ft 0.110 8.95 0.465 55 0.55 FIGURE 4.1 ) Tensn. Calculations: Weight :In Air (Ibs) Bouyal1t Weight In Mud (lbs) 81,000.00 68,614.68 Maximum setting depth (ft) 10,370.37 In Air: = Jt Strength I Wt.ppf Joint Strength Safety Factor 5.19 In Air: = Jt Strength I (Wt ppf. set depth) Body Yield Safety Factor 7.77 In Air: = Body Yld I (Wt ppf * set depth COllaþse Calculations: Collapse Safety Factor 4. 12 Collapse Res I (Depth TVO * % Fluid Drop *(Mud S-up Grad - Gas Grad» Colla~e SF while cementing 2.26 Collapse Res I Depth TVO * (Cmt Grad . a-up Mud Grad) No lost Circulation/Evacuation ocçurs Burst Calculations: Assume seawater backup gradient. .466 psiAt for burst design purposes Assume worst case by using frac gradhmt at casing shoe for ASP calculation!. ASP (anticipated surface pressure) 1,343. 78 (Frac Grad . Gas Grad)* Set Depth TVO Top Burst Safety Factor 2.33 Tube burst rating I ASP Bottom! Burst Safety Factor 3.01 (Int. Yld + Depth TVD * Seawater Grad) I ASP Summary OF 10 3/4 Safety Factors Body Yield 5.19 in air "Tensile" Joint Strength 7.77 in air "Tensile" Collapse 4.12 Collapse 2.26 while cementing Top Burst 2.33 Bottom Burst 3.01 OK OK OK OK OK OK ) I WelllD Nicolai Creek Unit 1 B Min. Safety Factors To Be Used: Body Yield: Jt. Strength: Collapse . Collapse While Cementing fTop Burst . Bottom Burst Casing String No.3 Properties: Casin~ Properties: Size OD: Grade: Weight ppf: Coupling: Set Depth ft Next Casing Depth 7 K-55 23.00 LTC 3653.00 (ft)MD 3653.00 (ft)MD .Collaps, Resistance (psi) Internal ¡Yield (psi) Joint St~ngth (psi) x 1000 Body Yield (psi) x 1000 Fluid Properties: .Material Mud W$ight Anticip~ted Mud Wt Next Csg Pt. Calcula~ed Bóuyancy Factor @ Mud Wt: Anticip*ed Cement Weight (ppg) . Sea W*er Gradient (ppg) Frac Gr~dient at Shoe(ppg) Gas G",dient (psi/ft) Mud Backup Gradient ppg ..% Fluid I Drop for Collapse' Calculation (Enter I). 1.5 1.8 1.5 1.5 1.5 1.5 ') 3600.00 (ft)TVD 3653.00 (ft)TVD 3270.00 4360.00 313.00 366.00 313.000.00 it Tensile Limits 366.000.00 it Tensile Limits Weight ppg Gradient psi/ft 9.50 0.494 psi/ft 9.60 0.499 psilft 0.85 15.8 0.822 psilft 8.94 0.465 psi/ft 15.3 0.796 psi/ft 0.110 8.95 0.465 55 0.55 FIGURE 4.2 I Tensile Calculations: Weight ,In Air (Ibs) Bouyal1t Weight In Mud (Ibs) Maximum setting depth (ft) Joint Strength Safety Factor Body Yield Safety Factor Colladse Calculations: Collap$e Safety Factor Collap$e SF while cementing Burst Calculations: ASP (anticipated surface pressure) Top Burst Safety Factor Bottomi Burst Safety Factor Summary OF 7 Body Yield Joint Strength Collapse Collapse Top Burst Bottom Burst ) 84,019.00 71,814.41 13,608.70 In Air: = Jt Strength I Wt.ppf 3.73 In Air: = Jt Strength I (Wt ppf. set depth) 4.36 In Air: = Body Yld I (Wt ppf'" set depth 4.65 Collapse Res I (Depth TVO " % Fluid Drop "(Mud B-up Grad - Gas Grad») 2. 55 Collapse Res I Depth TVD " (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Assume seawater backup gradient, .465 psíIft for burst design putp0S6S Assume worst case by using frac gradient at casing shoe for ASP calculations. 2,468. 16 (Frac Grad . Gas Gradt Set Depth TVD 1. 77 Tube burst rating I ASP 2.44 (Int. Yld + Depth TVD .. Seawater Grad) I ASP Safety Factors 3.73 in air "Tensile" 4.36 in air "Tensile" 4.65 2.55 while cementing 1.77 2.44 OK OK OK OK OK OK ') ) 5.0 Drilling Hazards Drilling in the South Central Region of Alaska offers its own challenges. Common known hazards are as follows: 5.1 Shallow gas: Shallow gas is a known hazard which exists throughout the area. Shallow gas has been encountered in surface water wells in the Wasilla area, and is believed to originate in the many shallow coal beds which make up the regions subsurface. Of critical importance to the well being worked on, shallow gas of sufficient quantity to require mud weights of 13.5 ppg was encountered in a coa' seam at 750' MD. In the case of the NCD 1 A well, the gaseous seam has been cased off and should not pose a hazard at this time. What does constjtute a potential hazard though, are the gas production zones which will be encountered during the sidetrack. Due to the shallow nature of the well, vigilant monitoring of the pit system, especially during trips is critical. This is because there is little reaction time allowed between when a potential kick is observed and decisive action must be taken to close in the well. 5.2 Coal Seams: The Cook Inlet region is rich in coal seams, interbedded between the sands, gravels and shale~s that make up the Beluga and Tyonek formations. Drilling into a coal seam will appear to be a drilling break. The major hazard of drilling into a coal seam, without observing the proper response, is the risk of stuck pipe. The proper course of action for preventing stuck pipe is two-fold. First, prior to drilling, insure the drilling fluid system is up to par, per recommendations from the on-site mud engineer. The second step to successfully drilling through coals in the Cook Inlet area is to not get greedy when coals are encountered. When a coal has been encountered, pull back above coal after drilling into it, and circulate, allowing the coal to stabilize. Re-enter, drill some more, and pull back out again. Continue in this fashion until successfully through the coal bed. The key word in successfully drilling the coal beds is patience. It should be remembered that coals behave plastically, and will flow under the weight of the overburden. The deeper the coal, the more pronounced this tendency becomes. For this reason, it is critical to maintain the proper weight and viscosity of your drilling fluid to properly remove the coals drilled up, and to hold flowing coals in place. Again, heed the recommended drilling fluid program and advice offered by the Mud Engineer. 5.3 Nearby Well's: The NCD lA wellhead is within close proximity to two other wells on the same pad, the NCD 2, currently being worked over, and NCD 6, a P&A'd well. Proximity wise, these wells vary in distance from 12' to 50' from the NCD lA. At surface one needs to be careful around the wellhead of the NCD 2 well, which will be completed when NCD IB is drilled. From a subsurface point of view, sufficient clearance is available so no interference, magnetic or mechanical should be observed. In the event the sidetracking operation does not follow the directional plan, wellbore separation may pose a problem and should be analyzed at that time. Fairweather E&P Services, Inc. 7/30/2002 Page 12 of 13 Rev 1.2 I. J Prop.osed I x I As is 26" Hole 20"94# H-40 @ 232' CMT'D to surface WI 300 Sks Whipstock @ 645' in 17 1/2" hole EZSV @ 690' 171/2" Hole 13 3/8" 54# J-55 @ 1904' Cmt'd to surface WI 1530 Sks 12 1/4" Hole 103/4" 40.5# J-55 @ 3817' Cmt'd to surface WI 900 Sks ) Nicolai Creek No. 1A OJ...'.' Nicolai Creek Field Alas.,. . Suspended Cement Plug: Surface.. 890' 60 Sk Top Job in 20" X 13 3/8" Annulus 9 7/8" Hole 5' cement on top of retainer DC Retainer @ 6666' 60 Sk cement squeeze DC Retainer @ 6735' 200 Sk cement squeeze Bridge Plug @ 7200' DC Retainer @ 7520' 120 Sk cement squeeze Baffle @ 8209' MD 7" 26# & 29# @ 8298' MD Cmt'd WI 300 Sks through TO @ 9302' MD baffle. 9149' TVD ' Perfs: 400' Sq.z'd WI 400 Sks Cmt Peñs: 650' Circ & Sqz'd 230 - Sks Cmt. Perfs: 705' Perfs: 720' - 721' Sqz'd 980 Sks Cmt. Perfs: 1040' Sqz'd wi 840 Sks Cmt Peñs: 1070' Questionable Penetration i;,. '..', t. ",'. .~ \j ., .< ..,.:~~,' . .. ~ ,I I~II .. ?~ i:~-t-,"', ',I, Ð . " ..:.~~: .::~:...,,,,:_.:;t;-~7" ,~.. r:. .;' c, .,. , 'i/'I.l ~.\J.: ~~: r . . u ~~~;~ . ,. Jr ¡Ii. f.!J, ... . .. I.: .. .. )~~Itr~ ~ ".~~. '. . Perfs: 1140' Questionable Penetration I ~ß~." ; \~h., . r . ~:;¡W t::~ 5 SPF @ 298' Squeezed wI 200 sx in 1991 ~!l\IN'~il 13.63 ppg )';'I;¡\I~\ I~'.)~ M d ,..p lll1~.\ U r'@~-I:' t~! ...I."'.;Balanced Cement Plug 3002' to 3663' . ,., .fi.f~fJ;¿~~~'¿: ,,;. WSO Perforations: 3318' 2 spf ., ::r;J~,,!t??J!! '.. Perforations: 3420' - 3462',2 spf .:1". ...-~ ..,~.......~ .' .. .'1. ,,,,;t.; .,-..';¡f~.t',;.,j:.'~ .I'.~i" ~... I'r¡ ~...~~,"" ",.\~ ._~tï:~:~~j¿~~'~ :~. ; Peñorations: 3615' - 3630',2 spf =-~~1')..~¡;"':i.;.~~~'I!';.';.: \. .I~' ,A I ,It.~;¡;',.,,;.r;.~ .". ~.i~, I .~, I i . t ;~ ~":::;;~"'-:;""':'-J;; ._~ I ., :.t~l~.~ (-~~\{.':£:-.~:S-.~~~.:~ l}~!.~.' ' Balanced cement plug from 3659' .. 3880 I'.,,, ;.,\:I~~jf~2 ':>.F~7"''!oI.'~ II" .~,I. ~i'\'¡\'\~~. "b~;:~;s;).~~ ~ ,~_c_c.~c -:"""""""7" Casing cut at 3780' and pulled Attachment I . Peñorations: 6685' - 6725', 2 spf Peñorations: 6740' 2 spf Perforations: 7210' .. 7230',2 spf Peñorations: 7570' -7670', 2 spf ...1 , Peñorations: 7680' .. 7710',2 spf Peñorations: 7790' -7828', 2 spf Peñorations: 7820 -7850', 2 spf DRAWING NOT TO SCALE NICOlAI CREEK No. 1A FAIRWEATHER E&P Rev. 02 I CtN SERVICES ¡NO. 23-..V&02 ) ) 5.4 Incorrect A V's / Mud Solids / Stuck Pipe: The configuration of the wellbore while drilling will present it's own problems. The current plan calls for sidetracking out of the 10 %" casing and drilling an 8 ~"hole to TD. The BRA will utilize 6 ~"- 6 %" drill collars, RWDP and components. While sufficient hydraulics should be achievable in the 8 ~" OR section, the 3 ~" X 10 %" cased hole section just above the liner lap is an area of concern. While drilling, it will be necessary to monitor mud rheology and pump conditions carefully to insure the best hydraulics, within the limits imposed by the surface equipment are maintained. In the event a pump should go down, or flow is reduced to a point where the hole is not being properly unloaded, it may be necessary to pull off bottom and pull BRA up into the 10 %" cased hole section, until the pump problems can be resolved. While drilling, run occasional higlt-vis sweeps as recommended by the on-site mud engineer to control the amount of solids in the hole. After extended drilling, do not allow pipe to remain stationary any longer than absolutely necessary in a pumps down mpde, ie., connections, survey's, repairs.. If excessive drag, torque, or pipe sticking is evident while making connections, á. high-vis sweep, a short trip to the window, or both may be required. When making connections, it may be necessary to work the pipe a couple times with the pumps running prior to making the connections. Fairweather E&P Services, Inc. 7/30/2002 Page 13 of 13 Rev 1.2 I x I Proposed l I As is Nicolai Creek No.1 B Nicolai Creek Field Alaska Producer ) ) 2718 J-55 6.5 #/ft Production tubing Peñs: 400' Sqz'd WI 400 Sks Cmt Perfs: 650' Circ & Sqz'd 230 - Sks Cmt. Perfs: 705' Perfs: 720' -721' Sqz'd 980 Sks Cmt. Perfs: 1040' Sqz'd wi 840 Sks Cmt Perfs: 1070' Questionable Penetration Perfs: 1140' Questionable Penetration Top 7" 23# K-55liner @ -1850' MD Baker Model "D" Liner Hanger I Packer 26" Hole 20"94# H-40 @ 232' CMT'D to suñace W/300 Sks Whipstock @ 645' in 17 1/2" hole 17 1/2" Hole 133/8" 54# J-55 g 1904' Cmt'd to surface WI 1530 Sks Tøp Whipstock @ - 2000' . Baker v.vindowMaster Bottom ~\ Set Whlpstock.a2 1/4" Hole f~. Perforations: 3615' - 3630',2 spf 103/4" 40.5# J-5S @ 3817' Cmt'd to surface WI 900 Sks Attachment II O2 Inhibited KCL packer fluid in 2 7/8" X casing annulus to suñace above Packer "X" Nipple Permanent Packer @ - 3000' 31/2" J-SS Production Tubing Spacer between screen intervals 5 112" Meshrite Screen 3050' to 3400' Well perforations 3325' - 3335' 3420' .. 3460' 3615' - 3630' @ 6 spf, 60-degree phasing 7" liner set at 3650' MD(3600' TVD) NCU 1 B TD @ - 3650' MD (3600' TVD) See NCU 1A Diagram for additional Info DRAWING NOT TO SCALE NICOLAI CREEK No. 18 . . . FAIRWEATHER E&P Rev. t12 I DHV SERVICES INo. ~ ) ~ June 7, 2002 Fairweather E&P Services Inc. Anchorage, Alaska A TTN: Duane Vaagan Ref: Aurora Gas Nicolai Creek Unit IB Duane Enclosed ,S the mud program for your upcoming Nicolai Creek #lB re-entry. Included is a well summary, economic summary, interva~ summary, and the project team. This program is for a Flo-ProlKla-Gard system with 3% KCL. This system is the current system of choice by Unocal and Marathon for shallow gas wells in Cook Inlet. We have had consider- able success with this sýstem in the Kenai Peninsula in the past year in inhibiting shale hydration, minimizing washouts/hole enlargements, and in reducing dilution rates. Mud weigl).ts up to 10.0 ppg can be expected. The completion costs for this well assumes using 3% KCI brine. Please call me if you have any questions regarding the mud program, Lee Dewees Project Engineer M - I Drilling Fluids 907 274-5533 M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax ~ DRilliNG r ~ FLUIDS ) ) /' Well Summary Nicolai Creek r Casing Size (in) Hole Size (in) Casing Program Existing 10.75" 8 3/4" 7 Liner 8.3/4" Key Issue 1 Hole Cleaning Key Issue 2 Lost Circulation Key Issue 3 Hole Stability Coal Stability Key Issue 4 Mesh Rite Screen M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Depth TVD Mud Mud Sum Cumulative System Weight Days Mud Cost (ft) (ft) (ppg) Recycled mud 9.5 3 $13250 2250' 2250' To Flo-ProlK1a-Gard 9.5 - 10.0 10 $70,350 1 3650' . Maintain adequate rheology (LSRV +/- 40,000 cps) to insure good hole cleaning. . Periodic additions of Safecarb Fine or Medium will control seepage losses. . Maintain 4 - 6 ppb KlaGard concentration through the en- tire interval. Add Dualf10 and Pløypac UL as required. . Add Asphasol supreme if required. . Build 3% KCI completion brine. ~ DRILLING r ~ FLUIDS ) ) Interval Summary - Nicolai Creek Drilling Fluid System Flo-Pro / Kla-G-ard/3 % KCL Key Products Flo- Vis / Kla-Gard / Barite / Caustic Soda / Dual-Flo/KCL/DD/Drill XT/Safe Carb/ Asphasol Solids Control Shale Shakers / Desilter / Centrifuge / Ditch Magnets Potential Pròblems Window Milling / Hole Cleaning / Lost Circulation / Directional Control/Drill Solids/ Hole Stability/ Soughing Coal/Bit Balling Depth Mud Plastic Yield API Lubricant Total Interval Weight Viscosity Point Fluid Loss Percentage Solids (ft) (ppg) (cp) (lb/100ft2) (ml/30min) (%) (%) 2250' (milling) 9.5 5-7 25- 35 8 +-- 10 0 0-1 2250' -3650' 9.5-10.0 8-12 20 - 30 6-8 1-2 2-10 . Use recycled fluids to de-complete Nicolai Creek Unit lB. Treat as required. . Build initial volume with 3% KCL, 1.5-2 ppb Flovis, Caustic for 9.0 pH3 ppb, Kla-Gard, 2 ppb Dual-Flol, 4 ppb Asphasol, and 1/4 ppb Greencide. . Ensure proper placement of ditch magnets to capture metal cuttings . Rlli, set whipstock, displace well to Flo- Pro fluid, begin milling when fluid passes mill. . Pump high-viscosity sweeps as needed to insure good hole cleaning. . Keep drill solids to a minimum by aggressive use of all solids control equipment, dilution with 3% KCL, and maintaining 4+ ppb concentration of Kla-Gard (shale inhibitor). . Maintain fluid loss control with additions of Dual-FIo and PolyPac UL. . At T.D., sweep hole, spot a clean FloPro pill (35 -40 yield point) . Run and set liner, clean pits, displace well to 3% KCL. . Initial volume requirements should be 400 - 500 bbls M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax ~ DRILLINIi , ~ FLUIDS ) ) Project Team Nicolai Creek Ray Figueroa Field Engineer Lee Dewees Project Engineer t ~... t ~ , Gus Wile Warehouse Manager i II . MI Project Engineer and Tech Service Engineer will coordinate between the Fairweather office, rig, warehouse, and the M-I field engineers. . Well progress will be monitored to look for any changes which will improve the efficiency of the opera- tion or avert trouble.. Project Team Title Work Cellular Craig Bieber District Manager 907274-5051 907 229-1196 Deen Bryan Tech Service 907 274-5003 907223-1634 Lee Dewees Project Engineer 907274-5533 907 227- Gus Wik Warehouse Manager 907776-8680 907 252-4218 Ray Figueroa Field Engineer 907274-5564 Rob Reinhardt Field Engineer 907 274-5564 M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax P1J"'f-j DRilliNG , ~ FWIDS ) ') Attachment III Schlumberger's Recomroended Gas Production Start-Up Procedures for MeshRite Screen following installation. For Gas Wells: Step 1. Step 2. Step 3, Step 4. Limit gas flow to 25% of full production for 2 - 4 days, 4 preferred. Increase gas flow to 50% of full production for 2 - 4 days, 4 preferred. Increase gas flow to 75% of full production for 2 - 4 days, 4 preferred. Open production to 100%. By following the proposed gas production initiation regimen above, the following benefits should be achieved: ' 1. Plugging of the perforation channels will be minimized 2. Erosion of the screen across the perforated intervals will be minimized. 3. Solids migration through the screen will be minimized 4. The induced sand pack distribution between the perforations and the screen assembly will be optimized 5. An effective sand pack set up will occur within the screen 6. Clay and silt transportation in the near wellbore region will be reduced or eliminated, reducing the likely hood of plugging. ~.Inp3~O.ld }f30JsdIQM SIOOL 110 .I3}J8H \ ( Section 1. 1.0 1.1 1.2 10~"~indowMaffi~M~~~etB~~~)~p~~~ \ . Well Preparation Prior to Running the WihdowMasterTtJI System. A casing scraper run should be made to ensure that no restrictions are present in the well bore that may cause a premature set of the Bottom Trip Anchor or release from the whipstock via the shear bolt. If a casing scraper run is declined, at minimum a full bit diameter Gauge ring run on wireline should be performed. 1.3 A Bridge Plug shöuld now be set (+-2') above the casing collar. In the Intended kick-off joint. 1.4 Window will start (27') above top of bridge þlug. 1.5 Completed window length will be (+- 21') Please note that if a casing scraper run is performed the well could be displac~d to milling fluid at this point and thus allow for milling to commence once the Bottom Trip Anchor has been set. Section 2. 2.0 2.1 Assembly of WindowMasterTM Bottom Trip Whipstock System. Make-Up the following assembly. 103/4" Bottom Trip TorqueMaster Anchor w/4-1/2IF Box. 10 3/4" WindowMasterTM Whipstock w/4..1/2 IF Pin. WindowMasterTM Window Mill wI 4-1/2 Reg Pin. WindowMasterTM Lower Watermelon Mill wI 4-1/2 Reg Box x 4-1/2 IF Box WindowMasterTM Flex J9int wI 4-1/2 IF Box x Pin. WindowMasterTM Upper Watermelon Mill wI 4-1/2 IF Box x Pin. 1 Joint 5" HWDP 6-114 Ob Bowen Lubricated Bumper Sub wI 4-1/2 IF Box x Pin. 6-114" M.W.D. wI 4..1/2 IF Box x Pin. U.B.H.O. Wireline Orientation Sub wI 4-1/2 IF Box x Pin. (MWD Failure Contingency) (12) X 6-1/4" Drill Collars wI 4-112 IF Box x Pin (15) X 5" Heviwate Drillpipe wI 4-1/2 IF Box x Pin. Drillpipe to suñace. 2.2 Install the Anchor I Whipstock assembly to the WindowMaster milling assembly via the whipstock (45k) shear bolt. At this poi~t align the U.B.H.O. wireline orientation sub and M.W.D (scribe as required) with the whipstock face, this should be witnessed by all relevant parties. The U.B.H.O. wireline orientation sub would be used only as a backup if there were an M.W.D. failure. Baker Fishing Services Creig Boyd 7/30/2002 10 3/4" WindowMast..)rM TorqueMaster Bottom 1.:P Whipstock System Section 3. 3.0 Running and Setting Procedure For WindowMasterTM Bottom Trip System. 3.1 Run in hole with full whipstock assembly; take great care while running through the stack and wellhead. Note: Run assembly at a maximum rate of 90 to 120 seconds per stand 1aking care not to Spud or catch the slips. Ensure running string is stationary prior to insertion of the slips and that slips are removed slowly when releasiog the work string to R.I.H. These precautions are required to avoid any weakening of the Whipstock shear mechanisms and I or to avoid part I pre set on the packer. 3.2 At 45 ft above setting depth establish working constants, slack off weight, and pick up weight with and without circulation. rake great care not to create any sudden movements that could affect the whipstock shear mechanisms. 3.3 Survey the WhipstQck face with the M.W.D. and orient the whipstock to the requested kick-off direction, take a minimum of three surveys. Once the correct orientation has been reached reciprocate the whipstock to confirm that the face has not rotated. Lower to setting depth and re-check orientation if required. Note: Recommended ranges for this setting is from 90 deg. right to 90 deg. left of High Side. Other settings should be discussed before job. 3.4 Once orientation and depth have been verified by all relevant parties set down 15-20k Ibs to shear the slip mechanism and set the Bottom Trip Anchor. Check that the Bottom Trip Anchor has set by taking a max. Overpull of 5k Ibs above pick up weight. Note: If the well has not been displaced tQ milling fluid by this point it would be required to be displaced prior to milling operations to allow for constant mud properties during the process. Do not commence milling until mud returns are seen at suñace. Section. 4. 4.0 Shear-out and MiUing Procedure for WindowMasterTM Bottom Trip whipstock System. 4.1 With the Anchor set work pipe from neutral weight to 45k Ibs down to shear the whipstock bolt. If a positive shear is not seen at surface repeat the above a further four times (Do not overpull more than 15k Ibs and do not increase overpull on each pull). If no noticeable shear has been noted GO TO 4.2. If sheared GO TO 4.3 Baker Fishing Services Creig Boyd 7/30/2002 10 3/4" WindowM~sté. ''M TorqueMaster Bottom T~ .)WhipstockSystem. 4.2 Slack off a maximum 5k Ibs, install torque into work string up to the original free rotational torque value. Once torque has been locked in slowly raise the work string until rotation is accomplished, if rotation is not achieved and an overpull is being induced, stop and release to neutral weight and slowly unwind the torqued trapped in the string. The Anchor is rated for 20k ftlJbs torque. Note: It may only be possible to establish that the bolt has sheared by rotation as there is only limited lateral movement of the mill after shear-out. If no rotation is possible Revert to 4.1 4.3 Pick up to neutral weight and break circulation and establish rotation and start milling the window as follows: 4.3.1 Lower the milling assembly with 2-4k Ibs W.O.B. and with 50-60 rpm for the first f60t or two. 4.3.2 Increase the rotation as required to 10Q-135 rpm with a maximum of 8-10k Ib$ W.O.B. An minimum Annular velocity of 150 ftlmin should be maintained. The yield point of the mud should be kept to a minimum of 40 to ensure carrying capacity for cutting removal. 4.3.3 Continu~ milling until the Upper Watermelon Mill is out in open hole. This should be at approx. 38 ft. Once depth has been reached the window can be reamed as required, avoid rotation jf possible. Once ahy drag has been removed P.O.O.H. Note: If the Upper Watermelon Mill is more than 1/8" undersize on recovery a second reaming trip would be required. Baker Fishing Services Creig Boyd 7/30/2002 103/4" Wi~dowfv'låstt..)M Torquefv'låsterBottom .T.JWhipst~êkSystem. Recommended Milling Parameter: Time W.O.B. Torque Footage r.p.m. Flowrate Pressure [hr.] [Lbs] [Ftlbs] [Ft] [1/min] [GaVmin] [psi] 0.00 0000 2000 0 50 258 250 0.15 3000 3000 0 50 258 250 0.30 3000 3500 0.5 50 258 250 0.45 3000 3500 1 50 301 400 1.00 3000 4000 1.5 90 430 650 1.45 2000 4500 2.75 90 430 650 2.00 3000 6 -6.5 k 3 110 430 650 2.30 3000 6000 4 110 430 650 3.00 4000 5000 5.5 110 430 600 3.15 4000 6000 5.75 130 430 600 3.30 4500 5000 6 110 430 600 4.15 7000 4.5-5 k 7.5 130 430 600 4.30 4000 3000 7.75 140 430 550 4.40 4000 3000 8 140 430 550 4.55 4000 2500 8.5 140 430 550 (rough milling) 5.05 4000 2500 8.75 140 430 550 5.15 4000 2500 9 140 430 525 5.30 4000 3500 9.5 140 430 525 5.40 4000 3000 9.75 145 430 525 5.50 4000 2500 10 145 439 500 6.25 6-7k 2500 11 145 430 500 6.45 7000 3000 12 90 430 500 7.05 5000 3000 13.5 90 430 500 7.25 6000 3000 15 90 430 500 7.35 6000 3500 16 90 430 550 7.45 6000 4500 17 Formation 90 430 550 8.10 6000 3500 19.5 90 430 550 8.25 6000 3000 21.5 90 430 550 8.45 8000 3000 23 90 430 550 8.50 8000 3000 24 90 430 550 9.00 8000 2500 25 90 430 550 10.40 6-8 k 2500 38 90 430 550 11.00 6-8 k 2500 40 95 430 550 11.50 6-8k 2500 42 95 430 550 12.00 6-8 k 2500 44 95 430 550 12.50 6-8k 2500 46 Window Complete 95 430 550 Note: No milling assemblies are to be broken out without the prior written consent of Baker Oil Tools. Job Complete Baker Fishing Services Creig Boyd 7/30/2002 PROPOSED well SCHEMATIC '.'.: ..íf~T ~~'~' ..'.... '.:'.\.'..'.i i :.. ", r EQUIPMENT AND SERVICES LOCATION OPERATOR COMPANY REP. FIELD STATE LOADING DOCK RIG NAME PREPARED BY DATE SUBMITTED JOB REPORT # No. ") ) SALES LOCATION r&iíll BAKER HUGHES Baker Oil Tools Baker Oil Tools Insert Product Line here Baker Oil Tools Insert Address Here Insert Phone here FAX# BHP BHT PHONE# ZONE DEV. Page: 1 MAX DEV. WELL NO. SCREEN SIZE STARTING WELL LEASE SAND SIZE I COMPLETION FLUID (weight and type) COATING (type) PHONE # PERFORATIONS PHONE # SIZE 10 3/4 WEIGHT 40.50 GRADE J-55 THREAD PHONE # CASING LINER TUBING WRKSTR. JOB# (-Ii) WEll TYPE DEPTH LENGTH ID DESCRIPTION OD 7.5 9.894 3.500 Upper String Mill 7.5 7.96 7.750 3.500 Flex Joint 15.46 10.58 9.445 3.500 Lower String Mill 26.04 1.7 9.132 Window Mill 27.74 23.53 9.000 WindowMaster Whipstock 51.27 21' Window 2.93 WindowMaster Bottom Trip TorqueMaster Anchor 9.524 54.2 ) Baker Oil Tools Liner Hanger Procedure ) ) LINER SETTING, RUNNING AND CEMENTING for a Model "D" Liner Hanger/Packer TYPICAL LINER ASSEMBLY . Guide Shoe . 1-Joint of Liner . Float Collar . 1-Joint of Liner . Landing Collar . Liner . Liner Hanger/Packer ( mechanical set) . Liner Setting Tool ( C-2 ) . Drillpipe to Surface Liner Running Notes . Circulate liner contents after liner is fully made UP and note weight of liner in mud. . Ensure that all excess thread compound has been cleaned off the casing before running in hole. . Bring blocks to a complete stÇ)P before setting slips. . Keep liner full while running in hole. . Monitor pick-up and slack-off weights while running in hole. Record hanging weight, P/u weight, S/O weight with liner previous shoe depth and at TD. . Maximum pull at the liner is 80% of the connection or pipe yield, which ever is less. . Monitor mudflow while running pipe in hole. If returns decrease or are lost, reduce running speed. ) STEP BY STEP PROCEDURE ) 1. On final trip prior to POH for liner, pump a sweep. Rotate and reciprocate while pumping sweep. Record SPP and torque/drag before and after sweep. Rack back singles periodically during extended circulating time. 2. Short trip and repeat circulating pill procedure to ensure the hole is clean. Always reciprocate the pipe while circulating and do not circulate more than the r~te used to drill the well to avoid hole washouts. . If tight spots persist, or if considerable sliding occurred while drilling which created a tortuous well path, consider a hole opener run 3. Just prior to POH for liner, spot a liner running pill. Circulate a minimum of 120% of bottoms' up or drillpipe volume, whichever is greater POH for liner. 4. Drop rabbit on wire and POH and LD BHA. 5. Rig up and run casing. 6. Baker-lock shoe joint, check floats and make up liner. Make up packer/hanger/setting tool assembly. Run one stand and circulate liner contents to ensure liner is free of obstructions. RIH to TO. Ensure cementing equipment is on location when liner is on bottom. 7. Position the liner hanger/packer assembly +- 150' abové the intermediate casing shoe such that the hanger/packer is not set in a severe dogleg or at a previous casing float collar. 8. Circulate at the maximum possible rate until the returns are clean. At least 3 annular volumes should be circulated. Reciprocate while conditioning and cementing if hole conditions permit. 9. RU and pump cement. 10. Drop liner wiper plug. Approximately 5-10 barrels prior to the pump down plug reaching the liner wiper plug slow the pump rate to 1-2 BPM. When the pump down plug latches into the liner wiper plug, a slight pressure increase should be noted prior to the plug's shear. 11. Approximately 5-10 barrels prior to the calculated plug displacement to the landing collar slow the pump rate once again. 12. When the plugs reach the landing collar, 800-1200 psi over circulating pressure should be applied to the landing collar system. 13. Bleed pressure to zero and check floats to insure that they are holding. Tag bottom again, and then pick up liner to setting depth. RECOMMENDED PRACTICES 2 ) ') 14. Once liner hanger/packer is at setting depth put three rounds of left-hand torque and hold with tongs. Pick up off slips just enough to clear and with a smooth motion, slack off liner weight plus an additional 15,000 - 20,000 Ibs. 15. Set slips, leaving 10,000 Ibs. On plug dropping head swivel. Rotate setting string 6-8 rounds to the right, checking for return torque. Pick up 4' to check for loss of liner weight. 16. Circulate a minimum. of 20 bbls at maximum rate at the top of the liner. Continue circulation LONG WAY, while reciprocating, a minimum of 1 % times the annulus volume to surfaces. 17. Watch for cement returns and estimate the volume returned. Once returns are clean, switch to clean fuild and circulate from top of liner until returns clean up. 18. Contingencie~: If cement is suspected to have fallen into the line a clean out BHA will be needed. 19.RIH and tag the top of cement. Clean out and drill cement to landing collar. Retest well. 20. Circulate well over to clean seawater at TD. 21. POOH to liner top and circulate One complete volume. 22. Finish POOH and lay down all drill pipe and BHA's. RECOMMENDED PRACTICES 3 PROPOSED WELL SCHEMATIC B~ ~ c .¡ -/ .. l- UI E = fJ E~ :=J E~~ J ,E ~ ====== ~ == It ~ E 'j ( : J ~ --- EQUIPMENT AND SERVICES LOCATIO... Baker Oil Tools Completion Drawing OPERATOR FAX II Aurora COMPANY REP. PHONE II FIELD WELL NO. Nicolai Creek 1B STATE LEASE Alaska LOADING DOCK PHONE II RIG NAME PHONE II PREPARED BY Creig Boyd DATE SUBMITTED 8-Jul-02 PHONE II 561-1939 JOB II (version II) JOB REPORT II WELL TYPE Gas OD No. DEPTH LENGTH SAlES LOCATION BHT r&íi8 BAKER HUGHES Baker Oil Tools Baker Oil Tools Kenai, Alaska 907-776-8131 907-561- 1939 BHP MAX DEV. SCREEN SIZE SAND SIZE PERFORATIONS CASING LINER TUBING WRKSTR. ID -~-~~--~'-'-"--"'----._--~._-------------- ZONE DEV. Page: 1 ~-~---~------- --- ----------'--~'-----"-~--<-'-----'-----'~----- STARTING WELL ----~---~---- I COMPLETION FLU~~:_::_mmm.- ~~:TI:G(~). . ------ SIZE 10.750 7 lJY!;lŒ:!L____GBAQI';_.. .__-.T.tIBEAD 40.50 ----_._~-._~------ -_~.___n__-.~_--~------.- 26.00 L-80 "---'''~-- --~-~.--_.__.._------ - ---'--~-'-,----, -.---.-<" ----'--'-~ ~--------_._-- DESCRIPTION E-22 Anchor Seal Assembly SC-1 7" 23-29# PKR 70B-40 w/5 1/2 17# SPCL SLHT B 6' Retrievable Extension X-over Casing sub 5" 18# SLHT B x 3 1/2 EUE Tubing 31/2 EUE Pup Joint 10' long "X" Nipple Profile 2.313 3 1/2 EUE Pup Joint 10' long X-over 3 1/2 EUE B x Pin f/ Screen Screen Guide Shoe ) Lm Proposal No: 100172456A Fairweather Expl & Prod Inc Nicolai Creek Unit No.1 B Aurora Gas Rig NO.1 Rig Nicolai Creek Field Kenai County, Alaska June 24, 2002 Cement Recommendation Prep~red for: Duane Vaagen Proj~ct Engineer Fairweather E & P I Aurora Gas, LLC Prepared by: J. Jay Garner Manager, City Sales Kenai, Alaska Bus Phone: (907) 349-6518, Anchorage Email: jgarner@bjservices.com POW E R V I S I ONSY Service Point: Kenai Bus Phone: (907) 776-4084 (907) 659-2329 (907) 776-4087 Fax: Service Representatives: J. Jay Garner Manager, City Sales Kenai, Alaska Bus Phone: (907) 349-6518, Anchorage Email: jgarner@bjservices.com Gr4105 Operator Name: Fairweather Expl [)ad Inc Well Name: Nicolai Creek Unit NO. 1 B Job Description: 7" Liner Cementing Operation Date: June 24, 2002 !£j Proposal No: 100172456A JOB AT A GLANCE Depth (TVD) Depth (MD) 3,650 ft 3,650 ft HoleiSize 8.75 in Liner SizelWeight : 7 in, 23 Ibs/ft Pump Via Drill Pipe 3 1/2" 0.0. (2.602" .1.0) 15.5 # Drill Pipe 7" 0.0. (6.366" .1.0) 23 # Total Mix Water Required 1,707 gals W~ighted Spacer .Spacer MCS-4D Density Cement Slurry :Class G Cement Density Yield 30 bbls 10.5 ppg 348 sacks 15.8 ppg 1.17 cf/sack Dh~placement . Drilling Mud Density 80 bbls 9.5 ppg Report Prinled on: June 24, 2002 4:27 PM Page 1 Gr41 09 Operator Name: Fairweather Expl / }od Inc Well Name: Nicolai Creek Unit ,,,0. 18 Job Description: 7" Liner Cementing Operation Date: June 24, 2002 WELL D~TA ANNULAR GEOMETRY ¡ANNULAR 1.0. (in) 10.054 CASING 8.750 HOLE ) Lill Proposal No: 100172456A MEASURED 2,250 3,650 DEPTH(ft) I TRUE VERTICAL I 2,250 I 3,650 SUSPENDED PIPES ,... . J:' > '." ¡ DIAMETER .(in) OlD. : I 7.000 I I.D. 6.366 WEIGHT (Ibs/ft) 23 Drill Pipe 3.5 (in) OD, 2.602 (in) ID, 15.5 (Ibs/ft) set @ Drill Pipe 7.0 (in) OD, 6.366 (in) ID, 23 (Ibs/ft) set @ Depth to Top of Liner Float Collar set @ Mud Density Mud Type Est. Static Temp. Est. Circ. Temp. DEPTH(ft) MEASURED I TRUE VERTICAL 3,650 I 3,650 1,850 ft 3,650 ft 1,850 ft 3,570 ft 9.50 ppg Water Based 117 0 F 90 0 F VOLUME CALCULATIONS I 400 ft x 0.2841 cf/ft with 0 % excess = 1,400 ft x 0.1503 cf/ft with 30 % excess = 80 ft x 0.2210 cf/ft with 0 % excess = TOTAL SLURRY VOLUME = 114 cf 274 cf 18 cf (inside pipe) 405 cf 72 bbls = 1. Remedial cementing proposal to be generated based on results of liner top pressure test. Report Printed on: JUlIe 24, 2002 4:27 PM Page 2 Gr4117 Operator Name: Fairweather Expl P'{od Inc Well Name: Nicolai Creek Unit 1. 1 B Job Description: 7" Liner Cementing Operation Date: June 24, 2002 FLUID SP~CIFICA TIONS Weighted Spacer FLUID VOLUME VOLUME CU-FT FACTOR Cement Slurry 405 Displacement CEMENT PROPERTIES Slurry WØight (ppg) Slurry YiØld (cf/sack) Amount 9f Mix Water (gps) Amount of Mix Fluid (gps) Estimated Pumping Time - 70 BC (HH:MM) Free Wa~er (mls) @ 90 0 F @ 90 0 angle Free Water (mls) @ 900 F @ 45 0 angle Fluid LO$s (cc/30min) at 1 ØOO psi and 90 0 F COMPRESSIVE STRENGTH 12 hrs @ 1000 F (psi) 24hrs @ 1000 F (psi) 48 hrs @ 1000 F (psi) 72 hrs @ 1000 F (psi) RHEO'-OGIES FLUI'D Cement Slurry TEMP @ 80 0 F ) E£j Proposal No: 100172456A 30.0 bbls Spacer MCS-4D + 6 Ibs/bbl MCS-D + 8.99 Ibs/bbl Potassium Chloride + 30.15 Ibs/bbl Bentonite + 90 Ibs/bbl Barite, Bulk @ 10.5 ppg AMOUNT ANO TYPF OF CFMFNT 1.17 = 348 sacks Class G Cement + 1 gals/100 sack FP-6L + 0.15% bwoc Sodium Metasilicate + 2% bwow Potassium Chloride + 0.5% bwoc CD-32 + 0.6% bwoc FL-33 + 0.9% bwoc BA-10A + 43.5% Fresh Water 79.9 bbls Drilling Mud @ 9.5 ppg SLURRY NO.1 15.80 1.17 4.90 4.91 7:30 0.0 0.0 10.0 300 820 1410 1925 600 216 300 134 200 98 100 58 6 13 3 12 Slight additive adjustments should be expected to achieve the desired slurry properties, based on pilot test results. Report Printed on: June 24, 2002 4:27 PM Page 3 Gr4129 Ms. Cammy Oechsli Taylor, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 July 29, 2002 ") ) :.Aurora Gas, '-'-C E E ~ JI II '-, 1 r¡O\Il? ;",,;~ ,,) . t. '-'- Alasl~a &. (;ommiSS10n RE: Application for Permit to Drill: Nicolai Creek Unit No. IB Anchorage Dear Ms. Taylor, Aurora Gas LLC, hereby applies for a Permit to Drill, a prerequisite for re-entering and re-drilling the suspended well NCU 1A. At this time~ Aurora Gas LLC. would like to re- enter the NCU 1A well, sidetrack and re-complete it as a natural gas production well, Because of the proximity of the NCU 1A well with respect to nearby wells at surface and subsurface, a Spacing Exception Order is required, the application of which has been submitted under separate cover. The Nicolai Creek Unit No. 1A well, is located onshore Granite Point, in the Nicolai Creek operating unit, and is approximately 11 miles Southwest of the village of Tyonek. Aurora plans to begin well re-entry, sidetracking and recompletion operations on August 6th, 2002. Upon receipt of all necessary permits and approvals, contractors will rig-up over the NCU 1A wellhead to begin operations with Aurora Well Service Rig No.1. The rig is currently rigged up over adjacent well, NCU No.2, performing re-entry and re- completion procedures. Pertinent information in and attached to this application, includes the following: 1) 2) 3) 4) Form 10-401 Application for Permit to Drill- 3 copies, Fee of$100.00 payable to the State of Alaska. A plat map and information detailing the surface location and proposed bottomhole location 20 AAC 25.050 (c )(2). Directional plots and proximity calculations in accordance with the requirements of 20 AAC 25.050. Diagrams and description of the BOP equipment to be used as required by 20 AAC 25.035 (a)(I) and (b). The proposed casing program as per 20 AAC 25.030. The drilling fluid program, in addition to the requirements of 20 AAC 25.033 are attached. 5) 6) 7) Lf"\r\ßr"D~¡ ~L , '--1/ ~ ~ . ~ ~\J . ,.I¡'ìiU!I\iJ Ms. Taylor Page 2 8) 9) 10) 11) 12) 13) ') ') A copy of the well history, proposed re-entry, driUing and recompletion procedure and operational considerations is attached. Aurora Gas LLC. does not anticipate the presence of H2S in the formation to be encountered in this well. However, H2S monitoring equipment will be functioning on the rig at all times during sidetracking, drilling and completion operations. While this well is considered a development well, basic mud logging will be performed while drilling to aid in tracking the location, thickness and quality of the intervals penetrated. A Summary of Drilling Hazards. Pressure Information The following are Aurora Gas LLC's designated contacts for reporting responsibilities to the Commission. 1) Completion Report (20 AAC 25.070) Duane Vaagen, Project Engineer (907)258-3446 2) Geologic Data and Information Andy Clifford, President (20 AAC 25.071) (713)977-5799 3) Well Records, Testing and Production Reporting (20 AAC 25.070) Ed Jones, Executive Vice President (713)977-5799 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 Ed. Jones Executive Vice President / Production Manager Enclosures cc: if ¡ , \"",1 '-. Duane Vaagen Andy Clifford Cammïssìon L . ¡ PAY One Hundred Dollars And 00 Cents '-" TO THE ORDER OF STATE OF ALASKA .~/VCU /6 ~' TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE I. NCLUDED IN TRANJMITT AL LET~/ ¡ WELL NAME dCð/ Ä¿ (!¡ 0u.;' ;L() 2- - I h 2--- CHECK WHAT APPLIES / Rev: 07/10/02 C\j ody\templates PTD# ADD-ONS (OPTIONS) MUL TI LATERAL (If API number last two (2) digits are between 60-69) PILOT (PH) HOLE SPACING EXCEPTION DRY DITCH SAMPLE /~ "CLUE" The permit is for a new wellbore segment of existing well Permit No, API No. Production should continue to be reported as a function. of the original API number stated above. In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 70/80) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation orJJer approving a spacing exception. ~A- 6a..$-- ~C- (Company Name) assumes the liability óf any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. WELL PERMIT CHECKLIST COMPANY fl~A WELL NAME d (J,U I $. PROGRAM: Exp Dev ./ Redrll Re-Enter Serv Wellbore seg FIELD & POOL ~t.O!>~ INIT CLASS ~V GEOL ARE-;:- 82.0 - UNIT# ,-;J5/Ý3'D ON/OFF SHORE 0;, ADMINISTRATION 1. Permit fee attached. . . . . . . . . . . . . . . . . . . . . . . ¡";¡) N 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . ~ N 3. Unique well name and number. . . . . . . . . . . . . . . . . Ô) N .' /.' , / . ~.~' _.17 ci: ~::: :~::~ ~::~~~~:~~,,; driili~g ~n¡t b~u~cia;Y: '. '. '. ~~ /V: <.Þ <k- a ~:;-,r:<>o ..., 1/27 : ~ . /) I I ¡? !'I L- 6. Well located p roperdistance from other wells. . . . . . . . . . '-yí~. ....5~a..c:...~ J2_J<-C-~' ,d}.v. Þ-'L¿) l..;> I ~ . -rt~t....~ d(C/-t< P--I .~. E' <!.-~ fiè- .APPR DATE 7. Sufficient acreage avaitable in drilling unit.. . . . . . . . . . . y (J JtJ\ 3'.65-ò2- 8. If deviated, is wellbore plat included.. . . . . . . . . . . . . . :..- ~ 9. Operator only affected party.. . . . . . . . . . . . . . . . . . ~N - .J;'; ff. ~ ~~: ~~~~t~~~a:e~~~~:ri~:~~~~~~~s~Z:tio~ ~~~r: : : : : : : : L}'@ ~~~~ (~;:-vh';" . ~~'~¿~.£:'Y dJ¡ k $<-1 ¡;.. ~Zo/'o¿, 12. Permit can be issued without administrative approval.. . . . . Œ5N V {) (Service Well Only) 13. Well located w/in area & strata authorized by injection order #-----.: Y N.;1C/A (Service Well Only) 14. All wells w/in ~ mile area of review identified. . . . . . . . .. Y N. dA ENGINEERING 15. Conductor string provided. . . . . . . . . . . . . . . . . . . Y N \ ~~: ~~:I~~S~~~~;~:~:~II:t~o:C~~~:t~r&~urt~g:: : : :.~. ~ ~~o\.~~,~~,~ ~Q\\ ~~',:::~:~~\~~ 18. CMT vol adequate to tie-in long string to surf csg. . . . . . . . Y N '" ~ 19. CMT will cover all known productive horizons. . . . . . . . . . (!) N . \ 20. Casing designs adequate for C, T, B & permafrost. . . . . . '.. <D N \0. ~ ,~", N:l ~ ~ ~ .~~ "?:. \3>UÇ»-> \ ~}G ~ ~\ ~ ~S- (':" ~ bCJ ~o 21. Adequate tankage ~~~ ~~~.~ p~,,~~ Y N ~\c ~"""-,,,,~~CL\ ..;;)';;)~ b">' \,(\~ <:;O~ \ ~ \-.~ .~~'\.~\. '-\c:~...,,~"'\~ 22. If a re-drill, has a 10-403 for abandonment been appro~ed. . . cr> N,'~ - 'Ç'\ '" ",,,," sC'c. ~ ~~ ~~, ~~~\.<:o.: '~~ ~~,~"""-~ 23. Ad~quate well~ore separ~tion propose~.. . . . . . . . . . . . a; N, 4 i-\()-Š l""~Q~'-"R..~ ~ .~" r-...~ 'i"'" "-~'-) \ ~ 24. If ~I~erter ~equlred, does It me~t regul~tlo.ns. . . . . . . . . . ~t>...~ ~ ~~~, .~-\. -~~ ''i~"'' ~ D tt.~'<:J. .' 25. Dnlllng fluid program schematic & equip list adequate. . . . . <i) N ...t:;~ 'b~\. ti,,~~~~} \.."'\J~;'" \"D \;~')~CJl, ~~ çs~ G ~,,\ \;:;~W 26. BOPEs, do they meet regulation. . . . . . . . . . . . . . . . ~ N - C'\. , 27. BOPE press rating appropriate; test to d....~'t') psig. ~ N \-.\~,>'Ç> 4t..,,>~Q. \..Ç$~ ,,~\ ~7~;'\ ~c:::.~'è.)~'\ ~"-,,~\.~ 28. Choke manifold complies w/API RP-53 (May 84). . . . . . . . ~ N . 29. Work will occur without operation shutdown. . . . . . . . . . . Y . N .. .. \ it ~ i' 30. Is presence ofH2S gas probable.. . . . . . . . . . . . . . . . ([) ~"'~ ~ ~\'o.."'~\'1 t)\~ ~~ ~'\. "'(3.~<t SC~~ 31. Mechanical condition of wells within AOR verified. . . . . . . . ~~-Y N ' 32. Permit can be issued w/o hydrogen sulfide measures. . . . . ~~."Y- ¿ /) ~ ~ t-l( . / ~ ..) 33. Da~a ~resente~ on potential overpressure zones. . . . . . . . /\ .Y:I, ,.~(~~. ~ or-A . Þ~6.. 17°: f'S ~/ W:i) :. Ó:/(5/b 34. Seismic analysIs of shallow gas zones. . . . . . . . . . /. . . N "- -)0, I( htJ ~Ø¡44 t.4 ~Þ\.6~ -IV 6.c-, ~ Þ'I- -f4A. ~. / f?L~1I ~ 35. Seabed condition survey (if off-shore). . . . . . . . . . . . . Y N .::JU¡"K~ ~,y¡... ¡:'~ I Ç[, i..; ~,6- b 1'/I~"T-Id4-(:"¡ ~ 36. Contact name/phone for weekly progress reports. . . . . ~ . . Y N ~~ ~~ ò'?-- ~ 12-~/ij. ~Y) GEOLOGY: PETROLEUM E~t.. INEERING: RESERVOIR ENGINEERING UIC ENGINEER COMMISSIONER: Comments/Instructions: RPC TEM kH-?fY}~'c,-r::i') JDH JBR COT DTS G ~ J 13 J ç:, Z. ~PPR DATE .~~ 7JI( ~~~ (Service Well Only) GEOLOGY APPR DATE ~b ¡cr;.02.. (Exploratory Only) Rev: 07/12/02 SFD ~þ / WGA MJW G:\geology\perm its\checklist.doc